HomeMy WebLinkAboutAPA1373I
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SUSITNA HYDROELECTRIC PROJECT
Prepared by:
FERC LICENSE APPLICATION
EXHIBIT D
FIRST DRAFT
SEPTEMBER 24, 1982
.____---.:__ALASKA POWER AUTHORITY_-----.~
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EXHIBIT D -PROJECT COSTS AND FI:i.4NCING
TABLE OF CONTENTS
List of Tables
List of .Figures
1 -ESTIMATES OF COST
1.1 -Construction Costs
(a) Code of Accounts
(b) Approach to Cost Estimating
(c) Cost Data
(d) Seasonal Influences on Productivity
(e) Construction Methods
{f) Quantity Takeoffs
(g) Indirect Construction Costs
1.2 -Mitigation Costs
1.3 -Engineering and Administration Costs
{a) Engineering and Project Management Costs
(b) Construction Management Costs
(c) Procurement Costs ·
{d) Owners Costs
1. 4 -Allowance for Funds Used During Construct ion
1.5-Escalation
~ 1.6 -Cash Flow and Manpower Loading Requirements 1.7 -Contingency
1.8 -Previously Constructed Project Facilities
2 -ESTIMATED ANNUAL PROJECT COSTS
3 -MARKET VALUE OF PROJECT POWER
3.1 -The Railbelt Power System
3.2 -Regional Electric Power Demand and Supply
3.3 -i'1arket and Price for Watana Output in 1994
3. 4 -Narket Price for vJatana Output 1995-2001
3.5 -Market and Price for ~Jatana and Devil Canyon
Output in 2003
3. 6 -Potential Impact of State Appropriations
3.7 -Conclusions
4 -EVALUATION OF ALTERNATIVE ENERGY PLANS
4.1 -General
4.2 -Existing System Characteristics
(a) System Description
{b) Retirement Schedule
{c) Schedule of Additions
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EXHIBIT D -TABLE OF CONTENTS (Continued)
4.3 -Fairbanks -Anchorage-Intertie
4.4 -Hydroelectric Alternatives
4.5 -Thermal Options
(a) Assessment of Thermal Alternatives
{b) Coal..,fired Steam
(c) Combined Cycle
(d) Gas-Turbine <
(e) Diesel Power Generation
(f) Plan Formulation and Evaluation
4.6 -Without Susitna Plan
(a) System as of January 1993
(b) System Additions
(c) Sjstem as of 2010
4.7 -Economic Evaluation
(a) Economic Principles and Parameters
(b) Analysis of Net Economic Benefits
4.8 -Probability Assessment and Risk Ana.lysis
(a) Multivariate Sensitivity Analysis
(b) Comparison of Long-Term Costs .
{c) Net Benefit Comparison
(d) Sensitivity of Results to Probabilities
(e) Approach to Risk Analysis
(f) Elements of the Risk Analysis
(g) Risk Assessments
(h) Interpretation of Results
(i) Conclusions
4.9 -Battelle Railbelt Alternatives Study
{a) Alternatives Evaluation
{b) Energy Plans
5 -CONSEQUENCES OF LICENSE DENIAL
5.1 -Cost of License Denial
5.2 -Future Use of Damsites if License is Denied
6 -FINANCING
6.1 -Financial Evaluation
(a)
(b)
(c)
(d)
(e)
(f)
(g)
Forecast Financial Parameters
Inflationary Financing Deficit
Basic Financial Options
Issues Arising from the Basic Financing
Options
Financing Options Under Senate Bill 646
and House Bill 655
Future Development and Resolution of
Uncertainties
Conclusion
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EXHIBIT D -TABLE OF CONTENTS (Continued)
6.2 -Financial R~sk
(a) Pre-completion Risks
(b) Post-completion Risks
(c) Conclusions
List of References
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LIST OF TABLES
Table
No.
0.1
0.2
D.3
0.4
0.5
0.6
0.7
0.8
0.9
0.10
0.11
0.12
0.13
0.14
0.15
0.16
0.17
0.18
0.19
0.20
0.21
0.22
0.23
0.24
0.25
0.26
0.27
0.28
0.29
0.30
0.31
Summary of Cost Estimate
Estimate Summary -Watana
Estimate Summary -Devil Canyon
Mitigation Measures -Summary of Costs Incorporated
In Construction Cost Estimates
Pro-Former Financial Statements
No Fund-No State Contribution Scenario
Susitna Annual Cost of Power
Forecast Financial Parameters
Railbelt Utilities Providing Market Potential
List of Generating Plants Supplying Railbf:!lt Region
Total Generating Capacity Within the Rai'~belt System
Generating Units Within the Railbelt -1980
Schedule of Planned Utility Additions {1980-19BB}
Operating and Economic Parameters for Selected Hydroelectric Plants
Results of Economic Analyses of Alternative Generation Scenarios
Summary of Thermal Generating Resource Plant Parameters/1982$
Real (Inflation-Adjsuted) Annual Growth in Oil Prices
Domestic Market Prices and Export Opportunity Values of Natural Gas
Summary of Coal Opportunity Values
Summary of Fuel Prices Used in the OGP5 Probability Tree Analysis
Economic Analysis
Susitna Project -Base Plan
Summary of Load Forecasts Used for Ser.sitivity Analysis
load Forecast Sensitivity Analysis
Discount Rate Sensitivity Analysis
Capital Cost Sensitivity An.a!ysis
Sensitivity Analysis-Updated Base Plan
(January 1982) Coal Prices
Sensitivity Analysis -Real Cost Escalation
Sensitivity Analysis -Non-Susitna
Plan with Chakachamna
Sensitivity Analysis -Susitna Project Delay
Summary of Sensitivity Analysis Indexes of Net Economic Benefits
Battelle Alternatives Study for the Railbelt Candidate
Electric Energy Generating Technologies
Bat tel 1 e Alternatives Study, Summary of Cost and
Performance Characteristics of Selected Alternatives
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LIST OF TABLES (Continued)
Table
No.
0.32
0.33
0.34
0.35
0.36
0.37
0.38
Battelle Alternatives Study,. Summary of E1ectric Energy
Alternatives Included as Future Additions in Electric Energy Plans
100% State Appropriation of Total Capital Cost
($5.1 Billion in 1982 Dollars)
$3 Billion (1982 Dollars) State Appropriation Scenario
7% Inflation and 10% Interest
$2.3 Billion (1982 Dollars) Minimum State Appropriation
Scenario 7% Inflation and 10% Interest
Financing Requirements -$ Billion for $3.0 Billion
State Appropriation Scenario
Financing Requirements-$ Billion·far $2.3 Billion
State Appropriation Scenario
Basic Parameters of Risk Generation ~1odel
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LIST OF FIGURES
Figure
No.
0 .. 1
0.2
0.3
0.4
D.5
D.6
D.7
D.B
0.9
0.10
0.11
0.12
D.l3
D.14
D.15
0.16
D.17
D.l8
0.19
0.20
0.21
0 .. 22
D.23
0.24
0.25
0.26
0"27
0.28
0.29
0.30
Watana Development Cumulative and Annual Cash Flow January, 1982 Dollars
Devil Canyon Development Cumulative and Annual Cash Flow January, 1982 Dollars
Susitna Hydroelectric Project Cumulative and Annual Cash
Flow Entire Project, January, 198?. Do 11 ars
Railbelt Region Generating and Transmission Facilities
Service Areas of Railbelt Utilities
Energy Supply; Generating Facilities; Net Generation by
Types of Fuel; Relative Mix of Electrical Generating
Technology-Railbelt Utilities -1980
Energy Demand and Deliveries From Susitna
Energy Pricing Comparisons -1994
System Costs ·Avoided by Developing Susitna
Energy Pricing Comparisons -2003
Location flflap
Formulation of Plans Incorporating Non-Sus1tna Hydro Generation
Selected Alternative Hydroelectric Sites
Generation Scenario Incorporating Thermal and Alernative
Hydropower Developments -Medium Load Forecast
Formulation of Plans Incorporating All-Thermal ,Generation
Alternative Generation Scenario Battelle Medium Load Forecast
Probability Tree-System with Alternatives to Susitna
Probability Tree -System with Susitna
Susitna Multivariate Sensitivity Analysis Long-Term
Costs vs Cumulative Probability
Susitna Multivariate Sensitivity Analysis -Cumulative Probability vs Net Benefits
Energy Cost Comparison -100% Debt Financing
0 and 7% Inflation
Energy Cost Comparison-State Appropriation $3 Billion (1982 $)
Energy Cost Comparison $2.3 Billion (1982 $) -
Minimum State Appropriation
Energy Cost Comparison -Pricing Restricted 94/95 and 03/04
Energy Cost Comparison Meeting SB 646 Requirements with 100% Financing ,
Energy Cost Comparison Meeting SB 646 Requirements with $3.0 Billion Appropriation
Bond Financing Requirements
Debt Service Cover
Watana Unit Costs as Percent of ·Best Thermal Option in 1996
Cumu·l ative Net Operating Earnings by 2000
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EXHIBIT 0 -PROJECT COSTS AND FINANCING
This exhibit presents the estimated project cost for the Susitna
Hydroelectric Project, the market value of project power and a
financing plan for the project .. Alternative sources of power which
were studied are a1 so presented.
1 -ESTIMATES OF COST
This sect ion presents estimates of capital and operating costs for the
Susitna Hydroelectric Project, comprising the \\tatana and Devil Canyon
developments and associated transmission and access facilities. The
rosts of design features and facilities incorporated into the project
to mitigate environmental impacts during construction and operation are
identified. Cash flow schedules, outlining cap·ital requirements during
planning, construction, and start-up are presented. The approach to
the derivation of the capital and operating costs estimates is
described.
The total cost of the Watana and Devil Canyon projects is summarized in
Table 0.1. A more detailed breakdown of cost for each development is
presented in Tables·D.2 and 0.3.
1.1 -Construction Costs
This section describes the process used for deriva~ion of construction
costs and discusses the Code of Accounts established, the basis for the
estimates and the various assumptions made in arriving at the esti-
mates. For general consistency with planning studies, all costs devel-
oped for the project are: in January, 1982 dollars.
(a) Code of Accounts
Estimates of construct ion costs were developed using the FERC for-
mat as outlined in the Federal Code of Regu1ations, Title 18 {1).
The estimates have been subdivided fnto the following main cost
groupings:
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Production Plant
Transmission Plant
General Plant
Indirect Costs
Overhead Construction Costs
.
Description
Costs for structures, equip-
ment, and facilities necessa--y
to produce power.
Costs for structures, equip-
ment, and facilities necessary
to transmit power from the
sites"to load centers.
Costs for equipment and facili-
ties required for the operation
and maintenance of the produc-
tion and transmission plant.
Costs that are common to a
number of construction acti vi-
ties. For this estimate only
camps have been identified in
this group. The estimate for
camps includes electric power
costs. Other indirect costs
have been included in the costs
under production~ transmission,
and general plant costs.
Costs for engineering and
administration.
Further subdivision within these. groupings was made. on the basis
of the various types of work invol ve.d, as typically shown in the
following example:
-Group: Product ion P1 ant
-Account 332: Reservoir, Dcu-n, and Waterways
-Main Structure 332. 3: Main Dam
-Element 332.31: Main Dam Structure
-\~ork Item 332. 311: Excavation
-Typ~ of Work: Rock
(b) Approach to Cost Estimating
The estimating process used generally included the following
steps:
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-Collection and assembly of detailed cost data for labor, mater-
ial, and equipment as well as information on productivity, cli-
matic conditions~ and other related items;
-Review of engineering drawings and technical infonnation with
regard to construction methodology and feasibility;
-Production of detailed quantity takeoffs from drawings in accor-
dance with. the previously developed Code of Accounts and item
listing;
-Determination of dil-~ect unit costs for each major type of work
by development of labor, material, and equipment requirements;
development of other costs by use of estimating guides, quota-
tions from vendors, and other information as appropriate;
-Development of construction indirect costs by review of labor,
material~ equipment, supporting facilities, and ovE~rheads; and
-Development of construction camp size and support requirements
from the 1 abor demand generated by the construction direct and
indirect costs.
(c) Cost Data
Cost information was obtained from standard estimating sources,
from sources in Alaska, from quotes by major equipment suppliers
and vendors, and from representative recent hydroelectric pro-
jects. Labor and equipment costs for 1982 were developed from a
number of sources (2,3) and from an analysis of costs for recent
projects performed in the Alaska environment.
It has been assumed that contractors will work an average of two
9-hour shifts per day, 6 days per week, with an expected range as
follows:
Mechanical/Electrical Work
Formwork/Concrete Work
Excavat ion/Fi 11 Work
8-hour shifts
9-hour shifts
10-hour shifts
These assumptions provide for high utilization of construction
equipment and reasonable levels of overtime earnings to attract
workers. The two-shift basis generally achieves the most
economical balance between 1 abor and camp costs.
Construction equipment costs were obtained from vendors on an FOB
Anchorage basis with an appropriate allowance i.ncluded for trans-
portation to site. A repr·esentative list of construction equip-
ment required for the project was assembled as a basis for the
estimate. It has been assumed that most equipment would be fully
depreciated over the life of the project. For some activities
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(d)
such as construction of the ~Jatana main dam, an allowance for
major overhaul was included rather than fleet replacement. Equip-
ment operating costs were estimated from industry source data,
with appropriate modifications for the remote nature and extreme
climatic environment of the site. Fuel and oil prices have also
been included based upon FOB. site prices.
In format ion fat permanent mechanic a1 and electrical equipment was
obtained from vendors and manufacturers who provided guideline
costs on major power plant equipment~
The costs of materials required for site construction were esti-
mated on the basis of suppliers' quotations, adjusted for· Alaskan
d ·r· con 1 .~ 1 ons.
Seasonal Influences on Productivity
A review of climatic conditions together with an analysis of
experience in A1 aska and in Northern Canada on 1 arge construction
projects 'lias undertaken to determine the aver age duration for
various key activities. It has been projected that most
aboveground activities will either stop or be curtailed during the
period of December and January because of the extreme cold weather
and the associated lower productivity. For the main dam
construction activities, the following seasons have been used:
-Watana dam fill -6-month season; and
-Devil Canyon arch dam -8-month season.
Other aboveground activities are assumed to extend up to 11 months
depending on the type of work and the criticality of the schedule.
Underground activities are generally not affected by climate and
should continue throughout the year.
Studies by others (4) have indicated a 60 percent or greater
decrease in efficiency in construct ion ope rat ions under adverse
winter conditions. Therefore, it is expected that most
contractors would attempt to schedule outs ide work over a period
of between 6 to 10 months •
Studies performed as part of this work program indicate that the
general construction activity at the Susitna damsite during the
months of Apt"' i 1 through September would be cornparab le with that in
the northern sections of the western United States. Rainfall in
the general region of the site is moderate between ·mid-April and
mid-October, ranging from a low of 0.75 inches precipitation in
April to a high of 5. 33 inches in August. Temperatures in this
period range from 33°F to 66°F for a twenty-year average. In the
five-month period from November through March the temperature
ranges from 9.4°F to 20.3"F, with snowfall of 10 inches per
month.
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(e) Construction Methods
The construction methods assumed for development of the estimate
and construction schedule are generally considered as normal to
the industry, in line with the avail able level of technical
information. A conservative approach has been taken in those
areas where more detailed information will be developed during
subsequent investigation and engineering programs. For example,
normal drilling, blasting, and mucking methods have been assumed
for all underground excavation. Conventional equipment has also
been considered for major fill and concrete work.
(f) Quantity Takeoffs
Detai 1 ed quantity takeoffs wer·e produced from the engineering
drawings \Jsing methods normal to the industry. The quantities
deve 1 oped are 1 i sted in the det ai 1 ed ~ummar y estimates in Appendix
C to the Susitna Hydroelectric Feasibi 1 ity Report (5).
(g) Indirect Construction Costs
Indirect construction costs were estimated in detail for the civil
construction activities. A more general evaluation was used for
the mechanical and el£strical ~rk.
Indirect costs included the following:
-Mobilization;
-Technical and supervisory personnel above the level of trades
foremen;
-All vehicle costs for supervisory personnel;,)
-Fixed offices, mobile offices,. workshops, storage facilities,
and 1 aydov.n areas, inc 1 ud i ng a 11 services;
-General transportation for workmen on site and off site;
-Yard cranes and floats;
-Utilities including electrical power, heat, water, and com-
pressed air;
-Sm a 11 too 1 s ;
-Safety program and equipment;
-Financing;
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-Bonds and securities;
-Insurance;
-Taxes;
-Permits;
-Head office overhead;
-Contingency allowance; and
-Profit.
In developing contractors indirect costs, the following
assumptions have been made:
-Mobi 1 i zat ion costs have generally been spread over construct ion items;
-No escalation a.llowances have been made, and therefore any risks
associ a ted with esc a 1 at ion are not inc 1 uded;
-Financing of progress payments has been estimated for 45 days,
the average time between expenditure and reimbursement;
-Holdback would be limited to a nominal amount;
-Project all-risk insurance has been estimated as a contractor•s
indirect cost for this estimate, but it is expected that this
insurance \oJou1d be carried by the owner; and
-Contract packaging would provide for the supply of major mater-
; al s to contractors at site at cost. These include fuel, el ec-
tric power~ cement~ and rei~forcing steel.
1.2 -Mitigation Costs
·The project 1rrangement includes a number of features designed to
mitigate potential impacts on t.he natural environment and on residents
and communities in the vicinity of the pr'oject. In addition, a number
of measures are planned during construction of the project to reduce
similar impacts caused by construction activities. These measures and
facilities represent additional costs to the project than would
otherwise be required for safe and efficient operation of a
hydroelectric develof111ent. These mitigation costs have been estimated
at $149 million and have been summarized in Table 0.4. In addition,
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the costs of full reservoir clearing at both sites has been estimated
at $85 million. Although full clearing is considered good engineering
practice, i-t ·;s not essential to the operation of the power facilities.
These costs include direct and indirect costs, engineering,
administration, and contingencies.
[NOTE: This section will be revised to be made exact after the
completion of mitigation planningo]
A number of mitigation costs are associated with facilities,
improvements or other programs not directly related to the project or
located outside the project boundaries. These would include the
following items:
-Caribou barriers;
-Fish channels;
-Fish hatcheries;
-Stream improvements;
-Salt licks;
-Recreational facilities;
Habitat management for moose;
Fish stocking program in reservoirs; and
-Land acquistion cost for recreation.
.)
It is anticipated that some of these features or programs will not be
required during or after construction of the project. In this regard a
probability factor has been assigned to each of the above items, and
the estimated cost of each reduced accordingly. The estimated cost of
these measures, based on this procedure, is approximately $9 million.
These costs have been assumed to be covered by the construction
contingency.
A number of studies and programs will be required to monitor the
impacts of the project on the environment and to develop and record
various data during project construction and operation. These
include:
-Archaeological studies;
-Fisheries and wildlife studies;
·· Right-of -\'Jay studies; and
-Socioeconomic planning studies.
The costs for the above \vork have been included in the owner• s costs
under project overheads.
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1.3 -Engineering and Administration Costs
Engineering has been subdivided into the follo\>Jing accounts for the
purposes of the cost estimates:
-Account 71
. Engineering and Project Management
• Construct ion Management
. Procurement
-Account 76
<Mner' s Costs
The total cost of engineering and administrative activities has been
estimated at 12.5 percent of the total construction costs, including
contingencies. A detailed breakdown of these costs is dependent on the
organizational structure established to undertake design and management
of the project, as well as more definitive data relating to the scope
and nature of the various project components. However, the main
.elements of cost included are as follows:
(a) Engineering and Project Management Costs
These costs include allowances for:
-Feasibility studies, including site surveys and investigations
and logistics support;
-Preparation of the 1 icense application to the FERC;
-Technical and administrative input (/for other federal., state and
local permit and 1 icense applications;
-Overall coordination and administration of engineering, con-
struction management, and procurement activities;
-Overall planning, coordination, and monitoring activities
rel J.ted to cost and schedule of the project;
-Coordination with and reporting to the Power Authority regarding
all aspects of the project;
-Preliminary and detailed design;
-Technical input to procurement of construction services, support
services, ·and equipment;
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-Monitoring of construction to ensure conformance to design
requirements;
-Preparation of start-up and acceptance test procedures; and
-Preparation of project operating and maintenance manuals.
(b) Construction Management Costs
Construction management costs have beer assumed to include:
-Initial planning and scheduling and establishment of project
procedures and organization;
-Coord in at ion of onsite contractors and construction management
activities;
-Administration of onsite contractors to ensure harmony of
trades, compliance with applicable regulations, and maintenance
of adequate site security and safety requirements;
-Development, coordination, and monitoring of constrvction
schedules;
-Construction cost control;
-Material~ equipment and drawing control;
'
-Inspection of construction and survey control;
-Measurement for payment;
-Start-up and acceptance tests for equipment and systems;
-Compilation of as-constructed records; and
-Final acceptance o
(c) Procurement Costs
Procurement costs have been assumed to include:
-Establishment of project procurement procedures;
-Preparation of non-technical procurement documents;
-Solicitation and review of bids for construction services, sup-
port services, permanent equipment, and other items required to
comp 1 ete the project ;
-Cost administration and control for procurement contracts; and
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. -Quality assurance services during fabrication or manufacture of
equipment and other purchased items.
(d) Owner•s Costs
Owner 1 s costs have been assumed to include the following;
-A9ministration and coordination of project management and
engineering organizations;
-Coordination with other state, local, and federal agencies and
groups having jurisdiction or interest in the project;
-Coordination with interested public groups and individuals;
-Reporting to legislature and the public on the progress of the
project; and
-Legal costs (Account 72)o
1.4 -Allowance for Funds Used During Construction
At current high levels of interest rates in the financial marketplace,
AFOC will amount to a significant element of financing cost for the
lengthy periods required for construction of the Watana and Devil
Canyon projects. However, in economic evaluations of the Susitna
project the low real rates of interest assumed waul d have a much
reduced impact on assumed project development costs. Furthermore!)
direct state involvement in financing of the Susitna project will also
have a significant impact on the amount, if any, of AFDC. For purposes
of the feasibility study, therefore, the conventional practice of
calculating AFDC as a separate line item for inclusion as part of
project construction cost has not been followed. Provisions for AFDC
at appropriate rates of interest are made in the economic and financial
analyses included in this Exhibit.
1. 5 -Escalation
All costs presented in this Exhibit are at January 1982 -levels~ and
consequently include no allo~'lance for future cost escalation. Thus,
these costs would not be truly representative of construct ion and
procurement bid prices. This is because provision must be made in such
bids for continuing escalation of costs, and the extent and variation.
of escalation which might take place over the lengthy construction
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periods involved. Economic and financial evaluations take full account
of such escalation at appropriate rates.
1.6 -Cash Flow and Manpower Loading Requirements
The cash flow requirements for construction of \~atana and Devil Canyon
are an essential input to economic and financial planntng studies. The
bases for the cash flow are the construction cost estimates in January
1982 dollars and the construction schedules presented in Exhibit C,
with no provision being made as such for escalation. The cash flow
estimates were computed on an annual basis and do not include
adjustments for advanced payments for mobilization or for holdbacks on
construction contracts. The results are presented in Figures D.l
through 0.3. The manpower loading requirements (5) were developed from
cash flow projections. These curves were used as the basis for camp
loading and associated socioeconomic impact studies.
1.7 -Contingency
A contingency allowance of 17.5 percent of construction costs has been
included in the cost estimates. The contingency is estimated to
include cost increases which may occur in the detailed engineering
phase of the project after more comprehensive site investigations and
final designs have been completed and after the requirements of various
concerned agencies have been satisfied. The contingency estimate also
includes allowances for inherent uncertainties in costs of labor,
equipment and materials, and for unforeseen conditions which may be ·
encountered during construction. Escalation in costs due to inflation
is not inc1uded. No allowance has been included for costs associated
with significant delays in project implementation.
1.8 -Previously Constructed ?roject Facilities
An electrical intertie between the major load centers of Fairbanks and
Anchorage is currently under construction. The line will connect
existing transmission systems at Willow in the south and Healy in the
north. The intertie is being built to the same standards as those
proposed for the Susitna project transmission lines and will become
part of the licensed project. The line will be energized initially at
138 kV in 1984 and will operate at 345 kV after the Watana phase of ~the ·
Susitna project is complete.
The current estimate for the completed intertie is $ • ------
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2 -ESTIMATED ANNUAL PRO,JECT COSTS
As a two-stag·e (Watana and Devil Canyon) development with varying
levels of energy output and the assumption of ongoing inflation (at 7
percent per annum), the real cost of Susitna power will be continually
varying. As a consequence~ no simple single value real cost of power
can be used.
Table 0.5 gives the projected year-by-year projection energy·levels on
the first line and the second, the year-by-year unit cost of power in
19H2 dollars. Costs are based on power sales at cost assuming 100
percent debt finance at 10 percent interest. This is seen to r:~sult in
a real cost of power of 128 mills in 1994 (first 'normal' year of
Watana) falling to 72.76 mills in 2003 (the first 'normal' year of
Watana and Devil Canyon). The real cost of power would then fa11
progressively for the whole remaining life.
Table 0 .. 6 pr·ovides a reconstruction of the annual cost of power for
2003 in both 1982 and 2003 price levels. An underlying 7 percent
inflation rate has been assumed.
It is expected that the State of Alaska will introduce financial
measures which will have the affect of reducing the cost of Susitna
energy thus enabling its long term economic advantages to be realized
without excessively high early year costs to consumers,
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3 -MARKET VALUE OF PROJECT POWER
This section presents an assessment of the market in the Railb~lt .
region for the energy and capacity of the Susitna deve1opment. A range
of rates at which this power could be priced is presented together with
a proposed basis for contracting for the supply of Susitna energy.
3.1 -The Railbelt Power System
Susitna capacity and energy will be delivered to the "Railbelt Region
Interconnected Systemn which will result from the ·linkage of the
Anchorage and Fairbanks systems by an intertie to be completed in the
mid-1980s.
The Railbelt region covers the Anchorage-Cook Inlet area, the
Fairbanks-Tanana Valley arealt and the G1enna11en-Valdez area
(Figure 0.4) •. The utilities, military installations and universities
within this region which own electric generating facilities are listed
in Table 0.8. The service areas of these utilities are shown in
Figure 0.5 and the generating plants serving the region are listed in
Table 0.9.
The Railbelt region is currently served by nine major utility systems;
five are rural electric cooperatives, three are municipally owned and
operated, and one is a federal wholesaler. The relative mix of
electric generating technolo.gies and types of fuel used by the Railbelt
utilities in 1980 is summarized in Figure 0.6.
In 1980, the Anchorage-Cook Inlet area had 81 percent, the
Fairbanks-Tanana Valley area 17 percent, and the Glennallen-Valdez area
2 percent of the total energy sale"s in the Railbelt region.
Due to the pending construction of the Willow to Healy transmission
line, the Anchorage and Fairbanks power systems will be intertied
before the Susitna Project comes into operation. ihe proposed intertie:
will allow.a capacity transfer of up to 70 MW in either direction. The
proposed plan of interconnection envisages initial operation at 138 kV
with subsequent uprating to 345 kV allowing the line to be integrated
into the Susitna transmission facilities.
3.2 -Regional Electric Power Demand and Supply
A review of the so:ioeconomic scenarios upon which forecasts of
electric power demand were based is presented in Exhibit B of this
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application. The forecasts used here are in the mid-t·ange levels
made by Battelle Northwest in December 1981. The results of studies
presented in Exhibit B call for Watana to come into operation in 1993
and to deliver a full year's energy generation in 1g94. Devil Canyon
will come into operation in 2002 and de 1 i y,;,. J full year's energy. in
2003. Energy demand in the Rail belt region and the de 1 i veri es from Susitna are shown in Figure 0.7.
3.3 -Market and Price for Watana Output in 1994
It has been assumed that Watana energy will be supplied at a single
wholesale rate on a free market basis. This requires, in effect, that
Susitna energy be priced so that it is attractive even to utilities
with the lowest cost alternative source of energy. On this basis it is
estimated that for the initially marketable 3315 GWh of energy
generated by Watana in 1994 to be attractive, a price of 145 mills per
kWh in 1994 dollars is required. Justification for this price is
illustrated in Figure 0.8. Note that the assumption is made that the
only capital costs which would be avoided in the early 1990s would be
those due to the alternative addition of new coal-fired generating
p 1 ants (i.e., the 2 x 200 MW coal-fired Be 1 uga station). The Sus itna
energy pric~ of 145 mills/kWh suggested here matches closely the value
determined from generation planning analysis in the financial eva1 uation ..
The financing considerations under which it would be appropriate for
Watana energy to be sold at approximately 145 mills per kWh price are
considered in Section 6 of this Exhibit; however, it should be noted
that some of the energy which would be displaced by Watana's production
would have been generated at a lower cost than 145 mills, and utilities-
might wish to delay accepting it at this price until the escalating
cost of natural gas or other fuels made it more attractiveg A number
of approaches to the resolution of this probl~ can be postulated, including pre-contract arrangements.
It will be necessary to contract with Railbelt Utilities for the
purchase of Susitna capacity and energy on a basis appropriate to support financing of the project.
Pricing policies for S_usitna output will be constrained by both cost
(as defined by Alaska Senate Bill 25) and by the price of energy from
the best alternative option. These options are discussed in Section 4 of this Exhibit.
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Marketing Susitna's output within these twin costraints \1/0uld ensure
that all state support for Susitna flowed through to consumers and
under· no circumstances waul d prices to consumers be higher than they
would have been under the best alternative option. In addition,
o consumers would also obtain the long-term economic benefits of
Susitna•s low cost energy.
3.4 -Market Price for Watana Output 1995-2001
After its initial entry into the system in 1994, the price and market
for the total 3387 MWh of Watana output is cons.istently upheld over the
years to 2001 by the projected 20.percent increase in total demand over
this period.
There waul d, as a result, be a 70 percent increase in cost savin.gs
compared with the best thermal generating alternative: the increasing
cost per unit of output from a system without Susitna is illustrated. in Figure D.9.
3.5 -Market and Price for \.Jatana and Devil Canyon Output in 2003
A diagramatic analysis of the total cost savings which the combined
Watana and Devil Canyon output will confer on the system compared with
the alternative thermal option in the year 2003 is shown in
Figure D.lO. These total savings are divided by the energy contributed
by Susitna to indicate a price of 250 mills per kWh as the maximum
price which can be charged for Susitna output.
Only about 90 percent of the total Susitna energy output will be
absorbed by the system in 2002; the balance of the output will be
progressively absorbed over the following decade. This will provide
increasing total savings to the system from Susitna with no associated
increase in costs.
3.6 -Potential Impact of State Appropriations
In the preceding paragraphs the maximum price at which Susitna energy
could be sold has been identified. Sale of the energy at these prices
will depend upon the magnitude of any proposed state appropriation
designed "to reduce the cost of Susitna energy in the earlier years. At
significantly lower prices it is likely that the total system demand
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will be higher than assumed. This, combined with a state appropriation
to reduce the energy cost of vJatana energy, would make it
correspondingly easier to market the output from the Susitna
development; however, as the preceding analysis shows, a viable and
strengthening market exists for the energy from the deve1 opment that
would make it possible to price the output up to the cost of the best
thermal alternative.
3.7 -Conclusions
Based on the assessment of the market for power and energy output from
the Susitna Hydroelectric Project, it has been concluded that with the
appropriate level of state appropriation and with pricing policy as
defined in Alaska State Laws, an attractive basis exists, particularly
in the long term, for the Ra.ilbelt utilities to derive benefit from the
Project.
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4 -EVALUATION OF ALTERNATIVE ENERGY PLAN
4.1 -General
This section describes the process of assembling the information neces-
sary to carry out the systemwide generation planning studies necessary
for assessment of economic feasibility of the Susitna Project. Includ-
ed is a discussion of the ftXisting system characteristics, the planned
Anchorage-Fairbanks intertie, and details of various generating options
including hydroelectric and thennal. Performance and cost information
required for the generation planning studies is pr.esented for the
hydroelectric and thermal generation options considered.
The approach taken in economically evaluating the Susitna project
involved the development of long term generation plans for the Railbelt
electrical supply system with and without the proposed project. In
order to compare the with and without plans, the cost of the plans were
compared on a present worth basis. A generation planning model \'ktich
simulated the operation of the system annually was used to project the
annua 1 generation costs.
During the pre-license phase of the Susitna project planning, two
studies proceeded in parallel which addressed the alternatives in
generating power in the Alaska Railbelto These studies are the Susitna
Hydroelectric Project Feasibility Study done by Acres American
Incorporated for the Alaska Power Authority and the Railbelt Electric
·Puwer Alternatives Study done by Battelle Pacific Northwest
Laboratories for the Office of the Governor, State of Alaska.
One objective of the Susitna Feasibility was to determine the
feasibility of the proposed project. The economic 2val uations done
during study found the project to be feasible as documented in this
exhibit. The independent study done by Battelle focused on the
feasibility of all possible generating and conservation alternatives.
Although the studies vrere independent, several key factors were
consistent. Both studies used the approach of comparing costs by using
generation planning simulation models. Thus, selected alternatives
were put into a plan context and their economic performance compared by
comparirlg costs of· the plans. Additionally, parameters such as costs
for fuel and capital costs and escalation were consis.tent between the
two studies.
The following presentation focuses primarily on the feasibility study
process and findings. A separate section provides the findings of the
Battelle Study, vklich generally agree with the feasibility study
findings.
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4.2 -Existing System Characteristics
(a) System Description
The two major load center~s of the Rai 1 belt region are the
Anchorage-Cook Inlet area and the Fairbanks-Tanana Valley area
(see Figure D.ll), which, at present, operate independently. The
existing transmission system bet\'leen Anchorage and Willow consists
of a network of 115 k V and 138 k V l i ries with interconnect ion to
to Palmer. Fairbanks is primarily served by a 138-kV 1 i ne from
the 28-f.-lW coal-fired plant at Healy. Communities between ~Jillow
and Healy are served by local distribution.
There are currently nine electric utili.ties (including the Alaska
P.o\'Jer Administration) providing power and energy to the Railbelt
system. Table 0.10 summarizes the total generating capacity
within the Railbelt system in 1980~ based on information provided
by Railbelt utilities and other sources. Table 0.11 presents the
resulting detailed listing of units currently operating in the
Railbelt, information on their performance characteristics, and
their online r:\nd projected retirement dates for generation
planning purposes. The total Railbelt installed capacity of 984
MW as of 1980 consists of two hydroelectric plants totaling 46 MW
plus 938 MW of thermal generation units fired by oil, gas, or
coal, as sumnari zed in Table 0.12.
(b) Retirement Schedule
In order to establish a retirement pol icy for the existing gener-
ating units, several sources were consulted, including the Power·
Authority's draft feasibility study guidelines, FERC guidelines,
the Battelle Railbelt Alternatives Study!) and historical records.
Utilities, particularly those in the Fairbanks area, were also
consulted. Based on these sources, the following retirement
periods of ope rat ion were adopted for use in this analysis:
-Large Coal-Fired Steam Turbines (> 100 MW}:
-Small Coal-Fired Steam Turbines ( < 100 MW):
~Oil-Fired Gas Turbines:
-Natural Gas-Fired Gas Turbines:
-Diesels:
-Combined Cycle Units:
-Conventional Hydro:
30 years
35 years
20 years
30 years
30 years
30 years
50 years
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Table 0.12 lists the retirement dates for each of the current
generating units based on the above retirement policy.
(c) Schedule of Additions
Six new projects were expected to be added to the Rai 1bel t system
prior to 1990. The Chugach Electric Association is in the process
of adding gas-fired combined-cycle capacity in Anchorage at a
plant called Beluga No. 8. When complete, the total plant
capacity will be 178 MW, but the plant will encompass existing
Units 6 and 7. Chugach added a 26.4 MW gas turbine rehabilitation
at Bernice Lake No. 4 in August 1982.
The Corps of Engineers is currently in the post-authorization
planning phase for the Bradley Lake hydroelectric project located
on the Kenai Peninsula. The project would include between 90 and
135 MW of installed capacity and would produce an annual average
energy of 350 Gwn. For analysis purposes, the project is assumed
to come on line in 1988.
Three other units are also scheduled or have been added to the
system since 1980. Anchorage Municipal Light and Po\'ler Department
is planning to add a 90 MW gas turbine in 1983-84 called AMLPD No.
8. Copper..,J Valley Electric Association is operating the new 12 MW
Solomon Gulch Hydroelectric Project. Finally, the 7 MW Grant Lake
Hydroelectric Project is undergoing planning for addition to the
system in 1988 by the Alaska Power Authority.
4.3 -Fairbanks -Anchorage Intertie
Engineering studies have been undertaken for construction of an inter-
tie between the Anchorage and Fairbanks systems. As presently envis-
aged, this connection \~11 involve a 345-kV transmission line between
Willow and Healy scheduled for completion in 1984. The line will
initially be ope.rated at 138 kV with the capability for expansion as
the loads grow in the load centers.
Based on these evaluations, it was concluded that an interconnected
system should be assumed for the generation planning studies, and that
the basic intertie facilities vmuld be common to all generation
scenarios considered.
Costs of additional transmission facilities were added to the scenarios
as necessary for each unit added. In the 11 With Sus itnan scenarios, the
costs of adding circuits to the intertie corridor were added to the
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Susitna project cost. For the non-Susitna units, transmission costs
were added as follows:
-No costs were added for combined-cycle or gas-turbine units, since
they were assumed to have sufficient siting flexibility to be placed
near the major transmission works;
-A multiple coal-fired unit development in the Beluga fields was esti-
mated to have a transmission system with equal security to that
planned for Susitna, costing $220 mi11ion. This system would take
power from the bus back to the existing load center; and
-A single coal-fired unit development in the Nenana area using coa1
mined in the Healy fields would require a transmission system costing
$117 million dollars.
With the addition of a unit in the Fairbanks area in the 1990s, no
additions to the 345 kV 1 ine were considered necessary. Thus,, no other
transmission changes were made to the non-Susitna plans.
4.4 -Hydroelectric Alternatives
Numerous studies of hydroelectric potential in Alaska have been under-
taken. These date as far back as 1947 and were performea by various
agencies including the then Federal Power Commission, the Corps of
Engineers, the U.S. Bureau of Reclamation, the U.S. Geological Survey,
and the State of Alaska. A significant amount of the identified
potential is located in the Railbelt region, inc"!uding several sites in
the Susitna River Basin.
(a) Selection Process
The application of the five-step methodology (Figure 0.12) for
selection of non-Susitna plans which incorporate hydroelectric
developments is summarized in this section. The analysis was
completed in early 1981 and is based on January 1981 cost figures;
all other· parameters are contained in the Development Selection
Report {6). Step 1 of this process essentially established the
overall objective of the exercise as the selection of an optimum
Railbelt generation plan which incorporated the proposed non-
Susitna hydroelectric developments for compariso.n with other
plans.
Under Step 2 of the selection process~ all feasible candidate
sites were identified for inclusion in the subsequent screening
exercise. A total of 91 potential sites were obtained from
inventories of potential sites published in. the COE National
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Hydropower Study and the Power Administration report·
"Hydroelectric Alternatives for the Alaska Rai lbelt .·11
The screening of sites under Step 3 required a total of four
successive iterations to reduce the number of alternatives to a
manageable short list. The overall objective of this process was
defined as the selection of approximately 10 sites for
consideration in plan formulation, essentially on the basis of
published data on the sites and appropriately defined criteria.
Figure 0.13 shows 49 of the sites which remained after the two
initial screens.
In Step 4 of the plan selection process, the ten sites shortlisted
under Step 3 were further refined as a basis for fonnul at ion of
Railbelt generation plans. Engineering sketch-type layouts were
produced for each of the sites, and quantities and capital costs
were evaluated. These costs, listed in Table D.l3, inccl"'porate a
20 percent allowance for contingencies and 10 percent for
engineering and owner's administration. A total of five plans
were formulated incorporating various combinations of these sites
as input into the Step 5 evaluations.
Power and energy values for each of the developments were
reevaluated in Step 5 utilizing monthly streamflow and a computer
reservoir simulation model. The results of these calculations are
summarized in Table 0.13.
The essential objective of Step 5 was established as the
derivation of the optimum plan for the future Railbelt generation
incorporating non-Susitna hydro generation as well as required
thermal generation ..
(b) Selected Sites
The selected potential non-Susitna Basin hydro developments
were ranked in tenms of their economic cost of energy. They were
then introduced into the all-thermal generating scenario during
the generation planning analyses, in groups of two or three. The,
most economic schemes were introduced first and were followed by
the 1 ess economic schemes. The methods of analysis are the same
as those discussed in Section 4.5 (f).
The results of these analyses, completed in early 1981, are
summarized in Table D.14 and illustrate that a minimum total
1 system cost can be achieved by the introduction of the
Chakachamna, Keetna, and Snow projects (See also Figure 0.14).
Note that further studies of the Chakachamna project were
initiated in mid.;.1981 by Bechtel for the Alaska Power Authority.
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(c) Lake Chakachamna
Bechtel Civil and Minerals studied the feasibility of developing
the power potential of Lake Chakachamna. The 1 ake is on the west
side of Cook Inlet 85 miles west of Anchorage. Its water surface
1 ies at about elevation 1140 feet.
Two basic alternatives have been identified to harness the
hydraulic head for the generation of electrical ertergy. One is
vi a the valley of the Chakachatna River. This river runs out of
the easterly end of the lake and :escents to about elevation 400
feet where the river leaves the confines of the valley and spi 11 s
out onto a broad alluvial flood pla:i-fh A maximum hydrostatic head
of about 740 feet could be developed via this alternative.
The other alternative is for development by diversion of the lake
outflow to the valley of the McArthur River which lies to the
southeast of the lake outlet.. A m,aximum hydrostatic head of about
960 feet could be harnessed by this diversion.
(i) Project Layout
The Be.chtel study evaluated the merits of develC\ping the
power potential by diversion of water southeasterly to the
McArthur river vi a a tunnel about 10-mil es long, or easterly
down the Chakachatna valley either by a tunnel about
12-miles long or by a dam and tunnel development. In the
Chakachatna valley, few sites, adverse foundation
conditions, the need for a large capacity spillway and the
nearby presence of an active volcano made it evident that
the feasibility of constructing a darn there would be
problematical. The main thrust of the initial study was
therefore directed toward the tunne 1 alternatives.
Two alignments were studied for the McArthur tunnel. The
first considered the shortest distance that gave no
opportunity for an additional point of access during
construction via an intermediate adit. The second alignment
was about a mile. longer, but gave an additional point of
access, thus reducing the lengths of headings and also the
time required for construction of the tunnel. Cost
comparisons nevertheless favored the shorter 10-mile 25-foot
diameter tunnel.
The second alignment running more or less parallel to the
Chakachatna River in the right (southerly) wall of the
valley afforded two opportunities for intermediate access
adits. These, plus the upstream and downstream portals
would allow construction to proceed simultaneously in 6
headings and reduce the construction time·by 18 months from
that required for the McArthur tunnel •
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If all the controlled \t~ater were used for power generation,
the McArthur po~1er·house could support 400 MW installed
. capacity, and produce average annual firm energy of 1753
GWh. The effects of making a provisional reservation of -
approximately 19 percent of the average annual inflow to the
1 ake for instream flow requirements in the Chakachatna River
were found to reduce the economic tunnel diameter to ~3
feet. The·installed capacity in the powerhouse would then
be reduced to 330 MW and the average annual firm energy to
1446 MW.
For the Chakachatna powerhouse, diversion of all the
controlled water for power generation would support an
installed capacity of 300 MW with an average annual firm
energy generation of 1314 GWh. Provisional reservation of
approximately 0. 8 percent of the average annual inflow to
the 1 ake for instrean flow requirements in the Chakachatna
River was regarded as having neg 1 i g ib 1 e effect on the
installed capacity and average annual firm energy because
that reduction is within the accuracy of the Bechtel study.
Technical Evaluation and Discussion
Several alternative methods of developing the project have
been identified and reviewed. Based on theoanalyses
performed, the more viable alternatives have been identified
by Bechtel for further study .
-Chakachatna Dam Alternative
The construction of a dam in the Chakachatna River canyon
approximately 6 miles downstream from the lake outlet,
does not appear to be a reasonable alternative. While the
site is topographically suitable, the foundation
conditions in the river valley and left abutment are poor ..
Furthermore, its environmental impact specifically on the
fisheries resource will be significant although provision
of fish passage facilities could mitigate this impact to a
certain extent.
-McArthur Tunnel Alternatives A and B
Diversion of flow from Chakachanma Lake to the McArthur
valley to develop a head of approximately 900 feet has
been identified as. the most advantageous with respect to
energy production and cost.-
The geologic conditions for the various project facilities
including intake, power tunnel, and powerhouse appear to
be favorable based on a 1981 field reconnaissance. No
d.
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insurmountable engineering problems appear to exist in
development of the project.
Alternative A, in M'lich essentially all stored water would
be diverted· form Chakachamna Lake for power product ion
purposes could deliver 1664 GWh of firm energy per year· to
Anchorage and provide 400 MW of peaking capacity. Hovever~ since the flow of the Chakachatna River below the
1 ake outlet would be adversely affected, the existing
anadromous fishery resource \lmich uses the river to gain
entry to the lake and its tributaries for spawning, would
be lost. In addition, the fish which spawn in the lower
Chakachatna River would also be impacted due to the much
reduced river flow. For this reason, A1 ternative B hq.s
been developed, with essentially the same project
arrangement except that approximately 19 percent of the
average annual flow into Chakachamna Lake would be
released into the Chakac~;atna River below the lake outlet
to maintain the fishery resource. Because of the smaller
flow available for power production, the installed
capacity of the project would be reduced to 330 MW and the
firm energy delivered to Anchorage \'vQul d be 1374 GWh per
year. Obviously, the long term environmental impacts of
the project in this Alternative B are significantly
reduced in comparison to Alternative A, since the river
flow is maintained, albeit at a reduced amount. Estimated
project costs for Alternatives A and Bar-e $L5 bill ion
and $1.45 billion respectively.
-Chakachatna Tunnel Alternatives C and 0
An alternative to the development of this hydroelectric
resource by diversion of flows from Chakachamna Lake to
the McArthur River is by constructing a tunnel thorugh the
right wall of the Chakachatna valley and locating the
powerhouse near the downstream end of the valley. The
general la,Ynut of the project would be similar to that of
Alternatives A and B for a slightly longer pov~er tunnel.
The geologic conditions for the various project features
including intake, power tunnel, and powerhouse appear to
be favorable and very simi 1 ar to those of A1ternat ives A
and B. Similarly, no insurmountable engineering problems
appear to exist in development of the project.
Alternative C, in \'lhich essentially all stored v1ater is
diverted from Chakachamna Lake for power production, could
deliver 1248 GWh of firm energy per year to Anchorage and
provide 300 M~J of peaking capability. \4hile the riverflow
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in the Chakachatna River bel ow the powerhouse at the end
of the canyon wi 11 not be substantially affected, the fact
that no releases are pt"OVided into the river at the lake
outlet will cause a substantial impact on the anadromous
fish which normally enter the 1 ake and pass through it to
the upstream tributaries. Alternative D was therefore
proposed in which a release of 30 cfs is maintained at the
1 ake outlet to facilitate fish passage thorugh the canyon
section into the 1 ake. In either of Alternatives C or D
the environmental impact would be 1 imited to the
Olakachatna River as_opposed to Alternatives A and B in
which both the Chakachatna and McArthur Rivers would be
affected. Since the instream flow-release. for Alternative
Dis less than 1 percent of the total available flow~ the
power production of Alternative 0 can be regarded as being
the same as those of Alternative C (300 MW peaking
capability, 1248 GWh of firm energy delivered to
Anchorage). Estimated project costs for Alternatives C
and 0 are $1.6 billion and $1.65 billion respectively.
4.5 -T~ermal Options -Development Selection
As discussed earlier in this section, the major portion of generating
capability in the Rai lbelt is currently thermal; principally natural
gas with some coal-and oil-fired installations. There is no doubt
that the future electric energy demand in the Rai lbelt could be
satisfied by an all-thermal generation mix. In the following
paragraphs, an outline is presented of the analysis undertaken in the
feasibility study to determine an appropriate all-thermal generation
scenario for comparison with the Susi tna hydroelectric scenario.
(a) Assessment of Thermal Alternatives
The overall objective established for this selection process was
the selection of an optimum all-thermal Railbelt generation plan
for comparison with other plans (Figure 0.15).
Primary consideration was given to gas, coal, and oil-fired
generation sources which are the most readily developable
alternatives in the Railbelt from the standpoint of technical and
ecof)omic feasibility. The broader perspectives of other
alternative resources such as peat, refuse, geothermal, wind and
solar and the relevant environmental, social, and other issues
involved were addressed in the Battelle alternatives study (32).
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As such, a screening process was therefore considered unnecessary
in this study, and emphasis was placed on selection of unit sizes
appropriate for inclusio'n in the generation ·planning ·exercise.
For analysis purposes the fallowing types of thennal power
generation units were considered:
-Coal-fired steam;
-Gas-fir·ed combined-cycle;
-Gas-fired gas turbine; and
-Diesel.
The following paragr·aphs present the thermal options used in
developing the present without Susitna plan.
(b) Coal-Fired Steam
A coal-fired steam plant is one in which steam is generated by a
coal-fired boiler and used to drive a steam-turbine generator.
Cooling of these units is accomplished by steam condensation in
cooling to\"'ers or by direct water cooling.
Aside from the military power plant at Fort Wainwright_and the
self supplied generation at the University of Alaska~ there are
currently two coal-fir-ed steam plants in operat')~p in the
Rail belt. These plants are small in comparison with new units
under consideration in the lower 48 states and in Alaska.
(i) Capital Costs
A detai 1 ed cost study was done by Ebasco Services Incorpor-
ated as part of Battelle's alternative study. The report
found that it was feasible to establish a plant at either
the undeveloped Beluga field or near Nenanas using Healy
field coal. The study produced costs and operating
characteristics for both plants. All new coal units were
estimated to have an average heat rate of 10,000 Btu/kWh
and involve an average construction period of five to six
years. Capital costs and operating parameters are defined
for coal and other thenmal generating plants in Table
0.15.
It was found that, rather than develop solely at one field
in the non-Susitna case, development would be 1 i kely to
take pl ace(L in both fields. Thus, one unit would be
developed near Nenana to service the Fairbanks load center~
with other units placed in the Beluga fields.
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To satisfy the national New Performance Standards, the cap-
ital costs incorporate provision for installation of flue
gas de.sulfurization for sulphur control, highly efficient
combustion technology for cor.trol of nitrogen acids, and
baghouses for particulate removal.
(ii) Fuel Costs
Fuel costs based on long-term opportunity values were set
at $L 43/MMBtu for Beluga field coal and $1. 75/MMBtu for
Healy coal to be used at Nenana. Real escalation on these
values was estimated as follows:
Beluga/Coal
Healy Coal at Nenana
1982-2000
2.6%
2.3%
2001-2010
1.2%
lol%
Details of the fuel cost infonnation are included in
Reference 31 of this report.
(iii) Other Performance Characteristics
Annual operation and maintenance costs and representative
forced outage rates are shown in Table 0.15.
(c) Combined Cycle
A combined cycle plant is one in which electricity is generated
partly in a gas turbine and partly in a steam turbine cycle. Com-
bined cycle plants achieve higher efficiencies than conventional
gas turbines. There are two combined cycle plants in Alaska at
present. One is operational and the other is under construction.
The plant under construct ion is the Beluga No. 8 unit owned by
Chugach Electric Assoc·iation (CEA}. It is a 42-MW steam turbine!t
which will be added to the system in late 1982, and utilize heat
from curr·ently operating gas turbine units, Beluga Nos. 6 and 7.
(i) Capital Costs
A new combined cycle plant unit size of 200-MW capacity was
considered to be representative of future additions to gen-
erating capability in the Anchorage area. This is based on
economic sizing for plants in the lower 48 states and pro-
jected load increases in the Railbelt. A heat rate of
8, 000 Btu/kWh was adopted based on the alternative study
completed by Battelle.
The capital cost was estimated using the Battelle study
basis and is listed in Table 0.15.
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(ii) Fuel Costs
The combined cycle facilities would burn only gas v1ith a
domestic market value of $3.00 per MM Btu was chosen to
reflect the equitable value of gas in Anchorage, assuming
development of the export market. Currently, the local
incremental gas market price is about one-third of this
amount due to the relatively 1 ight local demands and
limited facilities for export.
Using an approach similar to that used for coal costs, a
real annual growth rate in gas costs of 2. 5 percent
(1982-2000} and 2 percent (2000-2040) was used in the
analysis.
(iii) Other Performance Characteristics
Annual operation and maintenance costs, along with a repre-
sentative forced outage rate, are given in Table 0.15.
{ d} Gas-Turbine
Gas turbines burn natural gas or oil in units similar to jet
engines which are coupled to electric generators. These also
require an appropriate water coo 1 i ng arrangement.
Gas turbines are by far the main source of thennal power
generating resources in the Railbelt area at present. There are
470 MW of installed gas turbines operating on natural gas in the
Anchorage area and approximately 168 MW of oil-fired gas turbines
. supplying the Fairbanks area {see Table 0.11). Their low initial
cost, simplicity of construction and operation, and relatively
short implementation lead time have made them attractive as a
_Railbelt generating alternative~ The extremely low-cost contract
gas in the Anchorage area also has made this type of generating
facility cost-effective for the Anchorage load center.
(i) Capital Costs
A unit size of 75 MW v.Jas considered to be representative of
a modern gas turbine p1ant addition in the Railbelt region.,
1-bwever, the possibility of installing gas turbine units at
Beluga was not considered, since the Beluga development is
at this time primarily being considered for coal.
Gas turbine plants Gan be built over a tvm-year construc-
tion period and have an average heat rate of approximately
10,000 Btu/kWh. The capital costs were again taken fran
the Battelle alternatives study.
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(ii) Fuel Costs
Gas turbine units can be operated on oil as well as natural
gas. The opportunity value and market cost for oil are
considered to be equa 1, at $6. 50 per mill ion Btu. The real ...
annual growth rates ·in oil costs used were 2 percent for
1982-2000 and 1 percent for 2000-2040.
(iii) Other Performance Characteristics
Annual operation and maintenance costs and forced outage
rates are shown in Table 0.15.
(e) Diesel Power Generation
Most di ese.l plants in the Ra i 1 be 1 t today are on standby status or
are operated only for peak load service~ Nearly all the -continu-
ous duty units were retired in the past several years because of
high fuel prices. About 65 MW of diesel plant capacity is cur-
rently available.
( i) Capital Costs
The high cost of diesel fuel and low capital cost makes new
diesel plants most effective for emergency use or in remote
areas where small loads exist. A unit size of 10 MW vJas
selected as appropriate for this type of facility. The
capital cost was derived from the same source as given in
Table 0.15.
(ii) Fuel Costs
Diesel fuel costs and growth rates are the same as oil
costs for gas turbines.
(iii) Other Performance Character-istics
Annual operation and maintenance and the forced outage rate
are given in Table 0.15.
(f) Plan Formulation and Evaluation
The four candidate unit types and sizes were used to formulate
plans for meeting future Rai1belt power generation requirements.
The objective of this exercise was defined as the formulation of
appropriate plans for meeting the projected Rai lbelt demand on the
basis of economic preferences.
Economic evaluation of any Susitna Basin development plan requires
that the impact of the plan on the cost of energy to the Rai lbelt
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area consumer be assessed on a systemwide basis. Since the
consumer is supplied by a large number of different generating
sources, it is necessary to determine the total Railbelt system
cost in each case to compare the. various Susitna Basin development
options.
The primary tool used for system costs was the mathematical model
developed by the Electricity Utility Systems Engineering
Department of the General Electric Company. The model is commonly
known as OGP5 or Optimized Generation Planning Model, Version 5.
The following information is paraphrased from GE 1 iterature on the
program.
The OGP5 program was developed over ten years to combine the three
main elements of generation expansion planning (system
reliability, operating and investment costs) and ·automate
generation addition decision analysis. OGP5 will automatically
develop optimum generation expansion patterns in terms of
economics, reliability and operation. Many utilities use OGP5 to
study load management, unit size, capital. and fuel costs, energy
storage~ forced outage rates, and forecast uncertainty.
The OGP5 program requires an extensive system of specific data to
perform its planning function. In developing an optimal plan, the
ptograrn considers the existing and committed units (planned and
under construction) available to the system and the characteris-
tics of these units including age, heat rate, size and outage
rates as the base generation plan. The program then considers the
given load forecast and operation criteria to determine the need
for additional system capacity based on given reliability
criteria. This determines "how much" capacity to add and 11 Whenu
it should be installed. If a need exists during any monthly
iteration, the program will consider additions from a list of
alternatives and select the avail able unit best fitting the system
needs. Unit selection is made by computing production costs for
the system for each alternative included and comparing the
results.
The unit resulting in the lowest system production costs is
selected and added to the system. Finally, an investment cost
analysis of the capital costs is completed to answer the question
of 11 What kind" of generation to add to the system.
The ~odel is then further used to compare alternative plans for
meeting variable electrical demands, based on system reliaoility
and production costs for the study period.
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Thus, it should be recognized that the production costs modeled
represent only a port ion of ultimate consumer costs and in effect
are only a portion, albeit major, of total costs.
The use of the output from the generation planning model is in
Sect ion 4. 6{ a).
4. 6 -Without Susitna P 1 an
In order to analyze the economics of developing the Susitna project, it
was necessary to analyze the costs of meeting the projected Alaska
Railbelt load forecast with and without the project. Thus, a plan
using the identified components was developed.
Using the OGP5 system model, a, base case 11 Without Susitna11 plan was
structured based rin middle .range projections. The base case input to
the model included:
-Batte11 e' s middle range load for·ecast (Exhibit B);
-Fuel cost as specified;
-Coal-fired steam and gas-fired combined-cycle and combustion turb·ine
units as future additions to the system;
-Costs and characteristics of future additions as specified;
-The existing system as specified and scheduled commitments 1 i sted in
Tab 1 e D .. ~.2 ;
-Middle range fuel escalation as specified;
-Economic parameters of three percent interest and zero percent gener-·
a 1 in fl at ion ;
-Real escalation on operation and maintenance and capital costs at a
rate of 1.8 percent to 1992 and 2 percent thereafter; and
-Generation system reliability set to a loss of load probability of
v~e day. in ten years. This is a probabilistic measure of the inabil-
ity of the generating system to meet projected load. One day in ten
years is a value generally accepted in the industry for planning gen-
eration systems.
The model was initially to be operated for a period from 1982-2000. It
was found that, under the medi urn load forecast, the critical period for
capacity addition to the system would be in the winter of 1992-1993.
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Until that time" the existing system, given the additions of the
planned intertie and the planned units, appear to be sufficient to meet
Railbelt demands. Given this information, the period of plan develop-
ment using the model was set as 1993-2010.
The following was established as the non-Susitna Railbelt base plan
(see Figure 0.16):
(a) System as of January 1993
Co a f:::lrred"'"s"te am: ................. M,.
Natural gas GT:
Oil GT:
Diesel:
Natural gas CC:
Hydropower:
Total (including committed
59 MW
452 MW
140 MW
67 MW
317 MW
155 MW
conditions): 1190 MW
(b) System Additions
Gas Fired
Gas Turbine
Year
1993
1994
1996
1997
1998
2001
2003
2004
2005
2006
2007
2009
Total
(c) System as of 2010
Coal-fired steam:
Natural gas GT:
Oi 1 GT:
Diesel:
Natural gas CC:
Hydropu wer:
{MW)
1 X 70
1 X 70
1 X 70
1 X 70
1 X 70
2 X 70
1 X 70
1 X 70
630
Total (accounting for
813 MW
746 MW
0 MW
6 MW
317 MW
155 MW
retirements and additions) 2037 MW
Coal Fired Unit
(MW)
1 x 200 (Beluga Coal)
1 x 200 {Beluga Coal)
1 x 200 (Nenana/Healy Coal)
1 X 200 (Be 1 ug a Co a 1 )
800
..
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There is one particularl·Y important assumption underlying the plan~
The costs associated with the Beluga development are based on the
opening of that coal field for commercial development.. That
development is not a certainty now and is somewhat beyond the control
of the state, since the rights are in the hands of private inte"fests.
Even if the seam is mined for export, there will be environmental
problems to ovet--come. The greatest problem will be the availability of
cooling water for the units. The problem could be solved in the
11 WOrstn case by using the sea water from Cook Inlet as cooling water;
however, this solution would add significantly to project costs.
Two alternatives which Battelle included in their base plan M'lich have
not been included in this plan are the Chakachcunna and Allison Creek
hydroelectric plants. The Chakachamna plant is currently the subject
of a feasibility study by the Power Authority. The current plan would
develop a 330 MW plant at a cost of $1.45 bi 11 ion at January, 1982
price levels. The plant would produce nearly 1500 G\aJh on an average
annual basis.
Due to some current questions regarding the feasibility of the Chaka-
chamna plant, it has not been included in the non-Susitna plan. It has
been checked, however, in the sensitivity analysis presented later in
this sect ion.
The Allison Creek Hydroelectric Project was included on the non-Susitna
base plan by Battelle. It has not been included in this base plan due
to its high costs ($125/MWh in 1981 dollars).
The thermal plan described above has been selected as representative of
the generation scenario that would be pursued in the absence of Susit-
rra. The selection has been confirmed by the Battelle results which
show an almost identical plan to be the 1 owest cost of any non-Susitna
plan.
4.7 -Economic Evaluation
This section provides a discussion of the key economic parameters used
in the study and develops the net economic benefits steaming fran the
Susitna Hydroelectric Project. Section 4. 7 (a) deals with those
econo.11ic principles relevant to the analysis of net economic benefits
and develops inflation and discount rates and the Alaskan opportunity
values (shadow prices) of oil, na:tural gas and coal. In particular the
ana 1 ys is is focused on the longer-term prospects for coal market~ and
prices. This folloWs from the evaluation that, in the absence of
Susitna, the next best thermal generation plan would rely on
exploitation of Alaskan coal. The future coal price is thetefore
considered in detai 1 to provide rigorous estimates of pric~s in the
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most likely alternative markets and hence the market price of coal at
the mine-head within the state~
Section 4.7 (c) presents the net economic benefits of the proposed
hydroelectric power investments compared with this thermal alternative ..
These are measured in terms of present valued differences between
benefits and costs. Recognizing that even the most careful estimates
will be surrounded by a degree of uncertainty, the benefit-cost
assessments are also carried out in a probabilistic framework as shown
in Section 4 .. 8. The. analysis therefore provides both a most likely
estimate of net economic benefits accruing to the state and a range of
net economic benefits that can be expected with a likelihood
{confidence level) of 95 percent or more.
(a) Economic Principles and Parameters
(i) Economic Principles -Concept of Net Economic Benefits
A necessary condition for maximizing the increase in state
income and economic growth is the selection· of public or
private investments with the highest present valued net
benefits to the state. In the context of Alaskan electric ·po~r investments, the net benefits are defined as the dif-
ference between the costs of optimal Susitna-incl usive and
Susitna-excl usi ve (all thermal) gene rat ion plans.
The energy costs of power generation are initially measured
in terms of opportunity values or shadow prices which may
differ from accounting or market prices currently prevail-
ing in the state. The concept and use of opportunity val-
ues is fundamental to the optimal allocation of scarce re-
sources. Energy investment decisions should not be made
solely on the basis of accounting prices in the state if
the international value of traded energy commodities such
as coal and gas diverge from local market prices.
The choice of a time horizon is also crucial. If a short-
tenn planning period is selected, the investment rankings
and choices will differ markedly from those obtained
through a long-term perspective. In other words, the
benefit-cost analysis would point to different generation
expansion plans depending on the selected planning period.
A short-run optimization of state income would, at best,
allow only a moderate growth in fixed capital investment;
at worst, it would lead to underinvestment in not only the
energy sector but al sc in other infrastructure facilities
such as roads, airports, hospitals, schools, and communica-
tions •
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It therefore follows that the Susitna Project, like other
Alaskan investments, should be appraised on the basis of
long-run optimization, where the long-run is defined as the
expected economic life of the facility. For hydroelectric
projects, this service life is typically 50 years or more.
The costs of a Susitna-inclusive generation plan have .
therefore been compared with the costs of the next-best
alternative which is the all-thermal generation plan and
assessed over a planning period extending from 1982 to
2040, using internally consistent sets of economic
scenatios ar.d appropriate opportunity values of Alaskan
energy ..
Throughout the analysis, all costs and prices are expressed
in real (inflation-adjusted) terms using January 1982 dol-
lars. Hence, the results of the economic calculations are
not sensitive to modified assumptions concerning the rates
of general ptice inflation. In contrast, the financial and
market analyses conducted in nominal (inflation-inclusive)
terms will be influenced by the rate of general price
inflation from 1982 to 2051. ··
(ii) Price Inflation and Discount 1ates
-General Price Inflation
-------------------~
Despite the fact that price levels are generally higher
in Alaska than in the Lower 48, there is little differ-
ence in the comparative rates of price changes; i .. e.~
price inflation. Between 1970 and 1978, for example, the
U .. S~ and Anchorage consumer price indexes rose at annual
rates of 6.9 and 7.1 percent, respectively. Froml977 to
1978, the differential was even smaller: the consumer
prices increased by 8. 8 percent and 8. 7 percent in the
U.S. and Anchorage (7).
Forecasts of Alaskan prices extend only to 1986 (8).
These indic~te an average rate of incr·ease of 8. 7 percent
from 1980 to 1986. For the 1 onger period between
1986 and 2010~ it is assumed that Alaskan prices will es-
calate at the overall U.S. rate, or at 5 to 7 percent
compounded annually. The average annual r·ate of price
inflation is therefore about 7 percent between 1982 and
2010.. Since this is consistent with long-term forecasts
of the CPI advanced by leading economic consulti.ng
organizations, 7 percent has been adopted as the study
V a, 110. ( Q 1{) \
• ""''-\ .,., ' ... " I •
-Discount Rates
Discount rates are required to compare and aggregate cash
flows occurring in different time periods of the pla.nning
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horizon. In essence, the discount rate is a weighting
factor reflecting that a dollar received tomorrow is
worth less than a dollar received today. This holds even
in an inflation-free economy as long as the productivity
of capital is positive. In other words, the value of a
dollar received in the future must be deflated to reflect
its earning power foregqne by not receiving it today.
The use of discount rates extends to both real dollar
(economic) and escalated dollar {financial) evaluations,
with corresponding inflation-adjusted (real) and
inflation-inclusive (nominal) values ..
• Real Discount and Interest Rates
Several approache.s have been suggested for estimating
the real discount rate applicable to public projects
(or to private projects from the public perspective).
Three common alternatives include:
.. the social opportunity cost (SOC) rate;
•. the social time preference (STP) rate; and
.. . the government! s rea 1_ borrowing rate or the real
cost of debt capital ( 11, 12, 13).
The SOC rate measures the real social return (before
taxes and subsidies) that capital funds could earn in
alternative investments. If, for example, the marginal
capital investment in Alaska has an estimated social
yield of X percent, the Susitna Hydroelectric Project
should be appraised using the X percent measure of
~•foregone returns" or opportunity costs. A shortcoming
for this concept is the difficulty inherent in deter-
mining the nature and yields of the foregone invest-
ments.
The STP rate measures society's prefere'lces for allo-
cating resources between investment and consumption.
This approach is also fraught with practical measure-
ment difficulties since a wide range of STP rates may
be inferred from market interest rates and socially-
desirable rates of investment.
A sub-set of STP rates used in project evaluations is
the owner • s real cost of borrowing; that is, the real
cost of debt capital. This industrial or government
borrowing rate may be readily measured and provides a
starting point for determining project-specific dis-
count rates. For example! long-term industri a1 bond
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rates have aver aged about 2 to 3 percent in the Ue S. in
real (inflation-adjusted) terms (9,14). Forecasts of
real interest rates show average values of about 3
percent and 2 percent in the periods of 1985 to 1990
and 1990 to 2000, respectively. The U.So ftlclear
Regulatory Comnission has also analyzed the choice of
discount rates for investment appraisal in the electric
utility industry and has reconmended a 3 percent real
rate ( 30). Therefore, a rea 1 rate of 3 percent has been
adopted as the base case discount and interest rate for
the period 1982 to 2040 •
. Nominal Discount and interest Rates
The nominal discount and interest rates are derived
from the real values and the anticipated rate of gen-.
eral price inflation.. Given a 3 percent real discount
rate and a 7 percent rate of price inflation, the nomi-
nal discount rate is determined as 10.2 percent or
about 10 percent*.
{iii} Oil and Gas Prices
-Oil Prices
In the base period (January 1982), the Alaskan 1982
dollar price of No. 2 fuel oil is estimated at $6.50/
f'MBtu ..
Long-term trends in oil prices wi 11 be inf1 uenced by
events that are economic, pol iticai and technological in
nature, and are therefore estimated within a probabilis-
tic framework.
As sho.wn in Table 0.16, the base case (most likely es-
calation rate) is estimated to be 2 percent to 2000 and 1
percent from 2000 to 2040. To be-consistent with
Battelle forecasts, a 2 oercent rate was used throughout
the OGP planning period 1982 to 2010 and 0 percent there-
after. In other scenarios the growth rates were
est~mated crt 0 percent from 1982-2051 {low growth); and
at 4 percent to. 2000, and 2 percent beyond 2000 (high
growth). These projections are also consistent with
* (1 +the nominal rate) = (1 +the real rate) x (1 +the inflation
rate) = 1. 03 x 1. 07, or 1.102
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/ ..
those recently advanced by such organizations as DRI
(15), World Bank (16), U.S. DOE (17)-, and Canadian
National Energy Board (18).
-Gas Prices
Alaskan gas prices have been forecast using both export
opportunity values (netting back CIF prices from Japan to
Cook Inlet) and domestic market prices as likely to be
faced in the future by Alaskan electric utilities. The
generation planning analysis used market prices as
estimated by Battelle, since· there are indications that
Cook Inlet reserves may remain insufficient to serve new
export markets •
. Domestic Market Prices
Table 0.17 depicts the low, medium and high domestic
market prices used in the 9eneration planning analysis.
In the medium {most likely) case, prices escalate at
real rates of 2. 5 percent from 1982 to 2000 and 2
percent beyond 2000. In the 1 ow case, there is zero
escalation and in the high case, gas prices grow at 4
percent 1982 to 2000 and 2 percent beyond 2000 •
. Export Opportunity Values
Table 0.17 also shows the current and projected oppor-
tunity value of Cook Inlet gas in a scenario where the
Japanese ex port market for LNG continues to be the al-
ternative to domestic demand. Fron a base period plant
gate price of $4.69 Mt4Btu ( CIF Japan), low, medium and
high price escalation rates have been estimated for the
intervals 1982 to 2000 and 2000 to 2040. The cost of
liquefaction and shipping (assumed to be constant in
real terms) was subtracted from the escalated CIF
prices to derive the Cook Inlet pl ant-g ..... te prices and
their growth rates. These Alaskan opportunity values
are projected to escalate at 2. 7 percent and 1. 2 per-
cent in the med i urn (most 1 ike 1 y) case. Nqte that the
export opportunity values consistently exceed the
domestic prices. In the year 2000, for examp1.e, the
opportunity value is nearly daub le the domestic. price
estimated by Battelle.
~iv) Coal Prices
The shadow price or opportunity value of Beluga and Healy
coal is the delivered price in alternative markets less the
cost of transportation to those markets. The most likely
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alternative demand for thermal coal is the East Asian
market, principally Japan, South Korea, and Taiwan. The
development of 60-year forecasts of coal prices in these
markets is conditional on the procurement policies of the
importing nations. These factors, in turn, are influenced
to a 1 arge extent by the price movements of crude o i 1.
-Historical Trends
Examination of historical coal price trends reveals that
FOB and CIF prites have escalated at annual real rates of
1.5 percent to 6.3 percent as shown below:
• Coal prices (bituminous, export unit value, FOO U.S.
ports} grew at real annual rates of 1.5 percent (1950
to 1979) and 2. 8 percent {1972 to 1979) (17). ·
In Alaska, the price of thermal coal sold to the GVEA
utility advanced at real rates of 2 .. 2 percent (1965 to
1978) and 2. 3 percent (1970 to 1978) •.
• In Japan, the average CIF prices of steam coal experi-
enced real escalation rates of 6. 3 percent per year in
the period 1977 to 1981 (26,27}. This represents an
increase in the average price from approximately $35.22
per metric ton (mt} in 1977 to about $76. 63/mt in 1981.
As shown below, export prices of coal are highly correl-
ated with oil prices, and an analysis of production costs
has not predicted accurately the level of coal prices.
Even if the production cost forecast itself is accurate,
it \vill establish a minimum coal price, rather than the
market clearing price set by both supply .and demand con-
ditions ..
• In real terms export prices of U.S .. coal showed a 94
percent and 92 percent correlation with oil prices
(1950 to 1979 and 1972 to 1979).*
• Supply function (product ion :::ost) analysis has
estimated Canadian coal at a price of $23.70 {1980 U.S.
$/ton) for S.E. British Columbia (B.C.) coking coal,
FOB Roberts Bank, B. C., Canada (24, 29). In fact, o
Kaiser Resources (now B. C. Coal Ltd.) has signed agree<L~
*Analysis is based on data from the World Bank.
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ments with Japan at an FOB Price. of about $47.50 {1980
U .. S. $/ton) (25). This is 100 percent more than the
price estimate based on production costs.
• The same comparison for Canadian· B. C. thermal coal in-
dicates that the expected price of $55.00 (1981
Canadian$) per MT {2200 pounds) or about $37.00 (1980
U.S. $) per ton ~ul d be 60 percent above estimates
founded on product ion costs {24, 25, 29).
• In longer-term coal export contracts, there has been
provision for reviewing the base price {regardless of
escalation clauses) if significant developments occur
in. pricing or markets. That is, prices may respond to
market conditions even before the expiration of the
contract.* ·
• Energy-importing nations in Asia, especially Japan,
have a stated pol icy of diversified procurement for
their coal supplies. They wi 11 not buy only from the
lowest-cost supplier (as would be the case in a per-
fectly competitive model of coal trade) but instead
wi 11 pay a risk premi urn to ensure security of supply
( 24, 29).
-Survey of Forecasts
Data Resources Incorporated is tJr'ojecti ng an average
annual real growth rate of 2. 6 percent for U.S. coal
prices in the period 1981 to 2000 {9). The World Bank has
forecast that the real price of steam cdal would advance
at approximately the same rate as oil prices (3
percent/ a) in the period 1980 to 19~ (16). Canadian
Resourcecon Limited has recently forecast growth rates of
2 percent to 4 percent (1980 to 2010) for subbituminous
and bituminous steam coal (28).
-Opportunity Value of Alaskan Coal
• Delivered Prices, CIF Japan
Based on these considerations, the shadow price of coal
{CIF price in Japan) was forecast using conditional
*This clause forms part of the recently concluded agreement between
Denison Mines and Teck Corporation and Japanese steel makers.
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probabilities given low~ medium, and high oil price
scenarios. Table 0.18 depicts the estimated coal price
growth rates and their associated probabilities, given
the three sets o( oil prices. Combining these proba-
bilities with those attached to the oil price cases
yields the following coal price scenarios, CIF Japan.
Scenario Probabi 1 itv Real Price Growth
Medi urn 49 percent 2 percent [ 1982-2000 l (most likely) 1 percent 2000-2040
Low 24 percent 0 percent ( 1982-2040)
High 27 percent 4 percent {1982 -2000)
2 percent {2000-2040)
The 1982 base period price was initially estimated
using the data from the Battelle Beluga Market Study
(24). Based on this study, a sample of 1980 spot
prices (averaging $1. 66/MMBtu) was escalated to January
1982 to provide a starting value of $1.95/MMBtu in
January 1982 dollars.* •
As more recent and more comp1 ete coal import price sta-
tistics became available, this method of estimating
was found to give a significant underestimate of actual
CIF prices. By late 1981, Japan•s average import price
of steam coal reached $2. 96/MMBtu. ** An important
sensitivity case was therefore developed reflecting
these updated actual CIF prices o The updated base
period value of $2.96 wa.s reduced by 10 percent to
$2.66 to recognize the price discount dictated by
quality differentials between Alaskan coal and other
*The escalation factor was 1. 03 x 1.14, where 3 percent is the fore-
cast real growth in prices (mid-1980 to January 1982) at an annual
rate of 2 percent, and 14 percent is the 18-month increase if .the CPI
is used to convert from mid-1980 dollars to January 1982 dollars.
** As reported by Coal Week International in October 1981, the average
GIF value of steam -.:>al was $75.50 per MT. At an average heat value
of 11,500 Btu/lb, this is equivalent to $2 .. 96/MMBtu.
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sources of Japanese coal imports, as estimated by Battelle (24).
Opportunity Values in Alaska ~~----~-------------
.• Base Case -Battelle-based CIF Prices,
No Export Potential for Healy Coal
Transport at ion costs of $0. 52/MMBtu were subtracted
from the initially estimated CIF price of $1.95 to
detennine the opportunity value of Beluga coal at
Anchorage. In January 1982 dollars, this base
period net-back price is therefore $1. 43. In subse-
quent years, the opportunity value is derived as the
difference between the escalated CIF price and the
transport cost (estimated to be constant in real
terms). The real growth rate in these FOB prices is
determined residually from the forecast opportunity
values. In the medium (most likely) case, the
Beluga opportunity values escalate at annual rates
of 2. 6 percent and 1. 2 percent during the· intervals
1982 to 2000 and 2000 to 2040, respectively.
For Healy cc3.1, it was estimated that the base
period price of $1. 75/MMBtu (at Healy) would also
escalate at 2.6 percent {to 2000} and 1.2 percent
(2000 to 2040). Adding the escalated cost of trans-
port at ion from Healy to Nenana results in a January
1982 price of $1.75/t1v1Btu.* In subsequent years,
the cost of transportation (of which 30 percent is
repr·esented by fuel cost which escalates at 2
percent) is added to the Healy price, resulting in
Nenana prices that grow at real rates of 2. 3 percent;
(1982 to 2000) and 1.1 percent {2000 to 2040).
Table 0.18 summarizes the real escalation rates
applicable to Nenana and Beluga coal in the low,
:nedium, and high price scenarios •
• . Sensitivity Case -Updated CIF Prices)
Export Potential for Healy Coal
The updated CIF price of steam coal ($2.66/MMBtu
after adjusting for quality differentials) was re-
duced by shipping costs from Healy and Beluga to
Japan to yield Alaskan opportunity values. In
*Transportation costs are based on Battelle (18, 23).
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(b)
January 1982, prices were $2.08 and $1.74 at
Anchorage and Nenana, respectively. The differences
between escalated CIF prices and shipping costs
result in ·FOB prices that have real growth rates· of
2. 5 percent and 1. 2 percent for Be 1 uga coal and 2. 7
percent and 1. 2 percent for Healy coal (at Nenana).
Table 0.18 shows escalation rates for the
opportunity value of Alaskan coal in the low,
medium, and high price scenarios, using updated base
period values.
(v) Generation Planning Analysis -Base Case Study Values
Based on the considerations presented in ( i) through ( i v)
abov·e, a consistent set of fuel prices was assembled for
the base case probabilistic generation planning {OGP5)
analysis, as shown in Table 0.19. The study values include
probabilities for the low, medium and high fuel price
scenarios. The probabilities are common for the three
fuels (oil, gas and coal) within each scenario in order to
keep the number of generation planning runs to manageable
size. In the case of the, natural gas prices, domestic
market prices were selected for the base case analysis with
the export opportunity values used in sensitivity runs.
The base period value of $3 was derived by deflating the
1996 Battelle prices to 1982 by 2. 5 percent per year. Coal
prices were also selected from the base case using
Battel1e's 1980 sample of prices as the starting point,
with the updated CIF prices of coal reserved for
sensitivity runs. Oil prices have been escalated by 2
percent (1982 to 2040).
Analysis of Net Economic Benefits
(i) Modelinq Approach
Using the economic parameters discussed in the previous
sect ion and data relating to the electrical energy genera-
tion alternatives available for the Railbelt, an analysis
was made comparing the costs of electrical energy produc-
,}ion with and without the Susitna project. The primary
too1 for the analysis was a generation planning model
{0Gf'5) which simulates production costs over a planning
period extending from 1982 to 2010.
The roethod of comparing the "with" and 11 without" Susitna
alternative generation scenarios is based on the long-term
present worth (PW) or total system costs. The planning
model detenni nes the total product ion costs of alternative
p1 ans on a year-by-year basis. These total costs for the
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period of modeling include all cpsts of fuel and operation
and maintenance (O&M) for all generating units included as
part of the system, and the annualized investment costs of
any generating and system transmission plants added during
the period of 1993 to 2010. Factors which contribute to
the ultimate consumer cost of power but which are not in-
cluded as input -to this model are investment costs for all
gener·ation plants in service prior to 1993 investment, cost
of the transmission and distribution facilities already in
service, and administrative costs of utilities. These
costs are common to all scenarios and therefore have been
omitted from the study.
In order to aggregate and compare costs on a si gni fi c antl y
1 ong-tenn basis, annual costs have been aggregated for the
period of 1993 to 2051. Costs have been computed as the
sum of two components and converted to a 19~ PW. The
first component is the 1982 PW of cost output from the
first 18 years of model simulation from 1993 to 2010. The
second component is the estimated PW of long-term system
costs from 2011 to 2051.
For an assumed set of economic parameters on a particuiar
generation alternative, the first element of the PW value
represents the amqunt of cash (not including those costs
noted above) needed in 1982 to meet electrical production
needs in the Railbelt for the period 1993 to 2010. The
second element of the aggregated PW value is the long-term
( 2011 to 2051) PW estimate of production costs. In consi d-
ering the value to the system of the addition of a hydro-
electric power plant which has a useful life of
approximately 50 years, the shorter study pel"iod would be
inadequate. A hydroelectric plant added in 1993 or 2002
would accrue PW benefits for only 17 or 9 years,
res~ectively, using an investment horizon that extends to
2010~ However, to model the system for an additional 40
yei=lrs it would be necessary to develop future load
forecasts and generation alternatives which are beyond the
realm of any prudent prcjections. For this reason, it has
been assumed that the production costs for the final study
year (2010) would simply reoccur for an additional 41
years, and the PW of these was added to the 18-year PW
(1995 to 2010) to establish the long-term cost differences
between alternative methods of power generation.
(ii) ~ase Case Analysis
-Pattern of Investments "With 11 and "Without" Susitna
The base case comparison~ of the 11 with" and uwi tho ut 11
Susitna plans is based on an assessment of the PW produc-
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tion costs for the period 1993 to 2051, using mid-range
values for the energy demand and load forecast, fuel
prices, fuel price escalation rates, capital costs, and
capital cost escalation rates~
The with-Susitna plan calls for 680 MW of generating
capacity at Wata11a. to be avail able to the system in 1993.
Al thou~h the project may come on-1 ine in stages during
that year, for modeling purposes full-load generating
capabi 1 ity is assumed to be avail ab 1 e for the entire
year. The second stage of Sus i tna, the Devi 1 Canyon
project; is scheduled to come on-line in 2002. The
optimum timing for the addition of Devil Canyon was
tested for earlier and 1 ater dates. Add it ion in the year
2002 was found to result in the lowest long-term cost.
Devil Canyon will have 600 MW of installed capacity.
The without-Susitna plan is discussed in Section 4.5. It
includes three 200MW coal-fired plants added at Beluga
in 1993, 1994, and 2007. A 200 MW unit is added at
Nenana i~ 1996 and nine 70 MW gas-fired combustion
turbines (GTs) would be added during the 1997 to 2010
period. ·
-Base Case Net Economic Benefits
The economic comparison of these plans is shown in
Table D.20. During the 1993 to 2010 study. period, the
19~ PW cost for the Susitna plan is $3.119 bill ion.. The
annual p~oduction cost in 2010 is $0.385 billion. The~~
of this level cost, which remain·s virtually constant for
a period extending to the end of the life of the Devil
Canyon plant (2051), is $3.943 billion. The resulting
total cost of the with-Susitna plan is $7.06 billion in
1982 dollars, presently valued to 1982.
The non-Susitna plan (Section 4~5) which was modeled has
a 1982 PW cost of $3.213 billion for the 1993 to 2010
periods with a 2010 annual cost of $0.491 billion. The
total long-tenn cost has a PW of $8.24 bill ion.
Therefore, the net economic benefit of adopting the
Susitna plan is $1.18billion. In other,words~ the
present valued cost difference between ~he Susitna plan
and the ex pans ion plan based on thennal plant add it ion is
$1ol8 billion in 1982 dollars. This is equivalent to a
1982 per capita net economic benefit of $2,700 per capita
for the 1982 population of the State of Alaska.
Expressed in 1993 dollars (at the on-1 i ne d::tte of
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Watana)~ the net benefits would have a levelized value of
$2.48 billion.*
It is noted that the magnitude of net economic benefits
($1.18 billion) is not particularly sensitive to alterna-
tive assumptions concerning the overall rate of price in-
flation as measured by the Consumer Price Index. The
analysis has been carried out in real (inflation-
adjusted) tenns.. Therefore, the present valued cost
savings will remain close to $1.18 billion regardless of
CPI movements, as long as the real (inflation-adjusted)
discount and interest rates are maintained at 3 percent.
The Susitna project!s internal rate of return {IRR),
1~e., the real (inflation-adjusted) discount rate at
w~·tich the with-Susitna_ plan has zero net econo.-nic bene-
fit~, or the discount rate at which the costs of the
with -Susi tna and the alternative plans have equal costs,
has ai so been determined. The IRR is about 4 .. 1 pe.rcent
in real terms, and 11.4 percent in nominal [inflation-
inclusive) terms. Therefore, the investment 1n Susitna
would significantly exce·ed the 5 percent naninal rate of
return 11 test 11 proposed by the State of Alaska in cases
where state appropriations may be involved.**
It is emphasized that these net economic benefits and the
rate of return stemning from the Susitna project are in-
herently con serv at i ve estimates due to several assump-
tions made in the OGPS analysis.
. Zero Growth in Long-term Costs
From 2010 to 2051, the OGPS analysis assumed constant
annual production costs in both the Susitna and non-
Susitna plans. This has the effect of excluding real
escalation in fuel prices and the capital co~ts of
thennal plant replacements, and thereby understating
the long-term PW costs of thermal generation plans •
. Loss of Load Probabilities
The loss of load probability in the non-Susitna plan is
calculated at 0.099 in the year 2010. This means that
* $1.18 billion times 2.105, where 2.105 is the general price
inflation index for the period 1982 to 1993.
** See State of A1 aska • s SB -25, Section 44. 83.670.
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the system in 2010 is on the verge of adding an addi-
tional plant, and would do so in 201L These costs are
however, not included in the analysis, which is cut off
at 2010. On the other hand, the Susitna plan has a
loss of load probability of 0. 025, and .may not requir·c
additional capacity for several years beyond 2010.
~ Long-term Energy From Susitna
Some of the Susitna energy output (about 350 G~lh) is
still not used by 2010. This energy output would be
available to meet future increases in projected demand
in the summer months. No benefit is attributed to this
energy in the analysis.
• Equal Environmental Costs
The generation planning analysis has implicitly assumed
equal environmental costs for both the Susi tna and the
non-Susitna plans. To the extent that the thermal
generation expansion plan is expected to carry greater
environmental costs than the Susitna plan, the economic
cost savings fran the Susi tna project are understated.
It is conceivable that these so-called negative
externalities from coal-fired electricity generation
wi 11 have been mitigated by 1993 and beyond as a result
of the enactment of new environmental legislation.
(iii) Sensitivity Analysis
Rather than rely on a single point cc:>11parison to assess the
net benefit of the Susitna project, a sensitivity analysis
was carried out to identify the impact of modified assump-
tions on the results. The analysis was directed at the
fo 11 owing vari ab 1 es:
-Load forecast;
-Real interest and discount rate;
-Construction period;
-Period of analysis;
-ca'pit al costs;
• Susi tna
• Thermal alternatives
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-O&M costs;
-Base period fuel price;
-Real e!:J~alation in capital costs, O&M costs, and fuel
prices;
-System re1·iability;
-Chackacharnna; and
-Susitna Project delay.
Tables 0.22 to 0.29 depict the results of the sensitivity
analysis.. In particular, Table 0.29 surrmarizes the net
economic benefits of the Susitna Project associated with
each sensitivity test. The net benefits have been compared
using indexes relative to the base Lase value ($1 .. 176
bill ion) which is set to 100.
Tne greatest variability in results occurs in sensitivity
tests pertaining to fuel escalation rates, discount rates,
and base period coal prices. For example~ a scenario with
high fuel price escalation results in net benefits that
have a value of 253 relative to the base case. In other
words~ the high case provides 253 percent of the base case
net benefits. In general, the Susitna plan maintains its·
positive net benefits over a reasonably wide range .of
values assigned to the key variables.
A multivariate analysis in the fonn. of probability trees
has been undertaken to test the joint effects of varying
several assumptions in combination rather than individual-
lye This probabilistic analysis reported in Section 4.7
provides a range of expected net economic benefits and
probability distributions that identify the chances of
exceeding particular values of net benefits at given levels
of confidence.
4.8 -Probability Assessment
{a) Multivariate Sensitivity Analysis
The feasibility study of the Susitna Hydroelectric Project in-
cluded an economic analysis based on a comparison of generation
system product ion costs with and without the proposed project
using a computerized model of the Railbelt generation system. In
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(b)
order to carry out this analysis, numerous projections and fore-
casts of future conditions were made. These forecasts of uncer-
tain conditions include future electrical demand, costs, and esca-
lation. In order to address these uncertain conditions, a sensi-
tivity analysis on key factors was carried out. This analysis
focused on the variance of each of a number of forecast conditions
and determined the impact of variance on the economic feasibility
of the project. Each factor was varied singularly with all other
var:iables held constant to determine clearly its importance.
The purpose of this multi v ari ab 1 e analysis was to select the most
critical and sensitive variables in the economic analysis and to
test the economic feasibility of the Susitna Project in each pas-
sib 1 e combination of the selected \fari ab 1 es.
While a number of variables were identified and tested in the
single variable sensitivity analysis fot the Susitna economic
feasibility study, the variables which were chosen for the multi-
variate sensitivity analysis represent the key issues such as load
forecasts, capita1 cost of alternatives, fuel escalation and
Susitna capital cost.
The methodology for the multivariate .:1nalysis was implemented by
constructing probability trees of future conditions for the Alaska
Railbelt electrical system, with and without the Susitna Project.
Each branching of the tree represents three values for a given
variable. These were assigned a high, medium, and low value as
well as a corresponding probability of occurrence. The three
values represent the expected range and mid-point for a given
variable. In some cases, the mid-point represents the most likely
value which would be expected to occur. End 1 imbs of the proba-
bility tree represent scenarios of mixed variable conditions and a
probability of occurrence of the scenario.
The OGP 5 product ion cost model was then used to detenni ne the PW
(in 1982 dollars) of the long-term cost of the electric generation
related to each variable. The PW of the long-tenn costs for each
"with" and 11 Without" Susitna scenario in terms of cumulative pro-
bability of occurrence were determined and plotted. Net benefits
of the project have also been calculated ~nd analyzed in a proba-
bilistic manner.
Figures 0.17 and 0.18 present the non-Susitna and Susitna proba-
bility trees with resultant long-term costse
Co~parison of Long-term Costs
Figure 0.19 presents the two histograms of long-term costs for the
11 with" and "without 11 Susitna cases plotted on the same axes. From
these plots it is seen that the non-Susitna plan costs could be
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expected to be significantly less than the Susitna plan costs for
about 6 percent of the time, approximately equal to the Susitna
costs 16 percent of the time~ and significantly greater for 78
percent of the time.
A comparison of the expected value of long-term costs of the 11 With" and 11 without11 Susitna 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 Susitna LTC of $7.03 billion.
(c) Net Benefit Comparison
A second method of comparing the 11with 11 and 11 Withoutu Susitna pro-
bability trees is by making a direct comparison of similar scen-
arios and calculating the net benefit which applies. As in the
case nf the individual tree cases~ the net benefits were ranked
from low to high and plotted against cumulative probability. This
graph has been represented as a single line due to the number of
points on the curve. It~ however~ would be most accurately por-
trayed as a histogram in the manner of Figure 0.19. The net bene-
fits vary from a negative $2.92 billion with an associated proba-
bility of .0015 to a high of $4.80 billion with an associated
probability of .018. The single comparison with the highest pro-
bability of occurrence of .<L108 has a net benefit of $2.09 billion.
Figure 0.20 plots the net benefit with the cross-over between the
11 With" and "without" Susitna costs occurring at about 23 percent.
This is consistent wi~h the previous comparison and with the ex-
pected value net benef;t calculated by this method of $1.45 bil-
lion.
(d) Sensitivity of Results to Probabilities
In assigning the probabilities of occurrence for each set of vari-
ables, a number of subjective assumptions were made. An exception
was the Susitna capital cost probability distribution which was
supported by a probabilistic 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 exceedence of approximately 10
percent for the high level of demand.
Capital costs for alternative generation modes estimated in the
Battelle study reflect a 0.20~ 0 .. 60 and 0.20 distribution~ again
within a range of a 90 percent chance of exceedence of the low and
10 percent exceedence of the high level.
The single variable to which the results are most· sensitive is the
r·ate of real fuel escalation adopted. (This conclusion is sup-
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ported by the single variable analysis as well.) The distribution
o~ probabilities was 0.25, 0.50 and Q25 for low, medium and high
fuel cost escalatton scenarios. A case can be made for the argu-
ment that some of the combined events, for example high fuel cost
escalation, load and capital cost are not (as our results assume)
independent of each other. High fuel prices, it may be argued,
\'.OUld result in lower load and increased capital cost. It is pro-
bable, however, that the greater revenues consequent on higher
fuel prices would result in greater economic activity in Alaska
thus increasing demand for ene.rgyo This and other considerations
1 ed to the conclusion that the results would be relatively insen-
sitive to probable ranges of interdependence.
4. 9 -Battelle Railbelt Alternatives Study
[Note to Power Authority -This section wi 11 be revised u pan receipt of
the final (and extensively revised) Battelle reports.] .
The Office of the Governor, State of Alaska, Division of Policy
Development and Planning and the Governor's Policy Review Committee
contracted with Battelle, Pacific Northwest Laboratories to investigate
potential strategies for future electric power development in the
Rail belt region of Alaska. This sect ion presents a sumnary of final
results of the Railbelt Electric Power Alternatives Study.
The overall approach taken on this study involved five major tasks or
activities that lead to the results of the project,-a comparative
evaluation of electric energy plans for the Railbelt. The five tasks
conducted as part of the study evaluated the fo 11 owing aspects of
electrical power planning: ·
-fuel supply and price analysis
-electrical demand forecasts
-generation and r.onservation alternatives evaluation
-development of electric energy themes or 11 futures 11 avail able to the
Rail belt
-systems integration/evaluation of electric energy plans.
Note that while each of the tasks contributed data and infonnation to
the final results of the project, they also developed important results
that are of interest independent of the final· results of this project.
The first task evaluated the price and availability of fuels that
either directly could be used as fuels for electrical generc.tion or
indirectly could compete with electricity in e-;j-use applications such
as· space or water heating.
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The second task, electrical demand forecasts~ was required for two
reasons.. The amount of e1 ectricity demanded detennines both the size
of generating units that can be 'included in the system and the number
of generating units or the total generating capacity required. The
forecast used from this study in the Susitna feasibility study is
presented in Exhibit B.
The third task • s purpose was to identify electric power generation and
conservation alternatives potentially applicable to the Railbe1t region
and to examine their feasibility, considering several factors. These
factors include cost of power, environmental and socioeconomic effects,
and public acceptance. Alternatives appearing to be best suited for
future application to the region were then subjected to additional
in-depth study and were incorporated into one or more of the electric
energy plans.
The fourth task, the development of electric energy themes or plans~
presents possible electric energy nfuturesn for the Railbe1t. These
plans were developed both to encompass the full range of viable
alternatives available to the region and to provide a direct comparison
of those futures currently receiving the greatest interest w·i thin the
Railbelt. A plan is defined by a set of electrical generation and
conservation alternatives sufficient to meet the peak demand and annual
energy requirements over the time horizon of t~e study. The time
horizon of the study is from 1981-2050 time period. The set of
alternatives used in each plan \'las drawn from the alternatives selected
for further study in the analysis of al ter·natives task.
As the name implies, the purpose of the fifth task, the system
integration/comparative analysis task, was to integrate the results of
the other tasks and to produce a comparative evaluation of the electric
energy plans. This comparative eva1 uation basically is a description
of the implications and impacts of each electric energy plan. The
major criteria used to evaluate and compare the plans are cost of
power, environmental and socioeconomic impacts, as well as the
susceptibility of the plan to. future uncertainty in assumptions and
parameter estimates.
This summary focuses on the third, fourth and 'fifth tasks: alternatives
ev a 1 u at ion, p 1 an d eve 1 o pmen t and p 1 an com pari son .
(a) Alternatives Evaluation
The Battelle study reviewed a much :'/ider range of generating
alternatives than the Susitna feasibility study. The following
text summarizes the process followed and results of selecting
technologies for developing energy plans.
Selecting generating alternatives for the Railbelt electric energy
plans proceeded in three stages. First, a broad set of candidate
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technologies was identified, constrained only by the availability
of the technology for corrmerci al service prior to year 2000.-
After a study was prepared on the candidate technologies, they
were evaluated based on several technical, economic, environmental
and institutional considerations. Using the results of that
study, a subset of more promising t~chnd1ogies subsequently was
identified. Finally, prototypical gener~ting facilities (specific
sites in the case of hydropower) were identified for further
development of the data required to support the analysis of
electric energy plans.
A wide variety of energy resources capable of being applied to the
generation of electricity is found in the Railbelt. Resour·ces
currently used include coal~ natural gas, petroleum~derived
1 i quids and hydropower. Energy resources currently not being used
but which could be developed for pt"oducing electric power within
the planning period of this study include peat, wind power, solar
energy, municipal refuse-derived fuels, and ~od waste. Light
water reactor fuel is manufactured in the "lower 48" states and
could be readily supplied to the Railbelt, if desired. Candidate
electric generating technologies using these resources and most
likely to be available for commercial order prior to year 2000 are
listed in Table 0.30. The 37 generation technologies and
combinations of fuel conversion -generation technologies shown in
the table comprised the candidate set of technologies selected for
additional study. Further discussiqn of the selection process and
technologies rejected from consideration at this stage are
provided in Reference 33.
Selection of generation alternatives was based on the followinng
considerations:
-the avai 1 ability and cost of energy resources;
-the 1 i kely effects of minimum plant size and operational
characteristics on system operation;
-the economic perfonnance of the various technologies as
refl ect~d in estimated busbar power costs;
-pub 1 ic acceptance, both as reflected in the fr arne work of
electric energy plans within which the selection was conducted
and as impacting specific technologies; and
-ongoing Rail belt electric power planning activities. ?
From this analysis, described morefully in Reference 33~ 13
generating technologies were selected for possible inclusion in
the Railbe.lt electric pov1er plans. For each nonhydro technology,
a prototypical plant was defined to facilitate further development
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of the needed information. For the hydro technologies, prom1s1ng
sites were selected for further study. These prototypical plants
and sites consi stute the gener3.ting alternatives selected for
consideration in the Railbe.lt electric energy plans. In the
follov1ing paragraphs, each of the 13 preferred technologies is
briefly described, along with some of the principal reasons for
its selection. Also described are the prototypical plants and
hydro sites selected for further study.
{i) Coal-Fired Steam-Electric Plants
Coal-fired steam-electric generation was selected for
consideration in Railbelt electric energy plans because it
is a corrmerci aily mature and economical technology that
potentiallY is capable of supplying all of the Railbelt's
base-load electric power needs for the indefinite future.
An abundance of coal in the Railbelt should be mineable at
costs .allowing electricity production to be economically
competitive with all but the most favorable alternatives
throughout the planning period. The extremely low sulfur
content of Railbelt coal and the availability of
commercially tested oxides of sul pher {SOx) and partic-
ulate control devices wi 11 facilitate control of these
emissions to levels mandated by the Clean Air Act.
Principal concerns of this technology are environmental
impacts of coal mining, possible a~bient air-quality
effects of residual SOx, oxides of nitrogen (NO~) and
particulate emissions, long-term atmospheric bu1ldup of co 2 (common to all combustion-based technologies) and the
1 ong tenn susceptibility of busbar power costs to
inflation.
Two prototypical fac il it i es were chosen for in-depth study:
in the Beluga area a 200-MW plant that uses coal mined from
the Chutna Field, and at Nenana a plant of similar capacity
that uses coal delivered from the Nenan field at Healy by
Alaska Railroad. The results of the prototypical study are·
documented in Reference 34.
(ii) Coal Gasifier-Combined-Cycle Plants
These plants consist of coal gasifiers producing a
synthetic gas that is burned in combustion turbines that
drive electric generators. Heat~recovery boilers use
turbine exhaust heat to raise steam to drive a steam
turbine-generator.
These plants, when commercially available, should allow
continued use of Alaskan coal resources at costs comparable
to conventional coal steam-electric plants~ \'Alile providing
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envirom~ntal and operatio~al advantages compared to
convent1ona1 plants. Env1ronmental advantages include less
waste-heat rejection and water consumption per unit of
output due to higher plant eficiency. Better control of
NOx, SOx and particu1 ate emission is also affor-ded.
From an operational standpoint, these plants offer a
potential for load-following operation, broadening their
application to intennedi ate loading duty. (However, much
of the existing Railbelt capacity most likely will be
avail able for intennedi ate and peak loading during the
planning period.) Because of superior plant efficiencies,
coal gasified-combined-cycle p'lants should be somewhat
less susceptible to 'inflation fuel cost than conventional
steam-electric plants. Principal concerns relative to
these plants include 1 and disturbance resulting from mining
of coal, C02 production, and uncertainties in plant
performance and capital cost due to the current state of
technology development.
A prototypical plant was selected for in-deRth analysis.
This 200 MW plant is located in the Beluga area and uses
coal mined from the Chuitna Field. The plant would use
oxygen-blown gasifiers of Shell design, producing a medium
Btu synthesis gas for combustion turbine firing~ The plant
\"K>Uld be capable of load-following operation. The results
of the study of the prototypical plant are described in
Reference 35 ..
(iii) Natural Gas Combustion Turbines
Although of relatively lo~l efficiency, natural gas
combustion turbines serve we 11 as peaking units in a system
dominated by steam-electric plants. The short construction
lead times characteristic of these units also offer
opportunities to meet unexpected or temporary increases in
demand. Except for production of co 2, and potential
local noise problems, these· units produce minimal environ-
mental impact. The principal economc concern is the
sensitivity of these plants to escalating fuel costs.
Because the costs and performance of combustion turbines
are relatively well understood, and because a major
component of future Railbelt capacity additions most likely
would not consist of combustion turbines, no prototype was
selected for in-depth study.
(iv) Natural-Gas ~Combined-Cycle Plants
Natural gas -combined-cycle plants were selected for
conside.at ion because of the current availability of low-
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( v)
(vi)
cost natural gas in the Cook Inlet area and the likel_y
future avail aoil ity of North Slope supplies in the Ra1lbelt
(although at prices higher than those currently
experienced). Combined-cycle plants are the most econom-
ical and environmentally benign method currently available
to generate electric power using natural gas. The
principal economic concern· is the sensitivity of busbar
power costs to the possi.ble substantial rise in natural gas
costs. The principal environmetnai concern is C02
production and .possible local noise problems ..
A nominal 200 MW prototypical p1 ant was selected for
further study. The plant is located in the Beluga area and
uses Cook Inlet natura.l gas. The results of the analysis
of this prototype are documented in Reference 35.
Natural Gas Fuel-Cell Stations
These plants would consist of a fuel conditioner to convert
natural gas to hydrogen and C02, phosphoric acid fuel
cells to produce de power by electrolytic oxidation-of
hydrogen, a power conditioner to convert the de power
output of the fuel cells to ac power. Fuel-cell stations
most likely would be relatively small and sited near load
centers.
Natural gas fuel-cell stations were considered in the
Railbe1t electric energy plans primarily because of the
apparent peaking duty advantages they may offer over
combustion turbines for systems relying upon coal or
natural-gas fired base an:.J i· ... termediate load units. Plant
efficiencies most likely 1;1~··1 be far superior to combustion
turbines and relatively unaffected by partial ·po\'er
operation. Capital inve~tment cost most likely will be
com par ab 1 e to that of combust ion turbines. These cost and
performance characteristics should lead to sign~ficant
reduction in busbar power costs, and greater protect·ion
from escalation of natural gas prices compared to
combustion turbines. Construction lead time should be
comparable to those of combustion turbines. Because.
environmental effects most likely will be limited to co, ....
production, load-center siting will be possible and
transmision losses and costs consequently will be reduced.
No prototypical plant was selected for further study ..
/ .... (
Natur·al-Gas -Fuel-Cell -Combined-Cycle
These plants would consist of a fuel conditioner that
converts natural gas to hydrogen and carbon dioxide, molten
car~?onate fuel cells that produce de power by elet:trolytic
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oxidation ·of hydrogen, and heat recovery boilers that use
waste heat from the fuel cells to raise stean fm"" driving a
steam turbine-generator. A power conditioner converts the
de fuel cell power to ac power for distribution. If they
attain commercial maturity as envisioned, fuel-cell
combined-cycle plants should demonstrate a substantial
improvement in efficiency over conventional~ combustion
turbine-combined-cycle plants. Although the potential
capital costs of these p1 ants currently are not we 11 know,
the reduct ion in fuel consumption promised by the
forecasted heat rate of these plants waul d result in a.
baseload plant less sensitive to inflating fuel costs and
less consumptive of limited fuel supplies than conventional
combined-cycle plants. An added advantage is the likely
absence of significant environmental impact.
Operationally, these plants appear to be less flexible than
conventional combined-cycle plants and will be limited tc.
baseload operation.
Because of the early stages of development of these plants,
additional study within the scope of this project was
believed to yield little additional useful information.
Consequently, no prototypical plant was selected for
study.
(vii) Conventional Hydroelectric Plant~
Substantial hydro resources are pre sent in the Rai lbel t
region. Much of this caul d be developed with conventional
(approximately 15 MW installed capacity or larger) hydro-
electric plants. The data and alternatives considered were
the same as those discussed in Section 3 of this exhibit.
(viii) Small-Scale Hydroelectric Plants
Small-scale hydroelectric plants include facilities having
rated capacity of Oo 1 t4W to 15 MW. Several small-scale
hydro sites have been identified in the Railbelt and two
currently undeveloped sites (Allison and Grant Lake) have
been subject to recent feasibility studies. Although
typically not as economicarl y favorab 1 e as conventional
hydro because of higher capital costs, small-scale hydro
affords similar long-term protection from escalation of
costso
Two small-scale hydroelectric projects were se 1 ected for
consideration in Railhelt electric energy plans: the
A11ison Hydroelectrit ?roject at Allison Lake near Valdez
and the Gr .. ant Lake Hydt~oelectric Project at Grant Lake
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north of Seward. These two projects appear· to have
relatively favorable economics compared with other small
hydroelectric sites, and relatively minor environmental
impact.
(ix) Microhydroelectric Systems
Microhydroelectric systems are ;·:ydroelectric installations
~rated at 100 kW or less. They typically consist of a
water-intake structure, a penstock, and turbine-generator.
Reservors often are not provided and the units operate on
run -of-the-stream.
Microhydroel ectric systems were chosen for analysis because
of public interest in these systems~ their renewable
character and potentially modest, environmental inpact.
Concrete. in format ion on power product ion costs typical of
these facilities were not available vmen the preferred
technologies were se·lected. Further analysis indicated,
however, that few michrohydroel ectric reservoirs cou1 d be
developed for 1 ess than 80 mi 11 s/kWh and even at
considerably higher rates, the contribution of this
resource \\Ould likely be minor. Beca_use of the very
1 imited potential of this te..;hnology in the Railbelt, it
was subsequently dropped from consideration. However,
installations at certain sites, for exemple residences or
other facilities remote from distribution systems, may be
justified.
(x) Large Wind Energy Conversion Systems
Large wind energy conversion systems consist of machines of
100 kW capacity and greater. These systems typically would
be installed in clusters in areas of favorable wind
resource and would be operated as central generating units ..
Operation is in the fuel-saving mode because of the
intermittent nature of the. wind resource.
Large w~nd .energy conversion systems were selected for
consideration in Railbelt el~ctric nergy plants for several
reasons. Several areas of excellent wind resource have
been identfi ed in the Rail belt, no tab 1 y in the Isabell Pass
area of the Alaska Range, and in coastal locations. The
winds of ~hese areas are strongest during fall~ winter and
spring months, coinciding with the. winter-peaking electric
1 oad of the Rai 1 belt. Furthermore, developing
hydroelectric projects in the Rai lbelt would prove
complernentary to wind energy systems. Surplus
wino-generated electricity could be readily ustorerf• by
reducing hydro generation. Hydro operation could be used
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to rapidly pick up load during periods of wind
insufficiency. \~ind machine.s could provide additional
energy~ whereas excess installed hydro capacity could
provide capacity credit. Finally, wind systems have few
adverse environmental effects with the except ion of their
visual presence and appear to have widespread public
support.
A prototypical large wind energy conversion system was
selected for further study. The prototype consisted of a
wind farm located in the Isabell Pass area and was
comprised of ten 2. 5 MW rated capacity, Boeing MOD-2,
horizontal axi-s wind turbines. The results of the
prototype studied are provided in Reference 36.
(xi) Small Wino ~nergy Conversion Systems
• f
Small wind energy conversion systens are small wino
turbines of either horizontal or vertical axis, desig~
rated at less than 100 kW capacity. Machines of this size
\'tDUld generally be dispersed in individual households and
in conmercial establishments.
Small wind energy conversion systems were selected for
consideraton in Railbelt electric energy plar~ for several
reasons.. Within the Rai 1 belt, se 1 ected area:· :1ave been
identified as having superior wind re:.-:ource potential.
Another reason for selection is because the resource is
renewable. Finally, power produced by these systens
appeared to possibly be marginally economically competitive
with generating facilities currently operating in the ·
Rai 1 belt. However, these machines operate in a fue 1-saver
mode because of the intermittent nature of the wind
resource, and because their economic performance can be
analyzed only by comparing the busbar power cost of these
machines to the energy cost of power they could displace ..
Data for further analysis of small wind energy conversion
systems were taken from the technology profiles. Further
analysis of this alternative indicated that 20 MW of
installed capacity producing approximately 40 G\~h of
electric energy possible. could be economically developed at
80 mill marginal power costs~ under the highly unlikely
assumption of full penetration of the avail able market
(households). Furthermore, in this analysis these machine.s
were give parity-with firm generating alternatives for cost
of power comparisons. Because the potential contribution
of this alternative is relatively minor even under the
rather liberal assumptions of this analysis, the potential
energy production of small wind energy conversion systems
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was not included in the analysis of Railbelt electric
energy plans.,
{xii) Tidal Power
Tidal power plants typically consist of .a "tidal barrage"
extending across a bay or inlet that has substantial tidal
fluctuations. The barrage contains sluice gates to admit
water behind the barrage on the incoming tide, and
turbine-generator units to generate power on the outgoing
tide.. Tidal power is intennittent, avail able, and requires
a power system with equivalent amount of installed capacity
capable to cycling in complement to the output of the tidal
plant .. Hydro capacity is especially suited for this
purpose. Alternatively, energy storage facilities {pumped
hydro, compressed air, storage batteries) can be used to
regulate the power output of the tidal facflity.
Tidal power was selected for consideration in Railhelt
electric energy plans because of the substantial Cook Inlet
tidal resource, because of the renewable character of this
energy resource and because of the substantial interest in
the resource, as evidenced by the first-phase assessment of
Cook Inlet tidal power development ..
Estimated production costs .of unretimed tidal powet"
facility would be competitive with principal alternative
sources of power, such as coal-fired power plants, if all
power production could be used effectively. The costs
\'K>Uld not be competitive, however, unless a specialized
industry were established to absorb the predictable, but
cyclic output of the plant. Alternatively, only the
portion of the power output that could be absorbed by the
Railbelt power system could be used. The cost of this
energy would be extremely high relative to other
power-producing options because only a fraction of the
"raw" energy production could be used. An additional
alternative would be to construct a retiming facility,
probably a pumped storage plant. Due to the increased
capital costs and power losses inherent in this option,
busbar power costs would st i 11 be substantially greater
than for nontidal generating alternatives. For these
reasons, the Cook Inlet tidal power alternative was not
considered further in the analysis of Railbelt electric
energy plans.
(xiii) Refuse-Derived Fuel Steam Electric Plants
These plants consist of boilers, fired by the combustible
fraction of municipal refuse, that pr.oduce steam for the
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operation of a steam turbine-generator. Rated capacities
typically are small due to the difficulties of transporting ·
and storing refuse, a relatively low energy density fuel.
Supplemental firing by fossil fuel may be required to
compensate for seasonal variation in refuse productiona
Enough municipal refuse appears to be avail able in the
Anchorage and Fairbanks areas to support small
refuse-derived fuel-fired steam-electric plants if
supplemental firing (using coal) were provided to
compensate for seasonal fl uct uat ions in refuse
avai·l ability. The cost of ~ower from such a facility
appears to be reasonably competitive, although this
competitiveness depends upon receipt of refuse-derived fue 1
at 1 ittle or no cost.. Advantages presented by disposal of
municipo1 refuse by combustion may outweigh the some\'klat
higher power costs of such a facility compared to
coal-fired plants. The principal concerns relative to this
type of p1 ant re1 ate to po"-:ent i al rel i·abi 1 ity s-atmospheric
emission, and odor problems.
Cost and performance characteristics of these alternatives
are summarized in Table 0.31.
(b) Energy Plans
Four electric energy plans \'/ere developed using different
combinations of these generation and conservation options. Each
plan represents a possible electric energy future for the
Railbelt. The plans were selected to encompass the full range of
viable alternatives available to the Railbelt.
Plan 1: Base Case
A. Without Upper Susitna
B. With Upper Susitna
Plan 2: High Conservation and Use of Renewable Resources
A. Without Upper Susitna
B. With Upper Susitna
'Plan 3: Increased Use of Coal
Plan 4: Increased Use of Natural Gas
The 1 ist of alternatives used in developing each of the above
plans is in Table D.32. Battelle has used a generation planning
model derived from the EPRI Over/Under Capacity Model to construct
the plans and calculate annual energy costs.
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To compare the costs of power for the various plans, Battelle used
the concept of a levelized cost of power. The levelized cost of
power is computed by estimating a single level annual payment,
which would be equivalent to the present worth, given assumptions
about the time va 1 ue of money.
The level ized cost of po~r is computed using the present wor ... th of
the annual costs of power produced over the time horizon. In
equation form:
d (1 +d) i Level i zed Cost of Po\'/er = PWCP * ----~-
(l+d) i -1
where:
PWCP = Present worth of the cost of power
d = Real discount rate
i = year -1981 (base year)
In turn:
PWCP
where:
n TAC. l
= 2: ,* E PP . -( 1-+-d )-...-1
• 1. 1 1=
TAC; = total annual costs in year i ($)
EPP; = e1ectric.a1 power produced in year i (kWh)
n = time horizon (years)
Formal forecasts of power costs were not made by Battelle beyond
2010, however 5 this difference in power costs between with and ·
without Susitna p1 ans can be expected to increse over the service
life of the Upper Susitna project. This difference is :expected to
be maintained because the other plans are relatively more reliant
on fossil fuel, which is expected to continue to escalate in
price.
To recognize this longer term behavior of power costs, the
1 evel i zed costs of power were computed for two different time
horizons (1981-2010 and 1981-2050) throughout the Battelle
analysis. The shorter time horizon was picked to correspond to
the time horizon of the study. However, since the study evaluates
the Upper Susitna project, which has an economic lifetime of 50
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years (and an even longer expected service 1 ifetime) ~ the longer
time is ~1 so used to correspond to the economic 1 i fet ime of the
project. The level ized costs of power for the 1981-2050 time
period are computed assuming that no change will occur in the
annual cost of power over the 2010--·2050 time horizon. Whereas
this assumption understates the relative advantages of the plans
that include the Upper Susitna project, it does indicate
advantages of these plans over the project 1ifetime. The
1 evel i zed costs of power for the six p1 ans over the two periods of ·
ana1ysi s are presented below.
Leve1ized Cost of Powet' (mills/kWh) ·
Low Medium I High
Economic Economic Economic
Scenario Scenario Scenario
1981-1 no1 1981-1981-1981-1981-
.L:7U -
2010 2050 2010 2050 2010 2050 --
Plan 1A 58 65 58 64 60 66
Plan lB 58 63 58 59 58 60
Plan 2A 58 66 59 66 58 66
Plan 2B 57 61 58 61 57 69
P1 an 3 58 67 59 65 62 68
P1an 4 57 64 59 66 61 68
For the medium economic scenario, essentiar~y no difference exists
in the levelized cost of power among the varius electric energy
plans over the 1981-2010 time period. Over the longer time
horizon the costs of power for the plans including the Upper
Susitna project (Plans lB and 2B) are lower than for the other
plans.
For the low economic scenario, again 1 ittle difference ex.ists in
the levelized costs of power over the 1981-2010 time horizon. The
advantages of the plans including the Upper susitna project are
smaller than for the medium economic scenario.
In the case of the high economic scenario, relatively 1 ittl e
difference exists in the costs of power over the shorter time
period, ~although the plans including the Upper Susitna project
have slightly lower po\'-Jer costs. Over the longer time period, the
plans in-cluding the Upper Susitna project have significantly lower
power costs. The plans heavily reliant on fossil fuels, Plans lA,
3, and 4, have relatively high power costs in the high economic
scenario. In general, the longer the time period and the higher
the demand, the more attractive are plans containing the Upper
Susi tna project.
Based upon the evaluation of the socioecqnomic and environmental
effects of the plans and sensitivity analyses of factors affecting
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..
the plans, the following conclusions are drawn for the various
electric energy plans.
(i) Plan lA: Base Case Without Upper Susitna
-The 1 evel i zed costs of power for this plan are-
relatively stable among the various sensitivity test$ ..
Generally, it is neither the highest nor the lowest cost
plan ..
Significant potential impacts on air quality~ 1 and use,
and susceptibility, to inf1 at ion due to fossil fuel use
are possible. ·
Incrementa1 coal munng and reclamation activities will
occur due to expanded coal use in the Beluga and Healy
areas.
-The development of a coal export mine at Beluga to.
supply coal to generat·ing plants located there is
uncertain.
-The costs and environmental impacts of the Chakachamna
hydroelectric project are uncertain.
(ii) Plan lB: Base Case With Upper Susitna
-Except for cases assuming higher than estimated capital
costs for the Upper Susitna project, this plan provides
relatively low power costs over the 1981-2010 time
period. The plan provides either the lowest or nearly
the lowest cost of power in all senstivity te.sts over
the ~xtended time period.
-Electric power needs can be met without significant
impacts to air quality, visibility, health and safety
and other environmental sectors. However, improper
river flow control may be detrimental to fish
product ion.
-Relatively good information is avail able on capital cost
and environmental impacts of the Upper Susitna Project ..
The p1 an is resistant to inflation once the project is
~ constructed.
-Significant boom/bust, land-use effects and high capital
costs are associated with the construct ion of the Upper
Susitna project.
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(iii) Plan 2A: High Conservation and Use of Renewable Resources
Without Upper Susitoa
-This p1 an has slightly higher power costs in most cases.
The costs are high mainly because of the plan's reliance
on relatively high capital cost generating alternatives
(hydroelectric, refuse-derived fuel, and wind).
-Reduced air infiltration associated with building
conser·vat ion may present health and safety hazards from
indoor air pollution. The exact relationship between
b ui 1 ding conservation and indoor air po 11 ut ion has not
be established.
-The capital Gosts of altern ate hydroelectric projects
are uncertain ..
-., This plan assumes that a state conservation grant
program exists.
(iv) Plan 2B: High Conservation and Use of Renewable Resources
With Upper Susitna
-This plan has much the same costs a.nd impacts as Plan
lB. This sirnil arity is expected since they both include
the Upper Susitna project.
The health and safety aspects of the indoor air quality
of conservation activities are unknown.
-As with 2A, this p 1 an assumes an extensive state
conservation grant program.
(v) Plan 3: Increased Use of Coal
-This plan produces re1 at ively high costs of power over
the 1981-2050 time period. The plan is more attractive
in the case with lower fuel price escalation rates.
Significant potential problems are possible in air
quality, water quality, visual impacts, and land-use and
i nfl at ion effects.
-Constraints due to nondegradatio,n air-qua1ty regulations
are possible. • /
Incremental coal rn1n1ng and reclamation activities wi11
occur due to expanded coal use i'n the Beluga and Healy
area.
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-The development of a coal export mine at Beluga is
uncertain.
{vi) Plan 4: Increased Use of Natural Gas
-This plan b~~haves very similarly to Plan 3. It provides
the 1 owe st cost of power over the 1981-2010 time period
in the case of lower fuel price escalation rates and in
the case of reduced demand beyond 1995. It is one of
the higher cost alternatiVes over the extended time
horizon.
-This plan has little impact on all sectors of the
environment. rt> major problems are associated with
jobs, boom/bust effects, or land use.
Due to high technology of fuel cells and gas combined-
cycle units susbstantial spending will occur outside the
state.
Inflation effects are significant because power
production is directly tied to the price of natural
gas.
-Existing reserves of natural gas in the Cook Inlet area
will not be adequate to support expanded gas-fired
generation beyond 1990-1995.. The discovery of
additional reserves is uncertain.
As indicated by this discussion, much uncertainty remains
regarding all key alternatives to the Upper Susitna
project. Coal, natural gas and hydroe1 ectr ic projects are
the primary alternatives to the Upper Sus i tna project ..
Whereas uncertainties do remain regarding the Upper Susitna
project, more is known about the costs and impacts of the
Upper Susitna project than any of the alternatives. The
following uncertainties are associated with the
alternatives:
-Coal-based generation at Beluga depends upon the
development of a 1 arge-scale export mine. Such a mine
is based upon Pacific Rim steam coal market "'development.
\~hile this market is expanding development of Beluga
coal resources is uncertain.
-Current reserves of natural gas in the Cook Inlet area
are not expected to be adequate for generation beyond
1990-1995.. The availability of additional reserves by
that time is uncertain.
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' -Gas-based generation in Fairbanks depends UQon the
availability of natural gas from the North Slope in the
Fairbanks area either via the Alaska Natural Gas
Tra_nsportat ion System (ANGTS) or another system.
The capital costs and environmental impacts of
alternative hydroelectric projects are based upon
reconnaissance studies and as a result have a high
degree of uncertainty associated with them.
-The relationship between building conservation and
indoor air pollution has not been established.
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5 -CONSEQUENCES OF LICENSE DENIAL
5.1 -Cost of License Denial
The forecast energy demand for the Rail belt through the year 2010 can
be met without constructing the Watana-Devi1 Canyon hydroelectric
project. The best alternative generating system is outlined in
Section 4.5 of this Exhibit. However, the economic comparison
described in Section 4. 7 concludes that the Susitna. project wi 11 yield
an expected present valued net benefit of $1.45 billion. Further,
there is a 0.5 probability that this net benefit will be exceeded, and
only a 0. 36 probability that the net benefit wi 11 fall below $0.5
billion.
Therefore, the consequences of 1 icense denial wi 11 be the probab 1 e
costs mentioned above~
5. 2 -Future Use. of D:1ms i tes if License is Denied
There are no present plans for an alternative use of the Watana and
Devil Canyon damsites. In the absence of the hydroelectric project,
they would remain in their present state.
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6 -FINANCING
6.1 -Financial Evaluation
(a) Forecast Financial Parameters
The financial, economic, and engineering estimates used in the
financial analysis are summarized in Table 0.7. The interest
rates and forecast rates of inflation (in the Consumer Price Index
-CPI) are of special importance.-They have been based on the
forecast i nfl at ion rates and the forecast of interest rates on
industrial bonds as given by Data Resources Incorporated (9), and
conform to a range of other authoritative forecasts. To allow for
the factors which have brought about a narrowing of the
differential between tax exempt and tax-liable securities, it has
been assumed that any tax exempt financing would be at a rate of
80 percent rather than the historical 75 percent or so of the tax-
liable interest rate. This identifies the forecast interest rates
in the financing periods from 1985 in successive five-year periods
as being of the order of 8.6 percent, 7.8 percent, and 7 percent.
The accompanying rate of inflation would be about 7 percent. In
view of the uncertainty attaching to such forecasts and in the
interest of conse~vatism, the financial projections which follow
have been based upon the assumption of a 10 percent rate of
interest for tax-exempt bonds and an ongoing inf1 at ion rate of 7
percent.
(b) Inflationary Financing Deficit
The basic financing problem of Susitna is the magnitude of its
"inflationary financing deficits". Under inflationary conditions
these deficits (early year losses) are an inherent characteristic
of almost all debt financed, long life, capital intensive projects
(see Figure 0.21). As such, they are entirely compatible (as in
the Susitna case) with a project showing a good economic ~ate of
return. However, unless specific measures are taken to meet this
"inflationary financing deficith the project may be unable to pro-
ceed without imposing a substantial and possibly unacceptable bur-
den of high early-year costs on consumers.
(c). Basic Financial Options
A range of financing options compatible with the conditions laid
down in Senate Bill 25 have been considered as a means of meeting
the inflationary financing deficit. rhe options basically consist
of a range of appropriations by the State of Alaska with the bal-
ance of the project financing made up by either 35-year tax-
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exempt revenue bonds or by a combination of General Obligation
(G.O.) bonds and 35-year revenue bonds~ with the G.O. bonds re-
financed into revenue bonds at the earliest opportunity. Through-
out central estimates of capital costs, revenues, etc., are used.
(i) 100 Percent State Appropriation of Total
·capital Cost ($5.l_bi11ion in 1982 dollars)
This conforms to the possible outcome of Senate Bill 25 and
represents the simplest financing option. It could take
the form of the State of Alaska appropriating funds to meet
capital costs as incurred over the 15-year construction
schedule detailed in Table 0.33.
On the basis of the present wholesale energy rate setting
requirement incorporated in Senate Bi 11 25, the Power
.Authority would, however, not br :ible to charge more than
the actual costs incurred. Given that in this case the
only costs would be the very small year-to-year operating
costs, this option would involve the output from Susitna
being supplied at only a fraction of the price of
electricity from the best thermal option.
(ii} State Appropriation of $3 Billion {in
{iii}
1982 dollars) with Residual Bond Financing
The outcome for this option is summarized in Figure 0.22
and Table 0.34. It would still enable Susitna energy to be
produced at a price 46 percent less than that of the best
thermal option. It waul d also enable the project to be
completed with only $0.9 billion (in 1982 dollars) of
revenue bonds or G.O. bonds over the period 1991-93. The
Devil Canyon stage could then be completed with a further
$2.3 billion (in 1982 dollars) of revenue bonds over the
period 1994 to 2002.
This level of appropriation would enable Susitna energy
prices to be held virtually constant at their initial level
for nearly a decade. A temporary "step-up" in pric€ of
Susitna output to the cost of the electricity from the best
thermal option would be required \'/hen Devil Canyon was
completed on the basis of its 100 percent revenue bond
.financingc Thereafter, however, the cost of the Susitna
energy would again stabilize and give ever-increasing sav-
ings compared with cost of the best thermal option ..
"Minimum 11 State Appropriation of $2.3 Billion
(in 1982 dollars) with Resid~al Bond Financing
The "minimum" state appropriation is taken as the minimum
· amount required to meet a debt service cover of 1 .. 25 on the
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residual debt financing by revenue bonds and makes .
Susitna's wholesale energy price competitive with the best
the""mal option in its first normal cost year (1994). This
level of appropriation would require $1u7 billion {in 1982
dollars) of bond financing in 1990-93 and a further $2 .. 1
billion (in 1982 dollars) over the period 1994 to 2002 to
complete Devil Canyon (see Figure 0.23 and Table 0.35).
These levels of state appropriation would all therefore eliminate
Susitna•s "inflationary financing deficit".
(d) Issues Arising from the Basic Financing Option~
(i) Need for Financial Restructuring
Irrespective of Susitna being chosen as the best means of
meeting the Railbelt energy needs, significant financial
restructuring of some Railbelt utilities will be required
to enable them to offer adequate financial security in
their power contracts and debt financing to meet generation
expansion·. It is assumed that this restructuring will take
p 1 ace.
(ii) Tax-exempt Bond Financing
In the $2.3 bi-11 ion state appropriation case interest cost~
on the basis of tax-exempt financing, accounts for 90 per-
cent of the unit price of Susitna output in 1994. Failure
to obtain tax-exempt bond financing would increase these
interest costs by approximately one-quarter. Ensuring
tax-exempt status for the Susitna bond issues is therefore
of fundamental importance to the economics of the project
under these options.
This issue has been extensively reviewed by tax advisers
and consultants and i c has been concluded that at the stage.
at which bond financing is required in the early 1990s,.
tax-exempt financing should be possible in compliance with
Section 103 of the IRS code.
(iii) Op~ions for Residual Financing
Tables 0.36 and 0.37 set out the estimated requirements for
bond financing with state appropriations of $3 billion and
$2.3 billion respectively. Several options available to
meet these financing needs are summarized below.
-Revenue Bonds with a Completion Guarantee
A completion guarantee must be assumed to be a precondi-
tion of bond financing at the Watana stage (up to 1993).
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A State of Alaska guarantee of project completion would
probably enaHle all residual financing to be met by rev-
enue bonds. (The completion guarantee may of necessity
have to take the form of a G.O. bond authorization of an
amount to be determined prior to the timing of the
issuance of revenue bonds).
-Guaranteed Revenue Bonds with Post-Completion
Refinancing
If the revenue bonds were guaranteed by the State of
Alaska they could be issued without the provision of a
completion guarantee.
-G.O. Bonds with Post-Completion Refinancing
G.O. Bonds on the "full faith and credit" of the State of
Alaska are effectively identical to guaranteed revenue
bonds and would also avoid the necessity of a completion
guaranteee
In this case, as with that of guaranteed revenue bonds,
the burden on the credit of the state could be minimized
by making the bonds subject to "call 11 after a few years
(when project viability was established) and refinancing
into non-guaranteed revenue bonds.
(iv) Refjnancing Watana and the Financing of Devil Canyon
Early refinancing of any guaranteed o.r G.O. bonds used to
finance Watana, and the ongoing financing of Devil Canyon
entirely by revenue bonds is taken to be an important
financing objective. The main factor determining the date
at which such refinancing will be possible is the magnitude
of the initial state appropriation.
The basic conclusion from the analysis is that, with a
state appropriation of $2.3 billion (in 1982 dollars),
there is a very high degree of certaittty that refinancing
into non-guaranteed revenue bonds could occur within a few
years of project completion.
. .
(v) Importance of Adequate State Appropriation
The principal effect of appropriations significantly less
than $2.3 billion would be a possible need for additional
guaranteed or G.O. bond financing for Devil Canyon. This
is because the impact of lesser appropriations would (as
illustrated in Figure 0.24} give rise to inadequate
earnings coverage in the early years of Watana, and
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(e)
subsequently Devil Canyon, so that the raising of revenue
bonds requiring such cover would have to be delayed. In
addition, such inadequate funding would force the Susitna
price to 11 track" the cost of energy from the best thermal
option until adequate revenue had been built up to allow
such refinancingo
(vi) Impact on State Credit Rating of
Guaranteed or G.O. Bond Financing
The impact on state credit rating of guaranteed or G.O.
bond financing of the order cf $1.7 billion in the $2.3
billion (both in 1982 dollars) state appropriation case has
been assessed by the Alaska Power Authority's investment
banking and financial advisers First Boston Corporation
and First Southwest Company. They have concurred in the
following statement.
11 We are only able to render a conditional estimate of the
possible impact on the credit of the State of Alaska as a
result of the contemplated general obligation bond finan-
cing of $1.7 billion for the.Watana stage of the Susitna
hydroelectric project. Alaska's presently favorable rat-
ings are greatly influenced by it's low debt to assessed
value ratio which helps to overcome the unusually high
per capita debt statistics. Given the dramatic growth of
assessed valuation and the fact that interest expense
through start-up of Watana is to be capitalized from bond
proceeds the envisaged financing should not significantly
impair the credit of the.state. Even if the State of
Alaska's general obligation bond rating were reduced one
full letter grade, the cost in terms of interest rates on
future bond issues would likely be in the approximate
range of 1/4 percent to 1/2 percent per annum."
Financing Options Under Senate Bill 64_9 and House Bill 655
As proposed these bills would permit financing of approved energy
developments by state funding to be repaid at the rate of 3 per-
cent per annum with an 11 uplift" reflecting past inflation.
{i) 100 Percent State Appropriation
The outcome in thfs case is illustrated in Figure 0.25 and
waul d differ from that covered by the outright appropri a-
tion (c) (i) above in that the resulting charge for Susitna
energy to cover the repayment of state funding would be 81
mills/kWh in 1994 compared with 19 mills/kWh in the (c) {i) case.
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(ii) "Minimum" State Appropriation of $3 Billion
(in 1982 dollars) ·
The outcome of a state appropriation of $3 bi.llion (in 1982
dollars) is shown in Figure 0.26. This·also would differ
from the $3 billion outright appropriation dealt with in
(c) (ii) in representing the minimum compatible with
residual financing by revenue bonds, since the increasing
payment~ to the state create an earnings cover shortfall in .
2003. It would also result in a consequent higher charge
for Susitna energy. In this case it would be·120 mills/kWh
in 1994 compared with 80 mills/kWh under (c) (ii).
In both (i) and (ii) Susitna energy would still be produced at a price
competitive with the best thermal option. These scenarios would also
be compatible (subject to certain legislative requirements) with resid-
ual financing by revenue bonds.
(f) Future Development and Resolution of Uncertainties
Prior to the decision to proceed with actual construction of Susitna~ several significant uncertainties affecting the project
wi 11 have been reduced. Demand forecasts wi 11 be more certain and
the impact of the electrical intertie between Anchorage and Fair-
banks wi 11 be ·known. Fuel cost trends and energy prices from al-
ternative generation sources will be more precisely known. More
advanced engineering work and definition of the basis for con-
struction contracts will have firmed up requirements for capital
funds. In addition, the ·passage of time will have allowed better
definition of the level of state appropriation required and the
ability of the state to provide the necessary financial support.
The development of the institutional structure of the Railbelt
utilities by this date should also permit power contracts and
legislative proposals to be drawn UJ:> which would equitably share
these then more clearly delineated risks b~tween the utilities~
the Power Authority and the State of Alaskao The key requirements
for state guarantees and financing could then be more precisely
defined in an appropriately limited form which would be acceptable
to the state and adequate for project financing.
(g) Conclusion
The principal conclusion of the financial evaluatim .... i1 that with
a state appropriation of not less than $2.3 billion (in 1982 dol-
lars) and consent for guaranteed or G.O. bond financing of $1.7
billion {in 1982 dollars), Susitna would be financially viable.
It would also be able to market its output at an initial price
competitive with the most efficient thermal option and produce
substantial long-term savings compared with this option.
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"
The evaluation, however, stressed the importance of establishing
the project on a strong financial basis that would enable it to
secure conversion of the guaranteed or G.O. bonds issued for the
construction of Watana into non-guaranteed revenue bonds and ob-
tain a highly competitive rate of interest. These objectives (to-
gether with the marketing of the Watana output in 1994 and a price
46 percent below that of the most efficient thermal option)~ could
be secured by state appropriation of $3.0 billion (in 1982 dol-
lars).
It should also be noted that the cost benefit analysis shows that
full recovery long-term of any state appropriation would be pos-
sible with a better than 10 percent rate of return. Meeting the
Susitna "inflationary financing deficit" by such appropriations
can therefore be considered as a separate issue from subsidization
of electricity prices by foregoing recovery of all or part of the
state appropriation designed to meet this deficit.
6.2 -Financial Risk
The financial risks considered are those arising to the State of Alaska
and to Alaskan consumers. The analysis of these risks is restricted to
the period up to 2001 covering the completion of Watana and its first
eight years of operation.
(a) Pre-completi0n Risk
The major pre-completion risk is simply the risk that the project
will not be completed. The possibility of this arising owing to
natural hazard has a negligibly small probability of occurrence,
based on the risk analysi~ described in Reference 31.
The risk of non-completion owing to capital overrun is also as-
sessed to have negligible probability.. This is on the grounds
that the project only involves well-established technology, has
been extensively evaluated by Acres and wholly independent
consultants and shown by formal probabi 1 ity analysis to have only
a 27 to 20 percent probability of any real capital overrun.
{b)_ Post-completion Risks
(i) The Generation of Post-completion Risks
A probabilistic financial model was developed taking into
account the probability distributions of the major engi-
neering and financial variables on which the financial out-
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come for Susitna depends .. This model, the basic parameters
of which are given in Table 0.38, was then used to consider
in detail critical specific and aggregative risks pos~d by
t-he n ... n;nr.t-
viJ p1 VJ~'--v •
(ii) Specific Risks
-Specific Risk I; Risk of Bond
Requirement Overrun (Figure 0.27)
Extensive analysis was undertaken to assess the probabil-
ity that the bond financing requirements would overrun
the forecast values as a result of capital costs, infla-
tion, interest rates, etc., being less favorable than
forecast. In the $2.3 billion state appropriation case
it was found that the probability of the bond financing
requirement exceeding the forecast of $1.7 billion (in
1982 dollars) by more than 50 percent was only 0.12.
There is also a significant probability (0.71) that the
bond financing requirements will be less than the fore-
cast $1.7 billion.
-Specific Risk II; Inadequate Debt
Service Cover (Figure 0.28)
Adverse impact on state credit rating might occur if the
project failed to earn adequate debt service and cover
and consequently conver~ion into non-guaranteed revenue
bonds was delayed. The analysis showed that in the $2.3
billion state appropriation case:
• The probability of forecast coverage being less than
· adequate ( 1. 25 cover age) in 1994 (first norma 1 year of
Watana) is 0.22.
Given that the probability of coverage shortfall dimin-
ishes with time (due to increased cost of alternative
fuels), the risk of delayed conversion due to inadequate
cover is minimal.
-Specific Risk III; Early Year
Non-viability (Figure 0.29
The measure of financial non-viability in the early years
is taken as the ratio of Watana's unit cost to the costs
of the best thermal option in Watana • s third year (1996).
(For comparability excess debt service cover was ex-
cluded.) If this ratio is less than forecast it would
reflect "non-viability" in the sense of the project not
realizing its forecast savings in these important early
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years. This analysis indicates that in the $2.3 billion
appropriation case there is only a 0.29 chance of the
Susitna costs exceeding their forecast value {51 percent
of the best thermal).
(iii) The Aggregate Risk
While specific risks of the type considered above are of
importance basic concern must center on the aggregate risk.
In long-term economics this is measured by the risk
attaching to the rate of return. For the purpose of the
financial risk, however, it is taken as represented by
accumulative net operating earnings at the end of the first
eight years of operation of Watana. Since this statistic
is net of interest and debt repayment, it effectively
subsumes all the risks involved in capital expenditure.,
inflation, interest rates, revenues etc., deviating from
their forecast values. This statistic was also adjusted to
allow the pricing up of Watana energy to the cost of the
best thermal option so that the statistic reflects the
11 Upside" risk as well as the "downside ...
On this basis in the $2.3 billion state appropriation case
the statistic (see Figure 0.30) was found to have only a
0.27 chance of being below forecast level of $0~8 billion
(in 1982 dollars) by more than $0.2 billion. There is also
a 0.73 probability of the statistic exceeding $0.8 billion
and thus creating greater savings for the Alaskan comsumer.
(c) Conclusions
The analysis shows the exposure of the project, either to.critical
specific risks or:-to aggregative risk, at the Watana stage is rel-
atively limited. v The qualification attaching to this analysis is
that the estimates and probabilities used are free from any sys-
tematic biases. The structure of the plan of the overall plan of
study for Susitna and analysis of its alternatives has, however,
been specifically designed to take every reasonable precaution
against this possibility by seeking extensive independent
verification of the key variables by Batelle and Ebasco operating
wholly as independent consultants.
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LIST OF REFERENCES
1. Code of Federal Regulations, Title 18, Conservation of Power and
Water Resources-, Parts 1 and 2, Washington, D.C., Government
Printing Office, 1981.
2.
3.
4 ..
5.
6.
7.
8.
.9.
10.
Alaska Agreements of Wages and Benefits for Construction Trades.
In effect January 1982.
Caterpillar Performance Handbook, Caterpillar Tractor Co.i Peoria,
1T1inois, Octo6er 1981.
Roberts, WilliamS., Regionalize!:i Feasibility Study of Cold
Weather Earthwork, Cold Regions Research and tngineering
Laboratory, July 1976, Special Report 76-2.
Acres American, Inc. Susitna Hydroelectric Project Feasibility
Report, Volume 6 (Appendix C). Prepared for the Alaska Power
Authority~ March 1982.
Acres American Incorporated.
Development Selection Report.
Authority, December 1981.
Susitna Hydroelectric Project
Prepared for the Alaska Power
U.S. Department of Labor, Monthly Labor Review, various issues.
Alaska Department of Commerce and Economic Development, The Alaska
Economic Information and Reporting System, July 1980.
Data Resources Inc., U.S. Long-Term Review, Fall 1980, Lexington,
MA, 1980:-
Wharton Econometric Forecasting Associates, Fall 1981, Philadel-
phia, PA, (reported in Economic Council of Canada CANDIDE Model
2-0 Run, date.d December 18, 1981.)
11. Baumol, W.J., "On the Social Rate of Discount 11 , American Economic
Review, Vol. 58, September 1968.
12. Mishan, E.J., Cost-Benefit Analysis, George Allen and Unwin,
London, 1975.
13.. Prest, A .. R. and R. Turvey, "Cost-Benefit Analysis: A Survey",
Economic Journal, Vol. 75, 1965.
14. U.S. Department of Commerce, Survey of Current Business, various
issues.
15. Data Resources, Inc., personal communication, November 1981.
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16. World Bank, personal communication, January 1981 ..
17. U.S. Department of Energy, Energy Information Administration,
Annual Report to Congress, Washington, D.C., 1980 ..
18. National Energy Board of Canada, Ottawa, Canada~ personal communi-
cation, October 1981.
19.. Noroil, "Natural Gas and International LNG Trade", Vo~i. 9, October
1981.
20. Segal, J. 11Slower Growth for the 1980's .. , Petroleum Economist,
December 1980.
21. Segal, J. and F. Niering, ''Special Report on World Natural Gas
Pricing .. , Petroleum Economist, September 1980.
22. SRI International, personal communication, October 1981.
23. World Bank, Commodity Trade and Price Trends, Washington 1980.
24. Battelle Pacific Northwest Laboratories, Beluga Coal Market Study,
Final Report~ Richland, Washington, 1980.
25. B.Ce Business~ August 1981.
26. Coal Week International, various issues.
27. Japanese f4inistry of International Trade and Industry, personal
communication, January 1982 ..
28. Canadian Resourcecon Limited, Industrial Thermal Coal Use in
Canada, 1980 to 2010, May 1980.
29. Battelle Pacific Northwest Laboratories, Alaska Coal Future Avail-
ability and Price Forecast, May 1981.
30. Roberts, J.o. et al, Treatment of Inflation in the Development of
Discount Rates and Leve1ized Costs in NEPA Analyses for the
Electric Utility Industry, U.S. Nuclear Regulatory Commission,
~ashington, D.c., January 1980.
31. Acres J\merican Incorporated. Report on "Economic, Marketing and
Financial Evaluation" for Susitna Hydroelectric Project. ·
32. Battelle Pacific Northwest, 11 Railbelt Electric Power Alternatives
Study: Evaluation of Railbelt Electric Energy Plans", prepared
for the Office of the Governor, State of Alaska, August 1982.
33. Battelle Pacific Northwest 11 Railbelt Electric Power Alternatives
Study Candidate Technolgies 11 , prepared for the Office of the
Governor, State of Alaska, August, 1982.
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34. Battelle Pacific Northwest "Railbelt Electric Power Alternatives
Study: Coal Fired Pl antsn, prepared for the Office of the
Governor, State of Alaska, August, 1982.
35. Battelle Pacific Northwest "Railb~lt Electric Power Alternatives
Study: Natural Gas and Combined Cycle", prepared for the Office
of the Governor, State of Alaska, August, 1982.
36. Battelle Pacific Northwest "Railbelt Electric Power Alternatives
Study: Wind Energy"; prepared for the Office of tfie Governor,
State of Alaska, August, 1982.
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Categor~
Production Plant
Transmission Plant
General Plant
Indirect
Subtotal
Contingency 17.5$
Total Construction
Overhead Construction
TOTAL FROJECT
TABLE D. t: SUW-tARY OF COST ESTIMATE
Januar~ 1982 Dol Iars $ X 106
Watana Devr I Can~ on Total
$1,986 $ 835 $2,821
391 91 482
5 5 10
378 188 566 --$2,760 $ 1, 119 $3,879
482 196 678
$3,242 $ 1,315 $4,557
405 165 570
$3,647 $1,480 $5,127
-•. ------- - --- --·--
ESTIMATE SUMMARY TABLE D.2
j~~m ALASKA R>WER AUTHORITY WATANA Feaslbll tty
CLIENT TYPE OF ESTIMATE
PROJECT SUS ITNA HYDROELECTRIC ffiOJECT APPROVED BY _ JDL
No. DESCRIPTiON QUANTITY UNIT COST/ UNIT AMOUNT TOTALS
ex 1 o6> (x 1 o6 >
PROOUCT I ON PLANT
330 land & land Rights •••••••·•o•••••• ••••••••••a••••••• ••••••••• •••••·••• $ 51
331 Powerplan"t Structures & lmprovemen s •••••••••••••••••••••@••• •••••••• 73
332 Reservoir, Dams & Waterways •••••••••••••••••••••••• ••••••••• ....... .. 1,532
333· Waterwheels, Turbines & Generators •••••••••••••••••••• .. •••••• •••••••• 65
334 Accessory Electrical Equipment ••• ••••o•••••••••••••••••••••• •••••••• 21
335 Mlscel laneous Powerplant Equipment (Mechanical) ............... •••••••• 14
336 Roads & Railroads •••••••••••••••• : ................ . 230
TOTAL PRODUCTION PLANT ••••••••••••••••••••••••••••• ••••••••• •••••••• $ t ,986
0
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--· -·-
JOB NUMBER P~?'lllo.oo
FILE NUMBER ?~1;~00. 14 ·09
SHEET 1 OF "' . __ .....__
BY --......... .....---DATE ...-rr.,..,...-
CHKD JRP DATE. 2782
RE:~ARKS
•
--------
ESTIMATE SUMMARY
CL I ENi ALASKA FOWER AUTHORITY
---
TABLE 0.,2
WATANA
--
TYPE OF ESTIMATE
- -
Feasibility
PROJECT SUS I TNA HYDROELECffi I C FROJ ECT APPROVED BY ___ J_D_L ----
No.
350
352
353
354
356
359
· DESCRIPTION QUANTITY UNIT COST
UNIT
TOTAL BROUGHT FORWARD ••••••••••••••••••••••••••••••!••••••••• ••••••'~>•
TRANSMISSION PLANT
Land & land Rights ................ •••o•••••••e•••••• ••••••••• ••••••••
Substa-tion & Switching Station Str .
····~···
Substation & Switching Station Equ pment •••• ~ ....... • ••••••••
Steel Towers & Fixtures ........... ••••••••••••••••• ••••••oe
Overhead Conductors & Devices •••• ••••••••••••••••• ••••o•••
Roads & Tra tIs •••••••••e••••e•••• •••••••••a••••••• ••••••••
TOTAL TRANSMISSION PLANT ••••••••• ••••••••••••••••e ••••••••• e•••••••
AMOUNT TOTALS
0
$ 1,986
$ 8
12
129
130
99
13
$ 391
$ 2,377
--
JOB NUMBER P-5:7no .. oo
FILE NUMBER' ?2'700. 14 •09
-
SHEET 2:' OF 5
BY--~---DATE JRP · ... 2T-;~aroo~z-
CHKD DATE
RE'MARKS
- - - ------ - --... •• -----
.
ESTIMATE SUMMARY TABLE De2 JOB NUMBER P5K1V..OO
FILE NUMBER P 57~"\. U-4.09
~~~m WATANA l Cl-IENT ALASKA POWER AUTHORITY TYPE OF ESTIMATE Fe as 1 b 1 11 ty SHEET •3 OF ·5
BY l
SUSITNA HYDROELECTRIC PROJECT APPROVED BY JDL DATE
PROJECT JRP 2/B2 CHKD DATE_
No. DESCRIPTION QUANT tTY UNIT COST]
UNIT AMOUNT TOTALS REitARKS
(x 1 o6> (x 106 )
TOTAL BROUGHT ~ORWARD .............. ••••••••••••••••o• ••••••••• • •••••• o $ 2,382
I INDIRECT COSTS '
61 Temporary Construction Faci lltles. , •••••••••••••••e•• ••o•••••• ·"'······· $ -See Note
62 Construction Equipment ··~········· •••••••••••••••••• ·····~··· ••e•••••• -See Note
63 Camp & Commissary .-................ •••••••s•••••••••• ••••••••• ••••••••• 378
64 Labor Expense ••••••••••••••••10•••• •••••••••••••••••• ••••••••• •••••e••• -
65 Superintendence ••••••••••••••••••• •~•••••••o••=••••• ••••••o•• ., ........ -See Note
66 Insurance ••••••••••••••••~··•••••• •••••••••••••••e•• .......... ••••••••• -See Note
.
69 Fees e••••••••••••••••••••••••••••• ·········!)········ ••••••••• ••••••••• -::iee Note
Note: Costs under· accounts 6 l , 62 64, 65, 66, and ( 9
are Included ln the appropr ate d l rect costs
II sted above.
.
T01"AL INDIRECT COSTS ••••••••••••• ••••o•••••••••••• ••••••••• ••••••••• $ 378
.
.
.
$ 2,760 .
. .
- -
No.
71
72
75
16
77
80
... - ----- -------
ESTIMATE SUMMARY TABLE D.2
CLIENT ALASKA POWER AUTHORITY WATANA
PROJECT SUS ITNA HYDROELEC1'RJC FROJECT
DESCRIPTION . QUANTITY UNIT
TOTAL BROUGHT FORWARD (Construct for Costs) .. u•••••• •••••••••
Contingency 17.5% ••••••••••••••••••••••.,••••••••.,••••••••••••
TOTAL CONSTRUCTION COSTS •••••••••••••••••••••••••••••••••~•••
OVERHEAD CONSTRUCTION COSTS (PROJECT INDIRECTS)
Engineering/ Administration •••••••••••••••••••••••••••••••••• .
Legal Expenses •••••••••••• ..................................... ..
Taxes .........................................................
Administrative & General Expenses ···~··••••••••••••••••••••••
lnteres't ••••••••••••••••••••• • •••••••••••••••••••••.•••••••••
Earnings/Expenses During Construct on ••••••••••••••• •••••••••
Tota I Overhead ...................................... , ......... .
TOTAL FROJECT COST • • • • .. • • • • • • • • • .. • •••••.••• o....... . . " ..... .
TYPE OF ESTIMATE Feaslbf llty
APPROVED BY ___ JD_L ___ _
COST/ UNIT
•o••••••
I ••••••••
••••••••
•••••••••
••••••••
•••••••••
•••.,v•••
••••••••
• ••••••••
••••••••
$
•
AMOUNT TOTALS
$ 2,760
482
3,242
405
-
-
-
-
-
405
$ 3.647
- --
JOB NUMBER ps;r,oo •. oo
FILE NUMBER P2-r'~. i4-.09
-
SHEET 4 OF 5
BY ---m---· DATE ........,,.,...,--JRP 2/82
CHKD O,ATE
.
Included l n 71
Not applicable
Included tn 7t
Not Included
Not included
07. OZ. Q!, Jform ~~~A
... - - ----- -- ---- -- -
ESTIMATE SUMMARY TABLE 0.2 JOB NUMBER P5-~.oo.oo
FILE NUMBER P~h'!.OO. 14 .. 09
~~~rn WATANA ALASKA POWER AUTHORITY TYPE OF ESTIMATE Feas i b I I I ty SHEET
"~.:. 5 CLIENT ",j OF
SUSITNA HYDROELECTRIC PROJECT APPROVED BY JDL BY DATE
PROJECT JRP 2/82 CHKD DATE
No. DESCRI PTlON QUANTITY UNIT AMOUNT TOTALS REMARKS
<x 1 o6·> (x 106 )
TOTAL BROUGHT FORWARD •••••••••••• •••••••••••••••• . ......... ••••••••• $ 2,377
GENERAL PLANT
389 Land & land Rights ............... -c .................. •••o••~• $ Included under ~:So
390 Structures & Improvements •••••••• ········~········ ··••-o••• Included under ~:S1
391 Office Furnlture/Equ1pment ••• ~ ••• ·········-~~····· .......... Included under }99
392 Transportat~on Equipment •••••··~· It n ••••••••••••••••• • •••••••
393 Stores Equipment ••••••••••••••••• II tv ••••••••o•••••••• ee•&•eeea ... , ....
394 Tools Shop & Garage Equipment •••• •••••••a••••••••• " II ••••••••• e 0 G e.e 8 e e
395 Laboratory Equipment ••••••••••••• n It ••••••••••••••••• ••••••••• ••••••••
396 Power-operated Equipment 11 " ••••••••• ·~··~············ ••••••••• ••••••••
397 Communications Equipment • -•••••• 0
n " ••••••••• •••••••••~•••••e• •••••••••
398 Miscellaneous Equlpment it II
•••••••••• •o••••••••••••••• ...... , ... ••••••••
399 other T~ngtble Property •••••••••• ••••••a•••••••••• •••••••• ···~···· 5
TOTAL GENERAL PLANT •••••••••••••• ••••••o•••••••••• •••••••• • ••••••• $ 5 .
$ 2,382
•• ____ .w _____________ _
ESTIMATE SUMMARY
CLIENT ALASKA POWER /'.UTHOR I TY
TABLE D.3
DEVIL CANYON
TYPE OF ESTIMATE Feasibll tty
PRO-JECT SUSITNA HYDROELECTRIC PROJECT APPROVED BY ___ JD_L ___ _
No. OESCRlPTION QUANTITY UNIT fl~Tf/
PRODUCTION PLANT
330 Land & Land Rights •••••••••••••• •••••••••~••••••• ••••••••• •••••••• S
331 Powerplant Structures & lmproveme1ts ......... ,.e•••• ••••••••• ••••••••
332 Reservoir, Dams & Waterways ••••• ••••••••••••••••• •••••••••I-••••••••
333
334
335
Waterwheels, Turbines & Generator
Accessory Electrical Equipment ••
Miscellaneous Powerplant Equtpmen
• e. 8 8 e e •• e. e e 8 8 e I e e e e e e 8 e ep 8 •• e •••• i
············~···· ·········~········1
(Mechanical) ••• •••••••••~••&1•••••
336 Roads & Railroads ••••••••••••••• ••••••••••••••••• •••••••••It•,••••••
TOTAL PRODUCTION PLANT •••••••••• •••••••••••••••"• •••••••••to••••••••
AMOUNT TOTALS
22
71
635
42
14
12
39
$ 835
JOB NUMBER P5-7C}!} .. 00
FILE NUMBER P 5 7e:ID·14 ·U9
S'iEET 1 OF 5
BY __ ___,JR""'P..---OATE -"~~,"~"~"Sl.,..._
CHKD OATE
.•
07. oa. 05. ,orm 134A
1
I l
-
r
I
No.
350
352
353
354
356
359
-
.
---- ---•• ------
ESTIMATE SUMMARY TABLE 0.3
DEVlL CANYON
CLIENT ALASKA POWER AUTHORITY TYPE OF ESTIMATE Feaslb; lity
PROJECT SUSITNA HXOBOELECTRIC PROJECT APPROVED BY ___ JD_L ___ _
DESCRiPTION
TOTAL BROUGHT FORWARD
TRANSMISSION PLANT
QUANTITY
•••••••••••••••••
UNIT COST/
UNlT
·········~~·······
Land & Land Rights •••••••••••••• ••••••••••••••~•· ••••••••••••••••••
Substation & Switching Station Structures & lmprovenents •••••••••••••
Substation & Switching Station Eq~lpment •••••••••• ••••••••••••••••••
Steel Towers & Fixtures •s••••••• ••••••••••••••••• •••••••e••••••••••
Overhead Conductors & Devices ••• •••••••~••••••••• ·~·~··············
Roads & Trails •••••••••••••••••• ••••••••••••••••• ••••••••••••••••••
TOTAL TRANSMISSION PLANT •••••••• ~•••••••••••••••• •••••••••••••e••••
.
1l
.
. .
----
AMOUNT
$
7
21
29
34
TOTALS
835
$ 91
.
$ 926
•
--
.
JOB NUMBER PS?r~~.oo
FILE NUMBER PS.J't~m .. 14 • 09
SHEET 2 OF 5
BY ---J"""R,...P--·--DATE '2/Bl
CHKD -OATE
Included in Wa-t~na Es-timate
Inc I uded l n ~/c:rtt~na Estimate
I
.
--
No.
369
390
391
392
393
394
395
396
391
398
399
-- ----- -- - -
TABLE 0.3
DEVIL CANYON ESTIMATE SUMMARY
CL.IENT ALASKA POWER AUTHORITY TYPE OF ESTIMATE
PROJECT SUSITNA HYDROELECTRIC PROJECT APPROVED BY
DESCRiPTION
TOTAL BROUGHT FORWARD •••••••••••
GENERAL PLANT
QUANTITY
•••••••••••••••••
UNIT COST/
UNIT
Land & Land Rights •••••••oo••••• ..... ooooo•••••••• •o•••••••••••••o••
Structures & Improvements ••••••• ••••••••••••o•,•• •••o•••••••••••••"
Office Furniture/Equipment •••••• ••••••••••••••••• ••••••••••••••••••
Transporta't I on Eq u I pment ...... ., • • , .• o.. • • • • • • • • • • • • . o ••••••.••.••.•••.
Stores Equipment •••••••••••••••• ••••••••••••••••• •••••••••••••••• .. •
Tools Shop & Garage Equipment ...................... ••••••••••••••••"•
Laboratory Equipment •••••••••••• •••••••••·~·••••• ••••••••••••••••••
Power Operated Equipment oo•••••• .................. ••••••••••••••••••
Communlc;:ations Equipment •••••••• .................... ••••••••••••'••••••
Miscellaneous Equlpment ••••••••• •••••••••••••••"• ••••••••••••••••••
Other Tang i b I e Property ~ ••••••• ··~................. • •••••• • •••• • • •. • •
TOTAL GENERAL PLANT •••••••••••··~··••••••• .. ••••••• •o.••••••••••a•••••
AMOUNT
$
5
.... --
Feaslbll tty
JDL
TOTALS
926
.
$ 5
$ 931
----
JOB NUMBER PSW:m.oo
FILE NUMBER PS/~~·l 4 .. 09
SHEET --"""'3-._.: ............ OF __ s"-
BY --~----DATE....,..,~-JRP 2/82
CHKD DATE
RE'~Rl<S
Included under ~:50
Included under :531
Included under' .:'599
11 tl .
" u.
11 lt'
" It
11 It
II u
II n ...
--
No.
61
62 .
63
64
65
66
69
(
... - ----- --- - ---
ESTIMATE SUMMARY
TABLE 0.3
DEVIL CANYON
CLlENT ALASKA POWER AUTHORITY TYPE OF ESTIMATE Feasibility
PROJECT SUSITNA HXQROELECTRIC PROJECT APPROVED BY ___ JD_L ___ _
DESCRIPTION QUANTITY UNIT COST I
UNIT
TOTAL BROUGHT FORWARD •••e••••••• •••••••••••~••••• ••••••••••••••••••
INDIRECT COSTS
Temporary Construc-tion Fact I itles ••••••••o•••••••• •••••••••
Construc-tion Equipment ••••••••• ••••••••••••••••• •••••••••
Camp & Commissary ................ ••••••••o•••••••• ••••••••• .
Labor Expense ••••••••••••••••••• ••••••••••••••••• •••••• u ••
Superintendence ••••••••••••••••• ••••••o•••••••••• •••••••••
lnsun.rice ••••••••••••••••••••••• ••••••••••••••••• •••••••••
Fees ••••••••••••e•••a••••••••••• ••••••••••••••o•• •••••••••
Note: Cos-ts under accounts 61, 6g, 64, 65, 66, and 69
are included in the approp iate direct costs
I I sted above.
•••••••••
..........
eeeaoeoao
•••••••••
• ••••••••
••••••••e
e••••••••
TOTAL INDIRECT COSTS •••••••••••••••••••••••••••••••••••••••••••••••
AMOUNT TOTALS
931
$ -
-
188
-
-
-
'-
$ 188
$ 1, 119
---
JOB NUMBER
FILE NUMBER P5.~~ ... 14• 09
SHE£T 4 ... OF s
BY ---mrn--·--'DATE. -~-r--JRP 2J&
CHKD OATE
REPtl.aRKS
See Note
See Note
See Note
See Note
See Note
See Note
...
..,
--
l
i
No.
71
72
75
76
77
80
-------- ---
ESTIMATE SUMMARY
TABLE 0.3
DEVIL CANYON
CL.IENT ALASKA POWER AUTHORITY TYPE OF ESTIMATE
PROJECT SU§ITNA HXQROELECTRIC PROJECT
DESCRIPTIO.N QUANTITY
TOTAL BROUGHT FORWARD (Construct I ~n Costs) ........ •
Contingency 17.5% •••••••••••••••
UNIT COST/
UNIT
APPROVED BY
• AMOUNT
••••o•••••••••••••
TOTAL CONSTRUCTION COSTS •••••••• ••••~••••e••••••• •e••••••••••••••••
OVERHEAD CONSTRUCTlON COSTS CPROJ CT lNDIRECTS)
Eng I neer I ng O•••••••••o•••••••••• ••••••••••••••••• ••••••••• ••••••••• $ 165 .
Legal Expenses ................... ••••••••••••••••• •o••••••• •••••o••• -
Taxds ••a••••••••••••••••••••o••• •••••••o••••••••• ••••••••e ••••••••• -
Administrative & General Expenses ••••••••••••••o•• •••••••o• •••••••o• -
Interest ···················~···· ••••••••••••••••• ••••••••• ••••oee.,:,e -
Earnings/Expenses During Construe ion ••••••••••o•• • • • ,, • • • • e ••••••••• -
Total Overhead Costs . ., .......... ••••o•••••••••••• • •••••••• ••••o••••
TOTAL FROJECT COST ••••o••••••••• ••••••••••••••••• ••••••••• . . ._ .. , ....
••
-llil - ---
JOB NUMBER · PSJOO. 00
FILE NUMBER PS?QlO. 14 •09
Feasibility SHEET 5 OF 5 -----
JDL BY ---m---DATE -M'ti"T""-JRP 2/82
CHKD DATE
TOTALS REM~RKS
$ 1, 119
196
1,315
Included In 11
Not Appl icabre
Included in 7t
No-t Included
Not Included
165
$ 1,480
I
I
"I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
TABLE D.4: t4tTtc:ATim~ t-'iEASURES -SLNivtARY OF OJSTS JN:;CRPORATED
iN CONSTRUCTION COST ESTIMATES
COSTS INCORPORATED IN CONSTRUCTION ESTIMATES
Outlet Facilities
tAa in Dam at Dev i 1 Canyon
Tunnel Spillway at Watana
Restoration of Borrow Area D
Restoration of Borrow Area F
Restoration of Camp and Vii lage
Restoration of Construction Sites
Fencing around Camp
Fencing around Garbage Disposal Area
Mu It il eve I Intake Str~cture
Camp facilities Associated with trying
to Keep Workers out of Local Communities
Restoration of Haul Roads
S!JBTOTAL
Contingency 17.5$
TOTAL CONSTRUCTION
Engineering 12.5$
TOTAL FROJECT
WATANA
$ X 103
. 47,050
1,617
551
2,260
4,050
"' 350
125
18,400
10, 156
756
85,315
14.,930
100,.245
. 12,530
t 12,775
DEVI L C~NYON
$X 10 __
14,610
NA
NA
990
2,016
217
125
NA.
9,000
505
27;463
4,806
32,269
4,034
36,303 149,01'6
------------ - ---- -
1995 1996 1997 1993 1999 2000 2001 2002 20Q~ 2004
CAS~ FlOW 'itJH~A·P Y
73 C:Nt:RGY GPIH 3367
===($~Illl0N)=~==
3387 3397 3387 3387 3387 3387 5721 5'8'~>4 S968 521 REAL PPtCE-HillS .119 e6) ... • 112.91 105e'i3 99.59 93.98 67 .. 63 82e87 47.60 79:.,u1 72.76
f 466 INFLATION INDEX 24~·23 266.73 ·zd5.40 305.38 326.75 349.62 374.10 400.2.9 428 -~l ~~8.29
I 39~ PRICt-MillS 29d.22 301.17 301.17 304.13 3.r>7.08 307.08 310.03 }q0.54 338 ... a33 311.47
I -----INCOME-----------------210 REVENUE 1010.0 1020.\.) 1020.0 1031).0 11}40.0 1040.0 1050.0 1090.0 19!3;1! .... :.0 1 Q90. 0
170 l ':SS OPtiUTlNG CIJSTS 24.-1 26.7 lR.S 30.'5 32$7 35.0 37.4 72.0 1'1',.. ~ 84~0
---~' _____ ...__
--.-...-------.. ---------
,_ ________
---------.. -------------------------4.16-
_a. ____ ...._...,....., _____ ._ _ . .,.,._
• f 213 IJPERAT I NG ! NCOME 9135.1 993.3 991 .. 5 999.5 1007.3 1005.0 1012.6 1018.0 190~ ... ~ 1 :)06 .ri .
i ZotO LESS INTeReST EXPENSE 923 .. tJ 920.5 917 .. 0 913.2 908eR 901te0 898 .. 7 892.8 i.ltO'-.,~ 1710.2 ----.. --~----~-----------------
________ ..._ ___
-........ ______
--------~-
___ .. ___ .._,_,_ -·-----... ---______ ,.... ........... ______ ..,. ___
-1527 'lET EAP.NI~GS. FRuH OPERS 61 .. 5 72.3 74.S 8b.3 98.5 101.1 113.9 12Se2 PH .... ~ lqS.Il
Zllt I ~T€R£::ST EARNeD :JN FUND$ 4.9 5.2 5.6 o.o 6.4 6.CJ 7.3 7.9 lS~l l 6. 3 43,. I NTcREST Ot4 CASH DEFICIT o.o o.o o.o o.o o.o o .. o o.o of>o 0' ... ~ -0.6
-----CASI'i SOURCE AND USf----
44'j CASH lNC0"4': 66.1t 73.0 '30.1 92.3 104.0 107.9 121.2 133.0 206...,'(; el~.q . 41t6 STATE CONTR 11UTION o.o o.c o.o 1')~0 o.o J.O o.o o.o o .. ~ o.o I 143 LONG TERM JEaT O~AWDOWNS 3~1.7 .. 45.5 415.7 1179.2 l 44 t. 1 1617.9 1485.9 1098.13 lO.t..,~ 1"5.6 _____ .., ___
---------------------·----... -----------
__ ., ______
-------------------------~~ ....
... _ .... ______
447 TOTAl SOURCES OF FUNDS 458.1 :z3.6 495.11 1270.5 l 546.0 1725.8 1607.1 1231.8 3081 ... ' ]28.4
320 lESS CAPITAL EXPENDITURe 417.4 477.9 446.9 1215.8 1466.0 1661.1 1535ol 1077.'3 9C~~ 99.2 1 4,.3 LESS W'JR.C4P 4NO FUP-lDS 3.7 4.9 4.2 5.5 5.13 5.1 6., 5 81,9 tot •• :~ 14.,'1
• 26\l LESS DEBT REPAYHEflcTS 37.0 lt0e1 44cJ:i 49.2 54 .. 2 59.,6 b5.') 1 z .• 1 1()9.,,-; 120.4
l ----------___ .,_.. _____
------------------------------------------------------------·---.... .-..
_.,._ _______
1~1 CASH SURPlUSlDFFIClTl IJ.O o.~ o.o o.o J.O o.o o.o o.o a.,~ -o.l t 249 SJiORT TER1'1 O!::OT o.o 0.1') l). 0 c.n o.o c .. o o.c o.o ~ .. ~. o.o
i It 50 C4SH SUqPLUSCDEFICITI o.o o.u o.n o.o o.o 0 .I) o.o o.o ~.l -6.1
i -----PALAN.Cf SHEET----------
22'i ~Fsr~vJ: 1\ND CONT .. FUND 52.3 56.0 sq.q 64.1 68.6 73 .t, 71!o6 151.3 163.3 176.3 211 DEBT SF.PVICE PF.SSRVE· o.o o.o o.o o.o o.o o.c o.o o.o Q.,rt) o.o 451t !JTHER CASH SURPLU3 o.n o.o o.o o.o o.o o.v o.o o.o 6..,). o.o I ---------
___ ..., _____
------------·-----~-------·--------.;--"'---.... -------_..., _______
------,-~.....,~ ....... ~------
5,3 TOTAl FUNL)S 52.3 '36.\l 5·). q 64.1 68.6 73.4 78.6 1:51.3 16q."\ 176.3
1
.371 QTHEtt "'oqJ<rr-.~ CAP !TAl 104.7 10n.o 106.3 lC 7.6 108.9 lOQ.2 110.6 ll9eB 209.1 ZtJ..6
370 r.u~ot. CAP lT ,\L SXP END I TU RE 10140.~ 10613.'1 1l 06.5. 7 1221H.S 13767.5 15428.6 16963.6 18041.4 1Bl3le.l }8l31.5
==~~=====·========= ---------====·==---=.== :&:'!:'===== ~===·===·== ~=====--=== =======:c= :::::':=-='~-::.~ ~~tt.=:::.=~== ---------.. b.i CAPITAL Ef1PVJYIW 10298.0 10780.~ 11231.9 12453.2 13~45.0 15611.2 17152.8 18317..5 18.511 ..... 18'>t"<l.4 ==:::r====== :az.z::::,:: ========= •==:::===== :::::::::-:: =-====:::.::::-========:: =·.a:::::-;;::: :z.::-:;::.~==-~ !:t::;.:::::~=;:.:::
461 STATE CONTRJ5UTlCI-.. o.o o.o o.o o.o. o.o o.v o.o o.o o,.,"O o.o
' 46Z ~ETA 1 '41:0 EAR~INGS 485.7 563.7 643.8 736.l 841.0 948.9 1070.1 ll03,l 1409..,~ 1622.4
! zso IJ~BT UUTSTANOINu 9812.J 10217.2 l058cl·l 11717.1 13104.1 l't1,62.4 160tV.7 17!09~4 17!01.,~ lt.9Q7.o
i 382 OO:Bi SERVICE c:>Vr:R-CASH 1.00 1.oo t.oo 1.0·J 1.oo 1.00 1.00 .o. 99 o.~l>, 1.oo
3il3 DE aT SeRVICE COVER-I.NCOHE 1.03 1.04 la04 1.::>4 1.05 1.0': 1.(}6 \. 06 1.0~ t.os
j 511 !lEST SfilVICE CCV~R-BEF TFR 1.03 le04 le04 1.05 1.or; leOS 1.06 ··1· 06 1.0~ 1.0,
l '-1Z ?EST Sf.~VlCE COVt:R-AFT TFR 1.03 le04 l.C' 4 1.05 l.t)~ l.O'.i 1.06 1.06 t .. l)"j I .. O«j
l ~
~
;
l l
f 1
' NO FUND-NO STATE CONTRIBUTION SCENARIO f
• 1 1% 'INFLATION, 100/c, INTEREST
l
! Sheet2 of 2 TABLE 0.5 !I
l
J
!
---·-... -- ----- -------
'
~~!OI!Ct***C!OI**~*********I!I********>:r**':t~.t'C:;t(t*********~********<n:::)*****~***********+ll=********************************(l*********¢~*~******~* DATA9H WATANA-OC CON LINE 1993-2002)-NO FUNO-NO STATE C3~TR.-INFLATIDN 7~-tNTEREST 10~-C.PITAL COST 55.117 8N ~~-J~~-l~
**J)(tJ;a*(t****Q*****'I',E(t(t(tl,'t(t*******"':t;r***:Qt***********************************~.:vt******>!'****:~::t(::;l::._':'!;J'1**:::*::c******~*****************:.'t~~~***~***~
71 ~NERGY GWH
521. REAl PRICE-~ILLS
ltbb INFLATION INOfl(
39~ PP ICF=-MU.LS
~---~INC~ME--~---------~~~--
210 ~ EVENUE
170 lESS OPERATING COSTS
213 OPE:RATING JNCO.•R 21t0 lt::SS INTEREST EXPtNSE
521 ~FT EARNINGS F~OM IJPt~S
Z14 INTEReST EARN tO :'2N t:.at·,. r .. ~ r·v••u..J 434 I ~TER'=S T ON CASH Of. F I C l'!
-----CASH SOURC£; ANr~ USE----44'> CASH lNC:lH.: 44b STATE CONT?l:lUTlON
143 lONG itRM OEHT DPAWOOWNS
447 TOTAL SOU~CES IJF FUNDS
320 lESS CAPITAl FXP ENO JTURE 448 LESS WJRCl\P A'-10 FIJ"40S
261) LESS DEBT REPAYf1FNTS
141 CAS._. Si.J.R?l US ( OEF J C t T J
249 SHGRT T~llM O(:BT
450 CASH SURPLUSCOEFICITl
-----BALANCE SH£!ET----------
225 RESClWt AND CONT. FUND
:!21 DfBT SE RV J CE RESSRVE
454 JTHER CASH SUAPLIJS
!'Z1 TOTAL FUNDS
311 •) THfR WORK t NG CAPITAl
310 CUM. CAPITAL EXP cNiH TlJ RE
465 CAPITAL cf'\PlJY€0
4bl STATE CONTR I8UTIO.N
462 ~C'TAJN€0 £:1\RrHNGS
21:\0 O~lH OUTSTANDING
382 OF'JT StRVlCE COV£:R-CASH
163 f)EBT SERVICE cov::=.P.-l"'CCME
511 OF.AT S~~V ICE COVtR-BEF TFR
Sl2 DEBT SERVICE COVF.R-AFl TFR
·1985 l9Sb 1987 l 988 1'~89 1990
CASH·FLCW t;U~MA~Y
===I$Mlll1UN):=~=
'} 0 f) l) 'J 0 o .. oo o.oo 14~=~~ o .. oo o.oo c.oo 126.72 l3'i.sq l'>:.lct 166.10 177eT3
\).OIJ c.oo 0.01) c.on. o.oo OeO'l
o.o o .. o o.o o .. c o.o o.:> o .. u o.o o.n ('.:> ().1) o.n
-----------------------------...-----------·--------___ ...._ _____
o.o o.J u.o o.o o.o O.f) o.o 0.() o • .o 0.) o.o o.o -------------·-------___ .__,.. ___ _ ,_ .. ____ .....,_
---------
____ .....__ ... ___
o .. o o.o o.o o.o o.u o.o o.o o.o o.o 0.1') o.o O.G o.o o.n o.o o.o o.o o.o
o.o o.o o.o c.o o.o c.o o.o o.o o. f) 0.0 o .. o o.o
403.7 513.0 '>71.4 ~46.4 1152.0 1879.2 __ .. ______
--~---------------------~-·---
..., ________
----~.,---403.7 513.0 511.4 h4i3 .. 4 1151.0 1A7'/e2
403.7 513.0 571.4 ·61t8.4 1152e0 l67q.z
O.!>. o.o o.o o.o o.c o .r1 o.J 0.') o.o o.·J o.o o.D _____ _,_,, ___ __ ._,_.., ___ ~, ---------------------------
___ ..., _____
).tl Q.,l'\ o .. o 0.1 o.o o.o o.c o.o o.o Q.,l) ~ .. ) (). 0 o.o o.o o.J o.o OeO o.o
o.o o.o o.o o.o o.o o.o
O.'J o.o o.o o.o o.o o.o o.o o.o O.C'I o.o o.o o.o ---------------------_,_ _________ ____ ,. ____
------------------o.o o.o o.o o ... o o.o o.o o.:> o.o n.o 0.1') o .. o o.o
403.7 916.9 14LIB.l 2136.5 3288.5 5167.7 ---------===:===== =======-=-= =====-=-=== ========; ===::::::;:: ---------403o7 916.6 t4aCJ.1 2136.5 3288.5 5167.7 :::.:====·== ======:::== ==-======= ===-====== =====:=== ---·---------------o.o o,o o.o 0. t' o.o o.o o.o IJ.J o.o o.·) o.o o.n
403.7 9lt.J.t! 14 s ':t. 1 2136.5 5288.5 5167.1 o.oo o.oc o.oo o.o'> o.oo o.oo o.oo o.oo o.oo o.oo o.oo o.oo o.oc o.oo o.oo o.oo o.oo O.'CO o.oo o.oo Oe'.lO o.oo o.o') o.o'.l
NO FUND-NO STATE CONTRIBUTION SCENARiO
7% INFLATION, 100A. INTEREST
1991 1992 l 9~ 3' 1 ~~~
0 0 33~71 ~3.87 o.oo OeOO 5o .. r '!! lZ~i.Ol 190.17 203.48 211.:r~ 2J2.97 o.oo o.oo l0°.Z~ zqs.zz
c.') o.o 37Q.,C;. 1010.0 c.o o.o zr..,s: 2 ~-3 ---------
_________ ....., _______ ,_,~ ....,. ________
o.o o.o 34~._,.!:' 986.1 c.o o.o (J.,C' 9l:U.? ----------------·--~·
.. _,_ ___ ..,_..,..
'------~--o.o o.o 348.,~ b6.5 o.o 011('1 0-.,t:.~ 4~6 o.o o.o o •. (':' ').0
Oe'l o.o 34d~;'!'> 71.1 o.o o.o o ... c; o.o 176'3.tl 1369.6 90 1-.~i l89.2 ,.. ________
---------______ , __ ,._... .... ,~*'------1763.8 1369.6 1249..,2' 360.2
176 3. a l36Q.6 1!6:""~ ]'iQ,.2 o.o o.o 86 .. Q; 67.4 o.o o.o Q.,.;jl 1l.o -------------------------.. ---~ ~--------c .. o o.o o .. ,t;;; o .. o o.o o.o o.~ o.o o.a o.o c .. c-, o.o
o.o O.Q 45.]' ~R.9 o.o o.o 0-.\"\ o.o o.o o.o 0""~ o.o __ ""' ______ ----------______ ,..._,.,.,.
"""----------o.o o.o 45-.';l 48.q o.o o.o 40.1 Io~t.s
b93t.i 830lel 94b<t.,l 97?3.5 ::::======== ========= :::·=== .::;;:. ·lt:'.e:;:::::::
6931.5 830lol 9550: •. 1 qa7~.<.:J =======.== ==:::=~==::= ==--====::;;t !!':::·:::::·::. o.o o.o o .. o. o .. o o.o o.o 346.~ 41 Q. 3
6q3l.'i 6301..1 9701-d Q4')7.6 o.oo o.oo o.nn .) • 1.)4 o.oo o.oo Oei.H} h.04 o.oo o .. oo o.o(.) 1.04 o.oo o.oo o.oo. t.04
TABLE 0. 5
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TABLE D~6: SUSITNA COST OF POWER
First full year of Watana & Devil Canyon -
(See Table 5 for Detail) 2003
.
$•s Per Net Kilowatt
Total Plant Investment
(RL 370 + 73) Inc. I.D.C.
I. Fixed Charges Per~ent
(a) Cost of Money · lOoOO
(b) Depreciation
( 1 0% 50 yr S. P. ) • 09
(c) Insurance .10
(d) Taxes .00
1. Federal Income
2& Federal
t-1i see 11 aneous
3. State & Local
0.00
0.00
0.00
10.19
II. Fixe'd Operating Costs
{a) Operation & Maintenance
{RL 213 & 73)
(b) Administrative & General
Experience {35% of (a))
Total Annual Capacity Costs
Actual $• s 1982 $' s
3103
316 .. 17
14.40
4.69
334.26
724
73.81
3.13
1.10
78.04
Notes: (1)
(2)
(3)
RL =Reference Line on far left of Table 5 printout
Working Capital carying charge is omitted as 80% covered
by earnings from Reserve & Contingency Fund (RL 225).
Cost in 1982 $'s is derived by deflating Actual $ cost by
the inflation index {RL 466) to reflect the economic cost
to consumers over the 50-yr. assumed 1 i fe of the facility.
It therefore diverges from the year to year financial cost
of power dependent on the specific debt QJ11ortization and
financing plan embodied in the assumed financing scenario.
As noted in pages to it is expected that the State of
Alaska wi 11 finance a mahor part of the investment and
substantially reduce the financia1 cost of power very
substantially bel ow that of RL 399 of Attachment A.
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TABLE D. 7: FORECAST F INANC!Al PARAMETERS
Project Canpletion -Year
Energy level -1993
-2002
-2010
Costs Tn January 1~92 Dollars
CapiTal Costs
Operating Costs -per
annum
Provision for Capital
Renewals -per annum
(0.3 percent of Capital Costs)
Operating Worl<tng Capital
Reserve and Contingency
Interest Rate
Debt Repayment Perlod
Inflat-Ion Rate
Watana
1993
$ 3.647
L.1..i_ . ..L~--UltJIUII
$10.0
mill ion
$10.94
Real Ra-te of Increase tn Operating Costs
9 -1982 TO 1987
-1988 on
Rea! Rate of Increase In Capital Costs
-1982 TO 1985
-1986 to 1992
-1993 on
Devil
Canyon
2002
$1.470
bi II ion
$5.42
mill ion
$4.41
Total
3 387 Gtlh
5 223 n
6 616 n
.$ 5.117
bill ion
$15.42
mtl lion
$15.35
15 percent of Operating Costs
10 percent of Revenue
100 percent of Opera-ting Costs.
100 percent of Provision for Capital
Renewals
10 percent' per annum
35 years
7 percent per annum
1 .. 7 percent per annum
2.0 percent per annum
1.1 percent per annum
1.0 percent per annum
2.0 percent per annum
-----------------
Generating Purchases Utility ~uat
Capacity 1981 Predominant Tax Status Wholesale Provides Energy O~nd
MWat0°F Type of Re: IRS Electrical Wholesale 1900
UTILITY Rating Generation Section 103 Energy Supply GWn
lN ANCHORAGE~COOK INLET AREA
Anchorage Municipal light and Power 221.6 SCCT Exempt * -585J.~
Chugach Electric Association 395.1 SCCT Non-Exempt .. .. 941~3
Matanuska Electroc Association 0.9 Diesel Non-Exempt * -2sa.e
Homer Electric Association 2.6 Diesel Non-Exempt * -284J~;
Seward Electric System 5.5 Diesel Non-Exempt * .... 26 .. ¢
Alaska Power Administration 30.0 Hydro Non-Exempt -* ....,.
National Defense 58.8 ST Non-Exempt ---
Industrial -Kenai 25.0 SCCT Non· Exempt ---
IN FAIRBANKS-TANANA VALLEY
' '
Fairbanks Municipal Utility System 1 68.5 ST/Die!iel Exempt -. -116 .. 7
Golden Valley Electric Association 1 221.J SCCT /Diesel Non-Exempt --316.7
University of Alaska 18.6 ST Non·Exempt ---
National Defense 1 46.5 ST Non-Exempt ---
!
.
IN GLENALLEN/VALDEZ AREA t
Copper Valley Electric Association 19.~ SCCT Non-Exempt --37A .
TOTAL 1114.3 . 2577,1,
1 Pooling_ Arrangements in Force
TABLE 0.8 _ RAILBEL T UTILITIES PROVIDING MARKET POTENTIAL 1 A~~(u
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I PLANT LIST
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PLANT TYPE OF No. NAME OF PLANT UTILITY OWNERSHIP
I 2 Anchorage No. 1 Anchorage Municipal light and Power Municipal I
' ~
i 3 Anchora~e Anchorage Municipal light and Power Municipal
t 6 Eklutna Alaska Power Administration Federal I
7 Chen a Fairbanks Municipal U-:ifities System Municipal
10 Knik Arm Chugach Electric Association, Inc. Cooperative
22 Elmendorf-West United States Air Force Federal I
I 23 Fairbank~ Golden Valley Electric Association, Inc. Cooperative
I
32 Cooper lake Chugach Electric Asso.ciation, Inc. Cooperative
34 Elmendorf-East United States Air Force Federal
35 Ft. Richardson United States Army Federal
36 Ft. Wainright United States Air Force Federal
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I
37 Eitson United States Air Force Federal
J
38 Ft. Greeley United States Army Federal
47 Bernice lake Chugach Electric Association, Inc. Cooperative i , 55 International Station Chugach Electric Association, lnc. Cooperative •
I 58 Healy Golden Valley Electric Association, Inc. Cooperative
59 Beluga Chugach Electric Association, Inc. Ceoperative l 75 Clear AFB United States Air Force Federal
80 Collier-Kenai Colliei-Kenai Municipal
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81 Eyak Cordova Public Utilities Municipa.l
82 North Pole Golden Valley Electric Association1 Inc. Cooperati-ve ... 83 Valdez Golden Valley Electric Association, Inc. Cooperative
84 Glennallen Golden Valley Electric Association, lnc. Cooperative I
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I I • I TABLE 0.9 -LIST OF GENERATING PLANTS SUPPLYfNG RAILBELT REGION
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TABLE D. 10: TOTAL GENERATING CAPACITY WITHIN THE RAlLBElT SYSTEM
Abbreviations
AMLPD
CEA
GVEA
A-1US
CVEA
MEA
HEA
SES
A PAd
U of A
TOTAL
Rai I bel't Uti I ity
Anchorage Municipal light & Power
Department
Chugach Electric Association
Golden Valley Electric Association
Fairbanks Municipal uti I tty System
Copper Val ley Electric Association
Matanuska·Eiectric Association
Homer Electric Association
Seward Electric System
Alaska Power Administration
University of Alaska
I nsta If ed Capacity 1
221.6
395 .. 1
221.6
68.5
19.6
o. 9
2.6
5;.5
30.0
18 .. 6
984.0
(l) Installed capacity as of 1980 at o•F
(2) Excludes National Defense installed capacity of 46.5MW
-------------------
TABLE 0.11: GENERATING UNITS WITHIN THE RAILBELT -1980
.> a lbel"t tat ion nstallation Uti I it Name Year Fuel T e Ret i remeni-'~':ear Anchorage Muntcipal AMLPD 1 GT 1962 14,000 16.3 NG 1992
Light & Power N4LPD 2 GT 1964 14,000 16.3 NG 1994
Department AMLPD 3 GT 1968 14,000 18.0 NG 1998 N4LPD 4 GT 1972 12,000 32.0 NG 2002'
CAMLPO) G.M. Su Ill van 5,6, 7 cc 1979 8,500 139.0 NG 2011 Chugach Beluga 1 GT 1968 15,000 16. 1 NG 199S
Electric Beluga 2 GT 1968 15,000 16. 1 NG 1998
Association (CEA) Beluga 3 Gr 1973 10,000 53.0 NG 2003. 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 Bernice lake 1 GT 1963 23,440 8.6 NG ;:; 1993 2 GT 1972 23,440 18.9 NG 2002 3 GT .1978 23,440 26.4 NG 2008 I nternat ion a I
Station 1 GT 1964 40,000 14.0 NG 1994 2 GT 1965 --* 14.0 NG 1995 3 GT 1970 --* 18.0 NG 2000 Copper Lake i HY 1961 --* 16.0 2011 Go 1 den Va I I ey Healy 1 ST 1967 11,808 25.0 Coal 2002 Electric 2 IC 1967 . 000 2.8 or 1 1997 Association North Pole 1 GT 1976 1 .. ~00 65.0 011 1996 (GVEA) 2 GT 1977 13,500 65.0 Oil 1997 Zehander 1 GT 197l 14,500 18.4 011 1991 2 GT 1972 14,500 17.4 Oil 1992 3 GT 1975 . 14,900 3.5 011 1995 4 GT 1975 14, 9:)0 3.5 011 1995 5 IC 1965 14,000 3. 5 Oil 1995 6 IC 1965 14,000 3.5 Oil 1995 7 IC 1965 14,000 3.5 Oil 1995 8 IC 1965 14,000 3.5 Oil· 1995 9 IC 1965 14,000 3. 5 Oil 1995 10 IC 1965 14,000 3.5 Oil 1995 Fairbanks Chen a 1 ST 1954 14,000 5.0 Coal 1969 ~1unlclpal 2 ST 1952 14,000 2.5 Coal 1987 Utt llty 3 ST 1952 .14, 000 t. 5 Coal 1987 System < FM US) 4 Gf 1963 16,500 1.0 Oll 1993 5 ST 1970 14,500 21.0 Coal 2005 6 Gf t976 12,490 23.1 011 1997 FMLS 1 rc 1967 11,000 2.8 Oil 1997 2 IC 1968 11,000 . 2.8 Ofl 1998 3 IC 1968 11,000 2.8 011 1998
- - - - - --· - - - - - - - - - -'--
TABLE 0.11 CCont I nued)
Ra II belt Station Unit Ul it Instal I at ion P.aat Rate Install eel
Uti I it~ Name No. TyEe Year (Btu/kWh) Ca2aclt~ (MW) Fuel T;tEe RetIrement 1\7ear
Homer Electric Homer
Association Kenai 1 IC 1979 15,000 o. 9 Oi I 2oog:
CHEA) pt. Graham 1 lC 1971 15,000 0.2 or 1 2001
Seldovia 1 IC 1952 15,000 0.3 Oi I 1982
2 IC 1964 15,000 0.6 Of I 1994
3 IC 1970 15,000 0.6 Oil 2000
University of Un I varsity 1 ST 1980 12,000 1. 5 Coal 2015
AI aska (U of A) University 2 ST 1980 12,000 1. 5 Coal 2015
University 3 ST 1980 12,000 10 .. 0 Coal 2015
Un Ivers lty 1 IC 1980 10,500 2. 8 Oil 2011
lhlverslty 2 IC 1980 10,500 2.8 Ot I 2011
Copper· Va I I ey CVEA 1-3 lC 1963 10,500 1. 2 Oil 1993
Electric CVEA 4-5 lC 1966 10,500 2 .. 4 Oil 1996
Association (CVEA) CVEA 6-7 lC 1976 10,.500 5 .. 2 Ot I 2006
CVEA 1-3 lC 1967 l 0,500 1.8 OIL 1997
CVEA 4 ·IC 1972 to, 500 1. 9 Oil 2002
CVEA 5 IC 1975 10,500 1.0· 011 2005
CVEA 6 IC 1975 10,500 2.6 Oll 2005
CVEA 7 GT 1976 14,000 3.5 Oil 1996
Matanuska Elec11 Talkeetna 1 lC 1967 15,000 o. 9 Oil 199/
Association (MEA)
Seward Electric SES l lC 1965 15,000 1e 5 Oil 1995
Sy-:tem (SES) 2 tc 1965 15,000 1 •. 5 011 1995
3-IC 1965 15,000 2. 5 011 1995
Alaska Power Eklutna HY 1955 30a0 2005
Administration
(APAd)
TOTAL 984.0
Notes:
~
GT = Gas turbine
CC =Combined cycle
HY = Conventronal hydro
IC = Internal combustion
ST = Steam turbine
NG = NaturaJ gas
NA =Not available
*Th ls value Judged to be unreal i stic for I arge rang a p l ann I ng and therefore Is adjusted to
15,000 for generation planning studies.
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TABLE D. ~2: SCHEDULE OF PLANNED UTILITY ADDITIONS (1980-1988)
Avg. Energy
utility Unit Type MW Year CGWh)
CVEA
CEA
AMLPD
CEA
COE
APA
TOTAL
So I ornon Gu I ch
Bern ice Lake 14
AMLPD IJ8
Beluga 16.7,8
Bradley Lake
Grant Lake
HY
c;r
Gf
cc
Hydro
Hydro
12 1981
26.4. 1982
90.0
42*
90.0
7.0
267.4
1982
1982
1988
* New Unit No. 8 w iJ I encompass Units 6 and 7, each rated
at. 68 MW. To-tal new station capacity wl If be 178 MW.
D
55
33
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TABLE 0.13: OPERATiNG AND ECONOI-11C PARAMETERS fOR SELECTED HYDROELECTRIC PLANTS
0 Max. Average ( 1981 $)
Gross Ins-talled Annual PlanT Capii"ifl
Head Capacfty Energy Faci"or Cost
No. Sii"e River (fi") CM~I) {Gwh) <%> ($10 )
1 Snow Snow 690 50 220 50 255
2 Bruskasna Nenana 235 30 140 .53 238
3 Keetna Talkeetna 330 100 395 45 463
4 Cache Tal keei"na 310 50 0 220 51 564
5 Browne Nenana 195 100 410 47 625
6 Talkeetna-2 Talkeetna 350 50 215 50 500
7 Hicks 3 f.,ai"anuska 275 60 245 46 529
8 Chakachamna Chakachai"na 945 500 1925 44 1480
9 AI i i son AI I i son Creek 1270 8 33 47 54
10 Strand I ine
Lake Beluga 810 20 85 49 126.
Notes:
<t> Including engineering and owner's administrative costs but excluding AFDC.
(2) Including IDC, lnsurance1 Amol'tizat'lon, and Ope1ation and MainTenance Costs.
(3) An indepedent study by Bechtel has proposed an installed capacit-y of 330 MW,
1500 GWh annually at a cost of $1,405 mil lion (1982 dol Iars), including AFDC.
Econamtc2
Cost of
Energy
($/1000 Kwh)
45
113
73
100
59
90
84
30
125
115
----~---------------
TABLE D. 14: RESULTS OF ECONOMIC ANALYSES OF ALTERNATIVE GENERATION SCENARIOS
:,
InsTal led Capacity (MW) by Total System ,,;
a~~ a~ System
Categor~ 1~2010 Installed ~$Sent \~orth
Generation Scenario OGP5 Run Thermal R:tdro Capacity In ~1--
Type Description Load Forecast ld. No. Coal Gas Oi I 2010 (MW) . ""'!J06 ~4~1if ) '""on,
All Thermal No Renewals Medium LMEl 000 801 50 144 1895 :8130
Thermal Pius No Renewals Plus: Medium LN/1 600 576 70 744 1990 7080
Alternative Chakachamna (500)1-1993
Hydro Keetna ( 100)...,1997
No Renewals Plus: Medtum LFL7 700 501 10 894 2005 7040
Chakachamna (500)-1993
Keetna (100)-1997
Snow (50)-2002
No Renewals Plus: Medium LWP7 500 576 60 822 1958 7064
Chakachamna (500)-1993
Keetna (100)-1996
Strand I I ne ( 20).,
Allison Creek (8),
Snow (50)-1998
No Renewals P]us: Medium LXF 1 700 426 30 822 1978 7041
Chakachamna (500) -1993
Keetna (100)-1996
Strandline (20>,
Allison Creek (8),
Snow (50)-2002
No Renewals Plus: Medium L403 500 576 30 922 2028 7088
Chakachamna (500)-1993
Keetna (100)-1996
Snow (50), Cache (SO),
Allison Creek (8),
Tal keeTna-2 (50),
Strandline (20)-2002
Notes:
( 1 ) -I nsta I I ed capacity.
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TABLE 0.15: SUMMARY OF THERMAL GENERATING RESOURCE PLANT PARAt-1ETERS/l982$
Parameter
Heat Rate (Btu/kWh>
Ear-ll est Ava i I abi J ity
0&1-1 Costs
Fixed O&M ($/yr/kW)
Var i ab I e O&M { &}l-1WH)
Outages
Planned Outages C%)
Forced Outages <%>
Construction Period (yrs)
Startup Time Cyrs)
Unit Capital Cost {$/kW>1
Ratlbelt
Beluga
Nenana
UnIt Cap ita I Cost ($/kW)2
Rall belt
Beluga
Nenana
Notes:
200 MW
10,000
1989
16.83
0.6
8
5.7
6
6
2,061
2,107
2,242
2,309
Comblned
Cycle
200 MW
8,000
1980
7.25
1.69
7
8
2
4
1, 075
1,107
(l) As estimated by Batte! le/Ebasco without AFOC.
Gas
Turbine
70 MW
12,200
1984
2.7
4.8
3.2
8
4
627
636
(2) Including IDC at 0 pecent escc:latlon and .3 percent Interest,
assuming an S -shaped expenditure curve.
(3) Excludes transmission.
Diesel
10 MW
11,500
1980
0.55
5.38
1
5
1
1
856
869
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TABLE D. 16: REAL (I NFLATJON-ADJUSTED) ANNUAL
GROWTH IN OIL PRICES
Growth Rates {Percent)
1982-2000 2000-2040 Probabi I i+~
Low Case
Medium {most t ikely
High Case
Base Period
(January 1982)
0
case) 2.0
4.0
P~ice of No. 2 Fuel Oil -$6.50fl~~tu.
0 0.3
1.0 0.5
2.0 0 .. 2
T.A.9LE D. 17: IX>t·1ESTIC MARKET ffiiCES AND E>roRT
OPPORTUNITY VALUES OF NATURAL GAS
Domestrc Market Price 1
Cow Medium High
Ex~ort Oeportunity Value
Cow Medium High
Probab i I i ty of
Occurrence N.A. N .. A~ N.A. 21% 46% 27%
Base Peri cd Vat ue. $3. OO/l•t\1Btu -$4. 65/Mt-1Btu 2 -
Real Escalat~n CIF
Pr i.ce, Japan
1982 -2000 N.A. O% 2% 4%
0
2000 -2040 O% 1% 2%
Real Escalaf'4on
Alaska Price
1982 -2000 O% 2.5% 5.0% O% , 2. 7% 5.2%
2000 -2040 O% 2.0~ 2.0% O% 1.2% 2.2%
OGP5 analysts used domestic markeT prices with zero escalation beyond 2010.
{Source: Battelle)
2 Based on Clf price in Japan ($6. 75) less estimated cost of I iquefaction and
shipping ($2.10). (Source: 19, 20, 21).
3 Source: ( 9)., {22h
4 Alaska oppor-tunlty value escalates more rapidly than CIF prices as IJque-
faction and shipping costs are estlmated -to remain constant in real terms •
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TABLE D. 18: SUf-1M..;.qy OF COAL OPPORTUNITY VALUES
Base Case
Battelle Base
Period CIF Pric~
Medium Scenario
-CIF Japan
-FOO Be! uga
-Nenana
Low Scenario
-CIF Japan
-Fee Beluga
-Nenana
High Scenario
-CIF Japan
-FOO Beluga
-Nenana
Sensitivity Case
Updated Base . 1 Period CIF Arice
f.1edi urn Scenario
-Clf Japan
-FOO Beluga
-FOO Nenana
Low Scenario
-Clf Japan
-FOO Beluga
-FOB Nenana
High Scenario
-Clf Japan
-FOO Beluga
-FOB Nenana
/ ..
Base Period
(Jan. 1982)
Value
{$/MMBtu}
1 .. 95
1.43
1. 75
..
1. 95
1.43
1. 75
t. 95
1.43
1. 75
2.66
2.08
t. 74
2.66
2.08
la 74
2.66
2.08
1. 74
Annual Real Growth Rate
1900 -2000
(:£)
2.0
2.6
2.,3
0
0
o. 1
4.0
5.0
4.5
2.0
2.5
2.7
0
0 \ -o.2
4. 0
4 .. 8
5.3
2000 -2040
C%>
lo 0
1.2
t. 1
0
0
o. 1
2.0
2.2
t. 9
1.0
1.2
1. 2
0
0
-o. 1
2.0
2.2
2.3
Probab i ll ty
of
Occurrence
,%
49
49
49
24
24
24
27
27
27
49
49
49
24
24
24
27
27
27
Assuming a 10 percent discoun-t for Alaskan coal due to qual tty differen-
tials, and export potential for Healy coal.
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TABLE D. 19: Stt-1MARY OF FUEL PRICES USED IN THE
OGP5 PROBABILITY TREE ANALYSIS
Fuel Price Scenarlo
Low Medium ~
Probab II i ty ot occurrence 25% 50% 25$
Base period January 1982 prices
( l982$fi~>1Btu)
Fuel Oi 1 6. 50 6.50 6.50
l'etura I Gas 3.00 3.00 3.00
Coal
-Beluga 1.43 1.43 1.43 -Nenana 1. 75 1. 75 1. 75
Real esca,ation
{percenT)
rates per year
Fuel or 1
-1982 -2000 0 2.0 4.0 -2000 -2040 0 2.0 2.0
Natural Gas
-1982 -2000 0 2. 5 5.0 -2000 -2040 0 2.0 2..0
Beluga Coal
-1982 -2000 0 2.6 s.o -2000 -2040 0 1.2 2.2
Nenana Coal
-1982 -2000 Oo 1 2.3 4.5 -2000 -2040 0.1 1. 1 1. 9
1
Beyond 2010., the OGP analysis has used zero real escalat.ion in
all cases.
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TABLE D. 20: ECONQ.'\IC ANALYSIS
SUSITNA PROJECT -BASE PLAN
1982 Present Wortn gt System Costs
$X 10
Plan lD
Non Susitna A
Susitna c
Net Economic Benefit
of Sus itna Plan
1993-Estimated
Components 2010 2010 2011-2051
600 J.,W Coal-Beluga 3,213 491 5,025
200 MW Coa I -ten ana
630 MW GT
680 MW \~atana 3, 119 385 3,943
600 MW Devi I Canyon
180 MW GT
TABLE D.21: SUv1MARY OF LOAD FCRECASTS
USED FOR SENSITIVITY ANALYSIS
MEiJdlum Low High
MW GWh MW GWh MW ----
1990 892 4,456 802 31999 1,098
2000 1,084 5,469 921 4,641 1,439
2010 1, 537 7, 791 1,245 6,303 2,165
1993-
2051
8,238
7,062
1,176
GWh
5,703
7,457
llg435
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Plan 10
Non-Susitna Kt with
Low forecas-t
Susitna Kz with
Low ForecasT
Non-Sus I tna Jl with
High Forecas-t
Susitna J2
with
High Forecast
1 From 1993 to 2040
Plan 10
Non-Sus itna Ql
Susttna Q2
l'bn~Sus l tna A
Susltna c
Non-Sus Itna sl
Susitna 52
Non-Susitna pl
Susitna p2
TABLE 0.22: LOAD FORECAST SENSITiVITY ANALYSIS
1982 Presen1' Worth of System Costs ($ X 106 )
Nat 1993-Estimated 1993-Economic Comeonents 2010 2010 2011-2051 2051 Benet i"t
400 MW Coal-Beluga 2,640 404 4,238 6,878
200 MW Coal-Nenana
560 M'l'l Gf
680 MW Watana (1995) 2, 882 360 3, 768 6,650 228
600 MW Davi I Canyon (2004)
800 MW Coal-Beluga 4,176 700 6,683 10_, 85911
200 MW Goa I -Nenana
700 MW Gf
430 M\~ Pre-1993
680 MW Watana (1993) 3,867 564 5,380 9,24711 t, 612
600 MW 03v II Canyon
350 M'li Gf
( 1997)
430 MW Pre-1993 (\
TABLE 0.23: DISCOUNT RATE SENSIT!VITY AIMLYSIS
1982 Present Worth of S~stem Costs ($ X 10 6 )
Real
1\et Discount Rate 1993-Estimated 1993-Economic (Percent) 2010 2010 2011_;2051 2051 BenefiT
2 3, 701 465 7, 766 1 l, 167
2 3, 156 323 5;394 8,550 2,&17
3 3,213 491 5,025 81328
3 31119 385 3,943 7,062 1, 176
4 21791 517 3,444 6,235
4 " 3,080 457 3,046 6ll 126 109
5 2,468 550 2,478 4ll946
5 3,032 539 2,426 5,459 (513)
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TABLE 0.24: CAPITAL COST SENSITIVITY ANALYSIS
.
1982 PresenT Worth of System Costs ($ x 106 )
t-at
1993-Estimated 1993-EconQTiic Plan ID 2010 20l0 2011-2051 2051 Benefit ---
Non-Susitna Capital
CosTs Up 20 Percent
Non-Susitna G 3,460 528 5,398 8,858
Susitna cl 3, 119 385 3,943 7,062
Non-Susl tna CapiTal
CosTs Down 10 Percent
Non-Susitna G 3,084 472 4,831 7,915
Susitna cl 3, 119 385 3,943 7,062
Susitna CapiTal Costs
less Contingency
Non-Susitna A 3, 213 491 5,025 8,238
Susitna x2 2, 710 336 3,441 6, 151
Susitna Capital Costs
Plus Doubled ConTingency
Non-Susitna A 3, 213 491 5,025 8,238
Susitna Y2 3,529 434 4,445 7,974
1
An adjusTment calculation ~'as made regarding the + capitai costs of
the 3GT gnit·s added in 2007-2010 since the difference was less than
$10 x 10 • Beyond 2010, this effect was not inc I uded.
TABLE 0.25: SENSITIVITY ANALYSIS -UPDATED BASE PLAN
(JANUARY 1982) COAL PRICES
1982 Present Worth of S~stem Costs Base
Period Beluga Costs of Costs of
Coal Price t-bn -Sus i tna Susttna
( 1982 $JVJ-Btu) Plan Plan
Base Case 1 .. 4.3 8,238 7,062
Sensitivity
{Updated) Case 2.08 9,030 7,062
1,976
853
2,087
264
($ X 106l_
Net
Economic
Benefits ---.-
1, 176
1,968
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TABLE 0.26: SENS IT I V J TY ANALYSIS -REAL COST ESCALATION
1982 Present Worth gt Sys-tem Costs
($ X 10 }
1993-Estimated 1993-Net Plan 10 2010 2010 20] 1-2051 2051 Benet IT
Zero -Esc a I aT ion in
Cap iTa I and O&M Costs
• Non-Sus iTna o, 2,838 422 4, 319 7, 157 • Susl-tna o2 2,525 299 3,060 5,585 1, 572
Escala-tion in Capital 1 Cos-ts and O&M (Battelle)
• tbn-Susi-tna x, 3,142 477 4,881 8,023 • Susit'na x2 2, 988 366 3, 745 6, 737 1, 286
Double Escala-tion
Capital and O&M Costs
• Non-SusiTna Pt 3,650 602 6, 161 9,811 • Susitna P2 3,881 503 5, 148 9,029 7ffl.
Zero-Escala-tion
in Fuel Prices
• Non-Sus iTna vl 2,233 335 3,427 5, 660 • Susitna v2 3, 002 365 3, 736 6, 738 (1, 078}
High Escalation
in Fuel Prices
• Non-Susli11a Wt 4,063 643 6, 5'74 10,367 • SusiTna Wz 3, 267 403 4, 12 t 7,388 2,979
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"CapiTa I and O&M costs assumed to esc a 1 ate at 1. 4 percent 1982 to 2010
TABLE 0.27: SENSITIVITY ANALYSIS -NON··SUSIT~
PLAN WITH CHAI<ACHAMNA
Plan
• t-bn-Sus i-tna With
Chakachamna
• Sus itna
10 Components
B 330MW Chakachamna
400 t-1W C~a I ~el uga
200 MW Goat ,.;\en ana
440 t.ff/ GT
c 680 MW W3tana
500 t-tl'/ Oevi I Canyon
180 MW GT
,}
1982 Aresent Worth gt System CosTs
CS X 10 )
1993
2010 2010
Estimated 1993-Ne-t
2011-2051 2051 Bene.fi"t
2, 038 475 4,861 7,899
3,119 385 3,943 7, 062 837
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Susitna Base Case I One-year delay for
Wa-tana ( 1994)
I One-year delay for
Devil Caryon (2003)
One-year delay for
I \~at"ana and Dev i I
Canyon ( 1994, 2003)
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TABLE 0.28: SENSlTIVlTY ANALYSIS-
SUSITNA PROJECT DELAY
$ X 106
$X 106 1982 Present \'#orth
ID of System Costs Ne-t Economic Benefit
c 71062 1, 176
C3 7, 105 1, 133
04 1~ 165 1, 134
C5 7,230 1~ 138
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TABLE 0.29: SIJ~HARY 0:: SENSITIVITY ANALYSIS INDEXES
OF NET ECONOMIC BENEfiTS
BASE CASE ($1,176 MIL~ION)
Fuel Escal a-t!on
-High
-Low
Discoun-t Ra-tes
-High-High {5%>
-High (4$)
-Low <2%>
Susi-tna Capi-tal Cos-t
-High
-Low
Load ForecasT
-High
-Low
Non-Susi-tna (Thermal)
Capi-tal Cos-ts
-High
-Low
Capi-tal and O&t-4
Cos-t Esc a I at ion
-High
-Intermediate (Battelle)
-Low
Chakachamna (included in
Non-Susitna Plan)
Updated Base Coal Price
Planned Delay In Susitna
Project
-One-year delay, Watana
-One-year delay, ~latana and Dev tl Canyon
-Two-year delay, Watana and DeylJ Canyon
Index Values
100
-44
9
223
23
178
137
19
166
73
67
109
134
71
167
96
96
97
1
High fuel escalation case provides net benefi-ts equal to 253 percent of the
base value, 2.53 x $1,176, or $2,975.
2 low fuel escalation case provtdes minus 92 percent of The base case net
benefits, -. 92 x $1, 176, or -$1,082.
-------------------
TABLE 0~30:. BATTELLE ALTERNATIVE STUDY
Resource Princtpal Sources Fuel Base for Ra ilbe lt Conversion
Coal Beluga Field. Caok Inlet Crush
Nenana Field, Healy
Natural Gas Cook Inlet
North Slope
Petroleum Cook Inlet
North Slope
Peat Kena 1 Peninsula
Lower Susitna Valley
Mun 1c'ipa 1 Refuse Anchorage
Fa irbaak s
Wood Waste Kenai
Anchorage
Nenana
Fairbanks
Gasification
Liquefaction
None
Refine to
distill ate and
residual fractions
t
None
Gasification
Sort & C'assify
• Hog
Generation T,lp1cal Technologx A[![! icat.1on
Direct-Fired Steam-Electric Base load
Oirec t-F ired s team-Electric Ba.seload Combined Cycle B!iseload/C.vc linq Fuel-Cell -Combined-Cycle Base load
01rect-Ffred Steam-Electric 8aseload Combined Cycle Base load/Cycling Fuel-Cell Station Baseload/C~cling Fuel-Cell -Combined-Cycle Bas;eload
Direct-Fired Steam-Electric Base load Combined Cycle Baseload/Cyclinq Fuel-Cell Station Base load/Cycling Fuel-Cell -Combined-Cycle UasP.loacl Combustion Turbine Base load/Cycling
01rect-F1red Steam-Electric Basaload Combined Cycle Base load/Cycling Fuel-Ce n Stations Base load/Cycling
Fuel-Cell -Combined-Cycle Base load Combustion Turbine Base load/Cycling Oiese 1 Electric Base load/Cycling
Direct-Fired Steam-Electric Base load
Direct-Fired Steam~Electric Base load Combined Cycle Baseload/CyclfnQ
Fuel-Cell -Combined-Cycle Base load
Direct-fir·ed Steam-Electric Base load( a)
Oirecto·Fired Steam-Electric Base load( a)
Avai labi titw "fhT
r.onmerc i a 1 {!~.~Pr
Currently Av~~1nb1e
1985-1990
1905-1990
1990-1995
1985-1990
1985-1990
1985-1990
1990-lQ95
Current l v A<Jil$ \;~b le
Currently Avail':~hle 1905 ':Qt)Q
199( ,.,i!Ji. ,.
Curre~·~. :y Ava~n.ablp
Currently Ava id!ahlt"
Currently Ava}~abl~
1985-1990
19q0-1995
Currently Ava\lahle
Currently Avatl~hlp
Currently Availablp
1990-2000
1Q90-2000
1990-7000
Currently Ava1lablp
Currently Available
------------------
I ....
Resource
Base
Geothermal
Uydroe 1 ec tric
Tidal Power
Wind
Solar
Uranium
Principal Sources
for Railbelt
Wrangell Mountains
Chigmit Mountains
Kenai Mountains
Alaska Range • ·
Cook Inlet
lsabe 11 Pass
Offshore
Coastal
Throughout Region
Import
TABLE 0.30 {Contd)
Fuel
Conversion
Enrichment &
Fabrication
Generation
Technology
Typical
Applicati~n-
Avai1··"1ilit.v f'~nr
Comw~~·r. ia 1 OrtJ~r
-;t"-·~
Hot Ory Rock-Steam-Electric Base1oad
Hydrothermal-Steam-Electric Baseload
1990-2000
r.urrPnt.lv Avai;.1:llh1P
Conventional Hydroelectric
Small-Scale Hydroelectric
Microhydroelectr1c
T1da 1 Electric
Tidal Electric w/Retime
Large Wind Energy Systems
Small W1nd Energy Systems
Solar Photovolta1t
Solar Thermal
Light Water Reactors
0
Bilseload/CyclinQ Currently Avaftrr~hlP
(b) Currentfy Avat:;nhle
Fuel Saver Currently Ava·i n·ahle
Fuel Saver Currently Avai!inble
BaseloadfCyclinq Currently i\vaF1nhle
Fuel Saver
Fuel Saver
Fue 1 ·Saver.,
Fuel Saver
Base load
19R5-I9qo
1985•1990
1985-1990
1995-?000
Currently AvafU~blP
(a) Supplemental fir1ng (w/eoal) would be required to support baseload
operation due to eye lica 1 fue 1 supply.
(b) May be baseload/cycling or fuel saver depending upon reservoir capacity.
.. . . . .• .. ~· '. . . . :. .· '. " ' .
. . . . • . ·. ":;' ~\7 . . : . . ; . .. .. . . . ~ . . . . ,. . . .. ...:. ..~ . It Jt;~~ .... • -• : ~ ·~. • ..•• o. .. .: ;f:. ~ .-
. . .
_J ...... ·.$ •. ~ ~ .:· ·;~· ·~~· .. 0 '. •·: 0 • • ~: • •• --.. • • • _,. A ·-~ ', ...
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TABLE 0.31: BATTELLE ALTERNATIVES STUDY
Alternative
Average
Annual Capafl)Y . Heat Rate Availability Energy
Qlltl. (Btu/kWh) . {S) ·-{GWn)
Coal Steam-Electric {Beluga)
Coa 1 Steam-Electric (Nenana)
CoaJ Sasifi2r-Combined Cycle
Nati. Gas Conbustion Turbines
Natl. Gas Combined Cyc1~
.
Natl. Gas Fuel Cell Stations
Natl. Gas Fuel Cell Comb. Cyc.
zoo
200
220
70
200
25
200
Bradley Lake Hydroelectric 90
Chakachamna Hydroe1ec. {330 MW)(d) 330
Chakachamna Hy~roelec. (480 MW)(e) 480
Upper Susitna (Watana I}
Upper Susitna (Watana II)
Upper Susitna (Devil Canyon) .
Snow Electric
KeetnC! Hydroelectric
Strand 1 i ne Lake 1iydroe lee.
Browne Hydroelectric
Allison Hydroelectic
Grant lake HydrPelectric
Isabell Pass Wind farm
Refuse-Derived Fuel
.Steam Electric (Anchorage}
Refuse-Derived Fuel
Steam Electric (Fair!Janks}
680
340
600
63
100
20(17)
100(80)
8
7
25
50
20
10,000
1011000
9,290
13,eoo(b)
8,2oo<c)
9,200
5,700
14.000
14,000
97
85
89
85
91
83
94
.94
94
94
94
94
94
94
94·
94
94
36
N/A
N/A
347
157(1
1923
3459
3334
220
395
85
430
37
8
{a) Configuration in parentheses used in ana1ysis of RaiU:"lc electric el'lergy
p1 us taken from t=arl ier estirnates (Alaska Power AuthO"ltY 1980)
(b) ,, neat rate of l2YOOO Btu/kWh was used in analysis ot~ Railbelt electric
energy plans. 13,000 Btu/kWh is probably more. representative of partial
load op..!ratioo characteristic of peaking cfuty ..
(c) An ear tier estimate of 8500 Btu/I<W'h was used in the f".nalysis of Railbelt
electric energy :1lans. ·
{c!) Configuration selected in preliminary feasibility study (Bechtel CivP and
Minerals 1981)
(e) Ctlnfigurati"ff selected in Railbelt alternatives study {Ebasco 1982b}
Capital
Cost
{S/kli}
2090
2150
130
1050
890
3190
3860
2100
4669
168
2263
5850
5480
7240
4470
4820
2840
2490
2980
3320
Fixed O&M
(S/KW/yrj
16.70
16.70
14.80
48
7.30
42
50
9
4
4
5
5
5
1
5
44
5
44
44
3.70
140
140
Variable
O&M
{mills/kWh}
0.6
0.6
3.5
1 .. 7
3.3 •
15
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TABLE 0.32: SufTiilary of Electrical Energy Alternatives Included as
Future Additions in Electric Energy Plans
BASE LOAD ALTERNATIVES
Coal Steam Electric
Refuse-Derived Fuel Steam Electric .
CYCLING ALTERNATfvtS
Coal Gasifier -Combined-Cycle
Natural Gas -Fuel Cell-Stations
Natural Gas -Combined-Cycle
Natural Gas -Combustion Turb1ne
Natural Gas -Fuel-Cell Combined-Cycle
Bradley Lake Hyd!"oelectric
Grant Lake Hydroelectric
Lake Chak achamna Hydroe 1 ectri c
Upper Susitna Hydroelectric
A 11 i son Hydroe 1 ectric
Browne Hy9roe1ectric
Keetna Hydroelectric
Snow Hydroelectric
Strandline lake Hydroelectric
FUEL SAVER (INTERMITIENT) ALTERNATIVES
Large Wind Energy Conversion System
ELECTRIC ENERGY SUBSTITUTES
Passive Solar Space Heating
Active Soiar Hot Water Heating
Wood-Fired Space Heating
ELECTRIC ENERGY CONSERVATION
Building Conservation
~
(a) Plan 1: Base Case
A. Without Upper Susitn~
S. With Upper Sus i tna
1
X
X
X
X
X
X
X
Electric Energy Plan(a)
lB 2A 28 3 4
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Plan 2: High conservation and use of renewables
A. Without Upper Susitna
B. With Upper Sus·itna
Plan 3: Increase Use of Coal
Plan 4: Increase Use of Natural gas
0
X
X
X
X
X
-.. ------ ----lllrJI ----.
. -
*'~l)·~~:";~l;!:;:,:;:t,:(!:::=::<:(rf.-*S::~f.:::t***********!)*:)**':'•~""""'.._ ... ..._ .... .,. ..... .._ ... _.. ... , ..... _._ ... ..._~..._ ... ..._ ................. ...,~t,::;:*¢t,:'¢*(t:***************************(U)(t:************~;~_:;.:(tl)'¢.>::;;Cl:;:*
OATAlOK \#AlANA-DC <ON UNf lq'B-Z002)· INFLATION 7~-INTEREST 10~-CAP COST £5.,.117 BN 23-{t.;,f-B-62
.;o:**'::*****(l'(t(l#'l<**>:l****(::)S::(t¢(t:,.-c***(::(tt.:***"'Ji:l:;:J\I::;t•;n:r:;t~:;t:I;J:C,U.ll:(Xs;:J\I:~Ji:l·::s;:***************:ct***********************:c<***:C:**¢****:(t*~:ct*lli!Ct*:¢~i;.l;***'*"***
7J E~fRGY GWH
Sll ~EAL PRICE-HILLS
46b INFLATION lNOEX
'>20 l>"lCE-MllLS
-----lNCOM~-----------------'iltl REVENU£
170 LCSS OPeRATING COSTS
~17 0P~R4TING INCOMe
21~ ADD l~TEREST f.ARNfO lN f-UN0S
-~50 LESS INTeREST ON SHORT T=RH DeBT
391 lESS INTEREST ON LONG TERM D~BT
54U ~ST EARNINGS fRO~ JPfRS
-----CASH SOURCe AND USC----
54~ CASH INCO~f FRCM OP~RS
~4~ STATE CONTRIBUTI~N
143 LONG TERH DEBT O~AWOOWNS
l4d·~ORCAP DEBT ORAWOOWNS
TOTAL SOURCtS OF FU~DS
320 L~SS CAP(TAL CXP(NOITURE
44tl LESS W~RCAP ~NO FUND~
2o0 LFSS 0£8T RePAYMENTS
141 C~SH SURPLUS(DEFICIT)
~4~ SHORT TfRH DlBT
4~4 CASH RECOVERED
-----bALANCE SHt~T----------
22~ ~ESERV~ AND CONT. FUND
j7l OTHER WORKING CAPITAL
4S4 CASH SURPLUS RETAINED
370 CU~~ tAPlTAL EXPENOITUR~
~bj CAPITAL eMPLOYED
o 4hl STAT£. CONTRtnUTICN
4bl ~t\AINtO lAPNlNG$
S'b (;f{\T OlJTSTANDING-SIHlRT Tt:RM
554 DEBT OUTSTANDING-LONG TERM
54l A~NUAl orsT ORAWWUOWN 51962
543 tUM. 0~6T DRAW~DOWN $l98Z
)11 DEdT StRVICE CO\ER
1985
0 o.oo
l2oo72 o.oo
o.o o.o
1986
0 o.ao
135.59 o.oo
o.o o.o
1961 19Ba l98q
CASH FLOW SUMMARY
===fSMILLION)====
0 0 o.oo o.oo
145.08 155.24 o.oo o.oo
o.o o.o u.o o.o
0 o.oo
166.10 o.oo
o .. o o.o
0 o.oo
177.73 o.oo
o.o o.o
0 o.oo·
1q0.11 o.oo
o.o o .. o
1992
0 o.oo
203 .. ltB o.oo
o.o o.o
19q3
3387'
3.b:~
217.1'~
7.9"~
2& .. ~
26.~
.}3tH
7.Q8
231-.97
l~.s;q
-----------------------------------------------------------------------· ~-------o.o o.o o.o o.o
o.o o.o o.o o .. o
o.o o.o
O.l) o.o
o.o o.o o.o o.o
o.o o.o o.o o.o
o.o o.o o.o o .. o
o.o o.o o.o o.o
o.o o.o o.e o.o
1).6
r;.. 6.
9.8 o.o --------------------------------------------------------------------------------o.o
o.o
403o7 o.o o.o
o.o
o.o
it72.7 o.o o.o
o.o
o.o
47 '1 01 o.o o.o --------~--------~-~----
403.7 o.o o.o
472.7 o .. o o.o
479.7 o.o u.o
o.o
o ... o
~99 .. 5 o.o o.o
o.o
o.o
938.3 o.o o.o
o.o
o .. o
1550.4 o.o o .. o
499.5 . 938.3 1550.4
499.5 u.o o.o
938.3 o.o o.o
1550.4 o.o o.o
o.o
o.o
1 247 0 l o.o o.o --------1 24 7. 1
1Z47.1 o.o o.o
o .. o
o.o
676.4 o.o o .. o
676.4
676.4. o.o o.o
-------~
43lol
333 ... l
98.0. o.o
29.5
2zq.,7 o.o
17.7 ,_,,... _____ _
276.9
2-'>9 .. 2
17.7 o.o ----------------------------------------------------------------------~---------o.o o.o o.o
o.o o.o o.o
403. '1 --·----·----------403.7 _..._._. _____ _ --------403.7 o.o u.o o.o
o.o o.o o.oo
o.o
0 .. 0
OoO
o.o o.o o.o
676.4 _______ ,_ --------876.4
O.l)
OoO o.o
o.o o.o o.('\
135bel
=·====-=·==
1156. l :::::::: ::======
876.4 o.u o.o o.o
o.c o.o o.oo
1356.1 o.o o.o o.o
o.c o.o
tJeOO
o.o o.o o.o
o.o o.o o.o
l855e6 ----------------l35S.b ----------------1355.6 u.o o.o cr.o
o.o
0.0 u.oo
o .. o o.o o.o
o.a o.o o.o
2794.0 ----------------2794.0 -----------------l19t..o. o.o o •. o o.o
o.o o.o o.oo
o.o o.o o.o
o.o o .. o o.o
4344t.3 ----------------
=::==-==::=
lt34/e • .3 o.o o.o o.o
o.o o.o o.oo
J.O o.o o.o
o.o o.o o.o
5591.4 ======== 5591.4 -----------------5591.4 o.o o.o o.o
o.o o.o o.oo
o.o o.o o.o
o.o o.o o .. o
6267.8 ::t======:
62b7.B
o. \) o.o o.Q
56 .. 5-
.r.t.ill. o.o
6600.9
:-::::::;;::::t
6698.'} ======== ·~=====· 6267.8 o.o o.o o .. o
o.o o.o o.oo
6bOO.~ o.o
98.Q o.o
0~!!0 o.o o.oo
o.o o.o o.o
6le6
')4.1 o.o
6860.1 :!::.======
b91"5.B
c.a.:w.6
l~.S
ll~-7 o.o
o.,o o.o o.oo
100% STATE APPROPRIATION OF TOTAL CAP2TAL COST {$5.1 BILLION IN 1982 DOLLARS) TABLE o.33[A~.amJ Sheet 1 of 3
=~o~=~*~***u*****~*=¢~ouo**~*********~~-·~·-~··~-·~-·~~·--~·~-·--1~ooooo~**********~**********************c**********~~~******* OATAlO~ WATA~A-~t {ON LINE 1993-2002)-iNFLATION 7~-INTEREST 10~-tAP COST ~5.117 8N 23-~~~-~2
·~=~oooooo~~**************************~=~~oooooPooooooooo~oooooooooooooooooooooooooooooooooooooooooooooooooo~~*******•••******
fl tNI-R~\' G"'H
'J 71 1t r A l P R l c c-M 1 t l S
46n INfLATION lNOEX
.,l> PR1Cl-Hlll5 •
-----tNC~~(-----------------
r, 1 b lt r;v (NUl,
lhl lCSS OPE~.\TtNG COSTS
'll1 ,)PtRATlNG INCO.,.C
ll~ '00 1NTSRE~T ~ARN~O ON FUNDS
~~~ LtSS INT~REST ON SHORT TERM OE81
191 l~SS INTER~ST ON l~NG TERM DEBT
S4~ NFT EARNINGS FROM CPERS
' '14·.
~4h
l 41
24'i
'j4l
-----CASH S00RCC AND US~---
l'\SH INC:JMF F:lOM l)~'~tRS
~TAlF CO~TRlCUTlON
t (}N(j Tt:RH llHH ORAWI)OWNS
~ORLAP DEdT ORAWOO~NS
TOTAl S00RCES OF FUNDS
J20 t!:SS CA'PITAL E~PENtllTURC
44H lfSS HilRCAP AND FUNDS
760 leSS DEBT R~PAYMENTS
141 £49
lt44
"l.l ~.
371
4 '> ..
370
CAS~ SU~PlUStOEFltlT) SHOkT TERM DEaT
CASH RECOVERED
··----BALA.NCE SHEET----------
RESE~VE AND CONT. FUND
~THeR WO~KlNG CAPITAL
CASH S0RPLUS RETAINED CUM .. CAPITAL EXPENDITURt
CAPITAL EMPLOYED
461 STAlf CCNTRI&UTtON
4~2 RETAINED EARNINGS
~S~ OFBT OUTSTANDING-SHORT TCRM
554 nEBT OUTSTANDING-LONG TERM
~4Z ANNUAl OEBT JRAWW~OWN ~1982
543 tu~. DEBT URAwWOOWN $1982
SlQ DEBT SERVICE COVER
33tH
B.38
Zbo.73
Z7..3b
75.7
35.0
1 ~9d 1~99
CASH FLOw SUMMARY
=:=CSHILL!QN)====
3387 3367 3387 a.74 a.aa 9.04
28~.~0 305.38 j26s7S
z~.q3 27.13 29o53
t\4.4
38.1
100.0
4 5.4
2000
3387
9.17
349.62
32 .. 06
2001
33a7
q ... 30
374.10
34.79
117.8
':>4 .. }
2002
5223
1obb
400.29
30.64
. 2003
541~
8.64.
42tl.Jl
37.t3t>
2004
;;;,60:'i
ll.6B
.r.'ifl.l9 ,q.ao
--------------------------------------------------------------------------------37.6
baZ
11.6 o.o
40.8
6.7
12.4 o.o
50.2 o.o
lbo4 o.\J
54 .. 6
t\.1
17.7 o.o
69.0
11.4
ZlaO o.o
l05.'i
l q. t
31.8'
O.Q
U4.o. zo.q
3o.3 o .. o --------------------------------------------------------------------------------3Z .• 2
32.2
363 .. 1 o.o
tl.l
40'3.4
39'5 .. 3
8.1 o.o
3'5.1
3dl.l o.o
29o3 --------446$5
~17.2
29o3 o.o
'18.3
303.8 o.o
11.2
35 3.1
34 z.1 n. 2 o.a
41.8
41.8
102e.3 o.o
lZo2 __ '"""'_ ..... __ _
lOu2.4
1070.1
12.2 o.o
45.6
45.6
1177.5 o.o
10 .. 6
123 3.7
1223.2
10.!> o .. o
49 .. 8
1204.8
0 at) to., ... _.,...,. ___ _
1265.1
lZ54.o
lO.lt o.o
54.4
'H 3.1 o .. o
12. 3 -------"""'!"' 979.0
9b 7. 5
12.3 o.o
59.3
490.3
36Z.3
128.0 o.o
90.<;-
99.2 o.o o. •. o
4l .. 6 ·-------
--------------------------------------------------------------------------------o.o o.o o.o
o7.Z
5b.b o .. o
7255.4
7379.2 ====='='== 7193.7
blob
123.9 o.o
o.o o.o o.oo
o.o o.o o.o
73.4
19.1 o.o
7b7le6
7325.7 ========-7575 .. 9
9~.a
153.1 o.o
o.o o.o o.oo
o.o o.o
OoO
qo.1
84.2 o.o
8014.7 ----------------6179.0
:::::::::
7'\79.6
l35e1
1 () 4. 3 o.o
o.o o.o o.oo
o.o o.o o.o
67 ...
a9.l o.o
9084.8 -========
----------------1:3907.·}
176.,0
l7bob o.o
o.o o.o o.oo
o.o o.o o.o
95.4
91.7 o.o
10308.0 ======== 10495.1 ----------------10085.4
2Z.l..b
187.1 o.o
o.o o.o o .. oo
o.o o.o o .. o
104 o1
93.4 o.o
l\56l. 6 ----------------11760.2 =-=-====== 11290.3
272.4
197.6
OoO
o.o o.o o.oo
o.o o.o o.o
113.7
9b.Z o.o
12530.1
========
12740.0
=====:::.::
12203.4
326.7
209.9 o.o
o.o o.o o.oo
o.o o.o o.o
Pn.3
l46 •. b o.o
1289Z.5
13230.3 ======== 12506alt
386 .. 1
337.8 o.o
o.o o.o o.oo
13345.~
121)06.<\.
lf11.Q
362.6 o.u
o.o o.o o.oo
o.o o .. o o.o
t)A~n.q
'===='=~== 12506.4
1)76-l
o\0'5.4 o.o
o.o o.o o .. oo
Sheet2 of 3
100% STATE APPROPRiATION OF TOTAL CAPITAL COST ($5.1 BILLION IN 1982 DOLLARS) TABLE £4531 A~~l~ I
-- --- -
-- - --- -----
~~ ¢ -•':.; ,.! ; .. ~*!..!·~~'t,:~: ::t ** **~¢(rt.: *·::t :)¢:*:l"::t~t~: **:).¢::;::; ... -.. .............. .;.~ .. A.-... ..... <A.._.,._"""'~..~ ... ~ ..... ,~., ..... .-. 4 •.J.wt.. ....... • .. ,..,., ..... *t::~**:~:~s;:::: ***~* **:~:);~-:)')~****·*~* ***·l) ') :;t:e: **:) J!r~~J:t*~**(:~~***~~.::;'*~'*e:*~
DAT\l0K WATANA-OC CON Ll~~ 1993-2002) ·INFLATION 7%-lNTEREST 10~-CAP COST 15.117 BN 23-F~R-82
:0:-;:t~;'r ~;:t:¢~;:t¢¢·~~~~********~***:;)*~******l(: • .r;::;r~!;T::;::;::;r::;:;;~::t=:;r:;:s;r.:;:::;r:.:;::;::;:s;r:;::;:::;:¢******~********:,.';.(r.(:>)J)"(l"(l~.(r******~*********************~****~~.);:~:t>:****
7\ N(RGY GWH
5!1 ~fAl P~lCE-MillS
4bh IN~LATlON INDEX
')Z,J PRlCE-J11LlS
-----lNtOM~-----------------
'11 '> 1\f VfNUf
lf1 LtSS OP~RATING CJSTS
•; 1 1 tl P ~~ q AT l N G 1 N C 0 H t:
ll4 ADD JNTF~EST EARNED UN FUNDS
'l').l lFSS ltHf:RFST ON SHORT Tt:RM OFBT
\'H t.C~S INTlRfST ON dONG TrR"1 DCtH
*, 4 , N t f ~ A Hli N G S F R U M .J l) t R S
-----Lt.SH <ii'ltJkC.f J\ND USE----
c)4•J C.\ lli lNCOMi.. FROM ::lPERS
44•, .)TAT£ CONTRifJUTltlN
143 LONG TERM DEBT DRAWUOWN~
l41 wllRCltP OtBT !>RAkOOWNS
~4~ TOTAl SOUflCFS uF FUNDS
120 Lt~S CAPITAl EXPENOITURF
44d L~S~ WORCAP AND FUNDS
Zb~ L~SS OtBT REPAYMENTS
141 CA~H SUR~lUS<DEFJCIT)
14·1 'i HOR T TERM DE: l\T
444 CASH RECOVERGD
-----OAlANCE SH[fT----------
2/~ Rf~ERV( ANO CO~T. ruND
3Tl .1'flllR WOPKING CAPITAl
4~4 CA\H SURPLUS RETAINiO
370 CUM. CAPITAL EXPENDITURE
4o, C.APJiAL EMPLOYeD
~61 \rATt CONTRidUTJO~
4b2 N'TAINFO FARNI~GS
t•c," ,HilT OUTSTAN')ING-'iHU~T TERM
~,4 ~f UT OUTSTANDING-LONG TERM
~4£' 1\NNliAl l)!;IH .)1\Al'IWGOWN Sl982.
'l't1 (,IJM. DE-BT ORAWWDOW•'i UQBZ
~1~ U~Qf StRVICt COV~R
l005
60Ql
8.lfl
490.37
40.12
l?t>-0
2.2. R
4(').5 o.n
lO!Jo2
108.2 o.o o.o
36.4
2006
bl47
0.27
524.69
43.39
1 n.~
24.9
44.2 o.o
ltU.l
lltl.l o.o o.o
51.3
2007 200~ 2009
CASH FLOW SUMMARY ===(SMILllON)====
6250 6472 654b
Oe33 ~.24 8o30
561.42 600.72 642.77
4bc75 49e49 SJ.3i
.:>•U.l
141.0
l2U .. 9
320 • .}
153o9
166.3
}q.b
5t;.~ o.o
140.7
140.7 o.c o .. c
4S.B
349.1
lOEJ.O
2010
6616 a.3s
687.77
57.45
16'7 .. 6 o .. o o.o sz.o
2011
6638
8.411
735 .. 91
62.39
4lio .. l
200.[
214.0
'· ')" "i td. () o .. o ---"" .... fi!Q.--
zo 12
66b0
B. 57
7tn.4z
67.~t6
449.-4
218.4 --------231.0
42.0
73.4 n.o
199.7 o.o o.o
~1.2
2013
66HZ
f!. 67
842.54
73.02'
249.~
4~.9
11. ~· o.o
T(Jl Al
104~ 2 b o .. oo o.co o.oo
"""" ...... ____ _
"1lfl-()
4ll.4
1t.b.6 o.o
"':0;-~T.t;. __ ..,._ --
l'l'l3.n
tiie!>Oo • .r. o.o
819.7 -------- ----------------------------------------------------------------~, _____ _ llt4.7
l0f:J.2
36.4 o.o
!69.4
lld 0 1
51.3 o.o
18H .. l
128.9
59.3 o.o
186.5
140.1
45 .. 6 o .. o
199.4
153 .. (!
45.9 o.o
219.6
167"6 sz.o o.o
220.6
lf?2.Q
31.1 o.o
240.6
199.7
41 .. 2 o.o
Z17.9
lt4.Q o.o -------------------------------- -------- ----------------------------------------o.o o.o o.o
o.o o .. o o.o
271.4
221.7 o.o
133oa.q ======== =~======
========
l2'i0h.4
684.4
44lef:J o.o
0.1} o.o o.oo
----------------12506 .. 4
aoz.~
4~3.1 o.o
o .. o o.o o.oo
o.o o.o o.o
2Gb.,:J
256.2 o.o
13437.8 ----------------
n.o o.o o .. oo
o.o o.o o.o
323 .. 3
274.9 o.o
13578.5 ----------------
----------------ll'506.4
l 072. 1
518.£
0"0
o.o o.o o.vo
o.o o.o o.o
352.8
291..2 o.o
13732.1 ----------------
12';06.4
12l5 ... 7
64it.O o.o
o .. o o.o o.oo
o.o o.o o.o
385.1
310.9 o.o
13899.7
o.o o.o
O.()
420.3
313.4 n.o
14082 .. 6
o.o o.o o.o
458.7
316.2 o.o
142132.3 ======== ======== ========
12C)06.4
1393.3
696.0 o.o
o .. o o.o o .. oo
12506.4
1576.3
733.7 o.o
o.o o.o o .. oo
12506.4
1775.9
774.0 o.o
o.o o.o o.oo
o .. o o.o n.o
===~===;
12506.'t
l9Q1.EI
tJ19.7 o.o
o.o o.o o.oo
o.o o.o o.o
\l'l06.4
\~Q3.fl
819 .. "! o.o
o.o o.o o.oo
-
Sheet 3 of 3 TABLE D.33!Aim.~
0~4~000000COOOOOOOO'OC~OCOOOOOOOO.OOOOOOOOC00000*00#0*0000¢0~*****'******GOOOOOOOOOOOOOC'OOO*OOOOOOOOOOOOOOOOOOOOOOOOOOCO~*~O~OOOO
DATAlOK WATA~A-DC (ON LINE lq93-Z002l-$3.0 BN(Sl982) STATE FUNDS-I~FLATION 7~-lNTEREST 10%-CAPCOST \5.117 BN 21-F~~-82
OOOOO~OOO#OC.OO'O:O~O'OOO'O(l00COO*OO'I)000000>0tOOO¢*OOOOOOO>Ot00*0000'¢0000:)¢;(l0'1)1)1)0000********•*0<)000*0000000000000000000000000:00~~:~~:C<:).OOO
11 CNtRuY GWH 521 R(AL PRICE-HILLS
466 INFLATION INDEX
S20 PR.lCt-MllLS
-----INCOME---~-------------
'llb ~t=V(UUf.
17~ tCSS OPERATING COSTS
1985
0 o.oo
126 .. 72 o.oo
o.o o.o
0 o .. oo
135.59 o.oo
o.o o.o
1937 1988 1989
CASH FLOW SUMMARY
~==CSMllLIONJ:===
0 0 o.oo o.oo
145.08 155.24· o.oo o.oo
o.o o.o o .. o
Q.O
l) o.oo
166.10 o.oo
o.n o.o
1990
0 o.oo
177.?3 o.CJo
o,o o.o
1991
0 o.oo
190.17 o.oo
o.o o.o
1992
0 O.aOO
203.46 o.oo
o.o o.o
l99'l
--------__ ._. _____ --------------------·---· ... -----------------------------------------
511
ll.
c,.:;'}
391
<;4q
~,4n
44o
l 4 \
~~~~
wPl:RAT I NG 1 NC.C~t ADO INTSREST EARN~O ON ~UNDS
Lf5S INTEREST ON ~HORT TERM OEBT
l~SS lNTfREST ON LONG TERM O~BT
NET EARNINGS fROM OPERS
-----C.A$H SOURtf ANO USC----
CASil lNLOH!:' Fl'OH PPERS
~TATE CONTRIOUTION
lONG Tl P'-' llfflT DRA'.tOOWNS
lo401U, AP IJI 1\ T DR AWOOWNS
TOTAL SOURCES OF FUNDS
121 LrSS CAPITAL EXPENOlTURE
446 LfSS WORCAP AND FUNDS
260 LES5 DEBT REPAYKENTS
141 ~ASH SURPLUSlOEFlClT)
~4q SHORT TERM Of::.BT
444 lASH RlCOVEP.~O
-----OALANCE SHt[T----·-----
ll'J rtCt;f.RV• ANO CONT. fUND 171 )fl-ll:.R io!O:\KING Ci\PlTAL
454 CASH SURPLUS RETAINED
170 LUK. CAPITAL EXPENDITURE
46S CAPITAL EHPLJYEO
461 STATE CONTRIBUTION
~~l ~rTAtN~O EARNINGS
55~ OEDT OUTSTANDING-SHORT T~RH
554 OE6T OUTSlANDING-lONG TERM
~42 ANNUAl O~BT DRAWWOOWN ~1C}82
541 CUM. DEBT DRAWWOOWN Sl98Z
519 DEBT SERVICE COVtR
o.o o.o o.o o.o
o.o
o.o
403.7 o.o n.o
403.7
403.7 o .. o o.o
o.o o.o
l).O
o.o
OeO o.o
403.7 ----------------
403 .. 7 ----------------
403.7 o.o o.o o.o
o.o o.o o.oo
o.o o.o o .. o o.o
1).0
o.o
412 .. 7 o.o o.o
472.'1
472.7 o.o o .. o
o.o o.o o.o
o.o -o.o o.o
876 .. 4 ----------------
-----.-----------
876.4 o.o o.o o.o
o.o o ... o
0.')0
o.o o.o o.o o.o o.o • o.o o.o o.o
o.o
o.o
479.7 o.o
().,()
~1~.1
479. '7 o.o
(\.0
o.o o .. o o.o
o.o o.o o.o
13'>6.1 ----..------------
l 3S6.l ----------------1356.1 o.o o.o o.o
o.o o.o o.oo
o.o
o.o
499.5 o.o o.o --------
499.5 o.o o.o
o.o o.o o.o
o.o c.o o.o
1 wss. 6 ----------------
==-~=====
1855.6 o .. o o.o o.o
o.o o.o o.oo
o.o o.o o .. o o.o
o.o
o.o
936.3 o.o o.n
938 .. 3
930.3 o.o o.o
o.o . o.o o.o
o.o o.o o.o
2 794 .• 0 ----------------
=~=.:::::
2794.0 o.o o.o o.o
o.o o.o o.oo
o.o o.o o.o o.o
o.o
1~50.4
155().4 o .. o o.o
o.o o.o o.o
s:::::===
lt31t4.3 o.o o.o o.o
o.o o.o o.oo
o.o o.o o.o o.o
o.o
o.o
46~.4
78~.7 n.o
121t7.1
1247.1 o .. o o.o
o.o o.o o.o
o.o o.o o.o
5S9l~4
:..:.:::::::·:
===-==-::;==
o\806.7 o.o o.o
784.7
o\12-6
412.. b o.oo
Sheet 1 of 3 E-1-LLJON (1982 oo~CLA-Rs')-STATE APP-RO.;R~l~TION SCENARIO
7% INFLATION AND 10% INTEREST
-... ~R ---~ ~ ..... __ _
o.o o.o o.o o.o
o.o
o.o o.o
7'54.9 o.o
754.C} o.o o.o
~t:H .1
333.\
96.0: o.o. -------..... o.o o.o o .. o
o.o o.o o .. o
631t6.3
========
ltS06o7 o.o o.o
1539.5
311.0,
783.6 o.oo
o.o
OoO o .. o
56.S
Ad .. ') o.o
6679.4
'SI::s::::::~::;
6777 •. 4:
4806.7
'30.~
96.0
l831tel
ll'i.l
'HIJ.9: t.zs
241.q
5a6
Q.R
un.~
-'------~
c;,..} o .. o
]11 .. 6
11.1
~-------283.7
l"lQ.l
11.1
6·8 ....~_.._. ___ _
o ... o o.o o.o
6t.r,
5-"-l o.o
6938.,()
-::::::::':'.\C%1<:
1054.3
1!t:~':'ll:!r':S;=
\806 .. 7
<)2.R
115.7 cOJ9.o
90·8
1009.7
~. 25
TABLE
r·---,
~54lA~li
----
73 £NE"GY GWH
~21 RrAl PRlCE-HlLlS
4ob lH~LATlON INDEX
·.>lO Pit ICE-MILLS
-
-----INCOM£-----------------
5lb !{€VENUE
l7o LLSS OPERATING COSTS
~11 OPfRATihG INCOME
-
?1~ ~DO INTEREST CARNED ON FUND$
~S~ LESS lNTERESr ON ·sHORT iERM DCBT
)~l LESS INTrRfST ON LONG TERM DEBT
S48 NET eARNINGS FR0M OPERS
-----CASH SOURCE A:-.0 USE----
S43 CASH INCOMF FROM UPCRS
446 STATE CONTRIBUTION
143 LONG T(RM DEBT ORAWDOWNS
?~J WORLAP DEBT DRAWDOWNS
~4~ TOTAL SOURC~S OF FUNDS
120 LrSS CAPITAL fXPENOlTURE
44~ LESS WORCAP AND FUNDS
2bU LfSS DEBT REPAYMENTS
141 CASH SURPLUSfOEFICITt
249 SHORT TERH DEBT
4lt4 CASH RECOVERCO
-----BALANCf SHffT----------
71~ KlSL~Vr AND CONT. fUND
J71 OTH[R WORKING CAPITAL
454 CASH SURPLUS Rf:TAINED
170 CU~& CAPITAL EXPENDITURE
4b5 CAPITAL EHPLQYED
461 STAT€ CONTRISUTION
4bZ RFTAINEO ~ARNINCS
5~~ JEBT OUTSTANOlNG-SHORT TERM
5'>-'t UEBT OUTSTANOING~LONG TeRM
542 A~NUAL 0€8T DRAW~OOWN '1982
~~3 CUM. OCST DRAWWDOWN Sl982
~19 OEUT StRVltE COVER
-
199!>~
27S.2
32.0
- ----
1996
3301
3v.Bl
266 .. 73
~2 .. 18
278.3
35.0
243.4
b.1
12.4
182.0
~ 1997 1998 1999
CASH FLOW SU~HARY
===f$~1LL10N):===
3387 33a7 3387
29.37 27.83 26.39
285.40 305.36 326.75
83.81 84c97 86.2~
283.8
38.1
21t6 .. 2
R.O
16.1t
1'30.3
246 .. 6
8.7
17.7
179.3
-
2000
--
2001
3387
23.79
371t.l0
89.00
301.4
54.1 ------·---247.3
10.4
20.0
l71o0
-
2002
152?3 so. '55
400.29
234.36
1132.9
ll.lt
21.9
863.-t
-
2003
______ ...._~
·'>60'5
50.<\9
4'58.29
231 .. 'H
1.?9b.7
l08.'i
"'!;!~..'too..------·
l.PHi.l
10-e~
16.3
891 .. ~ ------------------------------------------------------------------------~-------ss.o
ss.o
O~~cO
368.9
3.1
55 .. 7 56.6
56.6 o.o
395.,4
11.2
57.5
57.5 o.o
11b3.0
12.2
58.1t o.o
1432.3
lOeb
59.5 o.o
1604.7
10.4
60.7
6':>.7 o.o
l-'f73. 5
12.3
239.0
239.0 o.o
137.8
128 .o
277 .. ?. o.o o ... o
2~.1 ' -------------------------------------------------------------------------·------Sl2.8 463.1
44lc9
11.2
9o0
1232.7
1210.5
12.2
9 .. 9
l50l.J
1 4 1 q. 8
10.6
10.9
lb74.7
l6")~t.5
10 .. -'t
lZe~~O
1546.,5
1527.9
12.)
1'3. 2
SO~t.8
362.3
128 ... 0
1<\.S.
301.9'
--------~-----------------------------------~----~------~---------------~-------o.o o.o o.o
o .. o o.o o.o
o.o o.o o.o
o.o o.o o.o
o.o o.o o.o
-2.3
lo3 o.o
-6.8
6.8 o.o
o.o o.,o o.o
135.4 o.o
135.~
-
67.2
'56.6 o.o
7'3 55 .o
73,4
79.7
OoO
7930.3
,) (). 1
f54.2 o.o
8273.2
J7.4
119.1 o.o
9483.7
9S. 4
91.7 o.o
10963.'5
10/r.,l
93 .. 4 o.o
12618.0
113.7
96.2 o.o
14[~-;.q
191..3
llt6 •• ~ o .. o
'141\508.2
208.8
153.6 o.o
14599.1
227.8
177 .........
=:====== 7478 .. 8 .
========
4806~7
147 .. 8
123.9
240D.S
t4B.u
1157.7
la25
----------------7983.4 ---..... -------------oft806.7
203.5
1~3.1
2820.0
lo0.4
1318.0
1.25
----------------8437.5 ======== 480 6. 7
260.1
1b4o3
3206.4
138.5
14'>6.6
1.25
----------------
----------------460b.7
317.5
t7o.b
4359 ...
380 .. 8
1837.4
1. Z5
----------------
11150.6
:::::<:.:::::::
4806.7
3 76.0
187.1
5780.8
438.3
2275.7
1.25
::::":;:::::::
12615.6 ::·==-=:==
lt806~7
435.S
l.99o8
7373.5
459.0
2731t.7
1.25
:-:======
14355.8
:::c::-::z:
,. 806.7
496.2
21().0
8833 •. 8
393.Q
3128.6
1.25
~~--------------..,
:::~::"a:
14846.1
::Xlii<:Zll::C:
lt806.7
735.2
3,.b.9
6957.1
34 ...
3163.0
1 .. 25
1 .. 961.7
::,z::::::::::::
lt606.7
877.8
362.6
891,..6
o.o
3163.0
le25
o.o 1~6(}8.3
·'*~·==·=='== P5103. 7
'W;iii;;,t;,:;;:'::;::::::
~806 .. 7
to21.n
-\0~.4
8867.7
o.o
316)..,0
lei?
$3 BILLION (1982 DOLLARS) STATE APPROPRIATION SCENARIO
7% INFLATION AND 10% INTEREST
Sheet?. of 3 . TABLE 0.34 lA~~fil
-- - -------- -- -----
"*~*(t~~~~**l)~****************::r***********************~*************"*t;**::r**********:l)*******lo'**(l***********************"l.:Q'~tt<**~***** OATAlOK WATANA-UC !ON liNE 1993-2002)-52.3 BN CS198l) STATE FUNOS-INFlATION 7:t-INTEREST 'iO't-CAP COST S5.117 SN 23-iftS-82 ¢l;tl)0li.lttll.l*******lOI*****lCl*lCl21l(l::rlll~**lCl***OICJ(Il).***tc***********O*ICJ*****'(nQnero::r:¢t.*******~*~********J);*****.II)****-***ICI***********lQI*****-* ... le<:o•****
1985 1986 1987 1988 1969 1990 1991 1992 1993 l 9 14t
CASH FlOW SUMMARY
ENERGY ~==(SHilllONl====
73 GWH 0 0 0 0 0 0 0 0 3387' 3387 ')?l KEAL PRlCE-MtlLS o.oo o.oo o.oo o.oo o.oo o .. oo OeOO o.oo 50 ... 65 58.76
46b 1 NFU\T I ON INDEX 126.72 135.59 145.08 155.24 l66el0 177 .. 73 190.17 203.48 217.73 .232.q7 520 PRICE-tHLLS o.oo o.oo o.oo o.oo o.oo o.oo o.oo o.oo 110. 73' 136.90
-----INCOME-----------------Sib R EVENUC o.o o .. o o.o o.o o.o o.o o.o o.o 375.0' <\63.6 170 LLSS OPERATING C•1STS o.o o.o o .. o. o.o o.o o .. o o.o o.o 26..,9' 29e3 -------·-~--.-------------------------------------------_____ ... ___ --------....
__ ..,......, ____ ........... .., _____
!117 OPERATING I NCOHE o.o o.o o.o o.o o.o o.o o.o o .. o 3,.6.1 43~.3 ~l-4 ADO INTEREST EARNED ON FUNDS o"'o o.o o.o o.o o.o o.o 080 o.o o .. o '5.6 '>50 LESS TNIEREST ON SHORT TERM DEBT o.o o.o o.o o.o o.o o.o o.o o.o o.o 9 .. 8 3<H LF.SS INTEREST ON lONG TERM DEBT o.o o.o o.o o.o o.o o.o o.o o.o 303.1 331.'9 --------____ _.,. ___
----~---.----------._. _______ ---------------........ _ ------.-.-__ .... ____ ~
~"-' ......... ____
548 i.JST EARNINGS fRuH OPERS o.o o .. o o.o o.o o.o o.o o.o o.o lt5.0' 98.3
-----CASH SO\JRCE AND USE----
548 CJ.\SH INCOME FROH OPERS o.o o.o o .. o o.o o.o o.o o.o o.o 4S.o 98.3 44b STATE CONTRIBUTION 't03.7 472 •. 7 479.7 499 .. '5 938.3 738.4 o.o o.o o.o· o.o 143 LONG TER."\ DEBT DRAW DOWNS o.o o.o o.o o.o o.o 612.0 1328.3 890 ... 288.1: 17 3. 2 Z4r8 WOR.CAP DEBT DRAWDOWNS o.o o.o o.o OoO o.o o.o o.o o.o ~a.o 17 .. 7 ---------·-------------------------------------------------------------...a;-.... ~~-~---
549 TOTAL SOURCES Of FUNDS 4.03. 7 472.7 479.7 lt99.'5 938.3 1550elt 132fJ.3 890.4 ~31.1 289.2
120 LESS CAPITAl EXPENDITURE 403.7 lt72.7 479.7 499.5 938.3 1550.4 132R.3 890.4 333. l. zs~.z
't4H LESS WORCAP AND FUN OS D.O o.o o.o o .. o OoO o.o o.o o.o 98 .. 0 17.7 260 LESS DEBT REPAYMENTS o .. o o.o o.o o.o o.o o.o o.o o.o o.o 12.2 __ .., _____ __,.. _____ ---------------------------------__ ... ______ ---------_. ________ ....,......._ ______
l4l CASH SURPLUSlDEFICITJ o.o o.o o.o OeO o.o o.o o.o o.o o.o o.o
249 SHORT TERM DEBT o.o o.o o.o o.o o.o o.o o.o o.o o.o o.o 444 CASH RECOVERED OaO o.o o.o o.o o.o o.o o.o o.o o.o o.o
-----BALANCE SHCET----------
2 25 RfSERVf: AND CONT. FUND o.o o.o o.o o.o o.o o.o o.o o.o 56.5 6l.b 311 JTHtR WORKING CAPITAl o.o o.o o.o o.o o.o o.o o.o o.o <tl.5. 54.1
4'>4 CASH SURPlUS RETAlNED o.o o.o o.o o.o o.o o.o o.o o.o o.o . o.o 370 cu~. CAPITAL EXPENOI TURE 403 .. 7 876.4 1356.1 1855.6 2794.0 4344.3 567l.6 6563.0 6896.1 7155.3 ======== =~='===== =::t====== --------===-===== ======== =~-=-'~==-::= ===:::::z:z. :l'liS::IIZ:IO:II%; 'lllr'lll:z:':::;:z --------465 CAPt TAL EMPLOYED 403.7 676.4 l356ol tsss.o 1794.0 431t4o3 5672.6 6563.0 6')94ol 1211 .. 0 =====-=== ====-=-=== ========-:.::====== ===-====-= ====:::::: ========= S:Z:'llt:Z:Z::z ::z·::z::tz,.ll :lli!~~~""=%=
ltbl S TA.TE CONTRIBUTION lt03.7 876.4 1356.1 1855.6 2794.0 3532.4 3532.4 3532.4 3532.~ 353Z .. .r.
ltb l RETAIN£-0 EAR 'If I NGS o.o o.o o.o o.o o.o o.o o.o o.o 45.0 143.3
5 5'l OF.:BT OUTSTANDING-SHORT TERM o.o t.o o.o o.D o.o o·.o o.o o.o qa.o 115.7 ~54 ot: nT OUTSTAN!HNG-LDNG TERM o.o o.o o.o o.o o.o BllaO 2140.2 3030.7 3316.7 . )479.6
~42 A~NUAL DeBT URAWWOOWN $1982 o.o o .. o o .. o o.o o.o 456e8 698elt 437.6 132.3 74.3 5"~3 cu~. DEBT DRAWWDOWN $1982 o.o o.o o.o o.o 0 ... 456.8 1155.3 1592e9 172.5.2 1799.5 .u
5).9 DE.8T SERVICE COVER o.oo o.oo o.oo o.oo o.oo o.oo o.oo o.oo leiS 1. Z5
$2.3 BILLION (1982 DOLLARS) MINIMUM STATE APPROPRIATION SCENARIO ~P,[Q II
~Sh_ee_t_1_o_f_3 ______ _:-~ ..... -----~--------_-_-_::_-_-...... -... -7 __ %_o:_I:._N:_F:.,L:._A:_T:_I-0---N-:_A-·_·_N ___ o~-1-=0o/cr~~-!_.~_~::-E_~_~_~_~;::· ::::::::::::::.::.::::::_::-_:-_-_-_ ...... _......J _____ T_A_B_.L_..E_D_~.:. ~hfl d .
-
1
I
- - -
71 tNERGY G\.4H
521 QfAL ?RICe-MILLS
4bo lkflATlON lNOEX
S20 PR.lCt-KillS
-
-----lNCOHE-----------------'3lb RfV[NUf
170 LtSS OPERATING COSTS
'17 0PfRAflNG lNCOM(
-
21~ AUO JNTfR(Sf l~RNLD GN FU~u$
~~~ LESS lNTtREST UN SHO~T TtRH DEBT
391 L~SS INTEREST ON LONG TERM OEBT
S4J Ntl EARNiNGS FRJM ~PERS
-----LASH SOURCE AND USE----CASH lNCDHE FRJH OPERS 5-<d
41ob
l'd
l48
~lO
448
lbO
141
24)
44.r.
22S
371
4~i4
370
465
4bl
.lt62
S?S .,., ..
STAT2 CONTRIJUTlON
L~NG TCRM OE9T O~AWOOWNS
WORCAP OEGT OkAWDOWNS
TOTAL SOURCES OF FUNnS
LfSS CAPITAL CXPF.NOlTURC
L~SS WORCAP AND FUNDS LESS DEBT R~PAYHENTS
CASH SURPLUS(OEfiC.JT)
SHORT TeRM DEBT
CASH RfCOVEREO
-----BALANCE SHEEl----------
~~SLRVf AND CONT. FUND OTHCR WORKING CAPITAL
CASH SURPLUS RFTAINtD
CUM. CAPITAL EXPENDITURE
CAPITAL EMPLOYED
STATE CONTRIBUTlO~
~ETAlNcO EARNINGS
OE8T OUTSTANDING-SHORT TERH
OfRT OUTSTANDING-LONG 12RM
~42 A~NUAL Dt.BI DRAwwCOWN ~lqSz
~43 CUH. OEUT DRAWWOOWN Sl93Z
~lQ OEST Sf~VltE COV(R
-
2005
l44b. "5
118.4 ---------1327.6
"22.8
40.5 qsz. 8
327.3
327.3 o.o o.o
36.~
363.7
108.2
)6.4 o5.Z
153.8 o.o
153.8
?43 .. 7
l'·Be2
OoO
14891 .. 3 ----------------15) 33.1 ----------------3532.4
1595.9
441.8
976"3.0
o.o
3827.2
1.25
------·----
2006
bt47
~5.23
524.69
237.3 l
l32.'l.lt z,..9
44.,. 2
976.3
333.0
333.8 o.o o.o
'51 •. 3
385.0
l1 B.l
->t.J
71.8
143.9 o.o
143.9
171.4
221.7 o.o
15009.4 ======== 15502.5 --------------..--3532.4
1785 .. 8
493 .. 1
9691.2
o~o
3821.2
lo25
2001 20oa 2009
CASH FLOW SU~MARY
==~(SMlLL10N)====
~l50 6472 6544
41.99 38.32 35.80
561.42 600.72' 642.77
235.75 230.18 230 .. 09
l't73.3
141.0 _______ ,.. __
l332.3
2 7 .t
49.3
969.1
341.0
400.Z
12 a.q
59.'3
79.9
133.1 o.o
133 .. 1
296.2
25t>o2 o.o
15138.3
===::::====
l5b90o7
=~======
3532.4
1993.7
552.4
9611 .. 3
o.o
3827.2
1.25
13\').7
~·1. f.;
5!l .. 2
961.2 _______ ....,.
.346.9 o.o o.o
4'>.8
394.,. 7
140 .. 7
4'i.O
86.8
121.3 o.o
121.3
323.3
2·14.9 o.o
t527q.o
=======:
15 877.2 ----------------
o.o
3827.2
lol5
1'317.6
32.3
59.3
952.') --------357.5
357 .. 5 o.o o.o
45.9
403.4
153.6
lt'l.'i
95.5
100.4 o.o
103.4
352.8
291.2 o.o
15432.6 ======== 16076.6
3532.4
2470.3
644.0
9429.9
o.o
3827.2.
}.25
2010
6616
33.46
687.77
230.15
1522.6
163.4 --------l3Jq.?
35.3
64.4
943.0 _ ,_ ______ _
367.1
367.1 o.o o.o -,z.o
419 .. 0
167.6 s.?.o
l05ol
385.1
310.9 o.o
15600.2 ==-====== 16296.2.
===':-=:.::::=
o.o
3a27.z
1.25
2011
6638
31.5'5
735.91
232.21
l'i4l.3
lOO.l
---------377.6
'377.6 o.o o.o
37.7
415.3
162.9 \7.,7
115.6
79.1 o.o
79.1
420.3
313.<\ o.o
1578.3.2
::::=::::::::c
16516.8
s::·~-s===
3532..4
3041.5
733.7
920C}.2
o.o
'3827.?
t ... zs
2012
6660
29.75
787.42
234.23
1559.8
216.4\
389.2 o.o o.o
41.2
it30o)
199.1
41.2
127.1
62.4 o.o
62.4
ltSA.-7
316.2 o.o
15982.8
:::z:s:s::sz:~:
167'51'.6 ======-== 3532.4
3368.3
771te8
9082..1
o.o
3827.2
1.25
,----· -. -··
$2.3 BILLION (1982 DOLLARS).MINIMUM STATE APPROPRIATION SCENARIO
11:,
Sheet 3 of 3
' 7% INFLATION AND 10% INTEREST
--------~,·-···-·---r··-·---'---"""""""'--------..J
-
2013
6682.
28.07
642.54
Z36e"t9
1580 ... 1
238.4 ---------1341.7'
.AtS.9
77.5
908.l
446.8
217 .. 9
44.()
139.q
44.1 o.o
lt4 .. l
500.6.
319.2 o.o
16200.7
::-:cs::::.:.:;;
17020.S
3532.<\
3726.1
8t9.1
8<J42e1
o.o
3827.2
1.25.
-
lOTAL
104820: o..oo o.oo o.oo
~l.<J2'1.6
·2.?02.0 ~Jorlio..._ ____ _
\<J11l.t.
4ll."t
1>\6..6 l>~t~26 .. 0 ll:l:;i..."C. _____ _
ii,<Jb~.~t
1"i}l.o\
\UlOT.S
H l q. 7 ..._.~,._Jio., ___ _
~~42'5.3
\6200.7
OP~.7
l\6'> .. ~
....,....~-------
S00.6
'H9.2 o.o
16200.7
•~x:::::&.,.:s::
17020.~
'lllli::.!!'Ji:::::::x
3~32.~
37'26 .. 1
8l<J,7
89~2.2
3827.2
'3827.2 o.ob
-
TABLE 0.351 A~Uf~.l
w ~...,.a·~·-........ ---------------------~~----------............ ~....._,.,., __ . ____________ .-........,_ ........ ~ .............. --···· •1M~"
~'(,:)¢;.>t>::¢*~?:,ttt******~**C;****"t****~****=***Cn::*i'l~:***************=et*>::"*¢****'~:;:¢:)¢l,):!r*:OC*~*:0Cl:CI):**~l):)~~*'*tltl):l):;(t0*******-0*******~****~~2/I:-.I):-.I):I):I):O D~TA1JK hATANA-JC tON LINE 1Q9]-Z002)-SZ~3 CN (11962) STATE FUNDS-INFLATION 7t-INTEREST lOt-CAP COST ~5.117 6N 23-f~B-~2
****************************-*ICI*******:::tl)l)l)::::t****~******~***::r*****************************li)~:)*~*********OI):l(ll****~<~~t******~~~l):l):****
1995 1996 1997 1998 l9q9 2000 20tH
CASH FLOW SUMMARY ===«•MlllJON)====
7) fNERGY GTIH 33d7 33117 3387 33!H 33B7 .3387 3387
":ll 1t CAl P.:t. I C E-M I L l S 55.38 51.11 4-9.27 4-0.:..3 43.78 41.29 38.96
4bb INFLAliO~ INDEX 249 .. 26 ?bbe73 2!-J5.4(' )Q'j.36 32be75 349.6l 374.10
~lu PRICE-HillS l3Be06 13"1.00 i40eo3 l4lo79 143.06 l44.3fl 145.75
-----INCOME---~-------------
'J lb ~~VlNU( 467.6 470.8 476.) 480.2 484.5 488.9 493.6
1 7l) LESS OPERAT !..-cG COSTS 32.0 35.0 38ol 41.6 45.4 49.6 54.1 ---.-------------------------·-----------------.:..----------'il7 JPcRAT l~(; INC.OM«:. 435.6 1t3S.8 43~.1 lt3tlo 6 f.t)Q .• l 439.3 439.'5
7.l4 1\DCJ INTERfST EJ\Rt~ED ON FlJNDS 6.2 6.7 7.3 a.o 6.7 9.5 lO • .ft
5~0 leSS INTEREST ON SHORT TE.RM OEUT llob 12.4 15.3 16.4 17.7 18.1 19.8
Jl:ll LESS INTEREST ON LONG TERM DEBT 330.6 3Z9o3 327.8 326 .. 2 324.4 3Z2e4 320 .. 3 ------·---------··-__ ., ______
-----~--
__ .....,.. _____ --------·---------,4t! NE.T EARNINGS FROM OPERS 99.5 100.8 102s3 lOlteO 105.13 107.7 109.9
-----CASH SOUR Cr.: ANo_usc----
'J41 t J\~H 1 Nt•JME FROM OPERS 9~.s 100.8 102 .. 3 104 .o 105 •. 8 107.1 109.9
~4{· STATf C.ONTR lHUTl ON o.o OeO o.o o.o o.o . o.o o.o
143 tONG TlRM DEBT ~R AWDOWNS 326.5 3'l1 .. 2 34 ..... 2 ll 06 ·<• l'\70 .. 3 1530.0 l40Ji.6
24:! ;.tORC.AP DEBT ORAWOOWNS 8.1 .Z9.3 11.2 12.2 lOeb lOelt 1Zo3 ----------------------.... -_____ ...,__~ ------·-----------·-------">4~ TOTAL SOURCES OF FUNDS .:t34.2 511.3 457.7 lZZleU 1486.6 1651'.0 1527.6
320 LESS CAPITAL fXPENOt TURt 41"Z..6 4&7.;'. 430eZ 11 <)2. 7 1456.3 1624.6 1.491.6
4-48 LESS WORCAP AND FUNDS Sol 29.3 11.1 lz.z 10.6 10.4 12.3
lbu lESS DE'aT REPAYMeNTS 13.5 14.8 16.3 17.(} 19.7 Zle7 23.9 ----------------------·--_____ .,.. __ ..,._.,..... _____
---~--------·-----141 CASH SURPLUS< DEFICIT) o.o o.o 1).0 o.o o.o o.o o.o
l~~ SHORT TERH DEBT o.o OeO o.o o.o o.o o.o o.o
lt44 CASH RECOVERED o.o o.o o.o o.o o.o o.o o.o
-•---BALA'NCE SHEET----------
22'1 tttSERV~ 1\ND CONT. FUND 67.2 73.4 oo.1 87.4 95o4 104.1 113.7
371 .JTtiER WORKING CAPITAL 5o .. 6 79.7 34.2 99.1 91.7 93.4 96.2
45.10, CASH SURPLUS ReTAINED OoO OoO o.o o.o o.o o.o o.o :no CUM. CAPITAL EXPENDITURE 7567.9 8035.1 8465.3 <}657.9 11114 .. 2. 12739.1 14Z30. 7
.=-::::::::::: =====:::== --------======== ===-===z-= -::::::::!::'1::.!11':: =====-===---------461j CAPlTAL EMPLOYED 7691.7 3188.2 H629.b 96 34.5 11301.4 129)6.6 14 .. 40.5
=======:: ====:'='== -------·-::-::::-::.:::: =====-=== ===-=:.::!~"; ======== --------
46.1 ;jTATt: CONTR l!HJT tON 3532.4 3532.4 3532.4 3532.lt 3532.4 3512.4 3532.1t
41>2 R t:TA HIED EARNINGS 242.8 ;\1+3.7 446.0 550.0 655 .. 7 763 .. 4 873.3
555 DEBT OUTSTANDI~G-SHORT TERH 123o9 153.1 lblt.3 17.6 .. 6 lB7.l ).<}7.6 :Z09.9
5.,4 OEBT OUTST~NDlNG-LONG TERK 3792.7 4159.0 4·4~6.9 5 575.6 6926.2 841t3.3 fl825.0
'>4Z ANNUAL DEBT DRAWWDOWN U982 131.() 1 1•2.9 120.6 36le4 419.4 -440.1 375.7
543 CUM. DEBT DRAWWllOWN 11962 1930.5 2073.4 2194.0 2556.3 2975.7 3415.6 3791.5
51.} i>t: ~ T SERVIC.E COVCR le25 le25 lo25 1.25 1.25 le25 leZS
Sheet 2 of 3
I $2.3 BILLION (1982 DOLLARS) MI~I~UM STATE APPROPRIATION SCENARIO
7% INFLATION AND 10% INTEREST
zooz 2003 200-\
5223 54l4'. '):605
63.57 59.qq 55 ... 83 400.29 428.31 ·lOtSB. 2Q
254 .. 47 256. 5-8' 255.86
l3Z9.0 1369.0 lit14.,Q
9lel 99.4; 108.5 ,.. _______ ---------.._,.._ ______
12::37.9 l269 .. ll-132S .. 'i
11.~ l q_ t 2'0 •. 9
l1o0 3 :l. 6' "'\6~3
982.5 99~~1 988.6 --------·---·-~-..... ~-------2~5.8 ZSO .. tl' 321.3
245.8 280.& 3£1,.3 o.o o ... o o.o
14? ... 8 O.t) o.o tza.o 24.1' -42.8 ---------------"""""' ~"'~------516.5 305.5 364.2
362o3 90.~ 99.1 126.0 24 .. 1' ~2.6 lbel 53.~ 59.3 _,.. ______
------~.~
~ .. _______
o.o 136.0' 162.6 o.o o.o· o.o o.o 1J6.Q 162.8
191.3 206 • .8' ZZ7 .. 8 l46e6 153.& 177.6 o .. o o.o o.o
llt593.0 14683 .. 8 t'\-711'3.0
:.::::3:-S%·:: :az:=====· '1!:-::::::;=:~""=-:::::
14930 .. 8 15046.4-111)186.4
:.:==~:::= ======::~ :jt•et"" =-= = =::::::
353Ze4 3532.,. 3"l32 _,.
lll9el l263.q 1-\ZZ • .~to 337.8 362.6 4t05.Jt 991tl.5 9887~6, qazs .. z
35.'7 o.o o.o
3827.2 3827,.2 3627. z
lel.Z 1·2< leZ5
TABLE o.35ll~~I~J
t
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I
TABLE 0.36: FINANCING REQUIREMENTS -$ aiLLION
For $3.0 billion State Aepropriation Scenario
1985 State Appropriation
86 "
87 11
88 n
89 "
90 n
91 tl
Total State Appropriation
1990 Guaranteed or G.O Bonds
1 " " 2 " If
3 II n
Total Watana Bonds
Interest Rate 10%
inflation Rate 7%
1982
Actual Purchasing
Power
--.,S~b i 1 1 ion
0.4 0.3
Oe5 0.4
0.5 0.3
0.5 0.3
0.9 0.6
o. 5 0.9
1. 5 0.2
4.8 3.0
0.8 0.4 o. 7 0.4
0.3 0.1
1. 8 0.9
---------------------------------~-r---~---------~~--~--
1994 Revenue Bonds 0.2 0.1
5 " 11 0.4 0.1
6 " n 0.4 o. 2
7 !f ·n 0.4 0.1
8 " II 1 .. 2 0.4
9 n n 1. 4 0.4
2000 n u t. 6 0.5
1 n 11 1. 5 0.4
2 n n 0.1 0.1
Total Devi I Canyon Bonds 7.2 2o.3
Total Susttna Bonds 3.2
"
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I
I.
I
I
I
I
I
I
I
I
I
I
I
I
I
TABLE 0.37: FINANCING REQUlREt~ENTS -$ BILLION
For $2.3 bi II ion State Appropriation Scenario
' l985State Appropriation
86 n
87 II
88 n
89 "
90 n
Total State Appropriation
Interest Rate 10%
Inflation Rate 7%
1982
Actual Purchasing
Power
---.,.S--.b i I 1 ion
0.4 0.3
0.5 0.4
0.5 0.3
0.5 0.3
0.9 0.6 o. 7 0.4
3.5 2.3 ---------------.--------------------------------------......_-
1990 &.!aranteed or G.O Bonds 0.8 0.5
1 11 It 1.3 0..7
2 It tl 0.9 0.4
3 n u 0..3 0.1
Total Watana Bonds 3.3 13 7
-----------------------~----------~~--------------------
1994 Revenue Bonds 0.2 o. 1
5 n " 0.3 0.1
6 n " 0.4 0.2
7 -fl " 0.3 0..1
8 n u 1. 1 o. 4
9 n II 1.4 0.4
2000 n II 1 .. 5 0.4
1 It " 1 .. 4 0.4
2 tt II o. 2
Total Devil Canyon Bonds s.s 2.1
--------------------------------------------------------
Total ~: 1sitna Bonds 10. 1 3.8
..
')
BASIC PARAMETERS OF RISK GENERATION MODEL
--,
COAL PRICE ESCALATION(% REAL)
.
2.6 to 2000 5.0 to 2000 .
0
1.2 thereafter 2.2 thereafter
PROBABILITY .25 .50 .25
INTEREST RATES%
.
5-7 7-9 9-11 I 11 -13
I . I
I PROBABILITY .10 .32 .43 .15
INFLATION RATE
DIFFERENCE FROM INTEREST RATE
. ! -2% -3% -4% I
PROBABILITY .33 .3~ .33
'
CAPITAL COSTS (REAL 1982 $billion)
Below 3.1 Below 3.6 Below 4.3 Below 5.1
PROBABILiTY .46 .73 .90 1.00
TABLE
-------------------
4000
3000 -..
II:
<l _, _,
0
0 ... noo 0 .,
.z
2
..I _,
i -lOGO
~
..I ...
X .,
"' u
"" 1500 > ;:
"" _,
:;)
:It
:;) u
1000
100
'
f
fl1
IllS
CUIIut..lfTIVE CAit .. ~~
~
. I~
. .
liB.
-
•• I
••
YEARS
WATANA DEVELOPMENT
CWMULATIVE AND ANNUAl CASH FLOW
~ANUARY, 1182 DOLLARS
.11!1
-
CJI:)
""' c
~ ....
·'-'
~ 0 c ... a
"" :
~·
.:i ,_,
~ ~ -
~ ....
:c:
1Jii
~
~ ..I
~
:I: z
"'
~·
0
IH4 lftt
FtGURE. D. t
- -- ----
!000 --ft
II:
oC _, _,
0 a
Sl. I BOO
0 .,
z
0 :; _,
~
1000
~
..I a..
% .,
<C u
100
loJ >
fi
..J
(!
~
:I :;:, u
0
ltll 1111
------ -
~
l!UIM -~ il" F\.0\l•[•,i,
v
.
~
lit& .... iVtf .... ,.., l(tO~ eoo1 1001 · IOOJ
TIAJitl
DEVIl CANYON DEVELOPMENT
CUMULATIVE AND ANNUAl CASH fLOW
.JANUARY-. 1982 DOU.ARS
----
400
-• • c _, _,
900 0 a ..
0 .,
2 _,
1.00 _,
2
• 0 _, ...
::::
100 • ~ _,
c
:!) z z c
0
FIGURE p,·2
... ------------
•e.oo
&000 .
•
51500. .
" ~~ &000 v~
/ 4590 -/' ... a:
"' .... • £ ..1 4000 0 ~I'( . 0 I
~ I . ....... ~ ~ .PI _ .. &'W'! ~~ CAl 14 fWWI
In 1800 .
z .,..
0 :; .... a .... 1000
3t s
"' :::: uoo en c u
1!1 =: 100\» ·~e ....
!:)
! u
1500
0
IMl IHS IN4 IHI 1981 M7 11ft I'Nt 1590 1111 1111 lttl 1114 IIWI 1101 lilT ltli lltl 1000 1004 100& lOOS
Yl&\ffl
S~TNA HYDROELECTRIC PROJECT
CUMUL.ATJVE a ANNUAl. CASH FLOW ENTIRE PROJECT
JANUARY , 1982 DOLLARS
-
@50
too
8!0
500 -~ a::::
4BO '<11\t .w
~
40Q ~
~ ~
110 "<i!
=I! ~ -1l'i
~ !00 ~
~
250 ~
-!)
§
!DO
~ ~
150
100
so
0
FlGUAE 0.3
RAfLBELT REGION
GENERATING AND TRANSMISSION FACILITIES
Ot-::==A!E!It===3t30 K1LOMETEAS L 1
I
I
I
I
I
I
I
·I
I
I
I
I
I
I
I
I
I
I
LOCATION MAP
LEGEN(j
\1 PROPOSED
OAM SITES
----PROAJSED 1!15 KV UN£ .
---EXISTlNG LINES
FIGURE o. 5 -SERVICE AREAS OF RAj LBEL T UTIUTIES t ~iRl
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
Oil
2%
Rural E!ectric ~iva
7~
-----------------
Municipal Systems
23%
Administration -Eklutna
1. Does Not Include Seif Supplied Energy from
Milftagy Installations and The Univarsity of
Ala$b
A ENERGY SUPPLY
(Based on Net Generation 1980)
Gu 76%
1. Does Not Include Genernion by Milit:Qry
lnstaliations and The University of A12sb
C NETGENEflATJON BY TYPES OF FUEL
(Based on Net Generation 1 SSO)
B
Munic:iPal Systems
27%
Univenitt' of
Awu
Afa!XaPoww
Administration -Eklutna
GENERATING FACILITIES
(Based on Ncmsplate Generating C•pacity 1980)
Combined Cycle
Combustion Turbine
(139 MW-1~%)
R•mmrttva
Cycle
Combustion
Turbine
......... ~ (11t ~""-
Simple Cycle
Combustion Turb.ina
(520MW-5~)
18J
0 RELATIVE MIX OF ELECTRICAL GEPJERATING
TECHNOLOGY-RAILBEL T UTILITIES -1989
FIGURE D.$ •
I
I 10,000
I
I 9,000 .
I 8,000
I
I
I
I
I
7.000
6.000
i e i s.ooo
I
IU
.,, ,, .,., ,, ,, .,, ,, _,:, .,, _., ..s--· .,..,. r---.,...-,p.~ .,.# I i 0 .,-r_ ... ___ ,
~~' 0~ ~.,. I f~,--I --· """'"'~---Note: OGP~S Program I~ Usable f31'--~" __ j Output at Two Year lntervak
__ _. ---I• ----------~-----/
I
I
4,000
3 .. 000
Energy Oertveriea
From Susitna
/
~
I
I· 2.000
Watana Atone Watana And Devil Canyon .
I 1,000
I
I I I f ' _j i I I t ' ' f t I
I 1992 1995 2000 2010
I
'FIGURE
~
D. 7 -ENERGY DEMAND AND DELIVERIES FROM SUSJTNA lMtiJ
I
-----------------~-
300
250
200
~ ~ s :a
tl 160 0
(,.)
> ea
Cl) c w '
I WATANA ONLY IN 19941
LEGEND
·---· Energy Cott of Bert Thermal 0~
• • • •• • • • • Ene~ Con of SuDitna Option
Operating Cocts of Thermet Pfent fn u ..
In 1993 Extended ta 19M
Shadad Arta Rtprutnta Pfant Opeming
in 1;g2 Dftplatd tr( W~tana
ArM Under This Line is Annual Colt of Best Thmnal Option
(lneluding Investment Com}
l
I
..:.li'IP...,. ....................................... L . .t ... ::~Under This Llnoll Annual Colt of Susitna Option
f : Area Under This Line is Annual
1 • Operating Cost of Existing Capacity 1993/4 I : (Avoided Costs of Fuel and O&M Only)
I •
1 : Area Represents Annual Open.tln; Com I : from Existing Generating Plant
: Ctimmon to Both Sulitna and
Annual Enlf9Y Output GWh
Thtmnal Options
Medium Growth System Energy
FortCMt for 1994;4,8H GWh
t' FIGURE 0.8 • ENERGY PRICING COMPAR"~:'.')NS -1994
-
------------------
380
340
320
300 -.c
~ 280 ..... en --·-:E 260 -..
Cl)
u .i:
a. 240 "C c
C\'1 = ... 220 c3
> Ot ....
CD 200 c w
180
160
l!l<llft ... v
120
100
0
SYSTEM COSTS AVOIDED BY DEVELOPING SUSITNA
COMPARED WITH BEST THERMAL OPTION IN MILLS PER UNIT
OF SUSITNA OUTPtJT IN CURRENT DOLLARS
~· •* ,
·'! I I
•" COST SAVINGS FROM SUSITNA IN.CREASING
1 OVER WHOlE. liFE OF PROJECT
I •• . ~
II
~· •••• Increasing Thermal Fuel II
Costs Avoided~ -1
--~-----·····' ~···· **-.. -~·-•• '#].
I
I ,.._ Avoids Cost of a Further 200 MW Coal Fired Generming Unit
I
I
I
•••• 411-Avoids Cost of 2 x 200 MW Coal Fired Generating Units
If
Watana on Stream in 1993 Devil Canyon on.Streem in 2002
.~--~--~--~--~--~~~--------~~------~---· ----------------~--~~----~~--~--~----94 6 6 1 8 9 2000 01 02 03 04 05 (5~ 07 08 09 2010 11 12 13
FIGURE D. ~.1 .,.-SYSTEM COSTS AVOIDI;O BY DEVELOPING SUSITNA
~-----------------------------------------------------------------------------------------------~~--------------
--- -- -
--9 ---
f
I
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I
I
' I
I
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I
' I
I
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I
!
i
I
I
I
I
Energy Output Watana ~
I
I
I
I
I
I
I
----- --
j "'.-\TANA& DEVIL CANYON IN 2003 ~
!.EGEHD ·--· ........
-
Olteratll'll Com of Th~ PiMtt ln UM
ln 1983 &tendod to 1~
I
I
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I
I
I
I
I
I
I
••
I
I
I
I
I
I
I
I
lOCATION MAP
LEGENI}
"J PROPOSED
OAM SITES
--.... -PROPOSED 138 KV UN£
--EXISTING LINES
\
20 ~· ~-· -SCALE IN ULEI
).a 11M Bth i
LOCATION MAP FIGURE 0.11 I Mil I
---------~---------
SITE
SELECTION
·PREVIOUS
STUDIES
ENGENEERING
LAYOUTS AND
COST STUDIES
SCnEEN
CRIT~RIA
ECONO~~S
ENVIRC~MENTAL
OBJECTIVE
ECONOMICS
4 ITERATIONS
SNOW ( S}
BRUSKASNA ( 8 )
KEETNA { K)
CACHE (CA.)
BROWNE ( BR)
TALKEETNA • 2 ( T· 2 )
HICKS (H)
CHAKACHAMNA ( C H )
ALLISON CREEK ( AC)
STRANOllNE LAKE ( SL}
• CH, K
DATA ON DIFFERENT r
THERMAL GENERATING j;
SOURCES 1
t
COMPUTER MODELS TO
EVALUATE
.. POWER AND
ENERGY YIELDS
ll SYSTEM WIDE
ECONOMICS
........ ,T .........
"'"' c.ntM
ECONOMICS
• CH, K,S
CH,K,S a THERft\AL
LEGEND
• CH, I<,S,SL.,AC
-CH, K,S 1 SL,AC
.. CH, K,S,Sl.,AC,CA, T-2 ---~ STEP NUMB~R
lN STANDARD
PROCESS
(APPENDIX A)
FORMULATION OF PLANS INCORPORATING NON-SUSITNA HYDRO GENERATION 0.12. FIGURE
152° 15C 0 t48~ 146° l44° 142"
\
·~·
®
I
I
I
I
I
I
I Q•
I
I
I
I
I
I SCALE" MILES
I ltoi EQt!AtS APffiOXlMATEU' 40 MiLES
1\ A 8 0
o-25 MW ~5-IOOIIIW >IOOW
I
I
I
'· STRANOUI£ L. 13. WHlSK£RS• z •• SNOW 39. l..AH(
2. ' l.OWER BEUIGA .... COAL 'ZT. KENAI LO'WEft 40. TOKIOiiTHA
:1. LOWEIIt l.A~ ~ ''· CWUTNA 21. GERSTL£ .... .YEPJTNA
4. ALLISON~ t;. QilO 2:1. iANAHA ft. 42. CATH£Dft.AL !LUFI"'
5. -:RESCENT LAKE 2 17. tJ::\rNER CHUUT'Nl 30 .. BRlJSI(ASNA 43. ..IOHHSC'JH
6. ·GRANT LAKE ••• tACH! 31. !<ANT~ it. ·44· eiiJwiE
'1. McCWRt ~AY 11. GRE£NST'(j£ 32.. UPPER BELUGA 45 • • JUNCTION 1!1.
e. OPPER NEt.UE JUAN 20. TAIJ(££TNA Z 33 .. COfFEE 4&. VACHON IS.
•• POWER. CREEX II. GAAtm'£ CJORO! 34. GOIJ(AHA R. 47. TAZILMA
10. SILVER LAIC£ zz. KE£ml 35. KWTIIA 41. KENAI l...AAE
H. SOLOMOM GULCH z:s. Sl-tEEP atEEX 36. 6JtAtll..EY t.AK£ ""'· CHAI(;.CH~
tz. TUSTWEtiA 24. SK'N£fiTNA 37. liiCII(S SITE
%5. TA1.ACHOUTNA :sa. LOW£
SELECTED ALTERNATIVE HYDROELECTRIC SITES FtGURE
I 3
I
I
.~
~2
0
0
I
> !::
0
~I
<[
0
10
8
:J:
~6
0
0
0
i
2
715
1980 1990 2000
LEGEND
D. HYDROELECTRIC
(i~~~iil~¥J COAL FIRED THERMAL
E:Z] -GAS f'!REO THERMAL
OIL FIRED THERMAL( NOT SHOWN ON ENERGY DIAGRAM •
NOTE: RESULTS OBTAINED FROM
OGPS RUN LFL 7
DISPATCHED
KEETNA
·CHAKACHAMNA
EXISTING AND COMMITTED
~954
2010
I
I
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I
I
I
I
I
I
I
I
I
I
I
I
0~--~----~------------------~----------~------------------d 1980 1990 2000. 2010
TIME
I
GENERATION SCENARIO INCORPORATING THERMAL [i]
. AND ALTERNATIVE HYDROPOWER D. EVELOPMENTS 'IPim.
- M E.DIUM LOAD FORECAST-FIGURE o.t4 fti b1
--------------------
PREVIOUS
STUDIES
UNIT TYPE
SELECTION
COAL: 100 MW
250 MW
500 MW
COMBINED CYCLE l 250 MW
GAS TURBINE : 75 MW
DlESEL : 10 MW
PLAN
FORMULAT.ION
OBJECTIVE
ECONOMIC
COMPUTER MODELS
TO EVALUATE
SYSTEM WIDE ECONOMICS
EVALUATION
OBJECTIVE
GAS RENEWALS
NO GAS RENEWALS
ECONOMIC
NO GAS RENEWALS
tEGEND
FORMULATION OF PLANS INCORPORATING AL~THERMAL GENERATION
STEP NUMBER lN
STANDARD PROCESS
(APPENDIX A)
I
FIGURE 0.15! Al~m l
I
I
I ~
:E 2
0
0
2
I I > f-.
0
<t a..
I 4 I
(.)
I
0
I
8
I
I
6
I :1:
~
(!)
I 0
0
0 4 • )-
I
(!)
a:
ILl z w
I 2
I
I 0
I
I
I
I
1079
846
189
45
1980
TOTAL
DISPATCHED
1.980
LEGEND
ENERGY
D HYDROELECTRIC 0
COAL FIRED THERMAL
GAS FIRED THERMAL
OIL FlRED THE~MAL. .
1591"
1573
f'S9
634
1990
TIME
EXISTING a COMMITTED
1990
TIME
(NOT SHOWN ON ENERGY DIAGRAM)
2000
2000
ALTERNATIVE GENERATION SCENARIO
BATTELLE MEDIUM LOAD FORECAST
2037
2031
968
813
2010
I
2010
FIGURE
------------------
~---------------------------------------------------------------A~------~------------------------------------~
LOAD ALTERNATIVE FUEL COST RESUL1 .. LONG-TERM COST
FORECAST CAPITAL COST ESCALATION 10 PROBABILITY PRESENT WOR,rn
HIGH TOI .01 116,058 HIGH ~ MEDIUM T02 .02 11,689 LOW !03 .01 7,024
!0..4 .. .03 14,194
HIGH .20 MEDIUM J2 !05 .00 ' 1~~8~9 ....... ~
T06 .03 7,313
TOZ .01 13,742
~ .02 10,503
-:01-• 7!184
IIO • 03 11,272 HIGH J2 Ill .oil &.158
Il2-.o~ 15Ht
Il:i .08 10!837 MEDIUM GO Tl~ .J8 8.238
Il5 ~~ 15!681
;I: .03 10,321
:a~ : k::.: :~
;~ .01 9,.2&3 .0~ HIGH .02 7:<480
.01 4166
I22 .03 8,746
LOW .20 MEDIUM .12 I23 .06 6,878
T2.4 .03 411590
HIGH T25 .01. 81412
LOW .~ MEDIUM !26 .o;c 6,101 LDW T27 .01 4.412
l: • t.OO
\ FIGURE 0.11..,. PIIOBABI LITY TREE -SYSTEM WITH AL TERJ\IATIVE$ TO SUSITNA I A~~lll
---.• - - - - - - - --- - - - - -
LOAD
f.ORECAST
ALTERNATIVE
CAPITAL FUEL COST
COST ESCALATION
FIGURE 0.18-PROBABILITY TREE-SYSTEM WITH SUSITNA
- - - --· - - ----- - - - --: - -
I
14 r
raJ
~
12
w-
I
10
-co
0 -)C
0
0 8 C) .. -0 -tt ...
c ..1
Non-Susitu Plan r v I \ I---'
r -•• _$
,r ~ __,.-___,.
0
(..)
e 6 ...
CD ...
.~ c
!l
r
F -\ ·'
" Susitna Plan
.
~
-
4
,...I'
2
0 .1 .2 .3 .4 .5 .6 .7 .8 .9 1.0
Cumulative Probability
fiGURE 0.19-SUSITNA MULTIVARIATE SENSITIVITY ANALYSIS-LONG-IERM COSTS VS CUMULATIVE PROBABIL}TV
1.0
~~
.8
.7
.~ -.6 :0
(I) ..a
0
"' a. .5 ~ > ·-lij -:J .4 E
::J u
.3
.2
.1
~ l
/
~ v
•,
/ :
A v I
/ '
'
( v r
f
/ "' ! v ~
L j
t
/ ~ $
~ ~
(4600) (3500) (2500) (1500) \'500) 0 500 1600 2500 3500 5500
Net Benefit -$ x 106 ( 1982 $)
FIGURE 0.20 -SUS I TNA MUL "flVARIATE SENSITIVITY ANAL VSIS -CUMULATIVE PROBABILITY VS NET BENEFITS .
-Re.r ... -
380
380.
340
320
300 -..c
~ ~
280
:E 260 -aft
(1) u ·-...
Q. 240 ] co •
:t aft 220 8
~
(1) 200 c w
180
160
140
120
100
94
·----
5
NO STATE APPROPRIATION SCEt~ARIO
100% DEBT FINANCING
Susitna Mill Rate Cost With
7% Inflation, 10% Interest
COST SAVINGS
--~--~·-a9·
##
t1 II I COST SAVINGS GROWING OVER I WHOLE OF SUSITNA.LIFE
I I
Mill Rate Cost
Best Thermal Option
7% Inflation, 10% Interest
Mill Rata Cost
Best Thermal Option
0% I nflatlon, 3% Interest
-----------.. --' ----1 ' -----
, :::::~::~:::~:,~::~~~======::::::::::::-::~::-:.-~-----.. -................ .
Negligible Financing D1ficit with Zero Inflation
Susitna Cost with 0% Inflation, 3% Interest
7 8 9 2000 01 02 03 04 05 06 07 08 09 2010 11 12 13
Y•an
FIGURE 0.21-ENERGY COST COMPARISON-100% DEBT FINANCING 0 AND 7% INFLATION
~. -------------------
Rev. 1
360
340
320
300
280 -· .;C
!: 260 ~ -.....
.!: -·-
STATE APPROPRIATION OF
$3.0 BILLION WITH 7% INFLATION AND 10% INTEREST
• •• I I I I
Mill Rate Cost /
Bart Th&rmal Option /
~ '_., 7-
~#
~#
........... ,.# .....
COST SAVINGS GROWIN.G OVER
WHOLE OF SUSITNA LIFE
~ 240
wt
---I'A *., ~#
Susitna wholesale energ'l_, pries f~flt aj
anergy increasos to 2009 and ri~
=lowly thereafter
B ·-.. a.
"C c: co
D
"" 0
(.)
> Cia ...
CP c w
220
200
180
160
140
120
100
_., .-• I
I
I • I
I --~ ~-
Watana Completed 199~ with $1.8 billion
($0.9 bn 1982) of Bonds 1991 .. -!~: ~Yer of
1.25 at 80 Mills/kWh in 1994
Devil Canyon Completed with $7.2 bUUon ($2.3 bn 1982) of
Revenue Bonds 1994-2002
80 ~[--/~L~~~=-~. ~ ~~--_ susitna Wholesale Energy Price ~
94 5 6 7 8 9 2000 01 02 03 04 05 06 07 08 09 2010 11 12
Vaan
13
FIGURE 0.22-ENERGY COST COMPARISON-STATE APPROPRIATION $3 arLLION (1982 $)
-------------------;--
Rev.1
380
340
\ 300 -.I! s: .:.: . 280 ......
~
~ -260 M
Cl),
.~ ..
Q,.
"C 240 c:
(Q
~
0 220 (.)
~
Q,J c: 200 w
180
160
140
120
100
MINIMUM STATE APPROPRIATION OF
$2c3 BILLION WITH 7% INFLATION AND 10% INTEREST
6
Mill Rate Cost
Btst Thermal Optioo
Susitna Pricing Restricted to~
Maximum of B•st Tharmal Cost
Susitna Wholesale Energy Price
Watana Completed 1993 with $3.3 billion
($1.7 bn 1982) of Bonds 1990 -93; Cover of
1.25 at 137 Mills/kWh in 1994
COST SAVINGS GROWING OVER
WHOLE OF SUSITNA LIFE
Susitna wholesale anergy ~i~ faUs as
energy increaHs to 2010 ~~:rises
slowly theraafter
Devil Canyon Completed with $8.8 billion ($2..1 bn 1982) of.
Revantte Bonds 1994-2002
6 7 8 9 2000 01 ·02 03 04 05 06 07 08 09 2010 11 12 •i3 ~
FIGURE D. 23 -ENERGY C~;-COMI!ARISON.$2.3 BILLION (1982$1-MINIMUM STAtE APPROPRIATION •
------------------
RIIY. 1
380
360
340
320
300
-.c.
~ 280
~
~-260
In
4U u ·-..
Q. 240 "0 .c
1\1
:J 220 ...,
0
(,)
~ ...
200 w c w
180
140
120
I STATE APPROPRIATION OF
$1.8 BILLION WITH 7% INFLATION AND 10% INTEREST
Mill Rata Cort
Best The.-mal Option
Watana Completed with $4.4 billion ($2.4 bn 1982) of
Bondl1989-93. Inadequate Cover Unti11996
6
Years
1 8
-
9 2000 01 02
FIGURE
COST SAVINGS GROWING OVER
WHOLE OF SUSITNA LIFE
I
Susitna Price Track1 Cost of Best Thermal Option
Until 1.25 Dabt Service Cover Established
Devil Canyon Completed with $6.9 billion ($2.1 bn in 1982)
Inadequate COver Until 2004
: .
03 04 05 06 07 06 06 2010 ,, 12 13 1·,1 ~ 1
.0.24 -ENERGY COST COMPARISON-PRICING RESTRICTED 94/96 AND 03/04 II [8
-------------------
-.c ::
C! ~ -·-:E -... .,
u ·-""' ·c.
"0 c ..
~ ...
0
CJ
>-till ...
Q) c w
380
360
340
320
300
280
260
240
220
200
180
160
140
SENATE BILL 646 PROPOSAL-100% STATE FINANCING
Mill Rate Cost
_But Thermal Option Price
11/i•
~ •• ~~· •' ~#
I ~ ......
#
.# .
•••• ,_ •• .,.## COST SAVINGS GROWING OVER
WHOLE OF SUSITNA LIFE
Susitna Wholesale
Energy Price
120 Watana Comph'tld 1993
100 Oevil Canyon Comp21ted 2002
99 2000 o1 oz 03 . 04 os os · 01 oa 09 10 11 12 13 ·laPoro I
FIGURE 0.25-ENERGY COST COMPARISON MEETING SB &46 REQUIREMENTS WITH 100% FINANCING IIU0[0
94 96 97
Vaars
98
- - - - - - - - - --· .. - - - --~--~
-.c
~
.!:! -·-:E --.,.
CP
(,) ·--a.
"'C c
C'l .., ..... en
8
340
320
300
280
260
240
220
200
180
SENATE BILL 646 "MINIMUM" APPROPRIATION OF
$3.0 BILLION WITH 7% INFLATION AND 10% INTEREST
Mill Rate Cost
Bert ThermJI Option
Susitna Wholesale
Energy Price
COST SAVINGS GROWING OVER
WHOi..cOF SUSITNA LIFE
Operating Costs, Renewals 1od
Interest on Working Capital
Gl160 ....
CP c w
140
120
94 95
Costs, Renewals and
nta1rart· on Working Capital·
tjEtf'f SERVICE
Devil Canyon Completed with $7.5 bilhon
($2.3 bn In 1982) of Revenue Bonda1094-2002
97 98 99 2000 01 02 03 04 05 06 07 08 09 10 11 12 13
Years
FIGURE .0.26-ENERGY COST COMPARISON MEETINGSB_646 REQUIREMENTS WITH $3.0BILLJONAPPROPRIATION ·~~::;...!
I
I
I
I
I
I
I
I
I
I
I
'I
I
I
I
I
I
I
I
SPECIFIC FINANCING RISK HI: EARLY YEAR NONVIABILITY
1.0
0.9
0.8.
0.7
~. 0.6 --·· :g 0.5
.a
0 a: 0.4
0.3
0.2
0.1
0.0
-20 ·10 0
Watana Unit Cost as% of Bert Thermal
FIGURE D.2i'-WATANA UNI.T COSTS AS PERCENT OF BEST THERMAL OPTION IN t996
AGGREGATE RISK: POTENTIAL NET OPERATING EARNINGS
'!...------------~--------···-·-----------'
1.0 t
0.9
0..8
0.1
.~ 0.6 -:a co 0.5 .a
2
Q. 0.4
0.3
0.2
0.1 o~L.~~~~=-L-L-~~~~~~~~~
-0.6 ..().4 -0.2 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4
Cumulative Net Operating Earnings in $ bn {1982)
FIGURE 0.28-CUMULATIVE NET OPERATING EARNiNGS B'Y\2000
I
I
"I
I
1
-·
I
I
t
I
I
I
I
I
I
I
I
SFECII;IC RISK 1: RISK OF BOND REQUIREMENT OVERRUN I
0.9
0.8
0.7
fl 0.6
-a 0.5 .a e c. J 0.4
0.3
0.2
0.1
,,
1.0
I
Forecast Watana Borrowing Requirement
in $2.3 bn Appropriation Case / .
1.7 2.0 3.0
Bond Requirements for Watana in$ bn (1982)
4.0
FIGURE 0.29-BOND FINANCING REQUIREMENTS
SPECIFIC RISK U: IMPAf,RMENT OF STATE CREDIT
0.8
0.7
.~1 0.6 -:s
(I',S 0.5
.Q e c.
0.3
,..,. Minimum Cover Requirement
0.1 t.....d!!!~--L--1/~· _...J..__ __ --L.------1--
0.0 1.0 ~1.25 2.0 3.0 4.0
'
Coverage on Bonds Issued for Watana
FIGURE. 0.30-DEBT SERVICE COVER
[i].