HomeMy WebLinkAboutAPA1289I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
l• ' ~~ ... " . ~ .. ·'
AliR
SUSITNA HYDROELECTRIC
PROJECT
GENERATION PLANNING
STUDIES
CLOSE OUT REPORT
APRIL 1982
Acres American Incorporated
Suite 329
The Clark Building
5565 Sterrett Place
Columbia7 Maryland 21044
Telephone (301) 992-5300
I
I
I
I
I
I
I
I
I
0
I
I.
I
I
I.
I
I
I
I
I
~":l: .... o:.J:
TABLE OF CONTENTS
Section
1 -INTRODUCTION . . . . . . . . . . . . . . . . . . ~ . . . . . . . . . . . . . . . . . . . . . . ~ -. . . . . .
1.1 -Objective and Purpose .................................. .
1. 2 -The Report ........ ., .............. , ......... .,., .............. .
1.,3 -Methodology Summary •.......... ~ ..............•.........
2 -SUMMARY -GE OGP MODEL (adapted from ........................ .
General Electric literature)
3 -DETAILED GENERATION PLANNING INPUT ........ H •••••••••••••••••
Page
1-1
1-1
1-1
1-1
2-1
3-1
3.1-Load Forecasts ........ R ••••••••••••••••••••• ; •••• ~..... 3-1
3.2 -Existing Generation, Retirements, and Additions ........ 3-1
3.3 -Alternatives Data ............................. ~ .... 0 0 0 0 3-1
3.4 -Susitna Data ...................................... o... . .3-2
3.5 -Other Parameters ..•.. o •• o •••.•.•• -........................... 3-2
4 -RESULTS OF GENERATION PLANNING STUDIES o.... . . . . . . . . . . . . . . . . . . 4-1
4.1 -Methodology ........ e.................................... 4-1
4.2-Base Systems (1982 -1992) .................•........... 4-3
4. 3 -Non -Sus i tna P 1 an -Merii um Load Forecast .. '" • . . .. . . . . . . . . . 4-3
4.4-Susitna Plan-Medium Lead Forecast .........•.......... 4-3
4.5-Comparison of Base Pl.tns ............................... 4-4
4.6-Single Variable Sensitivity Analysis .. ;................. 4-4
4.7-Multivariate Sensitivity Analysis...................... 4-11
5-GENERATION PLANNING OGP MODEL OUTPUT SUMMARIES ............... 5~1
LIST OF TABLES
No. Title
3.1 Alaska Railbelt Medium Load Forecast
3.2 Alaska Railbelt High load Forecast
3.3 Alaska Railbelt Low Load Forecast
3.4 Existing Railbelt Generating Units -1980
3.5 Existing and Planned Railbelt Hydro Generation
3.6 Schedule of Planned Utility Add·1tions (1980-1988)
3.7 Summary of Thermal Generating Resource Plant Parameters
3.8 Fuel Costs and Escalation
3.9 Chakachamna Hydroelectric Project
3.10 Susitna Hydroelectric Project (renerat ion Planning Data
3.11 OGP System Data.
3.12 OGP Economic Data
4.1 Generation Planning Base Plans
4.2 Sensitivity Analysis -Load Forecast
4.3 Sensitivity Analysis ~ Economic Interest/Discount Rate
4.4 Sensitivity Analysis -Capital.Costs
4.5 Sensitivity ~~nalysis-Delay of Project
4.6 Sensitivity Analysis -Real Escalation
4.7 Sensitivity Analysis -Coal Prices
4.8 Sensitivity Analysis -Other Hydro Projects
4.9 ~1ultivariate Sensitivity Analysis-Alternative Capital Costs
4.10 Multivariate Sensitivity Analysis -Fuel Costs and Escalation
4.11 Multivariate Sensitivity Analysis -Susitna Capital Costs
4.12 Multivariate Sensitivity Analysis -Non-Susitna Tree
4.13 Multivariate Sensitivity Analysis -Susitna Tree
4.14 Multivariate Sensitivity Analysis-Calculation of Net Benefits
4.15 Multivariate Sensitivity Analysis -Susitna Capital Cost
Senstivity Analysis
5.1 Summary of Generation Planning OGP Runs
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
LIST OF FIGURES
No. Title
1.1 Generation Planning Methodology
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
Long-Term tost Concept
Net Benefits
Non-Susitna Plan Annual Cost
Sus i tna Plan Annual Cost
Base Generation Plans Yearly Cost
Base Generation Plans Percent Reserve
Base Generation Plans Net Benefits
Interest Rate Sensitivity
Non-Susitna Probability Tree
Susitna Probability Tree
Non-Susitna Long-Term Cost
Susitna Long-Term Cost
Long-Term Cost Comparison
Net Benefit Comparison
Fuel Cost Escalation Sensitivity
Susitna Capital Cost Sensitivity Normalized Plots
I
I
I
I
I
I ......
•'
I
I
I 1 -_INTRODUCTION
.
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I"
I
I
I
I·
I
I
I
I
I
I
1-
1 -INTRODUCTION
1.1 -Objective and Purpose
The objective of the generation planning studies 'lias to plan the ~xpansion
and operation of the Railbelt electrical generation system with and \'lithout
the Susitna Hydroelectric Project; The purpose of these studies was to
provide basic data for an economic analysis of the project, provide data
for staging and sizing of the project and supply information to project
financial studies.
1.2 -The Report
Four sections follow this introduction. Section 2 is a summary program
description of the General Electric Optimized Generation Planning (OGP)
Program. It was written and published by GE in 1979 and is reproduced in
total without editing with the permission or General Electric Utility
Systems Engineering DepartmentQ
Section 3 include~-; all of the data that was used in setting up and
operating the Rai'belt system planning model. Section 4 is a collection of
the results and interpretation of the generation planning studies. ·It
includes the basis for the economic analysis of the study presented in the
feasibility report.
Section 5 is a collection of output from the OGP program for many of the
scenarios. The output presented ·is selected pages from the output summary
and is only a small percentage of the data produced by the program,
although it does represent the most pertinent information.
A summar·y version of the information in this report is in the feasibility
study report. This report is intended as a reference document for
individuals interested in more detail.
1.3 -Methodology Summary
The primary tool used in the generation planning studies is a computer
program made by General Electric titled Optimized Generation Planning.. The
model was set up for the Railbelt early in the feasibility study and ili!Sed
extensively in the development selection phase of project studies. The
model was updated frow the. earlier phase using more detailed data on the
Susitna project and information from the Battelle Power Alternatives
Study. ·
Three major divisions of input data are needed for the model load data.,
existing generation system and alternatives data. An outline of the
methodology is shown in Figure 1.1.
1-l
The load data used was from projections made by Battelle in December 1981.
These vary somewhat 'from the final forecasts made by Battelle at a later
date. A range of three forecasts from reasonable low to high range were
considered.
Data on future alternatives and existing generation was also adapted from
Battelle's study. This data consisted of available alternatives, capital
cost estimates, fuel costs, operation and maintenance costs and operating
characteristics.
The alternatives selected by Battelle for use in the Sus·itna generation
planning update are:
Coal-fired steam electric at Nenana and Beluga (200 MW).
Gas-fired combined cycle plants at Anchorage or Fairbanks· (200 MW).
Gas-fired combustion turbines at Anchorage or Fairbanks {70 MW).
Chackachamna hydro project (330 MW).
Generation planning was done with economic parameters, consistent with
APA's planning criteria. Under these criteria, the effect of general
i nfl at ion is removed from study and on 1 y • rea 1' costs of capita 1 and
escalation are considered for the base cases. At zero inflation, a three
percent cost of capital and discount rate was used. Incremental escalation M
was considered for fuel costs, construction costs and operation and
maintenance costs. These elements are expected to ·increase in price faster
than the rate of general inflation.
The generation model was used in the following studies:
(a) Establish Pre-Susitna Base System
A common pre-Susitna 1982-1993 system was estab 1 i shed for each load
forecast as activities during this period would be the same with or
without Susitna. The period was not considered in the economic
analysis. The system was considered to include the initial phase of
the planned Anchorage/Fairbanks intertie and allow for full economic
exchange of power between utilites. In effect, all !Jtilities and
their resources were mode 1 ed as operating as a power pool. No
generating resources were needed as additiDn to the system during this
time period.
These plans are described in Section 4.2.
{b) Generation Plans Without Susitna
A without Susitna base generation plan was established using the
medium load forecast and expected or mid-range values for all other
variables. The plan covers the time period from 1993-2010. The
optimization features of the OGP program were used to add capacity to
the system as it became necessary. The need for additional capacity
was determined by reliability criteria.
0
1-2
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
The following assumptions were used in the generation planning:
No ., imit in natural gas use.
Economic parameters as specified by APA (0 percent escalation; 3
percent interest).
Costs of transm·ission for initial Beluga and Nenana plants were
included. ·
Alternatives available under Battelle's plans were considered
available to the system and staged as necessary.
Fuel escalation as specified by Battelle.
Similar model plans were made for the high and low forecasts and
described in Section 4.6.
(c) Generation Plans with Susitna
A number of model runs were made to focus upon a 11 With Susitrta11 plan
under the medium, high and low load forecasts, so described in Section
4.4.
Three key assumptions used in the analysis were:
Economic parameters.
The Susitna plan is Watana/Devil Canyon (in that order).
Susitna data {energy and cost) used in this task was identical to
that provided to Battelle in December 1981~
(d) Sensitivity Analysis
Many of the inputs to the generation planning model can be termed as
variables, such that they are results of policy decisions or
projections. Initially, these variab_les \'Jere studied singularly using
the model to test results on different values, as appropriate.
The methodology for single variable sens·itivity analysis (see Section
4.6) was as follows:
Identify areas of uncertainty.
For each topic, identify the range of variability.
Test sensitivity.
Discuss the variability.
1-3
•. c '· '
. "·~" ""'~·-~ · ... ~ .. ~·"'
I
I
I
I
I
I
I
I
I
I
I
I
I
I
II •
-I
I
1-
'·I
(e)
The following list of variable inputs was considered in the
sensitivity analysis:
- 1 oad forecasts
-economic interest/discount rate
-capital costs
-period of analYsis
-construction period
-real escalation capital costs, O&M and fuel costs
-O&M costs
-system reliability
-coal base price
-other hydro projects
Multivariate Sensitivity Analysis
After the individual variables were tested, the most critical were
chosen for a multivariate analysis. The purpose of this analysis was
to review combir ~ions of variables occuring together and compare long
term costs of \: scenario with and without the Susitna project.
This analysis is presented in Section 4.7.
To perform the analysis, a probability tree with and without the
project· was constructed. Each tree consisted of branches
corresponding to a high, medium or low value of a variable.
Probabilities were ass·igned to each value and calculated for each
scenario.
For each scenario, the yeneration planning model was used to determine
long term costs. Finally, comparisons among corresponding with and
without scenarios were made to establish project economic feasibility
under the full reasonable range of variability. •
a
1-4
------~------------
I
LOW
LCAD MODEL
{Update)
I
1982-1992
SYSTEM
I
1993-2010
I
WITHOUT ECONOMIC * WITH
SUSITNA PLAN SUSITNA
EXISTING GENERATION SYSTEM
1982
(UPDATE)
MEDIUM
LOAD MODEL
(Update)
1982-1992
SYSTEM
I
1993-2010
I
-
G j
HIGH
LOAD MODEL
{Update)
I
1982-199g
SYSTEM.
I
1993-2010
I
WITHOUT ECONOMIC* WITH WITHOUT . ECONOMIC* WITH
SUSiTNA PLAN SUSITNA SUSITNA PLAN SUSITNA
SINGLE
VARIABLE
,____SENSITIVITY---t
ANALYSIS
MULTIVARIATE I I '---------_._.-SENSITIVITY ___ ......_ ______ _._
• USING: 0°/" GENERAL INFLATION
3 °/o COST OF MONEY ·
ANALYSIS
GENERATION PLANNING . METHODOLOGY
FlGU~E 1.1
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
2 -SUMMARY -GE OGP MODEL
0
I r.~~) . ._··'V>.<?J.~ ELECTRIC UTIUTY SYSTEMS ENGINEERING DEPARTMENT
I
I
I
I
I
I
I
I
I
I
I
I
I
0PTil-1IZED GENERATION PLANNING PROGRAM
PROGRAM DESCRIPTION ·
(REPRINTED WITH PERMISSION FROM GE)
GENERAL ELEClRIC Cor .. ~PANY
1 RIVER ROAD
SCHENECT ~::>Y. N.Y 12345
t1ARCH 1979
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
Table of Contents
OPTIMIZED GENERATION PLANNING (OGP) PROGRAM • . ... . • •
Reliability Evaluation ••••••••••••••
Production Simulation • • • • • • • • • • • • • •
Purchases and Sales .. • • • • • • • ; • • • •
Conventional Hydro Scheduling • • • • • • • •
Thermal Unit Maintenance • • • • • • • • • •
Energy Storage Scheduling • • • • • • • • • •
Thermal Unit Corrunit~llent • • • • · • • • • • • •
Thermal Unit Dispatch .. • • • • .. ~ ••• o •
Fuel and Energy Limi i:ations • • • • • • • • •
Investment Costing • • • .. .. • • • • • • • • • • •
OGP Optimization Procedure~ • • • • • • • • • • • •
Sample Output Results •••• o ••• ~ •••••
FINANCIAL SIMULATION PROGRAM (FSP) • • • 0 • • • • • •
Introduction • • • • • • • • • • ~ o 9 o • • • • •
Model Structure e • • • • • • • .. • • • • • • • •
Capital Expend:~ tures • ... • • • • o • • • • •
Generation Projects • • • • • • • • • •
Transmission, Distribution and
Miscellaneous Plant • • • • • • • •
Investment Credits • • • • •••••••
Plant Retirement • • • • • • • • • • • • • •
Depreciation .. • • • • • • • • .. • • o • • •
Revenue • • • • • • • • • • • .. • • • • • • ·•
Expenses • • • • • • • • • • • • • .. • • .. •
Financial Planning • • • • • • • • • • • • •
Cash Management and Accounting • • • • • • •
Income Taxes • • • • • • • • • • • • • • • •
Rate Regulation • • • • • .. • • .. • • • • • •
Sample Output Results .. • • • • • • • • • • • • •
Pag~
1
1
5
5
6
6
6
7
9
9
10
10
12
18
18
18
18
21
21
21
21
21
22
22
22
23
23
23
24
..
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
OPTIMIZED GENERATION PLANNING (OGP) PROGRP~
The OGP progra.Ttl was developed over ten years ago to
combine the three main elements of generatfon expansion
planning (system reliability, operating and invesbnent
costs) and automate generation addition decision analys.is.
The first calculation in selecting the generating
capacity to install in a future year is the reliability
evaluation using either percen-c installed reserves or loss-
of-load probability (LOLP).. This answers the questions of
"how much" capacity to add and 11 when •e it should be in-
stalled. A production costing simulation is also done to
determine the operating costs for the generating ;system with
the given unit additions. Finally, an invesbnent cost
analysis of the capital costs of the " unit additions is
performed. The operating and investment costs help to
answer +-.he question of ''what kind11 of generation to add to
the system.
The next three sections review the elements of these
c9mputations.
Reliability Evaluation
Historically, electric utility system pl~nners measured
generation system reliability with a. percent reserves index.
This planning design criterion compared the total installed
generating capacity to the annual peak load demand. H.ow-
ever, 'this approach proved to be a relatively insensitive
indicator of system reliability, particularly when comparing
alternative units whose size and forced outage rate varied.
Since its introduction in 1946, the measure that has
gradually gained widest acceptance in the industry is the
"loss-of-load probability. •• The LOLP method is a probabi-
listic detennination of the expected number of days per year
on which the demand exceeds the available capacity. It
factors into the re1iabili ty calculation the forced and
planned outage rates of the units on the system as well as
their sizes. ·
Computing LOLP requires an identification of all outagii
events possible (in a system with n units, this means 2
events) and then a determination of the probability of each
outage event.. However, since LOLP is concerned with system
capacity outages and not so much with particular unit out-
ages, the probability of a given total amount of capacity on
outage is calculated.. This information can be presented as
a "cumulative capacity outage table 11 as shown in Figure· 1.
-1-
••
I
I
I
I
I
I
I
I
I
I
I
I
I
I I
I
I
I
I
CUMULATIVE PROBABILITY
OF MW OR MORE ON
OUTAGE
1.0
0.1
0.01
0.001 TOTAL
INSTALLED
CAPACITY
0.0001 '
' ") O.O~OQIL------------------------~------rl.
MW CAPACITY OR MORE ON OUTAGE
Figure lo Cumulative Capacity-Outage Table
t CAPACITY_ MODES]
OUT'AGE
OR GREATER
0 MW
10
20
30
40
50
•
CUMULATIVE . .
PROBABILITY
MW
LOOOO
0. 6342
0.3719
0.2463
0. 1986.
4--,
' ' 't
LOLP
·I
I
I
J
I
t = L PROBABILITIES
INSTALLED CAPACITY
HOURLY LOADS
HOURS
Figure 2. LOLP Calculation Procedure
-2-
"
ONE YEAR
\~ '
0
I·
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
Utilizing a highly efficient recursive computer technique 6
these capacity outage tables are calculated directly from a
list of unit ratings and forced outage rates.
The LOLP for a particular hour is calculated based on
the demand and installed capacity for that hour. The re-
serves are given by capacity minus demand. on this basis, a
Cieficiency in available capacity (i.e., loss of load) occurs
if the capacity on forced outage exceeds the reserves. The
probability of this happening is ·read directly from the
cumulative outage table and is the LOLP for a single hour as
shown in Figure 2.
In addition to calculating the percent installed re-
serves, OGP can also calculate a daily LOLP (days/year) and
an hourly value (hours/year). The daily LOLP is determined
by swnming the probabilities of not meet~ng the peak demand
for each ¥-"eekday in -the year. The hourly LOLP is calculated
by summing the probabilities of not meeting the load for all
the hours in the year. These two values are not related by
a factor of 24 because a deficiency for the peak hour of the
day does not necessarily imply a deficiency for the entire
day.
The discussion above proc·eeded on the assumption that
the hourly demand was specified deterministically. The in-
clusion of load forecasting uncertainty can also be impor-
tant and has be~n integrated into the OGP computational
procedur~. At each demand point in Llie unce.rtainty distri-
bution, the LOLP is calculated. The equivalent ·is then
determined by weighting the· LOLP result at each demand point
by the probability distribution value.
Utilizing this technique, generation · planners can
design the generation system to a specified level of relia-
bility. As the demand grows through time, generation addi-
tions are automatically timed by OGP such that the LOLP does
not exceed the design criterion.
Figure 3 plots LOLP versus the annual peak load for a
specific generation system. As the graph indicates, lDLP
varies exponentially with load changes. The design cri-
terion in this case is 0.1 days/year. .For the 1985 pe.ak
load indicated ·on the graph, the generation system is at a
level of reliability better than 0.1 days/year. Therefore,
no additional capacity is required.
ln 1.986, the ahnual peak has increased to a point where.
the generation system cannot maintain the desired 0.1 days/
year LOLP. In anticipation of this, a unit· addition would
-3-
••
I
I
I
I
I
'I
I
.I
I
I
I
I
I
I
I
I
I
I
ao.o
ORIGINAL.
SYSTEM
1.0
I QJQ
0.01
1985 1986
;
WITH
1986
UNIT
ADO IT ION
DESIGN _____ ,_
CRITERION
0.001·'-·-· ---------------
ANNUAL PEAK LOAD -MW
Figure 3. LOLP vs. Annual Peak Load
-4-
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
be scheduled for 1986. What happens to the LOLP versus peak
load curve?
With the new unit addition installed, the curve shi.rts
to the right as in Figure 3. In 1986, the LOLP has de-
creased from l. 0 days/year to about. 0. OS days/year because
of the unit addition~ This is below the desired 0.1 days/
year criterion established by the utility system planner and
hence the unit addition process is completed in tha~year.
Production Simulation
Once a system with sufficient ~Jjenerating,_ ~(ipaci ty has
been determined by the reliability evaluation~ · the fuel and
related operating and maintenance (O&M) costs of the system
must be calculated. OGP does this by an hourly simulation
of system <bperation.
The program commits and dispatches generation based on
economics· so as to minimize costs. _However, the user bas
b'1e option of biasing or overriding the normal economic
operation of the .. system. This can be accomplished in two
way~;. The user may specify weighting factors for various
environmentally related quantities such that the program
will operate those units to minimize their impact. The user
may also limit, on a monthly basis, the number of hours that
units may run or the amounts of different fuels that may be
consumed.
•
The production simulation in OGP is performed in six
steps: load modification based on recognition of contrac-
tual purchases and sales; conventional hydro scheduling and
its· associated load modification; monthly thermal unit
maintenance scheduling based on planned outage rates; pumped
storage hydro or other energy storage scheduling; thermal
unit conunitment for the remaining loads based on economics
and/or . environmental factors, spinning reserve rules, and
unit cycling capabilities; and unit dispatch based on incre-
mental· production costs and environmental emissions. The
production simulation is for a single utility system or
pool. Unrestrained power transfer capability is assumed
between areas or companies internal t~..., the pool represented ..
Purchases and Sales
The OGP production cost load model is an hour-by-hour
model of a typical weekday· and weekend day for ·each month,
arranged in monotonically decreasing order. These hourly
loads are modified to reflect the firm purchases and sales
between the area being studied and entities outside that
-5-
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
·I
area. Each contract has associated with it a demand charge
($/kW/yr) and an energy charge ($/MWh).
Conventional Hydro Scheduling
Hydro energy generally bas ·a very . small . incremental
variable cost and, therefore, in OGP it is used as much as
possible so as to minimize· system operating costs. There
are two types of conventional hydro. First, run of river
hydro is typically an installation which has a low head and
minimal storage. These units tend to be base loaded since~
the river and dam characteristics dictate that the.unit must
be running roost of the time. The second form of convention-
al hydro is pondage hydro, -characterized by a significant.
volume of storage. · ~ondage pydro units are usually sche-
duled during peak load time periods because it is during
these periods that the system's incremental fuel cost is at
its highest. Thus, the pondage hydro is scheduled to shave
pe:tks. !n scheduling conventional hydro, attention must be
given to the fact that hydro capability is affected by
seasonal conditions.. This is handled in OGP by specifying·
data on a monthly basis.
Thermal Unit Maintenance
On a utility system, the planned maintenance of indi-
vidual units is usually performed on a monthly basis.
Puring these periods, the units are unavailable for energy
production. Maintenance scheduling is normally done so as
to minimize the effect on both system reliability and system
operating costs. A common· strategy for scheduling main-
tenance, and the method used in OGP, is the levelized re-
serves approach. Basically, the monthly peak loads are
examined throughout the year and incremental amounts o£
generating capacity maintenance s·cheduled to try and level .....
ize the peak load plus capacity on maintenance throughout
the year •
. Increased maintenance levels which might be required
during the first few years of a unit's operation are modeled
using an immaturity multiplier. OGP also allows the user to
annually input a predetermined maintenance schedule for
units for which this information is available.
Energy Storage Scheduling
Although very often applied to studies of pumped stor-
age hydro, OGP may also be used to study other types. of
energy storage on electric utility systems such as bat-
teries, thermal storage, and compressed air storage.
-6-
I-
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
Recognizing losses in the cycle, generating and charg-
ing energy is scheduled to maximize the savings in system
prcduction costs on a weekly basis. Energy storage units
are assumed to be fully charged at the beginning of the
week. Incremental ~amounts of generation . are balanced by
enough charging to fully recharge the·unit by the start of
· the next ~week. Because of the nonlinearity in system oper-
ating costs, the energy storage units can operate so as to
decrease costs despite a cycle efficiency less than 100%.
Thermal Unit Commitment
After modifications for contracts, hydro, unit main-
tenance, and energy. storage, the remaining loads must be
served by the thermal units on the system. In OGP, the
units can be committed to minimize either the operating
costs, as is usually done, or some combination of user
specified environmental factors and operating costs. The
operating costs are calculated from +l!e fuel and vari~h1e
O&M costs and input-output curve for each unit. Fixed O&M
costs do not effect the order in which units t~:re committed,
but are included i:rt the total production cost. ·
Figure 4 illustrates the type of input-output represen-
tation used by OGP to model the thermal characteristics of
generating units. This model specifies the fuel input in
Btu per hour as a function of the electric power output in
megawatts. H~wever, performance economics are dictated not
only by the heat input but also the price ($/MBtu) of the
fqel used by the generating unit. Therefore, the cost
characteristic relating fuel cost per hour to power output
is simply the product of the beat input characteristic and
the fuel pric~.., In addition to the fuel input versus power
output specification, the maximum and minimum output are
specified as operating limits.
The environmental quantities that OGP can factor into
the operation of the system along with the operating costs
are: heat rejection into the atmosphere, heat rejection
into the cooling medium, so emissions, NO emissions" CO
emissions, particulate ernis~ions, and wat~r consumption.
Figure 5 shows that these characteristics are modeled much
like the unit heat rate.
The unit conunitment logic determines how many units
will be on-line each hour and also attempts to provide an
adequate level of operating reliability while minimizing the
system operating costs and/or envirorunental emissions. The
operating. reliability requirement is met by committing
.sufficient generation· to meet the loa·d plus a user specified
-7-
------.. -------------
I
co
I
i 1
FUEL INPUT FUEl. INPUT · .
(~~) <!r>
I
I
i
!
' ..,.,.
'MAXIMUM MINIMUM
. .
1 i
,
INCREMENTAL INCREMENTAL
FUEL INPUT FUEL INPUT
(~) (~)
MW CUT PUT
Figure 4. Generating Unit Input-Output
Representation
i
EMISSIONS
(lba) Dr
f
I I
l I
I l
I
MINIMUM 'MM(i~UM
l
A
I
INCREMENTAL
EMiSSIONS
(~)
j
" MW Me:tUT
Figure 5. Generating Unit Emissions
Output Representation
r.·
I
;I
~
:·
I
I
I
I
I
I
I.
I
I
I
I
I
I
I·
••
I·
spinning .reserve margin.. Units are committed in order of
their full load energy costs or emissions, starting with the
least expensive. ·
This comrni tment is then reviewed to determine if the
thermal cycling capability of any units is being violated.
If so, this-preliminary commit.mentwill be modified to keep
such units on line as ma~r be dictated by their cycling
restrictions.
Thermal Unit Dispatch
·If a unit is committed, the unit's minimum loading.
level reguires that its ou·tput be at that level or higher ..
Y.'hen the final comrni tment has been establishe.d6 each unit
will be_ loaded to at least it 1 s minimum. Typically the. sum
of the minimums does not ~~qual the load. Additional load
will be se;rved by t.he uni·t:s' incremental loading sections.
The dispatching function i.n the OGP production simulati'.>D
loads the incremental sections of the units conunitted in a
manner which serves the demand at minimum system fuel cost
or emissions. This dispatch technique is the equal incre-
mental cost approach.
Figures 4 and 5 also show the incremental fuel cost and
environmental emissions models used in dispatching the
incremental loading sections to serve the load.
OGP can model the forced outages of units either deter-
ministically, by extending the planned maintenance period,
or stochastically. In the~stochastic dispatch, the program
recognizes. that. units will be out of service in each zone of
constant commitment for a period of time proportional to the
forced outage rate. The load previously served by these
units will be transferred to higher cost units. This usu,al-
ly requires the commitment of additional generating units.
If additional units are not available, emergency tie energy
will be supplied at a cost input by the user.
Fuel and Energy Limitations
OGP.has the option of performing the production simula-
tion subject to additional constraints. The amount of
energy to be generated each mont.."l by each unit or the quan-
ti ties of the different fuels consumed in a month may be
limited. If any limits are l;'eached, other, less economic
units will be conuni tted and dispatched as needed.
-9-:
I
I
I
I
I
I
I
I
·I
I
I
I
I
I
I
••
I
I
., .I
lnve·stment Costing
The investment cost analysis in OGP calculates the
annual· carrying charges for each generating unit added tc
the system. This is computed based on a $/kW installed
cost, a kW nameplate rating, and an annual levelized fi~ed
charge rate. · ,_
OGP Optimization Procedure
.
Figure 6 outlines the procedure used by OGP to deter-~
mine an optimum generation ~xpansionplan.
For the year under study, a ·reliability evaluation is~
performed. This determines the need for additional generat-
ing capacity. If the capacity is sufficient, the program
calculates the annual production and investment costs,
prints these values, and pro~eeds to the next year.
If. additional capacity is needed, the program wili add
units from a list of available additions until the relia..-
bility index is rriet. This list can contain up to six ther-
mal types and three types of energy storage units. These
units can be added both by themselves and· in combinations
wii;h other types of generation. ·
For e·ach combination of units added to the system, OGP
does a production simulation and investment cost calculation
for the year under study. The program uses the information
gained from the cost calculations to logically step through
the different combinations of units to add, eliminating froa
consideration combinations that ~ould proc;luce higher~ annual
costs than previously found. This process continues ur,.til.
the expansion giving the lowest annual costs is found. The-
selected units are added to the system, and the program
proceeds to the next year of the study. .
In cases where operating cost inflation and/or time
variation in unit outagn~ rates are present, the OGP optimi--
zation logic utilizes .:t "look-ahead" feature. The look-
ahead f'eature develops levelized f'uel and _O&M costs and
mature outage rates for use in the economic evaluation. As
part of the output information available, the user obtains
documentation of the relative costs of all the alternatives
exa.mined. After the generating unit selection, the reli•
ability and costing calculations are repeated for the chosen
alternative so that the expansion report available for the
user contains the correct annual values.
-10-
I
I
I
I
I
I.
I
I I
EVALUATE
lOAD I G.i:NERATlON ] I STUDY ~ ']
FORECAST ~~-~~-~·~..-.-Y~S~T-:"Eo-::-.M~~-----· ·._ ___ o_A ...... T_A ____ ._·...,.~
EXISTING UNITS &
HOURLY BASED AlLO\\'ABLE
PEAKS & ENERGIES TECHNOLOGIES
FUTURE ECONOMICS &
OPERATING GUIDELINES
: -"-4--. . --" .. .,-z= ti •. ; . , .....:__ ... _ ...... ::::::::t:::t:;::;c:;:a::z::; ........ D_
· OPTIMIZED GENERATiON PLANNING (OGP) --:r:,.,.......... .. -... :. =i=·· ::. -=-r-;; . =: ~-;;-: 1 =· .. ~· '
EVAlUATE RELIABILITY
...
ALL CHOICES I WITH "LOOK-AHEAD"
t
I
I
SELECT UNIT SIZES & TYPES
I
CALCULATE OPERATING & INVESTMENT COSTS
]
STUDY
ALL YEARS
I
I
I·
I
I
I
I
I
I
·I
USING ,.LOOK-AHEAD .. : < ' ,,
•
CHOOSE LOWEST COST ADDITIONS ~
& CALCULATE CURRENT YEAR'S COSTS
• ~· ..
~
..
RESULTANT OPTIMUM EXPANSION PATTE&iN
& DOCUMENTATION OF NEAR..QPTIMUfw1 PLANS ----·. OUTPUT
;a .. 1. I c I
FINANC1AL ANALYSIS Of EXPANSION PLAN r----OUTPUT
Figure 6. Optimized Generation Planning (OGP) Program
-11-
I
I
'I
I
I
I
I
I
I
I
I
I
I
I
'I
I
I
'I
·I,
Sarnole.Output Results
·-.' ,_ -
' The ubottom line" result from the OGP program is the
annual summary of additions. Figures 7 and 8 present the
annual capacity additions by type (nuclear, coal,· gas tur-
bine, etc.). For example, in year 1995, the · OGP prograa
added in this sample run one 1300 MW nuclear uni't and two
300 MW ,blocks of gas turbines as well as 500 MW of purriped
storage hydro. The generating units indicated with an
asterisk ( *) are those units which have been previously
committed for service. For example, in 1984, a 1200 MW .
nuclear unit and a 500 lriW battery storage unit are committed
for service.
At the bottom of the additions · report, a summary is
provided. The first. row is the sum of megawatt additions
and retirements (MW ADD and MW RET) during the period.. The
second row is the capacity in service in 1998 (end of the
study).. The third row is the MW additions that were added
automatically (AUTO) by the OGP program (total additions
less committed additions).
Other summaries are also provided by the program.
Figure 9 presents the load, capacity, reserve, LOLP and cost
summary.. Figure 10 presents a more detailed cost summary
both on a yearly basis and also on a cumulative present
worth basis.
OGP also makes available more, detailed yearly and even
monthly results. One of these results is illustrated in
Figure 11. This is the annual production cost summary and
illustrates the annual history ·of each generating unit's
maintenance period, hours on line, capacity factor, fuel
cost, etc.
At the bottom of. the page, the energy output, capacity
factor, and fuel cost results are summarized }?y generating
plant type (nuclear, coal, gas turbine, etc.).
Other summaries are also available . including annual
fuel· consumption by fuel type {nuclear, coal, oil #2, oil
#6, natural gas~ etc.), and annual environmental summaries
(water consumption, so2 " and .Nox ernmissions, etc.).
While these summaries are examples of OGP program
output, a complete printout would include a formatted list•
ing of the input parameters and other useful displays of
information ...
-12-
I'
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
..
GENE':.~Al EI,ECTR I C:: _COMPANY
~,GP:-~ GENE:. RAT 1 ON .PLANrH N~ r-ROURAM ·SUMMARY OUTPUT
•••••••~••~~z=~~-~~••~•~~~~~••,••~•,•••:•••x••••
O~P-$ £l.EC.TRJ C $YST;::M .
USERS MANIJ,.t_ .t;:}tA11PLE
JOP NUMBER . 249395 03/14/79
GENERATION SYSTEH
NUet.. F-COAL O.T.
TYPE 1 2 3
O?TMZ J N.:~ 1 989 19&7 1979
PCT TiUM 2S 2S 0
1978 N~ 5005 .4781 702
STAG C-COAL F-CJL TYPES .. ~ 6 7""10
1984 1984 1987 •••
2S 2, 25
600 300 4792 934 Sut1= 171141
•~==~~••~·=~~~~z:•xa~~••r•~~•a•~:za:z~•*~•·~~Z&Z1a~•••:••••==~a•=~~aat•
1'0TAL
C.APAB.
YR YEARLY MW A 0 D ~ T I a N S + TlES
71 22St 2X a 50 1 8367
80 1200• 2X 1 50 1 SS44
_s~'------~~~~--~7~o~o~·--2=x~~'~5~o~----~~------------------------~2~o~e~o~4~-------------
52 1200* 400• 22289
83 1 200a 1X 150 23514
84 1200• sooa 25214
as soo 25534
86 sooa
87
a a
e9
90
91
92
93
94
95
96
97
98
2Xl300
2)(1300
2X 300
1X 300
1X 300
3X 300
1X 300
1X1300 2X 300
2X1300 2X 300
lX\300 lX 300
2.>'1300 2X 300
2X 41:)0
3X 400
3X 400
1X 400
500
600
1300
500
100
300
300
500
100
300
100
26554
27509
28778
30378
31863
34~48
3ea48
37902
39410
41647
4~527
46777
4S761
az~az=••~•s••••~••~••••=~•=•~••••••••=••••~~•:~r•~··~•••~•••••••r:ll:zswa~a
Zll:!tl£lt:11'1'S"t:lts:•KltSSS~ZZS:VtliiS"tZ!Ir2Slil%llSll"::.'lll:*lol:llr3i:ltlrlltltSSSI::r:::~~tll:ll''llZS:R2Z:::zzsaa
MW ADD
M"J RET
a:sssas
1998
PCT TOT
7400
0
tJESZSt
1240S
25.S
11375
-1455
Sll·.ll::ll::ltlf
14701
30.2
62!52
12.8
4000
0
4SOO
9.4
0
0
300
0.6
0
-1373 ••••••
3419
7.0
34425
-2828
aaaa ***••••••••
7034 Sl.Jtti: 48711
14.4 SL-r1~100 PCT
za:ast8~sxsaszs:t•z••~•••rsa%::•••••••••••••••s•*••••~=•,.•~•••~~~~aazaaa
AUTO 2600 10400 5550 3600 0 0 5100 SJ.Jt1: 272t50
PCT TOT 9.S 38.2 20.4 13.2 0. 0. 18.7 SlJM:100 ·PCT
• '='Ot-1M1 TTED MW
Figure 7. Annual Capacity ~dditions· by Type
-13-
I
I
I
I
I •
I
I
I
I
I
I
I
I
I
I
I
I
I
.I
GENERAL ELECfRt C COt1PANY
OGP•5 GEf''ERAT10N ?I..AN!il~G PROOP..J:..M-SUMMARY OUTPUT
saY~·•~aa:saa:~:••••~~·••gr~=•••~•••••~••••~~•••
. . " . . . ·---------.....------
OGP-~ ELEC~RJC SYSTEM
US£PS MANtJtaL EXAf-'i?LE
.. Je$ NIJt1~ER 2"939$ 03/14/79
GENERAT I f.N SYST.EH
THERMAL HYDRO PSH
TYPE 1-6" 1 a
OPTMZING ••• 1984
PCT TRJH 0
1978 MW 16190 310 624
BATHES COMPAfl!
S) 10
1984 1984
0 0
0 0 SUMs 17114
ax•~•~i~ar~s~a~a~a:xxzxssa:sx:asxa*•••••s:aaaaaaz~x••~~•••aaaa~ss:aazaa
TOTAL
CAPAB. LOAD LOL.P
YR y E A RLV MW A D D I T J 6 N s +TJES MW D/Y
SJI ···=·· aaazat &xaa::s sss:ssa •&lil:ll •• •::nr••• ltliUl'llriC as•••••
79 525 18367 1~091 0.41~3
80 1500 19S44 14SG6 0.3813
81 1050 2080.4 15684 0.4021
82 1600 222&9 l£\546 0.3362
83 1350 23514 17456 0.45S1
84 1200 SOO• 25214 1a,ns o. 24541
55 !SX 100 2558~ 191129 0.4728
as 5X 100 sooa 2G5a4 20498 C:.4290
87 600 6)\ 100 27509 '21625 0.~926
88 13X 100 28778 2281., O • .l:S:30
89 1100 5X 100 30378 24059 0.3~91
90 1500 1X 100 31963 25393 0.3380
91 2600 34348 25790 0.4140
92 2500 36848 28263 0.3910
93 900 3X 100 37902 29818 0.478~
94 1500 3X 100 39410 314~3 0.46£13
9S 1900 5X 100 41647 33188 0.<498
96 3200 tX 100 44627 35013 0.4217
97 2000 3X 100 46777 3C939 f). 4S51
98 3200 1X 100 • 49761 38970 0.4303
~•••*•zz::z~szz:••=••~~•••~==~z::xx~xt%tza~xxxw•:=s•~•~~*zzzxsz~=•••~••
···········==·=·······~····=·~·~······~············~·~··~·==~·==~···=·· MW ADD 28325
MW RET -2828
•••••• sxzzsas
1998 41677
• PCT TCSl 85.6
AUTCJ 22150
PCT TOT 81.3
• CO~'iMl TTEC MW
0
0
z:a:•aac
310
0.6
Figure 8.
5i00
0
ltllflt:ll:llll:
5724
11.8
S100
18.7
500
0
z::raan
500
1 .0
0 o.
500 SUM11: 3442S
0 SJ~~~ -2828 •••••• ······*=···· !SOO SUM= 48711
1. D sur-,= 100 PCT
0 SUM• 272~0
O. SUM= 100 PCT
Annual Capacity Additions by Tl'Pe
-14-
..
I
I
I
'I
I
I
I
I
I
I
I
I
I
I
I
GENERAL ELEC1RtC COMPANY
OGP·5 GENE~AT 1 ON PL.At-:Nl'.fG ?f\OGRAt1·SUt1t1ARY OUTPUT
•••••~•·~~•a~~·,·,~~-~;•••~v•,••=••••••••=•n~•••
OGP""5 ELECTRIC SYSTEM
USZRS l'1ANUAL EXAM?LE
JOB NU!1SER 2493()5 03/14/79
YEAR
li!ZlkW
1979
1980
1981
1S82
1983
1984
19a5
1S86
1987
1S88
19S9
1990
1991
.1992
1993
1994
1995
1S96
1997
199&
tOTAL CAPABILITY
CINCLUOlN\3 TtESl
YEAR TlM£ OF PCT.
LOAD END PEAK RSS.
14B66
1SGS4
16:546
17456
1841 (;
1S429
20498
2162S
22814
240Sg
25393
?6790
26263
29818
31458
33188
35013
36939
3e970
Zlk«E:a
113422
19384
20544
22'329
23~54
25254
25524
26524
27549
26S18
30416
31303
343SS
. 36S88
37:l42
39450
-41S87
44567
46817
<98{)1
:..-.::t••
'j 83.67
·19844
20804
22289
23514
25214 esss4
·25584
27609
28778
30378
31S63
3~~.48
36648
37S02
3S?410
41647
4.d627
45771
49761
••••
30.~
33.5
:_\2.6
34 .. 7
34.'7
36.S
31.7
29.7
27.7
26.1
25.2
25.2)
28.2
30.4
27.1
2~.3
25.5
27.5
26.6
27.7
LOSS OF LOAD
PROBABILITY
D/'i . H/Y
0.381
0.402
0.33Q
0.455
0.245
0.473
0.429
0.493
0.483
0.339
0.338
0.414
0.391
0.478
0.470
0.450
0.422
0.45~
0.430
0.53
0.48
o. :n
o. 4112
o.~a
0.31
0.59
0.52
0.58
0.56
0.38
0.37
0.47
0.45
O.S4
0.52
0.49
0.46
0.50
0 .. 47
COST tN MIU.hJH S
YEARlY CUM.. PW
COST TO'f.AL
Zlit'•~···
1207.8
1547.0
1.827 .. 0
2236.2
2G-;2.S
3146 .. 7
33~8.3
3754.7
4184.,
4731. ~
S:l64.5
6059.1
7233.1
8~91.6
930&.6
104~1.8
120~3 .4
137r.o. 1
15577.5
17r9~.6
WW::'J(:tJl.
1nsa.o
2376.5
3749oS
5277.0
6924.2
8700.<4
10444.2
12l95.8
13970.3
15794.4
1 767-~ •. 6
1!351.3.0
21713.2
2~922.9
26151.3
2f!-..~27. 7
30$06.5
.3328'11.4
3!'S2a.4
~8455.7
Figure 9. Summary of Load, Capacity, Reserve,
·LOLP, and Cost
-15-.I
l~· ..... ........___..... ~~. ' . .Y . ·-· ·-·-·~ .,,:.· ....... ···-'···-·'····.<-.· ... -··· ..•.•... ; ,,,_ ... , ..... ·"·-·-·-·•'--'"-·.-····· -···
-~ -----------'l!=NI!ftAI, lrLECTrll C,, COMPANy. QOP•lS GEN£RrlTJON PLANNING PRt'JORAM
'OP·~ ELECTRIC SYSTEM
JS~RS MANU~L EXAMPLE
POOl. TOTAL YEARLY COSTS (MJL.LION S)
PEAK ENERGY LOAO • a••••••••• !l*• .. ••••t***·it•~•• a••• • •••••••·• •a• ft!AR <MWl fG~!Hl FACTOR INVEST. FUEL O+M
Ul11 il ....... S«*~".,•••• e•••••• ........ s••*m•• •a••••• f979 14li'591 • 74061 .4 60:00 24.5 .997. 0 1Ss.2
J900 148GG, 7s::Ms, 9 60,00 24G.l 1085.0 176,2
1901 l!'3GS4. 02432:.~ 60,00 304,4 '1228. 3 192.7
1~£!?-1~6. ('!.ft966.L 0 so,oo 633&.8 1 333'-G 215,0
'~l'\.3 1 7" ~\(·. 9174!}. 0 GO,OO 896.0 '451 • 2 239.2
1904 104\6, 97061,3 60,00 1235.2 1ti03,0 2G7~5
I !HH~ 1911~!9. 10~1?.0,2 so.=-oo . 1272,0 17t\9,1 200, G.
1900 20-1981 107735 2 4 oo.oo 1352 1 7. 2012.7 P-9719
l9:.l7 21625. 11 ~002. 2 60.00 1427,G 2345.2 313.9
1900 22014. 120241 • G 60,00 1509.8 27~4.4 333$4
1909 2·10C9, 12C.SOO,G GO,OO 1077. 1 3214.2 31;2.a
L~9o· P5~2_;l. ,~~t/166.2 G0 1 0Q 182':7.9 3750
1
4 __ 397,2 -· .... -1991 ~(;7!)0, t4'101JOG.,2 GO,OO 2,1:)5. 3 4 ?.?.!>. 4 443.2..
1992 2cl?G3. l4CS!l6,2 oo.oo OOSG,O-471 \. 3 490,3
J99n 2!\0lO. \5&722.0 GO,OO 31-15.2 t)l190.7 530, G.
109411 3.}!1~.)6. 1 Gfi341 1 3 so,oo 3352.2 G:l81 1 1 ts75, 2 I .. ' . • 33 \flO. 174434 ~ 9 60.00 4028.5. 7173.2. 639.2
I 3tl013• 1611t\33014 GO,OO 40(10.0 7990.0 708,9 .... 36~39, 1 ~M 1 GO, 0 so.oo ~u42.G 8$\20.6 763.1
Cl'\ 3B9?0, 204828,& GO.OO ti303.ts 1000l5.tS .860.3 I ..
CUMULATIVE PRF.SENT WORTH CMlL.LlON S)
s••••••a•••~••••••••~••••••,*•••••••••••••••
_...._.:.V..:::E[\ ... R INVEST. . FUEL O+M NUC t NV TOTAL •••• ····~·· ···~··· ....... ···~··· ....... . 1979 22.3 . 906,4 142.0 27.3 1096.0
1900 22~.7 \803,1 287,6 G0,1 2376.~
= 190\ 4~9.5 27~5.9 432.4 91.0 3749t6
1902 932:4 3G3G,8 57973 128.~ 5277,0
1903 1486,7 4537,9 727.9 1G9,7 69~4.2
1904 2166.0 ' 5420.4 878.9 215.2 8700.4
---.:1...;90t'l 2639. t G~23. 1 1 022. 8 • 239. 2 1 0444. 2 19~0 3470.2 7262.0 1161.8 301.9 12195~8
1907 4075,G 8~~G,O 1294,9 343,2• \3970,3
1900 4GG9.3 9318,JS \423,~ 363.2 1&794.4
---:tgoq ~2~7,.. 1 104145, 1 1sso.·o 421.9 17674. s
fgijo tHi39,5 tlG42,0 1677.2. ~59:3 19618,0
1991 Gt\44,9 ·12t\G7.1 1005.0 495.6 21713.2
1~92 7349.0 \4107.7 1934.7 530.7 2~922.9
__ ,..1.9!1:\~-:·f\~1Q2 1,n 1.~?::a·~1::---:2=-:0-G\ .7 . 564 8 2G1t51 ~
. Cgh;, 8632.3 1001 o. 9 21 oa. 9 597.7 201'127. 7
19P5 no~g. ~ . -18230, o 231·a. 3 G33. a 30ooo. c:s
1 ll9G 1 Ot\04. G 1 9GG7,1 .2440, 8 G(Hl• 8 33261.4
f
NUC J NV TOTAL
• •••••• ••••••••
30,0 1207.8
39,6 1!547. 0
42.2 1627.6
5~~,7 2:!36.2
66t4 265279
00,6 3l4G,7
83,8 3!196,3
91 1 4 3754.7
97.4 .41 84. l
103.7 4731,:)
11 o. 4 ~3G4,5
117,6 6099. 1
125.3 7233. 1
1.33.4 6~01 '0
l.tl2.1 9306.0•
151,3 10459,0
182.5 1?.02!).4
194i4 , ~700, 1
231.2 · H~n7'1rU
246,3 11093,6
-------PAGE 78
24939S
0311Jtl79
YEARLY COSTS (S/MWH.)
• ••• •• ta IJ'l • • ast • •• 11 • • •••Iii••• • •ta.s • aa*:ftltt;• • • c
JNV .. FUE~ 0+11 N. 1 • Ttt'!t:AL
••• ll •• ···g·"' ....... • ••••• JIJt:.lt;;lt''ll. :a
0.3 13.~ 2. 1 0,4 tl\6. 3
3. 1 13,8 .2.2 o.~ n;g.?
4.4 14,9 2.3 0.5 ~.2
7\-3 1_~..£...3 2-~,..5 O,G ~:s. 7
9s8 1!5,6 2.6 0,7 :2879-
12.7 .. 16. 1 2.0 0,6 :J2,4
. 12.5 17&2 2 •. 7 o,e 03.0
t2.G 18.7 2.8 o.a ~:it·. 9
12.6 20,6 2,8 0.9 ~G. a
12.8 22.9 2.0 0,9 ~9.3
13.3 25.4 2,9 0,9 4l:2. 4
13.7 '20. 1 3.0 Ot..,9 41~ 7 -....,.... . -
17,3 ao.o 3. 1 o.9 ~1 ~ 4 .2o. a· 31 • G 3,3 0.9 ~t;.3
20.1 35,0 3,4 0.9 ~~~4
2013 30~_G 3~5 o.s ~!3.3
' . 1-;'0 ··~s. 9 23. 1 <41 I 1 3.7
2.0.4 4:l,3 3.8 1 • 1 '7.7-4 .. G
?.9. 1 • .tt~.9 4.0 1. 2 l!ro. 2
32, 1 48,,0 4 .. 2 1,2 6'0~.4 ..
----~19~n~7~·--~1~1~~~2~7~,3~~2~1~1~2~S~1~7~~2~S~G~9•rg~--~7~~HG~·~6~~3~&~~~~8~,~4~----------~--------------------------------------------~-------1VD8 l2400,9 22G13,0 269&.e 743.2 :J04'~8.7
Figure lOo._ rietailed sUmmary of Costs
--------------------~---------------------~------------------~-
-~-~~-~-.-. ~ -~~~. -.-..,..,-~--~,.,.---~-~~~......,__,.__,._,...__,...,......_...,...,.,.,__..,...__,...,....,....,........,_.....,......, ...... ..._
2~~~~
Ol/~!'i'?l
I:"'!')HU\1'\ ~ ~------------~~--~~~------------~-----------=~~~------~--------------------~------------~------------
1tRiU 1CFI'V J"~
S"IN~UitJ ltESEJ'tV£
~'~~$. 1'1W
~2.00. HW
l -~-,-,-.,-s-1~A~.-,-e~~-h~k-"pc--~~.-~u~~-~~EL AA11N~Alh1~GA~a Rlh-E~~~~~ft~a~v-~~~R~s-.-~c~x~PTA~e•naY-F~o~a~-~c~P~E~R~.~.-~r~u~tr~~r~e~~~e~£~b~,,~u,_T~~~~~~~.,~u~~~
ID !OEHT. TYr'L ~NPt ttW ,_TMH~ ~~'THS'" OUti"IJT CtN ~ACTOR C03T KAIHT. IJNT. OtJlM! CUTAG~ PllliCC
~lA.! f'IWH LUC ceSTa COST$ tu.tt MTE •1r-:a1U
I
I
Si 6-u~ -~~~ CS
4 1!-Ct.~OIIl 01
~S ~E-~ON 02
~~ ~R:N~l£11l 02
::s
::rs
I ;! ···c. 18 ~T,AT£
15 PA"ISO"
r..~;;.$r;.R
E::I:SON
EDISON
f":S.SEIIt
:z
t
2
:!1
J.JO.G c :X:ndt.
131 .o 0 !li:W.
7~0.0 1
621.0 0 FES.
100.0
7SO.O 0
22~.0 Q 0
:SSiJ.D 0 Owl •
~~0.0 0 S£1-T~
117.0 0 .JAN.
\!lO,O 0 .1UH£
2 t,7CZ3£. ::Svil.
~ 810P::l&. 7638.
2 •c=:e:J:J~. ~727.
2 3.e6676~. 7•73. ,. ::s.
su-T.
c. .
l510~25.
363:J.e.sa~
SE,.T. g~~l5:1.
2~3 .. 14.
243~=01.
FEa~ -4~710.
s;-....:•21.
1~ ~·:~c~ oa
I .~~s-;l~wA~~~~N~£~~E;P~I;~~b~h--~----~---~~~_;~~~------_;~-=~~~~~~-;~~r-~~~--~~r---~-?r.~~~~~~~--~~~il
'70 G.\$ TU~lN£ EDlseN ~ C.
70 G.II.S TUR.I!UNE EDISON. 3 a.
70 GAS TURBIN£ ~DISON 3 D .
I
I
I
I
CON\1. HYDMJ
P'U11PED HYDJtC
SATTEIU~S .........
TOTAL.
'• . • a 707~ ao. Q.OOl
388.
t t 2":l767Z.
2208000.
•11<UIIil81.
-~fHiZ7.
310200.
·nJEL COST
IFit:..lSI'hiJ
7;..c::rzt.
.e.&O.SI7.
c.Oi:J::t.
2CS87. ·•••21.
!le?Silse.
' .
23C2S. tt2A3767Z. 23U51il7~.
• • • •MAN:J4\.. t':.l.lNTE~NCE f".ATTER~•
PTRN J F " A ft ~ ~ A a 0
'1100000000
• • N
0
0
0
1
0
~eTt WHEN USED. PA~-E~~S O~ER~JDE THE
C::~DL:T£t:. f" C ft. •A 1 1N:JCAT'£S
c..
I
• D
0
g
0
0
I
. . .
20Cl. t••· o.
111o
231Sii7<1i. 305521. 87313.
22gea.
" ... THER1'4Al.
IRO ... SXMl I S/H•n
1•~cea. , .. ~,
9«373. 3Z.IS7
520:1. . ... ,.
~:l07.
.9Si13l.
30~~21. 23.22
Figure 11. Annual Production Cost Surr~ary
-17-
-. .
C~OBS o.oca 4.,7»
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
3 -DETAILED GENERATION PLANNING INPUT
e.
I
I
I
I
'I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
3 -DETAILED GENERATION PLANNING INPUT
~
This section presents the input made to the OGP program as used for the
Rai1belt model. The input is presented primarily in tabular form for
reference use.
3.1 -Load Forecasts
To represent load forecasts; a number of individual parameters are
necessary:
(1)
{2)
(3)
{4)
Peak demand (MW) per year
Peak energy (GWh) per year
·' Month to annual ratios per year
Week-day -24 hour load shapes
{5) Week-end -24 hour load shapes
(6 )' Monthly load duration curves.
Items (1) and (2) were supplied by the Battelle Railbelt Alternatives Study
in December 1981. These figures include an 8 percent increase to account
for transmission and distribution losses.. Note that the forecasts
presented in Tables 3.1, 3.2, and 3.3, and used in Susitna analysis are
different than the final Battelle figures due to the· varying project
deadlines.
Items (3) thru (6) were developed by Woodward-Clyde Consultants and are
contained in their final report dated April 1981.
3.2 -Existing Generation, Retirements and Additions
Data to represent the existing and future generat·ion system includes:
(1) Existing thermal generation by type and size-Table 3.4
{2) Existing and pl~nned hydro generation -Table 3.5
{3) Schedule of planned utility additions (1980-1988}-Table 3~6
3.3 -Alternatives Data
The Battelle Railbelt Alternatives studies identified essentialiy three
types of units for consideration as alternative forms of electric energy
generation in their base case:
3-1
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
(1) t.OO MW coal-fired steam
(2) 200 MW natural-gas combined cycle
(3) 70 MW natural-gas gas turbines.
A fourth type of unit, 10 MW oil-fired diesels was also"considered.
Alternative generation parameters are listed in Table 3.7.
Data on fuel price and escalation for the base case runs is presented in
Table 3.8.,
Information on the Chakachamna Hydroelectric project alternative is
presented in Table 3.9.
3.4 -Susitna Data
Data used to represent the Susitna hydroelectric project in the OGP model
is presented in Table 3.10. This data is identical to that used by
Battelle in their studies, but may be slightly different from the final
feasibility study data due to continued refinement of technical detail.
Table 3.10 summarizes monthly average and firm energy for the Watana and
Devil Canyon projects as well as other pertinent Susitna data.
3.5 -Other Parameters
The OGP mode 1 requires many other system and economic parameters to e,xecute
generation planning. The following tables summarize some of the key
variables. Tabie 3.11 lists some of the system parameters for production
cost calculations. Table 3.12 summarizes key economic variables.
3-2
... --,--~,, .. I (
I TABLE 3.1: ALASKA RAILBELT MEDIUM LOAD FORECAST!/ ---fi ........ '"
I :":'·
(MW) (MWH) Year Pool Peak Total Energ.x_ Load Factor
I 1981 574 2,893,000 57.54 1982 601 3,027"000 57.50
1983 626 3,162,000 57.66 I 1984 652 3,296,000 57.55
1985 678 3,431,000 57.77 1986 721 3,636,000 57.57
I 1987 764-3,841,000 57.39
1988 806 4,046,000 57.15
1989 849 4,251,000 57.16
I 1990 892 4,456,000 57.03
1991 910 4,549,000 57.07
1992 928 4,642,000 56.95
1993 947 4,736,000 57.09
I 1994 965 4,829,000 57.12
1995 983 4,922,000 57.16 1996 1,003 5,031,000 57.10
I 1997 1,023 5,141,000 57.37 .
1998 1~044 5,250,000 57.41 1999 1,064 5,360,000 57.51 2000 1,084 5,469,000 57 .• 44 I 2001 1,121 5,661,000 57.65 2002 1,158 5,853,000 57.70
2003 1,196 6,044,000 57.69
I 2004 1,233 6,236,000 57.58
2005 1,270 6,428,000 57.78
2006 1,323 6,701,000 57.82
I 2007 1,377 6,973,000 57.81
2008 1,430 7,246,000 57.69
2009 1,484 7,518,000 57.83
2010 1,537
I
7,791,000 57.86
I
1/ Provided by Battelle, Railbelt Alternatives Study, December 1981.
I
I
I
I
I
.. ---.
":1
I
I
I
I
I
I
I
I
,I
I
I
I
I
I
I ,.
I
I
!ABLE 3.2: ALASKA RAILBELT HIGH LOAD FORECAsrl/ -........
(MW) (MWH) Year Pool Peak Total Energy Load Factor·
1981 598 3,053,000 58.28 1982 647 ~,347,000 '19.05
. 1983 696 3,642,000 59 .. 73 1984 745 3,936,000 60.15 1985 794 4,231,000 60.83 1986 855 4,525,000 60.42
1987 916 4,820,000 60.07 1988 976 5,114,000 59.65 1989 1,037 5,409,000 59.54
1990 1,098 5,703,000 59.29 1991 1,128 5, 85.5, 000, 59.25 1992 1,158 6,007,000 59.06
1993 1,188 6,160,000 59.19 1994 1,218 6,312,000 59.16 1995 1,248 6,464,000 59.13 1996 1,286 6,663,000 58.98 1997 1,324 6,861,000 59.16 1998 1,363 7,060,000 59.13 1999 1,401 7,258,000 59,.14 2000 1,439 7,457~000 58.99 2001 1,505 7,795,000 59.13
2002 1,571 8,133,000 59.10
2003 1,637 8,472,000 59.08
2004 . 1, 703 . 8,810,000 58.80
2005 1,769 9,148,000 59.03 2006 1,848 9,605,000 59.33
2007 1,927 10,063,000 59.61
2008 2,007 10,520,000 59.67
2009 2,086 10,978~000 60.08.
2010 2,165 11,435,000 60.29
11 Provided by Battelle, Railbelt Alternatives Study, December 1981.
II
I
I
I
I
I
I
I
I
I
I
I
I
I
I
••
I
I
I
TABLE 3.3: ALASKA RAlLBELT LOW LOAD FORECAST!/
(MW) (MWH) Year Pool Peak Total Energy Load Factor
1981 568 2,853,000 57.34 1982 586 2,948,000 57'.43
1983 605 3,044,000 57.44
1984 623 3,139,000 57.36
1985 642 3,234,000 57.50
1986 674 3,387,000 57.37
1987 706 3,540,000 57.24
1988 738 3,693,000 56.97
1989 770 3,846,000 57.02
1990 802 3,999,000 56.92
1991 811 4,047,000 56.97
1992 821 4,0~5,000 56.78
1993 830 4,144,000 57.00
1994 840 4,192,000 56.97
1995 849 4,240,000 57.01
1996 . 863 4,320,000 56.99
1997 878 4,400,000 57.21
1998 892 4,481,000 57.35
1999 907 4,561,000 57.40
2000 921 4,641,000 57.37
2001 950 4,784,000 57.49
2002 979 4,928,000 57.46
2003 1,008 5)071,000 57.43
2004 1,037 , 5,215,000 57.25
2005 1,066 5,358,000 57.38
2006 1,102 5,547,000 57.46
2007 1,138 5,736,000 57.54
2008 1,173 5,925,000 57.50
2009 1,209 6,114,000 57.73
2010 1,245 6,303,000 57.79:
11 Provided by Battelle, Railbelt Alternatives Study, December 1981.
-------------------
TABLE 3.4: EXISTING RAILBELT GENERATING UNITS -1980
Installed!/ Rail belt Station Unit Unit Install at ion Heat Rate Capacity Fuel Retirement Utility Name No. Type Year (Btu/kWH) .I.:, 'f. (MW) Type Year
Anchorage AMLPD 1 GT 1962 14,000 16.3 NG 1992 Munici pa1 AMLPD 2 GT 1964 14,000 16.3 NG 1994 Light & Power AMLPD 3 GT 1968 14,000 18.0 NG 1998 Department AMLPD 4 GT 19.72 12,000 32.0 NG 2002 (AMLPD) G.M. Sullivan 5,6,7 cc 1979 8)000 139.0 NG 2011
Chugach Beluga 1 GT 1968 15,000 16.1 NG 1998 Electric Beluga 2 GT 1968 15,000 16.1 NG 1998 Associ at i"on Beluga 3 GT 1973 10,000 53.0 NG 2003 (CEA) Beluga 5 GT 1975 15,000 58.0 NG 2005 Beluga 6 GT 1976 15,000 68.0 NG 2012 Beluga 7 GT 1977 15,000 68.0 NG 2012 Beluga 1 GT 1963 23,440 8.6 NG 1993 Beluga 2 GT 1972 23,440 18.9 NG 2002 Beluga 3 GT 1978 23,440 26.4 NG 2008 Intern at i onil1 2/ Station 1 GT 1964 40,000-14 .. 0 NG 1994
2 GT 1965 40,000 14.0 NG 1995 3 GT 1970 40,000 18o0 NG 2000 Cooper Lake 1 HY 1961 16.0 2011
Golden Valley Healy 1 ST 1967 11,808 25.0 Coal 2002 Electric 2 lC 1967 14,000 2.8 Oi 1 1997 Association North Pole 1 GT 1976 13,500 65.0 Oil 1996 (GVEA) 2 GT 1977 13,500 65.0 Oi 1 1997 Zehander 1 GT 1971 14,500 18.4 Oil 1991
2 GT 1972 14,900 17.4 Oi 1 1992
3 GT 1975 14,900 3.5 Oil 1995
4 GT 1975 14,900 3.5 Oil 1995
5 GT 1965 14,000 3.5 Oil 1995
6 IC 1965 14,000 3.5 Oil 1995
7 lC 1965 14,000 3.5· Oil 1995
8 IC 1965 1.4,000 3.5 Oil 1995 9 IC i§&s 1a~sss ~:5 8\1 l~~§ 10 IC
--.. ------- -- -----; -"'
TABLE 3.4: EXISTING RAILBELT GENERATING UNITS {CONT'D) -
c Installed!/
Rail belt Station Unit Unit Install at ion Heat Rate Capacity Fuel Retirement.
Uti 1 ity Name No. Type Year (Btu/kWH) (MW) Type Year
Fairbanks Chen a 1 ST 1954 14,000 5.0 Coal 1989
Municipal -2 ST 1952 14,000 2.5 Coal 1987
Utility 3 ST 1952 14,000 1.5 Coal 1987
System (FMUS) 4 GT 1963 16,500 7.0 Oil 1993
5 ST 1970 14,500 21.0 Coal 2005
6 GT 1976 12,490 23.1 Oil 2006
FMUS 1 IC 1967 11,000 2.8 Oil 1997
2 IC 1968 11,000 2.8 Oil 1998
3 IC 1968 11,000 2.8 Oil 1998
Homer Homer
Electric Kenai 1 IC 1979 15,000 0.9 Oil 2009
Association Pt. Graham 1 IC 1971 15,000 0.2 Oil 2001
(HEA) Seldovia 1 IC 1952 15,000 0.3 Oil 1982
2 IC 1964 15,000 0.6. Oil 1994
3 IC 1970 15,000 0.6 Oil 2000
University University 1 ST 1980 12,000 1.5 Coal 2015
of Alaska University "" ST 1980 12,000 1.5 Coal 2015 c.
(U of A) University 3 ST 1980 12,000 10.0 Coal 2015
University 1 IC 1980 10,500 2.8 Oil 2011
University 2 IC 1980 10,500 2.8 Oil 2011
Copper Valley CVEA 1-3 IC 1963 10,500 1.2 Oil 1993
Electric CVEA 4-5 IC 1966 10,500 2.4 Oi 1 1996
Association CVEA 6-7 IC 1976 10,500 5.2 Oil 2006
(CVEA) CVEA 1-3 IC 1967 10,500 1.8 Oil 1997
CVEA 4 IJ; 1972 10,500 1.9 Oi 1 2002
CVEA 5 IC 1975 10,500 1.0 Oil 2005
CVEA 6 IC 1975 10,500 2.6 Oi 1 2005
CVEA 7 GT 1976 14,000 3.5 Oi 1 2006
- - - - - --- - - ---- - - --: - -
TABLE 3.4: EXISTING RAILBELT GENERATING UNITS
Railbelf Station
Utility Name
1"1atanuska Talkeetna
Elect. Assoc.
(MEA)
Seward SES
Electric
System (SES)
Alaska Ek1utna
Power
Admi ni strati on
(APAd)
TOTAL
NOTES: (l
GT = Gas turbine
CC = ComQined cycle
HY = Conventiona1 hydro
IC = Internal Combustion
ST = Steam turbine.
NG = Natural gas
NA =Not available
1/ Captibility at 0°F.
Unit Unit
No. Type·
1 IC
1 IC
2 IC
3 IC
I{!
(CONT'D)
Install ect.!./
I nst a 11 at ion Heat Rate Capacity Fuel Retirement
Year (Btu/kWH) (MW) Type Year
1967 15,000 0.9 Oil 1997
1965 15,000 1.5 Oil 1995
1965 15,000 1.5 Oil 1995
1965 15,000 .2. 5 Oil 1995
1955 --30.0 2011
984.0 MW
2/ This value judged to be unrealistic for long range planning and therefore was adjusted to 15,000
for generation planning studies.
-· - - - -·-- - - - - - - - - - - - -
TABLE 3.5: EXISTING AND PLANNED RAILBELT HYOttO GENERATION
Average Energ~ (GWh) Firm Energx {GWh)
Cooper Solomon Bradley Grant!/ total
Eklutna Lake Gulch Lake Lake 155 Cooper Solomon Bradley
Month (30 MW) (16 MW) (12 MW) (90 MW) (7 MW) MW Eklutna Lake Gulch Lake r~ta1
JAN 13.8 3.8 4.9 31.0 2.75 56 13.0 3.7 4.3 34.7 56
FEB 12.3 3.4 4.3 27.7 2.75 51 11.9 3.4 3.9 31.9 Sl
MAR 12.5 3.4 4.6 28.2 2. 75 . 52 9.1 2.6 3~0 24.4 39
APR 10.3 2.8 3.5 23.4 2.75 43 9.9 2.8 3.3 26.5 43
MAY 11.7 3.2 4.3 26.4 2.75 48 11.4 3.3 3.8 30.3 49
JUNE 11.8 3.3 4 .. 3 26.6 2.75 49 8.0 2.3 2.6 21.4 34
JULY 13.4 3.6 4 .. 9 30.2 2.75 55 8.3 2.4 2.7 22.2 36
AUG 14.1 3.8 4.9 31.7 2. 75 57 8.5 2.5 2.8 22.6 36
SEP 12.6 3.4 4.6 28.4 2.75 52 8.7 2.5 2.9 23.2 37
OCT 13.6 3.7 4 .. 9 30.6 2.75 55 9.4 2.7 3.1 25.0 40
NOV 13.7 3.8 4.9 30.6 2.75
0
56 8.1 2.3 2.7 21.6 35
DEC 14.1 3.8 4.9 31.7 2.75 57 11.7 3.4 3.9 31.-2 50
TOTAL 154 GWh 42 GWh 55 GWh 347 GWh 33 GWh 631 GWh 118 GWh 34 GWh 39 GWh 315 GWh 506 GWh
!/ Information on firm enel"QY from Grant Lake was not avail abl,e.
I
I
I
I
I
I
I
I
I
I
I
I
IG
I
I
I
I
I
I
TABLE 3.6: SCHEDULE OF PLANNED UTILITY ADDITIONS (1980-1988)
Capacity Average
Utility Unit Type MW Year Energy
CVEA Solomon Hydro 12 1981 55 GWh
Gulch
CEA Bernice GT 26.4 1982
Lake #4
1/
CEI\ Beluga cc 42-1982
#6, #7' #8
AMLPD Unit #8 GT 90 1982
COE Bradley Lake Hydro 90 1988 347 GWh
APA Grant Lake Hydro 7 1988 33 GWh
1/ New Unit #8 wi 11 encompass Units #6 and #7 each rated. at 68 MW. Total
-new station capacity will be 178 MW.
0
,,
I
I
I
I
I
I
I
I
·I
I
I
I
I
I
I
I
I
I
I·
TABLE 3.7: SUMMARY OF THERMAL GENERATING RESOURCE PLANT PARAMETERS ~ ~-....,;......--;..;..;..,;;..,.;.;...;....;.;.,...;_;;_
Parameter
Heat Rate (Btu/kWh)
Earliest Availability
Fuel Type
O&M Costs
Fixed O&M ($/yr/kW)
Variable O&M {$/MWh)
Outages
Planned Outages (%}
Forced Outages (%)
Construction Period (yrs)
Retirement Policy (yrs)
Start-up Time {yrs)
1/
Unit Capital Cost ($/kW)-
Railbelt:
Beluga:
Nenana:
2/
Unit Capital Cost ($/kW)-
Railbelt:
Beluga:
Nenana:
Coal Fired
Steam
200 MW
10,000
1989
Coal
16.83
0~6
8
5.7
6
30
6
2,051
2,107
2,242
2,309
Combined
Cycle
200 MW
8,000
1980
Natural Gas
7.25
1.69
7
8
2
30
4
1,075
1,107
Gas
Turbine
70 MW
12,200
1984
Natural Gas
2.70
4.84
3.2
8
1
30
4
627
636
Diesel
10 MW
11,500
1980
Oil
0.55
5.38
1
5
l
30
1
856
869
1./ As estimated by Battelle/Ebasco without interest during construction {AFDC).
2/ Including AFDC at 0 percent escalation and 3 percent interest, assuming an
s-shaped expenditure curve during construction period.
·------~------------------~------------------11
. . . ,.. . . . .... . . . .
I
I
·I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
.I
TABLE 3 .. 8: FUEL COSTS AND ESCALATION.!./
Coal Q'
Year Healy at Healy Healy at Nenana Beluga Natural Gas Oil . ...
1993 $1.94/MMBtu $2.25/MMBtu $1.90/MMBtu $3.03/MMBtu $8.08/MMBtu
1995 2.04 2o35 2.00 3.27 8.41
2000 2.32 2.64 2.27 4.80 9~28
2005 2.46 2.79 2.41 5.30 10.25
2010 2.61 2.95 2.56 5.85 11.32
1/ Base prices and escalation patterns derived frQm Battelle and Acres
-meetings and research.
0
I
I
I
I
I
I
I
I
I
I
I
I
I
I'
I
I
I
I
I
TABLE 3.9: CHAKACHAMNA HYDROELECTRIC PROJECT!/
Installed capacity
Earliest on-line date
330 MW
1990
Total Capital Cost including
AFDC and Transmission
$/kW
$1~450 million {1982 $}
$4,394/kW
Energy (GWh)
Month
Jan
Feb .
Mar
Apr
May
June
July
Aug
Sept
Oct
Nov
Dec
Average
139.9 GWh
120.7 GWh
118~7 GWh
103.1 GWh
97.4 GWh
95.3 GWh
147.9 GWh
156.8 GWh
103.1 GWh
121.7 GWh
135.5 GWh
152.1 GWh
1,491.6 GWh
1/ From Bechtel; Chakachamna Alternative "B" 1981.
Firm
140 GWh
121 GWh
119 G\~h
103 GWh
97 GWh
91 GWh
93 GWh
97 GWh
103 GWh
122 GWh
136 GWh
152 GWh
1,374 GWh
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
,TABLE 3.10: SUSITNA HYDROELECTRIC PROJECT GENERATION PLANNING DATA
~
Earliest on-line date:
Unit size:
Maximum no. of units:
Maximum capacity:
Minimum capacity:
Monthly energy production:
Month Firm
Oct
Nov
-Dec
Jan
Feb
Mar
Apr
May
June
July
Aug
Sept
Total
Site Access Cost:
Transmission Costs:
Subtotal
AFDC
Total Costs
TOTAL PROJECT:
Capacity
Cost
with AFDC
O&M
Watana only
Total Susitna
234 GWh
270
322
283
228
235
199
180
170
182
170
158
2,631 GWh
WATANA
-,,....,
1993
170 MW
6
1, 020 MW'
75 MW
Average
281 GWh
348
445
383
318
276 (\)
203
180
175
258
344
248
3,459 GWh
$3,175 million (82$}
472
$3,647
44?
$4,094 million
DEVIL CANYON
2000
150 f4W
4
600 MW
75 MW
Firm Average
203 GWh 230 GWh
232 295
276 373
257 332
224 281
235 256
261 248
262 285
322 303
205 263
151 253
135 215
2,763 GWh 3,334 GWh
$1,358 million (82$)
112
$1,470
161
$19631 million
1,280 Mw.!/
$5,117 millionY
$5,784 million
$14.7/kW
$12.1/kW
1/ The generation planning tasks used an installed capacity of 680 MW at
Watana. The extra 340 MW would be included for spinning reserve and O&M
flexibility.
2/ This cost was quoted in December 1981 as the cost of a 1280 MW project.
However, the final feasibility total project cost was $5,127 million for a.
1620 MW installation.
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
TABLE 3.11: OGP SYSTEM DATA
Item
Period of analysis:
External Contracts:
Optimization logic:
Spinning reserve:
Loss of Load Probability (LOLP):
Hydro reliability (firm energy):
Random forced outages:
Unit committment:
Immature operation:
!_nput
1993 -.2010
None apply due to isolation of
system
Select minimum production cost
expansion from .available units
and sizes
150 MW
0.1 day/ year
Input separate from average energy
Apply in production cost logic
Coal and combined cycle: if needed
minimum run time 4 hours; maximum 24
hours.
All others: if needed m1n1mum run
time 4 hours; maximum run time 12
hours
New units experience less efficient
operation during start-up period
I
I
~I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
TABLE 3.12: OGP ECONOMIC DATA
Item
Year costs are quoted:
Present worth to year:
Interest/discount rate :1./
Escalation rate
Economic Input
1982
1982
3%
0%
Annual fixed carrying charges:.!!
Cost of Money
Amort i z a.t ion
Insurance
Total
Capital and 0&~ Real Cost
Es..;,:\ 1 at ion :..£1
20-Yr life 30-Yr life
3.00
3.72
0.25
6.97
1982 -1987 ~.9%
1988 -2010 -2.0%
3.00
2.10
0.25
5.35
1/ Varies under sensitivity analysis of interest rates.
50-Yr life --·
3.00
0.89
0.10
3.99
2/ Assumed capital and O&M real cost escalation is greater than that used in
Battelle study. Use of lower values would tend to favor projects with high
capital cost (e.g.,. Susitna). Sensitivity of this rate was accomplished
under Section 4.6 (f).
\
l
., ~ -
I
, I
I
I
I
I
I
I
4 -RESULTS OF GENERATION PLANNING STUDIES
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
-I
4 -RESULTS OF GENE~R.~TI_QN PLANNING STUDIES
4.1 -Methodology
Given the data discussed in the previous section, an analysis of
alternatives for electrical energy generation in the Railbelt comparing the
production costs of electricity with and without the Susitna project was
done. The primary tool for the analysis was the generation planning model
(OGP) which simulates production costs over a period of time.
The primary method of comparing with and without Susitna alternative
scenarios is total system costs. The planning model provides output from
the OGP program of the total production costs of these aiternative models
on a year by year basis. These total costs for therperiod of modeling
include all costs of fuel and operation and maintenance of all generating
units included as part of the system. In addition, the production cost
includes the annualized investment costs of any production plants added
during the period of study. Factors 'lklich contribute to the ultimate
consumer cost of power which are not included in this model are: all
investment cost to plants in service prior to 1993, costs of the
transmission and distribution facilities already in service and
administrative cost of utilities for providing electric service to the
public. These costs are corrmon to all .scenarios and have been omitted from
the study, as having no impact on generation plant decisions.
Thus, the production costs modeled are only a portion of ultimate consumer
costs and in effect are only a portion, albeit major, of total costs. The
sum of the annual costs is an effective relative indicator of the measure
of cost of following one plan compared to another.
In order to compare costs, a 11 annua 1 c"osts fr-om 1993-2010 production
simulation have been converted to a present worth {PW) of 1982. These
present worths for all scenarios considered are shown in tabular form in
two anounts. The first 'is the 1982 PW of the 18 years of model study frorn
1993-2010. The second value is an estimated PW of long-term system costs.
The first PW value represents the theoretical amount of cash (not including
those items noted) needed in 1982 to meet electrical production costs in
the Railbelt for the period 1993-2010, given scenario assumptions.
The second cumulative PW value is the long:-term (2011-2051) PW estimate of
production costs under the medium scenario. In rQnsidering the value of
the addition of a hydropower plant, which has a useful life of
approximately 50 years, the study period is inadequately short. A plant
\vhich is added in 1993 or 2002 would accrue PW benefits or penalties for
only 17 or 9 years, respectively in the PW measure.
4-1
:1
I
I
I
I
I
I
I
I
I
I
I
:I
I
I
I
I
I ,
I
It is also true that modeling the system for an additional 50 years,
assuming loads and generation alternatives, is well beyond the realm of any
prudent projections. For this reason, the final study year (2010)
production costs were assumed to reoccur for an additivnal 41 years (in the
medium-load forecast), and added to the 18 year PW, to estimate a relative
measure of long-term cost differences between alternative methods of power
generation.. In economic notation, this can be expressed as (P/A,3%,41yr)
(P/F,3%,18yr), to al-.. rive at a long-term cost factor.
The production costs for the time period 1982 to 1993 are the same for all
non-Susitna and Susitna cases. For each generation system scenario, the
period 1993 to 2010 is simulated by the OGP program which calculates the
cumulative PW cost in 1982 dollars of operating the generation system
during that 18-year period. The annual cost in year 2010 is mathematically
extended so that the numb.er of years between the addition of the last
Susitna development and end of the simulation period is 50 years. This
number of years varies due to the fact that the second stage of the Susitna
project, the Devil Canyon development, is added to the system earlier or
later depending on the load forecast.
For the high "load forecast, the period of analysis extends from 2011 to
2046 (36 years) since Devil Canyon is added to the Railbelt system in 1997.
The low load forecast extends the period of analysis from 2011 to 2053 (43
years) b~cause Devil Canyon power comes on line in 2004.
Figure 4.1 illustrates the long-term cost concept.
It should be noted that the present worth of the long-term cost is not by
any means an absolute number but is a relative measure of alternative
scenario production costs. Nonetheless, it is a valid measurement of
comparing different plants of action because the costs not included in the
analysis are common to all scenarios.
For each generation plan, a present worth of the long-term cost has been
calculated. A second method cost comparison is by comparing net benefits.
The net benefit can be estimated by comparing similar with and without
Susitna scenarios, and by examining the difference in PW long-term cost
totals. For example, in a Susitna plan with PW long-term costs of $6!t000
mi 11 ion as compared to a simi 1 ar non-Susitna scenario with $7,000 mi 11 ion
PW long-term costs, the present worth ·value of the production cost saving
over the long term would be one billion dollars. Since all non-conmon
costs of the alternative plans are included in the production cost
simulation process, the one billion is a net benefit to the less expensive
alternative.
Fi~ure 4.2 illustates the net benefit concept. The 1982 to 1992 production
costs are conmon to both plans and therefore not included in the present
worth of long-term costs. {Note that they lie below the horizontal axis).
The 1993 to 2010 cumulative production costs are present worthed to 1982
dollars. The 2011 to 2051 economic extension of 2010 production costs
(medium load forecast) represents the full project life operation of
Susitna project.
4-2
·-. I
I
I
I
I
I
I
I
I•
I
I
I
I
I
I
I
I
I
I
The difference (non-Susitna plan minus Susitna plan) is the net benefit.
This is the second method used to interpret the results of the generation
planning study.
4. 2 -~ase Systems (1982 -1992)
The production costs for the time period 1982 to 1993 are the same for both
the non-Susitna and Susitna cases. These base plans were as follows:
Low and Medium Load Forecast ~ no capacity other than the scheduled
corrmi tted units necessary to meet demand.
High Load Forecast -·200 MW combined cycle added in 1987
200 MW combined cycle in 1990
70 MW gas turbine in 1992
4.3 -·Non-Susitna Plan-Medium Load Forecast
The without Susitna plan "A" includes three~200 M~J coal-fired plants added
in Beluga in 1993, 1994 and 2007. A 200 MW unit at Nenana is added in
1996 to provide Fairbanks with some reliability. In addition 9-70 MW gas
fired gas turbines are added during the 1997-2009 period.
Figure 4.3 summarizes the non-Susitna plan annual cost distribution.
The non-Susitna plan has a 1982 PW cost of $3,213 g 106 for the 1993-2010
modeled period. The 2010 annual cost is $491 x 10 and the computed
long-te·rm cost is $8,238 x 106. [3213 x 106 + (491 x 106)(10.2336)],
where 10.2336 is the long-tenn cost factor described in Section 4.1.
4.4 -Susitna Plan -Medium Load Forecast
The Susitna plan includes 680 MW of capacity at Watana available to the
system in 1993. Although the project can come on line in stages during
that year, for modeling purposes it was assumed to be av ai 1 able for the
whole year. This is true of all new units added to the system. The second
stage of Susitna, the Devil Canyon project, is scheduled to come on-line in
2002. The project was tested for addition at earlier and later dates :with
2002 found to result in the lowest long-term cost. Devil Canyon includes
600 r~W of installed capacity. Additionally, three-70 MW gas turbines are
added in the late years for winter peak capacity.
Note that during final feasibility study work, a 1020 MW Watana Scheme was
determined to be optimal for spinning ,~eserve and O&M considerations. The
reliability of having six-170 MW units available was considered as the most
desirable plan. Although the generation planning studies does not include
the extra 340 MW of capacity per se, the cost modeled in OGP reflects a
1020 MW \~at ana scheme. ·
Figure 4.4 summarizes the Susitna plan annual costs.
4-3
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
-·
I
Durln~ the l993-201g study period the 1982 PW of costs fov-the with 6Susitna
plan 1s $3;119 x 10 . The 2010 annual production cost is $385 x 10 .
The present worth of this 1evel ized cost for a period extending to the end
of the _life of the Devil Canyon project (2051) is $3,943 x 106. The
resultant is a long-term cost of $7,062 x 106.
4.5 -Comparison of Base Plans
The base case comparison of the with and without Susitna plans is based on
production cost simulation for 1993-2010, using all mid-range forecasts.
This includes the medium load forecast, projected fuel costs and estimated
capital costs and real escalation factors on those costs. General
escalation was set at zero percent with an interest and discount rate of 3
percent used. The economic comparison of these plans is shown in
Table 4.1. As can be seen, the net benefit in pursuing the Susitna plan is
$1,176 million. Figures 4.5 through 4.7 surrmarize the gener·ation plans for
the base cases, in three manners: comparing yearly costs, percent reserve
and long-term net benefits.
Two points should be noted in the comparison of these p1ans. First, the
loss of load probability (LOLP) in the non-Susitna plan in 2010 is
calculated at 0.099. This means that the system is on the verge of add1ng
an additional plant, and would do so in 2011. These costs are hov·-:ver not
included, in the analysis which is cut off at 4010. On the other hand, the
Susitna plan has a loss of load probability of 0 .. 025!:-and may not require
additional capacity for several years.
A second consideration is that some of the Susitna power is still not used
by 2010. This total is about 177 GWh which is not absorbed by the
projected demand in the sunmet' months. No benefit is attributed to this
energy in the analysis.
4.6 -Single Variable Sens)tivity Ary~lysis
Rather than rely on a single comparison cf cases to arrive at a net benefit
the project, a sensitivity analysis has been done to identify the impact of
key data on the r·esults. The method used to test sensitivity of key data
-has been to identify critical assumptions which are input to the analysis.
After that, a range of values for the input data has been estimated, \\tlere
appropr·iate.. Each parameter· has been reviewed for impact on the Susitna
decision and where applicable, the system mndel has been tested over the
identified range to determine the impact on 'long term costs of data
variance. The following list of va.ri tble inputs has been reviewed:
~~~
(c)
(d)
(e)
(f)
Load Forecast .
Economic Interest/Discount Rate
Capital Costs -Alternatives and Susitna
Period of Analysis
Construction Period
Real Escalation -Capita 1 Costs~ O&M and Fue 1 Costs
4-4
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
----_--~-~
(g) O&M Costs
(h) System Reliability
(i) Coal Bas~ Price
(j} Other Hydro Projects
(a) Load FDrecast
'
Throughout the Susitna feasibility study, planning has proceeded on
the project for the mcst part based on a medium load forecast. It has
all along been realized that this forecast has been made based on the
idea that the forecast is a center point of a range of uncertainty,
rather than the actual expected occurence. For this reason, ·
forecasters have bracketed the range with high and low forecasts ..
~
As part of the sensitivity analysis, the project has been analyzed
with both of these forecasts in place. The forecasts used for the
analysis are the medium, high and low forecasts by Battelle as
presented in Tables 3.1, 3.2, and 3a3.
Since the load forecast is the major-consideration as to \'Al~n and what
size capacity is added to the system~ the nature of the systems vary
gr-eatly between forecasts.
(if Low Forecast
In general, adopting a lower forecast allows for smaller amounts
of capacity at later period of time. In th~ non-Susitna plan~
only 600 MW of coal units are added, 2 units in Beluga and one
at Nenana. The units are added in 1995, 1997 and 2007.
Additionally, 8 GT units (or 560 MW) is added periodically after
1996. The pattern of capacity additions is close to that of the
medium forecast or base case, with several years of lag~
The optimal time for the addition of the Susitna units is also
changed from the medium fore~ast. As shown on Table 4~2, the
selected staging for the project is 680 MW" at Watana in 1995.)
with the 600 MW Devil Canyon coming on line in 2004. The
staging of Oevi 1 Canyon in 2007 was also tested, with a slightly
higher resulting long-term cost. Watana as a single project was
also tested, with long-tenn costs higher than with the addition
of De vi 1 Canyon. It can be noted that the staging of the second
project is not as critical as in the other forecasts. However,
th::·~re is a system need for additional capac·ity in 2004 which
De vi 1 Canyon satisfies. If the project is added in that year,
there is a significant amount of energy (1000 GWh) wh~ch cannot
he used by the system for many years.
Table 4.2 s~ow~ the long ~erm cost of th~ no;l-Su~it~a syst.em at
$6,878 x 10 w1th the Sus1tna system at $6,650 m1ll1on. 1hus
the net benefit to the Susitna pro.ject is $228 million.
4-5
I
I
I
I
I
I
I
I
I
.I
I
I
I
I
I
I
I
I
I
l·
(ii) High Forecast
Under this forecast, capacity is needed long before the
1993-19'"'~ time frame of medium and low forecasts. From the
analysis of the ten year period prior to 1993, it was found that
nearly 500 MW of other capacity is needed. This need was met by
the addition of 200 MW gas-fired combined cycle units in 1987
and 1990 and a 70 MW gas turbine unit in 1992. The combined
cycle units were one of the only choices for system addition
since the coal units are not available until 1989 due to
development lead time.
Note that the addition of these three units is common to both
the with and without Susitna plans. Therefore, the capital
costs of these pre-1993 plants have not been included in the
long-term cost.
In the non-Susitna p1an, 1000 MW of coal units are added, four
200 MW units at Be 1 uga and one at Nenana in 1996. In addition,
eleven 70 MW GT units. are added. The long-term cost of the
non-Susitna plan is $10,859 x 106 as calculated in Table 4 .. 2.
The staging of the Susitna project is condensed under the high
forecast. While Watana is still added in 1993, the Devil Canyon
addition is moved up five years to 1997. In addition, five 70
MW GT units are added in each of the years 2006-2010. The 1ong-
term6cost of the Susitna plan under the high fore~ast is $9,247
~ 10.. • The plan has a net benefit of $1,612 x 10 (see
1 able 4. 2).
{b) Economic Interest Discount Rate
As discussed in earlier portions of this section the base case runs
have been made with the interest rate set at 3 percent, assuming an
underlying inflation rate equal to zero. This rate has been selected,
consistent with APA guidelines, as the real return required on
investments, with no inflationary expectations.
Although the required return on investments will be a state policy
dec1sion, it is realized that the rate could vary to a higher or lower
range~ It has been considered reasonab 1 e that the requi t"ed real rate
of return could vary from 2 percent to 5 percent. Thus, the project
has been evaluated by the economic analysis method at each \t~hole
interest rate in this range. The results of the variance are
surnnarized in Tab1e 4.3. Note that the generation plans were kept
constant to the base plans to test the sensitivity of this parameter.
At 62 percent, the net benefits attributable to Susitna are $2,617 x
10 • . At. the othe\~ eng of the. 't"ailge ?r 5 percent, the Sus~tna net
benef1t 1s {$513 x 10 ) ., It 1s read1ly seen that the Sus1tna
decision is very sensitive to this parameter.
4-6
\ .
·I
I
I
I
I
I
I
I
I
I
I
I
I
, I
I
I
I
I
I
The net benefit of $109 . x 106 at an interest rate of 4 percent is
very close to the breakeven point. From Figure 4~8, a ~raph of net
benefit versus interest rate is estimated that the breakeven interest
rate, or internal rate of return on the project is 4.1 percent.
(c) Capit~l_Costs
Capital costs which have been estimated for the study have a
considerable impact on the long-term costs of either the with or
without Susitna scenario. Capital cost analysis has been approached
in two ways. First, with variance on the alternative cost and second
with variance on the Susitna costs.
The capital costs for the alternatives to Susitna have been estimated
by Ebasco, as part of the Battelle Railbelt Alternatives Study. There
is some concern that the estimates, based on a less detailed study,
are at a level'of confidence less than the Susitna estimate. Thus~
alternatives were checked against the Susitna base plan using a high
risk cost of 120 percent of the estimate and a low site cost of 90
percent of the estimate. Using the medium forecast Susitna plan_,
these sensitivities were tested.
The second testing was of the Susitna capital costs. In this case,
the Susitna plan was tested with a low capital ~?st equal to the
estimate less an assumed 20 per~ent contingency-. For a high
estimate, the contingency was doubled.
Table 4.4 shows the results of varying the capital costso Note that
the with and without plans remained the same regardless of this
variance in alternatives capital costs. In the alternatives variance
case, the net benefits vary by about 100 percent from the low to the
high case. The Susitna plan maintains positive net benefits in either
case.
The long-term costs are more sensitive to the variation in Susitna
costs. If the contingency is left off the Susitna cost estimate$< the
net benefits of the project are over $2 billion. However, if the
contingency value is doubled, the benefits drop to $264 x 106.
1/ In the final version of the project estimate, contingency allowance was
reduced to 17.5 percent as some uncertainties were removed. The range
of capital costs tested is sufficiently broad to include the final ·
estimate without cooti ngency and the final estimate with double
contingency.
4-7
I
I
I
I
I
I
I
I
I
_I
I
I
I
I
I
I
I
I
:-1
't
I
.
(d) Period of Analysis
The planning period for modeling purposes extends to 2010, considered
to be the outer limit for load forecasting and economic cost
projections. However~ the Susitna project is entered into the system
in the 1993-2004 timeframe (Watana/Devil Canyon separate stages) ..
Therefore, the method for analyzing the project has taken into account
extension of the system costs to a period equal to .50 years past the
last added project stage. This extension of the period of analysis is
discussed in more detail in earlier parts of this· section.,
The impact of this methodology can be determined by reviewing the base
_case (Table 4.1). The shortest period for analysis to be chosen would
be at the end of 2010. This however, would account for only 8 years
of operation of Devil Canyon, a very short period for reviewing
capital intensive projects. The net benefits to the Susitna project
are $93 x 10 6 , Just about the breakeven point. This can be ~ompared
to the future~period of-analysis net benefits of $1,176 x 10 .
If an interim point were selected, say 30 years of operation of Devil
Canyon, the net benefits of the Susitna project would be $718 x.106.
This corresponds to a long-term gost of $6,431 x 106 for the
non-Susitna plan and $5,713 x 10 for the Susitna plan. The net
benefits in this case are 60 percent of those calculated in the base
case.
(e) Construction Period
Variability in the construction period has the impact of increasing
interest during construction charges. Using 0 percent and 3 percent
parameters, the interest during construction is small and does not
change much with a one-or two-year change in construction per~ioo.
Should a project be delayed several years, alternative forms of
generation may be required in place of the planned unit; however~ this
would not impact the generation p'lanning analysis as units are
expected to come on-line as scheduled with lead times of ten or more
years. ·The construction schedule for Susitna has been analyzed in
detail in the study risk assessment.
Delaying the Susitna project stages by one and two years was tested.
Table 4.5 sunmarizes these delays. Essentially, the Susitna plans
remain constant, with three 70 MW·gas turbines added. However, two
are needed in 1993 when the project is delayed whereas the base plan
installs them in the 2007 to 2010 period ... Due to the fact that the
investment cost of the gas turbines is so small, the effect on net
benefit is negligible.
4-8
I
I
I
I
"I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
(f} Real Escalation
Under the economic analysis assumptions general inflation is removed
as an underlying conditjon. However, projections have been made which
predict real escalation to occur in two study factors.. These are in
capital and operation and maintenance costs and fuel costs.
(i) Capit~l Costs
Along with the capital cost estimates from the Battelle
Rail belt alternatives study, Ebasco projected esca1 ation on
capital costs of the plants. This concept of escalation was
adopted into the base case, although higher (yielding more
conservative Susitna net benefits) values than those provided
by Battelle were used. In order to test the sensitivity of
this assumption, tests were made with zero escalation on
capital costs and double the rate or about 4 percent. Of these
two cases, the lower end appears to be much more 1 ike 1 y si nee,
unlike finite fuel resouwces, construction and labor are not
diminishing resources.
Results of-this analysis are shown in Table 4.6. The variance
· in these escalation factors changes the net benefits in a
manner similar to the actual variance capital costs, that is,
by excluding real escalation on capital costs and O&M the net
benefits rise by one-third. By daub 1 i ng the rate of _
escalation!) the benefits fall by -one-third~ In th.e high case,
it should be noted that the non-Susitna plan changes from four
coal units to two, with the capacity difference made up in GT
and combined cycle capacity. An additional sensitivity case
was run using the Battelle figures. However, the escalation
rates varied from 2 percent to 0 percent, to a negative value
dur1 :19 the period 1983 to 1992.. Battelle studies adopted a
value of 1.4 percent per year-which tends to overestimate the
Ebasco numbers in early years and underestimates 1 ater years.
The base case assumption was 1.9 percent for the period 1983
1989, 1.1, 1.6 and 2 percent from 1990, 1991, and 1992 on.
{ii) Operation and Maintenance Costs
Escalation of operation and maintenance costs was adopted from
Ebasco estimates of 1.6, 1.6, 1.7, 1.8, 1.8, 2.0 for the years
83, 84, 85, 86, 87 and 88 on. Sensitivity was run using 0
percent and double escal.ation rates as seen in Table 4 •. 6.
(iii) Fuel Costs
As non-renewable resources, the prices of -coal, gas, and oil
are expected to increase in price at a rate greater than
general commodities. These prices and escalation factors are
I
I
I
I
·I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
discussed in theearlier portion of t11is chapter. Model runs
were-made with high and low levels of fuel escalation. The low
limit was established as zero percent real escalation. The
upper 1 imit was set at 52 percent for coal, 4 percent for oil
and 5 percent for gas until 2000 and thereafter at 2.2, 2.0 and
2.0 percent, respectively. The base case fuel cost inflation
patterns are 2. 6, 2 9 and 2 .. 5 percent unti 1 2000 and 1. 2, 2 and
2 per·cent, respectively until 20l0e ·
Under the low limit (see Table 4.6)~ the Susitna project has a
negative net benefit of $1,078 x 10 , conversely, under the
high fuel escalation scenario, net benefits rise to $2,979 x
10 . Clearly, fuel escalation estimates are a very key
assumption with regard to the project economic analysis •
•
(g) Operational and Maintenance Costs
The O&M costs attributable to the units in service are an important
part of the production cost model. However, in this case, these costs
consistently are only 8 to-12 percent of the total production costs in
any given yea('. Therefore, if the O&M estimates varied in a similar
manner to capital costs(+ 20 percent}, only a 1 to 2 perc~nt
difference i.n long-term costs would result. For this~·reason, the
sensitivity of O&M estimates were not tested further.
(h) System Reliability
A generating system loss of load probability of one day in ten years
has been used in system modeling. Variance of this factor would cause
the system to add more or less capacity, thus potentially changing the
strategy of alternatives.. However, since this is a selected criteria
ratner than an assumption or projection, there is no real basts for
variance.
(i) Coal Base Price
As shown in earlier parts-of this chapter, there is evidence that the
base price (opportunity value) for coal could be as high as $2 •. 08/
MMBtu, as compared to $1.43/MMBtu. This starting price was tested in
the without Susitna case with the results presented in Table 4.7~
Since the with Susitna case does not include development in the Beluga
or Nenana fields, the comparative with Susitna run is the base case.
(j) Other Hydro Projects
As discussed earlier, the 330 MW Chackachamna project has not been
included in the base non-Susitna plan. It has been included as a test
case hot~ever, with installation of the project into the non-Susitna
system. Net benefits of the Susitna project as compared to the with
Chackachamna system are $837 x 106 as seen in Table 4.8.
4-10
-
~ "_:_. ""·-~~. --~-~.--""" :: .. ·-~-_. .. .....::.,..· ... --.~ .. --. ...... ; .. ·~--·~-_ .... ~-~-·~·..,.;.-~1,-.. ,;~.r-...... ,.,_,~ -·
~--~~-..,.--__,..,......,.~.,.,-------, ------c -
·-
I
I
'I
I
I
I
I
I
I
I
I
I
~ I
I
I
I
I
1-II
All plans, both Susitna and non-Susitna include the 90 MW Bradley Lake
hydro project proposed on-line in 1988. However, the cost of the
Bradley Lake project is not included in the long-term cost
calculations since it is coOTilon to both plans. To test the
sensitivity of the Susitna development to this assumption, Bradley
Lake was replaced with two 70 MW gas turbines--one in 1988 and one in
1991. The generation plans are presented in Table 4._8. Two
comparisons are made. The Susitna plan without Bradl.~y Lake {F2)
compared to the non-Susitna base plan (A) has a net b:anefit of $949
million. Compared to the non-Susitna without Bradley Lake plan
(F 1 ), it has $1,454 million in be-nefits. Both of these comparisons -
do not assess the economic impact of constructing Bradley Lake,_ merely
the differences in production costs during 1993 -2010 given with and
without Bradley Lake energy.
4.7 -Multivariate Sensitivity Analysis
As described in the previous sections the Susitna project was assessed
using an economic analysis of generation system production costs. In order
to carry out this analysis, numerous projections and forecasts of future
conditions were made. These forecasts of uncertain conditions include
ftiture electrical demand, costs~ and escalation. In order to address these
uncertain conditions, a sensitivity analysis on key factors was done, as
described in the previous section. This analysis focused on the variance
of each of a number of forecasted conditions -and determined the impact of
this variance on the economic feasibility of the project. Each factor-was
var-ied singularly with all other variables held constant to clearly
determine its importance.
The purpos·e of this multivariate analysis was to iielect the most critical
and sensitive variables of the economic analysis at1d test the econom'ic
feasibility of the Susitna project in each possible combination of the
selected variables.
While a number of variables were identified and tested in the single
variable sensitivity analysis for the Susitna economic feasibility study,
the variables \\tlich were chosen for the multivariate sensitivity analysis
represent these key variables.
The methodology for the multivariate analysis was served by constructing a
probability tree of future conditions for the Alaska Railbelt electrical
system, witn and without the Susitna projector Each branching of the tree
represents three values for a given variable which were assigned a high,
medium and low value as well as a corresponding high, medium and low
probability of occurrence. The three values represent the expected range
and mid~point for a giv~m variable. In some cases, the mid-point
represents the most 1i.ke1y value which would be expected to occur. End
limbs of the probability tree represent scenarios of mixed variable
conditions and a probability of occurrence of the scenario.
4-11
·I
I
I
I
I
I
I
I
I
I
I
.I
I
I
I
....
I
I
I
A computer production cost model (OGP) was then used ·to determine the
present worth of the long-term cost of the electric generation system for
each scenario. Using the probabilities assigned to each variable, the
preserrl: worth of the long-term costs for each with and· without Susitna
scenario in terms of cumulative probabi 1 i ty of occurring were determined
and plotted. Net benefits of the project have a1 so been ca1cu1 ated and
analyzed-in a probabilistic manner.
{a) ~ Variables and Probabilities
Of the list of sensitivity check analyzed in the previous section~
several of the inputs are considered to be policy or methodology
decisions and are not in_cluded in this anal_ysis. These include the
interest and discount rate, the period of analysis and system
reliability criteria. The single variable sensitivity analysis
demonstrated that others such as the construction period, the coal
base price and the operation and maintenance costs had little or no
impact on the comparison 9f with and without Susitna system costs ..
Although sensitivity results based on var+ving the real escalation of
capital costs and operation and maintenance costs indicated a
measurab 1 e influence~ of that vari ab 1 e on long-term costs, it was not
included in the probabalistic analysis .. The range of capital cost
escalation rates tested in the sensitivity analysis was from zero to
4 percent per year ( 1982 -2010). The mid-range was approximately 2
percent. ·It is believed that this range accurately covers the
minimum and maximum percentage rate one might antici.pate for
construction cost escalation in addition to the general inflatinn
rate ..
The four variables used in the Susitna multivariate sensitivity
ana1ysis are discussed below.
(i) Load Forecasts
As in the single variable sensitivity analysis, load forecasts
remain one of the most important variables.
Selection of type and timing of alternative units is extremely
dependent on the selected forecast. The variability is
attributed to the varying forecasts of governJl1ent expenditure,
activity in the public sector, and population and industrial
growth.
ln terms of the mu 1 t i variate sens i ti vi ty ana 1 ys is, the load
forecast variation represents the fir·st level of uncertainty in
the probability tree. The forecasts used were the same as.
those used in the previous generation planning analyses~
generated by the Battelle Ra)lbelt Alternatives Study group in
December 1981 with the use of their Railbelt Electric Demand
4 .. 12
,,
~· '
• """''~~» . ..,,_·". _...._.·,,, ~· •-••·<••• .. ,,..,-_ ·-'·•·'-# ·~·•'> """'"""'"'•-.,,,., ...,.,..~, _ _, • .:.._ .... _.,. ___ ~:..., ..• ~•, N""-• u.' • ,t,~., ~.: •-•~., ... .._:., •,..,_,~_. •""'"'',..>»'~· •·">~"'"""'',!'•,'.~.,,,,. "'""'""''"'"·•"•"''""~"\...,.....'1'-<~~-'-"4'•-'l<i•>J:,,_...,,. • ~.:... ..... -.. .,....~~f'l_,,,_.,.,.... ~<;.-~"-""''" ,-(;).,,..,_,;."'"~~.'<"!'li,,...•~~<•."•f'~>o;.~y!~Jt,~,.,-.< '""'
~~." ·~,-·~--;
·I
I
I
I
I
I
"I
I
I
I
I
I "'
I
I
I
I
I
I
::
I
(RED} model. The ·range of variabi 1 ity in the load is
presented in Tables 3·.1, 3.2 and 3.3. Note that these
forecasts differ slightly from the fina'l forecasts produced in
January 1982 by Battelle.
The probability of the low, medium or h·igh forecast occurring
was estimated as a symnetrical pattern of 0.2;. 0.6, and 0.2,
respectively. These estimates of probabi 1 ity were based upon
the estimate by Battelle that the probability of exceedance of
Ureir forecasts was approximately 90 percent for the low
forecast and 10 percent for the high forecast~
The generation plans used in the probabilistic analysis are
identified as follows;
Low Load Forecast:
Non-Susitna -first 200 MW capacity added in 1995
Sus i-tna -Watana 680 MW in 1995
Devi·l Canyon 600 MW ·in 2004
Medium Load Forecast
ID
A Non-Susitna -first 200 .MW capacity added in 1993
C Susitna -Watana 680 MW in 1993
-Devil Canyon 600 MW in 2002
HJ.gh Load Forecast
1982 -1992 perioJ: (common to both cases) .
200.MW combined cycle added in 1987
200 MW combined cycle in 1990
70 MW gas turbine in 1992
ID
Non-Susitna -f1rst 200 MW capacity added in 1993
Susitna -Watana 680 MW in 1993
-Devil Canyon 600 MW in 1997 '·
( i i) A 1 tern at i ve2__Capi tal Cost
A considerable amount of variability can be introduced· into the
analysis due to the estimate of capital cost for alternative
forms of generation for the Railbelt varying by plus or minus
20 percent from the medium value. These variations have been
identified for the Susitna development as Nell as for coal, gas
4-13
I
I
I
I
I
I
I
I
I·
I
I
I
I
-I
I I
I
I
I
I
AI
"'
-~"
. ·-" . -~-. '-"' ,. ·~ .~-,.
turbine.and na~ura1 gas combined cyc;l~ plants. This parameter
was var1ed dur1ng the econom1c sens1t1v1ty analysis and was·
observed to have an imp~ct. on long-term results. Therefore,
the variation of estimated capita1 cost was carried forward to
the multivariate an-alysis.
Consistent wi":h the single variate economic anal y.si s, the base
capital cost estimate plus 20 percent was used as the high
value and base capital cost estimate minus 10 percent was used
as the low value. These figures were selected based on a
review of the Railbelt Alternatives Study Coal Cost Estimate
report prepared by Battelle. The discussion contained in the
report indicated that there was a greater likelihood of cost
increase than decrease.
The base (medium), .high and low capital costs for the coal, gas
turbine and gas-fired combined cycle plants are shown 1n Table
4.9. These capital costs include allowance for funds during
construction (fl,FDC) based on an S•sh.aped expenditure curve and
the medium economic parameter used throughout the 'study. In
addition, the first unit sited in the Beluga district and the
single unit at Nenana district carr·y the appropriate costs of
transmission system interconnection.
The probability for the occurrence of the high, medium and low
capital costs was estimated as a 0.20, 0.60, 0.20. This \~as
selected as a balanced distribution.
(iii) Fuel Cost and Escalation
Considerable efforts have bet.~ concentrated on defining fuel
prices and escalation rates of the various Railbelt fuels by ~
both Acres for the feasibi {V~.y study, and Battelle for their
Railbelt Alternatives Study. This discussion of ranges of the
three fuel types (coal, natural gas and oil) focus on tfite
incremental rate of escalation to be appliP~ to the base t:uel
:osts. The incremental value is that above general inflation
as measured by the Consumers Price Index.
The low, medium and high cases are all tied to the fuel
e~;cal at ion rate occurring in the world market price for oil,
presently 2 percent per year.
-Coal
As outlined in the feasibility report, coal reserves
available to the Railbelt include Healy mined coal and a
potential Beluga coal mining industry. Furthermore, Healy
coal could be transported to N.enana for use as fuel for a
potential 200 MW coal-plant located at Nenana. due to air
4-14
• ., .0
" '
• •• ~ •• , •••• > ~ -··-~-~~·-.... ,.;,._,.; ·"'-~·d·-"'"'~-~-· ·-··
I
I
I
I·
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
quality restrictions at Healy. Three starting coal prices
based on point of use were developed for input into the
multivariate sensitivity analysis.. For each of these
starting coal .Prices, three escalation rate scenarios were
developed~ a low; a medium or most likely case and a high
case. Probabilities of occurrence of 0~25, 0"50 and 0.25
respectively were assigned to the three escalated rates.
These probabilities are discussed in detail in Section 18 of
the Susitna Feasibility Study Report. Table 4.10 summarizes
these prices with the appropriate escalation rate applied.
-Natura1 Gas
Cook I:oJet natural gas is presently sold to Anchorage
utilit"es at existing contract rates. It is generally agreed
that toe price is artificially low and will increase
significantly as these contracts are renegotiated. Thus! a
world market opportunity value was selected as the base
5tarting price for modeling purposes. Based on the Battelle
~~dium price forecast 9 a 1982 opportunity value of
$3~00/MMBtu was selected. This value when coupled with Acres
medium fuel escalation rates yields values equal to
Battelle•s during the 1993-2010 study period. In the low
case!) the price was assumed constant at $3.00/MMBtu through-
out the study period {i.e., no escalation). The medium case
escalation rate was 2.5 percent {1982-2000) and 2 percent
(2001-2010). The high case escalation rate was set at 5
percent (1982~2000) and 2 percent (2001-2010). Table 4.10
surtlllarizes these patterns.
... Distillate Oil
Table 4.10 summarizes the low, medium and high oil price
increase patterns used in this analysis assuming a 1982 ll"o\te
of $6 .. 50/MMBtu. This value was based on Battelle estiaates~
{iv) Susitna Capital Cost
Variation of the Susitna project capital cost has been ~a1yzed
in the feasibility study under Task 9 and 11. In general~ the
concept in Task 9 has been tc produce an "upper limit 11
estimates of capital cost with a relatively high level of
confidence that the ultimate project cost will be less than the
"upp~r limit" estimated capital cost (discounting future
inflation). The risk analysis completed as part of Task 11 has
shown that this 11 upper 1 imit 11 estimated capital cost has a 17
percent chance of being equaled or exceeded given the low
probability but high impact risks which could occur during
construction (i.e., major seismic event or flood) ..
4-15
,; ,,
.If ·.._,.~,A_ ...... _..._.
I
I
I
I
I
I
I
I
••
Single variable sensitivity analysis provided for a •;ariance
from 83 percent to 117 percent of the project estimated cost.
Thes_e parameters were also used in the multivariate analysis
and are surrmarized in Table 4,.11.
Assignment of probabilities for the three levels of estimate
was based upon the feasibility study risk assessment. The
approach to the 11 Upper 1 imit" value for the Sus i tna capi.ta l
·cost was simp 1 y an attempt to bound the base estimate with a
high level of confidence that the overall project cost will be
less than this estimate. Therefore, the assignment of
probabilities of occurrence are somewhat different than for
non-Susitna alternatives. Based on the Risk Analysis a
probability of 0.60 was assigned to the low case and values of
0.25 and 0 .. 15 were assi __ gned to the medium and high value
ranges. These values reflect the expectation that ultimate
costs on the project will be less than the current estimate (in
1982 dollars).
(b) Probability Tree
"'
Given the three selected 41 key" variables for the 1on-Susitna an.alysis
(four for Susitna), a probability tre~ was plotted based on the high,
medium and low value for each of the variables.
The compounding effect for the non-Susitna tree is 3 variables by 3
r§nges (high, medium and low) which is mathematically equivalent to
3 or 27 possible combinations. This probability tree is shown in
Figure 4.9. The numbering system selected for this analysis ranges
from TOl to T27 where TOl refers to the thermal (non-Susitna) c.ase,
high load forecast, high alte•·native capital cost and high fuel cost
escalation. At the other end of the spectrum, 127 refers to the
thermal case, low load forecast, low alternative capital cost and. low
fuel cost escalation scenario.
The Susitna pr-obability tree (see Figure 4.10} has a possible
mathemati~al equivalent of 4 variables by 3 ranges (high, medium and
low) or 3 = 81 branches. However, when reviewing the Susitna base
plans developed in the economic feasibility analysis, the medil.lii plan
calls for the addition of only three 70 MW gas turbines in the last 3
years of study. A check on the impact uf varying the cost of these
units indicated an impact on long-term costs of less than 0.5 percent.
Thus, it was assumed that in the medium "branches" there is no
var·iability in thermal alternatives cost.
In the low forecast. there is no need for thermal, alternative
generation in the 1993 -2010 period where the with Susitna scenario
~s being considered. Accordingly, the alternatives capital cost
variable is removed from that branch. As a result, both the medium
and lo•:J torec~st portions of the probability tree are reduced by a
4-16
~--
1
I
I
:I
I
I
I
I-
I
I
I
I
I
I
I
I
I
,··1
factor of 3. These adjustments reduce the number of ultimate
scenarios from .-81 to 45 without affecting the accuracy of the
multivariate analysis,
A similar numbering system was adopted for the Susitna anelysis
ranging from SOl to S45 where SOl to S27 refer to high load forecast
scenarios, S28 to S36 refer to medium load forecast scenarios and S37
to 545 represent low load forecast scenarios.
(c) Results
(i) Probability Tree: Non-Susitna
The parameters for the 27 scenarios. defined by the ·probahility
t~·ee in Figure 4.9 were entered into the generation planni:ng
model to determine the 1982 present worth (PW) of the 1993..,.2010
cost and the 2010 year annual cost .. The 1982 PW of the
long-term costs (LTC) was then determined as descrfbed in
Section 4.1. These results are presented in Table 4.12 and
Figure 4.9.
The LTC varied by nearly 350 percent from the lowest cost
scenario, $4.41 billion to the highest cost scenario of $15~0
billion. The low cost relates to the case of 1 ow load
forecast, low capital costs for thermG:i units and zero real
escalation in fuel costs. Conversely!) the high .case includes
the high forecast for each of these v ari ab 1 es. The 1 arg,e
spread from low to high LTC seems most dependent on the fuel
cost escalation rate used. The wide range in fuel costs during
the study period and the large quantities of fuel used in the
non-Susitna cases led to the wide. spread in LTG.
Also shown on Tabie 4.12 is the calculation of cumulative lTC.
This val4e is the sumnation of the probabilistic increments of
LTC for each scenario. The increment c.f LTC is the. prodoct of
a scenario's LTC and its probability. The cumulative LTC
represents an expected va 1 ue based on the costs and
probabilities as presented. For the non-Susitna case, the
expected value LTC is $8.48 billion.
Visual representation of the data from Table 4.12 is shown on
Figure 4.11. This graph is. a histogram of long-term cost
versus cumulative probability. Since. each of the data paints
represents a percentage of time as compared to a point in time,
it is more accurately represented as a histogram rather than a
single line.
4-17
-
. ' :)
-,.
-1
I
I
I
I
I
I
I
I
I
I
-•
I
I
I
·I
I
I
I.
'·
(ii) Probability Tree: Susitna
The 45 scenarios in the with Susitna case shown in Figure 4.10
were also run by using the simu1ation model to obtain the
system production Gost·s. The results are shown in Table 4.13
and Figure 4.10 .. The overall variability of 1ong term costs in
the Susitna case is much less than the non-Susitna case. The
range from lowest to highest is $5.54 billion to $11.59
b i 11 ion, a range ()f about 200 percent as compared to 35.0
percent for the non-Susitna alternatives~
The expected value of long term· costs calculated by the method
described in Section 4.1 is $7.03 billion.· A histogram of
long-term costs versus cumulative probability is presented in
Figure 4.12.
(iii) Comparison of Present Worth of Long-term Costs
' Figure 4.13 presents the two histograms of long-tenn costs for
the with and without Susitna cases plotted on ·the same :axis.
From these plots it is seen that the non-Susitna plan costs
could be expected to be significantly less than the Susitna
plan costs about 6 percent of the time, approximately equal to
the Susitna costs 16 percent of the time, and significantly
greater 78 percent of the time. ·
A comparison of the expected value of long-term costs of the
with and )'/ithout cases yields an ·expected value net benefit of
$1.45 billion. This value represents the difference between
the non-Susitna LTC of $8.48 billion and the Susita LTC of
$7 .. 03 billion.
(iv) Net Benefits
A second method of comoari ng the with and without Susi tna
probability trees is by making a direct comparison of siE~i'lar
scenarios and calculating the net benefit of each comparison.
This method was also u~sed in the single variable sensitivity·
analysis, and ts discussed in more detail in Section 4 .. 1~
Table 4.14 lists the 81 comparisons of similar scenarios
between the 27 non-Susitna case and 45 Susitna case scenar·ios.
As was done for the individual tree cases, the net benefits
were ranked from low to high and plotted against cumulative
·probability. This graph (Figure 4.14) has been represented as
a single line due to the number of points on the curve. It
however, like Figures 4:.11 and 4.12, would be most accurately
portrayed as a histogram. The net benefits vary from a
negative of $2.92 billion with an associated probability of
0.0015 to a high of $4.80 billion with an associated
probability of 0,.018. The single comparison with the hi:ghest
probabi 1 ity of occurrence of .108 has a net benefit of $2-.09
billion.
" 4-18.
The plot of net benefits has its cQ.~t cross-over between the
with and without Susitna c.ases at anout 23 percent, consistent
with the previous comparison, It also is consistent that the
expected value net benefit calculated by this method is $1.45
billion.
Sensitivity of Probabilities on Results
In assigning the probabilities of occurrence for each S'3t of
variables, a number of subjective assumptions were mades with
the exception ..of the Susitna capital cost probabilities which
were supported by a probabi 1 i stic risk assessment of
construction cost. The probabilities for load forecast of 0.2,
0.6 and 0.2 for the low, medium, and high cases, respectively,
reflect the analysis by Battelle and the probability of
exceedance of approximately 90 percent for the high.
Alternative capital costs, as estimated by Ebasco for Battelle
reflect a 0 .. 20, 0.60 and 0 .. 20 distribution, again within the 90
perc~nt low exceedance and 10 percent probability of e.x~eedance
for the high case.
The single most sensitive variable in the study is the rate of
real fuel escalation adopted .. This conclusion is supported in
the single variable analysis as well. The distribution of
probabilities was 0.25, 0.50 and 0.25 for low {zero percent)
medium and high fuel cost escalation scenarios. There may be
some merit to an analysis varying the probabilities of these
fuel es.calation rates implying that high fuel costs may produce
greater revenues for the State, thus increasing economic
activity and electric demand. Con\;ersely, high fuel costs to
consumers and industry may also tend to drive down demand,
whi 1 e low fue.l costs may spur more demand for energy. Rather
than specu1ate on the probabilities of fuel price compounded
with demand, consider Figure 4.15 which plots cumulative
probability versus normalized long-term costs for high, medium,
and low fuel escalation scenarios for the with and withot..1:
Susitna trees.
Figure 4.15 illustrates the Susitna and non-Susitna fuel cost
escalation impacts assuming a 0.25$ 0.50, and 0.25
·distribution .. The left most points represent generally the low
1oad forecast impacts while the right side reflects high load
forecast r·esults. The high fuel cost curves show that over the
entire range of load forecast the Susitna plan remains
significantly better than the non-Susitna plan. Under low fuel
cost escalation parameters the Susitna plan is more expensive ..
However, over ~. wide range of load forecast low fue 1 cost
escalation has relatively no impact •.
4.-19
··I
I
I
I
'I
I
I
:1
I
I
I
I
·I
I
I
I
I
.·1
:J
-
~· .... ;:t;.~t ·~~~ , ..... ,.. • ,.; ... -·
-,·· .... ,_ ,.
·,·,
VariabilitY of the Susitna capital cost probabilities has also·
been rev1ewed by two methods.
Plotted on Figure 4.16 is the normali~ed probability curves
for variance in Susitna capital cost. The ~ssumed distribution
as defined by risk analysis V.'Ork was 0.60, 0.25, 0.15 for low,
medium, and high capital costs. Comparing the high and low
curves to:the non-Susitna curve illustrates that the Susitna
capital cost is· more. sensitive in the lower load forecast than
in the higher electricity demand scenario.
In order to further test this assumption the Susitna long-term
cost and entire net benefit analysis was recomputed using the
.20, .50, .20 probability distribution for Susitna capital
costs. Table 4.15 summarizes this calculation. Using this
probability distribution, the expected value of long-term costs
is $7,433 million; approximately 5 to 6 percent higher than the
assumed distribution. Net benefits decrea$e in expected value
from $1,176 million to $1305 million, a decrease of about 30
percent. It can be concluded from this check that while the
amount of benefits is sensitive to the probabilities assign~d,
the economic feasibility results remain the same ...
(vi) Conclusions
-Given the potential alte~natjve futures generated by the four
variables analyzed, the Susitna alternative will be the least
cost plan 80 percent of the time.
-The expected value of long-term costs in the Susitna case is
$7,03 billion as compared to $8.48 billion in the non-Susitna
case.
-The expected value of net benefits to the Susitna project are
$1.45 billion, compared to $1.18 billion in the base case
economic analysis.
-The most sensitive variable in the study is the rate of real
fuel escalation adopted.
4-20
-'--·-- - - - - - - - - - - - - --·
Plan IO
Non-Susitna A
Susitna - c
TABLE 4.1: GENERATION PLANNING BASE PLANS
Components
600 MW coal-Beluga
200 MW coal-Nenana
630 MW GT
680 MW Watama
600 MW Oev ·i 1 Canyon
210 MW GT
1982 Prese$txW~~~h of System Costs
1
Cum. Costs 2010-Estimated Long-Term Cost Net
1993-2010 Annual 2011-2051 1993-2051 Benefit
3,213 491 5,025 8,238
3,119 385 ·3,943 7,062 1,176
1./ 2010 annua.l cost is projected 41 years at 3% and present worthed 28 years to 1982 at 3%
to arrive at the 2011-2051 estimated present worth.
-- -·\-- - - - - - - - - - - --~ - -
Plan ID
TABLE, 4.2: SENSITIVITY ANALYSIS-LOAD FORECAST
Components
Cum. Costs
1993-2010
1982 Present Wor~h of System Costs
$ X 10
2010
Annual
Estimated Long-Term Cost-Net
2011-2051 1993-2053 Benefit
1/ Long tenn present worth is computed for the period 1993 to 2053 for the low forecast since the full
-Susitna project is delayed until 2004.
y Long Term present worth is computed for the period 1993-2046 for the high forecast since the full
Susi-tna project is ~dvanced to 1997 o ·
--------.. ---------;--
TABLE 4.3: SENSITIVITY ANALYSIS -ECONOMIC INTEREST/DISCOUNT RATE
Plan ID
Non-Susitna Q1
Susitna Q2
Non-Susitna A
Susitna c
Non-Susitna sl
Susitna s2
Non-Susitna pl
Susitna P2
Interest/
Discount Rate
2%
2%
3%
3%
,. 4%
4%
5%
5%
!/ 2010 annual cost is projected 41 years
1982 Present Worth of System Costs
. $ X 106
1
Cum. Costs Annual-Estimated Long-Term Cost Net
1993-2010 2010 2011-2051 1993-2051 Benefit
3,701 465 7'1766 11,167
3,156 323 5,394 8,550 2,617
3,213 491 5,025 8~238
_3, 119 385 3,943 7,-062 1,176
2'1891 517 3,444 6'1235
3'1080 457 3,046 6,126 109
2'1468 550 2,478 4,946
3'1032 539 2,426 5,459 (513}
at the appropriate interest/discount rate and then present
worthed to 1982 to arrive at the 2011-2051 estimated present worth.
. 'I
'
• ·C 1
.,
,. .. ~-•~~r---·~~~~
-----------------~--
Plan
Alternative Capital
Costs +20%
Non-Susitna
Susitna
Alternative Capital
Costs -10%
Non-Susitna
Susitna
Susitna Capital Cost
Less Contingency
Non-Susitna
Susitna
Susitna Capital Cost
Plus Double Contingency
Non-Susitna
Susitna
ID
TABLE 4.4: SENSITIVITY ANALYSIS -CAPITAL COSTS
Cum. Costs
1993-2010
3,460
3,119 °
3,084
3,119
3,213
2,710
3,213
.. 3,529
1982 Present Wor~h of System Costs
$ X 10
Annua~
2010
528
385
472
385
491
336
491
434
Estimated Long-Term Cost Net
2011-2051 1993-2051 Benefit
5,398
3,943
4,831
3,943
5,025
3,441
5,025
4,445
8,858
7,062
7,915
7,062
8,238
6,151
8,238
7,974
1,976
853-
2,087
264
* An adjustment calculation was made regarding the !: caoital costs of the 3 GT units added in
2007-2010 -since the di.fference was less than $10 x lObG In the long term cost, the effect
was not included.
"
--------------·---:--
Plan IO
Non-Susitna A
Susitna c
Susitna
TABLE 4.5: SENSITIVITY ANALYSIS -DELAY OF PROJECT
Components
600 MW Coal ... Beluga
200 t4W Co a 1 -Nenana
630 MW GT
680 MW Watana (1993}
600 MW Devil Canyon (2002)
210 MW GT
680 MW Watana (1995}
600 MW Devil Canyon (2004)
210 MW GT
Cum. Costs
1993-2010
3,213
3,119
3,099
1982 Present Worth 6of System Costs
$X 10
Annual Estimated Long-Term Cost
2010 20ll-20xxY 1993-20xx
"
5,025 8,238 (A)
491 5,087 8,299 ~B~ 5,147 8,360 c
385 3,943 7,062
394 4,131 7,230
,, ' ..........___..
N.e;it
Be~fit --....
.....
''"~~
1, ll!S (A)2l
1,130 (C)
1./ Delay of the Susitna project extends analysis period from 2051 (A) to 2052 (.8} and ~053 (C), respectively.
2/ Non-Susitna long-term cost comparison.
--.... --------------:--
TABLE 4.6: SENSITIVITY ANALYSIS -REAL ESCALATION
Plan
Zero Escalation Capital
Non -Sus i tn a
Susitna -? ~"
1.4% Escalation Capital
Non-:Susitna
Susitna
ID
Cost
01
02
Cost
x1
x2
and O&M
Cum. Costs
1993-2010
2,838
2,525
3,142
2,988
Ooub1e Escalation Capital Cost and O&M
Non-Susitna R1 3,650
Susitna R2· 3,881
Zero Esca·1ation Fuel Costs
Non-Susitna vl 2,233
Susitna Vf 3,002
High Escalation Fuel Costs
Non-Susitna wl 4,063
Susitna w2 3,267
1982 Present Worth of System Costs
$ X 106
Annual
2010
422
299
477
366
602
503
335
365
643
403
Estimated Long ... Term Cost Net
2011-2051 1993-2051 Benefit
4,319 7,157
3,060 5,585 1,572
4,881 8,023
3,745 6,733 1,290
6,161 9,811
5,148 9,029 782
3,427 5 .. ,560
3,736 6,738 {1,078)
6,574 10,367
4,121 7,388 2,979
- - - - - - - - - - - - - - ---- - ---,
e
TABLE 4.7: -SE~SITIVfTY ANALYSIS -COAL PRICEs!/
Plan ID
Non-Susitna Tl
Non-Susitna T2
Non-Susitna
TJ
Susitna c
Components
200 MW Coal
200 MW Coal
630 MW GT
800 MW CC
700 MW GT
-Beluga
-Nenana
600 MW Coal -Beluga
200 MW Co a 1 -Nenana
630 MW ,GT
680 MW Watana"
600 MW Devil Canyon
210 MW GT
1/ Coal price@ $2.08/MMBtu (1982).
2/ Non-Susitna plan comparison.
1982 Present Worth 6of·System Costs
$ X 10
Cum. Costs Annual Est·imated Long-Term Cost
1993-2010 2010 2011-2051 1993-2051
3,375 522 5,346 8,721
3,062 512 5,336 8,298
3,514 589 5,516 9,030
3,119 385 3,943 7,062
Net
B f'"~ ene:1'!~
-
11 659 {Tl)f/
1,236 (T2)
1,968 (T3)
- ----·----·-- --- ----
TABLE 4 •. 8: SENSITIVITY ANALYSIS -OTHER HYDRO PROJECTS .
Plan
Non-Susitna
with
Chakachamna
Susitna
Non-Susitna
with
Bradley Lake
-
Non-Susitna
without
Bradley Lake
Susitna
without
Bradley Lake
10
B
Components
330 MW Chakachamna
400 MW Coal-Beluga
200 MW Coal-Nenana
400 MW GT
C · 680 MW Watana ~
600 MW Devil Canyon
180 MW GT
A 90 MW Bradley Lake
600 MW Coal-Beluga
200 MW Coal-Nenana
630 MW GT
Fl 800 MW Coal-Beluga
200 MW Coal .. ·Nenana
560 MW GT
140 MW GT (88, 91)
F2 680 MW Watana
600 MW Devil Canyon
70 MW GT
140 MW GT (~8, 91}
1982 Present Worth of System Costs
$ X 10 6
Cum. Costs 2010 Estimated Long-Term Cost Net
1993-2010 Annual 2011-2051 1993~2051 Benefit
3,038 475 4,861 7,899
3,119 385 3,943 7,062 837
1/
(88) 3,213 491 5,025 8,238-
1/
3,.368 525 5,375 8,743-
1/
3,234 396 4,055 7,289-1,454 (Fl)
949 {A)
1/ Note that these long-term costs cia not include the capital cost of Bradley Lake. -
'I
I
I
I
I I
I
I
'I
I
I
I
I
I
I
I
I
I
I
I
Type/Size
MW
Coal/200 MW
@ Beluga
Coal/200 MW
@ Nenana
Gas Turbine/
70 MW
Combined Cycle/
200 MW
Probability of
Occurreqce
.
TABLE 4.9: MULTIVARIATE SENSITIVITY ANALYSIS
ALTERNATIVE CAPITAL COSTs!/
Low
$/k.;.;
2~018
2,073
572
996
0.20
Medium
$/kW?:/
2,242
2,303
636
1,107
0.60
High
$/kW y
2~690
2.764
763
1,328
0.20
1/ reveloped by Ebasco for the Railbelt Alternatives Study being
completed by Battelle
2/ Inc·{ udes AFOC.
I
i I ·TABLE 4.10: MULTIVARIATE SENSITIVITY. ANALYSIS
I
FUEL COSTS AND ESCALATION tJ
Probabi l_ity 0.25 0.50 0.25
I of Occurrence
HEALY COAL @ HEALY
I Year Low Medium ~is~ 1993 $!.46 11.94 $
1995 1.46 2.04 2.75
2000 1.46 2.32 3.51
·I 2005 1.46 2.46 3.91
2010 1.46 2.61 4.36
I HEALY COAL @ NENANA
i:
Year Low Medium High
I 1993 11.""75 $2.25 $2.84
1995 1.75 2.35 3.10
2000 1.75 2.64 3.87
2005 1.75 2.79 4.25
I 2010 1.75 2.95 4.67
BELUGA COAL
I Year Low Medium High
1993 Uo43 $1 .. 90 $2.45'
1995 1.43 2.00 2.69
I 2000 1.43 2.27 3.43
2005 1.43 2.41 3.82
2010 1.43 2.56 4.26
I NATURAL GAS.
Year Low Medium Hi h I 1993 ~00 $3.03 $~
1995 3.00 3.27 5.65
2000 3.00 4.80 7.22
I 2005 3.00 5.30 7.97
2010 3.00 5.85 8.80
I OIL
Year Low Medium ~ I993. ~50 l8~08 $1 ·I 1995 6.50 8.41 10.83
2000 6.50 9.28 13.17
2005 ~ 6.50 10.25 19.54
I 2010 6.50 11.32 16.05
I 1/ Base prices and escalation gatterns derived from Battelle and -Acres meetings and researc • · ·
I
'~~ ... ~
r;
I
I
I
I
·I
I
I
I
I
I
I
I
I
·I
I
I
I
I
·.I
iABLE 4.11: MULTIVARIATE SENSITIVITY ANALYSIS
SUSlTNA CAP I TAL COSTS ]j ~
Millions January 1982 $
Low Medium
Watana
Capital Cost $3,039 $3,647
AFDC 373 447
Devil Canyon
2/
Capital Cost $1,225 $1,470
AFDC 134 161
Total Cost $4,771 $5,725
Probability of
Occurrence 0.60 0.25
High .
$4,255
521
$1,714
188
$6,679
0 .. 15
l/ Based on the Susitna Project estimate of $5,117 million without
AFDC.
21 This differs from the final feasibility study report by $10
million.
Note: Low capital cost is computed as medium divided by 1 •. 20 and is equal
to a zero percent contingency. High capital cost is computed as
the low times 1.4 and represents a double (40 percent) contingency.
~ I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
TABLE 4.12: MULTIVARIATE SENSITIVITY ANALYSIS
LONG-TERM COSTS AND PROBABILITY
NON-SUSITNA TREE
(1982$~
$ X 10
Rank (Low 1/ Long-term
-High} IO-Cost
1 T27 4412
2 T24 4590
3 T21 4856
4 T18 5489
5 Tl5 5661
6 T12 5991
7 T26 6101
8 T23 6878
9 T09 7184
10 T06 7313
11 T20 7460
12 T03 7624
13 T17 7915
14 T14 8238
15 T25 8492
16. T22 8746"
17 T11 8858
18 Tl9 9253
19 T16 10321
20 T08 10503
21 T13 10637
22 T05 10859
23 TlO 11272
24 T02 11569
25 T07 13742
26 T04 14194
27 T01 15058
1/ Relates to Figure 4.1
~/ LTC -long-term costs
Cumula-
tive
Proba-Proba-
bility bility
.01 .01
.03 .04
.01 .05
.03 .08
.09 .17
.03 .20
.02 .22
.06 .28
.01 .29
.03 .32
.02 .34
.01 .35
.06 .41
.18 .59
.01 .60
.03 .63
.06 c69
.01 .70
.03 • 73
.02 .75
.09 .84
.06 .90
.03 • 93
.02 ~95
.01 .96
.03 .99
.01 1.00
1.00
2/
Incre--
mental
LTC
44.12
137.70
48.56
164.67
509.49
179.73
122.02
412.68
71.84
219.39
149.20
76.24
474.90
1482.84
84.92
262.38
531.48
92.53
309.63
210.06
957.33
651.54
338.16
231.38
137.42
425 .. 82
150.58
Cumula-
tive
LTC
44
189
~30
395
905
1084
1206
1619
1691
1910.
2059
2136
2611
4093
4178
4441
4972
5065
5374
5584
6541
7193
7531
7763
7900
8326
8476
I
I
·TABLE 4.13: MULTIVARIATE SENSITIVITY ANALYSIS!
LONG-TERM COSTS AND PROBABILITY
SUSITNA TREE
I !1982$~ Cumula ... 2/
X 10 t1ve lncre--Cumula-
I Rank (Low 1/ Long-term Proba-Proba-mental tive -High) ID-Cost bilit,x bility LTC LTC
1 S45 5543 .03 .0300 166.29 166
I 2 S42 5757 . 06 .0900 345.42 . 512
3 S36 5827 .09 .1800 524.43 1036
4 539 6097 .03 .2100 182.91 1219
5 S33 6151 .18 .3900 1107.18 2327 I 6 544 6437 .0125 .4025 80.46 2407
7 530 6477 .09 .4925 582.93 2990
8 541 6650 .025 .5175 166.25 3156
.I 9 535 6738 .0375 .5555 252.67 3408 10 S38 69~1 .0125 .5675 87.38 3496
11 532 7062 .075 .6425 529 .. 65 4026
I 12 S27 7087 .006 .6485 42.52 4068
13 518 7108 .018 .6665 127.94 4196
14 S09 7151 .006 .6725 42.91 4239
15 S43 7331 .0075 .6800 54.98 4294
I 16 S29 7388 .. 0375 .,7175 . 277.05 4571
17 S40 7543 .015 .7325 113.15 4684
18 S34 7650 .0225 .7550 172.12 4856
I 19 S37 7884 .0075 .7625 59.13 4915
20 S31 7974 .045 .8075 358.83 5274
21 S26 7986 .0025 .8100 19.96 5294
22 S17 8008 .0075 .8175 60.06 5354 I 23 SOB 8050 .0025 .8200 20.12 5374
24 S24 8326 .012 .8320 99.91 5474
25 515 8347 .. 036 .8680 300.49 5775
I 26 S28 8371 .0225 .. 8905 188.35 5963
27 S06 8390 .012 .9025 100.68 -6064
28 525 8886 .0015 .9040 13.33 6077
I 29 S16 8908 .0045 .9085 40.09 6117
30 S07 8951 :oo15 .9100 13.43 6131
31 S23 9225 .005 .9150 46.12 6177
32 ? 514 9247 .015 .9300 138.70 6315
I 33 sos 9290 .005 .9350 46.45 6362
34 S21 9614 .006 .9410 . 57 .. 68 6420
35 512 9758 .018 .9590 175.64 6595
I 36 S03 9784 .006 .9650 58.70 6654
37 S22 10126 .. 003 .9680 30.38 6684
-38 Sl3 10147 .009 .9770 91.32 6776
I 39 504 10190 .003 .9800 30.57 6806
40 S20 10514 .0025 .9825 26 .. 29 6833 > 41 Sl1 . 10658 .0075 .9900 . 79.94 6912
42 S02 10683 .0025 .9925 26.70 6939
I 43 Sl9 11414 .0015 .9940 17.12 6956
44 510 11558 .0045 .9985 52.01 7008
45 SOl 11584 .0015 1 .. 0000 17.38 7026
I r.ooo #
1/ Relates to Figure 4.2 2/ Long-Term Costs
I
-"· "l. .. -·"'·<''.: -~· ..
<,,_-. -
I
~· TABLE 4.14: MULTIVARIATE SENSITIVITY ANALYSIS
CALCULATION.OF NET BENEFITS
I
I Net Comparison T-ID S-10 p T-LTC S-LTC Benefit
1 TOl SOl .0015 15058 11584 3474
I 2 T01 S02 .0025 15058 10683 4375
3 TOl 503 .006 15058 9784 5274
11569 I 4 T02 S04 .003 10190 1379
I .s T02 S05 .005 . 11569 9290 2279
6 T02 .. 506 .. 012 11569 8390 3179 7 T03 S07 .0015 7624 8951 (1327)
8 T03 SOB .0025 7624 8051 (427) I 9 T03 . S09 .006 7624 . 7151 473
10 T04 510 .0045 14194 11558 2636 11 T04 511 .0075 14194 10658. 3536
I 12 T04 512 .018 14194 9758 4436 13 T05 Sl3 .009 10859 10147 712 14 T05 Sl4 . 015 10859 9247 1612
I 15 T05 Sl5 .036 10859 8347 2512
16 T06 516 .0045 7313 8908 (1595~ 17 T06 517 .. 0075 7313 8008 (695 18 T06 518 .018 7313 7108 205 I 19 T07 S19 .0015 13742 11414 2328
20 T07 520 .0025 13742 10514 3228 21 T07 S21 .006 13742 9614 4128
I 22 TOB S22 .003 10503 10126 311 23 T08 S23 .005 105C3 9225 1278
24 T08 S24 .012 10503 8326 2117 25 T09 S25 .0015 7184 8886 (1702) I 26 T09 526 ~·0025 7184 7986 (802) n
27 T09 S27 (1 .006 7184 7087 97
28 TlO S28 .0045 11272 8371 2901
I 29 T13 528 .0135 10637 8371 2266
30 T16 S28 .0045 10321 8371 1950
31 T10 529 .0075 11272 7388 3884
I 32 T13 S29 .0225 10637 7388 3249 33 T16 S29 .0075 10321 7388 2933
34 T10 S30 .018 11272 6477 4795
35 T13 S30 .054 10637 6477 4160
I 36 T16 S30 .018 10321 6477 3844
37 T11 531 .. 009 8858 7974 884 38 T14 · S31 .027 8238 7974 264
I 39 T17 531 . .009 7915 7974 (59)
40 T11 S32 .015 8858 7062 1796
41 Tl4 S32 G045 8238 7062 1176
I
42 T17 S32 .015 7915 7062 853
I
I.
"" ...... -,
I
I TABLE 4.14: MULTIVARIATE SENSITIVITY ANALYSIS
I CALCULATION 0£ NET BENEfiTS, (CON.tJ!l
c
I Net Comparison T-ID S-ID p T-LTC S-LTC Benefit
43 T11 533 .. 036 8858 6151 2707
I 44 T14 S33 .108 8238 6151 2087 45 T17 533 .036 7915 6151 1764
46 Tl2 534 .0045 5991 7650 (1659)
I 47 Tl5 534 .0135 5661 7650 (1989) 48 Tl8 534 .0045; 5489 7650 (216ll 49 T12 S35 .0075 . 5991 6738 {747 50 Tl5 535. .0225 5661 6738 (1077) I 51 Tl8 S35 .0075 5489 6738 (1249) 52 T12 S36 .018 5991 5827 164 53 Tl5 S36 .054 5661 5827 (166)
I 54 Tl8 S36 .018 5489 5827 (338) 55 T19 S37 .0015 9253 7884 1369 .
56 T22 $37 • 0045 8746 7884 862
I 57 T25 S37 .0015 8492 7884 608
58 T19 S38 .0025 9253 6991 2262 59 T22 S38 .0075 8746 6991 1755 60 T25 S38 .0025 8492 6991 1501
I 61 Tl9 S39 .006 9253 6097 3156
62 T22 539 .018 8746 6097 2649 63 T25 ·S39 .006 8492 6097 2395
I 64 T20 S40-.003 7460 7543 (83~ 65 T23 540 .009 6878 7543 (665
66 T26 S40 .003 6101 7543 (1442) 67 T20 S4l .005 7460 6650 810 I 68 T23 S41 .015 6878 6650 228
69 T26 S41 ~ .. 005 6101 6650 (549) 70 T20 S42 .012 7460 5757 1703
I 71 T23 542 .036 6878 5757 1121
72 T26 542 .012 6101 5757 344 73 T21 S43 .0015 4856 7331 (2415)
I 74 T24 543 .0045 4590 7331 (2741} 75 T27 543 .0015 4412 7331 (2919)
76 T21 S44 .0025 4856 6437 (15Bll 77 T24 S44 .0075 4590 6437 (1847 .-. 78 T27 S44 .0025 4412 6437 (2025l 79 T21 S45 .006 4856 5543 (687
80 T24 S45 .018 4590 5543 (953)
I 81 T27 S45 .006 4412 5543 (1131)
I
I
I
~.-~ " -·· •.t· ,-"" :.~ ' .•. . . ·-. -~'"-' .... , ~-,.. ' .... ' ,. '"" ~ ·---~ • "k -~~-'·
I
I TABLE 4 .. 15: MULTIVARIATE SENSITIVITY ANALYSIS
"l;'':.ot.--.
I SUSITNA CAPITAL COST SENST!ViTY ANALYSIS
~1982$~ Cumula-2/
X 10 tive Incre--Cumula-I Rank {Low 1/ Long-term Proba-Proba-mental tive
; High) ID Cost bilitl bil it~ LTC LTC
I 1 545 5543 .010 ~010 55.43 55 2 542 5757 ~020 .030 115.14 170
3 S36 5827 .030 .060 174.81 345 4 S39 6097 .010 .070 60.97 406 I 5 S33 6151 .060 .130 369.06 775
6 S44 6437 .030 .160 193.11 968 ·1 7 530 6477 .030 .. 190 194.31 1162 ..
I 8 541 6650 .060 .250 399.00 1561
9 S35 6738 .090 .340 606.4.2 2168 10 S38 6991 .030 .370 209.73 2377
I 11 532 7062 .180 .550 1271.16 3649 12 S27 7087 .002 .552 14.17 3663
13 .S18 7108 .006 .558 42.65 3705
14 S09 7151 .002 .. 560 14.30 3720
I 15 543 7331-. .010 .570 73.31 3793 16 S29 7388 .090 .660 664.92 4458
17 S40 7543 .. 020 .680 150.86 4609
I 18 S34 7650 .030 .710 229.50 48~8 19 S37 7884 .010 .720 78.84 4917 ,; 20 S31 7974 .060 .. 780 478.44 5396
21 S26 7986 .006 .786 47.92 5444 I 22 S17 8008 .018 .804 144.14 5588
23 SOB 8050 e006 .810 48.3 5636
24 S24 8326 .004 .814 33.30 5669
I 25 Sl5 8347 .012 .. 826 100.16 5769
26 528 8371 .030 .856 251.13 6021
27 506 8390 ~004 .860 33e56 6054
I• 28 S25 8886 .002 .862 17.77 6072
29 Sl6 8908 .006 ~868 53.45 6125
30 507 8951 ·----002 .870 17.90 6143 ...
•
31 S23 9225' .012 ' .882 110.70 6254
I 32 S14 9247 .036 .918 332.89 6587
33 S05 9290 .012 .930 111.48 6698
34 521 9614 .002 .932 19 .. 23 6718
I 35 S12 9758 .006 .938 58o55 6776
36 503 9784 .002 .940 19.57 6796
37 S22 10126 .004 .944 40.50 ·6836
I 38 513 10147 "012 .956 121.76 6958
39 S04 10190 .. 004 .960 40.76 6999
40 · S20 10514 .006 .966 63.08 7062
41 S11 10658 .018 .984 191.84 7254
I 42 S02 10683 .006 .990 64.10 7318
43 519 11414 .002 .992 22.83 7341
44 510 11558 .006 .. 998 69.35 7410
I 45 SOl 11584 .002 .1.0000 23.17 7433
1/ Re 1 ates to Figure 4. 2 _ ~I Long-Term Costs
-I
-~
·~ ····--· ~~.
--------.. -r-·
YEAR
·NON
SUSITNA
2010
.
2046
I I
I i
~~~~~----~------~~----------------------------~--~~
SUSITNA
HIGH LOAD
FORECAST
SUStTNA
MEDIUM LOAD
FORECAST
50 YEARS
OF SUSITNA
I I
I I
I I
I l
I t
I i
~,..,..,...,..,...,~.,-J.-------+--___:.-------------_...---;1 I
I 50 YEARS ~~----~~--------~----O~F~S~U~S~IT~N~A--~~--------------~
~~~~UL------------~------------------------------~
50 YEARS
OF SUSITNA
I
I
I
I
I
\... --~~-----y~------A~----------~------~y-------~----------~ y
I
.I
COMMON TO MODELLED BY EXTENDED BY ECONOMIC
ALL PLANS OGP ANALYSIS METHOD
LONG TERM
PW --CUMULATIVE CUMULATIVE
1982 PW
-
:iN 1882 t
1982 PW +
YEARS 1993·2010 YEARS 2011 TO 2046 -el-53 CH,M,Ll
FMilM 4.1 fill -LONG-TERM COST CONCEPT
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
PRESENT WORTH
OF
.LONG-TERM
COSTSI982I
NET BENEFITS
1993-2010
PRODUCTION
COSTS
COMMON
1982-1992
NON-SUSITNA SUSITNA
PLAN PLAN
NET BENEFITS(+)
xx-THE YEAR VARIES DUE TO DIFFERENT STAGE OF SUSITNA PROJECT WITH
RESPECT TO LOAD FORECAST.
FIGURE. 4. 2 IIIII
I
I
I
I
I
I
I
I
I
.I
I
I
I
I
I
I
I
I
I
OTHERS:·
(01 L/ HYDRO)
. 5004------------------------------------------I
-(/) z
0 -_,
..J -
1-
U)
0
0
..J
<(
:)
400..,.._ __
Z200~---
Z
4Ct
100
1993
CC 0 8 M
NG 0 8M
2000
YEAR
200S
CC NG FUEL
COST I
cc o aM
I
NGGT FU,L COSTS
·~~,....._ G; 0 e. T
NATURA\..
G.AS GTI
INVEST" ENI
1---COSTS
'///..,..._COAL .
20t0
INVESTMENT
COSTS
NON-.SUSITNA PLAN MEDIUM LOAD FORECAST
.. EHUUII ·4.al11l.
500~~~-----------------------------------~~----------~
-
325.0
~~0;---------~--------~~~-;~~~~~~~-----~ ~~~~ ~
0
_J
-t :::> z z
<t 200 -f--~:w:.:;:;~
1993 2000 2002 2005 2010
Y·EAR
SUSITNA PLAN MEDIUM LQtO.D FORECAST
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
'I
I
----~-~--~~=-c-----.,.....
--------------------------------------~------------~----~ .. ~~>--------
-...J _. -
450
400
:E 300
....
~
0
>~
• .J 250
D:
<[
11.1
)-
200
a eo
1990
MEDIUM LOAD
FORECAST
NON SUSITNA PLAN
1995 2000
YEAR
200S 2010
~v.EARLY ANNUAL COSTS
-•··•••• •.• [ii]
,,
I
I
I
I
I
I
I
I
I
I
I
1,~
I
I
I
-I
I
:1
z -C!) a: c :.
IAJ -> ~·.
0)
Ill ac
~
90
80
70
60
eo
40
30
20
MEOtUM LOAD
FORECAST
SUSITNA PLAN
,-
10~--~--~~--------~~~ .. ~~~
1990 1995 ' 2005 2010
YEAR
PERCENT RESERVE YSo TI~.~.J.AHIE ... Jiil
-0
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
., I
9~~------~·----------~
70001--------~-------NoN-SUSITNA PLAN ==~= .... ~-t----:~ ,""' ,
~ ~,
liJ
1-
0 ,_;.
0~~~------+-------~~~--~~-----+------~~----~
-~
0
~
Q..
11.1 3000
> -~
. ...J
:;)
ECONOMIC EXTENSION
. '
'2: 2000 1-------------+--~---+-------+-------4------+--------1 :E
:::) ·;u
1000~----~+---------~------~-------4------~~----·~
0 -
1990 2000 2010 20!0 2040
YEAR
MEDIUM LOAD· FORECAST----L-ONG TERM COSTS
)" ------·-.~~·---·~:•-w--•-
, •••• 4.7.
I
I
I •
I
I
I
-------------------
..
3000~------~----~~------~------~~------~--~---
\
-8
0 2000
~ -
(f)
1-
I u. w z w 1000 £I)
t-BREAK EVE
UJ POINT z
I t
0 2°/o 3°/o 5°/o
I ~AL INTE:RE:ST RATE ........ ._
-1000
-2000~------~------~------~--------~------~------~
INTEREST RATE SENSITIVITY
U~E. 4.8
-------------------
LOAD ALTERNATIVE FUEL COST RESULT LONG-TERMt --COST
FORECAST CAPITAL COST ESCALATION 10 PROBABILITY PRESENT \WORTH
MICJM IOI 01 ll!SO!JI: HitMI Ole -~ ... I02 Q2 IJ569•
T03 .DI 11624?-
T04 03 14194
HIIN 10 MEDtUM. J05 .OS I()!S'
T06 03 7lt':!
I07 04 037'42 LDW JM toe 02 1050S:
09 01 7t84-::""""'·'"
HltiM Jl IJQ 03 1121!-'
IlL..._ 06 13'51~
IJ2 03
... ~
~911-~---
10 ME'Dt\JIIil I13 09 t0&31'
~=:-r
P.2 J8 8~JI· ,..
:u; -~ ·:· "-~
,LI.,;:
tif .03 1032t
tJ)W Jl i aa-•-::: :
HUIIt 011 ~~ Ot =~-oz : 01 21
I22 OS 1745' .. ...... ... co·
123 £11 --liM·
n~ -QI ~l ..... I25 Dt ...
LDIIf JM .... _ IK D! liCit u. 127 Dt ...
-' I• tOO
NON· SUSITNA PROBABILITY TREE
FIGURE 4.9
·:--·-· --- - - - -
l
LOAD
FORECAST
........_ -
LOW
-- -
RESULT
10 -SOl
S02
S03
$~ -·
lSi
SOl m
SJO
Sl.L
512
Sl3
~, .. ···-t.z.J-w:
SIS
Sl6
Sl7 Sl8
519.
S20
S21
s~~
523
S.2!t
525
52' S2
52.8
S29 uo
5.31
&32
533
SM
HI
S37 m
H)
H~
S..4!
II
-----------
ffiOBABILI!r
®!!
®~
0060
ao~
~
QtZQ
001~
~
0040~
.00~
Q)aG
,0090
QI!IO
,Q~tll
0,24~
o~m~
QlJQ
DOl~
.QQ.Z~
QOf.iQ
~~
0050
Ql20 001, =-· .02a
.Q~:Z:.
D9C.D
,04~
Q~
.1100
.oz~
~
00"
~
OllO
D~ ·Q5ao
.007! • I·•.oooo
SUSITNA PROBABILITY TREE
----LONG-TEAt* CST
PRESENT W0.!RnJ
. Ill~
JC.'IML su•
Q90
L~
8"' 10!10
71~1 : .. ~~
10658
9'P.II
10141
9Z41
U4l
89(lt
tQ;)t
,.,~ f .....
Jt~··
IQ!) ..
~~ ---Nlc;w
!2ZI ~ ·~ MM ,.
zt4M -1371
1311
6477
1'9)t
11011
&Itt
1UI)
57311 .
5127 = ,..
C!llt gt . ..
~s
S&50
~.,
'"' mi
FIGURE 4.10
--------------------
--2 • .... -
II
10
I
•
l.F
•
I
Ht
I
I
~"
r -I
,r ~
I
r-
..
~
.
.10 .10 .40 JO .to .ro
CUMULATJVE PfltOeAfMLITY
SUSITNA MULTIVARIATE SENSITIVITY ANALYSIS
LONG-TERM COSTS VS CUMULATIVE PROBABILITY
NON .-SUSITNA PLAN
F
J
.10 .• o 00 I.
FIGURE 4.11 IiJ
-------------------
tl
-.,..... , ..
,:"
I;
·~ -., ....
41)
0 u
2 •
0:
"" ...
" z
0 _,
•
I
' .
,._...
I)
.
.o
I
•
I I
.-r-
_J -, r
.
.
.10 .10 ~·0 . ~ID .ue .'0
CUMUL.AT1VE ,_.ABILITY
SUSITNA MULTIVARIATE SENSITIVITY ANALYSIS
LONG-TERM COSTS VS CUMULATIVE PROBABILITY
SUSITNA PLAN
J
? -r
.IIU JIG ~~
. • FIGURE 4.121il
c/·
.-.. _..:, .._ ···-· :~.~.... . .. •.-e..:.m;,..._~n-t·~""":,;rezt=?:fu~ .. ~ • ., •. ,"~· .. "'~··rb#it:If
- - --
•
[:F
I
"
-- --- -- --
)
~
l I I -NON• SU! 11'-.A fii.AN • r1 I"""N"' ,.
----. _1 --
rl ~ __,.,-~ l _j
1' ~
~~---......
A I'LANj ""' r---SUIITl
<
. •• •• . I .
CUMULATtV£ f'ROIAIILITY
SUSITNA MULTIVARIATE SENSITIVITY ANALYSIS
LONG-TERM COSTS VS CUMULATiVE · PROBABILITY . . .
-
_j
J
'
•
- -
--
~
~
-
11
j
r ~ J
. ~
FIGURE 4.S
-
- - - - - - - - - - - - - - -·--·--
l .0
t
•
>-..... -7
...J -en
~.
CD
0 a:
0..·
"' >. -
I
5
4
.I
·-· -· --~ -·
~--·-·--
=·-t±L __ .
I ---t ··-··--·~ I· I I I r I 1 ' -,...--
. [
t
---· -·--
..,...,.. .. --. ·--
.. ,_ .. _ • .. -
~-.... ------~ ..... -
I
<
• -W4------·· ... ·-~ • • . _,_,...__,...
... __ J ___ l
---:---.
' I
-
~ -~ ~·-I /
,....
-l -. --. ._ __ ...
;. ! I -.
I . i ..... I I .. . ·--. .. --l ' I l ' ' i
!
i t t--· • ·-' ' , ....... ....., ;
' I ;
-1
J
: -·· -.... -·' ' ' I ' . l ' l I . • --. -· ·t-·--·;-· __ .....,.__,
I ! I
I ' .
L-·-----~ . '
' .I -----·-v -~---6----··-·· -1-·-·· ..
./_ •
' .I --·--· ·------~ ~
( 4100) C1G00) t 2500) (1100) (ICO) 0 100
NE~ BENEFIT
$•10 (1912 $ )
SUSITNA MULTIVARIATE SENSITIVITY ANALYSIS
CUMULATIVE PROBABILITY VS NET BENEF.ITS
I
1100
"... ..... Iil
-------------------
-cnQ ,.
* -~
en
1-en
0
(..)
~ a::
LtJ
f-
(.1) z
0
...J
·----------------------~~--------------~~~
INCREASING LOAD FORECAST •
NON-SUSITNA HIGH FUEL COST ESCALATION
SUSITNA LOW FUEL
COST ESCALATION
0.1 0.2 0.3
SUSITNA HIGH FUEL
COST ESCALATION
NON-SUSlTNA LOW FUEL COST
ESCALATION
0.4 0.5 0.6
CUMULATIVE PROBABILITY
0.7
SUSITNA FUEL COST SENSITIVITY
NORMALIZED PLOTS
0.8 0.9 1.0
FIGURE 4.15 {i]
-----------·---.
15 "
14
l-:t .... I
-
INCREASING LOAD FORECAST ... ~·
_1 12 i .I I ,..
• ,.._. -II I
mo
' i _ _,..r-_ _r---~ i -'* ! -10 .... -CJ) ,..._..
1-
Cl) r 0 9 -(.) r----_.. ~
NON-SUSITNA PLAN .J .. ~ Ill' a: ~------I UJ 8 ;/-~-SUSITNA HIGH CAPITAL COST 1-
~ ,-1 r-z 7 ' ... g r--'
I SUSITNA LOW C_APlTAL COST I •
6
......
• ~--I-.-
5 I
r-•
f*--r .
4 .
'1111: ..
' I
0.1 0.2 0.3 0.4 0.5 0.6 o:r 0.8 0.9 1.0
' CUMULATIVE PROBABILITY
SUS I TNA CAPITAL COST SENSITIVITY [ij] :
NORMALIZED PLOTS
. FIGURE 4 .. 16 ' ,, ·. ;. ..
I
I
I
I
(I
I
I
I
, I
I
I
I
I
I
I
I
I
I
"-"1
5 -GENERATION PLANNlNG OGP MODEL OUTPUT SUMMARIES
I
'I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
TABLE 5.1: SU~1MARY OF GENERATION PLANNING OGP RUNS -DIRECTORY
Run Plan OGP ID
*A · Non-Susitna L9J9
*B Non-Susitna L9El
and Chakachamna,
*C Susitna Wat~na/DC L9K3
D Sus itna DC/Watana LG16
E Chakachamna/DC LG17
Fl Non-Susitna L331
without Bradley Lake
*F2 Susitna L9F3
without Bradley Lake
*Gl Alternative's L3Nl
Cap. cost + 20%
G2 Susitna "C" L9K3
COMMENTS
Non-Susitna Base Plan
with 330 MW Chakachamna
in 1993
Watana 680 MW 1993 Watana
680 2002
Devil Canyon 600 1993
Watana 680 2002
Chakachamna 1993 330 MW
Devil Canyon 1997
Non-Susitna
Susitna
Non-Susitna
$ X 106 (82$)
Long-Term Cost
8,238
7,899
7,062
7,221
8,069
8,743
7,289
8,858
with manual adjustment of three gas turbine costs -10% 7,076
*Hl Alternative's
Cap. cost -10%
L303 Non-Susitna 7,915
H2 Susitna 11 C11 L9K3 7,056
with manual adjustment of three gas turbine costs -10%
*Jl High Load Forecast L4Wl
*J2 High Load Forecast LC15
*Kl Low Load Forecast Ll95
*K2 Low Load Forecast L9K7
"*01 O&M and Cost
Escalation = 0%
L4Z5
*02 O&M and Cost . L4Z7
Escalation = 0%
* OGP summaries included.
Non-Susitna 10,859
Susitna: Watana 1993 Devil 9,247.
Canyon 1997
Non-Susitna 6,878
Susitna: Watana 1995 Devil 6!'650
Canyon 2004
Non-Susitna "A" 7,157
Susitna "C 11 5,585
I
I
I
I ,.
I
I
I
,I
I
I
I
I
I
I
I
I
I
I
TABLE 5.1: SUMMARY OF GENERAtiON PLANNING OGP RUNS ... DIRECTOR! (Cont'd)
Run Plan OGP ID COMMENTS
*Pl
*P2
Interest Rate = 5% t9J7
Interest Rate = 5% L9J5
*Ql Interest Rate = 2% LD23
*Q2 Interest Rate = 2% LD27
*Rl O&M and Cost
Escalation : 4%
*R2 O&M and Cost
Escalation = 4%
LD31
LD33
Sl Interest Rate = 4% L431
S2 Interest Rate = 4% L439
*Tl High Co a 1 Cost
($2.08)
*T2 High Coal Cost
($2.08)
L3S3
L7Z5
*T3 High Coal Cost L7Z9
($2.08)
*Ul Susitna Less LOX3
Contingency
*U2 Susitna Plus L4L9
Double Contingency
*Vl Zero Fuel
Escalation
*V2 Zero Fue 1
Escalation
*Wl High Fuel
Escalation
*W2 High Fuel
Escalation
LI23
L3Y3
LI15
L4Ml
*Xl Capita 1 Cost LCJ7
Esca.lation = 1.4%
*X2 Capital Cost LCJ9
Escalation = 1.4%·
* OGP summaries included.
Susitna 11 C:
Non-Susitria i'A 11
Susitna 11 C:
Non-Susitna "A"
Susi tna "C"
Non-Susitna "A"
Susitna "C 11
Non-Susitna (Optimized)
Susitna "C"
Non Sus itna 11 A''
0% Contingency (S33)
40% Contingency (S31)
Non-Susitna {Tl5)
Susitna (S35)
Non-Susitna (Tl3)
Susitna {S29)
Non-Susitna
Susitna
$ x 1o6 (82$)
Long ... Term Cost
7,157
5,449
11~167
8,550
9,811 ..
9,029
6,235
6,126
9,721
9,030
6,151
7,974
10,367
6,838
7,388
8,023
·'·
6,733 0
. .
'I"
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
~·---1
I
~l:..a .. l..J~L ELECTRIC COMF't1NY .
OGP-5 ii'EHER~1TION F·LANNING PROGRAM-SUJiliARY ~OUTPUT
ttll*~*M*t***~*lW'******************************
flLf.lSI\A ti:A lLBELT RUN A
~:EF:O% -3%
JOB NUMBER 2ML9J9
****************************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYPE 1 2 3 4 5 6 7-10
OPTMZING 0 1993 1993 0 0 . 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 452 141 67 317 155 SUM= 1190
**********************************************~************************
YR
** 93
94
95
96
97
98
99
0
1
2
Y E A R L Y M W A D D I T I 0 N S
*****~* ******* ******* ******* ******* ******* ***** 200*
lX 200
1X
lX
lX
70
70
70
TOTAL
CAPAB.
+ TIES
****** **** ·1373
1542
1495
1624
1620
1635
1635
1591
1661
16'08
3 lX 70 1625
4 lX 70 1695
5 2X 70 -1747
6 lX 70, 1794
7 lX 200 1994
8 1968
9 1X 70 · 2037
10 2037
**************************************************************~******** * *** * ***** *** * * **~: ** * * * * **** **** * * * ***.* ***** ******** **************** * ** MW A!tD 0 800 630 0 0 0 0 SUH= 1430
HW RET 0 -46 -335 -141 -61 . 0 0 SUH= -583
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 813 746 0 .6 317 155 SUM= 2037
PCT TOT O. 39.9 36~6 o. 0.3 15.6 7.6 SUM=lOO PCT
*********************************************************************** AUTO 0 400 630 0 0 0 0 SUM= 1030
PCT T(JT O. 38.8 61.2 O. o. · o. o,. SUM=lOO PCT
* COMMI TTEI• M.W
I
I
I
I
I
I
I
I
I
I
I
I
'I
I
I
I
·I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING-PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAILBELT RUN A
ZERO?. .... 3%
JOB NUMBER 2ML9J9
****************************************
YEAR
**** 1993
1994
1995
1996
1997
1.998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
YR
** 93
94
95
96
97
98
99
0
1
2
3
J4
5
6
7
8
9
10
LOAil
***** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1 "')-:-•3 4~
1270
1323
1377
1430
1484
1537
POOL
F'EAK
<MW>
****** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
TOTAL CAPABILITY
<INCLUDING TIES>
YEAR TIME OF
ENII PEAK
***** ***** 1373 1373
1542
. 1495
1624
1620
1635
1635
1591
1661
1608
1625
1695
1747
1794
1994
1969
2037
2037
TOTAL
ENERGY
<GWH>
******* 4736
4829
4922
5031
5141
5250
5360
5469
5661
5853
6044
6236
6428
6701
6973
7246
7518
7791
1542
1·495
1624
1620
1635
1635
1591
1661
1608
1625
1695
1747
1794
1994
1968
2037
2037
LOAD
FACTOR
****** 57.09
57.12
57.16
57.10
57.37
57.40
57.51
57.44
57.65
57.70
57.69
57.58
57.78
57.82
57~81
57.69
57.83
57.86
F'CT •
RES.
LOSS OF LOAit
PROBABILITY
D/Y H/Y
COST IN
YEARLY
COST
MILLION $
CUH. PW
TOTAL
**** 45.0 ****** ****** o.o63 o. ******* 176.1 ******* 127.2
59.8
52.0
61.9
58.4
56.6
53.6
46.8
48.2
38.9
35.9
37.5
37.6
35.6
44.8
37.6
37.3
32.5
TOTAL
COSTS
01IL.t>
****** 176
200
207
261.
271
282
289
295
308
316
332
348
372
395
430
448
471
491
0.027 o.
0.077 o •
0.059 o.
0.084 ·0.
0.092 o.
0.055 o.
0.059 o.
0.038 o ..
0.062 o.
0.087 o.
0.057 o.
0.049 o.
0.052 o.
0.023 o.
0.066 o.
0.051 o.
0.099 o.
200.2
206.9
26.0. 9
271.1
282 .• 4
288.5
295.0
307.8
316.4
332.5
348.1
372.4
395.4
429.9
448.2
471.1
491.0
267.6.
408.5
581.0
755.0
930.9
1105.5
1278.6
1454.3
1629.4
1808.2
1989.8
2178.5
2373.0
2578.3
2786.1
2998.2
3212.8
YEARLY $/MWH
********************************** INV, FUEL OfM M.I. TOTAL
***** ***** ***** ***** ****** 9.31 23.36 4.51 o. 37.18
15.31 21.39 4.75 o. 41-.45
15,02 22.22· 4e79 O. 42.03
22.69 23.88 5.28 o. 51.86
22.82 24.59 5.32 o. 52.73
22.96 25.45 ·5.38 o. 53.79
22.4s 25.97 5.38 o~ 53.83
22.04 26.60 5.29 o. 53.93
21.89 27.14 5.34 o. 54.37
21.17 27.61 5.27 o. 54.05
21.09 29.60 5.32 o. 55.01
21.02 29.40
21.54 30.89
21.22 32.20
25.93 29.77
24.95 30.93
24.58 32.03
23.72 33.20
5.40
5.50
s.ss
5.'96
5.97
6.05
6.11
0 •· o. o.
o.
o.
o.
o.
55.82
57.93
59.00
61.65
61.85
62.66
63.03
I
I
.I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
G
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALAS 1\ A R A I L BEL, T RUN B
ZERO/. -3/.:
JOB NUMBER 2ML9E1
:f ** * * ** * * * * * * * * * * ** * * * * * * * * * * * * * * * * * *{* * *.
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYPE 1 2 3 4 5 6 7-10
OPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 452 141 67 317 155 .SUM= 1190
********************************************************************~:* TOTAL
CAPAB+
YR Y E A R L Y M W A D D I T I 0 N S + TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 330* 1503
94 1472
95 1424
96 1354
97 200* 1480
98 , lX 70 1.495
99 1495
0 200* 1651
1 1651
2 lX 70 1668
3 1X 70 1685
4 1685
5 2X 70 1737
6 1714
7 lX ""0 ~ . 1784
8 1X 200 1958
9 1957
10 lX 70 2027
*********************************************************************** *********************************************************************** MW ADD 0 600 490 0 0 0 330 SUM= 1420
HW RET 0 -46 -335 -141 -61 0 0 SUM= -583
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 613 606 0 6 317 485 SUM= 2027
PCT TOT o. 30.2 29•9 o. 0.3 15.6 23.9 SUH~lOO PCT
*********************************************************************** AUTO 0 200 490 0 0 0 0 SUM= 690
PCT TOT o. 29.0 71.0 o. · o. {). O. SUM=100 PCT
* COMMITTED MW
II
I
I
I
I
I
I
I
I
I
I
I
I
I
I
:I
I
I
I
w 1,:! r· .... .:..· ..-; i::. I': i:. T\ t'1 i 1 u I'! r L ,; N N l h b :-h b t3 f( ,:., i"'l -s tJ N N A F\ y u u 1 F u T
il***t********************'*~*******************
riLASKA RAILI!ELT RUN B
ZERO% -3/~
JOB NUMBER 2ML9E1
********************~*******************
YE.:iF!
**** 1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004'
2005
2006
2007
2008
2009
2010
LOAD
***** 947
965
983
1004
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
POOL
PEAK
<MW>
TOTAL CAPABILITY
<INCLUDING TIES)
YEAR TIME OF
EN!! PEAK
**:'** *****. 1503
1472
1424
1354
1480
1495
1495
1651
1651
1668
1685
1685
1737
1714
1784
1958
1957
2027
TOTAL
·ENERGY
<GWH>
1503
1472
1424
1354
1480
1495
1495
1651
1651
1668
1685
1685
1737
1•714
1784
1958
1957
2027
LOAD
FACTOR YR
** 93 ****** 947 ******* 4736 ****** 57.09
94
95
96
97
98
99
0
1
2
3
4
5
6
7
8
9
10
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
4829
4922
5031
5141
5250
5360
5469
5661
5853
6044
6236
~42.8
6701
6973
'F'F'7246
7518
7791
57.13
57.16
57.10
57.37
57.41
57.51
57.43
57.65
57.70
57.69
57.58
57t78
57.82
57<~81
57.69
57.83
57.87
F'CT.
RES.
**** 58.7
52.5
44.9
35.0
44.7
43.2
40.5
52.3
47.3
44.1
40.9
36.7
36.8
29:6
29.6
36.9
31.9
31.9
TOTAL
COSTS
<MIL.$)
****** 166
172
179
210
240
'1C'l .:.....J
259
301
309
323
333
344
367
380
404
435
452
475
LOSS OF LOAD
f.'._R 0 B A B I L I T Y
It/Y H/ Y
COST IN
YEARLY
COST
MILLION $
CUM. PW
TOTAL
****** ****** ******* 166.1 *******! 120t0 o.ooo o.
' .0. 000 0.
o.oo2 o.
0.019 o.
0.025 o.
0.031 o.
0.046 o.
0.026 o.
0.045 o.
0.067 o.
Ot041 O.
0.069 o.
0.056 o.
0.071 o.
0.061 o.
0.038 o.
o.oaa o.
0.075 o.
172.2
179.4
210.0
240.2
251.1
258.9
300.8
308.7
322.5
. 333.5
344.2
367.4
380.0
403.8
435.3
451.7
475.0
YEARLY $/M~JH
•240.8
363.0
501.9
656.0
812.4
969.0
1145\7
'1321 .. 7
1500.3
1679.6
1859"• 2
2045.4
2232.3
2425.1
2627.0
2830.3
3038.0
********************************** INV.
***** 14.89
14.61
14.33
14.02
23.01
23.14
22.66
30.18
29.15
28.79
28.46
27.59
27.91
26.77
26.28
30.72
29.61
29~09
FUEL
***** 16.01
16·. 84
17.83
23.38
19.16
20.06
20.95
19.68
.20.25
21.15
21.57
22.45
24.00
24.75
26.33
23.70
2.4 t 79
26.11
O+M
***** ~.18
4.22
4.29
4.33
4.55
4 •. 62
4.68
5.14
5.13
5 t 16
5.13
5.16
5.25
5.-18
5t30
5.66
5.68
s.77
N.I.
***'** o.
o.
o.
o.
o.
o •
o.
o.
o.
o.
o.
o.
o.
o.
o.
o.
o.
.Ot
TOTAL
****** 35.08
35.67
36.45
41.73
46.72
47. 8.2
48.29
55.00
54.53
55.10
55.17
55.20
57.15
56.70
57.91
60.08
60.08
60.97 .
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
utNERAL ELECTRlC COM~~NY
UGP-5 GENEh~TrON PLANNlNG PROGRAM-SUMMARY OUTPUT
+~~*~~***1~**'***~+**'*******$j*a***********t***
tr L ft S i\ ,~. H ti 1 L B E L ·1 RUN C
Z !:!" !:• 0 ·~· - 3 ., ._n ,.. 1.
JUB NUMBER 2ML9K3
* ;f' * * ~: * * * * * * *' * * ~· * * !+•' * * :f, * * * * * * * ;t· ~· * * * ~ :t· * * * * *
GENERATION SYS1EM
NUKE COAL NGASGT OIL GT DIESEL COMCYC
TYPE 1 2 3 4 5 6
OPTMZING 0 1993 1993 0 0 1993
PCT TRIM 0 0 0 0 0 0
TYPES
7-10
***
1992 MW 0 59 452 141 67 317 155 SUM= 1190
***********************************************************************
YR
"' •J.• ·l~ ,.,
93
~I.!
r\ L•• 7 ._1
96
Q7
.-4
98
99
0
1
2
~~
4
5
TOTAL
CAPAB.
Y E A R L Y M W A D D I T I 0 N S + TIES
******* ******* ******* ******* ******* ******* ***** ****** **** 680* 1853
1822
1774
1704
1630
1575
1575
1531
1531
601'lf 2079
2026
1% "0"7 ... --1939
6 1l 1917
7 1X 70 1987
8 1X 70 l* 2032
9 2031
10 1X 70 1* 2102
*********************************************************************** ***********~*********************************************************** MW ADD 0 0 210 0 0 0 1285 SUM= 1495
MW RET 0 -46 -335 -141 -61 0 . 0 SUM= -583
****** ****** *****~ ****** ****** ****** ****** **** *********** ~
2010 0 13 326 0 6 317 1440 SUM= 2102
F' C T 'T 0 T 0 • 0 • 6 15 • 5 0 • 0 • 3 15 • 1 6 8 • 5 SUM= 1 0 0 F' C T
********************************'************************************** t-t U T 0 0 0 21 0 0 0 0 0 SUM= 21 0
PCT TOT 0. O. 100.0 o. O. O. O. SUM=lOO PCT
-.. -.. -----::-----~-.:--:----:--
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
GENERAL ELECTRIC COMPANY
oGP-5 GENERATION F·LANNlNG F'.ROGR'AM-SUMMARY OUTF•UT
************************************************
Al-ASKA RAILBELT RUN C
ZER01. -3X
JOB NUMBER 2ML9K3
****************************************
YEAR
**** 1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
LOAD
***** 947
F'OOL
PEAK
<MW>
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
TOTAL CAPABILITY
<INCLUitiNG TIES>
YEAR TIME OF
END F'EAK
***** ***** 1853 1853
1822 1822
1774 1774
1704 1704
1630 1630
1575
1575
1531
1531
2079
2026
2027
1939
1917
1987
2032
2031
2102
TOTAL
ENERGY
<GWH)
1575
1575
1531
1531
2079
'J0?6 .... -.
?O'J7 ..... --~
1939
1917
1987
2032
2031
2102
LOA II
FACTOR
F'CT.
RES.
**** 95~7
8a.a
80.5
69.9
59.4
so.s
48.0
41.2
36.6
79.5
69.4
64.4
52.7
44.9
44.3
42.1
36.9
3.6.8
TOTAL
COSTS
<MIL.$) YR
** 93 ****** 947 ******* 4736 ****** 57.09 ****** 247
94
95
96
97
98
99
0
1
2
3
4
5
6
7
8
9
10
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
-1430
1484
153.7
4829
4922
5031
5141
5250
o36o
5469'
5661
6352
6455
6599
6698
6880
7079
7310
7551
7827
57.12
57.16
57.10
57.37
57.41
57.51
57.44
57.65
62.61
61.61
60.92
60.21
59.36
58.69
58.20
58.08
58.14
253
256
268
273
278
284
293
302
325
344
326
343
331
358
358
379
385
LOSS OF LOAit
PROBABILITY
It/Y H/Y
COST IN
YEARLY
COST
MILLION $
CUM. PW
TOTAL
****** ****** ******* 246.5 ******* 178.1 o.ooo o.
·o.ooo o.
o.ooo o.
o.ooo o.
o.ooo o.
0.001 o.
0.002 o.
0.015 o.
0.032 o.
o.ooo o.
0.001 o.
0.001 o.
0.017 o.
0.068 o.
0.025 o.
0.029 o.
0.050 o.
0. 025 ~tot
252.8
255.9
268.4
272.5
277.9
283.7
292.6
302.2
325.0
344.3
326.0
343.2
331.4
357.9
358.4
379.1
385~3
YEAF':LY $/MWH
355.4
529.7
707.1
on? 1 ul:)...,.t
1055.2
1226.9
1398.7
•1571.1
1751.0
1936.1
2106o2
2280.1
2443.2
2614.1
2780.3
2950.9
3119.4
********************************** INV.
***** 42.05
41.24
40.46
39.59
38.74
37.94
37.16
36.42
35.18
46.28
45.54
44.55
43.89
42.73
42.07
41.27
39.96
39.07
FUEL
***** 5.29
6.37
6.77
9.05
9.57
10.29
11.02
12.31
13.41
o.
2.83
o.
2'.49
0.70
3.62
2.95
5.39
5.33
O+H
***** 4.71
4.74
4.75
4.72
4.70
4.71
4.75
4.76
4.80
4.88
4.97
4.86
4.86
4.74
4.86
4.81
4.86
4.84
N.I.
***** o.
0 •.
o.
o.
o.
o.
o.
o.
o.
o.
o.
o.
o. ·o.
o.
o. o.
o.
TOTAL
****** 52.06
52.35
51.98
53.36
53.01
52.94
52.93
53.49
53.39
51.17
53.34
49.41
51.24
48.17
50.55
49.03
so:21
49.2~
·I
I
I
I
;.~
I I
I
I
I
I
I
I
I
I
I
I
I
I
I
\)
I
OGP-5 GENERATION PLANNING PROGRAH-SUMM~RY OUTPUT
*******t****************************************
ALASKA RAILBEL T RUN F2
ZERO% -3/.
JOB NUMBER 2ML9F3
****************************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYPE 1 2 3 4 5 6 7-10
OPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 592 141 67 317 65 SUM= 1240
***********************************************************************
YR
** 93
94
95
96
97
98
99
0
1 ., -3
4
5
6
7
8
c
7
TOTAL
CAPAB.
Y E A R L Y H W A D D I T I 0 N S + TIES
******* ******* ******* ******* ******* ******* ***** ****** ****
1X 70
680* 1903
601*
1*
1*
1*
1872
1824
1754
1680
1625
1625
1581
1581
2129
2076
2077
1989
1967
1967
1942
2011
10 1* 2012
*********************************************************************** ****************************~****************************************** MW ADD 0 0 70 0 0 0 1285 SUM= 1355
MW RET 0 -46 -335 -141 -61 0 0 SUM~ -583
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 13 326 0 6 317 1350 SUM= 2012
PCT TOT O. 0.6 16.2 O. 0.3 15.8 . 67.1 SUM=lOO PCT
*********************************************************************** AUTO 0 0 70 0 0 0 0 SUM= 70
PCT TOT O. O. 100.0 o~ O. O. O. SUM=100 PCT
* COMMI TTEit MW
I
I
I
11
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
-
SENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
***********'************************************
ALAS~:A RAILBELT RUN FZ ZERO% -3% '
JOB NUMBER 2ML9F3
****************************************
~ F'OOL TOTAL TOTAL YEARLY $/MWH
PE~K ENERGY LOA It COSTS *********************************t YR (HW> \GWH> FACTOR <MIL.$) INV. FUEL O+H N.Io TOTAL
** ****** ******* ****** ****** ***** ***** ***** ***** ****** 93 947 4736 57.09 255 42.QS 7.13 4.59 o. 53.77
94 965 4829 57.12 258 41.24 7.63 4.60 o. 53.47
95 983 4922 57.16 2.62 40.46 8.21 4·62 o. 53*30
96. 1003 5031 57~10 278 39.59 1lo03 4.60 o. 55~22
97 1023 ·5141 57.37 283 38.74 11.73 4.62 o. 55.09
98 1044 5250 57. 4.1 289 37.94 12~55 4~63 o~ S5.11
99 1064 5360 57.51 296 37.16 13.44 4.69 o. 55.29
0 1084 5469 57~44 305 36.42 1~· t 69 4.71 o, 55.82
1 1121 5661 57.65 7.~6 w.&· 35.18 15~96 4.76 o. 55.90
? -1158 6147 60.60 347 47.82' 3.66 s.ot .o. 56.49
3 1196 6298 . 60.11 348 46.68 3HS4 4.95 o. 55.27
4 1233 6526 60.25 349 45.05 3.59 4~se 0 (1 53.51
5 1270 6677 60.01 350 44.03 3.67 4.76 o. 52.46
b 1323 6994 60.35 355 42.03 4.02 4.64 o. 50.69
7 1377 7210 59.77 363 40.77 4.94 4t64 o. 50.35
8 1430 7495 59.66 371 39.23 5.67 4.58 o. 49.47
9 1484 7710 59.31 386 38.65 6.77 4.65 o. 50.07
10 1537 7999 59.41 396 37.25 7.64 4.64 .0. 49.5-4
TOTAL CAPABILITY
<INCLUDING TIES> LOSS or-LOAir COST IN KILLION $
YEAR TIME OF P~T-PRODABILlTY YEARLY . CU~o PW --.... YEAR LOA It END PEAK RES. II/Y H/Y COST !OTAL
**** ***** ***** ***** **** ****** ****** ******* ******* 1993 947 1903 1903 100.9 o.o~o o, 254.7 124.0
1994 965 1872 1872 94.0 o.ooo o. 258.2 365.1
1995 983 1824 1824 85.6 o.ooo o. 262.3 543.7
1S'96 :1003 1754 1754 74.8 o,ooo o. 277.8 727.4
1997 1023 1680 1680 64.3 o.ooo o. ~83.2 909.2
1998 1044 1625 162.5 55.6 o.ooo o. 289.3 1089.5
1999 1064 1625 1625 52.7 o.ooo o. 296.3 .1268~7
2000 1084 1581 ft::9" ~".I. 45.9 0.001 o. 305.3 1448.1
2001 1121 1581 1581 41.0 O.Q04 o. 316.5 1628.5
2002 1158 ') 1 ,,9 .. ~ 2129 83.9 o.ooo o. '":.&........ 3 ...... ,../ . . 1820.8
2003 1196 2076 2076 73.6 o.ooo o. 348.1 2.007.9
2004 1233 2077 2077 6a.s o.ooo o. 349.2 ~1 90 ? '~ .,........ ..,...,
2005 1270 1989 1989 5£..6 O.QO:! o. 350.3 2367.6
2006 1323 1967 1967 4847 o.oo4 o. 354.6 2542.0
2007 1377 1967 ~ 9J-... aT 42.9 0.013 o. 363•0 2715.4
2008 1430 1942 1942 35.8 o.oss o .. 370.8 2887.4
2009 1484 2011 2011 35.5 0.039 o. 386.0 3061.1
2010 153( 2012 "01? .... -30.9 o.o-,&3 o. 396·2 3234.3
I. , ..
I
•••
I
I
I
I
-I
I
I
I' .
I
I
I
I
I
I
I
I
••
GENERAL ELECTRIC .COMPANY
OGP-5 GENER~TION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAILBELT RUN Gl
ZERDX -3X
JOB NUMBE~ 2HL3N1
****************************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COHCYC TYPES
TYPE 1 2 3 4 5 6 7-10
OPTHZING 0 1993 1993 0 0 1993 ***
PCT TRIH 0 0 0 0 0 0
1992 MW 0 59 452 141 67 317 155 SUM= 1190
*********************************************************************** TOTAL
CAPAB.
YR Y E A R L Y H W A D D I T I 0 N S + TIES ** ******* ******* ******* ******* ******* *~S**** ***** ****** **** 93 200* 1373
94 200* 1542
95 1495
96 200* 1624
97 70* 1620
98 70* 1635
99 1635
0 1591
1 70* 1661
2 1608
3 70* 1625
4 70* 1695
5 140* 1747
6 70* 1794
7 ' 200* 1994
8 1968
9 70* 2037
10 2037
*********************************************************************** **************************************·********************************* HW ADD 0 800 630 0 0 0 0 SUH= 1430
HW RET 0 -46 -335 -141 -61 0 0 SUH= -593
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 813 746 0 6 317 155 SUM= 2037
PCT TOT o. 39.9 36.6 O. 0.3 15.6 7.6 SUH~100 PCT
.**************************************************a********************
> ,, c
............. _._......., ____ ........__ ___ . .._,;, /,....._. -----~~."!;...::__,_<.~J._~·"--'
0
·-··
.I
.I
I
I
I
I
I
I
I
-I
I
I
I
••
I
I
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAH-SUHHARY OUTPUT
************************************************·· ..
ALASKA RA-, ".BELT RUN Gl
ZERO:¥. -34
JOB NUMBER 2ML3N1
**************************************** .
YEAR
**** 1993
.1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
LOAD
***** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
TOTAL CAPAB-ILI-T.Y
<INCLUDING TIES)
YEAR TIME OF ·
END PEAK
***** ***** 1373 1373
1542 1542
1495 1495
1624 1624
1620 1620
1635 1635
1635 1635
1591 1591
1661 1661
1608 1608
1625 1625
1695 169.5
1747 1747
1794 1794
1994 1994
1968 1968
2037 2037
2037 2037
PCT.
RES.
**** 45.0
59.8
52.0
61.9
59.4
56.6
53.6
46.8
48.2
38.9
35.9
37.5
37.6
•35.6
44.8
37.6
37.3
32.5
POOL TOTAL TOTAL
LOSS OF LOAD
PROBABILITY
D/Y
****** 0.063
0.027
0.077
0.059
0.084
0.092 o.oss
0.059
0.038
Ot062
0.087
0,057
0.049
0.052
0.023
0.066
o.o5t
0.099
H/Y
****** o. o. o.
o.
o.
o.
o.
o. o.
o.
o. o. o.
o. o. o.
o. o.
COST IN
YEARLY
COST
******* 184t6
214.6
221.3
283.4
294.2
3()6_.1
312.3
319.7
332.2
340.8
357.6
373.9
399.6
423.4
465.6
483.9
507.6
527.5
YEARLY S/HWH
MILLION •
CUH. PW
TOTAL
******* 133.3
283.9
434.6
621 .• 9
810.8
1001.5
1190.4
1377.6
1567.1
1755.7
1947.9
2143.1
2345.6
2553 •. 8
2776.2
3000.6
3229.1
3459.6
f•EAK ENERGY LOAD COSTS ********************************** YR <MW> <GWH> FACTOR <MIL.s> INV. FUEL O+H ·N.I. TOTAL ** ****** ******* ****** ****** '***** ***** ***** ***** ****** 93 947 4736 57.09 185 11.17 23.36 4.44' o •. 38 ... 97 94 965 4829 57.12 215 18.37 21.39 4t68 o. 44.45 95 983 4922 57.16 221 18.02 22.22 .4.72 o. 44.97 96 1003 5031 57o10 283 27.23 23.88 5.21 o. S6.32 97 1023 5141 57937 294 27.38 24.59 5.25 o. 57.22 98 1044 5250 57.40 306. 27.55 25.45 5.31 o. 58.31 99 1064 5360 57.51 312 26.98 25.97 5.31 o. 58.26 0 1084 5469 57.44 319 26.44 26.60 .5.22 o. 58.27 1 1121 5661 57.65 332 26.~6 27.14 5.27 o. 58.67 2 1158 5853 57.70 341 25.40 27.a1 5.21 o. 58.22 3 1196 6044 57.69 358 25.30· 28.60 3.2it o. 59.16 4 1233 6236 57.58 374 25.22 29.40· 5.34 .o. 59 •. 9.6 5 1270 6428 57.78 400 25.84 30.89 5.43 o. 62.17 6 1323· 6701 57.82 423 25.46 32.20 5.52 o. 63.18 ... 1377 6973 57.81 466 31.11 29.77 ~5.90 o. 66,.77
?
8 1430 7246 57.69 484 29.94 30.93 5.91 o. 66.78 9 1484 7518 57.83 50S 29.49 32.03 6.00 o. 67&51 10 1537 7791 57.86 528, 28.46 33~20 6.0:6 o. 67.71
•••
I
I
I
I
I
I-
I
I
I
I
I
I
I
I
I
I
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAILBELT RUN Hl
ZERO/. -37.
JOB NUMBER 2ML303
*********~******************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYPE 1 2 3 4 5 6 7-10
DPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 -O 0
1992 MW 0 59 . 452 141 67 317 155 SUM= 1190
*********************************************************************** TOTAL
CAPAB~
YR Y E A R L Y M W A D D I T I 0 N S + TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 200* 1373
94 200* 1542
95 1495
96 200* 1624
97 70* 1620
98 70* 1635
99. 1635
0 1591
1 70* 1661
2 1608
3 70* 1625
4 70* 1695
5 140* 1747
6 70* 1794
7 200* 1994
8 1968
9 70* 2037
10 2037
*********************************************************************** *********************************************************************** MW ADD 0 BOO 630 0 0 0 0 SUM= 1430
MW RET 0 -46 -335 -1~1 -61 0 0 SUM= -583
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 · 813 746 0 6 31'7 155 SUM= ·2037
PGT TGT O. 39.9 36.6 0. 0.3 15.6 7.6 SUK=lOO PCT
***************************'******************************************* AUTO 0 0 0 0 0 0 0 SUM= 0
F'CT TOT 0. o. o. o. O. O., ., O. SUM= 0 PCT
* COMMITTED MW
... ,;. -~ "
"' '"''--~'-. _,,,._·.,.,.,~~,...·~·""-•••.·~"';;, -·~" •• ~. Jl '·'_.w~~ ~·••'
I
I
I
I
I
I
I
I
I
••
I
I
I
I
I
I
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
*****************************'*******************
ALASKA RAILBEL T RUN Hl
ZEROX -3/.:
JOB NUMBER 2ML303
****************************************
YEAR
**** 1993
1994
1995 -
1996
1997
.. 1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
. 2010
YR
** 93
94
95
96
97
98
99
0
1
2
3
4
5
6
7
8
9
10
LOA II
***** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
POOL
F'EAK
(MW>
****** 947
965
983
1003
1023
1044
•1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
TOTAL CAPABILITY
<INCLUDING TIES)
YEAR TIME OF
ENit PEAl\
***** ***** 1~73 1373
1542
1495
1624
1620
1635
1635
1591
1661
1608
1625
1695
1747
1794
1994
1968
2037
2037
TOTAL
ENERGY
<GWH>
******* 4736
4829
4922
5031
5141
5250
5360
5469
5661
5853
6044
6236
6428
6701
6973
7246
7518
7791
1542
1495
1624
1620
1635
·1635
1591
1661
1608
1.625
1695
1747
1794
1994
1968
2037
2037
LOAD
FACTOR
****** 57.09
57.12
.57 .16
57.10
57.37
57.40
·57. 51
57.44
57t65
57.70
57.69
57.58
57.78
57.82
57.81
57.69
57~83
57-.86
F'CT.
RESt
**** 45.0
59.8
52.0
61.9
58.4
56.6
53.6
46.8
49.2
38.9
35.9
37.5
37.6
35.6
44.8
37.6
37~3
32.5
LOSS OF LOAit
PROBABILITY
Ii/Y H/Y
****** ****** 0.063 o,
0.027 o.
0.077 o.
o~os9 o.
0.084 o.
0.092 o.
0.055 o.
0.059 o.
0.038 o.
0.062 o,
0.087 o.
0.057 o.
0.049 Oe-
0.052 o.
.0.023 o.
0.066 o.
0.051 o.
0.099 o.
COST IN
YEARLY
COST
******* 171.3
1'?2.5
199.2
249.1
259.0
270.0
276.1
282.5
295.0
303.6
319.3
334.6
358.1
380o7
411.4
429.6
452.1
472.1
MILLION $
CUM. PW
iOTAL
*****%* 123.8
258.8
394.4
559.1
725.3
893.6
1060.6
1226.6
1394,8
1562.9
1734.6
1909.2
2090.6
2277.9
2474.4
2673*6
2877+2
3083.5
TOTAL
COSTS
(MILo$)
YEARLY $/HWH
******************~*************** INV. FUEL O+M N.I~ TOTAL
****** 171
192
199
249
259
270
276
283
2.95
304
319
335
358
381
411
430
452
472
***** ***** ***** ***** ****** 8.38 23.36 4,44 -Oi 36.18
13.78 21.39 4.68 .o. 39~86
13.52 22.22 4.72 o. 40.47
20o42 23.88 5t21 Ot 49.52
20.s4 24.59 5.25 o~ so.3s
20.66 25.45 5.31 o. 51.42
20.23 25.97 5.31 o. 51.52
19.83 26.60 5.22 o. 51.66
19.70 27.14 5.27 o. 52.11
19.05 27.61 5.21 o. 51.67
18.99 28.60 ·s.26 0. S2,S4
18.91 29.40 5.34 o. 53.66
. 19.38 30.89 5.43 o. 55.71
19.09 32i20 5.52 o. 3b.82
23.33 29~77 5.90 o. 59.00
22.45 30.93 5.91 o. 59.29
22.12 32.03 6.oo o. 60.14.
21.34 33.20 6.06 o. 60.59
t
:I
I
.I
I
I
I
I
I
I
I
I
I
I
I
I
··'I
I
:I
GENERAL ELECTRIC COMPANY
-OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAILBELT RUN Jl
ZERO/. -37.
JOB NUMBER 2ML4W1 ~
****************************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYPE 1 2 3 4 5 6 7-10
OPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 522 141 67 717 155 SUM= 1660
***********************************************************************
YR
** 93
94
95
96
~'97
98
99
0
1
2
3
4
6
TOTAL
CAPAB.
Y E A R L Y M W A D D I T I 0 N S = + TIES
******* ******* ******* ******* ******* ******* ***** ****** ****
200*
lX 200
1X 200
?X .....
lX
1X
1X
lX
1X
70
70
70
70
70
70
1643
1812
1765
l,894
1960
1975
2045
2tr01
2071
2088
2235
2305
2417
lX 70 2464 • 7 2X 70 2604
8 lX 200 2778
9 2777
10 lX 70 2847
*********************************************************************** *********************************************************************** MW ADD 0 1000 770 0 0 0 0 SUM= 1770
MW RET 0 -46 -335 -141 -61 0 0 SUM= -583
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 1013 956 0 6 717 155 SUH= 2847
PCT TOT Oo 35.6 33.6 O. 0.2 25.2 5.4 SUM=lOO PCT
*******************************************************************~*** AUTO 0 600 770 0 0 0 0 SUM= 1370
PCT TOT o. 43.8 56.2 o. o. o. o. SUM=iOO PCT
* COMMITTED M~J
I
I
I
I
I
I
.I
I
I
I
I
I
I
I
I
I
I
I
I.
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGR~H-SUMMARY OUTPUT
************************************************
ALASKA RAILBELT RUN Jl
ZER01. -37.
JOB NUMBER 2Ml4W1
****************************************
YEAR
**** 1993
1994
1995
1996
1997
1Q98
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
200~
2010
LOA It
***** 1188
1218
1248
1286
1424
1363
1401
1439
1505
1571
1637
1703
1769
1848
1927
2007
.2086
2165
TOTAL CAF'ABILITY
<INCLUDING TIES>
YEAR TIME OF
END PEAK
***** ***** 1643 1643
1812 1812
1765 1765
1894 1894
1960 1960
1975
2045
2001
2071
2088
2235
2305
2417
2464
2604
2778
2777
2847
1975
2045
2001
2071
2088
2235
2305
2417
2464
2604.
2778
2777
2847
F'CT.
RES.
****' 38.3
48.8
41.4
47.2
48.1
44.9
45.9
39.1
37.6
32.9
36.5
'35v4
36.6
33.3
35.1
38.4
3'3.1
31.5
POOL TOTAL TOTAL
LOSS OF LOAII
PROBABILITY
It/Y H/Y
COST IN
YEARLY
COST
****** ****** ******* 177.0 0.076 o.
0.026 o.
0.076 o.
0.069 o.
0.048 o.
0.068 o.
0.046 o.
0.062 o. o.o6o o.
0.059 o.
0.057 o.
0.056 o.
0.072 o.
0.097 Ot
Oo055 Ot
0.040 o.
0.055 o.
o.o63 o~
YEARLY
219.6
230.6
304.1.
324.4
341.8
360.2
373.7
39.9. 4
42.1. 4
455.1
481.7
522.3
554.8
594.3
636.1
662.7
700.3
$./MWH
MILLION $
CUM. PW
TOTAL
******* 127.8
281.8
438.9
639.9
848~1
1061t:L
1279.1
1498.6
1726.4
1959.7
2204.3
.2455. 7
2720.4
2993 .. 3
3277~1
3572.1
3870.4·
4176.5
f'EAK ENERGY LOA[I COSTS ********************************** YR <MW> <GWH> FACTOR <MIL.$) INV. FUEL O+H N.I~ TOTAL
** ****** ******* ****** ****** ***** ***** ***** ***** ****** 93 1188 6160 59.19 177 o. 24.61 4.12 o~ 28.73
94 1218 6312 59.16 220 7.13 23.39 4.27 o. 34.79
95 1248 6464 59.13 231 6.96. 24.39 4.32 o. 35.67
96 1286 6663 58.98 304 12~79 28.27 4.57 o. 45.63
97 1324 6861 59.16 324 13.34 29.29 4.66 o. 47. 2.9
98 1363 7060 59.13 342 13.41 30.29 4.~71 o. 48.42
99 1401 7258 59 t 14 360 13.50 31.33 4.ao o. 49.63
0 1439 7457 5B.99 374 13.14 32~21 4.77 o. 50.12
1 1505 7795 59.13 399 13.01 33.37 4.86 o. 51.24
'J -1571 8133 59.10 421 . 12.89 34.06 4.86 o. 51.82
3 1637 8472 59.08 455 16.58 32.06 5.07 o. 53.72
4 1703 8810 58.89 482 16.36 33.17 5.15 o. ''54 .-68
5 1769 9148 59<t03 522 19.81 31.89 5.40 o. 57.10
6 1848 9605 59.33 555 19.26 33.06 5.44 o. 57.76
7 1927 10063 59.61 594 19.14 34.38 5.54 o. 59.06
8 2007 1 052.() 59.67 636 22.05 32.66 5.75 o. 60.46
9 2086 10978 60.0.8 663 21.13 33.50 5.74 0-t 60.'37
10 2165 11435 6.0.29 700 20.64 34.78 5.82 o. 61"24.
I
.I
I
I
I
I
I
I
I
'I
I
I
I
I
I
I
I
I
I
GENERAL ELECTRIC~COMPANY ~ . . . ... .
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
~***************'*********f**~******************
RtilLBF-L T RUN J2
'7 c R n. ... .... -. .. , .... .J;;. _.,.. ,.') ,.
JOE NUMBER 2MLCI5 .
·.:. "<: ;.· •J: ·J· \l' ~·· ".1.· ·~ \1, ·J.· "'-'It: .J• "' "-' "-: -L• , ••• \1• ·J.· ••• '<./; !l,• .,. * "' \1.• .., • .,. '-1.! \J.• ,_. "-' ·.b "<l . ..&· -.!.· • ·,\ .. '~, ~· ,, ..,.-·tt· , ... ~ tt· Ji '* .,-:t~ ,. 4 .,. ,r q. ~~'-t'J\ lf'.·1" ... .f ·1\ If· If ;; .. .,.. ,. . ., .. ~·If\ If.,.., ~'f, I'J•lf .11 1{. •r
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
1YPE 1 ? 3 4 5 6 7-10
· GPTMZING 0 19~3 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
. 1 9 ~ ~ MW 0 59 5?. ~ 1 -4 1 6 7 7 1 7 · <1 55 SUr1= . 1 6 6 0
******************~*********~*************************************f**** TOTAL
GAPAB.
YR Y E A R L Y M W A D D I T I 0 N S + TIES
** ******* ***~*** l****** ******* t****** ****~** ***** ****** **** 93 680* 2323
96 c-. . .
98
0
1
··~ "-
C:· 1X 70
1X 7C•
1x 7f't ' , ..
239.2
2244
217A
6001.\ ~700
l* 2602
1* 2~03
2550
:1.* 2498
2498
2410
2527
? 1X 70 2640
10 1X 70 2710
*********************************************************************** ~********************************************************************** N~J ADI! (1 0 350 0 0 . 0 1283 SUM= 1633
HW HET 0 -46 -335 -141 -61 . 0 0 SUH:; -583
St**** *****~ *****~ ****** ****** ****** ****** **** ******f**** 2010 0 13 536 0 6 717 1438 SUM= 2710
PCT TOT O~ 0.5 19.8 O. 0.2 26.5 53.1 SUM=lOO PCT
~*******************************************1************************** DUTO 0 0 350 0 0 0 0 SUH= 350
PCT TOT 04 O. 100.0 o. O. o. o~ SUM=lOO PCT
-~ COi1MITTE1t Nl·J
I
I
I
I
I
I
I
··I
I
I
I
1-
I
I
I
GENERAL ELECTRIC COMPANY
OGP-~ GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************ ..
RUN J2
'""EF·o·.--3 ... L \ ~D /u
JOB NUMBER ~MLCI5
*t»~******t*****~~*****f***************W
'i E~rR
*·*·:t:t
1993
1994
1995
1996
1997
·I.QQ8 ·'-" , ..
2000
2001
2002
2003
2004
2005
2006
2007.
2008
200?
"'"1'" ._"\._' \..'
L0~1!1
}f: :;: * * ;.f
1188
1218
.1248
1286
1 -·-~e.:.
1 4 (', •J .&. ......
1439
1505
1571
1637
1703
1769
1848
2007
2086
21.65
TOTr~tL CAPABILITY
(INCLUD1NG TIES)
YEAR TIME OF
EN.D
*~:***'
2323
2244
2174
2700
2645
264:.;
I''\ i. I'\ -. .:. ...... \..' .:J
255·:·
:2498
2498
2410
2457
25:!7
2571
264-0
2710
F ::: r.1K
~:)f:**~;
2323
2292
2244
2174
2700
2645
264~
2602
260:!
2550
2498
~410
2457
F'CT.
RES;
*q• \!. >.!•
If· If· t:"•
95.5
88.2
79.8
69.0
104.0
94-.C·
88iB
BC•. 8 -.... ,. ,.._
I..!· • '-.l
46.7
36.3
26t6
25 t 2·
LOSS OF LOAD
F'F:OBAB I L I TY
D/Y H/Y
*****~~ *****~; o.ooo o.
o.ooo o.
o.ooo o.
o.ooo o.
o.ooo o.
o.ooo o.
o.ooo o.
o.ooo
o.ooo
0-.000
0.001
0.003
0.03.2
0.042
0.037
0.054
0.053
0.052
o.
04--
o.
o.
o.
o.
0~
o.
o.
o.
0.
COST !N
YEARLY
COST
******* 284.7
292.2
299.8
327.4
342.7
344.2
346.8
3 c· "') -~ J..:..t;
351.9
3/'1 • 9
'377.4
41·1~5
441.5
469.1
498.6
530.~
563.8
YEF1RL Y $/MWH
H!LLION $
CUM. PW
TOTAL
***'**** 205.7
410.6
614.7
831.2
1051.2
1265~7·
1 "" ... ,!:) t"; . . ~ .....
1682.7
1883. ~.
2.709.3
2926..5
3150.5
3381 t ::·
3620~5
3B6c .• 9
POOL
PEAl<
O·HD
TO TilL
ENERGY
<GttJH.)
TOT,~L
COSTS
(MIL.$) *~********~*'*************'******t
*l
93
94
95
9c
97
?S
97
0
1
I; .
, ..
0
C• •
10
)!.•\!·'IJ.:•-.1•\l•-.:. ~-., ... .,,.,... ~ ,
1188
1218
1~48
1286
1324
1401
1437'
1505
:1.571
1637
1703
1769
1848
1927
2007
2086
2165
* :+:* *)f~ * :+:
6160
•• , # .....,..
0·~0~
6976
7153
7329
7510
7812
8133
8472
8810
9148
9605
10063
10520
10978
11435
59.19
59.16
59.13
58.99
60.15
59.91
59.72
57~4:.:!
59.25
59.10
59 t •)8
58.89
59.03
59.33
59.61
59.67
60.08
60.29
...!.• •J• '11• '" ••• ..:.· "!"• J; If• -r:~ ""' ,,
:265
''i~""i ........
327
343
344
347
352
...,..,, -·,
~,f /
397
414
442
469
499
530
564
INV. FUEL D+M N.I. TOTAL
**'t:+'if )f:~ ~ **: **~=** ****:.i' **:!:***:
"2 1 .::-;:-,;;~ • J ,J
30t81
29. 8''
40.86
39~85
32.89
37. ''5
36.49
3 t=" r, L-
,J '• -v'.J
33.64
31.16
30.07
29.08
28~19
27.37
26.64
10.08
10.88
14.62
... '""'9 .:lc-.j
3.43
3~-61
4.2t
... 9" ~. i
6.04
9.64
11 • 3:;
12.98
14.62
16.30
17.96
4. 6.6
4.66
4.68
4.63
4.88
4 .. 83
4.82
4.74
4.65
.. 1. 64
4.55
4.57
4.51
4.53
4.56
4. 57~
4.64
,1.71
o.
o.
o~
(· <
(t •
(),
r.
" '
0'
Ot
o.
Ot
o.
46.21
46.30
.. I' """"' .... •to.~.t
49t14
49.13
-18.11
\ ~ "'"'t",.~
Lt ~-• ~-..:.
"t 6 + 7 Co
45 ~ 0~5
45.73
44.54
,15. 06
45.31
45.9?
46:. 6~
I
I
I
I
I
I
I
I
I
I
I
••
I
I
I
I
I
I
I
-----,~
GEN~RAL ELECTRIC COMPANY .
OGP•S GENERATION PLANNING PROQRA~~SUMMARY OUTPUT
********************************~***************
ALASKA RA ILBEL T RUN Kl
ZERO% -3%
JOB NUMBER 2HL195
****************************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYPE 1 2 3 4 5 6 7-10
OPTHZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 HW 0 59 45~ 141 67 317 155 SUM= 1190
********************************************·*************************** TOTAL
CAPAB.
YR Y E A R L Y H W A D D I T I 0 N S + TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 1173
94 l 1142
95 200*' 1295
96 lX 70 1294
97 lX 70 1290
98 200{ 1435
99 14~5
0 1X 70 1461
1 1461
2 1X 70 1.479
3 1X 70 1495
4 -1495
5 lX 70 1477
6 1X 70 1524
7 lX 200 1724
8 1698
9 1697
10 !X 70 1767
*********************************************************************** ******************************************************~~**************** MW ADD 0 600 560 0 0 0 0 SUM= 1160
HW RET 0 -46 -335 -141 -61 0 0 SUM= -5B3
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 613 676 0 6 . 317 155 SUH= 1767
PCT TOT o. 34.7 38.3 o. 0.3 17.9 B.B Sll. .. =100 PCT
*********************************************************************** AUTO 0 200 560 0 0 &-0 SUM= 760
"PCT TOT o. 26.3 73.7 o. o. 0. · o. SUH=lOO PCT
* COMMITTED HW
II
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
YR
** 93
94
95
96
97
98
99
0
1
2
3
4
5
6
7
a
9
10.
~· ' ·.
GENERAL ELECTRIC COMPANY
OGP~S GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAILBELT RUN Kl
ZERO% -37.
JOB NUMBER 2HL195
*****************~**********************
TOTAL CAPABILITY
<INCLU!IING TIES>
YEAR TIME OF F'CT.
RES.
LOSS OF LOAD
PROBABILITY COST IN MILLION •
YEAR
**** 1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006'
2007
2008
2009
2010
LOAD
***** 830
840.
849
863
878
892
907
921
950
979
1008
1037
1066
1102
1138
1173
1209
1245
END F"EAK
***** ***** 1173 1173
1142 1142
1295 1295
1294 1294
1290 1290
1435 f43~
1435 1435
l461 1461
1461 1461
1478 1478
1495 1495
1495 1495
1477 1477
1524 1524
1724 1724
1698 1698
1697 1697
1767 1767
**** 41.3
36.0
52.5
49.9
47.0
60.8
58.2
58.6
53c-8
51.0
48.3
44.2
38.6
38.3
51.5
44.7
40.4
'1~1.9
DIY H/Y
****** ****** 0.034 o. o.o8o o.
0.045 o.
0.060 o.
0.086 o,.
0.053 o.
o.o6a o~
0.055 o.
0.035 o.
0.046 o.
0.057 o.
0.036 o.
0.077 o.
0.066 o.
0.022 o.
0.056 o.
0.086 o.
0.057 o.
YEARLY
COST
******* 127.6
135.2
166.1
195.1
2os.·a
237.4
244.4
257.1
261.9
275.2
290.0
297-t3
3~6.7
334.1
358{,7
371.9
386~0
404.3
I'_ u· ·u ht_, "" n • r .-\;'
TOTAL
******* 92.2
187.0
300.1
429.1
561.2
709·.1
857.0
1008.0
1157.4
1309.8
1465.6
1620.8
1781.3
1945 .• 6
2117.0
2289.4
2463.2
2639.9
POOL
PEAK
<MW>
TOTAL
ENERGY
<GWH>
LOAD
FACTOR
TOTAL
COSTS
<MIL.$)
YEARLY $/HWH
********************************** INV.
***** o. ****~* 830
840
849
86~~
878
892
907
921
950
979
1008
11>37
1066
1102
1138
1173
1209
1245
******* 4144
4192
4240
4320
4400
4481
4561
464!
4784
4928
5071
5215
5358
5547
5736
5925
6114
6303
****** 57.00
56.97
57~01
56.99
57.21
57.35
57.41
57.37
57.49
57.46
57.43
57.25
57.38
57.46
57.54
57.50
57.73
57.79
****** 128
135
166
195
206
237
244.
257
262
275
290
297
317
334·
359
372
386
404
o.
10.82
11.33
11.84
20.97
20.60
20.97
20.34
20.45
20.57
20.00
20.16
20.15
26.21
25.37
24.59
24.50
FUEL
***** 26.27
27.68
23.72
29.11
30.11
26.84
27.73
29.11
29 •. 15
30.07
31.21
31.63
33.50
34.54
30.38
31.43
32.52
33.52
OfH N.I.
***** ***** 4.51 o ..
4.58 o.
4•63 o.
4.72 o.
4.81 o.
5.17. o.
5.24 o.
5.31 o.
5.26 o,.
5.33 o.
5.41 o.
5.38 o.
~.46 o.
5•·55 o.
5.94 o.
5.96 o.
6.02 o.
6.13 o.
TOTAL.
****** 30.78
32.25
39.18
45.17
46.76
52.~99
53.59
55.39
54.75
55.85
57.19
57.00
59.11
60.24
62.54
62~77
63.14
64.14
---
"I
I"
I
I
I
I
I
I
.I
I
I
I
I
I
I
I
I
I
I
[,_, .. , " .
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
*************t**~*******************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYPE 1 2 3 4 5 6 "7-10
DPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 452 141 67 317 155 SUM= 1190
****l**************f*************************************************** . . .
TOTAL
C.APAB.
YR Y E A R L Y M W A D D I T I 0 N S + TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 1173
94 1142
95 680* 1774
96 1704
97. 1630
98 1575
99 1575
0 1531
1 1* 1532
2 1419
3 1426
4 600* 2026
5 1938
6 1915
7 1* 1916
8 1890
9 18S9
10 . 1* .£"990
*******************~*************************************************** *********************************************************************** MW ADD 0 0 0 .o · 0 0 1283 SUM= 1283
MW RET 0 -46 -335 -141 -61 0 0 SUM= -503
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 . 13 116 · 0 6 317 1438 SUM= 1890
PCT TOT o. 0.7 6.2 0. 0.3 16~8 76.1 SUM=100 PCT
*********************************************************************** AUTO 0 0 0 0 0 0 0 SUM= 0
F' C T T 0 T 0 • 0 • 0 • 0 • ~ ·o • 0 • 0 • SUM= 0 PC T
* COMMITTE!t MW
I
I
-I
I
I
I
I
I
I
I
••
I
I
I
I
I
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAlLBEL T RUN K2
Z.ERO/. -3/.
JOB NUMBER 2ML9K7
********************~*******************
YEAR
**** 1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
LOAD
***** 830
840
849
863
878
892
907
921
950
979
1008
1037
1066
1102
1138
1173
1209
1245
fOOL
PEAK
<MW)
TOTAL CAPABILITY
<INCLUDING TIES)
YEAR TIME OF PCT.
RES. END F'EAK
***~:* ***** 1173 1173
1142
1774
1704
1630
1575
1575
1531
1532
1479
1426
2026
1938 °
1915
1916
1890
1889
1890
1142
1774
170~
163v
1575
1575
1531
1532
1479
1426
2026
1938
1915
1916
1890
1889
1890
TOTAL
ENERGY
<GWH>
LOAD
FACT:JR
****-41.3
36.0
109.0
97.4
85.7
76.5
73.6
66.2
61.3
51.1
41.5
95.4
81.8
73.8
68.4
61.1
56.2
51.8
TOTAL
COSTS
<MIL.$) YR
** 93 *~ *~"** 830 ******* 4144 ****** 57.00 ****** 128
94
95
96
97
98
99
0
1
2
6
7
8
9
10
84(J
849
863
878
892
907 .
921
950
979
1008
10?7
1066
1102
11.38
1173
12or
1245
4192
4239
4320
4400
4481
4561
4641
4784
4928
5071
5213
535&
5547
5737
5925
6114
6303
56+97
57.00
56.99
57.21
57.35
57.41
57.37
57.49
57.46
57.43
\
57.23
~7.38
57.46
'57. 55
57.50
57.73
57.79
136 ,,. ... 1
" 259
262
264
267
276
277
283
289
357
365
378
346
372
388
359
LOSS OF LOAif
PROBABILITY
I•IY H/Y
****** ****** Oo034 O.
o~oao o.
o.ooo o.
o.ooo o.
o.ooo {).
o.ooo o.
o.ooo o.
o.ooo o.
o.vol o.
0.010 o.
o.o7s o~
o.ooo o.
o.ooo o.
o.oos o.
o.oo6 o.
o.os4 o.
0.035 o.
0.062 o.
COST IN
YEARLY
COST
******* 127.9
135.5
250.7
258.9
261.8
263.7
266,..5
276.0
277.3
282.9
288.6
357.3
364.6
378.0
346.4
371.8
388.4
359.5
MILLION $
CUM~ PW
TOTAL
******* 92.4
187.5
358.1
529.3
697.3
.861. 6
1022.9
1185.0
1343.1
1499.8
1654.9
1841.4
2026.1
2212.1
2377\.5
2549;,
2724,S
2881 •. 9
YEARLY $/MWH
********************************** INV. FUEL O+H N.I. TOTAL
***** ***** ***** ***** ****** o. 26.27 4.59 o. 30.86
o. 27.68 4.66 o. 3·2.33
48.88 4.91 5.33 o. 59.12
47.97 6.67 5.30 o. 59.93
47.o9 7.12 s.2a o. 59.49
46.24 7.34 5.26 0, 58.84·
45.43 7.72 5.28 o. 58.44
44.65 9.56 5.26 o. 59.46
43.31 9.45 5.21 o. 57.97
42.05 10.18 5.18 o. 57~40
40.86 10.90 5.14 o. 56.90
58.67 3.60 6.28 o. 68.54
57.08 4.82 6.15 o. 68~05
55.14 6.87 6.14 o. 68.15
53.31 1.25 5.82 o. 60.37
51.62 5.24 5.89 o. 62.75
50o02 7.57 5t93 O. 63.52
48~53 2.83 5.67 o. 57.03
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
. 01
'I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM~SUHMARY OUTPUT
.·• ************************************************
ALASKA RAILBEL T RUN 01
ZEROr. -3%
JOB NUMBER 2HL4Z5
****************************************
GENERATION SYSTEM
NUKE COAL NGASST OIL GT DIESEL COHCYC TYPES
TYPE 1 2 3 4 5 6 7-10
OPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 · 0 0 0 0 ·o
1992 MW 0 59 452 141 67 317 155 SUM= 1190
*********************************************************************** TOTAL
CAPAB.
YR Y E. A R L Y M W . A D D I T I 0 N S + TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 200* 1373
9~ 1X 200 1542
95 1495
96 200* 1624
97 1X 70 1620
98 1X 70 1635
99 1635
0 1591
1 1X .70 1661
2 1608
3 !X 70 1.625
4 1X 70 1695
5 1X 200 1807
6 1X 70 1854
7 lX 70 19.24
8 o 1X 70 1968
9 1X 200 2167
10 2167
***********.************************************************************ *********************************************************************** HW AitD 0 1000 560 0 0 0 0 SUM= 1560
MW RET 0 -46 -335 -141 -61 0 0 SUM= -583
****** ****** .****** ****** ****** ****** ****** **** *********** 2010 0 1013 676 0 6 317 155 SUH= 2167
PCT TOT O. 46.7 31.2 o. 0.3 14.6 7.2 SUM=l.OO .PCT
*********************************************************************** AUTO 0 600 . 560 0 0 0 0 SUH= 1160
PCT TOT O. 51.7 48.3 o. O. O. 0. SUH=100 PCT
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
·I
•I
I
,I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAH-SUHHARY OUTPUT
******~*****************************************
ALASKA RAILBELT RUN 01
ZEROX -3X
JOB NUMBER '2'tiL4ZS
**************************************•*
TOTAl CAPABILITY
<INCLUDING TIES) LOSS OF LOAD
F'ROSAE<lLITY
COST IN MILLION $
YEARLY CUM. PW
YEAR
**** 19~~
LOAD
YEAR
END
TIME OF
. t=:EAI<
PCT,
I~ES • IllY H/Y COST TOTAL
\(994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
POOL
***** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
13??
1430
1484
1537
***** 1373
1542
1495
1624
1620
1635
1635
1591
1661
1608
1625
1695
1807
1854
1924
1968
2167
2167
TOTAL
***** 1373
1542
1495
1624
1620
1635
1635
1591
1661
1608
1625
1695
1807
1854
1924
'1968
2167
2167
**** 45.0
59.8
52.0
61.9
58.4
56.6
53.6
46.8
48.2
38.9
35.9
37.5
42.3
40.2
39.7
3?.6
46.0
41.0
TOr TAL
****** ****** ******* 164.3 0.063 o.
0.027 o.
0.077 o.
0.059 o.
o.os4 o.
Oo092 Ot
0.055 Oo
0.059 o.
0.038 o.
0.062 o.
0.087 o.
0.057 Oo
0.062 o.
o.064 o.
0.057 o.
o~066 o. o.o26 o. o.os1 o ..
YEARLY $/MWH
181.9
188.3
231.9
240.7
250.5
256.1
261.2
273.1
·281.1
295.2
308.6
331.6
348~2
365.0
384.7
406~3
422.4·
******* 118.7
246.3
374·.5
527.8
682 .• 3
838.4
993.4
1146.8
1302.6
1458.2
1616.9
1777.9
1946.0.
2117.3
2291.6
2470.0
2652>r9
2837.5
f•EAK -ENERGY LOA II COSTS ********************************** YR <MW> <GWH> FACTOR <MIL.$) INV. FUEL O+M N.I. TOTAL
** *****'* ******* ****** ****** ***** ***** ***** ***** ****** 93 947 4736 57.09 164 7.64 23.36 3.69 o. 34.69
94 965 4829 57.12 182 12.46 21.39 3.82 o. 37.67
'"95 983 49"" ....... 57.16 188 12.22 22.25 3.78 o. 38.26
96 1003 5031 57.10 ?3? .,j<i,; ... 18.14 23.88 4.07 o. 46.09
97 1023 5141 57.37 241 18.21 24.59 4.01 o. 46.82
98 1044 5250 57.40 251 1.8t29 25.45 3.98 o. 47.72
99 1064 5360 57.51 256 17.91 25.97 3.90 o. 47.78
0 1084 5469 57.44 261 17.56 26.45 3.75 o. 47.77
1 1121 5661 57.65 273 17.38 27.14 3.72 o. 48.24
2 1158 5853 57.70 281 16.81 27.61 3.60 o. 48.02
3 1196 6044 57.69 295 16.68 28.60 3.56 o. 48.84
4 •1233 6236 57.58 309 16.54 29.40 3.55 o. 49.49
5 1270 6428 57.78 332 19.78 2S.04 3.77 o. 51.59
6 1323 6701 57.82 348 19.33 28.93 3.70 o. 51.97
7 1377 6.973 57.81 365 18.92 29.77 3.66 o. 52.35
8 1430 7246 57.69 385 18.54 . 30.93 3.62 o. 53.09
9 1484 7518 57.83 406 21-.. 06 29.16 3.82 o. 54.04
10 1537 7791 57.86 422 20.32 30.15 . 3.75 o. 54.22
I
'I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I ·----------
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
***********%************************************
AlASKA RAILBELT RUN 02
ZERO!Y. -3~
JOB NUMBER 2ML4Z7
****************************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COHCYC TYPES
TYPE 1 2 3 4 5 6 7-10
OPTHZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 HW 0 59 452 141 67 317 155 SUM= 1190
*********************************************************************** TOTAL
CAPAB.
YR Y E A R L Y M W A D D I T I 0 N S + TIES ** ******* ******* ******* ******* ******* ******* ***** ~***** **** 93 680* 1853
~4 1822
95 1774
96 1704
97 1630
98 1575
99 1575
0 1531
1 1531
2 601* 2079
3 2026
4 1* 2027
5 1939
6 1* 1917
7 lX 70 1987
S l X 70 1 * 2032
9 2031
10 lX 70 1* 2102
*********************************************************************~~* ********************************************************************>';;** MW ADD 0 0 210 0 0 0 1285 SUM= 14\95
MW RET 0 -46 -335 -141 -61 0 0 SUM= -5l13
*lt**** ****** ****** ****** -****** ****** ******-**** ***********
.. .
.:.
I
I
I
I
I
I
I
I.
I
I
I
I
••
I
I.
I
I
I
GENERAL ELECTRIC COMPANY
OGF'-5 GENERATION PLANNING PROGRAM-SUMMARY OUTFjUT
************************************************
ALASKA RAILBEL T RUN 02
ZERO% -3%
JOR NUMBER 2HL4Z7
*******~********************************
TOTAL CAPABILITY
<INCLUDING TIES)
YEAR TIME OF
,:-tR
¥*
'7'3
94
?>5
'-}6
97
98
99
00
01
·)2
()3
)4
·)5
)6
)7
)8
()9
1.0
LOA It
***** 947
965
983
1003 '
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
F'OOL
f'EAK
l"R . _<MW>
** ****** 93 947
94 965
C)15 983
96 1003
97 1023
98 1044
99 1064
0 1084
1 1121
2 1158
3 1196
4 1233
5 1270
6 1323
7 1377
8 1430
. 9 1484
l.O 1537
ENit F'EAt<
***** ***** 1853 1853
1822 1822
1774 1774
1704 1704
1630 1630
1575 1575
1575 1575
1531 1531
1531 1531
2079 2079
2026
2027
1939
1917
1987
2032
2031
2102
TOTAL
ENERGY
<GWH>
******* 4736
4829
4922
5031
51'41
5250
5360
5469
5661
6352
6455
6599
6698
6880
7079
7310
7551
7827
~026
2027
1939
1917
1987
2032
2031
2102
LOA!)
FACTOR
****** 57.09
57.12
57.16
57.10
57.37
57.41
57.51
57.44
57.65
62.61
61.61
60.92
60.21
59.36
58.69
C'8 "'O \.J • ..!. '
58.08
58.14
F'CT,
RES.
**** ~5.7 ss.s
so •. s
69.9
59.4
so.a
. 48.0
41.2
36.6
79.5
69.4
64.4
52.7
44.9
44.3
42.1
36.9
36.8
TOTAL
COSTS
(MIL,$)
****** 207
213
215
227
231
236
241
249
258
249
268
249
266
254
277
276
295
299
LOSS OF LOAit
PROBABILITY
DIY H/Y
****** ****** o.ooo o.
o.ooo o.
o.ooo o.
o.ooo o.
o.ooo o.
0.001 o.
0.002 o.
0.015 o.
0.032 o. o.ooo o.
0.001 o.
0.001 O.
0.017' o.
o.o6a o.
o.o2s o.
o.o29 of
o.oso o.
0.025 o.
COST IN
YEARLY
COST
******* 206.7
212.5
215.1
227.2
230.8
235.7
240.9
248.7
258.2
249.3
267.9
249.2
263.8
253.6
277.5
275.8
295.5
299.1
MILLION $
CUM. PW
TOTAL
******* 149.3
298~4
444.8
595.0
743.2
890.0
1.035.8
1181.9
1329.1
1467.2
1611.2
1741.2
1875.9
2000.6
2133.2
2·261.0
2394,1
2524.8
YEARLY S/HWH
********************************** INV.
***** 34.49
33.83
33.19
32.47
31.78
31.12
30.48
29.87
28.86
35.96
35.39
34.62
34.10
33.20
32.60
31 .• 90 Jo.ee
30.10
FUEL
***** 5.29
6.37
6.76
.9.05
9.57
10.29
11.02
12.22 .
13.41
o.
2.83
o.
2.49
0.70
3.62
2.95
5.39
5"33
O+H
***** 3.86
3.81
3.74
3.64
3.54
3.48
3.44
3.38
3.34
3 •. 29
3.29
3.15
3.09
2.95
2.97
2.88
2~B6
2.79
N.I.
***** o.
o.
o.
o. o.
o~
o.
o.
o.
o.
o.
o• o. o.
o. o. o. o.
TOTAL
****** 43.65
44.01
'43. 70
45.16
Jt4.89
44.89
44.94
45~47
45.61
39.26
41.50
37.77
39.68
'36.86
39.19
37.73
39.13
38.21
:1
·I
I
I
I
I
••
I
I
I
I
I
I
I
I
I
I
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNINGj PROGRAM-SUMMARY OUTPUT
ttl**************************'************'*****
ALASKA RAILBEL T RUN Pl
ZERO/. -5i.
JOB NUMBER 2ML9J7 01/20/82
****************************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYPE 1 2 3 4 5 6 7-10
OPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 452 141 67 317 155 SUM= 1190
*********************************************************************** " TOTAL
YR
** 93
94
95
96
97
98
99
0
1
2
Y E A R L Y M W A D D I T I 0 N S
******* ******* ******* ******* ******* ******* ***** 200*
200*
CAPAB.
+ TIES
****-** **** 1373
1 ~4., .... "-
1495
1624
1620
1635
1635
1591
1661
1608
3 70* 1625
4 70* 1695
5 140* 1747
6 70* 1794
7 200* 1994
8 1968
9 70* 2037
10 2037
*********************************************************************** *********************************************************************** MW ADD 0 800 630 0 0 0 0 SUM= 1430
MW RET 0 -46 -3~5 -141 -61 0 0 SUM= -583
****** ****** *****~ ****** ****** ****** ****** **** *********** 2010 0 813 746 0 6 317 155 SUM= 2037
PCT TOT O. 39.9 36.6 O. 0.3 15.6 7.6 SUM=lOO PCT
*********************************************************************** AUTO 0 0 0 0 0 0 0 SUM= 6
PCT TOT 0 I 0. 0. 0. 0. 0. 0. SUM= 0 PCT
f COMMI TTEI• MW
·.:I
I
I
I
I.
I
I
I
I
I
I
I
I
I
I
I
I
I
I
UENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
*~~*'***~**'************************************
flLASKA RAIL BELT
'7 E R 0 7. -t:' ., -•-.\.J./a
JOB NUMBER 2ML9J7
RUN Pl
****************************************
TOTAL CAPABILITY
<I NCLUIJING TIES)
YEAR TIME OF
LOSS OF LOAD·
PROBABILITY
COST IN KILLION $
YEARLY CUH. PW
YEAR
**** 1993
LOA II ENit PEAK
PCT~
RES. It/Y H/Y COST TOTI~L
***** 947 ***** ***** 1373 1373 **** 45 .• 0 ****** ****** 0.06.3 o. ******* ******* 190t2 111.2
1994
1995
1996
1997
1998
.1999
2000
2001
2002
2003
2004
2005
2006
2007
2009
2009
2010
YR
** 93
POOL
PEAK
<MW>
94
95
96
97
98
99
0
l
2
3
4
5
6
7
8
9
10
****** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
15.37
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
1542 1.542
1495 1495
1624 1624
1620 1620
1635 1635
1635 1635
1591 1591
1661 1661
1608 1608
1-625 1625
1695 1695
1747 1747
1794 1794
1994 1994
1968 1968
2037 2037
2037 2037
59.8
52.0
61.9
58.4
56.6
53.6
46.8
48.2
38.9
35.9
37.5
37~6
35.6
44.8
37.6
37.3
32.5
o~o27 o. 224.4 236.2
0.077 o. 231.1 358.8
0.059 o. 298.3 509.4
0.084 o. 309.4 658.2
0.092 o. 321.6 805.5
o~oss o. 327.7 948.5
0.059 o. ~334~1 1087.4
0.038 o. ~~47.9 1225.0
0.062 o. 356.5 1359.4
0.087 o. 373.6 1493.5
0.057 o. 390.2. 1626.9
0.049 o. 416.5 1762.5
().052 o. 44·0.6 1899~1
0.023 o. 488.1 2043.2
0.066 o. 5016.4 .2185.7
0.051 o. 530.4 2327.7
0.099 o. 55().4 2468.1
TOTAL
ENERGY
<GWH>
LOA II
FACTOR
TOTAL
COSTS
<MIL.$)
YEARLY $/MWH
********************************** INV • FUEL O+M N • I •· TOTAL
******* 4736
4829
4922
5031
5141
5250
5360
5469
5661
5853
6044
6236
6428
6701
6973
7246
75!8
7791
****** 57.09
57.12
57.16
57.10
57.37
57.40
57.51
57.44
57.65
57.70
57.69
57.58
5/.79
57.82
57.81
57.69
57.83
57.86
****** 190
224
2J1
298c
309
322
328
334
348
356
374
390
416
441
488
506
530
550
***** ***** ***** ***** ****** 12.30 23.36 4.51 o. 40.16
20.33 21~39 4.75 o. 46.47
19.95 22t22 4.79 o. 46.96
30.13 23.88 5.28 o. 59.29
30.27 24.59 5.32 o. 60.19
30.42 25.45 5.38 o. 61.25
29.79 25.~7 5.38 o. 61.14
29.20 26.60 5.29 o. 61.10
28.98 27.14 5.34 Ot 61.45
28.03 27.61 5.27 o. 60.91
27.89 28.60 5.32 Oo 61.81
27.77 29.40. 5.40' o. 62~57
28.40 30.89 s.so o. 64.79
27.96 32.20 5.58 o. 65.75
34.28 29.77 5.96 o. 70.00
32.98 30.93 . 5.97 o. 69.88
32.47 32.03 6.05 o. 70.55
31.33 33.20 6.11 o. 70.64
r-~· ~--~-------~~~-------------------------------
1
I
I
I
I
I
I
I
I
I
·I
I
I
I
I
I
~I
~·
I
:ENE~AL ELECTRIC COMPANY
OGP-~ GENE~~710N PLANNING PROGRAM-SUMMARY OUTPUT
'**'****1**~*f**'*******************************
ALASKA RI'~IL~EL T RUN P2
7 t_-c-. 0 •J --~· .. , ~~n h . ~h
JOB NUMBER 2ML9J5
****************'***********************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COHCYC TYPES
TYPE 1 2 3 4 5 6 7-10
OPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 452 141 67 317 155 SUM:; 1190 -·
***********************************************************************
YR
** 93
94
95
96
97
98
99
0
1
3
4
TOTAL
CAF'AB.
Y E A R L Y M W A D D I T I 0 N S + TIES
******* ******* ******* ******* ******* ******* ***** ****** **** 680* 1.853
601*
1822
1774
1704
16-30
1575
1575
1531
1531
2079
-. 1'\,C"'t. ·" /Lv~•O
1* 2021
s 1n9
6 1* 1917
7 1X 70 1987
8 lX 70 1* 2032
9 2~1
10 lX 70 ·1* 2102
*************************************~********************************* *********************************************************************** MW ADD 0 0 210 0 0 0 1285 SUM= 1495
MW RET 0 -46 -335 -141 -61 0 0 SUM~ -583
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 13 326 0 6 317 1440 SUM= 2102
PCT TOT Oe 0.6 15.5 o. 0~3 15.1 68.5 SUH=lOO PCT
*********************************************************************** AUTO 0 0 210 0 0 0 0 SUM= 210
PCT TOT O. O. 100.0 O. o. O. O. SUM=lOO PCT
* COMMITTED MW
:1.
I
I
I
I
I
I
I
I
I
I
I
I
I
••
I
:I
I
I
bENE~AL ELECTRIC COHPANY
OGP-~ GENERATION PLANNING PROGRA~-SUMMARY OUTPUT
************************************************
ALASKA RAILBEL.T RUN P2
ZEROX -5%
JOB NUMBER 2ML9J5
****************************************
YEAR
****-1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
YR
** 93
94
95
96
97
9B
99
0
1
2
3
4
5
6
7
8
9
10
LOAD
***** 947
965
983
1003
1023
1044
1064
1084
1121
1158-
1196
1233
1270
1323.
1377
1430
1484
1537
POOL
PEAK
<MW>
TOTAL CAPABIL-ITY
<INCLUitlNG TIES>
YEAR TIME OF
ENI• PEAK
***** ***** 1853
1822
1774
1704
1630
1575
1575
1531
1531
2079
2026
2027
1939
1917
1987
2032
2031
2102
TOTAL
ENERGY
<GWH>
1853
1822
1774
1704
1630
1575
1575
1531
1531
2079
2026
2027
1939
1917
1987
2032
2031
2102
LOAD
FACTOR
****** 947 ******* 4736 ****** 57.09
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
4829
4922
5031
5141
5250
5360
5469
5661
6352
6455
6599
6698
6880
. 7019
7310
7551
7827
"
57.12
57.16
57.10
57.37
57.41
57.51
57.44
57.65
62.61
61.61
60.92
60.21
59.36
58.69
58.20
58.08
58.14
PCT.
RES1
**** 95.7
88.8
80.5
69.9
59.4
50.8
48.0
41.2
36.6
79.5
69.4
64.4
52.7
44.9
44.3
42.1
36.9
36.8
LOSS OF LOAD
PROBABILITY
D/Y H/Y
****** ****** o.ooo o.
o.ooo o.
o.ooo o.
o.ooo o.
o.ooo o.
0.001 o.
0.002 o.
0.015 o.
0.032 o.
o.ooo o.
0.001 o.
o.oo1 o~
o.ol.7 o.
0.068 09
0.025 o.
0.029 o.
o.oso o.
0.025 o.
COST IN
YEARLY
COST
******* 349.7
355.9
359.0
371.6
375.7
381.0
386.8
395.7
405.3
475.2
494.5
476.2
493.4
481.6
509.1
510.8
531.5
538.8
TOTAL YEARLY S/MWH
MILLION $
CUM. PW
TOTAL
******* 204.4
402.6
593.0
780.7
961.4
1136.()
1304.7
1469.1
1629.6
1808~7
1.986.2
2149.0
2.309.6
2459.0
2609.3
2752.9
2895.3
3032.7
COSTS ********************************** <MIL.$) INV. FUEL O+M N.I. TOTAL
****** ***** ***** ***** ***** ****** 350 63.a3 5.29 4.71 o~ 73.s3
356 62.60 6.37 4.74 o. 73.71
359 61.42 6.77 4.75 o. 72.94
372 60.09 9.05 4.72 o. 73.86
376 58.80 9.57 4.70 o. 73.07
381 57.58 10.29 4.71 o. 72.58
387 56.40 11.02 4.75 o. 72.17
396 55.27 12.31 4.76 o. 72.35
405 53.40 13.41 4.80 o. 71.60
475 69.94 o. 4.88 o. 74.82
495 68.81 2.83 4.97 o. 76.61
476 67.32 o. 4.86 o. 72.17
493 66.31 2.49 4.86 o. 73.66
482 64.56 0.70 4.74 o. 70.01
S09 63.44 3.62 4.86 O. 71.92
511 62.12 2.95 4.81 o. 69.87
531 .. 60.14 5.39 4.86 o. 70.39 . 539 58.67 5t33 4.84 o. 68.84
:
I
I
I
I
I
I
I
I
I
I
I·
I
I
I
I
I
I
HI
r~:... ;.1 E !:::• .l'l L ::! r:·c· T t:i'1'C r '1 ~lf· • _).,j v ...... ._"' r~f'" '-' .... t:.-• ._~_. .... ua·-1. Hr,.. •
UGP-5 GEMERAT!ON PLANNING PROGRAM-SUMMARY OUTPUT
'***t*******************************************
ALASI<1!). HA!LBEl T
-<t E .. r· 0 •u . ...., '" ~ r~ /. -.:.. t.~
JOB NUMBER 2MLD23.
RUN Ql
oJ.• il.• \1.· >It \!• -.!• \1• 11• 'L• oJ:• ".1.• ..t . ..V ..V \l• q. '41.• ..!.• oJ. ·~ \1< \1.• \l• * ...t· il.• 'J: ~· * •ll * * * * \1· •.1." * * '-!· \1.· .lfr.lf• Ff II\.,, If~ -'i•,. ,., .. ~ "r ·T~ ~· 4T• .Jf\ .. ;, If 1)\ .,. ,.l, IJ) #I' trf\ ·.If· If· •T' If., \. f4\ .. i. ;iT .... ~ ,;)-~
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT" DIESEL COMCYC TYPES
lYPE 1 2 3 4 5 6 7-10
OPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 452 141 67 317 155 SUM= 1190
*********f*************************************************************
TOTAL
CAF'AB.
YR Y E A R L Y M W A D D I T I 0 N S + TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 200f 1373
94
95
96
97
98
99
0
1
2
3
4
5
6
7
200W
70*
70*
140*
70*
1542
1495
1624
1620
1635
1635
1591
166.1
160:8
1625
1695
1747
1794
1994
8 1968
9 70* 2037
10 203?
*********************************************************************** ***************f***************************t**********************~$*** MW ADD 0 800 630 0 0 0 0 SUM= 1430
MW RET 0 -46 -335 -141 -61 0 0 SUM~ -5S3
****** ****** ****~* ****** ****** ****** ****** **** *********** 2010 0 813 746 0 6 317 155 SUM~ 2037
PCT TOT O. 39.9 36.6 o. 0.3 15.6 7.6 SUM=100 PCT
*******************************************************************~*** AUTO 0 0 0 0 0 0 0 SUM= 0
PCT TOT O. O. O, O. Ot o~ o •. SUM: 0 PCT
* COMMITTED M~J
"
I l:i t:'l..t E c:_, ! L E t ;::-C T t::• l r ·~ :-M ~""• ... ~. , • ;.;>-1'. f\[) ._._ ,,,.,...., ,_:J,,iHI·{'f
I ~G~-5 GENER~TlON PL~HNING ~ROG~~M-EUMMARY QUTP~T
ff*'*****'*1*****************4***************'**
t:.• !· ll B' •.:·, ·~ r\ ll . 1:, .... ,
I • :Z E h D :~ -· 2 ·:;
J~B NUMFEH 2MLD23
RUN Ql
t )l'. *' * '*' ~ ~ '* ~\ ;f ~· * ~·~.;f.~:**'~.*'**** :t· * * *' *· :t * * * * :t. :t: :t· * >r.· *
I
1993
1 1994
1995
1996
197'7 1 1998
. 1999
2000
I 2001
.20()2
2003
20011 1 2005
2006
2007
12008
2009
? t1•l ()
..... W' It "tt
I
I YF~
~:w
I
o-z . ._.
94
9 :-;
96
I t>•••
I /
98
99
I 0
1 ,... .::.
I 3
4
5
6
. I 1
8
9
I 10
I
LOf-1It
;t·*·J.· * ~ ........
947
965
C>8:"J: ; . '-'
1003
1023
1044
1064
l.084
1121
1158
1196 1 ....... ,. ..... ..::.~~
1270
13"' .... -~
1377
1430
1484
1537
POOL
F'EAI\
'MW ., I\-t I
****** ·~47
965
983
1003
10""'1: ---· 1044
1064
1084
1121
1158.
1196
1233
1270
1323
1377
1430
1484
1537
TOTf-1L C?1FABILITY
·~ lNCLUDING i'IIIS)
YE1~R Til1E OF F'CT~
END PEAK RES.
***** ***** **** 1373 1373 45.0
1~42 1542 59.8
1495 1495 C''") 0 .._l.t:,. ..
1624 1624 61 f 9
1620 1620 58.4
1635 1.635 56.6
1635 1635 53.6
1591 1591 46.8
.1661 1661 48.2
1608 1608 38.9
1625 1625 35.9
1695 16Cl5 37.5
1747 1747 37.6
'1794 1794 35.6
1994 1994 44.8
1968 1968 ........ 6 ~ / t
2037 :!037 37.3
2037 ~~037 32.5
TOTAL TOTAL
E~!EF\:GY L0~1D COSTS
tGlrJH) FACTOR <MIL.$)
~:~ **.*** $***** ****** 4736 57.09 170
4829 \'::" ... 1,..,
._} / t ..:.. 190
4922 57+ 16 196
5031 57(10 245
5141 57.37 254
5250 57.40 265
5360 C.j"7 51 \.oi. I + 272
5469 57.44 278
5661 57.65 '100 ..:.. ,
5853 57.70 299
6044 57.69 315
6236 c;; 58 .... . . 330
6428 r::----.8 ,_1/t/ 353
6701 57.82 .... 76 ~ .
6973 57.81 405
72·16 r::""'] 69 >:J, •. 423
7518 57.83 445
7791 57.86 465
LOSS OF LO~~~ COST IN MILLION $
PROBABILITY YEARLY CUM~ PW
·DIY H/Y COST TOTAL
****** ****** ******* ******* 0.063 o. 169.9 136.6
0.027 o. 189.7 286.2
0.077 o. 196.4 438.0
0.059 o. 244.7 623.4
0.084 o. 254.5 812.5
0.092 o. 265.4 1005 .. 8
0.055 o. 271.5 1199.7
0.059 o. 277.9 1394.3
0.038 o. 290.3 1593.6
0.062 Ot 298.9 1794.8
.0.087 o.-314.6 2002..4
0.057 o • 329.8 2215.7
0.049 o. 353.1 2439~6
0.052 o. 375.7 2673-.2
0.023 o. 404.6 2919~B
0.066 o. 422.8 3172_., s
0.051 o. 445.3 3433.4
0.099 0 • 465.2 3700.6
YEARLY $/MWH
********************************** INV. FUEL O+M N.I. TOTAL
***** ***** ***** ***** ****** 8.01 23.36 4.51 o. 35~87
13.13 21.39 4.75 o. 39~28
12.89 22.22 4.79 o. 39.90
19.47 23.88 5.28 o. 48.63
19.59 24.59 5.32 Ot 49.50
19.72 25.45 5.38 o. S0 .• 55
19.31 25.97 5.38 o. 50.66
18.93 26.60 5.29 o. so~s2
18.81 27.14 5. 34 o. 5.1.29
18.19 27.61 5.27 o. 5.1)07
18.13 28.60 5.32 o, 52.05
18.08 29.40 5.40 o. 52.89
18.54 30.89 5.50 o. 54.94
18.28 32.20 5.58 o. so-..06
22.30 29.77 5.96 o. 58.02
21.46 30.93 5.97 o. 58.36
21.14 32.03 6.05 o. 59.23
20-.40 33.20 6.11 o. 59.71
-'' ~ .~., """ -~·"' .... "'""'" ..... , .. ,_,. , ... : .. , ........... ,,.,.,-~..,_,.,,.~ ... -:.-~;:::-.. ";._...,"''" ... ~~: ....... ,,.,,..,,. ._,,,,,..:.,.. "-v,-..~.;l;,..~ .... '!"4."">·! • .+.·<> ......... ;...,
I
I
I
I
I
JGP-5 GENERATION PL~NHINE PROGRAM-SUMMARY OUTPUT
1"*********************ll************!***********
RUN Q2
JOB NUMBER 2MLD27
*t~tW*f*********************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYFE 1 2 3 ·4 5 6 7-10
DPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
19 9:; 11 W 0 59 4 52 14 1 6 7 31 7 15 5 SUM=. 1190
I *******************************f*************************************** . TOTAL
CAF'AB.
I YR Y E A R L Y M W A D D I T I 0 N S + TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 680% 1853
I 95
96
1822
1774
1704
1630
1575
Q7 < I
I 98
9Cj'
0
.1575
1531
1531
601* 2079 I
I
I
1
2
/1. l
5
-l
8
1X
lX
70
70
2026.
1* 2027
1939
19.17'
1987
1* 2032
Q 2031
10 1X 70 1* 2102
lt******W******~*******~*********************************************** I *************************************************************~***t**~** MW ADD 0 0 210 0 0 0 1285 SUM= 1495
MW RET 0 -46 -335 -141 -61 0 0 SUM~ -583
I *·*~** ***~~* ****** ****~* ~***** **t*** ****** **** *******~*** 2010 0 13 326 0 6 317 1440 SUM= 2102
PCT TOT 0< 0~6 15.5 O. 0.3 15,1 68.5 SUM~100 PCT
**********¥***********.********~*************************************** I AUTO 0 0 210 0 0 0 0 SUM~ 210
PCT TOT O~ O. 100.0 o. Oi o. o. SUM=lOO PCT
I
I
I
I·
·-i: C 0 M M I T T E I! H :.:1
I
I
I
I
I
I
1.
I
I
I~
I_
I
I
I
I
I
I
I
I
. l . " I=' t" • • ,.. . 1:'' L .... t:.. • ,.. j• n. f.i. F' .. } I ~ ~ ~I'!-• • : i ~ ::. ;_..!. f •• .!.. ~ -~~ ~' 1 J··t ,~. I
:.: 2 F -·s G: E ~\ £ F: r~, T .1 t' N F' L ~~. ! N I N G F R JJ G R ~1 N ". S IJ M ti t~ f. .. \' 0 U T F' U '1
~**tl*¥***l**~***~*11~**********~**************t
RUN Q2
IQ~ ~UlMP~O ~Mt It~~ ""'"· .r:. I. t ......... \ ...... 1,'-' ._,
~~*~·w~~~~~.w~~~*~**~~*~~~~**'~~~*~~~~•w~~~ "( · · t ;; .. 't~ If.. ,. ? •1' ·"£\ o1f ·"7· II .,,_ · •'Tt ,, .. · t IJ IJ· 1 .IJ if 4~ ~1', •t' ~,. •• • t· 'f IT If• IT• ·T·t "• ,, •T
YEAF:
**** j 993
1994
:l995
1996
1997
1998
1999
2000
2C•01
'') 0 v"" ~ J:.. ~
200 41t
2005
.... ''(' 6 ,.·:.v ·'
2007
')f'l08 ..... ,
') Q\ ('I Q .... -"
2010
** t:~7 7 .. ,
94
95
96
97
98
99
0
1 ... ..::.
3
4
5
6
7 ..
10
LOA !I
***** 9·17
965
983
1003
1023
1044
1064
1084
11'21
1158
1.196
1 '.)7 ~ ~...;..-.......
1 '1,0 ..:....l
1323
1377
1430
1484
1537
POOL
PE?;K
<MW>
**~~***' 947
965
983
1044
1064
1084
1121
1158
1196
1233
1270
1323
:1377
1430
1484
1537
TOTAL CAPABILITY
(INCLUDING TIES)
'f£r:\r~ TINE OF
EN [I F·E AI\
:~**** ***** 1853
1822
1774
1704
1630
1575
1575
1531
1531
2·079
?0?6 .... .....
2027
1939
1917
1987
2032
2031
.?10? ... ...,
TOT tiL
ENERGY
<GWH)
**:+·**** 4736
4829
4 c;·?'1 ........
5031
5141
5250
5360
5469
5661
6352
6455
6599
6t.9.8
6880
7079
-"'rlo l~
7551
7827
1853
1822
1774
1704
1630
1575
1575
1531
1531
2079
2026
2027
1939
1917
1987
2032
-2031
2102
LOA!!
FACTOR
****** 57.09
57.12
57.16
~7 10 "" . .
57.41
r.:;? c;l .... • t .....
57.65
t.2 + 61
60~92
60.21
59.36
58.69
58.20
58.08
58.14
F'CTv
F~ES +
**** 95.7
88~8
80.5
'0 Q 0, + '
59.4
50)8
48.0
41~2
36.6
79.5
69.4
64.4
s::',... 7 ....... .::. .
44.9
44.3
TOTAL
COSTS
<MIL.$)
****:i<*
205
212
215
227
231
237
4'i4"') ~ &..
251
261
2·54
284
265
282
271
297
297
317
323
LOSS OF LOArt
·PROBABILITY
It/Y H/Y
****** ****** o.ooo o~
o.ooo o.
o.ooo o.
o.ooo o.
o.ooo o.
0.001 o.
0.002 o.
0.015 o.
0.032 o.
0.000 Oo
0.001 o.
0.001 o.
0.017 o •
0.068 o.
0.025 o.
0.029 o~
0.050 o.
0.025 o.
COST IN
YEARLY
COST
******* 205.3
211.5
214.6
227.2
231.3
236.7
242.4
251.3
261.0
264~2
283.5
265.3
282.4
270.6
296.6
296.7
317.4
323.1
MILLION $
CUH. f'W
TOTAL
*-****** 165.1
331.9
497.8
670.0
841.8
1014.2
1187~4
1363.3
1542.4
1 "7""0 ..., .:. .. -
1907.3
2078(-9
225S.O
2426.3
2607.1
2784.3
2970~3
3155.9
YEARLY $/MWH
****************************~***** I NV. FUEL _QtM N • I. TOTAL
***** ***** ***** ***** ****** 33.34 5.29 4.71 o. 43.35
32.70 6.37 4.74 o. 43.81
32.08 6,77 4o75 O. 43.60
31t39 9.05 4.72 o. 45i16
30.71 9.57 4.70 o. 44~99
30.08 10.29 4.71 o. 45.08
29.46 11.02 4.75 0( 45.23
28.87 12.31 4.76 o. 45.95
27.89 13.41 4c80 Oc 46.10
36.72 o. 4.88 o. 41.60
36.13 2,83 4.97 Ot 43.92
35.34 o. 4.86 o. 40.20
34.82 2c49 4.86 O. 42.16
33.90 0.70 4.74 Ot 39.34
33.42 3.62 4c86 Ot 41.90
32.83 2,95 4.81 o. 40.58
31.78 5+39 4.86 O, 42c03
31.11 5.33 4.84 O. 41.28
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAILBEL T RUN Rl
ZEROi! -3i.
JOB NUMBER 2MLD31
****************************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYPE 1 . 2 3 4 5 6 7-10
OPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 , 59 452 141 67 317 155 SUM= 1190
*ft~********************~********************************************** . TOTAL
CAPAB.
YR Y E A R L Y M W A D D I T I 0 N S + TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 200* 1'373
94 lX 70 1412
95 1X 70 1435
96 200*' 1564
97 lX 70 1560
98 lX 70 1575
99 1575
0 1531
1 1X 70 1601
2 1548
3 2X 70 1635
4 1635
5 lX 200 1747
6 lX 70 1794
7 1X 70 1864
8 lX 70 1908
9 lX 70 :1977
10 lX 70 2047
*****************************************•***************************** *********************************************************************** MW ADD 0 400 840 0 0 200 0 SUM= 1440
MW RET 0 -46 -335 -141 -61 0 0 SUM= -583
****** ******' ****** ****** ****** ****** ****** **** *********** 2010 0 413 956 0 6 517 155 SUM= 2047
PCT TOT o. 20.2 46.7 0. 0.3 25.3 7.o SUM=100 PCT
*********************************************************************** AUTO 0 0 840 0 0 200 0 SUM= 1040
F'CT TOT 0. ·o. 80.8 0. O. 19.2 O. SUM=lOO PCT
* COMMITTED MW
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAILBEL T RUN Rl
ZEROY. -3%
JOB NUMBER 2MLD31 J!
****************************************
YEAR
**** 1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
YR
** 93
94
95
96
97.
98
99
0
1
2
3
4
5
6
7
8
9
10 .
LOArt
***** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
. 1323
1377
1430
1484
1537
POOL
PEAK
<MW>
****** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
153.7
TOTAL CAPABILITY
< INCLUitiNG TIES)
YEAR TIME OF
ENII PEAK
***** ***** 1373 1373
1412 1412
1435 1435
1564 1564
1560 1~60
1575
1575
1531
1601
1548
1635
1635
1747
1794
1864
1908
1977
2047
TOTAL
ENERGY
<GWH>
******* 4736
4829
4922
5031
5141
5250
5360
5469
5661
5853
6044
6236
6428
6701
6973
7246
7518
7791
1575
1575
15.31
1601
1548
1635
1635
1747
1794
1864
1908
1977
2047
LOAD
FACTOR
****** 57.09
57.12
57.16
57.10
57.37
57.40
57.51
57.44
57.65
57.70
57.69
57.58
57.78
57.82
57.81
57.69
57.83
57.96
F'CT.
RES.
LOSS OF LOAit
F'ROBAB ILITY
It/Y H/Y
COST IN
YEARLY
COST
MILLION $
CUM. PW
TOTAL ****.
45.0 ****** ****** ******* 190.2 ******* 137.4
46.3
45.9
55.9 ..
52.5
so.a
48.0
41.2
42.8
33.7
36.7
32.6
37.6
35.6
35.4
33.4
33.2
3Z.2
TOTAL
COSTS
<MIL.$)
****** 190
202
215
281
294
309
315
328
348
359
388
405
440
468
500
533
565
,, 602
0.063 0&
0.047 o.
0.044 o.
0.038 o.
0.057 o.
0.065 o.
o.o37 o~
0.094 o.
0.060 o.
0.099 o.
0.052 o.
0.091 o.
0.079 o.
0.083 o.
0.069 . o.
0.082 o.
o.oso o.
0.043 o.
201.9
214.7
280.6
294.4
308.8
315.0
328.1
348.5
359.1
388.1
405.4
439.6
468.4
500.1
532.6
565.4
602.1
279.0
425.2
610.7
799,7
992.1
1182.7
1375.4
1574.2
1773.0
1981.7
.2193.2
2416.0
:2646.4
2885.2
3132.2
3386.7
3649.9
YEARLY $/MWH
********************************** INV. FUEL O+M N.I. TOTAL
***** ***** ***** ***S* ****** 11.31 23.36 5t48 o. 40.15
11t86 24.24 5o72 O, 41.81
12.41 25.23 5.99 o. 43.63
22.43 26.99 6.34 o. 55.77
22.76 27.94 6.58 o. 57.27
23.10 28.89 6.82 o. 58.81
22.63 29.23 6.92 o. 58.78
22.18 30.68 7.12 o. 59.98
22.28 31.84 7.44 o. 61.56
21.55 32.32 7.49 o. 61.36
22.59 33.77 7.86 o. 64.22
21.90 34.96 8.15 o. 65.02
25.61 34.48 8.29 o. 68.38
25.45 35.84 8.61 o. 69.89
25.33 37.39 9.00 o. 71.72
25.25 38.87 9.39 o. 73.51
25.22 40.20 9.78 o. 75.20
25.22 41.80 10e26 Ot 77.28
:I
I
;I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
GENERAL ELECTRIC COMP~NY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
~1LASKA RAlLBEL T RUN R2
ZEROi= -3%
JOB NUMBER 2MLD33
****************************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COHCYC TYPES
TYF'E. 1 2 3 . 4 5 6 7-10
OPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 -0 0 0
1992 MW 0 59 452 141 67 317 155 SUM= 1190
***********************************************************************
TOTAL
CAPAB, YR Y E A R L Y M W A D D I T I 0 N S t TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 680* 1853
94 1B22
95 1774
96 1704
97 1630
98 1575
99 1575
0 1531
1 1531
2 601* 2079 3 ~·o~6 ...... ..:..
4 1% 2027
5 1939
6 1* 1917
7 1X 70 l:987
8 1X 70 1* 2032
9 2031
10 1X 70 1* 2102
*********************************************************************** ***********************************************************************
MW ADD 0 0 210 0 0 0 1285 SUM= 1495
MW RET 0 -4o -335 -141 -61 0 0 SUM= -583
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 13 326 0 6 317 1440 SUM= 2102
PCT TOT o. 0.6 15.5 O. 0.3 15tl 68.5 SUM=100 PCT *******~*************************************************************** AUTO 0 0 210 0 0 0 0 SUM= 210
PCT TOT O. o. 100.0 o. o. 0. 0. SUM=100 PCT
* COMMITTEII MW
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
ALASKA RAILBEL T RUN R2
ZEROX -3%
JOB NUMBER 2MLD33
***************'f***********************
YEAR
**** 1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
LOA II
***** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
TOTAL CAPABILITY
<INCLUitiNG TIES)
YEAR TIME OF
ENit PEAK
***** ***** 1853 1853
1822
1774
1704
1630
1575
1575
1531
1531
2079
2026
2027
1939
1917
1987
2032
20.31
2102
1822
1774
1704
. 1630
1575
1575
1531
1531
2079
2026
2027
1939
1917
1987
2032
2031
2102
PCT.
RES.
**** 95.7 sa. a
eo~5
69.9
59.4
so.a
48.0
41.2
36.6
79.5
69.4
64.4
52.7
·44 t 9
44.3
42.1
36.9
36.8
YR
** 93
F'OOL
PEAK ·
<MW)
TOTAL
ENERGY
<GWH)
LOAD
FACTOR
TOTAL
COSTS
<MIL.$)
94
95
96
97
98
99
0
1
2
3
4
5
6
7
8
9
10
****** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1464
1537
******* 4736
4829
4922
5031
5141
5250
536-0
5469
5661
6352
6455
6599
6698
6880
7079
7310
7551
7827
****** 57.09
57.12
57.16
57.10
57.37
57o41
57.51
57.44
57.65
62.61
61.61
60.92
60.21
59.36
58.69
58.20
58.08
58.14
****** 294
301
306
318
324
329
336
315
357
423
444
427
445
434
465
469
492
503
LOSS OF LOAit
f•RQBAB IL I TY
DIY H/Y
****** ****** o.ooo o. o.ooo o.
o.ooo o.
o.ooo o.
o.ooo o.
0.001 o.
0.002 o.
0.015 o.
o;o32 o.
o.ooo o.
0.001 .o.
0.001 o.
0.017 o.
o-.o6a o.
0.025 o.
0.029 o.
o.oso o.
0.025 o.
COST IN
YEt.RLY
COST
******* 294~2
301.1
306.0
318.1
324.5
329.2
335.9
345.2
356.6
423.3
444.0
426.6
444.9
434.1
464.9
469.3
492.2
503. 2.
YEARLY $/M~JH
MILLION $
CUM. f•W
TOTAL
******* 212.5
423.7
632.1
842.4
1050.7
1255.9
1459.1
1661.9
1865.2
2099.6
2338.2
2560.8
2786.3
2999.-8
3221.9
3439.5
3661.1
3881.0
********************************** !NV. FUEL O+M N.I. TOTAL
***** ***** ***** ***** ****** 51~09 5.29 5.73 o. 62.11
so.11 6.37 s.aa o. 62.35
49.16 7&03 5.99 o. 62.18
48.09 ~.05 6.09 o. 63.24
47.06 8.84 6.21 o. 63.12
46.09 10.29 6.34 o~ 62~71
45.14 11.02 6.52 o. 62.68
44.24 12.22 6.65 o. 63.12
42.74 13.41 6.84 o. 62.99
59.69 o. 6~95 o. 66.64
58.73 2.83 7.22 o. 68.78
57.46 o. 7.19 o. 64.64
56.6~ 2.49 7.34 o. 66.42
55.11 0.70 7.29 o. 63.10
54.42 3.62 7.63 o. 65.67
53.57 2.95 7.69 o. 64.21
51.86 5.39 7.93 o. 65.18
50.90 5.33 8.05 o. 64•2S
I
•
I
.,;1
I
I
I
I
I
I
I
I
I
I
I
I
I
I
••
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAILBEL T RUN Tl
ZERO% -3i.
JOB NUMBER 2ML3S3
****************************************
GENERATION SYSTEM .
NUKE COAL NGASGT OIL GT DIESEL COHCYC TYPES
TYPE 1 2 3 4 5 6 7-10
OPTMZINB 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 452 141 67 317 155 SUM= 1190
*********************************************************************** TOTAL
CAPAB.
YR Y E A R L Y M W A D D I T I 0 N S + TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 200* 1373
94 1X 200 1542
95 1495
96 200* 1624.
97 lX 70 1620
98 1X 70 1635
99 1635
0 1591
1 1X 70 1661
2 1608
3 2X 70 1695
4 1695
5 2X 70 1747
6 1X 70 1794
7 1X 70 1664
8 lX 200 2038
9 2037
10 2037
*******************~*************************************************** *********************************************************************** MW ADD 0 400 630 0 0 400 0 SUM= 1430
MW RET 0 -46 -335 -141 -61 0 0 SUM: -583
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 413 746 0 6 · 717 155 SUH= 2037
PCT TOT O. 20~3 36.6 o. 0.3 35.2 7.6 SUH=100 PCT
*********************************************************************** AUTO 0 0 630 0 0 400 0 SUM= 1030
PCT TOT O. o. 61.2 6. O. 38.8 o. SUH=100 PCT
0
* COMMI TTEit MW
.'1
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAILBEL T RUN Tl
ZERO/. -3~
JOB NUMBER 2ML3S3 01/25/82
****************************************
YEAR
**** 1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
YR
** 93
94
95
96
97
98
99
0
1
2
3
4
5
6
7
8
9
10
LOA II
***** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
F'OOL
PEAK
<MW>
TOTAL CAPABILITY
<INCLUitiNG TIES)
YEAR TIME OF
END PEAK
***** ***** 1373 1373
1542 1542
1495 1495
1624 1624
1620 1620
1635 1635
1635 1635
1591
1661
1608
1695
1695
1747
1794
1864
2038
2037
2037
1591
1661
1608
1695
1695
1747 .
1794
1864
2038
2037
2037
PCT.
RES.
**** '45.0
59.8
52.0
61.9
58.4
56.6
53.6
46.8
48.2
38.9
41.7
37.5
37.6
35.6
35.4
42.5
37.3
32.5
TOTAL
ENERGY
<GWH>
LOAD
FACTOR
TOTAL
COSTS
<MIL.$)
****** 947 ******* 4736 ****** 57.09 ****** 187
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
4829
4922
5031
5141
5250
5360
5469
5661
5853
6044
6236
6428
6701
6973
7246
7518
7791
57.12
57.16
57.10
57.37
57.40
57.51
57.44
57.65
57.70
57.69
57.58
57.78
57.82
57 .·s1
57.69
57.83
57.96
202
209
268
279
292
300
311
325
334
356
369
398
422
448
478
500
522
LOSS OF LOAD
F'ROBAB I LITY
D/Y H/Y
****** ****** o.o63 Oe.
0.020 0-.
0.056 o.
0.044 o.
0.063 o.
0.051 o.
0.031 o.
0.073 o.
0.047 o.
0 .,077 0.
0.041 o.
0.069 o.
0.060 o.
0. 06·3 0.
0.053 o.
0.025 o.
0.047 . 0.
0.091 o.
COST IN
Yl::ARL Y
COST
******* 187.4
~'202. 0
209.4
268.0
279.4
2W1.6
3010.4
310 .. 7
3 ':)1-4 II-,') •
. 33-'). 2
355.8
369.2
397\.9
421.7
448.4
477.8
499. tS
522. it\
MILLION $
CUM. F'W
TOTAL
******* 135.4
277,1
419.7
596.9
776.2
957.9
1139.7
1322.1
1507.7
1692.8
1BB4.0
2076.7
2278.3
2485.8
2699.9
2921.5
3146.4
3374.7
YEARLY $/MWH
********************************** INV. FUEL O+M N.I. TOTAL
***** ***** ***** ***** ****** 9.31 25.76 4.50 o. 39.58
12.18 25.10 4.55 o. 41.84
11.95 26.00 4.60 o. 42.55
19.69 28o58 5.00 O. 53.27
19.BS 29.41 5.05 O. 54.34
20.08 30.35 5.11 o. 55.54
19.67 31.26 5.11 o. 56.04
19.27 32.43 5.09 o. 56.80
19.22 33.10 5.17 o. 57;49
18.59 33.41 5~09 o. 57.09
19.18. 34.49 5.20 o. 58.87
18.59 35.36 5.25 o. 59.20
19.18 37.34 5.38 o. 61.90
18.96 38.51 5.47 o. 62.94
18.77 39.94 5.61 o. 64.31
20.74 39.51 5.69 o. 65.94
19.99 40.71 5.75 o. 66.45
19.29 41.93 5.83 o ... 67.05
_I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
GENERAL ELECTRIC COMPANY
oc;F'-5 GENERATION PLANNING F'ROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAILBELT RUN T2
ZER07. -3%
JOB h1HBER 2ML7Z5
****************************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYPE 1 Z 3 4 5 6 7-10
OPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 452 141 67 317 155 SUM= 1190
*********************************************************************** TOTAL
CAF'AB.
YR Y E A R L Y M W A D D I T I 0 N S + TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 lX 200 1373
94 1X 200 1542
95 1495
96 1X 70 1494
97 1X 70 1490
98 1X 70 1505
99 1505
o 1X 70 1531
1 1X 70 1601
2 1X 70 1618
3 o 1X 70 1635
4 lX 200 1835
5 lX 70 1817
6 1X 70 1864
7 1864
8 1X 200 2038
9 2037
10 1X 70 2107
*********************************************************************** *********************************************************************** MW ADD 0 Q 700 0 0 800 0 SUM= 1500
MW RET 0 -46 -335 -141 -61 0 0 SUM= -583
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 13 816 0 6 1117 155 SUM= 2107
PCT TOT O. 0.6· 38.7 o. 0.3 53.0 7.4 SUM=lOO PCT
*****************************************************~***************** AUTO 0 0 700 0 0 800 0 SUM= 1 ~iOO
PCT TOT O. O. 46.7 . O. o. 53.3 O. SUM=100 PCT
I
I
I
I
I
I'
I
•I
I
I
I
I
I
I
I
I
I
I
I
~-·i.:.Hf ... ~t.t .. lL J::j. t.:.t; I f-\.ll; LUi.,lPANY
oc;;p .... ~:i GENEJ;~A T 1 ON F'LANN l:NG PROGl;:AM-SUMMAF~Y OUTPUT
************************************************
ALASI\f.1 HAIL.lH~LT RUN T2
Z r:· r:• (}. •; -·~ .. , .1;;,1\. /tt ..... / ..
JOB NUMBER 2ML7Z5
****************************************
YEAR
**** 1993
1994
1.995
1996
1997
1998
1999
2000
2001
2002
2003
'">"0. ~v q
2005
2006
2007
2008
2009
2010
YR
** 93
94
"95
96
97
98
99
0
1
2
3
4
5
6
7
8
9
10
TOTAL CAPABILITY
(INCLUDING TIES)
YEAR TIME OF
LOAD
***** 947
965
983
1003
1023
1044
1064
1084
1121
1.158
1196
12:~3
1270
1323
1377
1430
1484
1537
F·DOL
PEAK
<MW>
****** 947
965
983
l.003
1023
1044
1064
1084
1121
1158
1196
1234
1270
1323
1377
1430
14.84
1537
END PEAl\
***** ***** 1373 1373
1.542
1495
1494
1490
1505
1505
:l531
1601
:1.61.8
1635
1835
181.7
1864
1864
2038
2037
21.07
TOTAL
1542
1495
1494
1490
1505
1505
1 ~::::s 1
1601.
1618
1635
1835
18l.7
1864
1Sl>4
20~~8
2037
2107
ENEF\GY LOAD
( GWH) . FACTOR
******* ****** 4736 57*09
4829 57.12
4922. 57.16
5031 !:i7 + 10
5l.41 57.37
5250 57.40
53b0 57+ 5l.
5469 57.44
5661
5853
6044
6236
6428
6701
6973
7246
7518
7791
57.65
~;7 + 70
57.69
c·7 ~a ;;:..} + .;,;:}
57.78
57.82
57.81
57. 6'9
57.83
57.86
F'CT.
I~E::S.
**** 45.0
59.8
r.::~ 0 ,....._.
48.9
45.7
44.1
41.4
41.2
42.8
39.7
36.7
48.8
43.1
40.9
35.4
4 ~ e::· .: .. + ... )
37.3
37.1
LOSS OF LOAI:•
PROBABILITY
Il/Y H/Y
****** ****** 0.045 o.
0-,014 o.
0.041 o.
0.060 o.
0.063 o.
0.052 o.
0.071 o.
0.064 o.
0.041 o.
0.057 o.
0.081 0+
o.o21 o.
0.046 o.
0.049 o.
0.100 o.
o~o36 o.
0.066 o.
0.055 o.
COST IN
YEARLY
COST
******* 151.5
167.1
_175.0
220.5
232.9
245.6
256.2
273.0
291.9
310.9
333.2
354.7
378.6
405.0
429.7
458.7
481.9
511.6
MILLION $
CUM. F'W
TOTAL
******* 109.5
226.7
345.8
491.6
641.1
794.1
949.2
1109.5
.1276.0
1448.1
1627.2
1812.3
2004.2
2203.4·
2408.7
2621.4
2838.3
3061.9
TOTAL
COSTS
<MIL.$)
YEARLY $/MWH
********************************** INV. FUEL O+M N.I+ TOTAL
****** ***** ***** ***** ***** ******
1 r.:J·"> ... .:...
3.05 24.61 4.33 o. 31+99
6.04 24.16 4~41 o. 34.61 167
j,75
221
233
246
")1:6 .:..'-I
273
") 9."> .:.. ,:..
311
333
355
379
405
430
459
482
512
5,93 25.17 4.45 o. 35.55
6.41 32.91 4.51 o. 43.83
6.88 33.84 4.58 o. 45.30
7 + 35 34. 78 4. 64 -o o·. 46. 78
7.20 35.88 4.72 o. 47.80
7.67 37.43 4.83 o. 49.92
38 60 4.95 0 51.56 8.01 • •
8.34 39.73 5.05 o. 53.13
. 0 . 5. 16 0 55. 12 8~66 41.3 •
11.27 40.38 5.21 o. 56.87.
~1 4~ 10 ~ .• 29 o. 58.90 11+\,.;l . ..!... ...,
.4 5.40 o. 60.45 11.60 43.4
11.15 44.97 5.50 o. 61.62
13.41 44.34 5.55 o. 63.31
12-.93
13.00
45.55
46.92
5.62 o. 64.10
5.75 o. 65.67
I
I
I
I
I
I
I
1-
I
I
I
I
I
I
I
I
I
I
I
... ..,.. ... ,,.,~" . ~ .... ' .... ~ .... '• ·~
GENERAL ELECTRIC COMPANY
DGP-6 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************ . ..
ALASKA RAILBEL T RUN T3
ZERO% -37.
JOB NUMBER 2ML7Z9
****************************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYPE 1 2 3 4 5 6 7-10
OPTMZING · 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 452' 141 67 317 155 SUM= 1190
***********************************************************************
YR
** 93
94
Y E A R L Y M W A D D I T I 0 N S
******* ******* ******* ******* *****~* ******* ***** 200*
200*
TOTAL
CAPAB.
+ TIES
****** **** 1373
1542
95 1495
96 200* 1624
97 70* 1620
98 70* 1635
99 1635
0 1591
1 70* 1661
2 1608
3 70* 1625
4 70* 1695
5 140* 1747
6 70* 1794
7 200* 1994
8 1968
9 70* 2037
10 2037
*********************************************************************** *********************************************************************** MW ADD 0 800 630 0 0 0 0 SUM= 1430
MW RET 0 -46 -335 -141 -61 0 0 SUM= -583
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 813 746 0 6 · 317 155 SUM= 2037
PCT TOT o. 39.9 36+6 o. 0.~ 15.6 7.6 SUM=lOO PCT
***********************************************************************
' . '
', •-~:::-'..J:'<~•''"-"'"''r~"''-•-'-')'0_·~, ....
'I
I
I
••
I
I
I
I
I
I
I
I
I
I
I
I
·I
I
I
GI:!:NERAL ELECTRIC COMPANY
OGP-5 GENERATION PLA~NING PROGRAM-SUMMARY OUTPUT
************************************************ . .
ALASKA F~AILBEL.T RUN T3
ZERO% -3%
JOB NUMBER 2ML7Z9
****************************************
YEAR
**** 1993
1994
1995
1996
19-97
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
YR
** 93
94
95
96
97
98
99
0
1
2
3
4
5
6
7
a
9
:J. 0
LOAD
***** 947
965
983
1003
1023
1044
1064
1084
1121
1158
:J.l 96
1233
1270
1323
1377
1430
1484
1537
POOL
F'EAK
<MW>
****** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
143C
1484
1537
TOTAL CAPAB!L.ITY
<INGLUDING TIES>
YEAR TIME OF
ENll PEAK
***** ***** 1373 1373
1542
1495
1624
1620
1635
1635
1591
1661
1608
1625
1695
1747
1794
1994
1968
2037
2037
TOTAL
ENERGY
<GWH)
******* 4736
4829
4922
5031
5141
5250
5360
5469
5661
58!:i3
6044
6236
6428
6701
697~
7246
7518
7791
1542
1.495
1624
1620
1635
1635
1 C'9'' <;J .••
'1661
1608
1625
1695
1747
1794
1994
1968
203?
2037
LOA It
FAGTOR
****** 57.09
57.12
~j7 + 16
57.10
57.37
57.40
57.5l.
57.44
57.65
57.70
57.69
57.58
57.78
·a::-7. 8" \:} + ~
57.81
57.69
57.83
57.86
PCT.
RES.
**** 45.0
•59.8
52.0
61.9
58.~4
56.6
53.6
46.8
48.2
38.9
35.9
37.5
37.6
35.6
44.8
37.6
37.3
32.5
TOTAL
COSTS
<MIL.$)
****** 187
230
283
294
306
3:1,5
324
338
346
363
379
406
429
475
494
518
·s39
LOSS OF LOAD
F'ROBAI( I L I 1'Y
II/Y H/Y
****** ****** 0.063 o.
0.027 o •.
o·.o77 o.
0.059 o.
0.084 o.
0.092 o.
0.055 o.
0.059 o.
0.038 o.
o.o62 o.
0.087 o.
0.057 o.
o.o49 o.
0.052 o.
Ot023 0.
0.066 o.
0.051 o.
0.099 o.
COST lN
YEARLY
COST
******* 187.4
222.9
230.2
282.9
293.9
305.9
314.6
324.2
337.8
345.9
362.6
379.0
406.4
429.0
475.0
494.2
518.2
539.0
MILLION $
CUM. PW
TOTAL
******* 135+4
291.a
448.5
635+5
824o2
1014.8
1205.2
1395.6
1588.3
1779.8
1974.7
2172~5
2378.4
2589.4
2816.3
3045.4
3278.7
3514.3
YEARLY $/MWH
********************************** INV. FUEL O+M N.I~ TOTAL
***** ***** ***** ***** ****** 9.31 25.76 4.50 o. 39.58
15.31 26.11 4.74 o. 46.17
15.02 26.96 4.79 o~ 46.77
22.69 28.26 5.28 o. 56.23
22.82 29.04 5.32 o. 57.17
22.96 29.95 5.37 o. 58.28
22.49 30.83 5.37 o. 58.69
22.04 31.94 5.30 o. 59.28
21.89 32.42 5.35 o. 59.67
21.17 32.65 5.27 o. 59.09
21.09 33.58 5.32 o. 59.99
21.02 34.35 5.40 Oi 60.77
21.54 36.17 5.52 o. 63.23
21.22 37.21 5.59 o. 64.02
25.93 36.24 5.96 o. 68.12
24.95 37.29 5.96 o. 68.20
·z4.se 38.30 6.os o. 68.92
23.72 39.36 6.11 o. 69.19
_·:::._-, '
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
II
r-~-
l. -· ~
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
****************.*******************************
ALASKA RAILBEL T RUN Ul
ZERO% -3i!
JOB NUMBER 2MLOX3
****************************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYPE 1 2 ·· 3 4 5 6 7-10
OPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 452 141 67 317 155 SUM= 1190
* * ** * ** * * * * *** ** ** * ** * ** * * * * * *** ** * * *** * *·** * * * * * **** *** ** *** *** * * * * * * *' *. TOTAL
CAPABt
YR Y E A R L Y M W A D D I T I 0 N S + TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 680* 1853
94 1822
95 1774
96 1704
97 1630
98 1575
99 1575
0 lS31
1 1531 ., .... 601* 2079
:i 2026
4 1* "'0"7 ·--5 1939
6 1% 1917
7 .~X 70 1987
8 1X 70 1* 2032
Q 2031
10 lX 70 1f 2102
*********************************************************************** *********************************************************************** MW ADD 0 0 210 0 0 0 1285 SUM= 1495
J
MW RET 0 -46 -335 -141 -61 0 .0 SUM= -583
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 13 326 0 6 317 1440 SUM= 2102
PCT TOT O. 0.6 15.5 0. 0.3 15.1 68.5 SUM=lOO PCT
*********************************************************************** AUTO 0 0 210 0 0 0 0 SUM= 210
PCT TOT o. o. 100.0 o. o. o. O. SUM=l~O PCT
* COMMI TTEit MW
'-:.. .-~-.. ~.·..., ..• ~---. ' . ~ ~
,,., ..• ~-~~~--• ·•··"-""'·~·· , _ __,,_.,,_ •.. ,~ ,_ . ._""'·' .. ·• ,,,,, . .,,. ~--,_ ~ •. ,._.,_,, ,;, •. "'-"'~.>!•'·'-·· "'#'~ "'· _,, ..... _.,l~~-~~·-ret~~~vj
-
f "I
I= .•. GENERAL ELECTRIC COMPANY
I . . OGP~5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
***********************'************************
I ALASKA RAILBELT
ZEROX -3X
JOB NUMBER 2MLOX3
RUN Ul
I ****************************************
I
:=-YEAR-
**** 1 1993
1994
1995
I 1996
. 1997
1998
I 1999
2000
2001
I
I
I
I
2002
2003
2004
2005
2006
2007
2008
2009
2010
YR
LOAil
***** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
-1233
1270
1323
1-377
1430
1484
1537
f'OOL
PEAK
<MW>
TOTAL CAfiABILITY
<INCLUDING TIES)
YEAR TIME OF
ENI• PEAK
***** ***** 1853
1822
1774
1704
1630
1575
1575
1531
1531
2079
2026
2027
1939
1917
1987
2032
2031
2102
TOTAL
ENERGY
<GWH>
1853
1822
1774
1704
1630
1575
1575
-1531
1531
2079
2026
2027
1939
1917
1987
2032
2031
2102
LOA It
FACTOR
I ** 93 ****** 947 ******* 4736 *****:*
57.09
94
I 95
. 96
97
98 1 99
0
I
I
"I
I
1
2
3
4
5
6
7
s
9
10
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1~33
1270
1323
1377
1430
1484
1537
4829
4922
5031
5141
5250
;360
5469
5661
6352
6455
6599
6698
6880
7079
7310
7551
7827
57.12
57.16
57.10
. 57.37
57.41
57.51
57.44
57.65
6.2. 61 .
61.61
60.-92
60.21
59.36
58.69
58.20
58.08
58.14
PCT.
RES.
**** 95.7
88.8
80.5
69.9
C"9'4 t;.l-~
50.8
48.0
41.2
36.6
79t5
69.4
64.4
52.7
44.9
44~3
42.1
36.9
36.8
TOTAL
COSTS
<MIL.$)
****** 213
220
223
235
239
245
251
259
·269
276
295
277
294
282
309
309
330
336
LOSS OF LOAD.
PROBABILIJiY
It/Y H/Y
****** ****** o.ooo o.
OtOOO o.
o.ooo o.
o.ooo o.
o.ooo o.
0.001 O.
0.002 o.
O.OlS O.
0.032 o. o.ooo o.
o~oot o.
o.oo1 o.
0.017 o.
0.068 o.
0.025 o.
0,029 Oc
o.oso o.
. 0. 025 0.
COST IN
YEAF:LY
COST
******* 213.4
219.6
222.7
235.3
239.4
244.7
250,5
259.4
269.0
276.0
295.3
277.0
294.2
282.4
308.9
309.4
330.1
336.3
MILLION $
CUM. f'l.J
TOTAL
******* 154.1
308.2
459t8
615.4
769.0
921o5
1073 •. 1
1225 t 4-
1378.9
'1531. 7
1690-.4
1835.0
1984.1
2123.0
2270.6
2414.0
2562.7
270'9 ... 7
YEARLY $/MWH
********************************** INV.
***** 36.05
34.37
33.72
32a99
32.29
3lo62
30.97
30.35
29.32
38.57
37.95
37.13
3.6.58
35.61
35.15
34.57
33.47
32.81
FUEL
***** 5.29
6.37
6.77
9.05
9.57
10.29
11.02
12.31
13.41
o.
2.83 o.
2.49
0.70
3.62
2.95
5.39
5.33.
O+l1
***** 4.71
4.74
4.75
4.72
4.70
4~71
4.75
4.76
4d30
4.88
4.97
4.86
4.86
4.74
4.86
4 t 8.1
4.86
4.84
NJI.
***** o.
o.
o.
o.
0* o.
o.-
o-.
ot'
o.
o.
o.
o.
o.
o.
o.
o.
o-.
TOTAL
****** 45 .• 05
45.48
45.-24
46.76
46 .. 56
46.62
4·6.74
47-.43
47.52
43.45
45.75
41 .• 99
43~92
.41.05
43.63
42.33
43.72
42.97
:1
I
-I
I-
I
I
-I
I
I
I
I
I
I
I
I
I
I
I
••
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAILBEL T RUN U2
ZERO/. -3/.
JOB NUMBER 2ML4L9
****************************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COHCYC
TYPE 1 2 3 4 5 6
OPTMZING . 0 1993 1993 0 0 1993
PCT TRIM 0 0 0 0 0 0
TYPES
7-10
***
1992 Ht~ 0 59. 452 141 67 317 155 SUH= 1190
***********************************************************************
YR
** 93
94
95
96
97
98
99
0
1
2
TOTAL
CAPAB.
Y E A R L Y M W A D -D I T I 0 N S + TIES
******* ******* ******* ******* ******* ******* ***** ****** **** 680* 1853
l822
1--774
1704
1630
1575
1515
1531
1531
2079
3 2026
4 1* 2027
5 1939
6 1* 1917
7 1X 70 l9S7
B lX 70 1* 2032
9 2031
10 lX 70 1* 2102
**********************-************************************************* *********************************************************************** MW Aicit 0 0 210 0 0 0 12~.S~" __ SUH= 1495
MW RET 0 -46 -335 -141 -61 0 0 SUM= •583
****** ****** ****** ****** ****** ****** ****** **** *********** -2010 0 13 32.6 0 6 317 1440 SUM= 2102
PCT TOT o. 0.6 15.5 o. 0.3 15.1-68.5 SUH=lOO. PCT
-*********************************************************************** AUTO 0 0 210 0 0 0 0. SUM= 210
PCT TOT o. o. 100.0 o. O. o, o, SUM=100 PCT .
* COMMI TTEit ~1W
. . .
. ~·-~,~.w:.:_..i,;. ... ,~.~""'-·~·,."'j,__._.._ :~4
I
I
I
-·
I
-I
I
I
I
I
I
I
I
I
I
-.
I
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
*******************************•****************
ALASKA RAILBEL T RUN U2
ZERO" -3i.
JOB NUMBER 2ML4L9
****************************************
· YEAF~
**** 1993
1994
1995
1 ·~116
19'97
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
YR
** 93
94
95
96
-97
98
99
0
1
2
3
4
5
6
7
8
9·
10
LOA It
*:****
947
Cf6S
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
POOL-
PEAK
cnw>
*****.* 947
965
983
1003
1023
1044.-
1064
1084
1121
1158
1196
1233
·t270
1323
1377
1430
1484
1537
TOTAL CAPABILITY
<INCLUitiNG TIES)
YEAR TIME OF
ENrt PEAK
***** ***** 1853
·1822
1774
1704
1630
1575
1575
1531
1531
2079
2026
2027
1939
1917
1987
?03" ,....., ....
2031
2102
TOTAL
ENERGY
(GWH)
******* 4736
48?9
4922
5031
5141
5250
5360
5469
5661
6352
6455
6599.
6698
68,80
7079
7310
7551
7827
1853
1822
1774
1704
1630
01575
1575
1531
1531
2079
2026
2027
1939
1917
1987
2032
2031
2102
LOA II
F~lCTQR
****** 57.09
57.12
57.16
57~10
57.37
57.41
57.51
57.44
57.65
62.61
61.61
60.92
60 .21.
59.36
58.69
58.20
ss.os
58.14
PCT.
RES.
**** 95.7
88,.8
so.s
69.9
59.4.
50.8
48.0
41.2
36.6
/9.5
69.4
64.4
52.7
44.9
44.3
42.1
36.9
36o8
TOTAL
COSTS
<NIL.$)
****** 280
286
289
302
306
311
317
326
335
374
393
375
392
380
407
407
428
434
LOSS OF LOAit
PROBABiliTY
Ir/Y H/Y
****** ****** o.ooo o.
o.ooo· o.
o.ooo o.
o.ooo o.
o.ooo o.
0.001 o.
0.002 Oe
0.015 Oo
0.032 o.
o.ooo o.
o.oot o.
o.oot o.
0.017 o.
0.068 o.
0.025 o.
0.029 o. o.oso o.
0.025 o.
COST' IN
YEARLY
COST
******* 279.8
286.0
289.1
301.6
305.8
3.1.1.1
316.9
325.8
335.4
374.0
393.3
375.0
392.2
380.4
406.9
407.4
428.1
434.3
MILLION $
CUM. Plsr
TOTAL
i****** 202~1
402.7
599.6
799,0
995. 2.
1189.1
1380.9
1572.2
1763.5
1970.6
2182.0
2377.7
2576.4
2763.6
2957.9
31-46.8
3339.6
3529.4
YEARLY $/Mt•JH
********************************** INV • FUEL O+M N. l • TOTAL.
***** ***** ***** ***** ****** 49.07 5.29 4.71 o. 59.07
48.12 6.37 4 •. 74 o. 59.23
47,21 6.77 4.75 o. 58.73
46.19 9i05 4.72 o. 59.96
45.20 9.57 4.70 o. 59.47
44.26 10.29 4.71 o. 59~26
43.35 11.02 4.75 o. 59.13
42.49 12.31 4.76 o. 59.57
41.05 13.41 4.80 o. 59.25
54.oo o. 4.sa o. ss.aa
53.13 2.83 4.97 o. 60~93
51.98 o. 4.86 o. 56.84
51.20 2.49 4.86 o. 58.55
49tS5 0.70 4,74 0. 55.30
48.99 3+62 4.B6 O. 57.47
47.98 2.95 4.B1 o. 55.73
46.45 5.3~ 4.86 o. 56.70
45.33 5.33 4.84 o. ~5.49
j,'
''""~'; z, ·-·'' .;~'·"'"" , .• .,..,,, .• ~"-"'"'' ·~;;: •. _,._ ~-• ·.,.._,..,.,.,~.-i •.• _..-,,, _ _....,,,.,,.-<-> _.,,_.._,,,, ,•-" •~-... ~.~.YO.·~--"-·,.,., •~:_;"'•-• · > -.-..-.).~.,,:.r.· -~.:;· ·•:.:......·.~-'~'""·•·•••·*'•«-'·"' ··~-. "·'•'~ + :!<"""
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
-I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
********************************~***************
f.lLASKA R1i I LBELT ·RUN Vl
ZEROi! -3/.
JOB NUMBER 2MLI23
*****t**********************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COHCYC TYPES
TYPE = 1 2 3 4~ 5 6 7-10
OP1MZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1 9 9 2 ri W 0 59 4 52 141 6 7 31 7 1 55 S Uti= 11 9 0
**tf*~~*****~t**$***a'*t**~*~***~:************~***~*~********f~***~*****
93
94
95
1"\ I 70
9i'
98
0 .
l. ,.., .. -3
4
5
6
7
8
~ •
TOTAL
CAPAB.
Y E A R L Y M W A D D I T I 0 N S + TIES
******* ******* ******* ******* ******* ******* ***** ****** ****
1X
lX
1" l\
1X
1X
1>:
lX
1X
lX
-·o /-
.., "' l ....,.
70 _,..
~' \..~
~--l\J
70
70
.....
I\}
..... ; ... .. ..
lX 200 1373
1 .. '">0'' A ~, V
1X 20<:0
1412
1435
1688
1705
.17:05
1817
1864
1864
1978
1977
10 1X 70 2047
***~******************************************************************* *********************************************************************** MW hDD 0 0 840 0 0 600 0 SUM= 1440
MW RET 0 -46 -335 -141 -61 0 0 SUM= -583
****** *****~ ****** ****** $***** ****** ****'* **** *********** 2010 0 13 956 0 6 917 155 SUM= 2047.
PC T T 0 T 0 • 0 • 6 4 6 • :=-0 ~ 0 • 3 4 4 • 8 7 • 6 SUM= 1 0 0 PC T
********************************************~************************** t~UTO " 0 0 liA 0 0 0 600 0 SU1·1::: 1440
PCT TOT 0. 0. . 5S • 3 0 • 0 • · 41.7 0 • SUM~l 00 F'CT
)f:-CONMI TTEII NH
I
·.1
I
I
I
I
I
I
I
I
I
I
I
I
I
I
.I
.; .
GENERAt ELECTRIC COMPANY
OGP-5 GENERAT!ON 1 PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
f-1LASKA RAILBEL T
ZEROi; -3%
JOB NUMBER 2MLI23
RUN '1.~.
ki**********~**********$****************
YE?sR
*~:**
1993
1 ~·01: ... ·-'I
"'9C:r::" J. ,.J
1996
1997
19'?8
1999
2000
2001
,. .... ~ --· ,.. .. ~\l\,;•.:._
2003
2004
2005
r')·-·o' ........ 0
2007
2008
2009
2010
YR
=*t
93
94
95
96
97
98
99
0
1
3
4
5
6
7
8
9
10
LOA !I
***** 947
965
983
1·~03
1023
1044
1064
108.-1
1121
1158
1196
1233
1270
1 .... ,... ...
~.::.~
1377
1430
1484
1537
POOL
F'Ef.d\
<MW>
..!.· ... 'II.-..!.·~· . .,.~ 4'1• "'I 4J If• "J ·~
947
965
983
.1003
1023
1 0-'i 4
1064
1C•B4
1121
1158
1196
1233
1270
1323
1377
1430
1494
1 . .:;37 ·'-'· ~
TOTAL Ct!1F'ABILITY
<INCLUDING TIES)
YEAR TINE OF
ENII PEAK
****~t ***** 1373 1373
1412 1412
1134
1430
1445
1445
1471
1541
1705 .. 7 ~ ..... s::-J. ~. ... '-1
1817
1864
1864
1978
1977
2047
TOT~ll
ENERGY
<GWH)
i ~'**'*** 4736
4829
4 Q?? ..... _
5.031
5141
5250
5360
5469
5661
6044
6236
6428
6701
6973
7216
751S
7791
;
1435
1434
1430
1445
1.445
1471
1541 . ~so 1-:; . ·~
1705
1705
1817
1864
1864
1978
1977
2047
LOA II
FACT OF~
*:i'**** 57.09
'C'"-J 1'"' .;; . . ..::.
57.16
57.10
57.37
57c-40
57.51
57.44
57.65
57o7Ct
57.69
57.58
57.78
C!' •'J n'"' ~' ( • c.:
57.81
57..69 r:·-s-;;J/ + ~
.!:": ..... 8 . ...!/. ~
F'CT.
RES.
**** 45.0
46.3
45.9
42 t ~·
39.8
38.4
35.8
351)7
37.5
45.8
42.6
38~3
43.1
40.9
35 • .4
38.3
33.2
33.2
TOTAL
COSTS
<MIL.$)
***:4'**:
148
154
161
169
17t.
184
188
1"99
211
224
237
245
26.3
319
335
LOSS OF LOAit
PROBABILITY
Il/Y H/Y
****** ***=*** 0.045 o.
0.033 o.
o .• o32 o.
0.049 o.
0.053 o.
0.062 o.
0.086 o.
0.078 o.
0.049 o.
0.028 o.
0.040 0(
0.073 o.
0.061 o.
0. 0'49 0 •
0.100 o.
0.047 o.
0.073 o.
0.061 o.
COST IN
YEARLY
COST
*****:~*-
147.6
154.2
161.0
169.8
175.6
183.5
18.8 •. 2
199.2
210.9
.,., A • 0 ......... ·•
2.36.6
244.5
263.4
277+3
288.5
308.0
318.7
334.9
MILL.!ON $
CUH. PW
TOTAL
*~:*****
106.7
214.8
324.4
436.0
548.7
663.1
........ , C)
.//'Ot7
893.9
1014c-2
1138.2
1:!65.4
1393.0
1526.5
1662.?
1900.6
1943.4
2086.9
2233.3
-YEARLY $/rfWH
********************************** !NV. FUEL OfM N.I. TOTAL
***** ***** '**** ***** ****** 3.05 23.79 4t33 Oc 31.17
3.60 23.88 4.44 o. 31.93
4.15 24.00 4.56 o. 32.71
4t67 24~20 4.67 o. 33.55
5.18 -24.24 4~74 Ot 34~16
5~69 24.42 4.85 o. 34~95
5.57 24.58 4.96 o. 35.10
6.07 25.21 5.14 o. 36)42
6.46 25.48 5.31 o. 37,26
9.20 23.95 5.13 o. 39.27
9.50 24.41 5.24 Oe 39.15
9.20 24.67 5.34 o. 39.2l
11i78 23.89 s~31 Ot 40.98
11.86 24.12 5.40 o, 11.38
11.40 24.48
12.05 24,7t1'
11+61 25~01
11". 72· 25 t 33
5,50
51-68
5t77
5 .. \~4-
Oc
o.
o.
o.
41.37
12. ~50.
4 ?~-:c ..._,...,'-fl~
1·2;i·9S~
I
I
:I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA-RAILBELT RUN V2
ZERO/. -37.
JOB NUMBER 2ML3U3
*******************************~********
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
TYPE 1 2 3 4 5 6 7-10
DPTMZING 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 -452 141 67 317 155 SUM= 1190
*********************************************************************** TOTAL
CAPAB.
YR YEARLY M w-ADD IT I 0 N S +TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 680* 1853
94 1B22
95 1774
96 1704
9? 1630
98 1575
99 1575
0 1'531
1 1531
2 601* 2079
3 2026
4 1* 2027
5 1939
6 1* 1917
7 lX 70 19.87
8 1 X 7 0 · 1 * 2032
9 2931
10 lX 70 1* 2102
****************************************************************·******* *********************************************************************** MW ADD 0 .. 0 210 0 0 0 1285 SUM= 1495
MW RET 0 -46 -335 -141 -61 0 0 SUM~ -583
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 13 326 0 6 317 1440 SUK= 2102
PCT TOT o. 0.6 15.5 0. 0.3 15.1 68o5 SUM=100 PCT
**************'******************************************************** .~ AUTO 0 0 210 0 0 0 0 SUM= 210
PCT TOT o. o. ' 100.0 o. (). o. O. SUM=100 PCT
* · COMMI TTEit MtaJ
I
:1,
I
I
I
I
I
I
I
I
I
·I
I
••
I
I
I
I
tf._,
••
G~NERAL ~LECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGR~M-SUMMARY OUTPUT
************************************************ . . . .
ALASKA RAILBELT RUN V2
ZERO/. -3/.
JOB NUMBER 2ML3U3
****-******************************~*****
TOTAL CAPABILITY
(!NCLUI•ING TIES> LOSS OF LOAD COST IN MILLION $
YEAR TIME OF
YEAR LOAD END PEAK
**** ***** ***** ***** 1993 947 1853 1853
1994 965 1822 1822
1995 983 1774 1774
1996 1003 1704 1704
1997 1023 1630 1630
1998· 1044 1575 15:75
1999 1064 1575 1575
2000 1084 1531 1531
2001 1121 1531 1531
2002 1158 2079 2079
2003 1196 2026 2026
2004 1233 2027 2027
2005 1270 1939 1939
2006 1323 1917 1917
2007 1377 1987 1987
2008 1430 2032 2032
2009 1484 2031 2031
2010 1537 2102 2102
POOL TOTAL
F'EAK ENERGY LOA It
YF: <MW> <GWH> FACTOR
** ****** ******* ****** 93 947 4736 57.09
94 965 4829 57.12
95 983 4922 57•16
96 1003 5031 57.10
97 1023 5141 57.37
98 1044 5250 57941
99 1064 5360 57.51
0 1084 5469 57.44
1 1121 5661 57.65
2 1158 6352 62.61
3 1196 6455 61.61
4 1233 6599 60.92 0
s 1270· 6698 60.21
6 1323. 6'880 59 .. 36
7 1377 707.9 58.69 s 1430 731()·:: 58.20
9 1484 7551 ·ss.os
10 1537 7827 58.14
PCT.
RES,
**** 95.7
as.s
so is
69.9
59.4
so.s
·48.0
41.2
36.6
79.5
69.4
.64.4
52.7
449 9
44.3
42.1
36.9
36.8
TOTAL
COSTS
<MIL,$)
****** 2.45
250
252
254
257
259
263
267
273
325
337
326
336
~29
346
3"48
360
365
PROBABILITY YEARLY CUM. PW
D/Y H/Y COST TOTAL
****** ****** ******* ******* o.ooo o. 245~2 177.1
o.ooo -o. 250.0 352.5
o.ooo o. 252.4 524 .• 3
o.ooo o. 254.4 692.5
o.ooo o. 256.5 857.2
0.001 o. 259.4 1018.8
0.002 o. 262.5 1177.7
0.015 o. 267.0 1331.5
0.032 o. 272.9 1490'.1
o.ooo o. 3.2.5.0 1670.1
0.001 o. 336.9 1851.1
0.001 o. 326.0 2021.3
o.o11 o. 336.0 2191.5
0.068 o. 329.3 2353.5
0.025 o~ 346.2 2518.9
0.029 o. 348.4 2680.4
o.oso o. 359.8 . 2842-.4
0 .. 025 o. , 365.1 3001.9
YEARLY $/HWH
********************************** INV, FUEL
***** ***** 42.05 5.02
41.24 5.81
40.46 6.07
39.59 6.26
38.74 6.46
37 •. 9,4, .. 6.77
37.16 7.07
36.42 7.64
35.18 8.23
46.28 o.
45.54 1.67
44·.55 o.
4.3. 89 1.41
42.73 \ 0.39
42.07 ,1 .• 97
41.2:7 1.58
J9t96 2.83
39.07 2.74
OfM
***** 4.69
4.72
4.74
4.72
4.70"
4.71
4.75
. 4.76
4.80
4.88
4.97
4.86
4.86
4.7-4
4.86
4.81
4.86
4.·84
. .
N.I.
~**** o.
o.
o.
o.
o.
o. o.
o.
o.
o.
o.
o. o.
o.
o.
oif
o.
o.
TO.TAL
****** 51.77
5!.78
51.27
50.57
49.90
49.42
48.98
49.82
48.21
51.17
52.18
49.41
50.16
47.86
48.90
47.66
. 47 .65~
46.64
:.;;:~-::;.~~~:::'-~ -...... ·~.: ~.: .. ,.,. ,, , .. Gi~ ,; ; , ·..;::.. .... ,~_,. __ !.~~,, ... ,.,,_,..._,·_.,.~~-..,.~-~--~;.. .. ,.,. • ..,·~·-... ~_._.._,.,_,.--~,.,. ... ~""'''~:: .. _. ........ ~_....._ '.......:... •.. -.:··--'-~-~...:"··-~·,·-· .. -~ ... -· .... ___ ..___,~--.h.>-~--_:_,~~ ~· :--,~---~-~~· .. -.. . r~-~~~~~~~~~.
'I . . . ''-
I
I
I
I
I
I
I
I
I
I
I
"I
I
I
I
I
I
I.
G£NERAL ELECTRIC COMPANY
OGP-5 GENERnTION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
RUN Wl
JGB NUMBER 2MLI15
f*'t*******i****************************
GE~ERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
-vp·-1 ~ 3 4 ~ L II'£: .:. ;.r. ~ Q 7-10
Q~TMZING 0 1993 1993 0 0 1993 *** PCT TRIM 0 0 0 0 0 0
1992 M~ 0 59 452 141 67 317 155 SUM= 1190
~~-~~~~~~~~~~~~~·~*~*~-·~W~~.·*~~·~·~*·~.~·~-···*·~~·~~~·~~~~~··~~·. ·····~·-~¢·*·~ "'1" ~· ~ r1· tTo.. 'fl II'~ -If'. ¥1~ -'~ ~ 41• _.T• ll' ~1• II\ 'l-~ ~ .IJ''i · .,-~ 'l• If It• 1\ .:.tl• If. 'I"· If-:''' 41 .. T ')• 10 fl• ·!]-. ~ .. •i Jf'-~ #J"'o. i'f"o II" /i .. 7. 'a" .. Jf. ~ ~"f· ..... 'f• ~. ~ ~ ~ ~ .ef.' Jft. "'~\ ·l'f' If'.. ~J'... ~ ~ ~--._1\ ~ ~ ~-l!\ 'f~
Yr:
** 93
94
,.. •• ..
Y E A R L Y M W A D D I T I 0 N S
******* ******* ******* ******* **~**** ******* ***** 200*
1x :~oo
1 X .., :\ , ..
I ._,fV V
lX
1X
1X '7" •• "'
1X 70
TOTAL
C.APAB.
+ T!ES
****** **** 1373
1624
1.~2\}
'1..:..3·r., .,......,.. -.:
163~
15'9!.
1661
16.(}8
1 "'*"":::' -... ...... _,_
6 1X 70 1S54
7 lX 70 1924
8 1X 70 1~68
9 1X 70 2037
1~ 2037
****E****************************************************************** ****t****~************f*********************************************'** MW ADD 0 800 630 0 0 0 0 SUM= 1430
MW RET 0 -46 -335 -141 -61 0 0 SUH= ~583
****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 813 746 0 6 317 155 SUM= 2037
PCT TOT O. 39,9 36.6 o. 0.3 15.6 7,6 SUM~lOO PCT
*f*t*f**********************************************t****************** AUTO . 0 400 630 0 0 0 0 SUM= .1030
PCT TOT O. 38.8 .61.2 o. o. o. O. SUM: .. lOO F'GT
I
I
I
I
I
I
I
I
I
I
I
I
I
1--
I
I
~·
I
I
I
"-"'·' .. ,.-.,.,..,· ... .,.
GENERAL ELECTRIC COMPANY
OGP-5 GENERATIDN PLANNING PROGRAM~SUMMARY OUTPUT
************************************************
ALASI\A F:AILEEL T RUN Wl
ZEROi~ -3/.
JOB NUMBER 2MLI15
~*****************~*********************
YEAR
~c;:* *-
1993
1994
1995
199e
1997
1998
1999
2000
2001
2002
2003
2004
2005
'2006
'1:"0~ .:.V 1
2002
2009
2010
YF:
** 93
94
95
'96
97
98
9~9
0
1
2
3
4
5
6 -t
8
9
10
LOA!l
***** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1270
1
_,,....,
~.:.~
1 .., .., .....
~ J /
1430
1484
153_7
~·ooL
PEAt\
<MW>
****** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
13/7
1430
1484
1537
TOTAL CAPABILITY
(INCLU!IING TIES)
YEAF: Tit·iE OF
ENII PEAK
***:>!-::+: ***** 1373
1.542
1495
1624
1620
1635
16'35
1 ~91.
1661
1608
1625
1695
1807
1854
1'124
1968
2.037
2C•37
TOTAL
ENEI':GY
<GWH>
*****·:r.t
4736
1 77-WI~
1542
1495
1624
1620
1635
1635
1591
1661
1608
1625
1695
1807
1854
1924
1968
2037
~0 ... 7 ·-~
LOf-rii
FACTOR
****** 57.09
57.12
57.16
57.10
57.37
57.40
57.51
57.44
57·.65
571170
57.69
C:'7 1::1"'1 ..... r t ·wO
57.78
57.82
57ctB1
1829
4922
5031
5141
5250
5360
5469
5661
SS53
6044
6236
6428
6701
6973
7246
7518
7791
. 5_1:.>69
~ 57 .S3
57 ·• 86
F'CT.
RES.
****: 4 ~:;. 0
59') 8
52.0
58.4
56.6
53t,6
46.:8
48.2
38.9
35.9
37. ~i
40.2
39.7
37.6
37.3
32o:i
TOTAL
COSTS
<MIL.$)
****:i'*
238
251
263
'305
322
340
354
367
386
401
424
447
,487
515
544
577
611-
642
LOSS Of LOA!t
F·F!OBf'IB ILI TY
ti/Y H/Y
~=*****: ***·*'~·* 0.063 o.
0.027 Ct ..
0.077 Ot
0.039 o.
0.084 o.
0.092 o.
0.055 o.
0.059 o.
o.o3B o~
0,062 0(
0.087 o,
0.057 o.
0.062 o.
0.06'4 o.
o.os7 o. o.o66 o.
0.051 o.
0.099 o.
COST IN
YEARLY
COST
**'*~: **t 237.8
250.6
263io4
305.4
321.9
340 f-4
353.8
366 ~·s
386.4
400.5
423.9
.ft.ci6 ~ 6
486.7
514.9
543.6
576.9
610.8
64.2.4
~-c.~~~~ ..... · .•. ~·~".·· •.. · '~· ' -. .
•• ' -I• •
~ . . -.
11ILLION $
CUrt • Pt~
TOTAL
*~:~:*:~**
171.B
3-17.5
.~ ..... 0 ~..;!0+7
7::!8.8
935t4
.1147.5
1361.6
1 ·~--(\ ;;Jlit\.•
1-9-.. --'-j. ~ l '~.
2019.2
2247~1
:2tlBOv1
2726.7
2980.0
3239 ~ 6
3507.1
--a~ ·; ~.1 .........
6.8.26
6S.43
70.l4j~
71.61
75.71
77. 96..
79.62
81.24
j
;'l
l
i
I
I
I
I
I
I
I
I
I
I
I
I
I
I·
I
I
I
I
I
I
GENERAl ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAILBELT RUN W2
ZERO?. -3/.
JOB NUMBER 2ML4M1
***********'****************************
GENERATION SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COHCYC TYPES
TYPE 1 2 3 4 5 6 7-10
OPTMZING · 0 1993 1993 0 0 1993 ***
PCT TRIM 0 0 0 0 0 0
1992 MW 0 59 452 141 67 317 155 SUM= 1190
****************.****************************************************** TOTAL
CAPAB.
YR Y E A R L Y M W A D D I T I 0 N S + TIES
** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 680* 1853
94 1822
95
96
97
98
99
0
1
2
3
4
5
601*
1*
17'74
1704
1630
1575
1575
1531
1::>31
20.79
2:026
2027
1939
6 1* 1917
7 !X 70 1987
8 1X 70 1* 2032
9 2031
10 lX 70 1* 2102
*********************************************************************** *********************************************************************** HW ADD 0 0 210 0 0 0 1285 SUK= 1495
MW RET 0 -46 -335 -141 -61 0 0 SUM= -583
****** ****** ****** . ****** ****** ****** ****** **** *********** 2010 0 13 326 0 6 317 1440 SUM= 2102
PCT TOT o. 0.6 15.5 o. 0.3 15~1 68.5 SUH=100 PCT
*********************************************************************** AUTO 0 0 210 0 . 0 · . 0 0 SUM= 210
f'CT TOT 0 • 0. l 00 • 0 0 • 0. 0 • 0 + SUM=lOO f'CT
* COMMlTTED JiW
I
I
/I
"I
I II
I
I
I
I
I
I
I
I
I
I
I
I
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM~SUMMARY OUTPUT
************************************************
ALASKA RAILBEl. T RUN W2
ZEROX -37.
JOB NUMBER 2ML4M1
****************************************
YEAR
**** 1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
YR
** 93
94
95
96
97
98
99
0
1
2
3
4
5
6
7
8.
9
10
LOAit
*:****
947
965
983
1003
1023
1044
1064
1084
11.21
1158
1196
1233
1270
1323
1377
1430
1484
1537
f'OOL
PEAK
<MW)
****** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
·1484
1537
TOTAL CAPABILITY
<INCLUIIING TIES>
YEAR TIME OF
ENit PEAK
***** ***** 1853
1822
i774
1704
1630
1575
1575
1531
1531
2079
2026
2027
1939
1917
1987
2032
2031
2102
TOTAL
ENERGY
< GI~H >
******* 4736
4829
4922
5031
.5141
5250
5360
5469
5661
6352
6455
6599
6698
6880
7079
7310
. 7551
7827
1853
1822
1774
1704
1630
1575
1575
"1531
1531
2079
2026
2027
1939
1917
1987
2032
2031
2102
LOA I!
FACTOR
****** 57.09
57 t 12
57.16
57.10
57.37
57.41
57.51
57.44
57.65
62.61
61.61
60.92
60.21
59.36
58.69
58.20
58.08
58.14
PCT.
RES.
**** 95.7
ss.s
80.5
69.9
'59. 4
so .a·
48.0
41.2
36.6
79.5
69.4
64.4
52.7
44.9
44.3
42.1
36.9
36.8
TOTAL
COSTS
<MIL.$)
****** 260
270
276
282
289
297
307
320
334
325
352
326
35.0
333
368
367
396
403
LOSS OF LOAI•
PROBABILITY
II/Y H/Y
****** ****** o.ooo o.
o.ooo o.
o.ooo o.
0.000 Ot
o.ooo o.
o.oo1 o.
0.002 o.
0.015 o.
0.032 o.
0.000 Oc-
0.001 o.
o.oo1 <5.
0.017 o.
0.068 o.
0.025 o.
0.029 o. o.oso o.
0.025 o.
COST IN
YEARLY
COST
******* ~60.0
269.8
.275.9
282.0
288.8
297.5
307.0
319.9
333.9
325.0
352.1
326.0
350.0
333.4
368.4
367.3
396.0
402.7
MILLION $
CUM. F'W
TOTAL
******* 187.8
377.0
564.9
751.3
936.7
1122.0
1307.8
1495.7
1686.1
1866.0
2055.3
2225.4
2402.8
2566.8
2742.7
2913.0
3091.3
326'7. 3
YEARLY $/MWH
******************************~*** INV. FUEL O+M N.I. TOTAL
***** ***** ***** ***** ****** 42 ~OS 8 • 15 4. 69 0 • 54.89
41.24 9.90 4.72 o. 55.87
40.46 10.85 4o74 O. 56.05
39.59 11.75 4.71 o. '56.05
38.74 12.73 4.70 o. 56.17
37.94 14.01 4.71 o. 56.66
37.16 15.36 4.75 0& 57.27
36.42 17.32 4.76 o. 5&.49
35.18 19.oo 4.ao o. sa.9a
46.28 o. 4.88 o. 51.17
45.54 4.03 4.97 o. 54.54
44,55 o. 4.86 o. 49.41
43.89 3.51 4.86 o. 52.26
42.7'3 0.99 4.74 o. 48.46
42.07 5.11 4.86 o. 52.04
41 • 27 4 • 17 4 • Bl 0 < 50. 25
39.96 7.63 4.86 o. 52,44
39.07 7.54 4.8~ o. 51.44
I~
I
GENERAL ELECTRIC CDMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
ALASKA RAlLBELT
ZER01. -3/.:
JOB NUMBER 2MLCJ7
RUN Xl
I ****************************************-
GENERAtiON SYSTEM
THERMAL HYDRO PSH ES-2 ES-3 ·I TYPE 1-6 7 8 9 10
OPTMZING *** 0 0 0
PCT TRIM 0 0 0
I 1992 MW 1035 155 0 0 0 SUM= 1190
*********************************************************************** TOTAL
I CAPAB. LOAD LDLP
·-YR YEARLY M W ADD I T I 0 N S +TIES MW D/Y ** ****** ****** ****** ****** ****** ****** ***** ******* 93 200 1373 947 0.0635 I 94 200 1542 965 0.0274
95 1495 983 0.0772
96 200 1624 1oo3 o.ossa
I 97 70 1620 1023 0.0838
98 70 1635 1044 0.0920
99 ~ 1635 1064 Ot0554
0 1591 1084 0.0591
1 70 1661 1121 0.0379
2 1608 1159 0.0624
3 70 1625 1196 0.0868
4 70 1695 1233 0.0567
5 140 1747 1270 °0.0488
6 200 1924 1323 0.0267
7 1924 -1377 0.0569
8 70 1968 1430 0.0656
9 70 2037 1484 0.0510
I
I
I
10 2037 1537 0.0994 I *********************************************************************** *********************************************************************** MW ADD 1430 0 0 0 0 SUM= 1430
I HW RET -583 0 0 0 0 SUM= -583
****** ****** ****** ****** ****** ****** ************
I
I
I
·I·
I
2010 1882 155 0 0 0 SUM= 2037
PCT TOT 92.4 7.6 0. 0. o. SUM= 100 PCT
*********************************************************************** AUTO 1030 0 0 0 SUM= 1030
PCT TOT 100.0 0. 0. O. SUM= 100 PCT
* COMMI TTE!t Ml~,l
--------------------~~~~----~~--------.................. ..
GE~ERAL ELECTRIC COMPANY
I
I OGP-5 GENERATION PLANNING PWDGl~H-SUMMARY OUTPUT
************************************************ 1 ~~As~A RA~LEEL r RUN Xl
. LEROY. -3%
JOB NUMI~EH 2MLCJ7
I'******************************~·•••••••
TOTAL CAPABILITY
I YEAR
< INCLU!tiNG TIES> LOSS OF LQA[I COST IN
YEAR TIME OF F'CT • PROBABILITY YEARLY
LOAD EN.Ir PEAK RES. II/Y H/Y COST
**** ***** ***** ***** **** ****** ****** ******* 11993 947 1373 1373 45.0 0.063 o. 174.1
1994 965 1542 154;2 59.8 0.027 o. 196.7
1995 983 1495 1495 52.0 0.077 o. 203.5
11996 1003 1624 1624 61.9 0.059 o. 255.0
1997 1023 1620 1620 58t4 0.084 o. 265.0
1998 1044 1635 1635 56.6 0.092 o. 276.0
1999 1064 1635 1635 53.6 0.055 o. 282.2
.12000 1084 1591 1591 46.8 0.059 o. 288.6
?001 1121 1661 1661 48.2 0.038 o. 301.1
2002 1158 1608 1608 38.9 0.062 o. 309.7
12003 1196 1625 1625 35.9 0.087 o. 325.5
2004 1233 1695 1695 37.5 0•057 o. 340.8
2Q05 1270 1747 1747 37.6 0.049 o. 364.2 I 2006 1323 1.924 1924 45.4 0.027 o. 397.3
. 2007 1377 1924 1924 39.7 0.057 o. 412.6
2008 1430 1968 1968 37.6 0 • Oc.S6 o. 434.6
2009 1484 2037 2037 37.3 0.051 o. 457.0 1 2010 153.7 2037 2037 32.5 0+099 o. 476.9
POOL TOTAL TOTAL YEARLY $/MWH
MILLION $
CUM. F'W
TOTAL
******* 125.8
263.8
402.3
570.9
741.0
913~0
1083.7
1253.3
14.25.0
1596~5
1771.5
. 1949.3
2133 .. 9
2329.3
252&.3
2727~8
2933--.6
3142~()
I PEAK ENERGY LOAil COSTS ********************************** YR <MW> <GWH>
I
I
••
I
I
I
I
** 93
94
95
96
97
98
99
0
l
2
3
4
5
6
7
.8
9
10
****** ******* 947 4736
965 4829
983 4922
1003 5031
102.3 5141
1044 5250
1064. 536@
1084 5469
1121 5661
1158 5853
1196 6044
1233 6236
1270 6428
1323 6701
1377 6973
14.30 7246
1484 7518
1537 7791
•·
FACTOR <MIL.$)
****** ******. 57.09 174
57.12 197
57.16 203
57.10 255
57.37 265
57.40 276
57.51 282
57.44 289
57.65 301
57.70 310
57.69 326
57.58 341
57.78 . 364
57.82 397
57.81 413
57.69 435
57.83 457
57.86 477
,·-:>
: ' ''"· • -~···· -~ --· """~ '"' .,., •••• ' ............. ~. '.,. .>,-~ ""
INV. FUEL OtM N.I. TOTAL ***** ***** ***** ***** ****** 8.90 23.36 4.51 o. 36.76
14.60 21.39 4.75 o. 40.74
14.32 22.22 4.79 o. 41.34
21.52 23.88 5.28 o. so .• 68
21.63 24.59 5.32 o. 51.54
21.75 25.45 ' 5.38 o. 52.58
21.30 25.97 5.38 o. 5.2 .. 65
20.88 26.60 5.29 o. 52.78
20.72 27.14 5.34 o. 53,.19
20.04 27.61 5.27 o. 52.92
19.93 28.60 5.32 o. 53.86
19.84 29.40 5.40 o. 54.64
20.27 30.89 5.50 o. 56.66
24.44 28.93 5.92 o. 59.29
23~48 29.77 5.91 o. 59.17
23.07 30.93 5.97 o. 59.97
22.70 32.03 6.05 o. 60.78
21.90 33.20 6.11 o. 61.21
'~]
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
GENERAL ELECTRIC COHP~NY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
RUN X2
1~UM.BER 2MLCJ9
************************************
.:~ATI ON SYSTEM
NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES
1 2 3 4 5 6 7-10
.ZING 0 1993 1993. 0 0 1993 . ***
TRIM 0 0 0 0 0 0
! MW. 0 59 452 141 67 317 155 SUM= 1190
•******************************************************************* TOTAL
CAPAB.
Y E A R L Y M W A D D I T I 0 N S + TIES
******* ******* ******* ******* ******* ******* ***** ****** ****
lX 70
1X 70
680* 1953
1822
1774
1704
1630
1575
1575
1531
1531
601* 2079
262.6
1* 2027
!939
1# 1917.
1987
1* 2i032
2031
1X 70 ·1 * 2102
t******************************************************************* '******************************************************************* ADD 0 0 210 0 0 0 1285 SUM= 1495
RET 0 -46 -335 -141 -61 0 0 SUM= -583
•*** ****** ****** ****** ****** ****** ****** **** **•******** . 0 0 13 3 2 6 0 6 . 31 7 14 4 0 SUM= 21 0 2
: TOT O. 0.6 15.5 O. 0.3 15.1 68.5 SUH=100 PCT
!'******************************************************************* iO . 0 0 210 0 0 0 0 SUM= 210
TOT O. O. 100.0 O. o. o. o. SUH=lOO PCT
: OMMI TTED M~J
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
GENERAL ELECTRIC COMPANY
OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT
************************************************
tiLASI\A RAlLBEL T RUN X2
ZEROi. -3i!.
JOB NUMBER 2MLCJ9
****************************************
YEAR
**** 1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
YR
** 93
94
95
96
97
98
99
0
1
2
3
4
5
6
7
8
9
10
LOAD
***** 947
965
983
1003
1023'
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
. 1430
1484
1537
POOL
PEAK
<MW>
****** 947
965
983
1003
1023
1044
1064
1084
1121
1158
1196
1233
1270
1323
1377
1430
1484
1537
TOT ~1L CAPABILITY
<I NCLUiti NG TIES)
YEAR TIME OF
ENit PEAl\
***** ***** 1853
1822
1774
1704
1630
1575
1575
1531
1531
2079
2026
2027
1939
1917
1987
2032
2031
2102
TOTAL
ENERGY
(GWH)
******* 4736
4829
4922
5031
5141
5250
5360
5469
5661
6352
6455
6599
6698
6880
7079
7310
7551
7827
1853
1822
1774
1704
1630
1575
1575
1531
1531
2079
~026
2027
1939
1917
1987
2032
2031
2102
LOA It
PACT OR
****** 57.09
57.12
57.16
57.10
57.37
57.41
57.51
57.44
57.65
62.61
61.61
60.92
60.21
59.36
58.69
58.20 ss.oa
58.14
PCT.
RES.
**** 95.7
88.8
so.s
69.9
59.4
50.8
48.0
41t2
36,6
79.5
69~4
64.4
52.7
44.9
44.3
42.1
36.9
36.8
TOTAL
COSTS
<MIL.$)
******
0
238
244
247
260
264
269
275
284
293
307
327
308
326
314
340
340
360
366
LOSS OF LOAit
PROBABILITY
D/Y H/Y
****** ****** o.ooo o.
o.ooo o.
o.ooo o.
o.ooo o.
o.ooo o.
0.001 o.
0.002 o.
0.015 o.
0.032 o.
o.ooo o.
0.001 o.
0.001 o.
0.017 o.
0.068 o.
0.025 o.
0.029 o.
o.050 o.
0.025 o.
COST IN
YEARLY
COST
******* 237.7
244.0
247.1
259.6
263.7
269.1
274.9
283.7
293.4
307.3
326.6
308.3
325.5
313.7
339.7
339.8
360.5
366.1
YEARLY $/MWH
MILLION $
CUM. F'W
· TOTAL
******* 171.7
342.9
511.1
682.8
852.0
1019.7
1186.1
1352.7
1520.0
1690.2
1865.8
2026.7
2191.6
2345.9
2508.2
:2665.7
2826.0
2988.0
********************************** INV. FUEL O+M N.I. TOTAL
***** ***** ***** ***** ****** 40.19 5.29 4.71 o. 50.20
39.42 6.37 4.74 o. 50.53
3Bt67 6.77 4.75 o.. ·so.19
37t84 9.05 4.72 o. 51.61
37.03 9.57 4.70 o. 51.30
36.26 10.29 4.71 o~ 51.26
35.51 11.02 4.75 o. 51.29
34.81 12.31 4.76 o. 51.88
33~63 13.41 4.80 o. 51.83
43.50 o. 4.88 o. 48.38
42.80 2.83 4.97 o. 50.60
41.87 o. 4.86 o~ 46,73
41.25 2.49 4.86 o. 48.59
40.16 0.70 4.74 o. 45.60
39.50 3.62 4.86 o. 47.99
38.72 2~95 4.81 o. 46.48
37.49 5.39 4.86 o. 47.74
36.61 5.33 4.84 o. 46.78