HomeMy WebLinkAboutAPA221ACRES AMERICAN INCORPORATED
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Suite 305
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Telephone : (907) 279-9631
ALASKA PO~IER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
TASK 6 -DEVELOPMENT SELECTION
SUBTASK 6.05
DEVELOPMENT SELECTION REPORT
APPENDICES A THROUGH J
DECEMBER 1981
ACRES AMERICAN INCORPORATED
1000 Liberty Bank Building
Main at Court
Buffalo, New York 14202
Telephone: (716) 853-7525
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
SUSITNA BASIN DEVELOPMENT SELECTION
VOLUME II -APPENDICES A THROUGH J
TABLE OF CONTENTS Page
LIST OF TABLES •..........•.•.............•....•..•.•...•••......•.. iii
LIST OF FIGURES ................•................................... viii
A -GENERIC PLAN FORMULATION AND SELECTION METHODOLOGY
A.1-Plan Formulation and Selection Methodology ............... A-2
A.2 -Guidelines for Establishing Screening and Evaluation
Criteria .................................................. A-2
A.3-Plan Selection Procedure ................................. A-5
B -THERMAL GENERATING RESOURCES
B.1-Fuel Availability and Costs .............................. B-1
B.2-Thermal Generating Options-Characteristics and Costs ... B-7
B.3-Environmental Considerations .....................•....... B-16
C -ALTERNATIVE HYDRO GENERATING SOURCES
C.1 -Assessment of Hydro Alternatives ......................... C-1
C.2-Screening of Candidate Sites ................•............ C-1
D -ENGINEERING LAYOUT DESIGN ASSUMPTIONS
D.l -Approach to Project Definition Studies ................... D-1
D.2-Electrical System Considerations ......................... D-1
0.3-Geotechnical Considerations .............................. D-2
0.4-Hydrologic and Hydraulic Considerations .................. D-3
0.5-Engineering Layout Considerations ........................ D-3
0.6-Mechanical Equipment ..................................... D-3
0.7-Electrical Equipment ...................................•. D-4
0.8-Environmental Considerations ............................. D-4
E -SUSITNA BASIN SCREENING MODEL
E.1 -Screening Model .......................................... E-1
E. 2 -Mode 1 Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E-2
E.3 -Application of the Screening Model ....................... E-3
E .4 -Input Data ............................................... E-3
E.5-Model Runs and Results ................................... E-4
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
SUSITNA BASIN DEVELOPMENT SELECTION
VOLUME II -APPENDICES A THROUGH J
TABLE OF CONTENTS (Cont•d.)
F -SINGLE AND MULTI-RESERVOIR HYDROPOWER SIMULATION STUDIES
F .1 -Introduction .................................•........... F-1
F .2 -Single Reservoir Model ................................... F-1
F.3-Multi-Reservoir Simulation ............................... F-3
F .4 -Annual Demand Factor •..•••............................... F-3
F.5-Input to Simulation Models ............................... F-4
F .6 -Mode 1 Results ............................................. F-5
F.7-Interaction of OGP5 ........•............................. F-6
G -SYSTEMWIDE ECONOMIC EVALUATION
G.1 -Introduction .•......•....•......•........................ G-1
G.2-Generation Planning Models ........................•...... G-2
G.3-Generation Planning Results ....•......................... G-8
H -ENGINEERING STUDIES
H.l -Devil Canyon Site ....•................................... H-1
H .2 -Watana Site ...........•.............................•.... H-5
I -ENVIRONMENTAL STUDIES
I .1 -Summary .................................................. I-1
I. 2 -TES Report ...............•..•.....•...................... I-3
J -AGENCY AND OTHER COMMENTS
J.1-Responses to AEIDC Comments .............................. J-1
J.2-Responses to ADF&G Comments ...•.......................... J-2
J .3 -Response to USGS Comments ................................ J-2
J .4 -Response to USNPS Comments ............................... J-2
J.5-Response to ADEC Comments ................................ J-2
; ;
LIST OF TABLES
A.l
A.2
A.3
A.4
B. 1
8.2
B.3
B.4
B.5
B.6
B.7
B.8
B.9
B. 10
B.ll
B. 12
B.l3
B. 14
B. 15
c. l
C.2
Step 2 -Select Candidates
Step 3 -Screening Process
Step 5 -Plan Evaluation and Selection
Examples of Plan Formulation and Selection
Methodology
Alaskan Railbelt Coal Data
Alaskan Gas Fields
Alaskan Oil Fields
Alaskan Railbelt Fuel Prices (1980)
Summary of Alaskan Fuel Opportunity Values
Generating Units Within the Railbelt -1980
Existing Generating Capacity in the Railbelt
Region
1000 MW Coal-Fired Steam Plant Cost Estimate -
Lower 48
500 MW Coal Fired Steam Cost Estimates
250 MW Coal-Fired Steam Cost Estimates
100 MW Coal-Fired Steam Cost Estimates
250 MW Combined Cycle Plant Cost Estimates
Summary of Thermal Generating Resource Plant Paramaters
Gas Turbine Turnkey Cost Estimate
Gas 75 MW Gas Turbine Cost Estimate
Summary of Results of Screening Process
Sites Eliminated in Second Iteration
iii
LIST OF TABLES (Cont.)
C.3
C.4
C.5
C.6
C.7
C.8
C.9
c. 10
c. 11
C.12
c. 13
c. 14
c. 15
c. 16
c. 17
c. 18
c. 19
C.20
C.21
D. 1
D.2
D.3
Evaluation Cirteria
Sensitivity Scaling
Sensitivity Scaling of Evaluation Criteria
Site Evaluations
Site Evaluation Matrix
Criteria Weight Adjustments
Site Capacity Groups
Ranking Results
Shortlisted Sites
Preliminary Cost Estimate -Snow
Preliminary Cost Estimate -Keetna
Preliminary Cost Estimate -Cache
Preliminary Cost Estimate -Browne
Preliminary Cost Estimate -Talkeetna - 2
Preliminary Cost Estimate -Hicks
Preliminary Cost Estimate -Chakachamna
Operating and Economic Parameters for Selected
Hydroelectric Plants
Alternative Hydro Development Plans
Results of Economic Analyses of Alternative
Generation Scenarios
Monthly Variations of Energy and Peak Power
Demand
Geotechnical Design Considerations
Initial Hydrologic Design Considerations
iv
LIST OF TABLES {Cont.}
D.4
D.S
D.6
D.7
D.B
D.9
D.lO
E. 1
E.2
E.3
E.4
E.S
E.6
E.7
E.8
F. 1
F.2
F.3
F.4
F.S
F.6
F.7
Revised Design Flood Flows for Combined
Development
Site Specific Hydraulic Design Considerations
General Hydraulic Design Considerations
Preliminary Freeboard Requirement
Example Calculation of Freeboard Requirement
at Devil Canyon
Engineering Layout Considerations as Single
Developments
Tentative Environmental Flow Constraints
Computed Streamflow at Devil Canyon
Computed Streamflow at High Devil Canyon
Computed Streamflow at Watana
Computed Streamflow at Susitna 3
Computed Streamflow at Vee
Computed Streamflow at Maclaren
Computed Streamflow at Denali
Results of Screening Model
Reservoir and Flow Constraints
Dam Site Streamflow Relationship
Susitna Development Plans
Susitna Environmental Development Plans
Plan 1.1 -Energies
Plan 1.2-Energies
Plan 1.3-Energies
v
LIST OF TABLES (Cont.)
F.B
F.9
F. 10
F. 11
F.l2
F.l3
F.l4
F. 15
G. 1
G.2
G.3
G.4
G.5
G.6
G.7
G.B
G.9
G. 10
Plan 2.1 -Energies
Plan 2.2 ~ Energies
Plans 2.3 and E.213 ~ Energies
Plan 3.1 ~Energies
Plan 4,1 -Energies
Plan El.2-Energies
Plan El.3-Energies
Plan E2.4 -Energies
Salient Features of Generation Planning
Programs
Railbelt Region Load and Energy Forecasts Used
For Generation Planning Studies
Loads and Probabilities Used in Generation
Planning
Fuel Costs and Escalation Rates
Annual Fixed Carrying Charges Used in Generation
Planning Model
Ten Year Base Generation Plan Medium Load
Forecast
. Susitna Environmental Development Plans
Results of Economic Analyses of Susitna Plans -
Medium Load Forecast
Results of Economic Analyses of Susitna Plans -
Low and High Load Forecasts
Results of Economic Sensitivity Analyses for
Generation Scenario Incorporating Susitna
Basin Development Plan El.3-Medium Forecast
vi
LIST OF TABLES (Cont.)
G.ll
G.l2
I.l
!.2
!.3
Results of Economic Analyses of Alternative
Generation Scenarios
Results of Economic Analyses for Generation
Scenario Incorporating Thermal Development Plan -
Medium Forecast
Environmental Evaluation of Devil Canyon Dam
and Tunnel Scheme
Social Evaluation of Susitna Basin Development
Schemes/Plans
.Environmental Evaluation of Watana/Devil Canyon
and High Devil Canyon/Vee Development Plans
vii
LIST OF FIGURES
A.l
c. 1
C.2
C.3
C.4
C.5
C.6
C.7
C.B
C.9
c. 10
c. 11
E. l
E.2
E.3
E.4
F. 1
G. 1
H. 1
H.2
H.3
H.4
Plan Formulation and Selection Methodology
Selected Alternative Hydroelectric Sites
Alternative Hydro Sites Typical Dam Section
Alternative Hydro Sites Snow
Alternative Hydro Sites Keetna
Alternative Hydro Sites Cache
Alternative Hydro Sites Browne
Alternative Hydro Sites Talkeetna 2
Alternative Hydro Sites Hicks
Alternative Hydro Sites Chakachamna
Alternative Hydro Sites Chakachamna -Profile
and Sections
Generation Scenario Incorporating Thermal and
Alternative Hydropower Developments -Medium Load
Forecast
Damsite Cost vs Reservoir Storage Curves
Damsite Cost vs Reservoir Storage Curves
Damsite Cost vs Reservoir Storage Curves
Mutually Exclusive Development Alternatives
1995 Month/Annual Peak Load Ratios
Energy Forecasts Used For Generation Planning
Studies
Devil Canyon Arch Gravity Dam Scheme Plan and
Sections -General Arrangement
Devil Canyon Arch Gravity Dam Scheme Sections
Watana Arch Dam Geometry -General Arrangement
Watana Arch Dam Geometry -Sections Along Planes
of Centers
viii
APPENDIX A -GENERIC PLAN FORMULATION AND
SELECTION METHODOLOGY
On numerous occasions during the feasibility studies for the Susitna Hydro-
electric Project, decisions must be made in which a single or a small number of
courses of action are selected from a larger number of possible alternatives.
This appendix presents a generalized framework for this decision-making process
that has been developed for the Susitna planning studies. It outlines, in gen-
eral terms, the approach used in screening a large multitude of options and
finally establishing the best option or plan. It is comprehensive in that it
takes into account not just economic aspects but also a broad range of
environmental and social factors.
The application of this generalized methodology is particularly relevant to the
following decisions to be made during the Susitna studies:
-Selection of alternative plans involving thermal and/or non-Susitna hydro-
electric developments in the primary assessment of the economic feasibility of
the Susitna Basin development plan (Task 6).
-Selection of the preferred Susitna Basin hydroelectric development plan (i.e.
identification of best combination of dam sites to be developed) (Task 6).
-Selection of the preferred Railbelt generation expansion plan (i.e. comparison
of Railbelt plans with and without Susitna).
-Optimization of the selected Susitna Basin development plan (i.e. determining
the best dam heights, installed capacities, and staging sequences) (Task 6).
-Selection of the preferred transmission line routes (Task 8).
-Selection of the preferred mode of access and access routes (Task 2).
-Selection of the preferred location and size of construction and operational
camp facilities (Task 2).
It is recognized that the above planning activities embrace a very diverse set
of decision-making processes. The generalized methodology outlined here has
been carefully developed to be flexible and readily adaptable to a range of ob-
jectives and data availability associated with each decision.
The following sections briefly outline the overall decision-making process and
discuss the guidelines to be used for establishing screening and evaluation
criteria.
A-1
A.1 -Plan Formulat i on and Selection Methodology
The methodology to be used in the decision process can generally be subdivided
into five basic steps {Figure A.1):
-Step 1: Determine basic objectives of the planned course of action
-Step 2: Identify all feasible candidate courses of action
-Step 3: Establish a basis to be used and perform screening of candidates
-Step 4: Formulate plans incorporating preferred alternatives
-Step 5: Re-establish a basis to be used, evaluate plans and select preferred
plan
Under Step 2, the candidate courses of action are ·dentified such that they sat-
isfy, either individually or in combinations, the stated objectives {Table A1).
In Step 3, the basis of screening these candidates i s establishe.d in items of
redefined, specific objectives, assumptions, data base, criteria and methodol-
ogy. This process follows a sub-series of seven steps as shown in Table A.2 to
produce a short list, ideally of no more than five or six preferred alterna-
tives. Plans are then formulated in Step 4 to incorporate single alternatives
or appropriate combinations of alternatives. These plans are then evaluated in
Step 5, using a further redefined set of objectives, criteria and methodology,
to arrive at a selected plan. This six step procedure is illustrated in Table
A.3. Tables A.2 and A.3 also indicate the review process that must accompany
the planning process.
It is important that, within the plan formulation and selection methodology, the
objectives of each phase of the decision process be redefined as necessarv. At
the outset the objectives will be broad and somewhat general in nature. As the
process continues, there will be at least two redefinitions of objectives. The
first will take place during Step 3 and the second during Step 5. As an
example, the basic objectives at Step 1 might be the development and application
of an appropriate procedure for selection of a single, preferred course of
action. Step 2 might involve the selection of those candidates which are
technically feasible on the basis of a defined data base and set of assumptions.
The objectives at Step 3 might be the establishment and application of a defined
set of criteria for elimination of those candidates which are less acceptable
from an economical and environmental s~andpoint. This ~ould be accomplished on
the basis of an approp r iately modified data base and assumptions. Having
developed a series of plans i nco r porating the remaining or preferred alterna-
tives under Step 4, the objectives unde r Step 5 might be the selection of the
single alternative which best satisfies an appropriately redefined set of
criteria for economi :, environmental and social acceptability.
A.2 -Guidelines for Establishing Screening and Evaluation Criteria
The definition of criteria for the screening and evaluation procedures will
lar~ely depend on the precise nature of the alternatives under consideration.
However, in most cases comparisons will be based on technical, economic,
environmental and socioeconomic factors which wi 11 usually involve some degree
of trade-off in making a preferred selection. It is usually not possible to
adequately quantify such trade-offs.
A-2
:Additional criteria may also be separately considered in some cases, such as
~~fety or conservation of natural resources. Guidelines for consideration of
the more common over a 11 factors are discussed in the following paragraphs.
(a} Technical Feasi bi 1 ity
Basically, all options considered must be technically feasible, complete
within themselves, and must ensure public safety. They must be adequately
designed to cope with all possible conditions including flood flows. seis-
mic events, and all other types of normal loading conditions.
(b) Economic Criteria
In cases where a specific economic objective can be met by various alterna-
tive plans, the criteria to be used is the least present worth cost. For
example, this would apply to the evaluation of the various Railbelt power
generation scenarios, optimizing Susitna Basin hydroelectric developments,
and selection of the best transmission and access routes. In cases where
screening of a large number of options is to be carried out, unit commodity
costs can be used as a basis of comparison. For instance, energy cost in
$/kwh would apply to screening a number of hydroelectric development sites
distributed throughout southern Alaska. Similarily the screening of
alternative access or transmission line route segments would be based on a
$/mile comparison.
Because the Susitna Basin development is a state project, economic
parameters are to be used for all analyses. This implies the use of real
(inflation adjusted) interest rates and only the differential escalation
rates above or below the rate of general price inflation. Intra-state
transfer payments such as taxes and subsidies are excluded, and opportunity
values (or shadow prices) are used to establish parameters such as fuel and
transportation costs.
Extensive use should also be made of sensitivity analyses to ensure that
the conclusions based on economics are valid for a range of the values of
parameters used. For example, some of the more common parameters consid-
ered in comparisons of alternative generation plans particularly lend
themselves to sensitivity analyses. These may include:
-Load forecasts
-Fuel costs
-Fuel cost escalation rates
-Interest and discount rates
-Economic life of system components
-Capital cost of system components
A-3
(c) Environmental Criteria
Environmental criteria to be considered in comparisons of alternatives are
based on the FERC (1) requirements for the preparation of the Exhibit E
''Environmental ReportH to be submitted as part of the license application
for the project. These criteria include project impacts on:
-Physical resources, air, water and land
-Biological resources, flora, fauna and their associated habitats
-Historical and cultural resources
-Land use and aesthetic values
In addition to the above criteria, which are used for comparing or ranking
alternatives, the following economic aspects should also be incorporated in
the basic alternatives being studied:
-In developing the alternative concepts or plans, measures should be in-
corporated to minimize or preclude the possibility of undesirable and
irreversible changes to the natural environment.
-Efforts should also be made to incorporate measures which enhance the
quality aspects of water, land and air.
Care should be taken when incorporating the above aspects in the alterna-
tives being screened or evaluated to ensure consistency between alterna-
tives, i.e. that all alternatives incorporate the same degree of mitiga-
tion. As an example, these measures could include reservoir operational
constraints to minimize environmental impact, incorporation of air quality
control measures for thermal generating stations, and adoption of access
road and transmission line design standards and construction techniques
which minimize impact on terrestrial and aquatic habitat.
{d) Socioeconomic Criteria
Based generally on FERC requirements, the project impact assessment should
be considered in terms of socioeconomic criteria which include:
-Impact on local communities and the availability of public facilities and
services
-Impact of employment on tax and property values
-Displacement of people, businesses and farms
-Disruption of desirable community and regional growth
A-4
A.3 - P an Selection Procedure
As noted above, for each successive screening exercise, the criteria can be
refined or modified in order to reduce or increase the number of alternatives
being considered. As a general rule, no attempt will be made to ascribe numeri-
cal values to non-quantifiable attributes such as environmental and social
impacts in order to arrive at an overall numerical evaluation. Such a process
tends to mask the judgemental tradeoffs that are made in arriving at the best
plan. The adopted approach involves utilizing combinations of both quantifiable
and qualitative parameters in the screening exercise without making tradeoffs.
For example, the screening criteria used might be:
-
11
••• alternatives will be excluded from further consideration if their unit
costs exceed X and/or if they are judged to have a severe impact on wildlife
habitat ... 11
This approach is preferable to criteria which might state:
-" ... alternatives will be excluded if the sum of their unit cost index plus
the environmental impact index exceeds Y ... 11
Nevertheless, it is recognized that under certain circumstances, particularly
where a relatively large number of very diverse alternatives must be screened
very quickly, the latter quantitative approach may have to be used.
In the final plan evaluation stages, care will be taken to ensure that all
tradeoffs that have to be made between the different quantitative and qualita-
tive parameters used, are clearly highlighted. This will facilitate a rapid
focus on the key aspects in the decision-making process.
An example of such an evaluation result might be:
-" ... Plan A is superior to Plan B. It is $X more economic and this benefit is
judged to outweigh the lower environmental impact associated with Plan B 11
Sufficient detailed information should be presented to allow a reviewer to make
an independent assessment of the judgemental tradeoffs made.
The application of this procedure in the evaluation stage is facilitated by
performing the evaluations for paired alternatives only. For example, if the
shortlist plans are A, B, and C, then in the evaluation Plan A is first evalu-
ated against Plan B, then the better of these two is evaluated against C to
select the best overall plan.
A-5
LIST OF REFERENCES
(1) Code of Federal Regulations -Title 18; Parts 2, 4, 5, 16 and 131.
A-6
TABLE A.1 -STEP 2-SELECT CANDIDATES
Step 2.1 -Identification of candidates:
-objectives
-assumptions
-data base
-selection criteria
-selection methodology
Step 2.2 -List and describe candidates that will be used in Step 3.
TABLE A.2 -STEP 3 -SCREENING PROCESS
Step 3.1 -Establish:
-objectives
-assumptions
-data base
-screening criteria
-screening methodology
Step 3.2-Screen candidates, using methodology established in Step 3.1 to
conduct screening of alternatives.
Step 3.3-Identify any remaining individual alternatives (or combinations of
alternatives) that satisfy the objectives and meet the criteria
established in Step 3.1 under the assumptions made.
Step 3.4 -Determine whether a sufficient number of alternatives remain to
formulate a limited number of plans. If not, additional screening
via Steps 3.1 through 3.3 is required.
Step 3.5 -Prepare interim report.
Step 3.6 Review screening process via (as appropriate):
-Acres
-APA
-External groups
Step 3.7-Revise interim report.
TABLE A.3 -STEP 5 -PLAN EVALUATION AND SELECTION
Step 5.1 -Establish:
-objectives
-evaluation criteria
-evaluation methodology
Step 5.2 -Establish data requirements and develop data base.
Step 5.3 -Proceed with the plan evaluation and selection process as follows:
-Identify plan modifications to improve alternative plans
-Based on the established data base and the selection criteria, use
a paired comparison technique to rank the plans as (1) the preferr-
ed plan, (2) the second best plan, and (3) ather plans;
-Identify tradeoffs and assumptions made in ranking the plans.
Step 5.4 -Prepare draft plan selection report.
Step 5.5 -Review plan selection process via (as appropriate):
-Acres
-APA
-External groups
Step 5.6 -Prepare final plan selection report.
Activity
Susitna Basin
Development
Selection
Access Route
Selection
TABLE A.4 -EXAMPLES OF PLAN FORMULATION AND SELECTION METHODOLOGY
1. Def1ne
Objectives
Select best
Susitna Basin
hydropower
development
plan
Se.lect best
access route
to the pro-
posed hydro-
power develop-
ment sites
within the
basin for
purposes of
construction
and operation
2. Select
Alternatives
All alternative
dam sites in the
basin, e.g.:
Devil Canyon;
High Devil Canyon;
Watana
Susitna III;
Vee;
Maclaren;
Butte Creek;
Tyone;
Denali;
Gal d Creek;
Olson;
Devil Creek;
Tunnel Alternative
Al 1 alternative
road, rail, and
air transport
component links,
e.g.:
road and rail
links from Gold
Creek to sites
via north and
south routes;
Road links to
sites from Denali
Highway;
Air links to
sites and associated
landing facilities
3. Screen
Screen out sites
which are too
small or are
known to have
severe environ-
mental impacts
Screen out links
which are either
more costly or
have higher
environmental
impact than
equivalent
alternatives.
Ensure suffi-
cient links
remain to allow
formulation of
plans
4. Pian
Formulation
Select several
combinations of
dams which have
the potential
for delivering
the lowest cost
energy in the
basin, e.g.:
Watana-Devil
Canyon dams;
High Devil
Canyon-Vee dams;
Watana Dam -
Tunnel
Select several
different access
plans, e.g.:
Gold Creek road
access;
Gal d Creek road/
rail access;
Denali Highway
road access
5. Evaluation
Conduct detailed
evaluation of
development plans
Conduct detailed
evaluation of
development plans
DEFINE
OBJECTIVES
INPUT FROM AVAILABLE SOURCES -PREVIOUS AND CURRENT STUDIES
FEEDBACK
FEEDBACK
PLAN FORMULATION AND SELECTION METHODOLOGY
LEGEND
--" STEP NUMBER IN
4 STANDARD PROCESS
(APPENDIX A )
FIGURE A.l
APPENDIX B -THERMAL GENERATING RESOURCES
The purpose of this Appendix is to define the thermal generating resources
available to the Railbelt during the 1980-2010 study period. To address thermal
resources, it is necessary to review the existing thermal capacity, fuel avail-
ability and associated costs as well as review future plant capacities and capi-
tal costs for development. To develop the parameters necessary for generation.
planning studies, it is also necessary to assess operation and maintenance
costs, and planned and forced outages. The contents of this section document
the data used in the generation planning studies described in Sections 6 and 8.
8.1 -Fuel Availability and Costs
Fuel sources available in the Railbelt region for future electric generation
plants are primarily coal and natural gas. Distillate, although not expected to
play a maJor role, is discussed briefly. It is unlikely that oil will be used
as the primary fuel for additions to the generation system in the Railbelt due
to public policy and high value for other uses. Tables B.1, 8.2 and 8.3 summar-
ize estimated fuel reserves. Table 8.4 lists current (1980) fuel prices in the
Railbelt region. Table 8.5 summarizes the developed fuel costs which represent
opportunity (shadow) values, assuming active international marketing of Alaskan
fuels, as discussed in the following sections.
(a) Coal
Alaskan coal reserves include the following coal producing fields (2):
-Nenana
-Matanuska
-Beluga
-Kenai
-Bering River
-Herendeen Bay
-Chignik Bay
Of these eight regions, only four have potential for Railbelt use. Table
B.1 lists pertinent information of these four coal reserves.
The Beluga field, which is part of the larger Susitna Coal District, is an
undeveloped source located 45 to 60 miles west of Anchorage on the west
bank of Cook Inlet. Coal mining at this location would require the estab-
lishment of a mining operation, transportation system and supporting com-
munity and infrastructure. A number of studies have been conducted on the
reserves located in the Beluga Coal Fields. It has been estimated that
three areas (the Capps, Chuitna and Three Mile fields) contain 2.4 billion
tons of coal and that in excess of 400 million tons can be stripped without
exceeding economic limits on coal/overburden ratios.
The existing Nenana coal field, which is located in the vicinity of Fair-
banks, is primarily leased by Usibelli Coal Mine Incorporated. The field
ranges from less than a mile to more than 30 miles in width for about 80
miles along the north flank of the Alaska Range. Nenana coal is primarily
mined by surface methods. An estimated 95 million tons of coal is avail-
able by stripping, and an estimated total in excess of 2 billion additional
tons of coal could be extracted by underground mining.
B-1
The Matanuska coal fields, east of Anchorage, occupy most of the Matanuska
Valley. Although stripping and underground mining of this source have been
undertaken, stripping is limited due to relatively steep dips and increas-
ingly thick overburden. Reserves are estimated at 50 million tons, and ul-
timate resource value may be 100 million tons. Although limited usage is
possible locally, potential as a significant Railbelt source is unlikely
(3).
The fourth potential coal producing region is the Kenai coal field in the
Kenai lowlands, south of Tustumena Lake on the eastern shore of Cook Inlet.
Resources are estimated at 300 million tons. These coal seams are thin and
separated vertically, making mining extremely difficult.
Limited use of coal in the Railbelt at present is a result of an undevelop-
ed export market and the relatively small local demand for this fuel. Cur-
rently the Usibelli Coal Company mines Nenana coal at a facility located in
Healy and produces approximately 0.7 million tons/year. This coal repre-
sents the only major commercial coal operation in Alaska. The coal is
trucked several miles from the mine site to a 25 MW power plant owned and
operated by the Golden Valley Electric Association (GVEA) at Healy. The
delivered cost is approximately $1.25 per million Btu (MMBtu). The Nenana
coal is also trucked 8-1/2 miles to a railway spur loading station at
Susitana for transport to Fairbanks, a distance of 111 miles. This coal is
delivered to the Chena Station (capacity 29 MW), owned by Fairbanks Munici-
pal Utility System (FMUS), at an extra cost of approximately $0.34/MMBtu
bringing the price to FMUS to $1.40/MMBtu. Coal mined at Healy is also
used for generation in units at Fort ~4aim·Jright Army base and the Univer-
sity of Alaska power plants. Various proposals have been made for expanded
production in the Nenana coal field which would nearly double the
production. In September, 1980, a contract between llapan and the owners of
the Healy operation was signed to transport coal to Seward via the Alaskan
Railroad for barging to Japan. Details and costs of this proposal are not
available at this time. Other expansion options include:
-Enlarge the Healy generation plant to 100 MW (75 MW addition). This was
proposed jointly by GVEA and FMUS. However, the location of the Healy
plant 4.5 miles from Mt. McKinley National Park may restrict development
due to increased costs associated with meeting air quality standards.
Expand the FMUS Chena generation plant or build a new joint FMUS/GVEA
plant at Fairbanks to supply district heat and increased electric power
capability.
Transport Healy mined coal approximately 55 miles north via the Alaska
Railroad to Nenana and build a 100 MW expansion there. However, accord-
ing to GVEA and FMUS, this expansion plan has been postponed due in part
to slowing demand growth and environmental restrictions.
-Transport Healy mined coal approximately 200 miles south via the Alaska
Railroad to Anchorage for utilization in new 200 or 400 MW coal-fired
plants. This option is thought possible, but the economics of coal
transport at the necessary capacity via the existing rail system is in
question. Development at Beluga may also preclude this option.
B-2
Two potential developers have authorized studies of the Beluga coal dis-
trict to determine the economics and feasibility of extensive development.
Placer-Amex Incorporated has extensive holdings throughout the Beluga dis-
trict and Bass-Hunt-Wilson Venture has holdings in the Chuitna field.
(i) Placer-Amex Holdings
An extensive study of the potential of the Placer-Amex holdings was
completed in 1980 by the Alaska Division of Energy and Power Develop-
ment (16). This report summarizes the potential of development of the
Cook Inlet Region coal field. Several options were shown to exist for
development. The first option wquld be development by Beluga Coal
Company (a wholly owned subsidiary of Placer-Amex Inc.) within the
next two or three years. However, since most of the proposed project
output is exported, they cannot begin initiation until a firm market
is contracted for the coal. The second option is the construction of
a coal-fired generating plant by the Chugach Electric Association
(CEA). This option is dependent upon government mandated requests for
utilities to convert from natural gas to coal. The CEA has currently
no firm plans to construct such a plant.
Based on these two options, four possible levels of development at
Beluga are considered and were evaluated in the 1980 report noted
above.
-Low level of coal mining to supply local generating facilities.
Development could occur if the CEA is required by govenment mandate
to replace natural gas units with coal units. This scenario would
require moderate development of a work camp at Beluga, and would
include two 200 MW generators using approximately 1.5 million tons
per year. Construction would be during the period 1980 -1986.
-A sufficiently large (at least six million tons per year (MMTPY))
export market is developed and no generating stations are construc-
ted. This figure is considered the minimum amount necessary for
cost effective exporting. In this case, a permanent work camp would
be established similar to the first scenario. Exporting would begin
in 1990.
-Two 200 MW coal-fired generating plants and a six MMTPY coal export-
ing facility could justify the necessary front-end capital invest-
ment to establish a permanent community at Beluga. This would also
entail secondary economic development.
-There is a distinct possibility that no development of the Beluga
coal field will occur before 1990.
Export scenarios also include barging 3500 miles to Japan or 2100
miles to San Francisco and a slurry pipeline scheme to the Pacific
Northwest (28). Supplying Anchorage with coal via a new railroad tie
does not appear to be an option considered for the near future devel-
opment (28).
B-3
(ii) Bass-Hunt-Wilson Holdings
The study of the Beluga Coal Field potential at the Bass-Hunt-Wilson
(BHW) coal leases in the Chuitna River Field was completed by Bechtel
Corporation in April 1980 (27). This study resulted in a 7.7 MMTPY
economic export production rate with no consideration of local coal-
fired generating developments.
Potential export markets for Beluga coal as defined in the previous
section include the entire Lower 48 states or California, Pacific
Northwest and Japan markets. The average market price for coal in
California and the Pacific Northwest region, as reported in June, 1980
to the U.s. Department of Energy, ranged from $1. 55/MMBtu to
$1.46/MMBtu. These prices are slightly higher than the average U.S.
price. The costs of transporting Beluga mined coal to the Pacific
Northwest or to California were estimated in a 1977 Report on "Alaska
Coal and the Pacific.u (2) These prices were estimated and appear in
Table B.5.
The Beluga coal studies done for Placer-Amex and the Bass-Hunt-Wilson ven-
ture have resulted in opportunity costs for coal of $1.00 -$1.33/MMBtu.
For purposes of this study the value of $1.15/MMBtu will be used for
supplies to future coal-fired generating plants constructed in Alaska
(Table B.5).
A report issued in December, 1980 by Battelle Pacific Northwest Laboratory
(50) analyzed market opportunities for Beluga coal. Results reported in
this report were generally consistent with earlier Battelle and DOE
studies.
(b) Natural Gas
Natural gas resources available or potentially available to the Railbelt
region include the North Slope (Prudhoe Bay) reserves and the Cook Inlet
reserves. Information on these reserves is summarized in Table B.2.
The Prudhoe Bay Field contains the largest accumulation of oil and gas ever
discovered on the North American continent. The in-place gas volumes in
the field are estimated to be in excess of 40 trillion cubic feet (Tcf).
With losses considered, recoverable gas reserves are estimated at 29 Tcf.
Gas can be made available for sale from the Prudhoe Bay Field at a rate of
at least 2.0 billion cubic feet per day (Bcfd) and possibly slightly more
than 2.5 Bcfd. At this rate, gas deliveries can be sustained for 25 to 35
years, depending on the sales rate and ultimate gas recovery efficiency.
During the mid-seventies, three natural gas transport systems were proposed
to market natural gas from the North Slope Fields to the Lower 48 states.
Two overland pipeline routes (Alcan and Arctic) and a pipeline/LNG tanker
(El Paso) route were considered. The Alcan and Arctic pipeline routes
traversed Alaska and Canada for some 4000 to 5000 miles, terminating in the
central U.S. for distribution to points east and/or west. TheEl Paso
proposal involved an overland pipeline route that would generally follow
the Alyeska oil pipeline utility corridor for approximately 800 miles. A
liquefaction plant would process approximately 37 million cubic meters of
gas per day. The transfer station was proposed at Point Gravinia south of
the Valdez termination point. Eleven 165,000 cubic meter cryogenic tankers
would transport the LNG to Point Conception in California for
regasification.
The studies noted above have concluded with the initiation of a 4800 mile,
2.4 Bcfd, Alaska-Canada natural gas pipeline project, costing between $22
and $40 billion, expected to be operational by 1984-1985. The pipeline
project passes approximately 60 miles northeast of Fairbanks.
The Cook Inlet Reserves (Table B.2) are relatively small in comparison to
the North Slope reserves. Gas reserves are estimated at 4.2 Tcf as com-
pared to 29 Tcf in Prudhoe Bay. Of the 4.2 Tcf, approximately 3.5 Tcf is
available for use; the remaining reserves are considered shut-in at this
time. The gas production capability in the Kenai Peninsula and Cook Inlet
region far exceeds demand, as no major transportation system exists to ex-
port markets. As a result of this situation, the two Anchorage electric
utilities have a supply of natural gas at a very economic price. Export
facilities for Cook Inlet natural gas include one operating and one pro-
posed LNG scheme. The facility in operation, the Nikiski terminal, owned
and operated by Phillips-Marathon, is located on the eastern shore of Cook
Inlet. Two Liberian cryogenic tankers transport LNG some 4000 miles to
Japan. The volume produced is 185 MMCFD with raw natural gas requirements
of 70 percent from a platform in Cook Inlet and 30 percent from existing
onshore fields.
In 1979, the Pacific Alaska LNG Company (PALNG) proposed to ship LNG to
California from a terminal to be constructed at Nikiski on the Kenai Penin-
sula. This plant would ultimately process up to 430 MMCFD for shipment via
two cryogenic tankers to Little Cojo (near Point Conception), California.
The Federal Energy Regulatory Commission (FERC) has placed a rider on the
project permit, stipulating that in-place and committed gas reserves must
total 1.6 Tcf before a license is granted. 1o date PALNG estimates 1.0 Tcf
is in place.
There is also some potential for a gasline spur to be constructed from the
Cook Inlet region some 310 miles north to intersect with the Alaska-Canada
natural gas pipeline project in order to market the Cook Inlet gas. This
concept has not been extensively studied but could prove to be a viable
alternative.
Markets for Prudhoe Bay gas were not considered in developing a market
price for Railbelt fuel alternatives since an existing market and transpor-
tation system has been developed with the inception of the Alaska-Canada
pipeline project.
Markets for Cook Inlet gas include the Lower 48 states via two transporta-
tion modes: LNG tankers or a pipeline spur constructed from Anchorage to
Delta Junction and intersecting with the Alaska-Canada pipeline. The
regulated ceiling market price for natural gas on the west coast as
reported in the Federal Register, Department of Energy, Tuesday, October
27, 1980 was $4.89/MMBtu in the Region 10 area (Washington, Oregon,
California). The average reported U.S. price was $3.58/MMBtu. Shipment of
gas to these markets via the LNG tanker scheme as proposed by PALNG was
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was estimated to cost $2.50/MMBtu for transportation and processing.
Alternatively, the cost for shipment via a 310-mile pipeline spur from Cook
Inlet to the Al-Can pipeline was estimated (based on cost data available
from the current pipeline project) to be $1.97/MMBtu. This includes the
incremental cost of the Alaska-Canada pipeline ($1.27/MMBtu) and the cost
of the tap from Cook Inlet ($0.70/MMBtu). Table 8.5 lists the resulting
Alaskan opportunity values under these two assumptions for markets in
Region 10 and the Lower 48 states.
The current Japanese market price for natural gas sales from the Nikiski
LNG project is $4.50 to $4.65/MMBtu (46). Based on information collected
from Nikiski, transportation and processing costs were estimated to be
$3.00/MMBtu. This results in an Alaskan opportunity value of $1.50 to
$1. 65/MMBtu.
The resulting prices developed in these analyses range from $1.08 to
$2.92/MMBtu. For purposes of this study $2.00/MMBtu was adopted as the
opportunity value of natural gas in Alaska.
(c) Oil
Both the North Slope and the Cook Inlet Fields have significant quantities
of oil resources as seen in Table B.3. North Slope reserves are estimated
at 8375 million barrels. Oil reserves in the Cook Inlet region are esti-
mated at 198 million barrels (14). As of 1979, the bulk of Alaska crude
oil production (92.1 percent) came from Prudhoe Bay, with the remainder
from Cook Inlet. Net production in 1979 was 1.4 million barrels per day
( ll).
Oil resources from the Prudhoe Bay field are transported via the 800 mile
trans-Alaska pipeline at a rate of 1.2 million barrels per day. In excess
of 600 ships per year deliver oil from the port of Valdez to the west, Gulf
and east coasts of the u.s. Approximately 2 percent (or 10 million bar-
rels) of the Prudhoe Bay crude oil was used in Alaska refineries and along
the pipeline route to power pump stations (14). The North Pole Refinery,
located 14 miles southeast of Fairbanks, is supplied by the tra.ns-Alaska
pipeline via a spur. Refining capacity is around 25,000 barrels per day
with home heating oils, diesel and jet fuels the primary products.
Much of the installed generating capacity owned by Fairbanks• utilities is
fueled by oil. FMUS has 38.2 MW and GVEA has 186 t~W of oil-fired capacity.
Due to the high cost of oil, these utilities use available coal ired
capacity as much as possible with oil used as standby and for peaking
purposes.
Crude oil from offshore and onshore Kenai oil fields is refined at Kenai,
primarily for use in-state. Thermal generating stations in Anchorage rely
on oil as standby fuel only.
Since the installation of the Alyeska oil pipeline, which has made Alaskan
oil marketable, the opportunity cost of oil to Alaska has been the existing
market price. Contracts for oil to utilities have ranged from $3.45/MMBtu
to $4.01/MMBtu as reported to FERC. For purposes of the generation
B-6
expansion study, where oil is considered only available for standby units,
the price adopted for use is $4.00/MMBtu (Table 8.5).
8.2 -Thermal Generating Options -Characteristics and Costs
The analysis of thermal generating resources available to meet future Railbelt
needs requires the detailed determination of existing generating capacity, its
use, condition and planned retirement policy in addition to committed thermal
plant expansions. Of the 943.6 MW of existing (1980) capacity in the Railbelt
region, 95 percent of capacity relies on fossil fuels (Table B.6). A summary of
capacity by unit type is given in Table 8.7.
By far the most important thermal generating resources available to the Railbelt
in 1980, are the natural gas-fired gas turbines in the Anchorage/Cook Inlet re-
gion (Table B.7). The recent trend of both Anchorage Municipal Light and Power
Department (AMLPD) and the CEA has been to meet future generating needs using
combined cycle additions to existing gas turbine units. This ongoing trend is
illustrated by the anticipated expansion of CEA•s system with the Beluga No. 8
unit (60 MW) and the most recent AMLPD expansion of unit No. 6 at their
George M. Sullivan Plant. These units all rely on locally contracted Cook Inlet
natural gas for generation.
Oil-fired generation by gas turbines is generally confined to the Fairbanks re-
gion with units owned and operated by GVEA and FMUS. In addition, these two
utilities own and operate the 54 MW of coal-fired steam capacity using Healy
coal. Small diesel units are used for peaking and standby service in the Fair-
banks region. ·
The capital costs for four different types of thermal generating plants consid-
ered available to the Railbelt region were estimated. Capital cost estimates
for coal-fired steam, combined cycle, gas turbines and diesels appear in Tables
B.8 to B.l3. Table 8.13 summarizes the generation parameters necessary for the
production cost model in the generation planning studies described in Section
8.
Capital costs for new fossil (coal) thermal plant alternatives are an input to
any generation planning study. The development of capital cost estimates of
high accuracy generally consumes substantial time and effort for a single plant
design at a specified location. The development of detailed cost estimates for
numerous plant types at non-specific locations to be selected at some future
time would be a formidable task. The approach taken in this study has been to
develop generic coal-fired plant cost estimates, largely based upon published
Lower 48 states• cost data, previous studies of A+askan construction cost di
ferentials, and recent Alaskan construction experiences.
Gas turbine combined cycle and diesel plants are typically modularized units,
with major cost variations largely tied to specified site conditions or restric-
tions. Costs used.for these items were based on manufacturer supplied informa-
tion and published bid information for units to be installed in the Railbelt re-
gion.
B-7
(a) Coal-Fired Steam
As previously mentioned there are currently four coal-fired steam plants in
operation. The 29 MW Chena unit is operated by FMUS and another 25 MW
plant is operated by GVEA at Healy. Two more coal units, with a total
capacity of 6 MW, supply Fort Wainwright and the University of Alaska at
Fairbanks with heat and electric power. These two units supply FMUS on a
contractual basis, when available. All of these plants are small in
comparison to new electric utility units typically under consideration in
the Lower 48 states. Up-to-date cost comparisons for potential new
installations in Alaska were therefore difficult.
Other factors that have been considered in developing costs for new instal-
lations include:
Large, new coal-fired plants will require extensive emission control
equipment to meet current EPA emission standards
-Larger plants involve longer construction periods
-Current high interest and escalation rates have driven costs of new
plants to much higher levels than previously experienced
(i) Deviation of Plant Costs
Based on projected Alaskan plant capacity additions developed in previous
studies, coal-fired unit sizes of 100, 250, and 500 MW were considered for
capacity additions. It is unlikely that a 500 MW plant would be proposed
for local supply to either Anchorage or Fairbanks due to limited power de-
mand and fuel transportation capacity. The remoteness of Fairbanks also
possibly precludes the use of 500 MW plants. However, installation of such
a plant as a baseload unit, perhaps in the Beluga coal field region, to
feed an integrated utility grid is a possibility. Since typical plant unit
sizes required in Alaska are substantially smaller than those typical of
the Lower 48 states, previous studies have therefore incorporated relation-
ships for economy of scale, based upon Lower 48 data (3,17). The regional
differences in Alaskan construction costs can also be substantial, with the
result that Alaskan location adjustment factors have also been used in
these recent studies (3). Cost differences may be due to transportation
requirements, labor costs, climate, and distance from equipment supplies.
A review of Alaskan construction cost location adjustment factors was
undertaken by Battelle in March 1978 (3). These adjustment factors, iden-
tified for different locations in the Railbelt, ranged from 1.35 to 1.7 for
Anchorage, 1.8 to 2.75 for Beluga, and 2.20 to 2.42 for the Healy/Nenana/
Fairbanks area. The factors finally adopted by Battelle for their study
were 1.65, 1.80 and 2.20 for Anchorage, Beluga and the Healy-Fairbanks
area, respectively. The Battelle study included a review of material cost
additions due to transportation and labor cost variations due to lack of
developed social infrastructure in many areas in the state.
The Battelle study examined the Beluga coal fields as a power plant site.
Particular attention was paid to the variation in costs associated with
B-8
development of a largely uninhabited area. Land was considered to be lower
in cost than in other regions, and the site favored use of preassembled
p 1 ant modu 1 es barged to the site; both items produced cost reductions.
Cost increases resulted from construction of worker towns and transport of
equipment, food, fuel and other supplies.
In the Healy area, modularized construction of large units would not be
possible since transportation opportunities are limited to the ability of
Alaskan railroads to carry large loads. Therefore, the net effect on the
adjustment factor is increased.
There is a significant amount of uncertainty regarding the use of Alaskan
location adjustment factors derived in previous studies. ·Consequently,
attempts were made to cross check the validity of the Battelle factors with
independent development of costs for ongoing Alaskan projects and evalua-
tion of the Battelle sources whenever possible.
Capacity scaling factors, as used by EPRI and Battelle in previous studies,
extrapolate costs of larger units (500-1000 MW) to smaller units (100-500
MW). Under this procedure, the cost of a smaller unit can be computed
given the cost of a larger unit and an exponential scaling factor. This
procedure, exercised with caution over no more than a tenfold range of cap-
acity, can produce preliminary figures for cost comparison. Battelle, in
their study of Alaskan electric power, used capacity scaling factors of
0.85 in the 200-1000 MW range and 0.60 in the 100-200 MW range (3). Recog-
nizing the inaccuracies associated with using capacity scaling factors, the
use of the exponent approach was limited and was reviewed for consistency
once applied. A further check was made by means of cost sensitivity
assessments in generation planning studies (Section 8).
(ii) Basis of Plant Cost Estimates
The coal-fired plant cost estimates developed for input into thermal gener-
ating options were based on an EPRI document number AF-342, prepared by
Bechtel (17). This report extensively details the costs of 1000 MW coal
plants in various Lower 48 locations. The baseline plant, used to develop
Alaskan costs, was designed for a remote location in Oregon with maximum
environmental controls. This plant used Wyoming coals which have similar
characteristics to Alaskan coals.
The cost estimates were based on the following design assumptions:
-The plant location assumes both make-up water and rail access available,
but at some distance from the site.
A river intake and pumping plant would supply raw river water to a surge
pond through a thirteen-mile long pipeline.
-Coal would be rail delivered by unit train in open gondola cars for
rotary dump service.
B-9
The plant design has assumed to include the following systems:
-Coal handling system
-Auxiliary boiler system
-Raw water supply system
-Fire protection system
-Plant rain run-off system
-Light oil supply system
-Heating and ventilating system
-Boiler system
-Turbine generator system
-Condensate system
-Extraction steam system
-Main steam and reheat system
-Circulating water and cooling tower system
-Rain water system
-Chemical treatment
-Ash handling
-Waste water disposal
-Air quality control
The air quality control system is designed to control sulphur dioxide emis-
sions and particulates. This system was considered particularly important
due to the air quality of the Alaskan environment.
The switchyard cost includes:
-Circuit breakers
-Disconnect switches
-Line traps
-Potential devices
-Lightning arresters
-Foundations
-Control buildings
-Supporting structures
-Take-off towers
-Single aluminum bus-single breaker scheme with bus sectionalizing break-
ers of 345 kV
-Two start-up transformers
Emergency power supply (low voltage)
In the EPRI baseline design, water from the condensors would be cooled in
two mechanical draft cooling towers, with make-up water coming by pipeline.
There is, of course, the potential for open cycle cooling using a cooling
pond which offers a potential cost savings. However, due to the scope of
this study, this was not investigated. The use of natural waterbodies for
once-through cooling is generally cheaper than cooling towers. However,
due to environmental constraints, this cooling method is restricted.
Site access costs included in the EPRI plant design were based upon are-
mote area; accessories included 15 miles of railroad and switching station,
and 13 miles of water pipeline. This would adequately represent a remote
development in the Beluga area.
B-10
Table B.6 summarizes the cost estimate of the EPRI plant in 1976. The cost
in 1976 dollars for a 1000 MW plant was determined to be $566.6 million.
(iii) Cost Adjustments
Updated costs for 1980 were developed using the Handy-Whitman indices (54).
The Handy-Whitman indices are widely used for cost updating. They are
developed bi-annually by Whitman-Requardt and Associates and are based on
extensive utility plant cost research in each of six regions of the United
States. The Handy-Whitman indices used for this study are for the Region 6
-Pacific Northwest area. They are represented as a ratio of the January
1, 1980 dollar values to the January 1, 1976 dollar values for a variety of
plant cost estimates. The 1976 cost was therefore updated to give a 1980
dollar cost of $792 million. This cost represents the cost of a 1000 MW
plant in the Lower 48 and therefore is required to be scaled to reflect the
cost of a unit size applicable to the Railbelt region.
Two methods were considered in scaling the cost. The first was developed
from EPRI research which reported that approximately·54 percent of the
total construction cost was attributable to the first unit (17). The cost
of a single 500 MW unit would thus be 54 percent of the cost of a 1000 MW
plant, or $428 million. The capacity scaling equation used was:
Cost of Unit A
Cost of Unit B
(Capability of Unit A) exponent
(Capability of Unit B)
This equation was solved for the exponent by substituting the various costs
and capabilities. This yielded a value of 0.89 which is substantially
greater than the usual 0.6 value. However, as discussed in an article on
the subject of computing economy of scale values (51), inflation, high in-
terest rates and lengthened schedules have negated to a large degree the
0.6 economy of scale and brought the exponent up to values of 0.79 to 0.86.
This compares favorably to the 0.85 value obtained in analyses conducted by
Battelle for 200 to 500 MW units. It is assumed that the 0.85 value used
by Battelle in previous studies is an accurate representation of the cur-
rent economY of scale in power plant estimation. Consequently, this value
was used for the plant costs in this study. Tables B.8, B.9 and B.lO
reflect this application. For the 100 MW plant the scaling factor used was
0.85 rather than the 0.60 suggested by Battelle for plants in the 100 to
200 MW range. Applying the 0.85 factor results in a more conservative
figure for the 100 MW plant by almost $90 million dollars ($111 vs $199
million).
The application of the established Lower 48 cost to the Railbelt situation
must take into account a variety of other factors. Short-term additions to
existing coal-fired plants are a viable possibility for extension of Rail-
belt generation capability. Ongoing studies in the Fairbanks region to
expand existing coal-fired capacity for electricity and district heating,
although for a smaller plant capacity than the 100 MW considered here, have
shown the cost of new mechanical equipment alone to be approximately 1.77
times more compared to a similar installation in the Lower 48. This
result, in addition to research by the U.S. Army Corp of Engineers and
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Battelle, indicates increases in Lower 48 plant costs in the range of 1.2
to 2.65 for the Railbelt. Additionally, due to the limitations of most
optimized production cost models, allowance is made for a number of future
size additions; however, the additions are site-constricted, allowing no
variability in capital cost versus site conditions.
Reviewing the long-term coal production and use potential in the Railbelt
indicates that large scale development at Beluga is a good possibility.
This development would entail export operations and local generation usage.
Therefore, to develop and represent to a production cost model an indica-
tion of likely site development and cost, the Lower 48 capital costs were
adjusted to represent a Beluga-sited development. This representation in
no way disallows the possibility of expansion or even small scale develop-
ment of coal potential at other Railbelt locations. It does, however,
serve to represent an overall Railbelt coal potential cost for a remote
Alaskan situation. The Beluga cost figures shown in Tables B.8 to B.10 re-
flect a 1.8 Alaskan adjustment factor, which represents the middle range of
all Railbelt estimates and is similar to the developed Beluga factor
reported by Battelle (3).
In addition to the direct costs shown in Tables B.8, B.9 and B.10, a con-
tingency of 16 percent, 10 percent for utilities and other construction
facilities and 12 percent for engineering and administration was added.
Interest of 3 percent, net of escalation, during the construction period of
six years for the 500 and 250 MW plants and five years for the 100 MW plant
would be an added cost.
(iv) Operating Characteristics
Coal-fired plant operating characteristics which are incorporated in the
generation planning analysis are heat rate, unit availability and operation
and maintenance costs. The heat rate selected for the three plant sizes is
10,500 Btu/kWh, which is consistent with the EPRI plant design.
Outages for coal-fired steam plants are taken into account in terms of
scheduled (planned) and forced outages as a percent of time. Data publish-
ed by the Edison Electric Institute (EEI) indicates a forced outage of ap-
proximately 5.4 percent for large coal-fired plants (41). This figure was
rounded to 5 percent to represent forced outages for study purposes. Sche-
duled outages, as reported by GVEA for their Healy plant, are in the 5.1 to
16.3 percent range. An average of 11 percent, which also correlates with
the EEI data, was adopted as the scheduled outage rate for coal-fired
plants for this study. The parameters given above for thermal generating
plants are given in Table B.13.
Operation and maintenance (O&M) costs for use in generation planning are
divided into two components: fixed costs and variable costs (exclusive of
fuel). Fixed O&M costs for typical U.S. plants are reported periodically
in the DOE publication, Steam Plant Construction and Annual Production
Expenses (21). Trends indicated in these reports led to adoption of values
for fixed cost of 0.50, 1.05 and 1.30 $yr/kw for 500 ~lW, 250 MW and 100 MW
plants respectively. Variable costs in the DOE publication (21) are shown
to decrease with increasing unit size. The values used in this study are
$1.40, $1.80 and $2.20/yr/kW for 500 MW, 250 MW and 100 MW plants
respectively.
B-12
(b) Combined Cycle
A number of factors have recently led to an increased interest in combined
cycle generating plants, both in the Lower 48 and Alaska. These factors
include rising fuel prices, increasing environmental requirements and
greater flexibility for mid-and base-load applications dictated by chang-
ing system load requirements. These conditions have prompted two Anchorage
utilities, AMLPD and CEA, to look to combined cycle generation to meet
their needs.
Presently there are two combined cycle plants in operation in Alaska. An
operational unit, known as the G.M. Sullivan plant and owned by AMLPD, con-
sists of three units which, when operating in tandem, produce a net capa-
city of 140.9 MW. Another plant under construction for CEA and known as
Beluga No. 9 unit will add a 60 MW steam turbine to the system sometime in
1982. These two units represent expansions to existing gas-turbine plants
and are considered to be essentially short-term generation planning commit-
ments for the Railbelt. For the longer term, a unit capacity of 250 MW for
ne~J combined cycle plants was considered to be representative of potential
future additions in the Railbelt area. This assumption is based on trends
in the Lower 48 and load growth projections in Alaska. A heat rate of 8500
Btu/kWh was adopted based on Alaskan experience. The EPRI report AF-610
(18), was used as the basis of cost estimates for this type of plant.
A substantial quantity of natural gas could be available to utilities with
the implementation of the Alaskan Natural Gas Pipeline. However, construc-
tion of a natural gas pipeline spur to supply combined-cycle installations
in the Railbelt region is not likely during the critical study planning
period of 1990-1995. All generating resources in Fairbanks are currently
fueled with coal or oil. In addition, despite the close proximity of the
Beluga region to the Cook Inlet gas reserves, development at Beluga would
not be predicated on combined cycle plants. Therefore, the potential
installation of combined cycle plants will most likely be limited to the
Anchorage area. This premise is based on the local electric utilities•
most recent generation expansion programs and readily available Cook Inlet
natural gas.
Recent experience in combined cycle construction in Alaska has been limited
to small expansions of existing facilities. For purposes of this study, it
was therefore necessary to rely on Lower 48 cost estimates for larger in-
stallations, extrapolated to apply to Alaska conditions.
Lov1er 48 costs for 250 MW combined cycle generating units are given in
Table B.13. Ttlese costs were obtained from General Electric Corporation in
1980 dollars. Estimates were made for costs of foundations and buildings,
fuel handling facilities and other mechanical and electrical equipment. An
additional cost of 25 percent of the cost of the generating equipment has
been included for transportation of the basic unit to the Pacific
NorthvJest. These costs were compared to prior cost estimates of combined
cycle power plants in EPRI-AF-610 and were found to be consistent. Using
an Alaskan location adjustment factor of 1.6 recommended by Battelle (3),
the account items were adjusted for a plant located in the Anchorage area.
Transportation to Anchorage was assumed to be 25 percent more than to the
Pacific Northwest coast. This may be slightly high for transportation
costs to Alaska, hmvever, considering limited navigation periods and size
B-13
size of the 250 MW units, it is believed to be a reasonable assumption and
within limits of accuracy for study cost estimates. As for coal-fired
plants, indirect costs of 16 percent for contingency, 10 percent for
construction facilities and utilities, and 12 percent for engineering and
administration were added to the directed cost.
Table B.13 summarizes the results of these estimates. Allowance for funds
during construction (AFDC) for these years is included in this total. Op-
eration and maintenance (O&M) costs for large combined cycle plants, as re-
ported in EPRl, AF-610 {18) approximate $2.75/yr/kW for fixed O&M and
$0.30/MWh for variable O&M. These were adopted for Alaskan application.
Based on information provided by AMLPD for their G.M. Sullivan combined
cycle plant, scheduled outage rates are approximately 11 percent. For a
larger plant of 250 MW, based on EEl data, a 14 percent scheduled outage
rate was selected. A forced outage rate of 6 percent was also considered
appropriate based on the AMLPD and EEl data. The combined-cycle plant par-
ameters are summarized in Table B.13.
(c) Gas Turbines
Gas turbines are by far the main source of thermal power generating re-
sources in the Railbelt area at the present time. There are 470.5 MW of
installed gas turbines operating on natural gas in the Anchorage area and
approximately 168.3 MW of oil-fired gas turbines in the Fairbanks area
(Table B.7). Low initial cost and simplicity of construction and operation
in addition to available low cost gas have made gas turbines very attrac-
tive as a Railbelt generating scource. New oil-fired gas turbines were not
considered in this study primarily because of the price of distillate.
This price has been historically higher than natural gas and is expected to
remain so.
A unit size of 75 MW was considered to be representative of a modern gas
turbine plant addition to the Railbelt system. The possibility of install-
ing gas turbine units at Beluga was not considered, as this development is
intended primarily for coal. Coal conversion to methanol is a possibility;
but this consideration is beyond the scope of this study.
The gas turbine plants are assumed to have a two-year construction period
(22). The base plant costs were obtained from the Gas Turbine Horld Hand-
book (19), which lists "turnkey" bids in 1978 dollars for a gas turbine
project in Anchorage. These estimates are quoted in Table B.14. These es-
timates had an estimated heat rate of 12,000 Btu/kWh. The costs were esca-
lated by 13.7 percent using the developed Handy-Whitman indices to January,
1980 dollars. A 10 percent increase was included for construction facili-
ties and utilities as well as a 14 percent engineering and administration
fee (Table B.15). The resultant cost of $25.80 million (excluding AFDC)
was considered representative of the cost of gas turbine construction re-
gardless of location within the Railbelt. Potentially higher cost could,
however, be incurred for remote Alaskan locations.
Operation and maintenance (O&M) costs adopted are $2.50/yr/kW and $0.30/MWh
for the fixed and variable components. These values reflect intermediate
levels of O&M costs in the FMUS/GVEA Unit Study (32).
B-14
Three sources of data were consulted for planned and forced outages of gas
turbine units; the EEI report and information from AMLPD and GVEA. Sche-
duled outage rates of 11 to 12 percent and forced outage rates of 3.8 per-
cent appear to be valid in the Alaska area. Gas-turbine parameters are
given in Table B.12.
(d) Diesels
Most diesel plants in operation today are standby units or peaking genera-
tion equipment. Nearly all the continuous duty units have been placed on
standby service for several years due to the high oil prices and the conse-
quent high cost of operation. The lack of system interconnection and the
remote nature of localized village load centers has required the installa-
tion of many small diesel units. The installed capacity of these diesel
units is 64.9 MW, and these units are solely used for load following. The
high cost of diesel fuel makes new diesel plants expensive investments for
all but emergency use.
A unit size of 10 MW was selected to represent an addition of a small
amount of standby capacity in the Alaskan Railbelt. To develop a capital
cost of these units, three manufacturers 1 quotes for generating units were
obtained:
Six 16 cylinder units totalling 10,685 kW at 900 RPM at $5,050,000
F.O.B. Additional costs would be incurred for transportation to Alaska
(10 percent of generating units), controls and buildings/site ~evelop
ment.
- A four unit (2500 kW/unit) diesel generating plant at $3,000,000 F.O.B.
A $10,000/unit transportation cost to Alaska was suggested as well as
additional costs for pre-engineered building, foundations, controls and
electrical equipment.
-Ten 100 kW units plus two for continuous duty, each unit costing
$150,000, giving a total cost for 12 units of $1,800,000 F.O.B. A
$5,000/unit transportation cost was assessed and additional costs for
mechanical controls.
Also added to the cost of the generating units are auxiliary mechanical and
fuel handling equipment and electrical system/switchyard costs.
A construction period of one year was assumed since these plants are modu-
lar and quick to assemble. In addition, contingencies (16 percent), con-
struction facilities and utilities (10 percent), engineering and adminis-
tration (14 percent) are added to costs. An average cost of $7.67 million
1980 dollars (excluding AFDC) was adopted and used for the entire Railbelt
region regardless of location based on the modular and rapid construction
techniques associated with these small diesel units.
Diesel O&M costs quoted in the Williams Brothers Report for GVEA and FMUS
(32) are considered typical for small diesel units operating in Alaska.
Fixed costs of $0.50/yr/kW and $5.00/MWh for variable costs are used in
this study.
B-15
Diesel units have a low (1 percent) scheduled outage rate. This rate is
based on I utility experience. However, the EEI data correspond to units
in locations where parts and service are for the most part readily avail-
able. Canadian Electrical Associates data for remote isolated units with
difficult access for parts and service are far worse. Alaska could be
somewhere between these extremes, with heavy dependence on unit manufac-
turers and location giving forced outages rates of between 4.0 -5.0
percent. Consequently, a 5 percent rate was adopted for the system
planning study. Diesel parameters are summarized in Table B.l2.
B.3 -Environmental Considerations
The investigation of thermal alternatives for inclusion 1n proposed generation
expansion sequences dealt with generic plant types which were generally not site
specific. The underlying assumption for input was that environmentally accept-
able sites could be found within the Railbelt region. Thus, the concern add-
ressed was the identification of major cost items incurred by necessary environ-
mental protection measures.
The major environmental protection cost component of coal-fired, gas turbine,
combined cycle, and diesel units will be that required for air pollution control
to meet the National New Source Performance Standards (NSPS).
Siting of thermal plants in the Railbelt region may be limited by the Prevention
of Significant Deterioration (PSD) standards for Class I, II, and III airsheds.
Plants located near National Parks which are designated Class I will be subject
to the scrutiny of the effects of its emissions on visibility and air quality
within ~he park. Class II areas that are not presently in compliance with one
or more of the ambient air quality standards (Anchorage and Fairbanks) or that
are close to exceeding the PSD increment for the airshed (such as Valdez) may
not be acceptable sites for thermal plants.
Other environmental controls, such as those required for water use, effluent
discharge, solid waste disposal, noise control and construction activities, are
important with respect to the present quality of the Alaskan environment. These
factors, although not significant at this time for cost estimating purposes,
would have to be considered in the evaluation of any plant siting.
(a) Air Quality Requirements
The cost of air pollution control equipment is based on satisfaction of the
national NSPS and National Ambient Air Quality Standards (NAAllS) (36). It
is assumed that compliance with NSPS and NAAQS for the final site selection
for specific facilities will assure compliance with the Prevention of Sig-
nificant Deterioration (PSD) aspects of air quality regulation. The State
of Alaska has adopted the National Ambient Air Quality Standards, with ad-
dition of a standard for reduced sulfur compounds (36,37). The State may
also require measures for control of ice fog (38).
Three New Source Performance Standards cover the plant types under consid-
eration. The NSPS for Electric Utility Steam Generating Units is applic-
able to coal-fired steam units. Specific standards are set for control of
sulfur dioxide (S02), particulate, and nitrogen oxides (NOx). For the
coal-fired units, the use of highly efficient combustion technology is
B-16
accepted for control of NOX. Flue gas desulfurization is required for
so 2 removal, and dry scrubber technology is recommended by EPA for use
with low sulfur fuel. Low sulfur fuel is generally considered to have a
sulfur content less than 3 lb/million BTU or less than approximately 1.5
percent sulfur by weight in coal. Typical Alaskan coals have sulfur con-
tents of around 1.5 percent by weight. Dry technology is appropriate also
for reduction of potential ice fog problems. Baghouses are preferred by
EPA for removal of particulates in facilities burning low sulfur fuel.
Pollution control for gas turbine units and for combined cycle units burn-
ing gas is designated by the New Source Performance Standards for gas tur-
bines. Installation of gas turbine units requires wet control technology
such as water or steam injection for control of NOx emissions. Turbines
using the injection process, however, are exempt from meeting the NOx
emissions standards during periods when ice fog is deemed a traffic hazard.
S02 emissions are limited by limitations on fuel sulful content. NSPS
for Stationary Internal Combustion Engines which apply to the proposed die-
sel units require NOx control. Reduction of NOx emissions will be
achieved by an efficient fuel injection process.
New pollution sources must meet the PSD requirements for Class I, II, and
III airsheds (39). Most areas of the state are designated Class II areas
(40) in which implementation of NSPS technologies will be sufficient to
satisfy the PSD increment. There are several exceptions to this status
( 40).
Mt. McKinley National Park is designated as a Class I area. A plant locat-
ed in the vicinity of the Park would be subject to the restrictions based
on the effects of its emissions on visibility and air quality within the
park. Anchorage and Fairbanks -North Pole urban areas are presently the
only Class II areas not in compliance with one or more of ambient air qual-
ity standards. Valdez is close to exceeding the POS increment allowed for
the airstand.
Compliance with stricter regulations in any of these sensitive areas could
incur higher pollution control costs, or could effectively result in barr-
ing the development of a thermal plant in that area. It is likely that new
thermal plants will not be located in these areas if the cost of additional
pollution control equipment substantially affects the cost of energy sup-
plied to the consumer. These siting limitations, however, barely limit the
number of possible plant locations within the Railbelt. Therefore, ·the as-
sumption of compliance with NSPS is believed to be appropriate for deriva-
tion of air pollution control costs.
(b) Other Requirements
The costs for other environmental controls were also included in cost esti-
mates. These controls are mandated by national and state water discharge
standards, solid waste disposal standards and occupational health and
safety standards. These controls will have the greatest relative impact on
the cost of coal-fired plants compared to the other thermal plant types.
This is due to the large permanent staff required at coal plants for coal
handling and plant operations and maintenance, and to the treatment facili-
ties required for flue gas desulfurization wastes. However, compared to
the costs of air pollution control, these costs are of minor significance.
B-17
LIST OF REFERENCES
(1) Abegg, F. "Burning Coal in Alaska - A Winter Experience", ASME, 1980.
(2) Alaskan Department of Commerce and Economic Development, Alaska Coal and
the Pacific, Juneau, Alaska, September, 1977.
(3) Battelle Pacific Northwest Laboratories, Alaskan Electric Power; An
Analysis of Future Requirements and Supply Alternatives for the Railbelt
Region, March, 1978.
( 4) Engineering News Record, "Construction is Underway on A 1 aska-Canada
Gasline", August 21, 1980, P. 18.
(5) Erickson, Gregg and Boness, Frederick. Alaska Coal and Alaska Power
Alternatives for the Railbelt, May, 1980.
(6) Executive Office of the President, Energy Policy and Planning, Decision and
Report to Congress on the Alaska Natural Gas Transportation System,
September, 1977.
(7) ICF Incorporated. A Review of Alaska Natural Gas Transportation System
Issues; FERC, EJ-78-C-01-6395, May, 1979.
(8) Jensen Associates Inc. "The Market Outlook for Alaskan Natural Gas,u
September, 1979.
(9) u.s. Department of Energy, Cost and Quality of Fuels for Electric Utility
Plants. FPC Form NO. 423, DOE/EIA-0075 (80/04), June 1, 1980.
(10) u.s. Department of Energy, "Recommendation to the President on ANGTS,"
May 1, 1977.
(11) The Alaska Economy Year-End Performance Report, Alaska Department of
Commerce and Economic Development, 1979.
(12) Alaska Oil and Gas Conservation Commission Statistical Report, 1978.
(13) State of Alaska, Department of Natural Resources, Division of Minerals and
Energy Management, "Historic and Projected Demand for Oil and Gas in Alaska
1972-1995,11 April, 1977.
(14) The Energy Report, Vol. No. 3, Fairbanks North Star Borough, Community
Information Center, September, 1980.
(15) Rao, P.D. and Wolff, Ernest N., "Characterization and Evaluation of
Washability of Alaskan Coals." University of Fairbanks for DOE Grant No.
G0166212, May, 1978.
B-18
LIST OF REFERENCES (Cont'd)
(16) u.s. Department of Energy, Office of Environmental Assessments, Division of
Energy and Power. Alaska Regional Energy Resources Planning Project, Phase
2, Coal, Hydroelectric and Energy Alternatives; Volume 1 Beluga Coal
District Analysis. Prepared by Alaska Department of Commerce and Economic
Development, 1980.
(17) Coal-Fired Power Plant Capital Cost Estimates -EPRI AF-342 (SOA 76-329
Final Report, December, 1977.
(18) Combined Cycle Power Plant Capital Cost Estimates -EPRI AF-610 (SOA
77-402) Final Report, December, 1977.
(19) Gas Turbine World Handbook -1978, Pequot Pub. Vol. 4, 1979-80.
(20) 1978 Fairbanks Energy Inventory -Community Information Center Special
Report No. 4, Fairbanks North Star Borough, July, 1979.
(21) U.S. Department of Energy, Steam-Electric Plant Construction Cost and
Annual Production Expenses 1976, August, 1978.
(22) u.s. Department of Energy, Gas Turbine Electric Plant Construction Cost and
Annual Production Expenses-1976, EIA-0180, April, 1979.
(23) Phung, Doar L., A Method for Estimatin Escalation and Interest Durin
Construction EDC & IDC. ORAU/IEA-78-6 M, April, 1978.
(24) Electrical World Directory of Electric Utilities-1979-80 87th Edition.
(26) Personal communication, re: Susitna Hydroelectric Project -Task 6, Cost
Estimating. September, 1980.
(27) Bechtel Corporation, Executive Summary, Preliminary Feasibility Study, Coal
Export Program, Bass-Hunt-Wilson Coal Leases, Chuitna River Field, Alaska.
April, 1980.
(28) Hennigan, Brian D., Cook Inlet Coal: Economics of Mining and Marine Slurry
Transport, Masters Thesis, University of Washington, Seattle, Washington,
1977.
(29) Olsen, Marvin, et al., 1979. Beluga Coal Field Development: Social
Effects and Management Alternatives. Prepared for Alaska Division of
Energy and Power Development, Department of Commerce and Economic
Development, Anchorage, Alaska and the u.s. Department of Energy, Office of
Technology Impacts, Regional Assessment Division, Washington, D.C. by
Pacific Northwest Laboratory, Richland, Washington, Battelle Human Affairs
Research Centers, Seattle, Washington, and CH2M Hill, Anchorage, Alaska.
PNL-RAP-29 UC-11.
B-19
LIST OF REFERENCES (Cont'd)
{30) Battelle Pacific Northwest Laboratory, Oraft Final Report, eeluga Coal
l"larket Studies, for the State of Alaska, Office of the Governor, Division
of Policy Development and Planning, September, 1980.
{31) Federal Energy Regulatory Commission (FERC) Form No. 12, Power System
Statements for (a) Anchorage fvfunicipal Light and Power Department (AMLU),
(b) Chugach Electric Association (CEA), (c) Fairbanks Municipal Utility
Systems {FMUS), {d) Homer Electric Association (HEA), and (e) Golden Valley
Electric Association (GVEA), December 31, 1979.
( 32) Willi am tkothers Engineering Company, Report on FIVJUS and GVEA Systems,
1978.
{33) Al~ska Department of Revenue, Petroleum Revenue Division, Petroleum
Production Revenue Forecast, Quarterly Report, March, 1980.
(34) Alcan Pipeline Company, Alcan Pipeline Project, 48-Inch Alternative
Proposal, March, 1977.
(35) Markle, Donald, of OIT Geo-Heat Utilization Center, Geothermal Energy in
Alaska: Site Data Base and Development Status, for the U.S. Department of
Energy, April, 1979.
(36) The Bureau of National Affairs (BNA), Incorporated, BNA Policy and Practice
Series; Air Pollution Control, Section 101; Ambient Air Quality Standards,
Section 111; State Policies, Section 121, New Source Performance Standards,
copyright 1980.
( 37) State of Alaska, Alaska Administrative Code, Title 19, Cnapter 50.050(d).
(38) State of Alaska, Alaska Administrati Title 18, Chapter 50.090, Ice
Fog Limitations.
(39) State of Alaska, Alaska Administrative Code Title 18, Chapter 50.020,
Ambient Air Qual s.
(40) State of Alaska, Alaska Administrative Code, Title 18, Chapter 50. u21,
State Air wuality Classifications.
(41) Edison Electric Institute (tEl), "Report on Equipment Availability for the
10-year Period 1968-1978", 1979.
(42) Personal communication with Mr. Hank Nichols of Anchorage Municipal Light
and Power Department, September, 1980.
(43) Personal communication with Mr. Larry Colp of Fairbanks Municipal Utilities
System, September, 1980.
B-20
LIST OF REFERENCES (Cont 1 d)
(44) Personal communication with Mr. Woody Baker, Golden Valley Electric
Association Production Superintendent, September, 1980.
(45) u.s. Department of Energy, Office of Conservation and Solar Energy, Federal
Energy Management and Planning Programs; Methodology and Procedures for
Life Cycle Cost Analyses Average Fuel Costs, The Federal Register, Tuesday,
October 7, 1980.
(46) Personal communication with Dr. Charles Logsdan, Alaska State Department of
Revenue, December, 1980.
( 47) Persona 1 communication with Mr. Schandl er of Superior Products,
Springfield, Ohio, September, 1980.
(48) Personal communication with Belyea Company, Jersey City, New Jersey,
September, 1980.
(49) Personal communication with Mr. Marshall of Cummins International Diesel,
Baltimore, Maryland, September, 1980.
(50) Battelle Pacific Northwest Laboratory, Beluga Coal Market Study for the
State of Alaska, Office of the Governor, December, 1980.
(51) Comtois, Wilfred H., 11 Economy of Scale in Power Plants .. , Power Engineering,
August, 1977, p. 51-53.
(52) Budwani, Ramesh N., 11 Power Plant Capital Cost Analysis .. , Power Engineering,
May, 1980, p. 62-70.
(53) Battelle Pacific Northwest Labortory, Cook Inlet Natural Gas; Future
Availability and Price Forecasts for the State of Alaska, Office of the
Governor, February, 1981.
(54) Handy-Whitman, Cost Index for Hydropower Production in the Pacific
Northwest, 1978.
B-21
Table B.1 -ALASKAN RAILBELT COAL DATA1
"' % ., "' Value IV
"' "' "' ,.
ASTM million Moisture Volatile Fixed Ash Btu/lb IV IY IY IV Sulfur "' "' "' "' Coal Field Rank tons (range) Matter Carbon (range) (range) c H N 0 (range)
Beluga 2400 (12-33) (3-25) (7200-(0.2)
8900)
Water Fall Sub Bit C 20.56 36.62 34.68 8.14 8,665 49.9 6.0 0.56 35.2 0.15
Yentna #2 Lower Lignite 29.80 38.26 28.61 3.33 7,943 45.2 6.8 0.53 44.1 0.11
Kenai Cabin Sub Bit C 23.01 35.63 32.71 8.65 8,028 47.2 6.1 0.62 37.2 0.23
Nenana Sub Bit 2000 (11-27) (3-13) (7500-(0.1-0.3)
9400)
Poker Flat #4 Sub Bit C 25.29 32.51 32.55 9.85 1,119 45.3 6.3 1.10 37.1 0.33
Poker Flat #6 Mid Sub Bit C 25.23 35.71 31.40 1.66 8,136 46.1 6.3 0.60 39.2 0.12
Moose Seam· Sub Bit C 21.42 36.62 34.88 7.68 8,953 51.7 6.3 0.81 33.3 0.15
Caribou Seam Sub Bit C 21.93 35.88 32.85 9.34 8,567 49.4 6.1 0.69 34.3 0.13
/12 Seam Sub Bit C 26.76 33.12 32.25 7.87 7,966 46.4 6.4 0.63 38.5 0.17
Jarvis Creek Sub Bit c 20.58 36.20 34.16 9.06 8,746 49.8 5.8 0.86 33.4 1.05
Matanuska 100 (2-9) (4-21) (10,300-(0.2-1.0)
(limited) 14,000)
Castle Mountain Uv Ab 1.78 28.23 52.20 17.78 12,258 69.3 4.7 1.60 6.3 0.46
Premier Uv Bb 5.87 35.73 43.96 14.44 11,101 63.6 5.1 1.60 15.3 0.35
Kenai Sub Bit C 300 (21-30) (3-22) (6500-(0.1-0.4)
8500)
Notes:
(1) Proximate and ultimate analysis
Location/Field
North Slope:
Prudhoe Bay
East Umiat
Kavik
Kemik
South Barrow2
TOTAL:
Cook Inlet:
Albert Kaloa
Beaver Creek
Beluga
Birch Hill
Falls Creek
Ivan River
Kenai
Lewis River
McArthur River
Moquawkie
Nicolai Creek
North Cook Inlet
North Fork
North Middle Ground Shoal
Sterling
Swanson River
West Foreland
West Fork
Notes:
Table 8.2 -ALASKAN GAS FIELDS
Remaining Reserves1
Gas
(billion cubic feet)
29,000
Unknown
Unknown
Unknown
29,025+
Unknown
250
767
20
80
5
1313
Unknown
78
None
17
1074
20
125
23
300
120
Product
Destination
or Field
Status
Pipeline construction to
Lower 48 underway
Shut-in
Shut-in
Shut-in
Barrow residential &
commercial users
Shut-in
Local
Beluga River Power Plant (CEA)
Shut-in
Shut-in
Shut-in
LNG Plant, Anchorage &
Kenai Users
Shut-in
Local
Field Abandoned
Granite Pt. Field
LNG Plant
Shut-in
Shut-in
Kenai Users
Shut-in
Shut-in
Shut-in
(1) Recoverable reserves estaimed to show magnitude of field only.
( 2) Producing
Location/Field
North Slope:
Prudhoe Bay 2
Simpson
Ugnu
Umiat
TOTAL
Cook Inlet:
Beaver Creek
Granite Point
McArthur River
Middle Ground Shoal
Redoubt Shoal
Swanson River
Trading Bay
TOTAL
Notes:
Table B.3 -ALASKAN OIL FIELDS
Remaining Reserves1
Oil
(million barrels)
8,375
Unknown
Unknown
Unknown
8,375+
1
21
118
36
None
22
4
198+
Product
Destin at ion
or Field
Status
Pipeline to Valdez
Shut-in
Shut-in
Shut-in
Refinery
Drift River Terminal
Drift River Terminal
Nikiski Terminal
Field Abandoned
Nikiski Terminal
Nikiski Terminal
(1) Recoverable reserves estaimed to show magnitude of field only.
(2) Producing
Table B.4 -ALASKAN RAILBELT FUEL PRICES (1980)
Fuel Source/Use
Coal 1
Healy/Mine-Mouth (GVEA)
Healy/Fairbanks (FMUS)
Average Lower 48
DOE Region 10
DOE U.S. Average
Natural Gas2
Kenai-Cook Inlet/
Anchorage Utilities AMLPD
CEA: Beluga
Other
Average
Cook Inlet/LNG export
to Nikiski
Average Lower 48
DOE Region 10
DOE U.S. Average
Oil
Prudhoe Bay/Fairbanks
Utilities:
GVEA
FMUS
Average Lower 48
DOE U.S. Average
(1) Healy Coal = 8,500 Btu/lb
(2) Natural Gas= 1,005 Btu/cf
OS
$80/MMBTU References
1.25 ( ) & (
1.40 ( ) & (
1.35 (9) June 1980
1.55 (45) October 1980
1.46 (45) October 1980
1.00 (31)
0.24 (9) June 1980
1.04 (9) June 1980
0.34 (9) June 1980
4.50 -4.65 (46)
1.98 (9) June 1980
4.89 (45) October 1980
3.58 (45) October 1980
3.45 (31)
4.01 (32)
5.44 (9) June 1980
4-63 -4.93 (45) October 1980
Table 8.5 -SUMMARY OF ALASKAN FUEL OPPORTUNITY VALUES
as an
Opportunity
Market Price Transport Cost Value
Fuel Market Via $/MM8TU $/MM8TU $/MM8TU
Coal Pacific NW barge 1.55 0.50 1.05
Lower 48 barge 1.46 0.63 0.83
Japan barge N/A N/A 1.33
Japan Placer-Amex N/A N/A 1.33
Japan barge N/A N/A 1.00-1.30
Japan 8-H-W N/A N/A 1.00-1.30
Natural Region 10 LNG-tanker 4.89 2.50 2.39
Gas Region 10 Pipeline spur 4.89 1. 97 2.92
Lower 48 LNG-tanker 3.58 2.50 1.08
Lower 48 Pipeline spur 3.58 1. 971 1. 61
Japan LNG-tanker 4.50-4.65 3.00 1.50-1.65
Oil Lower 48 Pipeline-
tanker N/A N/A 4.00
Notes:
(1) estimated
Table B.6 -GENERATING UNITS WITHIN THE RAILBELT -1980
Railbelt Station Unit Unit Installation Heat Rate Installed Minimum Maximum Fuel Retirement
Utility Name it Type Year (BTU/kWH) Capacity Capacity Capacity Type Year
(MW) (MI'/) (MW)
Anchorage AMLPO 1 GT 1962 15,000 14 2 15 NG 1992
Municipal AMLPO 2 GT 1964 15,000 14 2 15 NG 1994
Light & Power AMLPD 3 GT 1968 14,000 15 2 20 NG 1998
Department AMLPD 4 GT 1972 12,000 28.5 2 35 NG 2002
(AMLPD) G.M. Sullivan 5,6,7 cc 1979 8,500 140.9 NA NA NG 2009
Chugach Beluga 1 GT 1969 13,742 15.1 NA NA NG 1998
Electric Beluga 2 GT 1968 13,742 15.1 NA NA NG 1998
Association Beluga 3 GT 1973 13,742 53.5 NA NA NG 2003
(CEA) Beluga 4 GT 1976 13,742 9.3 NA NA NG 2006
Beluga 5 GT 1975 13,742 53.5 NA NA NG 2005
Beluga 6 GT 1976 13,742 67.8 NA NA NG 2006
Beluga 7 GT 1978 13,742 67.8 NA NA NG 2008
Bernice Lake 1 GT 1963 23,440 8.2 NA NA NG 1993
2 GT 1972 23,440 19.6 NA NA NG 2002
3 GT 1978 23,440 24.0 NA NA NG 2008
International 1 Station 1 GT 1965 39,9731 14.5 NA NA NG 1995
2 GT 1975 39,9731 14.5 NA NA NG 1995
3 GT 1971 39,973 18.6 NA NA NG 2001
Knik Arm 1 GT 1952 28,264 14.5 NA NA NG 1985
Copper Lake 1 HY 1961 15.0 NA NA 2011
Golden Valley Healy 1 ST 1967 11,808 25.0 7 27 Coal 2002
Electric 2 IC 1967 14,000 2. 7 2 3 Oil 1997
Association North Pole 2 GT 1976 13,500 64.0 5 64 Oil 1996
(GVEA) 2 GT 1977 13,000 64.0 25 64 Oil 1997
Zehander 1 GT 1971 14,500 17.65 10 20 Oil 1991
2 GT 1972 14,500 17.65 10 20 Oil 1992
3 GT 1975 14,900 2.5 1 3 Oil 1995
4 GT 1975 14,900 2. 5 1 3 Oil 1995
5 IC 1970 14,000 2.5 1 3 Oil 2000
6 IC 1970 14,000 2. 5 1 3 Oil 2000
7 IC 1970 14,000 2.5 1 3 Oil 2000
8 IC 1970 14,000 2. 5 1 3 Oil 2000
9 IC 1970 14,000 2.5 1 3 Oil 2000
10 IC 1970 14,000 2. 5 1 3 Oil 2000
Table 8.6 (Continued)
Railbelt Station Unit Unit Installation Heat Rate Installed Minimum Maximum Fuel Retirement
Utility Name fj Type Year (BTU/kWH) Capacity Capacity Capacity Type Year
(MW) (MW) (MW)
Fairbanks Chena 1 ST 1954 14,000 5.0 2 5 Coal 1989
Municipal 2 ST 1952 14,000 2.5 1 2 Coal 1987
Utiltiy 3 ST 1952 14,000 1. 5 1 1. 5 Coal 1987
System (FMUS) 4 GT 1963 16,500 7.0 2 7 Oil 1993
5 ST 1970 14,500 20.0 5 20 Coal 2005
6 GT 1976 12,490 23.1 10 29 Oil 2006
FMUS 1 IC 1967 11,000 2. 7 1 3 Oil 1997
2 IC 1968 11,000 2.7 1 3 Oil 1998
3 IC 1968 11,000 2. 7 1 3 Oil 1998
Homer Elec. Homer=
Association Kenai 1 IC 1979 15,000 0.9 NA NA Oil 2009
(HEA) Pt. Graham 1 IC 1971 15,000 0.2 NA NA Oil 2001
Seldovia 1 IC 1952 15,000 0.3 NA NA Oil 1982
2 IC 1964 15,000 0.6 NA NA Oil 1994
3 IC 1970 15,000 0.6 NA NA Oil 2000
Matanuska Talkeetna 1 IC 1967 15,000 0.9 NA NA Oil 1997
Elec. Assoc.
(MEA)
Seward SES IC 1965 15,000 1. 5 NA NA Oil 1995
Electric
System (SES) 2 IC 1965 15,000 1. 5 NA NA Oil 1995
Alaska Eklutna HY 1955 30.0 NA NA 2005
Power
Administration
(APAd)
TOTAL 943.6
Notes:
GT = Gas turbine
cc = Combined cycle
HY = Conventional hydro
IC = Internal Combustion
ST = Steam turbine
NG = Natural gas
NA = Not available
(1) This value judged to be unrealistic for large range planning and therefore is adjusted
to 15,000 for generation planning studies.
TABLE B.7 -EXISTING GENERATING CAPACITY IN THE RAILBELT REGION
o.
Type Units Capacity (MW)
Coal-fired steam 5 54.0
Natural gas gas-turbines (Anchorage) 18 470.5
Oil-fired gas turbines (Fairbanks) 6 168.3
Diesels 21 64.9
Combined cycle (natural gas) 140.9
H dro 2 45.0
TOTAL 53 943.6 MW
TABLE B.8 -1000 MW COAL-FIRED STEAM PLANT COST ESTIMATE -LOWER 48
$ M I L L 1 o N 5
Handy-Whitman
Account/Item 1976 Adjustment 1980
10 Concrete 22.40 547/394 31.10
20 Civil/Structural/Architectural
21,22,24 Structural & Misc. Iron
& Steel 23.70 559/397 33.37
25 Architectural & Finish 11.90 500/361 16.76
26 Earthwork 23.70 500/361 32.82
28 Site Improvements 14.80 500/361 20.50
30 Steam Generators 119.70 571/407 167.93
41 Turbine Generators 48.40 413/293 68.22
42 Main Condenser & Auxiliaries 4.20 518/361 6.03
43 Rotating Equipment, Ex. T/G 12.80 518/361 18.36
44 Heaters & Exchangers 3.70 518/361 5.31
45 Tanks, Drums & Vessels 1.50 518/361 2.15
46 Water Treatment/Chemical Feed 2,40 518/361 3.44
47 Coal/Ash/FGD Egui~ment
47.1 Coal Onload1ng Equipment 3.50 461/338 4.77
47.2 Coal Reclaiming Equipment 3.40 461/338 4.63
47,3 Ash Handling Equipment 1.40 461/338 1. 90
47.4 Electrostatic Precipitators 61.30 461/338 83.60
47.6 FGD Removal Equipment 87.90 461/338 119.88
47.8 Stack (Lining, Lights, etc.) 5.20 461/338 7.09
48 Other Mechanical Eguitment
Incl. Insulat1on & agg1ng 9. 70 518/361 13.92
49 Heatin~E Ventilating 1 Air
~ond1. 1oning 1.70 518/361 2.43
50 Pi~ing 44.60 629/422 66.47
60 Control & Instrumentation 11.10 461/322 15.41
70 Electrical Erui2ment
(Switchgear/ ransformers/
461/332 MCCs/Fixtures) 11.30 15.69
80 Electrical Bulk Materials
81,82,83 Cable Tray & Conduit 11.60 173/123 16.31
84,85,86 Wire & Cable 13.40 173/123 18.85
Switchyard 11.30 173/123 15.89
CONSTRUCTION COST TOTAL $566.60 $792.82
TABLE B.9 -500 MW COAL-FIRED STEAM COST ESTIMATES
$ M I l L I o N s (1980)
ACCOUNT/ITEM Lower 48 Beluga
10-20 Civil/Structural/Architectural $ 72.66 $ 130.79
30-46 Mechanical Equipment 146.57 263.82
47 Coal/Ash/FGD 131.52 236.73
48-60 Other Mechanical 53.04 95.47
70-80 Electrical Equipment 36.05 64.89
CONSTRUCTION COST TOTAL: $ 439.84 $ 791.70
Contingency (16~) 70.37 126.67
Subtotal 510.21 918.37
Construction Facilities/
Utilities (10~) 51.02 91.84
Subtotal 561.23 1010.20
Engineering &
Administration (12~) 67.35 121.23
TOTAL (EXCLUDING AFDC) $ 628.57 $1131.43
TABLE B.10-250 MW COAL-FIRED STEAM COST ESTIMATES
ACCOUNT/ITEM
10-20 Civil/Structural/Architectural
30-46 Mechanical Equipment
47 Coal/Ash/FGD
48-60 Other Mechanical
70-80 Electrical Equipment
CONSTRUCTION COST TOTAL
Contingency (16%)
Subtotal
Construction Facilities/
Utilities (10%)
Subtotal
Engineering &
Administration (12%)
TOTAL (EXCLUDING AFDC)
$ M I l L I o N s
Lower 48
$ 39.23
79.15
77.52
28.65
9.46
$ 244.01
283.05
311.35
$ 348.71
(1980)
Beluga
$ 70.61
142.47
139.53
51.57
35.02
$ 439.20
509.47
560.41
$ 627.65
TABLE 8.11 -100 MW COAL-FIRED STEAM COST ESTIMATES
ACCOUNT/ITEM
10-20 Civil/Structural/Architectural
30-46 Mechanical Equipment
47 Coal/Ash/FGD
48-60 Other Mechanical
70-BO Electrical Equipment
CONSTRUCTION COST TOTAL
Contingency (16%)
Subtotal
Construction Facilities/
Utilities (10%)
Subtotal
Engineering &
Administration (12%)
TOTAL (EXCLUDING AFDC)
$ M 1 L L 1 o N s
Lower 48
$ 21.19
42.74
22.08
15.47
10.50
$ 111.98
129.89
142.88
$ 160.03
(1980)
Beluga
$ 38.14
76.93
39.74
27.85
18.90
$ 201.56
233.80
257.19
$ 288.05
TABLE B.12-250 MW COMBINED CYCLE PLANT COST ESTIMATES
$ R I [ [ I !J fl s (l9!J!JJ
ACCOUNT/ITEM [ower 4!J Beluga
20 Civil/Structural/Architectural
21,22,23 Buildings/Structures 2.83 4.53
26,28 Foundations Site Work 5.63 9.00
40 Mechanical
41-47 Generating Units 37,50 60.00
45 Fuel Handling 1.40 2.24
48 Other Mechanical 5.28 8.45
70/80 Electrical EguiEment 11.79 18.86
100 Transportation: (25%)(41-47 total) Pacific NW 9.38 18.75
(50%) (41-47 total) Anchorage
CONSTRUCTION COST TOTAL 73.81 121.83
Contingency (16%)
Subtotal 85.61 141.34
Construction Facilities/
Utilities (10\\l)
Subtotal 94.17 155.47
Engineering & Administration (12\\l)
TOTAL (EXCLUDING AFDC) $105.47 $174.13
TABLE B.13-SUMMARY OF THERMAL GENERATING RESOURCE PLANT PARAMETERS
CO~C-tiR~O ST~A~ GAS
Parameter TURBINE DIESEL
500 MW 250 MW 100 MW 75 MW 10 MW
Heat Rate (Btu/kWh) 10,500 10,500 10,500 8,500 12,000 11,500
O&M Costs
Fixed O&M ($/yr/kW) 0.50 1. 05 1.30 2. 75 2. 75 0.50
Variable O&M ($/MWH) 1.40 1.80 2.20 0.30 0.30 5.00
Outages
Planned Outages (%) 11 11 11 14 11 1
Forced Outages (%) 5 5 5 6 3.8 5
Construction Period (yrs) 6 6 5 3 2
Start-up Time (yrs) 6 6 6 4 4
Total Caeital Cost
($ million)
Railbelt: 175 26 7.7
Beluga: 1,130 630 290
Unit Caeital Cost ($/kW)1
Railbelt: 728 250 778
Beluga: 2473 2744 3102
Notes:
(1) Including AFDC at 0 percent escalation and 3 percent interest.
TABLE B.14-GAS TURBINE TURNKEY COST ESTIMATE 1
Turnkey
Installed Bids
Capacity ($million 1978)
63 13.95
75 18.10
77 1B.BO
78 14.32
Notes:
(1) Source: Reference (19)
TABLE B.15-GAS 75 MW GAS TURBINE COST ESTIMATE
Item
Turnkey Cost
Construction Facilities/Utilities (10%)
Engineering and Administration (14%)
TOTAL (EXCLUDING AFDC)
Notes:
Cost
($million 1978) ($million 1980)1
18.10 20.58
2.06
3.16
25.80
(1) Adjusted by Handy-Whitman Cost Indices for Steam Plants (258/227)
APPENDIX C -ALTERNATIVE HYDRO GENERATING SOURCES
The analysis of alternative sites for non-Susitna hydropower development follow-
ed the plan formulation and selection methodology discussed in Section 1.4 of
Volume I and Appendix A. The general application of the five-step methodology
(Figure A.1) for the selection of non-Susitna plans is presented in Section 6 of
this report. Additional data and explanation of the selection process are pre-
sented in more detail in this Appendix.
The first step in the plan formulation and selection process is to define the
overall objective of the exercise. For step 2 of the process, all feasible
sites are identified for inclusion into the subsequent screening process. The
screening process (step 3) eliminates those sites which do not meet the screen-
ing criteria and yields candidates which could be refined to include into the
formulation of Railbelt generation plans (step 4).
Details of each of the above planning steps are given below. The objective of
the process is to determine the optimum Railbelt generation plan which incorpor-
ates the proposed non-Susitna hydroelectric alternatives.
C.l -Assessment of Hydro Alternatives
Numerous studies of hydroelectric potential in Alaska have been undertaken.
These date as far back as 1947, and were performed by various agencies including
the then Federal Power Commission, the u.s. Army Corps of Engineers (COE), the
United States Bureau of Reclamation (USBR), the United States Geological Survey
(USGS) and the State of Alaska. A significant amount of the identified poten-
tial is located in the Railbelt region, including several sites in the Susitna
River Basin.
Review of the above studies and in particular the inventories of potential sites
published in the U.S. Army Corps of Engineers National Hydropower Study (1) and
the Alaska Power Administration (APAd) 11 Hydroelectric Alternatives for the
Alaska·Railbelt 11 (2) identified a total of 91 potential sites (Figure C.1). All
of these sites are technically feasible and, under step 2 of the planning
process, were identified for inclusion in the subsequent screening exercise.
C.2 - Screening of Candidate Sites
The screening process for this analysis required the application of four itera-
tions with progressively more stringent criteria.
(a) First Iteration
The first screen or iteration determined which sites were technically
infeasible or not economically viable and rejected these sites. The stan-
dard for economic viability in this iteration was defined as energy
production cost less than 50 mills per kWh, based on economic parameters.
This value for energy production cost was considered to be a reasonable
upper limit consistent with Susitna Basin alternatives for this phase of
the selection process.
C-1
Cost data provided in published COE and APAd reports were updated to repre-
sent the current level of economics in hydropower development for a total
of 91 sites inventoried within the Railbelt Region. As discussed in
Section 8, annual costs were derived on the basis of a 3 percent cost of
money, net of general inflation. Construction costs were developed by
1naking uniform the field costs provided in the COE and APAd reports. This
was necessary as the two agencies used different location factors in their
estimates, to account for higher price levels in Alaska. Contingencies of
20 percent and engineering-administration adjustments of 12 to 14 percent
were added to finally yield the project cost. Project costs were subse-
quently updated to a July 1, 1980 price level based on the 11 Handy-Whitman
Cost Index for Hydropower Production in the Pacific Northwest" (3).
Using updated project costs as well as a series of plant size-dependent
economic factors preliminarily selected for the rough economic screening,
the average annual production costs in mills/kWh were estimated for the 91
sites. Typical factors considered were construction period, annual invest-
ment carrying charges, and operation and maintenance expenditures. Plant
capacity factors ranged from 50 to 60 percent, based on source data. A
range of average annual production costs resulted for most of the sites,
similar to those initially estimated by both the COE and the APAd.
As a result of this screen, 26 sites were eliminated from the planning pro-
cess. The sites rejected are given in Table C.1. The remaining 65 sites
were subjected to a second iteration of screening which included additional
criteria on environmental acceptability. The location of the 65 remaining
sites are given in Figure C.1.
(b) Second Iteration
The inclusion of environmental criteria into the planning process required
a significant data survey to obtain information on the location of existing
and published sources of environmental data. The 27 reference sources
used in preparing the evaluation matrix include publications and maps for
which data were collected, prepared and/or adopted by the following
agencies:
-University of Alaska, Arctic Environmental Information and Data Center
-Alaska Department of Fish and Game
-Alaska Division of Parks
-National Park Service
-Bureau of Land Management, u.s. Department of Interior
-U.S. Geological Survey
-Alaska District Corps of Engineers
-Joint Federal State Land Use Planning Commission
C-2
In addition, representatives of state and federal agencies (including
AEIDC, ADNR, ADF&G, ADEC and Alaska Power Administration) were interviewed
ta provide subjective input to the planning process.
The basic data collected identified two levels of detail of environmental
screening. The purpose of the first level of screening was to eliminate
those sites which were unquestionably unacceptable from an environmental
standpoint. Rejection of sites occurred if:
(i) They would cause significant impacts within the boundaries of an
existing National Park or a proclaimed National Monument area;
(ii) They were located on a river in which:
-Anadromous fish are known to exist;
-The annual passage of fish at the site exceeds 50,000;
-Upstream of the site, a confluence with a tributary occurs in which
a major spawning or fishing area is located.
The definition of the above exclusion criteria was made only after a review
of the possible impacts of hydropower development on the natural environ-
ment and the effects of land issues on particular site development.
The first exclusion criterion reflects the existing restrictions to the
development of hydropower in certain classified land areas. Information
regarding the interpretations of land use regulations was gathered in dis-
cussions with state and federal officials, including representatives of the
Federal Regulatory Commission (FERC) who are responsible for the licensing
of hydropower projects affecting federal lands. Many land classifications
were identified, such as national and state parks, forests, game refuge or
habitat areas, wild and scenic rivers, and wilderness areas. Additionally,
the land ownership question in Alaska was further complicated by federal
land. withdrawals (under the Federal Land Policy and Management Act) and
Administration National Monument Proclamations.
After the various restrictions were evaluated, it became clear that the
only lands where hydropower development is strictly prohibited are National
Parks and Monuments, Wild and Scenic Rivers and National Wilderness Areas.
At this time, many lands were still protected by the National Monument
Proclamations, pending the passage of the Alaska National Interest Lands
Bill in Congress. Other land classifications allow for monitoring and
regulation of development by the controlling agency and, in some cases,
veto power if the development is not consistent with the purposes of the
land designation. Note that no sites coincided with either Wild and Scenic
Rivers or Wilderness Areas; these were not included as exclusion criteria.
At the time of evaluation, the Alaska Lands Bill had not yet been passed by
the U.S. Congress. Thus, the determination of impacts of restricted land
use was based on the existing legislation, which included the
C-3
Administration National Monument Proclamation of December 1, 1978, and the
Federal Land Policy and Management Act of 1976. The Lands Bill became
Public Law 96-487 on December 2, 1980. The resulting land status changes
have been evaluated to the extent that they affected the chosen hydropower
sites.
Many significant sensitivities were identified in the Alaskan setting.
However, only one of these was determined to be so highly sensitive to
hydro development and so important to the state that it alone could pro-
hibit the development of a site. Thus, sites located on a stretch of river
used as a major artery for anadromous fish passage were excluded. It was
believed that the potential for mitigation of adverse affects of such sites
was limited, and that even a relatively small percentage loss of fish could
have a devastating result for the fishery.
Of the 65 sites remaining after the preliminary economic screening, 19
sites were unable to meet the requirements set for the second screen.
These sites are given in Table C.l, and the reason for their rejection in
Table C.2
(c) Third Iteration
The reduction in the number of sites to 46 allowed a reasonable reassess-
ment of the capital and energy production costs for each of the remaining
sites to be made. Adjustments were made to take into account transmission
line costs necessary to link each site to the proposed Anchorage-Fairbanks
intertie. This iteration resulted in the rejection of 18 sites based on
judgemental elimination of the more obvious uneconomic or less
environmentally acceptable sites. The remaining 28 sites were subjected to
a fourth iteration which entailed a more detailed numerical environmental
assessment. The 18 sites rejected in the third iteration are given in
Table C.1.
(d) Fourth Iteration
To facilitate analysis, the sites were categorized into sizes as follows:
-Less than 25 MW: 5 sites;
-25 MW to 100 MW: 15 sites
-Greater than 100 MW: 8 sites.
The fourth and final screen was performed using detailed numerical environ-
mental assessment which considered eight criteria chosen to represent the
sensitivity of the natural and human environments at each of the sites.
Three main aspects were incorporated into the sel ion of these criteria:
-Criteria must represent the important components of the environmental
setting that may be impacted by the development of a hydroelectric pro-
ject.
-Criteria must include components th represent existing and potential
land use and management plans.
C-4
-Information relating to these criteria must be reasonably available and
easily incorporated into a screening/evaluation process.
The eight evaluation criteria are listed in Table C.3. Each criterion was
defined to identify the objectives used for investigating that criterion.
Following the selection of the evaluation criteria, it was necessary to
define the significance of a variety of factors within each set of criter-
ia. Under the category of anadromous fisheries, for example, it is neces-
sary to differentiate between a site which would adversely affect a major
spawning area and a site which is used only for passage by a relatively
small number of fish.
For each of the evaluation criteria, therefore, a system of sensitivity
scaling was used to rate the relative sensitivity of each site. A letter
(A, B, Cor D) was assigned to each site for each of the eight criteria to
represent this sensitivity. The scale rating system is defined in Table
C.4.
Each evaluation criterion has a definitive significance to the Alaskan
environment and degree of sensitivity to impact. A discussion of each
criterion is appropriate to determine the importance of that criterion in
the continued study or rejection of the hydroelectric sites.
(i) Big Game
The presence of big game is especially significant in the Alaskan
environment. Special protection and management techniques are em-
ployed to ensure propagation of the species and continued abundance
for subsistance and commercial harvesting as well as recreation uses.
This criterion has a very high importance in the life style and eco-
nomic well being of the Alaskan people.
Site specific information was extracted from a series of map overlays
which identified types of big game habitats with varying importance to
survival of the species considered. For example, a map may have a
large area designated as "moose present" or "moose distribution".
Within that large distribution area, smaller areas were identified as
seasonal concentration areas or calving areas. These smaller areas
were considered to be more sensitive to development than the large
areas because they satisfy specific needs within the life cycle of the
moose, and because the availability of appropriate land is limited.
Of the references inspected, "Alaska•s Wildlife Atlas, Vol 1" was
regarded as the most authoritative source, and took precedence in the
case of conflicting information. References "Musk Oxen and Caribou"
and ••Large Mammals" generally added to the body of knowledge. Refer-
ences "Bear Denning and Goat Range", "Dall Sheep, Deer and Moose Con-
centrations" and "Distribution of Caribou Herds in Alaska" were
reviewed, but had little input which corresponded with the sites
surveyed.
C-5
(ii) Argicultural Potential
Agricultural potential was assigned a relatively high importance. This
is because it is an indicaton of the potential for the self suffi-
ciency of any area, and the avenues towards self sufficiency require
special consideration in the economic climate of Alaska.
The best agricultural resources identified in the Railbelt region are
located in the lowlands adjacent to the lower Susitna basin. These
include the Yentna/Skwentna system and the northern and eastern shores
of Cook Inlet as well as the Tanana and Nenana River valleys and the
upper part of the Copper River basin. The latter was identified as
climatically marginal.
The amount of land identified with suitable farming soils is rela-
tively small and was assigned a higher sensitivity than land with
marginal farming soils. Lands with no suitable soils identified were
assigned the lowest sensitivity.
Map reference "Cultivatable Soils" and ''Alaska Resources Inventory,
Agricultural and Range Resources" were used to identify lands with
agricultural potential in the Railbelt.
(iii) Waterfowl, Raptors and Endangered Species
The Railbelt provides extensive habitats for many species of waterfowl
as well as habitats for some threatened and endangered bird species.
The protection of these habitats in the face of development is a con-
cern of many environmentalists and ecologists. As an evaluation cri-
terion, this was considered to be slightly less important than the big
game or fisheries criteria because of the combined ecological and
economic importance of those two criteria.
In evaluating the sensitivity of the various factors providing input
to these criteria, three reference maps were surveyed: "Alaska's
Wildlife Atlas Vol II" provided information regarding waterfowl and
seabirds; "Migratory Birds: Seabirds, Raptors & Endangered Species"
had information regarding seabirds and raptor habitats; and "Birds"
identified endangered and threatened species habitats. Generally,
raptor and endangered species' habitats were considered most
sensitive. High density and key waterfowl areas were considered to be
moderately sensitive.
(iv) Anadromous Fisheries
The anadromous fisheries resource is an essential component of
Alaska's economy and life style as well as its natural environment.
It is the single resource most affected by hydropower development due
to the nature of the development itself which not only hampers the
passage of fish but may also alter flow conditions essential to the
anadromous life cycle. Because of its sensitivity to hydropower
development, the anadromous fisheries resource was very highly
considered in this evaluation.
The comparative sensitivity of the sites was based on the number of
species identified as present or spawning in the vicinity. Particular
emphasis was placed on the river upstream of proposed dam sites and,
when information was available, on the estimated number of fish iden-
tified passing certain points. Some sites were excluded in prelimin-
ary screening because they were identified as major locations for fish
passage (greater than 50,000 annually.) The most sensitive of the
remaining sites were those with the largest number of species present
and with the most extensive spawning areas upsteam of the dam site.
Lowest sensitivity corresponded with the absence of anadromous fish in
the area.
Several compiled references were available for determining the extent
of fisheries' presence at each of the hydro sites considered. The
most comprehensive reference was "Alaska Fisheries Atlas" Volume I,
which indicated on USGS topographical maps the presence of each of
five species of salmon and their spawning areas for all areas of
interest. Two map overlays were used to determine more generally the
presence of anadromous fisheries: 11 FisherieS 11 and "Marine Mammals and
Fish". This information was also checked against the Ch2M-Hill
report 11 Review of South Central Alaska Hydropower Potential 11 for some
of the sites.
(v) Wilderness Consideration
National and state interest in the preservation of natural aesthetic
qualities in Alaska continue to be the impetus for studies and land
use legislation. Substantial amounts of land have been identified and
protected under state and federal law. However, other lands have been
identified for their unique wilderness, scenic, natural and primitive
qualities but have received no particular protection. This factor was
considered to the extent that any of the potential hydro sites would
impact the aesthetic quality of these unprotected lands.
Two map overlays prepared by the Joint Federal State Land Use Planning
Commission were used: "Selected Primitive Areas in Alaska for Consid-
eration for Wilderness Designation 11 and "Scenic, Natural and Primitive
Values 11
•
(vi) Cultural, Recreation and Scientific features
These criteria reflect the importance placed on the historical, cul-
tural and recreational values of certain landmarks, as well as the
values of scientific resources at identified locations. Areas of
varying significance were identified by the reference sources and com-
parative sensitivities were assigned accordingly if potential hydro
sites corresponded with identified areas.
Three map overlays were used to substantiate these criteria: 11 Recrea-
tion, Cultural and Scientific Features 11
, "Nationally Significant Cul-
tural Features 11
, and "Proposed Ecological Reserve System for Alaska 11 •
C-7
(vii) Restricted Land Use
A significant amount of land in Alaska is classified as national or
state parks, wildlife areas, monuments, etc. These classifications
afford varying levels of protection from complete exclusion of any
development activity to a monitoring or regulation of development
occurring on the protected lands. Using this criterion as an indica-
tion of the legal restrictions that might hinder the implementation of
a hydroelectric development, the comparative sensitivities were
defined. If a potential hydro site was located within a national
park or monument, the site was excluded during preliminary screening
from further consideration. Other land classifications were less
severe. This criterion, although it may be more of an indication of
institutional factors than the actual sensitivity of the site area,
represents real issues that would affect development.
Land status was identified using maps and reference materials prepared
by state sources: "Generalized State Land Activity", 11 Game Refuges,
Critical Habitat Areas and Sanctuaries", and federal sources, USGS
Alaska Map E and Quadrangle Maps, 11 Administration National Monument
Proclamation and FLDMA Withdrawals", 11 Alaska Illustrated Land Status 11
•
It should be noted that this evaluation was performed before the
passing of the Alaska National Interest Lands Conservation Act (PL
96-487). The results of the application of this criterion were
subsequently compared against the mandates of this federal act. No
substantial effects on the screening results were found.
(viii) Access
The main purpose of this criterion was to indicate how the potential
hydro sites fit into the existing infrastructure. In other words, the
concern was to identify those areas which would be most and least
affected or changed by the introduction of roads, transmission lines
and other facilities. The highest sensitivity was assigned to the
sites which were the farthest from the existing infrastructure,
indicating areas with the greatest potential for impacts. Lower
sensitivities were assigned to areas where roads, transmission lines
and settlements already exist.
Although this was an important criterion to consider, it was not given
a high weighting when compared to other criteria due to the subjective
nature of the interpretations made. It could be, for example, that an
existing small settlement would be more adamantly opposed to develop-
ment in an area where nobody has presently settled.
Information was garnered from notes in 11 Review of the Southcentral
Hydropower Potential .. and road maps of the area.
(ix) Summary of Criteria Weighting
The first four criteria-big game, agricultural potential, birds and
anadromous fisheries, were chosen to represent the most significant
features of the natural environment. These resources require
C-8
protection and careful management due to their position in the Alaskan
environment, their roles in the existing patterns of life of the state
residents and their importance in the future growth and economic inde-
pendence of the state. These four criteria were viewed as more impor-
tant than the following four criteria due to their quantifiable and
significant position in the lives of the Alaskan people.
The remaining four criteria-wilderness, cultural, recreation and
scientific features, restricted land use, and access were chosen to
represent the institutional factors to be considered in determining
any future land use. These are special features which have been iden-
tified or protected by governmental laws or programs and may have
varying degrees of protected status, or the criteria represent exist-
ing land status which may be subject to change by the potential devel-
opments.
It must be noted that the interpretations placed on these criteria are
subjective, although care was taken to ensure that the many viewpoints
which make up Alaska's sociopolitical climate were represented in the
evaluation. The latter four criteria were considered less important
in the comparative weighting of criteria mainly because of the subjec-
tive nature and lower degree of reliability of the facts collected.
Data relating to each of these criteria were complied separately and
recorded for each site, forming a data-base matrix. Then, based on
these data, a system of sensitivity scaling was developed to represent
the relative sensitivity of each environmental resource (by criterion)
at each site.
The scale ratings used are summarized below. A detailed explanation
of the scale rating may be found in Table C.5.
A-Exclusion (used for sites excluded in preliminary screening)
B -High Sensitivity
C -Moderate Sensitivity
D -Low Sensitivity
The scale ratings for the criteria at each site were recorded in the
evaluation matrix. Site evaluations of the 28 sites under considera-
tion are given in Table C.6. Preliminary data regarding technical
factors were also recorded for each potential development. Parameters
included installed capacity, development type (dam or diversion), dam
height, and new land flooded by impoundment. The complete evaluation
matrix may be found in Table C.7.
In this manner, the environmental data were reduced to a form from
which a relative comparison of sites could be made. The comparison
was carried out by means of a ranking process.
C-9
(x) Rank Weighting and Scoring
For the purpose of evaluating the environmental criteria, the follow-
ing relative weights were assigned to the criteria. A higher value ·
indicates greater importance or sensitivity than a lower value.
Big Game 8
Agricultural Potential 7
Birds 8
Anadromous Fisheries 10
Wilderness Values 4
Cultural Values 4
Land Use 5
Access 4
The criteria weights for the first four criteria were then adjusted
down, depending on related technical factors of the development
scheme.
Dam height was assumed to be the factor having the greatest impact on
anadromous fisheries. All the sites were ranked in terms of their dam
heights as follows:
-Height ~150 1 : Rank +
-Height 150 1
-350 1
: Rank++
-Height ~350 1 : Rank+++
A dam with the lowest height ranking (+) would have least impact,
and would therefore result in the fisheries weight to be adjusted down
by two points. Similarly, a dam of height (++) was adjusted down by
one point. A dam of height (+++) would have the greatest impact and
the weight remained at its designated value.
The amount of new land flooded by creation of a reservoir was con-
sidered to be the one factor with greatest impact on agriculture, bird
habitat, and big game habitat. Sites were ranked in terms of their
new reservoir area as follows:
-Area <5000 acres: Rank +
-Area 5000 -100,000 acres: Rank ++
-Area ~100,000 acres: Rank +++
The same adjustments were made for the big game, agricultural poten-
tials, and bird habitat weights based on this flooded area impact (see
Table C.8).
Note that for developments which utilized an existing lake for
storage, the new area flooded was assumed to be minimal (+).
C-10
The scale indicators were also given a weighted value as follows:
- B ~ 5
c = 3
0 = 1
To compute the ranking score, the scale weights were multiplied by the
adjusted criteria weights for each criteria and the resulting products
were added.
Two scores were then computed. The total score is the sum of all
eight criteria. The partial score is the sum of the first four cri-
teria only, which gives an indication of the relative importance of
the existing natural resources in comparison to the total score.
(xi) Evaluati
The evaluation of sites took place in the following manner: sites
were first divided into three groups in terms of their capacity.
Based on the economics, the best sites were chosen for environmental
evaluation. Table C.10 lists the number of sites evaluated in each of
the capacity groups. The sites were then evaluated as described
above. They were listed in ascending order according to their total
scores for each of the groups. The partial score was also compared.
The sites were then grouped as better, acceptable, questionable, or
unacceptable, based on the scores. The same general standards (e.g,
cut-off points) were used for all groups.
(xii) Analysis
The partial and total scores for each of the sites, grouped according
to capacity, are given in Table C.10.
-0 -25 MW
Of the five sites evaluated, all five were determined to be accep-
table, based on the overall standards. Three of these sites were
judged as a group to be better than the other two which had higher
partial and total scores.
-25 -100 MW
A cutoff point of approximately 134 for the total score and approxi-
mately 100 for the partial score was used. Sites scoring higher
were eliminated. The seven sites scoring lower were re-examined.
Three developments at Bruskasna, Bradley Lake, and Snow were the
best sites identified.
C-11
Of the remaining four, Coffee and Seetna were identified as ques-
tionable because of anticipated salmon fisheries problems. Lowe and
Cache scored only slightly better, but Lowe has minimal fisheries
problems, and the Cache site is farthest upstream on the Talkeetna
River, beyond which the salmon migrate only about five miles.
->100 MW
Again, the same cutoff point for acceptable sites with total scores
of 134 and partial scores of 100 used. The sites fell easily into
the two groupings of acceptable and unacceptable.
(xiii) Results
Sixteen sites were chosen for further consideration. Three con-
straints were used to identify these 16 sites. First, the most eco-
nomical sites which had passed the environmental screening were
chosen. Secondly, sites with a very good environmental impact rating
which had passed the economic screening were chosen. And finally, a
representative number of sites in each capacity group were to be
chosen, Table C.10.
From the list of 16 sites, 10 were selected for detailed development
and cost estimates required as input to the generation planning. The
ten sites chosen are underlined in Table C.1.
Three sites, Strandline Lake, Hicks, and Browne were identified by the
Ch2M-Hill Report to COE as being environmentally very good. These
sites were included, even though their associated economics were not
as good as many of the other sites which had also passed the economic
screening.
The Chakachamna site had both a very high economic ranking and a good
environmental rating in terms of the sensitivity of its natural
resources to development. Chakachamna was also identified by the
Ch2M~Hill report as having minimal environmental impacts. It should
be noted that under the recently passed Alaska National Interest Lands
Conservation Act (PL 96-487, December 2, 1980) the lands including the
Chakachamna site have not received protected status of any type. This
applies to both the project area and the existing Lake Chakachamna.
Although the boundary of designated wilderness area is located a few
miles from the eastern end of the lake, operation of the lake would
have little direct effect on the wilderness area. Because the
Chakachamna site is desirable in other respects, it is being consid-
ered as a viable alternate competing with the Susitna Project.
Three sites were chosen on the Talkeetna River. These are Cache,
Keetna, and Talkeetna-2 which are being studied as an integrated
system alternative. Although the identified environmental problems
are significant, the system is being studied for several reasons. It
C-12
is believed that with the system approach, the incremental impacts of
building a second or third plant on the same river system would be
smaller than the impacts associated with building plants on completely
separate rivers. The integrated system not only improves the economic
potential of the operating capacity, but also allows for better con-
trol over regulation of stream flows as needed by the downstream eco-
systems. Secondly, the choice of the Talkeetna River was made over
other rivers with potential for development of similar systems,
because the environmental sensitivity of the Talkeetna was not as
great as that of the Yentna-Skwentna basin, the Chulitna River or the
lower Susitna basin, particularly with regards to the presence of an-
adromous fish or big game. And finally, the Talkeetna River develop-
ments were some of the best sites economically, thus providing better
competition to Susitna.
The remaining sites of the 10 studied in detail are Allison Creek,
Snow, and Bruskasna. These are sites that were identified by the
environmental evaluation as being the best environmentally of the 28
economically superior sites.
(e) Plan Formulation and Evaluation
Steps 4 and 5 in the planning process are the formulation of the preferred
sites identified in Step 3 into Railbelt generation scenarios. To ade-
quately formulate these scenarios, the engineering, energy and environ-
mental aspects of the ten shortlisted sites were further refined (Step 4).
Engineering sketch layouts {Figures C.2 to C.lO) were produced for seven of
the sites with capacities of 50 MW or greater, and site specific construc-
tion cost estimates were prepared on the basis of this more detailed infor-
mation (Tables C.l2 through C.l8). For the three remaining sites, con-
struction costs were developed by a process of judgemental interpolation on
the basis of the estimates for the seven larger developments. Costs and
parameters associated with all ten sites are summarized in Table C.l9.
These costs incorporate a 20 percent allowance for contingencies and 10
percent for engineering and owner's administration. Cost of money has
again been assumed to be three percent, net of inflation. Energy and power
capability was determined for each of the sites using a monthly streamflow
simulation program (Appendix F). The annual average energy for each of the
the sites are also given in Table C.l9. Installed capacities were general-
ly assumed that would yield a plant factor for the developments of approx-
imately 50 percent. This ensures general consistency with Susitna develop-
ments and Railbelt system requirements.
The formulation of the ten sites into development plans resulted in the
identification of five plans incorporating various combinations of these
sites as input to the Step 5 evaluations. The five development plans are
given in Table C.20.
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. The methodology
used in the evaluation of alternative generation scenarios for the Railbelt
are discussed in detail in Section 8. The criterion on which the preferred
plan was finally selected in these activities was least present worth cost
based on economic parameters established in Section 8.
The selected potential non-Susitna hydro developments (Table C.19) were
ranked in terms of their economic cost of energy. Chakachamna is the high-
est ranked (preferred) with a cost of energy of 40 $/1000 kWh and Hicks is
the lowest ranked with a cost of energy of 1612 $/1000 kWh. The potential
developments were then introduced into the all-thermal generating scenario
in groups of two or three. The most economic schemes were introduced first
followed by the less economic schemes.
The results of these runs are given in Table C.21 and illustrate that a
minimum total system cost of $7040 million can be achieved by the introduc-
tion of the Chakachamna, Keetna and Snow projects (Plan C.2). This plan
includes 1211 MW of thermal capacity and assumes a medium load forecast.
No renewal of gas plants at retirement is also assumed. The make-up of the
Railbelt generation system under this least cost scenario is shown in
Figure C.11. Additional sites such as Snow, Strandline and Allison Creek
could be introduced without significantly changing the economics of the
generation scenarios. The introduction of these latter projects would be
beneficial in terms of displacing non-renewable energy resource
consumption.
C-14
LIST OF REFERENCES
(1) u.s. ArmY Corps of Engineers, National Hydropower Study, July, 1979.
(2) Alaska Power Administration, Hydroelectric Alternatives for the Alaska
Railbelt, February, 1980.
(3) Handy-Whitman, Cost Index for Hydropower Production in the Pacific
Northwest, 1978.
C-15
TABLE C.1 -SUMMARY OF RESULTS OF SCREENING PROCESS
Ehmination El1minat 10n Ehminahon Eliminat ron
Iteration Iteration Iteration Iteration
1 1 1 1
Site 2 3 4 Site 2 3 4 Site 2 3 4 Site 2 3 4
Allison Creek Fox * Lowe * Talachulitna River * 9eluga Lower * Gakona * lower Chulitiua * Talkeetnna R. -Sheep *
Beluga Upper * Gerstle * lucy * Talkeetna -2
Big Delta * Granite Gorge * McClure Bay * Tanana River * Bradley lake * Grant lake * McKinley River * Tazlina *
Bremmer R. -Salmon * Greenstone * Mclaren River * Tebay lake * Bremmer R. -S.F. * Gulkana River * Million Dollar * Teklanika *
Browne Hanagita * Moose Horn * Tiekel River * Bruskasna Healy * Nellie Juan River * Tokichitna * Cache Hicks Nellie Juan R. -Upper * Tat atlanika * Canyon Creek * 'Jael<River * Ohio * Tustumena * Caribou Creek * Johnson * Power Creek * Vachon Island *
Carlo * Junction Island * Power Creek - 1 * Whiskers * Cathedral Bluffs * Kanhshna River * Rampart * Wood Canyon * Chakachamna Kasilof River * Sanford * Yanert - 2 * Chulitna E .F. * Keetna Sheep Creek * Yentna *
Chulitna Hurrican * Kenai Lake * Sheep Creek - 1 * Chulitna W.F. * Kenai lower * Silver lake * Cleave * Killey River * Skwentna * Coal * King Mtn * Snow
Coffee * Klutina * '§TOman Gulch * Crescent lake * Kotsina * Stelters Ranch * Crescent lake - 2 * lake Creek Lower * Strandline lake
Deadman Creek * lake Creek Upper * Summit Lake *
Eagle River * lane * Talachulitna *
NOTES:
(1) Final site selection underlined.
* Site eliminated from further consideration.
Site
Healy
Carlo
Yanert -2
Cleave
Tebay Lake
Hanagita
Gakona
Sanford
Lake Creek Upper
McKinley River
Teklanika
Crescent Lake
Kasilof River
Million Dollar
Rampart
Vachon Island
Junction Island
Power Creek
TABLE C.2 -SITES ELIMINATED IN SECOND ITERATION
Criterion
National Park (Mt. McKinley)
National Monument (Wrangell-St. Elias National
Park) and Major Fishery
National Monument (Wrangell-St. Elias National
Park)
Naional Monument (Denali Naitonal Park)
National Monument (Lake Clark National Park)
Major Fishery
TABLE C.3 -EVALUATION CRITERIA
Evaluabon criteria
(1) Big Game
(2) Agricultural Potential
(3) Waterfowl, raptors &
endangered species
(4) Anadromous fisheries
(5) Wilderness Consider at ion
(6) Cultural, recreation
& scientific features
(7) Restricted land use
(B) Access
General Concerns
-protection of wildlife resources
-protection of existing and potential
agricultural resources
-protection of wildlife resources
-protection of fisheries
protection of wilderness and unique
features
-protection of existing and identified
potential features
-consideration of legal restriction to
land use
-identification of areas where the
greatest change would occur
Scale Rating
A. EXCLUSION
B. HIGH SENSITIVITY
c. MODERATE SENSITIVITY
D. LOW SENSITIVITY
TABLE C,4 -SENSITIVITY SCALING
Definition
The significance of one factor is great
enough to exclude a site from further
consideration. There is little or no
possibility for mitigation of extreme adverse
impacts or development of the site is legally
prohibited.
1) The most sensitive components of the
environmental criteria would be disturbed
by development, or
2) There exists a high potential for future
conflict which should be investigated in
a more detailed assessment.
Areas of concern were less important than
those in "B" above.
1) Areas of concerns are common for most or
many of the sites.
2) Concerns are less important than those of
"C" above.
3) The available information alone is not
enough to indicate a greater
significance.
Evaluation Criteria
Big Game:
Agricultural Potential
Waterfowl, Raptors and
Endangered Species
Anadromous fisheries
Wilderness Consideration
Cultural, Recreational and
Scientific features
TABLE C.5 -SENSITIVITY SCALING Of EVALUATION CRITERIA
Exclusion
-major anadromous fish
corridor for three or
more species
-more than 50,000
salmon passing site
High
-seasonal concentration
are key range areas
upland or lowland
soils suitable for
-nesting areas for:
• Peregrine falcon
• Canada Geese
• Trumputee Swan
-year round habitat
for Neritic seabirds
and raptors
-key migration area
three or more species
present or spawning
identified as a major
anadromous fish area
All of the following
-good to high quality:
• scenic area
• natural features
• primitive values
-selected for wilderness
consider at ion
-existing or proposed
historic landmark
-reserve proposed for
the Ecological Reserve
System
scALE
Moderate
-big game present
-bear denning area
-marginal farming soils
-high density waterfowl
area
-waterfowl migration
and hunting area
-waterfowl migration
route
-waterfowl nesting or
or molt area
-less than three
species present or
spawning
-identified as an impor-
tant fish area
Two of the following
-good to high quality:
• scenic area
• natural features
• primitive value
site in or close to an
area selected for
wilderness consideration
-Site affects one or
more of the following:
• boating potential
• recreational potential
• historic feature
• historic trail
archeological site
• ecological reserve
nomination
• cultural feature
Low
-habitat or distribu-
tion area for bear
-no identified agri-
cultural potential
-medium or low density
waterfowl areas
-waterfowl present
-not identified as
a spawning or
rearing area.
One or less of the
following
-good to high quality:
scenic area
• natural features
• primitive value
-site near one of the
factors in B or C
TABLE C.5 (Continued)
Evaluation Criteria
Restricted Land Use
Restricted Land Use
Exclusion
-Significant impact to:
• Existing National
Park
Federal Lands with-
drawn by National
Monument Proclaima-
tions
High
-Impact to:
• National Wildlife
Range
State Park
• State game refuge,
range, or wilderness
preservation area
-no existing roads,
railroads or airports
-terrain rough and
access difficult
-increase access to
SCALE
Moderate
-Increase:
• National For est
• Proposed wild and
scenic river
• National resource
area
• forest land withdrawn
-existing trails
-proposed roads or
-existing airports
-close to existing
roads
Low
-In one of the
following:
• State land
Native land
• None of A, B, C
-existing roads or
railroads
-existing power lines
IABL[ C.6 -Sll£ [VAliJAIIOHS
Agr {cultural WoEerFowl, Raploro, Wlldirneea tullural, f&icreo[ional, tfee[r lcted
Big c..., Potent iol [nd!I!!!J8red Specie• Conslderot !on and Scientific r!oherleo land Uoe
Allison Creek -Alack and Grizzly benr -None lde•'l.l rted -Year roood hobitet for -Spawning area for -HI~ to good quality -None !dent! rtod -Ncar Oluqoch
present neritic oeahlrda ond on lnaon epee leo aet!n lc area Hot lnnnl forest
roptors
-Peregr lne falcon
neat lng area
... Waterfowl resent
Orodley lnke -Block nnd Grizzly beor -25 to JO percent of -Peregr lne rn leon -Nom! !dent I fled -Good to hi~ quality -Doat lnq oroo -Nom! !dent Hied
pre ant soil morqinall !mit-nest lng areoo ecenery
-f.boaa present oble for forming
-hi alit forest a
Browne -Black and Grizzly boor -1-bre than 50 percent -low density of woter--Nom! -Nom! -Boot lng potential -Nom! I dent I rtod
-~~:"~resent morginolly sultoble fowl
for forntlng
-Car lbou winter ron
Bruskoeno -Block ond Grizzly bonr -Nono I dent! fled -low density of woter--None -Good to hI~ quo lit y -Boating potent lol -Nom! I dent! rted
present fowl scenery -Proposed ecological
-f.booe present -Neotlng and 1110 I ling reoorve site
-Cor ibour winter ran oren
Olnkochomno -Alock beor hohltot -Uphmd opruce, hard--Waterfowl neot lnq and -Two spec len present -Area under wllderneso -Anal ing orens -None I dent lflerl
-~loose present woort forent molt lng oroo conoldeot Ion,
-Good to hi~ quollty
ocenery
-Pr lmlt lYe and nnturol
feotureo
Coffee -Block and Grizzly beor -Moro than 50% of uppor -Key waterfowl hobltot -rour opec len present' -None I dent I fled -Bont lng oreo -None !dent I fled
present Iondo oultob le for two apownlng in oren
-ttlone present ogr lr.ul turol
-Good foreota
Cothedrnl Oluffn -Block and Grizzly bear -1-bre thqn 50% of lond -low drmalty of water--Onn opec lea prooent -Good scenery -None !dent! fled -Nom! ldentlfled
present morginnl for faraing fowl
-f.boae present -~lund spruce-hardwood -Neotlng and 1110lt lng
-Doll sheep present foreot oren
-Hoose c:cncentrat Ion or eo
Hicks -Black Dt'ld Grizzly beer -None I dent If led -Waterfowl neat lng and -rar downotruam of alto -Nom! I dent! fled -None ldont I fled -No praoent
present 1a0l t lng area only rei'Jt r let lonn
-Corlbou preaent
-Hoose winter 1 oren
Johnson -Dlack ond Grizzly bear -25 to 50!1 of upland -low denolty waterfowl -Saloon epownlng area, -Nom! !dent! fiad -Boot lng potont Ia! -Nom! !dent! fled
present ooll suitable for a reo one spec lea preoent
-foboBo, caribou ond farming -Neetlng ond mit lng
b loon preoent -t.plond opruce-hordwood a reo
forest
Keetno -Black ond Grizzly bear -None ldont I fled -Nom! !dent If led -rour &pee len preoent' -Coed to hi~ quality -HI~ booting potontlol -Nom! I dent I fled
present one ope-cleo opnhTiing prlooltlvo Iande
-Caribou winter area near elte
-Hooae fall/winter
conc:ent rat ion area
Kenai lake -Block .,d Grizzly boor -Nono Identified -Woturfowl neat lng ond -rour opec lee preoent' : :!!tur:i8 ~!~{u~~:nery -Boot lng potent lol -Olugoch National -~r~""~ep hRhttat
-Coastal hetllock-11'10lt lng area two spawning roreot
altko opruea forest
-foboae fall/winter
concentration areo
TA!llE C.6 (Contl,.,.,d)
e
Agr [cultural Waterfowl, RapEero, Wlldirno!IB Culturul, Recrev[ionol; 11iio£rleted
Big C...... Pot""t ial EndenQ!!red §l!!eleo tonoiderotion fmd Scientific rtllherloo Ltmd Use
Klut !no -Block and Grluly beor -25 to 50 pereent or -low d<molty w•lcrfowl -Two opccles present, High quality scern>ry -Boot lng pot....tlol -!lone ldontlfed
premtnt aollo morgtnai for orea Ot"'e speetea eptnn in -Natural forut lona
"" Corlbou ptenent farming -Nesting nnd ..,I tlnq vicinity of site -Prl10llhe lfmdo
-J.boso rail CDnctlnt ro--Cll..,te morglnol for area -Soloeted for wlldor-
t ton eree rariOing tJpland apruee-nonn conn lderot ton
hardWood roroet
lnne -Bl """ be or prem'"t -low densUy wntorfowl -rive i!p'DClfts prosont -Hcnn loontlf!ed -'::::!:ii't~ortonltleo -Hcnn ldonll flod
-f.bose present , area and upswn ln o \tc
Cor lbou preDent -Hooting and mo It lng vicinity
ercn
lo"" -Rinck and Grizzly boor -None ldont If led ... Per lgrene falcon -Oln spec leo praoent, -Good to high quollty -Hlntodcal feoturo • loeohd no or t no
pr-esent -Cosatnl wootorn hmnJock-nestlnt;J eroo othero down'&t reoo of -Propoood ocologlcol bordor of Onlgoch
f.bose pres~nt altkn cpruec forest olle reMtrve aite Nat lond foreot
lower O.ulltno • Block ond Grluly beQt -H::!ro thon ~0 pereont or -lbdh.., donslty ""torfowl -Four epoclos present t -Aron oolectod ror -l!oot lng rotontl6l • Hcnn ldootlrtod
present the uplond coila oult-area throe """"" lng In wlldoroenn cnnstder.ot ton
-Car tbou pnmont able for rormlnq: Neotlng ond mit lng vicinity
oroo
Silver loko -Block and Grizzly boar -Ilona .toont If lod -Yon round hobllot for -Ono spec toe prooont • -Good to Mgh quollty .., Oost lng etrm potont lAl • Cl1lo<joch ~lot lonol
preoent -Coootol waotorn hnr:doc:k-ner It lc o•oblrdn fmd morn downatrii'!<W:J """"'"Y roroo
-lli!J!:! d!!nslt~ or oeols oitko e.eruce foront r!Etoro • Primitive volua
Skwentno -50 percent or ttpperlmdo -low d<Joolty wohrrowl -Three ep0c leo prooant, -lboo !dent lfled : ~~~!~r.~n .. n. -Ibn!! ldont lrtod
oultoble for rer .. lng ClfOB apawnlng ln oroo
-Lowlfmd !lfJrUCe --Host lng ond molt lng
hardwood rorost IU03
Snow -Nooo ldontl fled • lbetlng ond molting -•-ldontlflod • Proposed ee<>loglcol • l.oeetod In Chll!lBCh
ores rnoerva alto ~lionel foroot
Slrcndllne toko II'ID:tgl--Nootlng Gnd ""It lng -Hone proe""t -ll<><>d to h!qf> quollly • Nooo Identified • -lt!.nt I fled
nree:
lol~eotno 2 -~~c .... ldontlfled -Four opec loo ptoaont, -Good to h lqf> qualIty • !looting potont lei • f'lo"" ld<tnll find
oott epee lea opawnn at eecnarv
olte -Pr I" it he lando
-llano ldontl fled -Hone ld<tnt \fled -four gpttC lea of 811\mon ~ Good to high quality -!looting potentlol -ltJne ldontl fled
preoent, epmwn lng nreos ec&nery
ldontirled -Prlmlt lve lond~
fa.rllno -IInne ldonll flod ... hm opec leo present -None identified -!looting potential • Hcnn ld:mtHied
-lowland apruet!-hordwood ut olte fmd upotrooo
forest
loklchltna -Black bear preoent -PtJte Umn 50 percent of -Hodlt,. donolty Willer--four cpecleo present., -Border primitive oren • lloollng potcnllol -Hcnn ldont lrted
-Hoose present Dolls nre u:Joblo for fowl ttreo threo epecteo opown ln
... Car Jbou preoent forming (In upper lando) -Nesting and ..,ltlnq ores olte •lcintly
TABlE t.~ (Continued)
hmlt.nern -Block be or hob It nt -Nooo !dent I fled • Nono !do!ntlrlod • Nono ldent Hied -S..lected ror wl!dnrnesn -None I <foot HI <><I -located in Kens l
-!loll ohoop hobllot tOMidorat ion Not tonal Noose R""9"
-Caod to hlgll qunl tty -Slte within n
scenery doolgnoted l'l:>t lenni
-Natural feot.Ut"t'!D WI tdormn;o areo
-Prlo,ltlve l""do
(%>per llo lu<t• -t-klooe present -Hadlum dennlty wnter-rour opecius prcoent, • Nono !donl H lod -l'.tout ing :Jrea -Nono ldonll flod
fowl IUftD tw cpm::ios opown in
-1\botlng end roaltlng nroa
ares
l%>P•r No llle -Grbzly bear preaent -1\bne ldontHiod -Nons ldentlrlod -Nons ldontl rted -ll:Jntlng IX!lllfltlol -thugDCh flat lrn>ol
Juon -Hoooo preoent -Conulsl weotern heraloclc-rorest
• fll&ek boor hobltot nitko optJrte roroat
Whlnkers Olock ond Crlzz!y beor -50 percent of upf)Etr lando -low density walcrfmd ... five epecloe: preuent., -Nons ldontlf!ed -Coot I"'J potmnt lol -liD"" I dent !r ied
-~==n~taeent sultoble ror ror,.lng erao two BfJOWJl ln are111
-llottoml1111d epuree• • Noet lng end 11101t ln9
-Cor lbeu erosent l!.'!l!lsr forest area
Yentna -Blt!Ck ond &rlzzly beor -25 to 5£1 percent or -HodhJO denulty wotor-- r he epee leo Elpnl«l ln -none ldl:nt tr lo<l -Coat lfl<l l"'tenUol • None I <lnnU fled
pTesent ootls in )mdondn uro rowl oreo BrftD
-ltlooo, spr lng/o..,.,.r/ rrultobl" ror rorl!l!ng Nootln9 and 1110ltlng
winter :onct:mtrot ton -eott ... lnnd spruce-poplor oreft
rorcnt
Crescent Lake
Chokochomno
Lower Be I uga
Coffee
~per llelugo
Strand line Lake
Bradley Lake
Kasilof River
Tust~.JTtenn
Kenai Lower
Kenol Lake
Crescent Lake-2
Grant Lake
Snow
1-lcClure Day
Big
Geme
c
c
c
c
c
c
c
c
c
c
ll
c
n
8
D
~per Nellie .l.Jon R C
Allison Creek D
Solomon Gulch tJ
lowe c
Silver Lake D
rower Creek D
Million Dollar D
Agr lcullurol
Potential
D
tJ
D
B
0
c
c
ll
D
B
0
D
IJ
D
D
D
D
IJ
D
D
D
IJ
D
c
c
c
c
c
R
c
IJ
c
c
c
c
c
0
D
R
B
R
ll
n
n
Anodromous
rtsherles
[J
c
8
B
D
D
D
A
D
0
B
c
ll
D
c
D
c
c
c
c
A
A
TABLE C. 7 -SITE EVALUATION MATRIX
Wilderness
Cons !deration
c
R
D
D
IJ
c
c
D
B
c
c
c
c
D
B
ll
D
D
c
c
c
B
Cult, Recren,
& SclentHlc
c
c
c
c
c
D
c
c
D
c
D
c
c
c
D
c
tJ
D
c
c
c
c
Restr lcted
Land Use
A
ll
D
D
D
D
0
B
B
c
c
c
c
c
c
0
D
D
c
c
c
Acceos
B
c )100
D <25
D 25-100
D 25-100
0 <25
0 25-100
0
B <25
25-100
0 )100
0 <25
D <25
D 25-100
c <25
<25
D <25
D <25
D 25-100
c <25
c <25
c
Dam
Scheme Height (rt)
Reservoir <150
w/Diverslon
Reservoir <150
w/IJI version
Reoervolr <150
ond Dam
Dsm end <150
Reservoir
[)om and 150-350
Reservoir
Reservoir <150
w/Di vera !on
Reservoir <150
w/Oiverolon
Reservoir 150-350
w/01 vers !on
Reservoir <150
w/Diverslon
Dnm ond <150
Reoervolr
Oson and >350
fleoervoir
Reservoir <150
w/01 vera ion
Reservoir <150
w/Diverslon
Reoervo!r 150-350
w/DI vers inn
Reserve ir <150
w/Di version
Reservoir <150
w/D! version
Reservoir <150
w/Di vera !on
Reservoir <150
w/01 version
Dam and 150-350
Reservoir
Reservoir <150
w/Di version
Reservoir <150
w/Di vera inn
Dam ond
Resr.rvoir
<150
on
nooded
(Acres)
<5000
<5000
<5000
<5000
5000 to
100,000
<5000
<5000
>100,000
<5000
<5000
5000 to
100,000
<5000
<5000
5000 to
100,000
<5000
<5000
<5000
<5000
5000 to
100,000
<5000
<5000
5000 to
100,000
Keetne
Granite Gorge
lalkeetnn-2
Greenstone
Cache
Hicks
Rampart
Vachon lsI ood
Junction Island
l<onllshna River
McKinley River
Tekloniko River
Browne
~oly
Carlo
Yonert-2
l.lruskasna
Tanana
Gerst le
Johnson
Cathedral Bluffs
Big
Game
B
B
fl
B
fl
1.1
c
B
B
c
B
B
!l
B
ll
1.1
B
B
!l
c
!l
Agrlcu !Lura I
Potent lei
0
D
0
0
D
D
B
ll
B
ll
D
D
c
c
0
0
0
[I
B
c
0
0
0
0
0
c
B
c
c
c
c
0
0
0
0
0
c
c
c
Anadromous
fisheries
B
B
B
B
B
0
A
A
A
ll
0
0
D
0
0
0
D
1.1
c
c
c
Wilderness
Conoiderat ion
D
c
c
c
c
0
D
D
0
B
B
D
B
B
B
0
D
D
0
0
Cult, Recreo,
& Scientific
c
c
c
0
c
c
c
0
c
B
c
c
B
c
c
c
0
Restricted
lend Use
0
D
0
D
D
0
c
0
0
D
A
A
D
A
A
A
D
D
D
D
D
Access
25-100
c 25-100
25-100
25-100
25-100
D 25-100
>100
c >100
>100
c 25-100
B
D )1£10
0
0
0
D 25-100
D 25-100
c 25-100
D )100
0 )100
Dsm
Scheme Height (ft)
Dum ond >350
Reservoir
Reoervolr 150-J50
w/Di version
Dsm and >350
Reservoir
Reservoir 150-350
w/Diversion
Dl!lll end 150-350
Reservb!r
Dam and 150-J50
Reservoir
Dam and
Reservoir
Dsm and
Reservoir
Dsm and
Reservoir
Dsm and
Reservoir
Dsm and
Reservoir
Dam ond
Reservoir
Dam nnd
Reservoir
Dam ond
Reservoir
Dam end
Reservoir
Dom end
Reservoir
Oom end
Reservoir
Dsm and
Reservoir
Dam and
Reservoir
flam and
Reservoir
>350
<150
150-350
(150
150-350
>350
150-350
150-J50
150-350
150-J50
150-J50
<150
<150
150-J50
a
flooded
(Acres)
5000 to
100,000
<5000
5000 to
100,000
<5000
<5000
<5000
>100,000
>100,000
)100,000
)100,000
<5000
5000 to
100,000
5000 to
100,000
5000 to
100,000
<5000
5000 to
100,000
5000 to
100,000
5000 to
100,000
<5000
5000 to
100,000
5000
TARLE C.7 (Conllnued)
Big __________________ Game
Clr.ove c
Wood Conyon c
Tehay Lake c
lbnaglta c
Klulino B
Tezl inn ll
Gakonn 13
Sanford 0
r.ulkona [l
Yentno B
Tolachultno B
SkwenLna R
luke Creek l\Jpe r c
Lake Creek lower c
lower Chulitna c
Toklchltna c
Coal B
!Jllo B
Chulitna n
Whiskers c
lnne c
Agr iculluro l
Potential
0
0
0
0
c
0
c
c
0
R
[l
B
0
B
n
n
0
0
0
B
B
B
c
0
0
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
Anadromous
risheries
B
B
c
0
c
c
c
c
c
B
R
B
c
[l
B
B
c
c
c
B
B
Wllrlerness
Consideration
B
B
B
0
R
0
0
0
0
0
0
0
c
0
c
c
c
c
c
0
0
Cult, Recreo, Reolrlcled
c\ Scienll fie lund Use
c
0
0
0
c
c
c
c
B
c
c
c
0
c
c
c
c
c
c
c
c
A
A
A
A
0
c
A
A
B
0
0
0
A
0
0
0
0
0
0
0
0
Access
0
0
B
ll
25-100
>100
0
0
0 25-100
c >100
c 25-100
c 25-100
c
c
D 25-100
D >100
0 25-100
0 25-100
0 25-100
c 25-100
c >100
Oom
Scheme Helgllt (ft)
Dum and 150-J50
Reservoir
Oom and >J50
Reservoir
Reservoir <150
w/Oi version
Reservoir <150
w/Oiverolon
Oom ond
Reservoir
Dam and
Reservoir
Oom ond
Reservoir
150-J50
150-J50
Reservoir 150-J50
w/DI vers \on
Dum and <150
Reservoir
Oom end <150
Reservoir
Oom and >350
Roservoir
Reservoir <150
w/Oi vera I on
Oom and 150-J50
Reservoir
Oom and
Reservoir
Onm and
Reservoir
Oom and
Reservoir
Dom ond
Reservoir
Dam and
Reservoir
Oom nnd
Reservoir
Dam and
150-350
150-350
150-350
150-350
150-350
<150
150-J50
0
rlooded
(Acres)
5000 to
100,000
>100,000
(5()00
<5000
5000 to
100,000
5000 to
100,000
5000 to
100,000
>100,000
5000 lo
100,000
5000 to
100,000
<5000
<5000
<5000
5000 to
100,000
<5000
<5000
<5000
<5000
<5000
lAIII.( C.1 (Conllnuedl
Big ______________ c..
llnnd C.Oyon
Honeqllo
,.,,,,..
s.nrord
~I keno
Venlne
loli0Cf1ultno
Slnenlno
loire Creek """'r
loire Creek l"""r
lok lctlll ...
rnot
"''"
O.Ultlno
tltl.ecerll
c
c
A
n
n
"
A
A
A
A
c
c
c
c
n
8
A
c
c
A
A9rlcu llurol
Potenltol
0
0
0
0
0
c
c
0
A
n
A
0
A
n
"
0
0
0
II
8
0
i•lerfowl,
R•plore ,
(ndl). Spec lea
B
0
0
r
c
c
c
c
c
c
r
c
r
c
c
c
c
r
c
0
8
A
0
c
c
c
c
8
R
8
c
8
II
8
c
c
c
B
II
0
WI lrlerneeo
Conoldlrollon
R
8
8
n
II
D
0
0
D
0
0
0
c
0
c
c
c
c
c
0
0
c
Cull, lllocr .. , llloolrlcled
& Sdenl tr tc lond lloe
c
II
0
0
c
c
c
c
A
c
c
c
0
c
c
c
c
c
c
c
c
A
0
c
A
B
0
0
0
0
0
0
0
0
0
D
D
D
Accooo
0
0
II
0
D
0
c
c
c
c
c
0
0
0
D
D
c
c
c
lneiei I iff
Cop...,lly
(Mil)
1~-100
)100
U-100
U -100
2).100
>100
U-100
U-100
U-100
n -1110
>100
n-1m
,.. end ...........
Dol end
Rtuw.rwoh
1~-)~0
>J~
........... (1)0
w/Oherolon
lloMrvolr <I~
w/Ol .. rol""
0.0 end
lllooerwolr
0.0 end ......... ,.
llollrwolr 1)0 -J~
w/Dhoro Inn
0.0 end ...........
,.. end ............
(I )I)
(I~
)J)O
llo11nolr <I~
w/OI .. rolon
0.0 end
Rre .. rvotr
0.0-
lllo11rwtr
,.. -........ ,,
0.0 end ......... ,,
0.0-
lllo11rvolr
0.0-
llo11rvolr
1\0 -J)O
I )O.J)O
1)0-J~
>no
( ....
floodM
(Acne)
)OliO to
IOO,!m
>100,000
(~
()000
)OliO to
100,0011
~n lo
IOO,OIWI
SOliD lo
100,1100
)1110,000
loOIIO lo
IOO,OIWI
)11110 to
100,1100
()f!OO
<)0011
<)000
)000 to
11111,000
<loOIIO
(\OliO
<:111111l
()0011
TABLE C.8 -CRITERIA WEIGHT ADJUSTMENTS
Dam Height
Adjusted We1ghts
Reserv. Area
Initial
Weight + ++-+++ + ++ +++
Big Game 8 6 7 8
Agricultural
Potential 7 5 6 7
Birds 8 6 7 8
Fisheries 10 8 9 10
TABLE C.9 -SITE CAPACITY GROUPS
No. of S1tes No. of Sites
Site Grou~ Evaluated Acce~ted
< 25 MW 5 3
25-100 MW 15 4 - 6
>100 MW 8 4
TABLE C.10-RANKING RESULTS
Site Group Partial Score Total Score
Sites: < 25 MW
Strandline Lake 59 85
Nellie Juan Upper 37 96
Tustumena 37 106
Allison Creek 65 82
Silver Lake 65 111
Sites: 25 -100 MW
Hicks 62 79
Bruskasna 71 104
Bradley Lake 71 104
Snow 71 106
Cache 86 127
Lowe 89 122
Keetna 89 131
Talkeetna -2 98 134
Coffee 101 126
Whiskers 101 134
Klutina 101 142
Lower Chulitiua 106 139
Beluga Upper 117 142
Talachultna River 126 159
Skwentna 136 169
Sites > 100 MW
Chakachamna 65 134
Browne 69 94
Tazlina 89 124
Johnson 96 121
Cathedral Bluffs 101 126
Lane 106 139
Kenai Lake 112 147
Tokichitna 117 150
TABLE C.11 -SHORTLISTED SITES
Environmental Ca~acit~
Rating 0 -25 MW 25 -100 MW 100 MW
Good Strandline Lake* Hicks* Browne*
Allison Creek* Snow* Johnson
Tustumena Cache*
Silver Lake Bruskasna*
Acceptable Keetna* Chakachamna*
Poor Talkeetna-2* Lane
Lower Chulitna Tokichitna
* 10 selected sites
Table C.12 -PRELIMINARY COST ESTIMATE-SNOW
Description
Diversion Tunnel
Earth Cofferdams
Excavation -Overburden
-Spillway
Impervious Fill
Pervious Fill
Filter Stone
Coarse Rock Fill
Concrete Spillway
9 Ft ~ Power Tunnel
22 Ft ~ Surge Shaft
50 MW Underground Powerhouse
Tailrace Tunnel
Tailrace Channel
Subtotal
Land/Damages
Reservoir Clearing
Switch yard
Transmission
Roads
Bridges
On-site Roads
Buildings/Equipment
Mobilization
Subtotal
Camp
Cater in
Subtotal
Engineering, Administration
Contingency
TOTAL
Quantity
2,000
132,000
768,000
638,000
3,028,000
83,000
57,000
1,600
10,000
200
1
505
2,000
Cost/Omt
Unit $
LF 3,060.00
cy 10.25
cy 4.50
cy 5.00
cy 5.00
cy 8.00
cy 8.50
LF 24,900.00
LF 1,978.00
VLF 7,000.00
ea
LF 1,978.00
LF 510.00
Airiognt
$10
Totgls
$10
6.12
1. 35
3.46
3.19
15.14
0.66
0.49
39.80
19.78
1.40
25.00
1.00
1.02
118.41
.98
4.16
3.00
7.20
4.20
5.00
8.00
7.54
158.49
20.00
14.40
192.89
61.72
254.61
Table C.13 -PRELIMINARY COST ESTIMATE-KEETNA
Description
Diversion Tunnel
Earth Cofferdams
Excavation -Overburden
Impervious Dam Fill
Pervious Dam Fill
Filter Stone
Coarse Rock -Rip Rap
Spillway Excavation
130 Ft Concrete Spillway
Power Tunnel
100 MW Surface Powerhouse
Subtotal
Lands/Damage
Reservoir Clearing
Switch yard
Transmission
Roads
Bridges
On-site Roads
Buildings/Equipment
Mobilization
Subtotal
Subtotal
Engineering, Administration,
Contingency
Quantity
2,000
824,000
1,474,000
1,850,000
8,513,000
193,000
148,000
410,000
1 ,ooo
2,100
1
Unit
LF
cy
cy
cy
cy
cy
cy
cy
LF
LF
ea
Cost/Unit
)
9,460.00
10.25
4.50
5.00
5.00
8.00
8.50
100,500.00
4,110.00
Amo~nt
$10
Totgls
$10
18.92
8.45
6.63
9.25
42.50
1.54
1. 26
100.50
8.64
50.00
247.69
1.66
12.18
3.00
3.20
3.60
5.00
5.00
8.00
14.47
303.80
30.00
361.10
115.55
Table C.14-PRELIMINARY COST ESTIMATE-CACHE
Cost/Unit Amo~nt Tot~ls
Descrietion Quant it~ Unit $ $10 $10
Diversion Tunnel 2,200 LF 8,390.00 18.45
Earth Cofferdams 301 '000 cy 10.25 3.09
Excavation -Overburden 2,946,000 cy 4.50 13.25
-Spillway 490,000 cy
Impervious Fill 2,750,000 cy 5.00 13.75
Pervious Fill 12,018,000 cy 5.00 60.09
Filter Stone 284,000 cy 8.00 2.27
Coarse Rock Fill 196,000 cy 8.50 1.67
Concrete Spillway 2,000 LF 71,400.00 142.80
13 Ft ~ Power Tunnel 2,000 LF 2,870.00 5.74
50 MW Surface Powerhouse 1 ea 25.00
Subtotal 286.11
Lands/Damages 1.89
Reservoir Clearing 13.96
Switch yard 3.00
Transmission 8.80
Roads 12.00
Bridges 5.00
On-site Roads 5.00
Buildings/Equipment 8.00
Mobilization 17.19
Subtotal 360.95
Camp 33.75
Cater in 32.40
Subtotal 427.10
Engineering, Administration,
Contin2enc~ 136.67
TOTAL 563.77
Table C.15 -PRELIMINARY COST ESTIMATE-BROWNE
Cost/Umt Amo~nt Totgls
Descri~tion Quant it~ Unit $ $10 $10
Diversion Tunnel 1,000 LF 12,000.00 12.00
Earth Cofferdams 196,000 cy 10.25 2.00
Excavation -Overburden 7,197,000 cy 4.50 32.39
-Spillway
Impervious Fill 2,497,000 cy 5.00 12.49
Pervious Fill . 11,895,000 cy 5.00 59.48
Filter Stone 337,000 cy 8.00 2.70
Coarse Rock Fill 329,000 cy 8.50 2.80
Concrete Spillway 1' 100 LF 128,000.00 141.00
23 Ft ~ Power Tunnel 1 ,DOD LF 5,540.00 5.54
100 MW Surface Powerhouse 1 ea 50.00
Tailrace Channel 300 LF 510.00 0.15
Subtotal 320.55
Lands/Damages 4.62
Reservoir Clearing 28.21
Switch yard 3.00
T r ansm iss ion 2.00
Roads 4.20
Bridges 5.00
Dn-s ite Roads 5.00
Buildings/Equipment 8.00
Mobilization 19.03
Subtotal 399.61
Camp 37.50
Cater in 36.00
Subtotal 473.11
Engineering, Administration,
Contingency 151.40
TOTAL 624.51
Table C.16-PRELIMINARY COST ESTIMATE-TALKEETNA-2
Cost/Un1t Ailio~nt Totgls
Descri~tion Quantitl: Unit $ $10 $10
Diversion. Tunnel 2,800 LF 8,660.00 24.25
Earth Cofferdams 445,000 cy 10.25 4.56
Excavation -Overburden 4,668,000 cy 4.50 21.00
-Spillway 333,000 cy
Impervious Fill 2,932,000 cy 5.00 14.66
Pervious Fill 14,213,000 cy 5.00 71 .07
Filter Stone 294,000 cy 8.00 2.35
Coarse Rock Fill 197,000 cy 8.50 1.67
Concrete Spillway 1,200 LF 81,600.00 97.90
12.5 Ft ~ Power Tunnel 2,400 LF 2,750.00 6.60
50 MW Surface Powerhouse 1 ea 25.00
Subtotal 269.06
Lands/Damages 0.48
Reservoir Clearing 3.27
Switch yard 3.00
Transmission 5.60
Roads 7.20
Bridges 5.00
On-site Roads 5.00
Buildings/Equipment 8.00
Mobilization 15.33
Subtotal 321.94
Camp 27.50
Cater in 29.10
Subtotal 378.54
Engineering, Administration,
Contingency 121.13
Table C.17 -PRELIMINARY COST ESTIMATE-HICKS
Cost/Un~t Amott Totals
Descri[!tion Quentitx Unit $ $10 $106
Diversion Tunnel 2,400 LF 8,450.00 20.28
Earth Cofferdams 641 ,DOD cy 10.25 6.60
Excavation -Overburden 2,136,000 cy 4.50 9,60
-Spillway 292,000 cy
Impervious Fill 2,160,000 cy 5.00 10.80
Pervious Fill 8,713,000 cy 5.00 43.60
Filter Stone 238,000 cy 8.00 1.90
Coarse Rock Fill 154,000 cy 8.50 1.30
Concrete Spillway 1,800 LF 79,444.00 143.00
15 Ft ~ Power Tunnel 1,900 LF 3,342.00 6.35
Surge Shaft
60 MW Surface Powerhouse ee 30.00
Subtotal 273.43
Lends/Damages 1. 76
Reservoir Clearing 1.48
Switchyard 3.00
Transmission 20.00
Roads 3.00
Bridges 5.00
On-site Roads 5.00
Buildings/Equipment 8.00
Mobilization 16.05
Subtotal 336.72
Camp 33.75
Cater in 30.30
Subtotal 400.77
Engineering, Administration,
Contingency 128.25
TOTAL 529.02
Table C.18-PRELIMINARY COST ESTIMATE-CHAKACHAMNA
tOst/Omt Aliio~nt lot~ls
Descri[:!tion Quantit~ Unit $ $10 $10
Main Dam ea 2.00
26 Ft Concrete Lined
Power Tunnel 57,000 LF 8,380.00 477.66
Adit Tunnels 14,000 LF 1 '680.00 23.50
35 Ft Tailrace Tunnel 1,000 LF 3,500.00 3.50
88 Ft ~ Surge Shaft 500 LF 50,000.00 25.00
16 Ft ~ Penstocks 3, 700 LF 5,090.00 18,85
500 MW Underground Powerhouse 1 ea 273.50
Diversion Tunnel 2,000 LF 9,580.00 19.15
Subtotal 843.16
Lands/Damages 0.50
Reservoir Clearing
Switchyard 3.00
Transmission 14.00
Roads 31.80
Bridges 10.00
On-site Roads 10.00
Buildings/Equipment 8.oo
Mobilization 44.40
Subtotal 964.86
Camp 72.50
Cater in 84.00
Subtotal 1121.36
Engineering, Administration,
Contingency 359.05
TOTAL 1480.41
Table C.19-OPERATING AND ECONOMIC PARAMETERS FOR SELECTED HYDROELECTRIC PLANTS
Max. Average Economic
Gross Installed Annual Plant Capit~l Cost of
Head Capacity En err Factor Cos~ Energy
No. Site River Ft. (MW) (Gwh (%) ($10 ) ($/1000 Kwh)
1 Snow Snow 690 50 220 50 255 45
2 Bruskasna Nenana 235 30 140 53 238 113
3 Keetna Talkeetna 330 100 395 45 477 47
4 Cache Talkeetna 310 50 220 51 564 100
5 Browne Nenana 195 100 410 47 625 59
6 Talkeetna-2 Talkeetna 350 50 215 50 500 90
7 Hicks Matanuska 275 60 245 46 529 84
8 D"lakachamna D"lakachatna 945 500 1925 44 1480 30
9 Allison Allison Cl'eek 1270 8 33 47 54 125
10 Strandline
Lake Beluga 810 20 85 49 126 115
NOTES:
TT)Tncluding engineering and owner's administrative costs but excluding AFDC.
TABLE C.20 -ALTERNATIVE HYDRO DEVELOPMENT PLANS
Installed On-Line
Plan Description Capacity Date
A.1 Olakachamna 500 1993
Keetna 100 1997
A.2 Olakachamna 500 1993
Keetna 100 1997
Snow 50 2002
A.3 Olakachamna 500 1993
Keetna 100 1996
Snow 50 1998
Strand line 20 1998
Allison Creek 8 1998
A.4 Olakachamna 500 1993
Keetna 100 1996
Snow 50 2002
Strandline 20 2002
Allison Creek 8 2002
A.5 Olakachamna 500 1993
Keetna 100 1996
Snow 50 2002
Talkeetna -2 50 2002
Cache 50 2002
Strandline 20 2002
Allison Creek 8 2002
TABLE C.21 -RESULTS OF ECONOMIC ANALYSES OF ALTERNATIVE GENERATION SCENARIOS
Installed Capacity (MW) by lotal System Iota! System
Categor~ in 2010 Installed Present Worth
Generation Scenario OGP5 Run ~fiermal Hydro Capacity in Cost -
ln~e Descn~tion Load Forecast Id. No. oal Gas Oil 2010 (MW) ($106)
All Thermal No Renewals Very Low 1 LBT7 500 426 90 144 1160 4930
No Renewals Low L7E1 700 300 40 144 1385 5920
With Renewals Low L2C7 600 657 30 144 1431 5910
No Renewals Medium LME1 900 801 50 144 1895 8130
With Renewals Medium LME3 900 807 40 144 1891 8110
No Renewals High L7F7 2000 1176 50 144 3370 13520
With Renewals High L2E9 2000 576 130 144 3306 13630
No Renewals Probabilistic LOF3 1100 1176 100 144 3120 8320
Thermal Plus No Renewals Plus: Medium L7W1 600 576 70 744 1990 7080
Alternative Chakachamna (500)2-1993
Hydro Keetna (100)-1997
No Renewals Plus: Medium LFL7 700 501 10 794 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
Strandl.i.ne (20),
Allison Creek (8),
Snow (50)-1998
No Renewals Plus: Medium LXF1 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 (50),
Allison Creek (8),
Talkeetna-2 (50),
Strandline (20)-2002
Notes:
(1) Incorporating load management
(2) Installed capacity
and conservation
152° 150° 148°
SCALE-MILES
I INCH EQUALS APPROXIMATELY 40 MILES
& G 0
0. 25 MW 25·100 MW > 100 MW
'· STRANDLINE L, 13. WHISKERS 26. SNOW 39, LANE
2. LOWER BELUGA 14. COAL 27. KENAI LOWER 40, TOKICHITNA
3. LOWER LAKE CR. 15. CHULITNA 28. GERSTLE 41, YENTNA
4. ALLISON CR. 16, OHIO 29. TANANA R. 42. CATHEDRAL BLUFFS
5. CRESCENT LAKE 2 17. LOWER CHULITNA 30, BRUSKASNA 43. JOHNSON
6. GRANT LAKE 16, CACHE 31. KANTISHNA R. 44. BROWNE
7, McCLURE BAY 19. GREENSTONE 32. UPPER BELUGA 45. JUNCTION IS.
s. UPPER NELLIE JUAN 20, TALKEETNA 2 33, COFFEE 46. VACHON IS.
9. POWER CREEK 21, GRANITE GORGE 34. GULKANA R, 47. TAZILNA
10. SILVER LAKE 22. KEETNA 35. KLUTINA 48. KENAI LAKE
II, SOLOMON GULCH 23. SHEEP CREEK 36. 8RAOLEY LAKE 49. C HAKACH AMNA
12, TUSTUMENA 24, SKWENTNA 37. HICK'S SITE
25, TALACHULITNA 38. LOWE
SELECTED ALTERNATIVE HYDROELECTRIC SITES FIGURE C. I I GIR I
3' GRAVEL _j9
BLANKET
sENORMAL MAX.WL(AS INDICATED ON PLAN)
COMPACTED PERVIOUS
FILL
GRAVEL 5URFJlCt:
CCREST ELEVATION (AS INDICATED ON PLAN)
~~:=....;:;::::---'----
COMPACTED PERVIOUS
FILL
U/S COFFE ~ DAM -' D/5 COFFE.RDA..M
DAM CROSS SECTION
ALTERNATIVE HYDRO SITES
TYPICAL DAM SECTION
SCALE. : 0 '200 400 FEET ~~~
FIGURE C.2
\
\ . \
I • I
\\.\ ~ \ ·.
Jl
8
0
0
£:!
0
(~
I
0
0 00 8~
( ~. • .
ALTERNATIVE HYDRO SITES
SNOW SCALE: B
_ ..... __ .......
-c,~: DlA. POWER TUNNEL
PLAN OF DEVELOPMENT
SCALE• B
0 0.1 0.'2. M\LES ~-----~----~ o,_._ .... :...-----::;2 MILES
FIGURE C.3 [iii]
NORMA'-MA')(,
W. L. EL. 0)4.5 t
.P~R INTAI<i
(\
SU~FACE. POWE.RI-lOUSE"
TOO MW CAPACITY
~LIPBUCKEi
/i'.AII...WATER El... (Q(S.O'j
~.------o/5 COF'FERDAM ... ---.. ...__.__ __
\ ALTERNATIVE HYDRO SITES
KEETNA
FIGURE C.4 •
1600
1500
~~oo
Jseo
170o _
--~--.... -~---
------------
---,.,. __
NORMAL MA'/.. WL I
E.L. 1630
\4.00 ~ --.... U/S COFFERDAM
' -----~ ...
. ------,
1400 ~
Ol..VER'5\0N
ALTERNATIVE HYDRO SITES
CACHE
SURFACE POWERHOUSE.
!50 MW CAPACITY
1500
\600
\iOO
1800
~A.Lf: 0 O.l .~~~~~ ----~O.Z. MIL~
FIGURE C.5
/
# /
.·(
___/ · . ... --...._ ----···----···
FLIP8UCt'E.T
0 0.2 MILES
FIGURE C.6 •
'Soc
NORMAL. MAX . w. L. E.L... '::,45 I
U/5
COFFE RO.t:>Jvt
/ ,,cO
1000 -!..:.--------
FL.OW >
--··-----~--
POWER TUNNE-L
ALTERNATIVE HYDRO SITES
TALKEETNA 2.
SCALE. 0
CAPACITY
0.1 0. '2. MlLE.'S
FIGURE C.7
···~ ~···'--, ••. DlVEI<SION
"•. ··.. ~ TUN~E.L~ ~ .. '-----.) . . . --....... ----. ......___ .. ·-... :::::::: ...
NORMAL MAX.
W. L. EL. 1<;;5;;; 1
.. ~·~~~-
ujs COFFERDAM
--19CQ
1700
I GOO
.........,_.~~========-----150::) '" D/S GOFF cRDAM
~. .,
'' ~ -----------------1400 \~ ~~ I SURFAcE:. POWE-RHOUSe.-~" <DO MW CAPACITY ,............,~ '"' ---. ".----···-K..J _______.. . .. . .. ----
'OP l Lt-WAY CONTROL
sTI<UCTURE.
ALTERNATIVE HYDRO SITES
HICKS
~ ·•"
1800
----~-------------)~00
rz.cx:o
SCA..LE. 0 0.1 0. 2 MIL..ES
~~~~-----.
FIGURE C.B [ii
-...,.,
CONSTRU iiON--f
ADIT
ALTERNATiVE HYDRO SITES
CHAKACHAMNA
0
Ut-.JDER.GROLJI-JD
POWS<.HOIJSE. -
:,00 MW CAPA.CIIY
'2 MIL.E.S
iiiiiiiilliillilii
FIGUREC.9 •
0
MAXI~UM
R6SER\OIR
EL 1130.0'
2 3 4 5
R:>WER TUNI-JEL.
2(;.0~ OIA.
6 ...,
HORIZONTAL DISTANCE.lt-..1 MILi;.S
8 9
PRO~ILE ALONG 4_ OF INTAK~, TUNNEL1 ~ POWERI40USl:
UNLit-JED OR SHOTCR&TE
TAILRACt TlJN"Na
ALTERNATIVE HYDRO SITES SCAL.,fiii
CHAKACHAMNA-PROFILE AND SECTIONS
SUR.G;E 51-4A.FT
10 II
----·;.·-~ FEET
1'380
LEGEND
D HYDROELECTRIC
IMi~@ COAL FIRED THERMAL
Ell GAS FIRED THERMAL
2000
• OIL FIRED THERMAL( NOT SHOWN ON ENERGY DIAGRI\M)/
NOTE: RESULTS OBTAINED FROM
OGPS RUN LFL 7
CHAKACHAMNA
EXISTING AND COMMITTED
1990 2000
TIME
GENERATION SCENARIO INCORPORATING THERMAL
AND ALTERNATIVE HYDROPOWER DEVELOPMENTS
-MEDIUM LOAD FORECAST-FIGURE C.ll
1954
2010
2010
APPENDIX D -ENGINEERING LAYOUT DESIGN ASSUMPTIONS
The objective of documenting the following design considerations is to facili-
tate a standarized approach to the engineering layout work being done as part of
Subtasks 6.02 "Investigate Tunnel Alternative", 6.03 "Evaluate Alternative
Susitna Developments" and 6.06 "Staged Development". It is emphasized that for
purposes of these initial project definition studies, layouts are essentially
conceptual and the material presented is based on published data modified by
judgement and experience.
D.l -Approach to Project Definition Studies
The general approach to the project definition studies involves three steps:
(a) Single Site Developments
All sites are treated as single projects.
(b) Multisite Developments
Two or three sites are developed in a series. This means that the down-
stream·sites may have installed capacities, spillway and diversion capaci-
ties, and drawdown levels which differ considerably from the single site
development.
{c) Staged Developments
Development at a site may be staged, i.e. in subsequent stages of develop-
ment, the dam crest level may be increased and the powerhouse capacity
expanded.
Although these steps normally follow consecutively, there is considerable over-
lap, and work could be progressing on all three steps at the same time.
This appendix essentially addresses the step {a) type studies. Careful inter-
pretation of the information is required when applying it to step {b) and (c)
studies.
D.2 -Electrical System Considerations
The current total system plant factor is reported to be of the order of 50 to
55 percent. Study projections (Section 5) indicate that this factor may go up
to between 56 and 63 percent in future years.
Initially, all projects should be sized for a 45 to 55 percent plant factor and
should incorporate daily peaking to satisfy this requirement. As a later step,
some of the proposed developments could have higher or lower plact factors, if
this is justified in economic studies.
0-1
,,
All projects should be capable of meeting a seasonally varying power demand.
Table D.l is based on load forecasting studies undertaken as discussed in
Section 5 and lists the monthly variation in power and energy demand that should
be used. In general, the installed capacity and reservoir level regulating
rules used in this study are established so that the firm energy output of the
project is maximized.
A number of terms relative to energy assessments which are used in the project
definition studies are listed and defined below. These definitions may be
modified during the subsequent steps of the feasibility studies to reflect the
higher sophistication of the studies and consequently the need for a more exact
or specific terminology definition.
-Average Monthly or Annual Energy
The average monthly annual energy produced by a hydro project over a given
period of operation.
-Firm Monthly or Annual Energy
The minimum amount of monthly or annual energy that can be guaranteed even
during low flow periods. For purposes of this preliminary study this should
correspond to the energy produced during the second lowest energy producing
year on record. This corresponds roughly to an annual level of assurance of
95%.
-Secondary Energy
Electric energy having limited availability. In good water years a hydro
plant can generate energy in excess of its firm energy capability. This
excess energy is classified as secondary energy because it is not available
every year, and varies in magnitude in those years when it is available.
-Installed Capacity
The rating of generators at design head and best gate available for production
of saleable power.
0.3 -Geotechnical Considerations
(a) Main and Saddle Dams
Geotechnical considerations inherent for each of the dam sites are
summarized in Table 0.2.
(b) Temporary Cofferdams
It is assumed that all cofferdams are of fill-type. Since much of the
original river bed material under the main dam shell may have to be exca-
vated, all cofferdams have been located outside the upstream and downstream
limits of the main dam in each case.
D-2
D.4-Hydrologic and Hydraulic Considerations
Tables D.3, D.4, D.5 and D.6 list the provisional hydrologic and hydraulic
parameters used in initial project definition studies. Table D. 7 details
preliminary freeboard requirements. An example is worked out in Table D.8 to
calculate freeboard requirements.
(a) General
Figures D.1 to D.8 illustrate the storage capacity and reservoir area at
each Susitna Basin dam site for the applicable range of water levels.
{b) Sizing of Hydraulic Components
Power Conduits -For dam schemes the sizes should be based on the maximum
velocities listed in Table D.6. For long tunnel schemes the diameter is
determined such that the cost of energy is minimized. That is, tunnel
diameter is optimized between cost of excavating larger tunnels against
reduced head losses.
-Diversion System -The cofferdam-diversion tunnel system is sized as
follows:
e The diversion tunnel is sized to accommodate the maximum velocity
permissible {Table D.6) for the design diversion flow. The top of
the upstream cofferdam is then determined by computing head loss
through the tunnel, adding to the elevation of the energy grade line
at the outlet portal, and providing a 10 feet freeboard allowance.
e The downstream cofferdam height is determined from the available
stage-discharge relationship with similar freeboard allowances.
-Spillway -Spillway size was based on the accommodation of the Project
Design Flood shown in Table D.3 and D.4. Supplementary emergency
spillways are used where necessary. All service spillways have
downstream stilling basins. The capacity of each structure is checked
for the PMF flow with a reduction up to 9 feet in freeboard (Table D.7).
The energy to be dissipated by the spillway structure was set at 45,000
hp per foot width under PMF conditions.
D.5 -Engineering Layout Considerations
Table D.9 lists the components that are incorporated in the engineering layouts
and describes the types of components to be used. Table D.9 was used as a guide
to design for all layouts.
D.6 -Mechanical Equipment
(a) Powerhouse
-Number of Units
In general, a decrease in the number of units will result in a reduction
in power plant cost. For preliminary studies it has been assumed that
unit capacities range from 100 to 250 MW. The minimum number of units
assumed is two and the maximum number is four.
D-3
-Turbines
The rated net head has been assumed to be approximately equal to the
minimum net head plus 75 percent of the difference between the maximum
and minimum net heads. For rated heads above 130 feet, vertical Francis
type units with steel spiral cases have been assumed. Vertical Kaplan
units are used for heads lower than 130 feet. Turbines are directly
connected to vertical synchronous generators in all cases.
(b) Overflow Spillway Gates
The spillway gates have been assumed to be fixed wheel vertical lift gates
operated by a double drum with rope hoists located in an enclosed tower and
bridge structure. Maximum gate size for preliminary design has been set at
50 feet width and 60 feet height. In all cases a provision of 3 feet of
freeboard for gates over maximum operating level has been assumed. The
gates are heated for winter operation.
(c) Miscellaneous ~echanical Equipment
Cost estimates provide for a full range of power station equipment
including cranes, gates, valves, etc.
0.7 -Electrical Equipment
(a) Powerhouse
Generators are of the vertical synchronous type with separate transformer
galleries provided for main and station transformers. Provision is made in
the cost estimates for a full range of miscellaneous operating and control
equipment including where necessary allowance for remote station
operations.
(b) Switchyard and Transmission Lines
The switchyard is designed to be located on the surface and as close to the
powerhouse as possible. Size guidelines for the yards are approximately
900 x 500 feet. Cost estimates allow for transmission lines and
substations (Table 0.9).
0.8 -Environmental Considerations
Previous investigations have shown that a prime environmental consideration is
the effect of possible development on fisheries. In order to avoid a severe
detrimental impact on the fisheries habitat, tentative water level fluctuations
and downstream flow release constraints have been developed. These are
guidelines only for the present studies and will be further addressed and
refined as work proceeds.
D-4
(a) Flow Constraints
Table 0.10 lists preliminary values of minimum flows required downstream of
any development at all times. The lower flows are based on preliminary
assessment of the requirements of resident fish while the higher flows are
estimated anadromous fish needs.
{b) Water Level Constraints
Daily reservoir level fluctuations should be kept below 5 feet while
seasonal drawdown should be limited to between 100 and 150 feet.
D-5
TABLE 0.1 -MONTHLY VARIATIONS DF ENERGY AND PEAK POWER DEMAND
Month Energy Var2a€1on Peak Demand
October .086 .eo
November .101 .92
December .109 1.00
January .100 .92
February .094 .87
March .086 .78
April .076 .70
May .069 .64
June .067 .62
July .066 .61
August .070 .64
Se[;!tember .076 • 70
General Conditions
Dam Type
U/S Slope
D/S Slope
General F O!Jndation Conditions
Required foundation Excavation
(in addition to overb1Jrden)
Required Foundation Treatment and
Grouting
Seismic Considerations
(MCE :::: Maximum Credible Earthquake)
Powerhouse Location
Permafrost
Construction Material Availability
Remarks
TABLE 0.2 -GEOTECHNICAL DESIGN CONSIDERATIONS
ena 1
Earth-Rock fill
4:1 (H/V)
4:1
All structures would have soil
foundations. Depth to bedrock
is believed to be ZOO'+. Inter-
stratified till and alluvium
foundation materialt local
liquefaction potential. 40'+
alluvium in valley*
Abutment
Channel
Total Excavation Depth
Core Shell --mr-""'TO"'"""
70' ·so•
Assune core-grout in five rows
of holes to 70 percent of head
up to a maximt)m of 300'.
Probable drain curtain or drain
blanket under downstream she 11.
Foundation surface -no special
treatment.
High exposure, no known site
faults. MCE = Richter 8.5 ® 40
Underground powerhouse unsuitable.
>100' deep in abutnEnts, probable
lenses under river.
No borrow areas identified.
Assume suitable materials are
available within a five-mile
radius. Processing of impervious
material will be required.
Based on Kachadoorian, 1959.
ac aren
Earth-Rockfil J
4:1
4:1
Assure soil foundations. Depth
to bedrock estimated at 2not.
Compressible, permeable and
liquefiable zones probably
exist.
Unknown.
Denali.
Assume same as for
Assume same as for Dena H.
High exposure, no known site faults ..
MCE = 8.5 @ 40 miles.
Underground powerhouse unsuitable ..
Probably >100'.
Assuffe saroo as for Denali.
No report on site. Parameters
based on regional geology ..
(1) Actual estimates on Watana and Devil Canyon have been taken from overburden contour maps.
(2) Oat.e compiled prior to January "\, 1981~ Estimates made after this date have used updated excavation c-riteria.
ee
Earth-Rockfill
2.25:1
2:1
River alluvium 125 1 , drift
abutments is 10-40' thick.
located on deep permafrost
or talus on
Saddle dam
alluvium~
Assume; Core
Shell
-Remove
rock
-Remove
average of 50' of
top 11) 1 of rock
Assume grouting same as for Watana. No
special treatrrent under shelL Asst.trne
extensive sand drains in saddle dam
permafrost area.
High exposure, no known site faults.
MCE = 8.5 @ 40 miles.
Unknown. Assume suitable for mderground
with substantial rock support,
)60' in saddle area, sporadic in abut-
ments.
Assume available Q.5 to 5 mile radius.
Impervious will requir-e processing.
Based on USSR studies ..
TABLE 0.2 (Continued)
General Conditions
Dam Type
U/S Slope
D/S Slope
G€'nera1 foundation Conditions
Required foundation [~cavation
(in addition to overburden)
Required Fotmdation Treatment and
Grouting
Seismic Considerations
(MCE = Maximum Credible Earthquake)
Powerhouse location
Permafrost
Construction Material Availability
Remarks
Sus1.lna
f.a rth-Rockfi ll
2.25:1
2:1
Unknown but rock probable over
50 1 in depth~ Possible perme-
able compressible and liquefiable
strata.
Assurre sarre as for Watana.
Assure grout and drain system Full
width of dam, dependent on founda-
tion quality. Drain gallery and
drain holes.
High exposure. MCE=B.5 ® 4Q miles.
A1 so near zone of intense
sheating.
Unknown. Assume suitable for
· underground with substantial rock
support.
Probably sporadic and deep.
Assume availabJe within five
miles. Processing similar to that
at Watana.
No reports available. Parameters
based on regional ~ology of the
area.
Earth-Rockfill or concrete arch
2.25:1 (for earth)
2:1
Abutments-assume 15' overburden (OB)
Valley bottom-48-78' alluvium.
Assume 70'. Right bank upstream -
approximately 475' deep relict
channel on right bank, upstream of
dam site.
Core: Remove top 40' of rock.
Shell: Remove top 10' of rock.
Extensive grouting to depth :::: 7fJJO
of head but not to exceed 300'.
Drain gallery and drain holes.
MCE = Richter 8.5 @ 40 miles or
7.0 ® 10 miles.
Underground favorable, extensive
support may be required.
>100 1 on left abutment. Mor-e
prevalent and deeper on north
facing slopes.
Available with 0-5 miles.
Processing required.
Based on Corps studies and 1980
Acres exploration6
Earth-Rockf ill
2.25:1
2:1
Assume 30-60' overburden and alluvium.
Core: Remove top 40' of rock.
Shell: Remove top 15' of rock.
Assurre same as for Watana.
Same as for Watana.
Probably favorable for underground but
assume support needed.
Sporadic, possibly 100 1 +.
No borrow areas defined~ Assume avail-
able within 5 miles.
No geotechnical data available. Para-
rreters based on regional g;ology ..
TABLE D.2 (Continued)
General Conditions
Dam Type
U/5 Slope
D/5 Slope
General Foundation Conditions
Required Foundation Excavation
(in addition to overburden)
Required Foundation Treatment and
Grouting
Seismic Considerations
(MCE = Maximum Credible Earthquake)
Powe<house Location
Permafrost
Construction Material Availability
Remarks
Devil Canyon
Concrete arch or gravity
Assume 35' alluvium in river bottom.
abutments, 35-50' of weathered rock.
deep. Assume excavation for spillway
valley walls.
Remove 50' of rock. Extensive
dental wo<k and shear zone over-
excavation will be requil.'ed.
Saddle dam: Excavation 15' into
rock.
Extensive grouting to 70% of head,
limited to 300'. Allow for long
anchors into rock for thrust
blocks. Extensive dental treat-
ment. Deep cutoff under saddle
dam, 15' into rock.
Same as for Watana.
Favorable for undergl.'mmd power-
hous8, assume moderate support.
None expected, but possibly
sporadic.
Concrete aggregate within 0.5
miles, embankment material -
assume within 3 miles.
Based on USBR, Corps and 1980
Acres explo<ation.
Rock fill
2.25:1
2:1
Shears and fau 1 t zones in both
Saddle dam overburden up to 90'
totals 90' to sound rock on
Core: Excavation 40' into rock
Shell: Excavate 15' into rock
Extensive grouting to 70% of head,
limited to 300'. Extensive dental
treatment under core. Deep cutoff
under saddle dam, 15' into rock.
Same as Watana.
Favorable for underground power-
house, assume moderate support.
None expected, but possibly
sporadic.
Concrete aggregate within O. 5 miles,
embankment material -assume within
3 miles.
Based an USBR, Corps and 1980
Acres exploration.
Portage Creek
Concrete gravity
Unknown -assume same as for Dev i 1 Canyon
Rock type is similar to Devil Canyon, so
assume foundation conditions are
similar.
Assume same as Devil Canyon.
MCE =Richter 8.5 ® 40 miles or 7.0
at 10 miles. -
Probably favorable for underground
powerhouse, assume moderate support.
None expected, but may be local a<eas
on north exposures o< in ove<burden.
Unknown -expect adequate sources 2-5
miles downstream.
No previous investigations are available
on this site.
TABLE D.3 -INITIAL HYDROLOGIC DESIGN CONSIDERATIONS
Susitna Devil Portage Tunnel
Parameter Denali Maclaren Vee III Watana Canz:on Creek Alternative Remarks
2 1 '269 . 4,140 4,225 5,180 5,760 5,810 5,840 Catchment area-sq .mi.: 2,320
Mean annual flow-cfs: 3,290 4,360 6,190 6,350 a, 140 9' 140 9,230 9,230
Spillway design flood-cfs: 89,800 106,000 133,000 137,000 175,000 198,000 200,000 200,000 17 5, 000 1:10,000 year
flood pect.:
without routing
Construction diversion
2o,ooo1 20,0001 flood cfs: 42,500 50,000 63,000 64,600 82,600 93,500 94,400 1:50 year flood
peak
50 year sediment
accumulation Acre-ft1: * 290,000 243,000 162,000 165,000 204,000 248 ,ooo 252,000 assumes no up-
stream develop-
Notes:
(1) Assumes upstream reservoir.
TABLE D.4 -REVISED DESIGN FLOOD FLOWS FOR COMBINED DEVELOPMENT
Parameters Scheme
(High Devil
(Watana II: Devil Canyon) ( Canyon
Spill way design
flood -cfs 115,01)0 135,1)00 145,000
Construction diversion 89,1 DO 21),000 99,100
PMF for checking 235,000 270,000 262,000
design -cfs
Notes:
This table is based on Acres Flood Frequency Analyses and supercedes
Table D.3 for Watana and High Devil Canyon first developments.
Portage )
& Creek II: Vee )
150,000 105,000
20,000 71,200
270,000 189,000
Remarks
1:10,000 year flood routed
through the reservoir at FSL
as in Table D.5
Subsequent developrrents
enjoy regulation by upstream
reservoir(s).
TABLE D.5 -SITE SPECIFIC HYDRAULIC DESIGN CONSIDERATIONS
Susitna High De vi 1 Devil Portage 1 Tunnel 1 Remarks Tunnel
Parameter Denali Maclaren Vee III Watana Can~on Can~on Creek Alternative Alternative Onl~
Reservoir Full 2,540 2,395 2, 330 2,340 2,220/ 1,750 1,445 1,020 2,200/ Tunnel alternative
Supply Level -ft 2,000 1,475 consists of Watana
and re-regulation
dams
Dam Crest Level -·ft 2,555 2,405 2,350 2,360 2,225/ 1, 775 1,465 1,030 2,225/ See above remal'ks
2,r:J60 (l'ock fill) 1,490
1,459
(concrete)2
Avel.'age Tail Water
Level -ft 2,4r:J5 2,320 1,925 1 '81 0 1,465 1,030 880 850 1,465/ Watana/Re-regula-
1,260/ t ion dam/Devil
9110 Canyon, t'espec-
tively
Installed Capacity -MW 50 10 230 330 800/400 800 400 150
Maximum Powel' Flow -5,400 2,000 8,300 9,000 18,1100/ 18,000 10,000 15,000 8,400 In Tunnel between
cfs 11 '1100 re-regulation and
Devil Canyon Powel'
House
Minimum Compensation 600 1,21)0 1,501) 1,500 2,0011 2,000 2,000 2,0011 1,000 In reach between
Flow -cfs tunnel outfall at
Devil Canyon
Low Level Outl~t
Capacity -cfs 8,900 4,700 8,300 10,0110 20,800 15,600 1tJ, 6011 9,300 20,800
Notes:
(1) Considered only as second developments after u/s dam(s) is built.
(2) Includes 4 1 high wave wall on top of dam.
(3) Empties l.'eset'voir to .10 percent capacity in 12 months.
TABLE D.6 -GENERAL HYDRAULIC DESIGN CONSIDERATIONS
Waterpassage1
Steel penstocks:
Power tunnels -lined:
Tailrace -lined:
-unlined:
Diversion tunnels -lined:
Notes:
ax1mum
Velocity
fps
20
15
15
10
50
(1) For tunnel-alternative schemes (tunnel length greater
than 5 miles) optimize velocity with respect to cost
of tunneling and energy loss in friction.
TABLE D.7-PRELIMINARY FREEBOARD REQUIREMENT
Parameter
Design Conditions
Dry freeboard -ft
Wave run up and wind set up -ft
Flood surcharge over full supply level
(FSL) -ft
Allowance for post-construction
settlement
Total freeboard -ft
Dam crest level -ft
Extreme Conditions for Checking Design
Seismic slump 1
PMF surcharge ove1: FSL allowable
Rock¥111/
Earthfill
Dam
3
6
5
1% dam height
14'
FSL + 14' +
1% dam height
1-1/2% of dam
height
14'
Concrete
Dam
3
6
5
nil
14'
FSL + 14'
nil
14'
(1) If seismic slump <14' design conditions fix dam ci:est level. If seismic
slump >14' dam c~:est level = FSL +seismic slump + 1 percent allowance foi:
post-construction settlement. -
TABLE D.B -EXAMPLE CALCULATION OF FREEBOARD REQUIREMENT AT DEVIL CANYON
Parameter
Design Conditions1
Dry freeboard -ft
Wave run up and wind set up -ft
Flood surcharge -ft
Height of dam -ft
1% of height for post-construction
settlement
Dam crest level
Extreme Conditions
Seismic slump (1-1/2%) -ft
Seismic slump < 14 feet
Thus, dam crest level remains the
same as calculated above
PMF condition
Maxi~Jm allowble water level
Notes:
Rockhtl
Dam
3
6
5
600
6
1445 + 14 + 6 = 1465'
9
1445 + 14 ::
1459'
( 1) Full supply level = 1445 ft; dam height = 61)0 ft
3
6
5
600
nil
1445 + 14 ::
1459'
nil
1445 + 14 =
1459'
Components
Dam
Spillway
Power Facilities
Intake:
Power Tunnel:
Penstocks:
Powerhouse:
Tailrace Tunnel:
Low Level Outlet Works
Intake and Tunnel:
Construction Facilities
U/S & D/S Cofferdams:
Diversion Tunnels:
Access
Road Access:
Transmission Line
Local
Compensation Flow
Outlet
Surge Chamber
Notes:
TABLE D.9 -ENERGINEERING LAYOUT CONSIDERATIONS AS SINGLE DEVELOPMENTS
Denali Maclaren Vee Susitna III Watana High Devil Canyon Devil Canyon Tunnel Alternatives
f-Conventional earth/rockfill----------------------------------------------Concrete Earth/rockfill
f-Service: Gated, open chute with downstream stilling basing ------------------------------------------1
(--Emergency: (if required) as above with downstream flip bucket --------------------------1
f-Single level----7 f-.-Multilevel ------------------------------------""""""'""7
f-Single concrete-J f--Minimum of two, concrete lined Two partially lined
lined tunnels (1/3 concrete
lined, 1/3 shot-
crated, 1/3 unlined)
f-Steel lining where necessary (near U.G. Powerhouse) (length= 1/S turbine head)------------------~
f--Underground if feasible
One lined/unlined ---7 ~Two lined/unlined ------------------------------------------7
(Lined or unlined -based on cost/energy loss
One or two with gates -use diversion tunnel(s) if possible ---------------------------------7
f-Earth or rockfill -------------------------------1 Fill or --) f----Fill ------1
f-cellular
(--Minimum of two ------------------------------------------------------7
f-To Denali Highway ---1 f--to Gold Creek --------------------------------1
To Cantwell along --1 f--to Gold Creek --------------------------------1 Denali Highway
Roads/tunnels and bridges as required ------------------------------------------------------1
f-Independent intake with control valve discharghing through low level outlet works or independent conduit----~
Upstream surge tank required if net head on machines < 1/6 of distance between reservoir and machine-----~
Downstream surge tank is required if tailrace is pressurized ----------------------------7
f-Size differential surge chambers for all locations where required
( 1) Portage Creek development will be similar to Maclaren except that
access roads and transmission lines will be to Gold Creek.
TABLE 0.10-TENTATIVE ENVIRONMENTAL FLOW CONSTRAINTS
rJow Release -cfs Maximum Allowable
W1th ProJect W1thout ProJect Flow for Daily
Located Located Peaking O~erations
Site Downstream 1 Downstream 1 CFS Remarks
Denali 300 600 5,000
Maclaren 600 1,200 6,500
Vee 800 1,500 9,500
Susitna III 8f}O 1' 500 9,500
Watana 1 ,ooo 2,000 12,000
High Devil Canyon 1, OOfJ 2,fJOO 13' 500
Devil Canyon 1,000 2,000 14,000
Alternative Tunnel
Scheme 1, fJOO 14,000 In the reach between
re-reg. dam and tail-
race outfall at
Devil Canyon
Notes:
(1) Does not apply if downstream dam backs up to tailwater level of dam above.
(2) Would not necessarily apply if scheme considered did not include a substantial amount of seasonal
regulation.
APPENDIX E -SUSITNA BASIN SCREENING MODEL
As discussed in Section 8, a screening model was developed for use in the selec-
tion of Susitna Basin sites for incorporation in the basin development plans.
The purpose of this Appendix is to provide the required background information
necessary to establish the validity and reasonableness of the screening model
used to determine these optimum basin developments for the selection process.
As in most models which try to optimize a desired product, the screening model
is dependent upon the availability and detail of information used as input. The
screening model is therefore only as good as the input estimates of cost, dam
types, environmental criteria, and energy output and requirements. The use of
the model should therefore be treated in a subjective manner appropriate to the
quality of the input data used.
E.l -Screening Model
The basic screening model is a useful tool, even when data bases are thought
inadequate or incomplete. The usefulness of the model stems from its ability to
reject alternatives that are obviously inferior to others and to rank all alter-
natives according to the information available. The net result is a reduction
.in the amount of analyses and investigations required to produce definitive
conclusions as to selection or rejection of development alternatives.
Development selection is determined through mathematical programming techniques
(optimization). The advantages of this technique are:
-Developments are never fully rejected from the list by the model;
-Comparisons of developments are based on the same objective function and
imposed constraints. The decisions are based on a homogenous and consistent
set of generated alternatives;
-Algorithms used to solve the objective function are mathematically proven and
efficient;
-Sensitivity analyses are relatively simple to conduct.
The disadvantages of the technique are more operational or economic than philo-
sophical in nature. The main program is large and expensive to run. However,
costs can usually be reduced by making simplifying assumptions.
The program selected for Susitna Basin screening uses a simplified Mixed Integer
Programming (MIP) Model. The MIP models are adaptions of classical Linear Pro-
gramming Models with integer variables. Generally MIP models optimize (either
minimize or maximize) a linear objective function which is subject to a set of
constraints or linear irregularities. In some circumstances MIP models can
optimize nonlinear objective functions but this is an unusual condition. The
selection of this modeling approach to screen possible developments is based on
the following observations:
-Many of the relationships between the model variables are linear or can be
made piecewise linear;
E-1
-Mixed integer programming offers one of the fastest algorithms for solving
optimization problems;
-Standard software for MIP is available;
-Mutually exclusive situations can be modelled through zero-one variables
and logical constraints;
-Sensitivity analyses are usually part of the program;
-The MIP model is cheaper than other techniques;
-Operational procedures are user oriented; and
-The solving algorithms are reliable.
E.2 -Model Components
The model components consist of three basic sets: variables, constraints and
objective function. In some cases, depending upon study type, a variable in one
study will be a constraint in another. Consequently care is usually required to
ensure that a reasonable set of variables and constraints are selected. The
objective function is less open to the vagaries of study type but is subject to
economic, social, environmental and political pressures.
(a) Variables
The variables of the model are the unknowns. Generally the variables can
be divided into three groups:
-State variables which characterize the behavior of the system;
-Decision variables that express a result of a choice; and
-Logical variables used to set up relationships among the various decision
variables.
No physical difference exists between state and decision variables, and in
some, model cases are reversible. Each variable can be continuous or
discrete (integer). In the model of the Susitna Basin, state variables
are: seasonal reservoir storage variation, seasonal energy yield and
spills. Decision variables are: sites (system configuration), reservoir
capacity (dam heights), installed capacity, and discharges.
(b) Constraints
Constraints are relationships which limit the value of a variable, usually
within a given range. Linear inequalities and bounds limiting one variable
are the two types of constraint used in the MIP model. Linear inequalities
can also be replaced by, or supplemented with, equations linking several
variables to a limiting condition.
The constraints included in the Susitna Basin model are: reservoir water
balance, maximum storage, power and energy equations, level of development
(quantified by the total installed capacity), convexity of logical equa-
tions (Section E4) and logical conditions for mutually exclusive alterna-
tives.
E-2
{c) Objective Function
The objective of the Susitna Basin studies as applied to this screening
model is to minimize costs of the system.
E.3 -Application of the Screening Model
The assumptions used and the approach to the site screening process are discuss-
ed in Section 8 of this report. The results of the site screening process
described in Section 8 indicate that the Susitna Basin development plan should
incorporate a combination of several major dams and powerhouses located at one
or more of the following sites:
-Devil Canyon;
-High Devil Canyon;
-Watana;
-Susitna III; and
-Vee.
In addition, sites at Watana and Denali are also recommended as candidates for
supplementary upstream flow regulation.
The main criterion {objective function) in selecting the Susitna Basin develop-
ment plans is economic {see Figure 8.1). Environmental considerations are
incorporated into the assessment of the plans finally selected.
The computer model used selects the least cost basin development plan for a
given total basin power and energy demand. In the selection the program deter-
mines the approximate dam height and installed capacity at each site. The model
is provided with basic hydrologic data, dam volume-cost curves at all the sites,
an indication of which sites are mutually exclusive and a total power demand
required from the basin. It then performs a time period by time period energy
simulation process for individual and group sites. In this process, the model
systematically searches out the least cost system of reservoirs and selects
installed capacities to meet the specified power and energy demand.
E.4 -Input Data
Input data to the model consists of the various variables and constraints re-
quired by the model to solve for the objective function. Input data to the
model takes the following form.
(a) Streamflow
As noted in the discussion of the model characteristics, simplifying
assumptions could be made to reduce the complexity of the model analysis.
One such simplification is to divide streamflow into two periods, summer
and winter. This assumption is reasonable for the Susitna River because of
the nature of streamflows in the region.
E-3
Flows are specified for these two periods for thirty years at all dam sites
except Devil Canyon, Vee, Maclaren and Denali. Streamflow records used are
historical data collected at the four gaging stations in the Upper Susitna
Basin, which have been extended where necessary to thirty years by
correlation with the thirty year record at Gold Creek. The smaller dam
sites at Devil Canyon, Vee, Maclaren and Denali, which have little or no
overyear storage capability, utilize only two typical years of hydrology as
input. These typical years correspond to a dry year (90 percent
probability of exceedence) and an average year (50 percent probability of
exceedence). Streamflow records used as input to the model are given in
Tables E.1 to E.?.
(b) Si Characteristics
For each of the seven sites, storage capacity versus cost curves were
developed based on engineering layouts presented in Section 8. Utilizing
these layouts as a basis, the quantities for lower level dam heights were
determined and used to estimate the costs associated with these lower
levels. Figures E.1 to E.3 depict the curves used in the model runs.
These curves also incorporate the cost of the appropriate generating equip-
ment except for the Denali and Maclaren reservoirs which are treated solely
as storage facilities.
(c) Basin Characteristics
Basin characteristics are inputed to the model to represent which sites are
mutually exclusive; that is, those sites which cannot be developed without
causing the elimination of another site. Mutually exclusive sites are
given in Figure E.4.
(d) Power and Energy Uemand
The model is supplied with a power and energy demand that is representative
of the future load requirements of the Railbe1t region. The total genera-
tion capacity required from the river basin and an associated annual plant
factor has been used. The capacity and annual plant factor are used to
determine the annual energy demand. The values used are discussed in Sec-
tion E.5.
E.5 -Model Runs and Results
The review of the energy forecasts given in Section 5 reveals that between
the earliest online date of the Susitna Project in 1993 and the end of the
planning period in 2010, approximately 2210, 4210 and 9620 GWh of addi-
tional energy would be required for the low, medium and high energy fore-
casts respectively. Based on these energy projections, the screening model
was run with the following total capacities and energy values:
-Run 1:
-Run 2:
-Run 3:
-Run 4:
400 MW -1750 GWh
800 MW -3500 GWh
1200 MW -5250 GWh
1400 MW -6150 GWh
E-4
For initial study purposes, the annual plant factor associated with all
these combinations was assumed to be 50 percent.
The results of the four screening model runs are given in Table E.8. The
three best solutions (optimal, first suboptimal and second suboptimal) from
an economic point of view are presented only. The most important conclu-
sions that can be drawn from these results are as follows:
-For energy requirements of up to 1750 GWh, the High Devil Canyon, Devil
Canyon or the Watana sites individually provide the most economic energy.
The difference between the costs shown on Table E.8 are around 10 percent
which is similar to the accuracy that can be expected from the screening
model;
-For energy requirements of between 1750 and 3500 GWh, the High Devil Can-
yon site is the most economic. Developments at Watana and Devil Canyon
are 20 to 25 percent more costly;
-For energy requirements of between 3b00 and 5250 GWh the combinations of
either Watana and Devil Canyon or High Devil Canyon and Vee are the most
economic. The High Devil/Susitna III combination is also competitive.
Its cost exceeds the Watana/Devil Canyon option by 11 percent which is
within the accuracy of the model;
-The total energy production capability of the Watana/Devil Canyon devel-
opment is considerably larger than that of the High Devil Canyon/Vee
development and is the only plan capable of meeting energy demands in the
6000 GWh range.
Of the seven sites available to the model for inclusion into plans of
Susitna Basin development two were rejected and only one included in a
second suboptimal solution. The rejected sites at Maclaren and Denali do
not significantly impact the systemS 1 energy capability and are relatively
costly so were eliminated from the plans. Susitna III was rejected, except
in the one case, due to high capital costs.
E-5
TABLE E. 1 -COMPUTED STREAMFLOW AT DEVIL CANYON
OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP
5/'58. 2 -2404.7 13•12.5 951.3 735.7 6 70-. 0 802• 2--i{)4-9-or7·····1fHbB-.6--2+3-&3.-4~-l002fh-6--71~-.B-----~
3652 .. 0 1231. 2 1030.8 905.7 767.5 697.1 1504.6 132l8.5 19978.5 21575.9 185~0.0 19799.1
5221. i' 2539.0 1757.5 :l483.) 943.2 828.2 878.5 4989.5 30014.2 2-1861.7 19647.2 13441.1
---=;-s-:~:-r-.-6 ---~-z-:3 2 ·•· 6· · · ·1550. <1 999.6 715.-6 . ·-76-6 .~1 ·····1.-53-i··r·Er·--1·7 7-5ih-3-·-25-Z3&.7'-1-9-t~--i-9-~~~:t-3-9-28.-4----
5:!.09.3 1921.3 1387.1 1224.2 929.7 729.4 1130~6 15286.0 23188.1 19154.1 24071.6 11579.1
4830.4 2506.8 1868.0 16ti9.1 1 ""1/1::" "J ,;.. I ...J + ,:_ 1023.6 1107. 4 8390.1 28081.9 26212.8 24959.6 13989.2
4647.9 -1-'?'&e ··6 1206.6 921.7 893.1 852+3 Bt-.7.3· ·15979 • -G-·3 :1:131-.1----2-921-2-r-<t-···22-609 .B-·1649-&-. 8----··
~5235 + 3 2773.8 1986.6 1583.2 1388.9 1105.4 1109.0 12473.6 28415.4 22109.6 19389.2 18029.0
7434.5 3590.4 2904.S:' 1792.0 1212.2 1085.7 1437.4 11849.2 24413.5 21763.1 21219.13 6988.8
--· ~-..ef-.t0·2·rB -1-9-9-9--.-B···--1 3 7 0 + 9 1316.9 1179.-:l: ·87·7.9 . -f-1·1-9-.-·9----J:·-;3 9 &0T9--L21:-fr-3·? J J 2 3-3-Tfh-+---2-€H5·94·•·-t--H5-(:H?-9+-tr--
6060.7 2622.7 2011.5 1686.2 1340.2 1112.8 121?.8 14802.9 14709.8 21?39.3 2;~066. 1 18929.9
7170.9 2759.9 2436.6 2212.0 1593.6 1638.9 2405.4 16030.7 27069.3 22880.6 21164.4 1221.8.6
--5459.-4 254~-.1 1978.7 1796·0 1413.4 r3·2<.h·3 1:61·3 r-4"·1-2141 .d2 -4% ?9T-r--2-4-9-9-0T6····-£r24·1.--8 ~--·1·471--6-?1· r2-------·"·
6307.7 2696.0 1896.0 1496.0 138:7 .4 9:38.4 8l.0.9 17697.6 24094.1 32388.4 22720.5 11777.2
~)998. 3 2085.4 138/'.1 9'78.0 900.2 663.8 696.5 4046.9 47816.4 21926.0 15585.8 8840.0
... !.§.J-44"•·.0---2-e-4~...-1"' 1160.8 925.3 82B.B "''---~6;,6 •. 9 -13 "j.-4 • 4--1. 22-.f,.-7-....1--"--2-4-1-lO-.·~~ st~~--t-¥-7.a¥ .... ~-+~-2.J.4 .• -Z---~
6496.5 1907.8 1478.4 1278.7 1187.4 1187.4 1619.1 8734.0 30446.3 18536.2 20244.6 10844.3
:3844.0 1457.9 13·'>4+9 13::'i7.9 1268.3 1089.1 1033.7 14435.5 2'7796.4 25081.2 30293.0 15728.2
45.8.5 .• 3 .2203 .. 5 .1929.7 1851.2 1778.7 .1778. .7 1791.0 -14 9 82 • 4 .29-4 6 2 .... 1."2427"1 ... ...0--16.0 9 0 .... 5." .. 8-.2.25.......sL-.~ -
357C:,.7 1531. 8 836.3 686.6 681.8 769.6 1421.3 10429.9 14950.7 15651.2 8483.6 47n;.~s
2866.5 1145.7 810.0 756.9 708.'7 721.8 104.6.6 10721.6 17118.9 21142.2 18652.8 8443.~5
4/'45.2 ... :zo~n .. a .. .. 2074.8 1318.8 943.6 . "_fJ.U, 8 ". -9 8i) • .2 .. -·"-3.4 27 .•. :$'. J.-1.0.3-1 .... .0. .. 22-St.4-1 .... 6.--J.O-J..1S .... -S ••. 1.~6 ..... -0----·
~3537. 0 2912.3 2312.6 2036.1 1836.4 1659.8 1565.5 19776.8 31929.8 21716.5 18634.1 11884.2
4638.6 2154.El 1387.0 1139.8 1128.6 955.0 986.7 7896.4 26392.6 17571.8 19478.1 8726.0
3491.4 ·1462 .. 9 99'7.4 842.7 745.9 689.5 949.1 1:5004.-~6 -16766. r'-17~·9()··r0 -rs:~·St'·· (t ·-11 a '7-0rt.--·
3506.8 1619.4 1486.::; 1408.8 1342.2 1271.9 1456.7 14036.5 30302.6 26188.0 17031.6 15154.7
?003.3 1853.0 1007.9 896.8 876.2 825+2 1261.2 11.305.3 22813.6 18252.6 19297.7 6463.:~
--~3-65-2-.4 ---~3-9+'1"::;. 2147.5 1657r4· 1 46·9 • 7-----·E~6-1 ,{} 15&9.-e-1-*·1-1-r-9 --~5-6-tt-&-.:r-zH«ttn-S--1:--8-3-71-r-2-......-:t-1-9-1-6·-.-i·---.. ~--
6936.3 3210.8 2371.4 :1.867.9 1525.0 1480.6 1597.1 11693.4 18416.8 20079.0 15326.5 8080.4
4502.3 2324.3 1549.4 1304.1 1203.6 1164.7 1402.8 13334.0 24052.4 27462.8 19106.7 10172.4
TABLE E. 2 -COMPUTED STREAMFLOW AT HIGH DEVIL CANYON
OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP
5675.8 2379.2 1328.8 940.5 728.3 662.0 792.5 10345.1 18307.0 21209.6 18669.2 7900.8
3624.0 12 21 :3 1020.9 898.0 760.0 691.0 1488.5 13094.0 19862.6 21433.9 i.8367.:l 19593.~5
517-1..-.S 2S.09.7 -1737~1 . 14 6:J! .~.1 ... 935~1 -.82~ •. &. .. -. ~ -S7...2 . .,..&.~-4-9--2-B-..-2·-·~-6.'7h &--~-19 4 b&-.-4--~ 2 9 2 , :;
7419.8 3194.9 1529.1 985.3 '7 35. 0 739.1 l.519.9 17542.3 24932.2 19038.9 19006.6 13736.7
5038.7 1895.7 1371.0 1213.4 919.6 722.1 1115.7 15001.1 22893.5 18981.9 23781.9 11387.6
4-753.3 2470.7 1842.8 1628.4 :1.237.3 10H~. 7····i094-.2··-&2a7·~4 2-78-27-.-9-2-6-(}~4-84-.b.-7---·1 ;;.946,-:J---·-·-·
4604.6 1772.7 1193.3 913.4 882.2 839.8 855.4 15738.9 30822.4 28943.6 22~~35 t 5 16233.8
~H 53,7 2734.3 1964.4 1566.5 1 ·z-,··· n . ......, I "'") + .,.) 1091.8 1096.0 12291.3 28166.1 21938.1 .19224.8 177?6.0
7323+4 3538·. 4 2853+6 1767+ 3 1198.7 i · 0 7 6 •·& H--t-4"23---r-B··-H-&9-9-.-:t:~..zij 2·2 9 .-7-.Z.4-6Vh 5 21 &5-f-+2~-~. e
4344.5 1978.4 1350.6 1298.2 1160.9 863.3 1101.3 13602.5 21.283.1 23160.5 28225.1 15102.4
5989.6 2590.2 1984.6 1663.5 1324.2 1100.7 1206.1 14663.4 14592.6 21562.1 21848.4 18704.1
7081.·9 2·725. 6 2399.8 2177.7 1570.7 1614.5· 2370.4 1584<J.8 2 6 7 2 9. 2-· 2 2 6·3-9-.-3 -rH 03-0··r7 · 1··2{15-4·.-2·~-----~
5394.2 2521.8 1961.4 1.781.2 1401.0 1308.9 1601.0 12077.1 40309.6 24867.8 22055.0 14606.8
6248.3 2681.2 1881.2 1481.2 1371.3 952.5 808.2 17507.2 23821.8 32101.0 22584.9 11699.6
5934 .• 0 20~-1.9 1371-.8 9~8 .. 0 817'0.8 656-.8 ..689 .. 6 ·--4009 .8----4-74-2-4-.. ·6--~-.:1:779., 7 -1-&46--Z-..-B· 876~.6
5665.9 2623.2 1153.6 920.4 824.4 862.2 1307.9 12163.9 23880.4 25960.8 19599.2 18074.8
6395.3 1880.6 1456.5 1261. 4 1171.3 1171.3 1596.8 8603.8 30088.6 18347.1 20018.1 10715.0
3792.4 1437.6 1345.5 1337.6 1249.5 1073.3 1037-.5 14286.3 2755l...-6-~ci4B-35-.6-·~96.0.v-6~-:15€+Mi·.-.O-·--···
4540.4 2182.1 1911.8 1832+7 :1.761.4 1761.4 1774.0 14811.3 29163.9 24649.7 15936.3 8141.5
3541.6 1517.7 829.7 681.2 675.9 762.<7' 1408.6 10341.3 14872.3 15587.1 8427.1 4n'i3.0
2829.7 1135.8 802r0 747.4 700.3 714.·0·· 1.0.4-lTfl 1{)~27. 5 ·16-903 ~--1-··2.09--2-§-.3---+84-6-3 -,-2 ... &346T:.f..-·----·--
4667.6 3035.3 2044.1 1301.2 930.5 855.0 972.5 3382.6 30759.7 22797.5 30088.2 13521.2
54'72.7 2886.5 2284.5 2007.1 1809.0 1636.3 1544.9 19475.0 31572.6 21566.0 18563.3 11810.5
4611 ~ 8 2140.7 13·75.8 1131.2 1118.5 948-.-5 -980. 9· 7848t1 2 61·9 h 5--1-7-4 7-5-.--{f---1-93 6-2-~-1--8-6-r6T3----
3-'156.9 1454.3 992.2 838.3 741.5 684.3 943.0 1.4836.7 16609.0 17645.7 15119.5 11244.4
3473,6 1607.9 1469.8 1393.5 1323.8 1253.6 1437.2 13848.9 30015.8 2S969.1 1A880.4 14989.7
-6898.2··· 183·3 .-(} 997.'4 885+8 865.6 81:4-.-6-·124 5 ··-2· 111-1:7·.~5 ·:c2s·ft9•1t·-rsts-4--.--.J--·-t-9-'l-2"5-•-9······--t"·4W·•·7' ~-------
3506.4 2354.8 2111.0 1632.9 1448.6 1341.1 1485.5 :L1002.2 35269.1 21579.1 18247.1 11812.7
6845.7 3165.9 2340.3 1844.9 1504.l1 1462.8 1582.2 11636 .. 8 18326.4 19944.6 15174.5 8005.2
4444.5· 2294 d.· -+5-3-G-,--6--· :1:2-9-<h-8 ··1191:.-9 --1 !·59...-7L·~--1:·-3-9-&.-:1: -1-3-2-5-r··-5 -2396b-5-..Z.:r-260. 3 1-B-9-1.-3-. ~-1 ~H7B 7 .-0 -~ -··
TABLE E. 3 -COMPUTED STREAMFLOW AT WATANA
OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP
4719.9 2083.6 1168.9 815.1 641.7 569.1 680.1 8655.9 16432.1 19193.4 16913.6 7320.4
329"7~T~ 1107;·3~ " "90 • ·eos-."o · ··s73 ;o· 51"'9-.""B ··r:ro2·.
4592.9 2170.1 1501.0 1274.5 841.0 735.0 803.9 4216.5 25773.4 22110.9 17356.3 11571.0
6285.7 2756.8 1281.2 8l.8.9 611.7 670.7 1382.0 15037.2 21469.8 17355.3 16681.6 11513.5
4218.9 1599+6 1183.8 1087.8 803•1 638 ··~~ . 942:. 6 1 d3 ·1 947'-6·•7· ·-t6-9&3-•6 -·:M4z&·•6
:3859.2 2051.1 1549.5 1388.3 1050.5 886.:1. 940.8 6718.1 24881.4 23787.9 1:~447.B
4l02.3 1588.1 1038.6 816.9 754.8 694.4 '718.3 12953.3 13194.4
420&+i> 227' 6 .-6~· ·1·'7 0 7 .• {) 1373.0 1189.0 ·935.-0 9·15 • 1 ~'-·6·~~2
6034.9 2935.9 2258.5 1480.6 1041.7 973.5 1265.4 9957 8 22097.8 19752.7 18843.·4 5978.7
3668.0 1729.5 1115.1 1081.0 949.0 694.0 885.7 10140.6 18329.6 20493.1 23940.4 12466.9
5165.5 2213.5 1672+3 14Nh 4 1138.9 9&1.1 1069·9 13044.:2· 1 :~233 •+ ~1
.so-t9. 3 2327.8 1973.2 1779.9 1304 8 1331.0 1965.0 13637.9 22784.1 19839.8 10146.2
4637.6 2263.4 1760.4 1608.9 1257.4 1176.8 1457.4 11333.5 36017.1
' -·~·5-60 .• 1 25~8r9 170Bt9 ·1308.9 118+.7 ·883~6 -·--·--·rt6T6··152·9S"+:2 -·-2-(}6
5l87.1 1789.1 1194.7 852.0 781.6 575.2 609.2 3578.8 4?841.9 ~~0082. 8 14048.2 7524.2
4759.4 2368.2 1070.3 863.0 772.7 807.3 1232.4 10966.0 21:213.0 23235t9 17394.1 16225 6
3·221 'f ,2~ 1565.3 1203.6 106{h4 984.7 984.7 1338. 4-· 7.()94. 1 25939 ~6-4-6·153.-5 -1-73-90.9 ·"'92-:1:4-.:1:~·--
3269.8 1202.2 1121.6 1102.2 1031.3 889.3 849.7 12535.5 24711.9 21987.3 26104.~3 136?2,9
4019.0 1934.3 1/'04.2 1t.17.6 1560.4 1560.4 1576.7 12826.7 25704.0 22082.B 14147.5 7163.6
----3435.0 -1354.-9 753r9 619;2 60·7. 5 686.0 126h 6-·-931 ::h7 ··13trr.S2..-1-1-J~&4-s• s ___ .. 9:r71:
2403.1 1020.9 709.3 636.2 602.1 624.1 986.4 9536.4 14399.0 18410.1 16263.8 7224. :l
3768.0 2496.4 1687.4 1097.1 777.4 717.1 813.7 2857.2 27612.8 21126.4 27446.6 12188.9
4979.1 25B7.0 1957.4 1670.9 1491 .4 1366.0 1305.4 15973.1 27 4~9··3--··178120·. 3 ·t.7509re; 95fh·"t···
4301.2 1977.9 1246.5 1031.5 1000.2 873.9 914.1 7287.0 238~)9. 3 16351.1 18016.7 8099.7
3056.:::; 1354.7 931.6 786.4 689. !:j• 627.3 871.9 12889.0 14780.6 15971.9 13523.7 9786.2
3088.8 1474 .. 4 1276.7 1215 • ..a ·1H:O. 3 · ·1041 .4 · -12-11-.-2· ··1·1-·672...--2 ··2&Cr&9-~ 2··-2-3-4-30·f"4---1:~-l·U.-6-·13&7S·r3--·~~·· ·· ·-
5679.1 1601.1 876.2 757.8 743.2 690.7 1059.8 8938.8 19994.0 1'7015.3 18393.5 5711.5
2973.5 1926.7 1687.5 1348.7 1202.9 1110.8 1203.4 8569.4 31352.8 19707.3 16807.3 10613.1
5793.Si 2.445.-3. . 1979 •. 7 1577.9 .J..a6-7 .. 7 ... ;t.a&b. 7 ··1408-.4 -11·2.J-1-• ..§--17-2-:;L7 . ..-2---·:J:..&3-8·~H·2-+341£r-1--· ·'74-3-~.&-·--····
3773.9 1944.9 1312.6 1136.8 1055.4 1101.2 1317.9 12369.3 22904.8 24911.7 16670.7 9096. '7
OCT NOV DEC
~--~-~4~1T+--·~·-94.-5--~--~·04··t 3
2761.4 918.5 716.3
3634.8 1607.9 1110.2
---44().8--.-s---243-l-. 6-----8-71. ()
2862.1 1109.4 874.1
2379.1 1356.7 1064.1
---.;¥r7~..9---1:-re-2 • 7 7-Br~ 5
2642.6 1519.0 1280.8
3902.2 1938.5 1273.5
--2548. 4 ·l:-~1-7-.-5-·· 725·. 3
3801.4 1590.0 1155.3
4340.1 1669.3 1267.0
------·---~.S.S....-4----~-·-· :tA-21-~ 7
4420.9 2223.8 1423.8
3951.0 1337.6 901.4
... 3259-.0 1-9--4.-b..-2 93-2. s
3277.9 1043.5 784.9
2394.9 812.5 750.9
.. :.;;t~:i-5T9····-1..§-24-.2 ... 1·3-60-. 6
2462.1 1085.5 628.5
1696.9 830.8 555.8
22-79 d 1604.-3··· 1097.2
4128.9 2091.3 1416.1
3787.1 1708.5 1032.4
2393.7 ··11B9-·r7··· 831+4
2451.8 1253.4 957.1
3661.3 1217.2 675.6
-2091.3 -1218. 1 986.6
4053.2 1783.5 1382 d.::
2664.0 1366.9 951.8
TABLE E. 4 -COMPUTED STREAMFLOW AT SUSITNA 3
JAN FEB MAR APR MAY JUN JUL AUG SEP
60'lr5·---···#-8.-3------4-1-s..-4---···-4.1f4--.-Q..-.----a860, i ! 3328,9 15856, 4 14 ~7 6359,8
659.1 529.0 502.1 993.8 9259.4 16292.1 17060.0 13351.1 13253.3
955.6 685.2 592.9 690.2 3038.5 19311.4 17919.1 13865.3 8721.4
54 3 · ..-5-·· -·4-07"-.-b:------§-24-...&---!+l;-3 • 8 ·· HH3-t..il-G-.·'7·-1·SN-9-r-0-4 4 56 8 • 7-12 8 3 ~h-3-· 7-9 3 3 , ?
880.0 610.2 499.4 656.3 6227.6 13821.2 13676.0 14857.0 5487.7
990.8 708.1 676.6 686.9 4170.3 20004.4 20092.8 21369.2 12622.8
·&&7 -+ 4 ----s-4 +.-o----453-.-e-~---·-4-94-.~ ---e-3 4 2 • 6 --rH: 2 9 • .; 2 o 6 -r 9 • 8 13 e 8 o • s----e 16 3 • 5
1032.6 884.3 675.4 695.4 6675.3 20489.7 16656.5 14161.2 9983.4
1006.0 781.8 802.6 1003.3 7075.7 18569.2 16689.2 15222.2 4439.4
7 21 • 5 -s 9 s .. 2---4-1-3 .e .. --s 28. a---~-44:1-&.-s~1--3-4-4t-M7--1-6-<7-7-e--.·2 1 6 8 4 8 .-&--~&1-f>-"'h--7------
964.9 832.2 730.1 844.6 10364.3 10983.7 16103.2 15143.3 11751.6
1121.5 864.9 861.8 1294.0 9991.8 16254.2 15206.1 16913.9 6988.2
1-3~3.-8.---~-1019 .. ~-----9-~-v-2---1--2·-i--9-. 8 10 l 02.6 289:1:2.2 21..Q.S/:,. 4 1/:,299 '0 9666.6
1023.8 875.7 769.5 724.4 11644.6 15435.6 23249.8 18407.0 9311.1
660.0 601.0. 440.2 476.1. 2865.4 35261.7 17274.1 11705.2 5519.1
76 7 • 9 .... -b8 7 .-l-~ -71-6--.-~ ' 1 :l 0·7····4--·-89·&3.~·-:1-6-1"·9 h-9-4~-~-;--2--+3-1-6-5-r&--
727.7 675.7 675.7 910.6 4595.2 19072.3 12522.6 13042.4 6730.0
712.5 670.1 585.3 538.9 9690.7 20011.7 17272.9 19721.9 10541.0
126--1 *-7-:1.227 o7-·---1227o·-7-·--l2-:}j0-.2---9~-h-7---1-9J;l.:;z.7,-2 17834 •+ :1: :1: 1&6---.-7--.e544.~9'---
516.6 494.4 5~8.6 1018.3 7612.7 12455.5 13612.6 6687.4 3444.0
452.3 439.5 475.4 894.6 7730.5 10254.4 14246.9 12623.4 5365.9
7 5-9 • 2. 1·9871-,&-·2--2-4-0-+.·1-·-1-tP,_,-6-{h-5--·~7-4,4 ~--9-9-8-3--.-B-·----524 t1 48-9··d) ... 5¥f{h 9
1114.4 10177.0 20571.5 16930.8 15765.3 9540.9 965.8 91.8.3 909.0
866.4 6358.4 19999.0 14491.0 15789.9 7145.3 804.5 750.4 803.5
70&+ 6 96-65+-2 -1+7-5-+•·;3---i-320 1 r&-~&.2-.-5--· ·7·3-7.:.;~-• ..:;----·-· 6~4.6 ·--5·32-.-6 ··-·7:54 t-3
921.8 8069.4 21183.0 19228.4 12223.6 9906.6 757.0 690.1 837.3
546.0 5332.7 15697.4 15129.9 17015.6 4566.0 340.7 485.6 733.1
8 78 • 1 4 54 2 • 7 2.4.87-.Q.-...-f ..... J;.~ .• 2--1-44-2-4 ... -3 . --86-2-:f---. 7--·-·-796.2-729 • .6--736 • .0
1135.9 10527.7 15540.5 15804.2 10494.9 5688.4 875.3 915.4 1120.8
881.8 10899.3 21155.9 21024.3 12958.6 7457.5 829.4 1004.4 1188.5
TABLE E. 5 -COMPUTED STREAMFLOW AT VEE
OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP
3005.9 1553.7 882.3 590.2 486.4 402.6 478.5 5627.1 130'70.3 1!:.i578.3 13765.5 6279.8
2716.6 902.8 700.5 646.7 517.0 492.3 968.1 9060.2 16106.6 16832.8 13090.5 12924.()
3~!55. 0 1561 ~· 0 1077+6 929.0 672.2 581.1 ·6&0. 7· 2940.3 :l:. 8 7·'9-2-~ 9-17l569r8 t3574
4252.1 1971.2 836.8 520.6 390.6 512.3 U.34.8 105~5.2 15261.4 14336.5 12512.6 752'7.0
2749.0 1068.5 848.3 862.7 594.1 487.8 632.4 5771.8 13349.9 13400.4 14393.4 5181.2
··czss.e ···i2"9fh 8···· ·1023 •7 ·95'7.-7 679·.6·-··659·.-1:·······665 ··7 ~-;;r95i3-•i7····r7·5%•-tr-· .. t97·~·-9---.Z l+tte .-t.s--·1 2554--d:t--··-
3201.6 1257.2 761.2 643.8 526.4 433.8 472.5 7958.4 20625.9 20250.5 l.3447.6 7744.3
2512.1 1455.9 1245.3 1025.9 858.9 653.8 6'74.6 6383.6 20090.9 16382.1 13898.2 9578.6
3724·•·5 1 85'5+"4 1191 + 4 966.5 760.1 788.4 981•·5 ·6835·•·5 ·tS27 -1 49.2 0.-4 ·--4-31:+·.-:r---~--
2455.1 1283.2 692.8 691.5 56(?. 0 390.3 499.1 3933.0 13033.6 13710.3 16257.6 7"741.2
3b87.7 1538.0 1112.2 928.6 806.6 710.8 825.8 101.41.0 10796.2 15819.6 14'795.0 11390.4
"' -41-,9 :;'-. :;'. ····· ' 16·1-4 -.--4 . 1208·~ 2 1066.6 . 828.2 -s;c7: -~· 7 -~-·1·2 :3 s ·~·· 1. .,.... 9 6 e s~-{)---1.-.f!r7 ·t.o-rtr-+4-&~&---~o.O.---6-tL~s.~--·--;....
3281.0 1800.0 1400.0 1300.0 1000.0 940.0 1200.0 10000.0 28320.1 20890.0 16000.0 9410.0
4326.0 2200.0 1400.0 1000.0 830.0 7-SO.O '720. 0 11340.0 15000.0 22790.0 18190.0 9187.0
3848.0 1300.0 877.0 644.0 586.0 429.0 41>5.0 2806.0 346 30'"'.-o-·-1:;;4>40. o--·1·Hr4(h <t-··· ~--5&52. o.-----
3134.0 1911.0 921.0 760.0 680.0 709.0 1097.0 8818.0 16430.0 18350.0 13440.0 12910.0
3116.0 1000.0 750.0 700.0 650.0 650.0 875.0 4387.0 18500.0 12220.0 12680.0 6523.0
~-322.0 ··· ·78-o-~-o . 72fl + 0 680 .o. 640 .o ---56-0rO· ··-513r0 · 9 45 2-.-o---H6~0-.t>-4&8~·--i-9-·t-9.0 r<f-·-':1:42BGr~---·
3084.0 1490.0 1332.0 1232.0 12'00 + 0 1200.0 1223.0 9268.0 19500.0 17480.0 10940.0 5410.0
2406.0 1063.0 618.0 508.0 485.0 548.0 998.0 7471.0 12330.0 13510.0 6597.0 337f.).()
. :l638 .o 815.0 543+0 437.0 426.0 46·3. 0 -887.0 ·7580.-0 .t:;.t:;fJ-9· + 0--t-3 9·(Hh 0-.. t.f!-3*~·0·· -~2-1-1-rO-·---~--
2155.0 1530.() 1048.0 731.0 503.0 470.0 529.0 t91ei.o 21970.0 18130.0 22710.0 9800.0
4058.0 2050.0 1371.0 1068.0 922.0 881.0 876.0 96<7'4.0 20000.0 16690.0 1~i620.0 942~L 0
·'-3144. 3 1666.0 HH4. 6 8S2.b 788.2 ··7·4(h1· 1-94.3 ' 6 2 81 • f> -· 1 9 677-.--3"-.. 1-43-36.<1·-·HS6{}4-~-3 .. ··· ~7.06-5.-H-----·--
2338.5 1176.0 823.0 693.5 597.5 524.7 744.5 9396.5 11502.1 12970.6 10662.4 7171.6
2398.7 1235.0 930.5 897.3 727.6 660.8 806.1 7769.2 20724.2 18878.2 11981.7 9642.5
.. 3493 .. 1 ·118-5. 2 658.9 528.4 523.8 468.-5 . 7~q .•. 5 5032 .. 2 15339.-4--14972 +"S--1-4-9 .. o.o ..... s 447--0. 5
2017.8 1159.1 928.2 8~8.9 ?62.3 697.8 697.7 4207.1 243~0.5 16351.0 14225.7 8462.2
3908.1 1711.7 1333.1 1099.1 842.8 887.0 1096.8 10469.1 15395.8 15589.1 10251.8 5568.0
2571 .• -s 131-8.7 92.1.7 . 8.,£.{) ... o 81() ,.,£. ... ····9·9-6-.·3-. . 117::)., 7 1 0·7·7ftt..S--·2-l-O·l.0.-.-2---2.(h7-.0.0-.. ~---:l-2049 .... ~ ---7-~ .. 9
OCT
1851.5
1579.9----
2043.6
2392.9
1778.3
1408.2
1961.5
1932.0
2327.0
1589.4
~~482.~}
2817.8
2144.1
2472.0
2179.0
2182.7
1862.1 ..
1891.8
2256.2
TABLE E. 6 -COMPUTED STREAMFLOW AT MACLAREN
-------------·--·--·---------------------
NOV DEC .JAN FEB MAR APR MAY JUN JUL AUG SEF'
930.0 557.2 340.3 308.0 229.9 296.0 3345.8 8595.6 11824.2 9947.8 3932.9
529-.-7~08--.-8--348-.-9--2-7-9-v-7--27-6--.-2--566,..-3-5-4-2-0-.9-1-0605r6-1-2·6·31-.-5--9898-.-4-817-4-.-3:---
845.0 583.8 544.9 436.3 384.7 441.3 2224.2 12442.8 13272.1 10301.1 5261.9
1158.0 490.4 326+4 240.8 288.2 705.7 7047.4 11176.5 11218.7 9206.1 4547.9
6 2 0 • 8--4 8 3-.-7---5 3 2-.-7--3 6 3-.-1--3 07-.-0--3 6 8-. 5-3 61-6 .-3--89 7 5. 5-1 0 54 6-.4-10 52 8 • 9-3 3 6 8-. 0------.
818.3 562.2 532.8 370.2 379.6 390.1 2753.9 13038.6 13381.9 15813.8 8225.5
709.6 454.1 416.2 285.3 263.4 289.2 6372.9 18316.8 16750.4 13544.8 6560.6
. 104 0. 5--783-.-2---5-7-6-.-9--484-.-6--35-9. 4 4 36-.-9---4--7-08-.-5-1-55-9-0-.-9-1-3406-.-0-1-1-54 0-.-4-6402-.-9---
1144.3 675.6 539.7. 411.7 406.7 541.0 3596.5 12617.6 12274~8 10132.9 2922.4
773.2 394.3 364.6 290.4 191.3 238.7 2704v8 10668,2 11497.9 11475.1 4747.3
1093.8 ·---805. 5-------65-1--.-9------529.3 --462-.--0--50ti. 6---6262.-8--762 h-9-1-1·94 7-.-9-10863. 7 --7637.-0------·
1069.4 794.1 646.6 510.0 513.4 768.1 5845.7 10400.8 10970.3 11305.8 4423.9
1160.5 851.8 717.6 566.0 528.9 674.7 5544.5 17338.0 14797.4 12262.2 6120.5
···12 3 5-.-0--7-7-7-.-6---571-.8--4 9 6-.-0---440-...7!--4 2 8-.-8-6 72·2-.-3-1-0296-• .:/-1-5-7-7-2-.-4-1-36 3 3 .-4-61 9 6-.-1----
723.3 481.9 356.2 331.3 246.9 273.7 1723.4 21497.0 11636.6 8679.0 3799.5
1220.7 554.4 451.7 405,9 422.9 653.3 5189.9 9701.9 11729.8 9057.0 9509.7.
-600.3 -·------458. 8---420.-2-393 .-1--393-.-1-----~135.-3-2812-.-2-1·1847 .-9---997-4 .-3-·9112-.4-4625-.-6-·--
637.5 504.2 485.6 411.5 430.0 362.0 6395,0 13647.0 13610.8 13784.5 6087.5
926.3 771.4 674.9 694.7 708.5 648.9 4428.6 12364.3 14259.6 10303.3 3572.5
. 1431.9 ... -629.6------363 . ....,3--300 ..... 7--288 ..... 0--3-1-7-.... 9--ti58 ...... 9~21-4....-6-9-9-4.() ...... 9-1-H-88 ...... 9--506 7-•-9--2711-..-9
1274.8 635.7 426.5 338.8 308.9 308.8 562.7 4513.7 7113.4 10790.3 883~.6 3346.7
1226.0 881.9 607.2 410.7 287.2 270.1 304.0 1180.7 14049.7 13721.9 15681.0 6081.6
2334.2 . 1152-. 4 -----BO!"i-..-1--651-. 7---.... _;,po . ...-8--541 ..... -3 . -5~W. 0 ----6139-.-0--1.-2326.....-9---1312-7 • ..0--1-164 8 • 1--5628.-7------
1987.2 907.7 555.7 467.4 431.8 404.9 428.1 3289.5 11719.7 10915.7 10844.3 4427.3
1503.4 768.3 562.1 474.5 411.1 359.3 469.0 5482.0 8156.0 11015.7 9879.9 6189.7
2248 +1 914·•-1--616-.-7--556.-2--426--..-3-39-'l-.-7--460.-0--4269-.-4-1-29-1 0 •. :=-j-l-:':iOl-3-.. -6-9305-.-6----6175 .-7---
2377.3 722.6 379.2 290.6 280.1 252.4 382.3 3189.5 9971.8 11309.9 13006.1 2958.2
1376.1 763.9 587.2 511.8 464.1 431.3 439.8 2660.2 15150.2 12730.3 11915.6 5747.0
2:432.1
.1597.1
·11 06 .-6---822-.6-----6'70-.-:?.--532-.-9-· -52.1--.0--620 .-7-5650-.-9--96()2. :5-H 822.-7---9333.-7--4456.8------
830.1 573.6 519.4 478.5 543.3 648.0 6216.9 13381.5 14307.2 10667.2 5717.0
TABLE E. 7 -COMPUTED STREAMFLOW AT DENALI
OCT NOV !IEC JAN FEB MAR APR MAY .JUN JUL AUG SEP
1493.5 618.9 398.2 219.4 220.1 149.6 218.8 2531.9 6232.7 10078.0 8015.0 2478.8
·· 89 9. 0 --·-3·10-.-2--250-.8--1-7·3--.-1--14 7-.--9--1-Sh-8--363-..-7-3-4 5·6-.. -3---7-J 89-.-2-1-0352-.8-8506 .-S-5878 .-o-·--
1216.4 488.0 338.6 359.1 309.3 282.9 298.1 2065.4 9767.3 11392.7 8965.7 3758.5
1600.3 780.5 362.2 269.1 193.9 166.9 . 456.8 5754.4 9952.4 9773.4 7960.8 3494.4
1485. s 4 42. 3----309.4---35 h-6---2:;·1-.-6--·215-. 9-.. -~!6-~-.--5--3-7·57•·7-7509.-7-946 7·.-o -·9416·.-6 ---:n 89 ··B---.. --.
1247.9 680.9 371.8 341.6 248.0 237.1 264.7 2669.5 9680.5 9760.9 12473.6 5239.0
1297.5 396.4 305.7 296.6 172.0 212.7 224.6 6666.0 18527.2 15779.2 15313.5 7290.9
.2000 • .2 ·-··972..-3---573 .-3--3·4·2· 6 30-h-4--22-h-9------i:~38-.-7-4 57-7.-1-13750-.-6-1-22-30-.-0-10 7 8 5-.-2--5 58 0·.-9----
1963,6 931.1 605.1 371.8 233.7 175.0 294.4 2090.9 9503.0 10136.3 7701.8 2374.6
1299.5 522.6 295.5 234.7 193.9 131~9 . :t!:-17.9 3626.7 10464.8 9754.3 101(;f.j,f 3902.4
2016. 2 ·· ... 960. 7--·-·-7 4 :h-4 -------584 .-2----41.9. 7-·-34 9-.4---33/-.·6--42 :1.-1:.-B 59 61 .-3---1013 4-. 5 .... 9255.6 6212 .-3
2331.2 872.0 710.3 543.0 412.6 432.1 631.0 4132.8 8514.2 9569.8 8079.2 3711.7
1693.2 817.7 547.1 371.8 316.5 290.4 356.5 2593.3 11374.3 10978.9 10609.2 4640.4
1445.7 601-.8--40 l-. 8--~~·H-.8--329. !:i---·--236·.·7---2.;.?.6·.-8--4429-. 6-8446.0-.1-2276-.-3-11 048·. 4--4428·.-3-----
1323.0 435.4 279.4 201.8 198.1 153.5 172.8 1139.7 14070.3 8481.2 7306.3 3278.5
1951.0 837.9 323.4 250.6 227.5 237.2 360.2 3102.3 6068.4 8208.0 6939.0 7940.3
154 5. 6 468. o ---3 7 4 ;g. -··--3:1. 7-.--1.------299. ~i ------299-.ei----4 :J.-7-.:l-243 3. 5·---9060. s---94 ss. 9-·---7832. o --3 9 9 9 •. 7 .... -------
1850.3 655.9 461.4 465.1 356.1 430.2 348.6 5020.6 10672.6 12672.4 11778.1 3946,0
1912.1 634.8 460.8 371.0 422.1 446.4 322.7 1850.2 8846.9 13207.8 10778~2 2713.1
. 91 b. 6 390 .. 8 -·21 2-.-4--1-78-.-0--l-76-.-4--1-86-.-0--30-7-..-3-23:1.5.-6--863:1.-.0-984·1-.-3--4268.-1---2475-. 7---
:t229.4 562.2 388.4 324.2 273.3 240.9 348.5 2/91.4 6347.3 9/94.3 /388.0 2544.2
1007.3 682.2 466.0 278.8 206.5 193.4 219.6 909.0 9775.9 11300.5 11807.6 3997.9
LH 2. 7 637. 6. .... -554 .•. :;---·-5 H~. 2---4 7 6. 2---430-.-1.----39.7.6--53.34 • 0----8769. 8 ·--l-1-380. 2---9225.5 -· 323~5. 5----
832.5 409.8 279.9 231.2 22/.0 192.8 188.6 1341.0 6983.8 8944.8 7984.9 2?52.3
1089.4 515.1 398.3 337.6 298.5 265.5 299.9 3578.9 6616.3 10438.9 10142.3 6229.0
234 (). l. ... /44 .. 1-----483.--9----3<.1-4. 7--·:s 1.3-+./---3-1.-3-.-1.--3-:~.() ... A.---27-9-9-t-9-8812-•. 6--1.3-462-.. 8-8229-. 6---4591. :1.----
2188.6 498.6 233.6 180.2 162.2 156.0 221.8 2965.9 7322.2 9165.0 10523.6 2190.8
1178.0 695.1 556.6 417.5 370.9 353.7 396.3 2794.4 10339.8 11007.4 10947.2 4346.2
1708.4 9:?.9. 4 ------63L-2 ----490 ;3--426 .... 3---355 •. 9 ----355 ... 6-225-7 .. 6--5809 .. 1-~823. 9----9583.1----4087.0---
1222.3 649.1 428.2 345.1 301.7 234.2 291.7 3264.3 8213.0 10755.5 10373.0 5039.7
TABLE E.B-RESULTS OF SCREENING MODEL
Total Demand First Second
Cap. Energy Site Site Site
Run MW GWh Names $ Names Names $
400 1750 High 15BO 400 885 Devil 1450 400 970 Watana 1950 400 980
Devil Canyon
Canyon
2 800 3500 High 1750 800 1500 Watana 1900 450 1130 Watana 2200 BOO 1B60
Devil
Canyon
Devil
Canyon 1250 350 710
TOTAL 800 1B40
3 1200 5250 Watana 2110 700 1690 High 1750 BOQ 1500 High 1750 820 1500
Devil Devil
Canyon Canyon
Devil 1350 500 BOO Vee 2350 400 1060 Susitna 2300 3BO 1260
Canyon III
TOTAL 1200 2490 TOTAL 1200 2560 TOTAL 1200 2760
4 1400 6150 Watana 2150 740 1770
N 0 S 0 l U T I 0 N N 0 S 0 L U T I 0 N
Devil 1450 660 1000
Canyon
I!)
Q .. -t;;
0 u
......
!.OQ
,. -.....
(/)
0 u
800
200
1000
LEGEND
a COST DEVELOPED DIRECTLY FROM
ENGINEERING LAYOUTS
O COST BASED ON ADJUSTMENTS TO
VALUES DETERMINED FROM LAYOUTS
OL---~--~~----~--~----~----~~~ 0 200 400 600 BOO 1000
REsERVOIR STORAGE ( 103x A F )
DEVIL CANYON
1500 1500
1000
500
1000 2000 3000
RESERVOIR STORAGE ( to 3 x A F)
HIGH DEVIL CANYON
DAMSITE COST VS RESERVOIR STORAGE CURVES
FIGURE E .I
2400
2000
ci)
g 1600 .. ....
~ u
400
1860 LEGEND
• COST DEVELOPED DIRECTLY FROM
ENGINEER lNG LAYOUTS
COST BASED ON ADJUSTMENTS TO
O VALUES DETERMINED FROM LAYOUTS
0~--~----~--~~--~~~~~~~--~~--~ 0 2000 4000 6000 8000 10000 12000
RESERVOIR STORAGE ( I03x AF)
WATANA
1500
1390
1000
IOQ
>< -1-
(/)
0 u
500
!000 2000 3000 4000
RESERVOIR STORAGE ( 103 x A F )
SUSITNA JII.
DAMSITE COST VS RESERVOIR STORAGE CURVES
FIGURE E.2
lj
1000
800
~ 600
)( ...
Iii 8 400
200
800
600
~
)( -~ 400
Iii
0 u
200
~500
~
1060
LEGEND
e COST DEVELOPED DIRECTLY FROM
ENGINEERING LAYOUTS
COST BASED Gl ADJUSTMENTS 10
0 VALUES DETERMINED FROM LAYOUTS
0~--~----~----~--~----~----~----~~
800
~ 600
t.OQ
><
1-400 8
200
0 200 400 600 BOO 1000
RESERVOIR STORAGE ( 103x AF)
MACLAREN
1000 2000 3000 4000
RESERVOIR STORAGE ( 10 3 x AF)
DENALI
5000
DAMSITE COST VS RESERVOIR STORAGE CURVES E.JiJ FIGURE
OLSON DEVIL
CANYON
DEVIL
CREEK WATAt>IA
GOLD CREEK
OLSON
DEVIL CANYON
HIGH DEVIL CANYON
DEVIL CREEK
WATANA
SUSITNA m
LEGEND
COMPATIBLE ALTERNATIVES VEE
D MACLAREN
MUTUALLY EXCLUSIVE ALTERNATIVES
DAM IN COLUMN IS MUTUALLY EXCLUSIVE IF FULL
SUPPLY LEVEL OF DAM IN ROW EXCEEDS THIS VALUE-FT.
VALUE IN BRACKET REFERS TO APPROXIMATE DAM HEIGHT.
VEE MACLAREN DENALI
DENALI
BUTTE CREEK
TYONE
MUTUALLY EXCLUSIVE DEVELOPMENT ALTERNATIVES
BUTTE
CREEK TYONE
APPENDIX F -SINGLE AND -RESERVOIR HYDROPOWER SIMULATION STUDIES
The economic comparisons of various Susitna Basin dam sites described in Section
8, both individually and in combination, were accomplished to a large extent
through simulation of energy availability from a given development. The purpose
of this Appendix is to describe the two computer models which were used to
simulate energy yields according to the storage and hydrology available at the
various dam sites.
F.l -Introduction
The reservoir simulation models determine the energy yield from the Susitna
developments given using inflow data for the thirty year period from 1949 to
1979, the installed capacity at each hydro plant and a specified annual energy
demand pattern and plant factor. The total energy supplied by Susitna was ·
assumed to be a fraction of the forecast electrical system demand for the Rail-
belt region as discussed in Section 5. The monthly distribution of the gener-
ated energy is assumed to be equal to the monthly peak load multiplied by the
load factor in that month.
Environmental constraints incorpo;ated into the model include a maximum seasonal
reservoir level fluctuation, a maximum daily reservoir fluctuation and a minimum
downstream flow requirement. These constraints are preliminary at this stage
and are only used to provide consistency between energy estimates at the
respective dam sites.
F.2-Single Reservoir Model
(a) Energy Demand
The simulation model is driven by an energy demand curve and will attempt
to meet this demand in each month. A icit is noted when the demand is
not met and a failure of the system is recorded. If the number of failures
in the study period is excessive, the energy demand is too high for the
system and another simulation must be made with a lower energy demand.
This process is repeated until deficits are recorded in none or in only one
year of the simulation.
(b) Utilization of Month Inflow
The average monthly inflow in any month is utilized as follows in order of
priority:
-Powerhouse flow to meet demand;
-Fill reservoir;
-Generate secondary energy; and
-Spill.
If inflow is inadequ to demand energy under constant head condi-
tions, then storage from the reservoir is used to supplement the inflow and
the reservoir is drawn down. Conversely if available inflow exceeds power
demand needs, the reservoir storage is replenished by any surplus inflow.
F-1
(c) Actions at Reservoir Boundary Conditions
Under boundary conditions of either minimum reservoir level or maximum
reservoir level, the following actions are taken:
(i) Minimum Reservoir Level
Turbine discharge is assumed equal to inflow plus the storage avail-
able to reduce the reservoir to the minimum level at the end of the
rnonth. If discharge is inadequate to meet the energy demand, a fail-
ure is recorded.
(ii) Maximum Reservoir Level
When the reservoir is full, the total capacity of the plant is theor-
etically available if the inflow is adequate. Consequently, the dis-
charge is set equal to the inflow except when the inflow exceeds the
installed capacity. In this case, the discharge equals the plant
capacity and the surplus water is spilled. Energy generated above
demand is designated as secondary energy.
(d) Simulation Procedure
(i) Monthly Simulation
The model computes the discharge that will give the energy demand for
the head available. If reservoir storage is depleted or replenished,
an iterative process is used to determine the combination discharge
flow and head necessary to meet demand. For these preliminary
studies it has been assumed that if the energy4·generated is within 5
percent of energy demand for single reservoir and 1 percent for
multi-reservoir, the result has converged sufficiently.
As noted earlier, a deficit is noted when energy generated does not
meet energy demand. Because of the nature of this system, a deficit
can only occur when the reservoir is drawn down to the specified min-
imum level. However, energy is generated since the powerhouse flow
is assumed equal to inflow, giving no change in reservoir level.
(ii) Daily Simulation
The monthly simulation has superimposed on it a daily requirement due
to peaking operation. The operation has been divided into base load
capacity, peaking capacity and secondary capacity. The peaking capa-
city has been assumed to be needed for 10 hours.
Baseload capacity and peaking capacity are determined so that the sum
of each daily generation for any month equals the energy determined
in the monthly simulation. In effect, monthly peaking capacity is
equal to the ratio of monthly peak to annual peak given in Figure F.l
multiplied by the nominal installed capacity. Baseload capacity is
variable and determined to produce the necessary energy to make the
daily operation consistent with monthly energy values. Secondary
capacity
is only used when the reservoir is full and would have to spill.
Secondary energy is assumed to be generated for 24 hours by the dif-
ference in installed capacity and the sum of base load and peaking
capacities. Secondary energy can also be produced during the off
peak period by the capacity difference between installed capacity and
base load capacity.
A lower limit on baseload powerhouse flow is the constraint of mini-
mum downstream flow which must always be met except when necessary to
violate the minimum reservoir level boundary. If baseload powerhouse
flows have to be set equal to downstream flow requirements, then
peaking period powerhouse flows must be reduced to maintain the
monthly energy balance. A peaking capacity deficit is therefore pro-
duced and this event is recorded and printed.
F.3-Multi-Reservoir Simulation
The multi-reservoir simulation follows the same operating rules as the single
reservoir program except that the energy demand in a particular month is allo-
cated to each hydropower plant according to the reservoir status in that month.
This allocation rule prevents the storage of water in one reservoir when another
reservoir is being drawn down. The allocation of the energy demand between res-
ervoirs is given by:
H ..
E .. = E. lJ
lJ J H.. lJ
where: E· J = the energy demand in month J
E .. = the fraction of the energy demand in month j allocated to lJ the hydropower plant i
H .. lJ = the net head in month j of the hydropower plant i
Hij = the total head of the cascade in month j
After this allocation, the single reservoir operating rules are applied for
every hydropower plant. The reservoir is checked for its final status solving
the same nonlinear system of inequalities iteratively for every month of the
simulation period.
F.4 -Annual Demand Factor
An annual demand factor is initially specified to enable an estimate of the
monthlY energy demand to be made for a given installed capacity and monthly peak
to annual peak ratios. The intention of this demand factor is to allow easy
adjustment to the energy demand curve which drives the simulation program.
F-3
Adjustment of the specified installed capacity would also adjust the energy
demand curve if the demand factor was held constant. Consequently, the demand
factor used coupled with installed capacity must be considered only as a means
of determining the energy demand that can be supplied by a given hydropower
system. Environmental constraints and hydrology (shortages and surpluses) lead
to an actual plant factor which is slightly different than the nominal demand
factor specified to determine demand.
F.5-Input to Simulation Models
Input to the simulation models has been determined from existing definitive
studies of the Susitna Basin hydro potential and from published and unpublished
USGS records. Input to the model can be classed under three main categories:
reservoir and power generation facility description, energy demand curve and
inflow records.
(a) voir and Power Generation Facilities
(i) Reservoir Storage -Elevation Curves
The storage curves for the seven dams identified in the Susitna
Basin screening model have been determined from 50 foot contour maps
of the reservoir areas being studied.
(ii) Reservoir Storage Constraints
Due to the possible environmental limitations to seasonal and daily
draw down of the reservoirs, tentative values have been set to allow
consistency in comparisons. The maximum daily reservoir fluctua-
tion, due to peaking operation, has been set at five feet. Seasonal
fluctuations vary according to the sized reservoir. The fluctua-
tions assumed are given in Table F.L These constraints may be
changed due to more information on and analyses of, the
environmental impact of these fluctuations.
(iii) Downstream Flow Constraint
This constraint only affects daily peaking operation. As such, it
occasionally limits the plant cap ility to produce either full or
demand power. The flow constraint has been set so that the plant at
least gives approximately the historical nter flow in the reach
immediately dovmstream of the dam site. Flow constraints are given
i n Tab 1 e F • 1.
(iv) Installed C
Installed capacity for each of the dam sites has been determined
from the plans identified during the optimum screening of Susitna
Basin developments (Appendix E). In some cases phased powerhouse
alternatives have been considered and qre usually 50 percent of full
development. Installed capacities considered are given in Tables
F.3andF.4.
F-4
(v) Tailwater Elevation and Efficiency
Average tailwater elevations have been determined from topographical
maps and from information contained in reports of past studies.
Tailwater elevations are given in Table F.l. The assessment of more
precise tailwater elevation rating curves developed during later
stages of the studies and further definition of channel geometry at
selected development sites will be undertaken during detailed pro-
ject feasibility studies.
Combined efficiency of generators. turbines and penstocks, etc. has
been assumed to be 81 percent. This value is conservative and is
believed to be a reasonable assumption for these initial assess-
ments.
(b) Energy Demand Curve
This distribution has been taken from studies of the Railbelt region energy
growth as discussed in Section 5. The distribution selected is that for
1995 under a medium load growth scenario and is given in Figure F.1.
(c) Inflow
The streamflow network of the Upper Susitna Basin consists of three gages
at Gold Creek (2920), Cantwell (2915) and Denali (2910) on the Sus itna
River and one at Maclaren on the Maclaren River (2912). The longest record
is at Gold Creek, which has 30 years of record from 1949 to 1979. The
others have shorter, intermittent records.
The records at the three gages with less than 30 years have been extended
by correlation with streamflows at Gold Creek. To estimate the streamflow
at each of the proposed dam sites, a relationship between drainage area and
upstream and downstream gage streamflow was determined. Basically, this
relationship was used to estimate the streamflow at a dam site by adding
the nearest upstream gage records to the flow difference between the
nearest upstream and downstream gages which were prorated to reflect the
drainage area at the dam site with respect to the nearest downstream gage.
These streamflow relationships are given in Table F.2. Streamflows at each
dam site for the 30 year period are given in Tables E.1 to E.7 of Appendix
E.
F.6-Model lts
The screening model identifi potential Susitna developments consisting of
either single darns or multi am developments (Appendix E). The main dams con-
sidered optimum for development are il Canyon, High Devil Canyon, Vee and
Watana. The optimization process indicated that Watana and High Devil Canyon
would be first stage developments in multi-dam development schemes. Second-
stage developments would result in a Watana/Devil Canyon plan and a High Devil
Canyon/Vee plan.
F-5
Adjustment of the specified installed capacity would also adjust the energy
demand curve if the demand factor was held constant. Consequently, the demand
factor used coupled with installed capacity must be considered only as a means
of determining the energy demand that can be supplied by a given hydropower
system. Environmental constraints and hydrology (shortages and surpluses) lead
to an actual plant factor which is slightly different than the nominal demand
factor specified to determine demand.
F.5-Input to Simulation Models
Input to the simulation models has been determined from existing definitive
studies of the Susitna Basin hydro potential and from published and unpublished
USGS records. Input to the model can be classed under three main categories:
reservoir and power generation facility description, energy demand curve and
inflow records.
(a) Reservoir and Power Generation Facilities
(i) Reservoir Storage -Elevation Curves
The storage curves for the seven dams identified in the Susitna
Basin screening model have been determined from 50 foot contour maps
of the reservoir areas being studied.
(ii) Reservoir Storage Constraints
Due to the possible environmental limitations to seasonal and daily
draw down of the reservoirs, tentative values have been set to allow
consistency in comparisons. The maximum daily reservoir fluctua-
tion, due to peaking operation, has been set at five feet. Seasonal
fluctuations vary according to the sized reservoir. The fluctua-
tions assumed are given in Table F.l. These constraints may be
changed due to more information on, and analyses of, the
environmental impact of these fluctuations.
(iii) Downstream Flow Constraint
This constraint only affects daily peaking operation. As such, it
occasionally limits the plant capability to produce either full or
demand power. The flow constraint has been set so that the plant at
least gives approximately the historical \·linter flow in the reach
immediately downstream of the dam site. Flow constraints are given
inTableF.L
(iv) Installed Capacity
Installed capacity for each of the dam sites has been determined
from the plans identified during the optimum screening of Susitna
Basin developments (Appendix E). In some cases phased powerhouse
alternatives have been considered and are usually 50 percent of full
development. Installed capacities considered are given in Tables
F.3 and F.4.
F-4
(v) Tailwater Elevation and Efficiency
Average tailwater elevations have been determined from topographical
maps and from information contained in reports of past studies.
Tailwater elevations are given in Table F.1. The assessment of more
precise tailwater elevation rating curves developed during later
stages of the studies and further definition of channel geometry at
selected development sites will be undertaken during detailed pro-
ject feasibility studies.
Combined efficiency of generators, turbines and penstocks, etc. has
been assumed to be 81 percent. This value is conservative and is
believed to be a reasonable assumption for these initial assess-
ments.
(b) Energy Demand Curve
This distribution has been taken from studies of the Railbelt region energy
growth as discussed in Section 5. The distribution selected is that for
1995 under a medium load growth scenario and is given in Figure F.1.
(c) Inflow
The streamflow network of the Upper Susitna Basin consists of three gages
at Gold Creek (2920), Cantwell (2915) and Denali (2910) on the Susitna
River and one at Maclaren on the Maclaren River (2912). The longest record
is at Gold Creek, which has 30 years of record from 1949 to 1979. The
others have shorter, intermittent reco~ds.
The records at the three gages with less than 30 years have been extended
by correlation with streamflows at Gold Creek. To estimate the streamflow
at each of the proposed dam sites, a relationship between drainage area and
upstream and downstream gage streamflow was determined. Basically, this
relationship was used to estimate the streamflow at a dam site by adding
the nearest upstream gage records to the flow difference between the
nearest upstream and downstream gages which were prorated to reflect the
drainage area at the dam site with respect to the nearest downstream gage.
These streamflow relationships are given in Table F.2. Streamflows at each
dam site for the 30 yea1' period are given in Tables E.1 to E.7 of Appendix
E.
F.6-Model Results
The screening model identified potential Susitna developments consisting of
either single darns or multi-dam developments (Appendix E). The main dams con-
sidered optimum for development are Devil Canyon, High Devil Canyon, Vee and
Watana. The optimization process indicated that Watana and High Devil Canyon
would be first stage developments in multi-dam development schemes. Second-
stage developments would result in a Watana/Devil Canyon plan and a High Devil
Canyon/Vee plan.
F-5
The simulation models were run to estimate energy yields from the single reser-
voir developments (Watana and High Devil Canyon), and then from basin develop-
ments (Watana/Devil Canyon and High Devil Canyon/Vee).
The avera9e annual energy levels obtained from the various development
possible (staged powerhouse, staged dams, etc.) are given in Table F.3
Details of monthly average energy and monthly firm energy are given in
F.5 to F.15.
F.7-Interaction of OGP5
plans
and F.4.
Tables
The final plant factor and the monthly peak ratios or demand curve are deter-
mined in an interactive run with OGP5. Basically, the input of the simulation
results to OGP5 can be assumed to apply to various installed capacities provided
the energy demand curve determined in the simulation procedure is not violated.
OGP5 then selects optimum plant factors (and installed capacity) which then
forms the basis for new reservoir simulation work.
F-6
TABLE F.1 -RESERVOIR AND FLOW CONSTRAINTS
Max1mum DOwnstream Normal
Seasonal Compensation Tail water Ma::dmum
Drawdown Flow Elevation Elevation
Dam (ft) (cfs) ( ft) ( ft)
Devil Canyon 100 2000 880 1450
High Devil Canyon 100 2000 1020 1750
Watana 150 2000 1465 2200
Vee 150 2000 1905 2350
TABLE f.2-DAM SITE STREAMflOW RELATIONSHIP
a1nage
Site Area Discharge Relationship
Gold Creek (g) 6160 Og
Cantwell (c) 4140 Qc
Denali (d) 950 Qd
Devil 'Canyon (DC) 5810 ~c = 0.827 (Q -Q J + a g c c
High Devil Canyon (HDC) 5760 QHDC = 0.802 (Q g -Q ) + Q c c
Watana (W) 5180 Q = 0.515 (Q -Q ) + Q w 9 c c
Susitna III (S) 4225 Q = 0.042 (Q -Q ) + Q s g c c
Vee (V) 4140 Oy = 0c
Denali (D) 950 ~ = 0.153 (Q -Q) + Q g c d
Maclaren (M) 2319 ~ = 0.429 (Q -Q ) + Q c d d
TABLE F.3. SUSITNA DEVELOPMENT PLANS
Stage/Incremental Data
Maximum
Capital Cost Earliest Reservoir Seasonal Plant
$ Millions On-line Full Supply Draw-factor
Plan Stage Construction (1980 values) Date 1 Level -ft. down-ft GWH !;;
1.1 1 Watana 2225 ft 800MW 1860 199, 2200 150 2670 46
2 Devil Canyon 1470 ft
600 MW 1000 1996 1450 100 5500 6230 51
TOTAl SYSTEM 1400 MW "21lblT
1.2 1 Watana 2060 ft 400 MW 1570 1992 2000 100 1710 2110 60
2 Watana raise to
2225 ft 360 1995 2200 150 2670 2990 85
3 Watana add 400 MW
capacity 130 2 1995 2200 150 2670 3250 46
4 Devil Canyon 1470 ft
600 MW 1000 1996 1450 100 5500 6230 51
TOTAL SYSTEM 1400 MW >TlblT
1. 3 1 Watana 2225 ft 400 MW 1740 1993 2200 150 2670 2990 85
2 Watana add 400 MW
capacity 150 1993 2200 150 2670 3250 46
3 Devil Canyon 1470 ft
600 MW 1000 1996 1450 100 5500 6230 51
TOTAL SYSTEM 1400 MW 'Zll9IT
TABLE f .3 (Continued)
umu a ~ve
Stage/Incremental Data System Datq
Annual
Maximum Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$ Millions On-line full Supply Draw-firm Avg. Factor
Plan Stage Construction (1980 values) Date 1 Level -ft. down-ft. GWK GWfl %
2.1 1 High Devil Canyon
1775 ft BOO MW 1500 1994 3 1750 150 2460 3400 49
2 Vee 2350 ft 400 MW 1060 1997 Z330 150 3870 4910 47
TOl Al SYSTEM 1 ZOO MW N1r
2.Z 1 fligh Devil Canyon
1 1630 ft 400 MW 1140 1993' 1610 100 1770 2020 58 z High Devil Canyon
add 400 MW Capacity
raise dam to 1775 ft 500 1996 '1750 150 2460 3400 49
3 Vee 2350 ft 400 MW 1060 1997 2330 150 3870 4910 47
TOTAL SYSTEM 1200 MW 'miT
2.3 High Devil Canyon
1775 ft 400 MW 1390 1994 3 1750 150 Z400 Z760 79
2 High Devil Canyon
add 400 MW capacity 140 1994 1750 150 2460 3400 49
3 Vee Z350 ft 400 MW 1060 1997 2330 150 3870 4910 47
TOTAL SYSTEM 1 ZOO MW 'Z5'lU
3.1 1 Watana 2225 ft BOO MW 1860 1993 2200 150 2670 3250 46
2 Watana add 50 MW
tunnel 330 MW 1500 1995 1475 4 4890 5430 53
TOTAL SYSTEM 1180 MW :mtr
TABLE F.3 (Continued)
Stageiincremental
umu a 1ve
Data System Data
Annua t
Maximum Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$ Millions On-line Full Supply Draw-Firm Avg. Factor
Plan Stage Construction (1980 values) Date 1 Level -ft. down-ft. GWH GWH " ~
3.2 1 Watana 2225 ft 400 MW 1740 1993 2200 150 2670 2990 85
2 Watana add 400 MW
capacity 150 1994 2200 150 2670 3250 46
3 Tunnel 330 MW add
50 MW to Watana 1500 1995 1475 4 4890 5430 53
))9IT
4.1 Watana
2225 Ft 400 MW 1740 1995 3 2200 150 2670 2990 85
2 Watana add 400 MW
capacity 150 1996 2200 150 2670 3250 46
3 High Devil Canyon
1470 ft 400 MW 860 1998 1450 100 4520 5280 50
4 Portage Creek
1030 ft 150 MW 650 2000 1020 50 5110 6000 51
TOTAL SYSTEM 1350 MW )lilJIJ"
NOTES:
(1) Allowing for a 3 year overlap construction period between major dams.
(2) Plan 1.2 Stage 3 is less expensive than Plan 1.3 Stage 2 dtJB to lower mobilization costs.
(3) Assumes fERC license can be filed by June 1984, ie. 2 years later than for the Watana/Devil Canyon Plan 1.
TABLE F.4. SUSITNA ENVIRONMENTAL DEVELOPMENT PLANS
umu a 1ve
Stage/Incremental Data System Data
Arinua (
Maximum Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$ Millions On-line Full Supply Draw-firm Avg. factor
(1980 values) 1 Plan Stage Construction Date Level -ft. down-ft GWH, GWH. " E1.1 1 Watana 2225 ft BOOMW
and Re-Regulation
Dam 1960 1993 2200 150 2670 3250 46
2 Devil Canyon 1470 ft
401JMW 900 1996 1450 100 5520 6070 58
TOTAL SYSTEM 1200HW miT
E1.2 1 Watana 2060 ft 40~~W 1570 1992 2000 100 1710 2110 60
2 Watana raise to
2225 ft 360 1995 2200 150 2670 2990 85
3 \~atana add 401JM~I
capacity and
Re-Regulation Dam 230 2 1995 2200 150 2670 3250 46
Devil Canyon 1470 ft
400NW 900 1996 1450 100 5520 6070 58
TOTAL SYSTEM 1200MW !ll6lr
E1.3 1 Watana 2225 ft 400MW 1740 1993 2200 150 2670 2990 85
2 Watana add 40[1>1\'1
capacity and
Re-Regulation Dam 250 1993 2200 150 2670 3250 46
3 Devil Canyon 1470 ft
400 MW 900 1996 1450 100 5520 6070 58
TOTAL SYSTEM 1200MW "21J9lJ
umu a l.ve
Stage/Incremental Data sxstem Data
Annual
Maximum Energy
Cap]tal Cost Earliest Reservoir Seasonal Production Plant
$Millions On-line Full Supply Draw-Firm Avg. F'actor
Plan Stage Construction (1980 values) Date 1 Level -ft. down-ft. GWH GWH %
£2.4 1 Hign Devil Canyon
1755 ft 400MW 1390 1994 3 1750 150 2400 2760 79
2 High Devil Canyon
add 400MW capacity
and Portage Creek
Dam 150 ft 790 1995 1750 150 3170 41J80 49
3 Vee 235Q ft
400MW 1060 1997 2330 150 4430 5540 47
TOTAL SYSTEM mrr
E3.2 1 Watana
2225 ft 400MW 1740 1993 2200 150 2670 2990 85
2 Watana add
400 MW capacity
and Re-Regulation
Dam 250 1994 2200 150 2670 3250 46
3 Watana add 50MW
Tunnel Scheme 330MW 1500 1995 1475 4 4890 5430 53
TOTAL SYSTEM 11BOMW )7j'q(j
E4. 1 1 Watana
2225 ft 400MW 1740 1995 3 zzoo 150 2670 2990 85
2 Watana
add 400MW capacity
and Re-Regulation
Dam 250 1996 Z200 150 2670 3250 46
3 High Devil Canyon
1470 ft 400MW 860 1998 1450 100 4520 5280 50
4 Portage Creek
1030 ft 150MW 650 2000 1020 50 5110 6000 51
TOTAL SYSTEM 1350 MW J5lJlj
NOTES:
m-Al lowing for a 3 year overlap construction period between major dams.
(2) Plan 1.2 Stage 3 is less expensive than Plan 1.3 Stage 2 due to lower mobilization costs.
( 3) Assumes FERC 1 icense can be filed by June 1984, ie. 2 years later than for the Watana/Devil Canyon Plan 1.
TABLE F.4 (Continued)
Cumulative
Stage/Incremental Data System Data
Mnual
Maximum Energy
Capital Cast Earliest Reser~oir Seasonal Production Plant
$ Millions On-line Full Supply Draw-firm Avg .. Factor
Plan Stage Construction (1980 values) Date 1 Level -ft. down-ft. GWH GWH %
E1.4 1 Watana 2225 ft 400MW 1740 1993 2200 150 2670 2990 85
2 Devil Canyon 1470 ft
400MI~ 900 1996 1450 100 5190 5670 81
TOTAL SYSTEM BOOMW Wiil
E2.1 High Oevi l Canyon
1775 ft SOOMW and
Re-Regulation Dam 1600 1994 3 1750 150 2460 3400 49
2 Vee 2350ft 400MW 1060 1997 2330 150 3870 4910 47
TOTAL SYST£H 1200MW 266ii
£2.2 High Devil Canyon
1 630 ft 400MW 1140 1993 3 1610 100 1770 2020 58
2 High Devil Canyon
raise dam to 1775 ft
add 400MW and
Re-Regulation Dam 600 1996 1750 150 2460 3400 49
3 Vee 2350 ft 400 HW 1060 1997 2330 150 3870 4910 47
TOTAL SYSTEM 1200MW 2Biiii
£2.3 1 High Devil Canyon
1775 ft 400MW 1}90 1994 3 1750 150 2400 2760 79
2 High Devil Canyon
add 400MW capacity
and Re-Regulation
Dam 240 1995 1750 150 2460 3400 49
3 Vee 2350 ft 400MW 1060 1997 2330 150 3870 4910 47
TOTAL SYSTEM 1200 T69o
T~BLE F.>-PL~N 1,1-ENERGIES
STAGE 1 STAGE 2
MONTH Watana (2200)
Add Dev1l Canyon
(1450)
800 MW 600 MW
EA EF EA EF
(GWH) (GWH) (GWH) (GWH)
JANUARY 264 263 542 538
FEBRUARY 2>0 249 514 >11
MARCH 224 224 452 456
APRIL 201 201 394 406
MAY 166 166 418 405
JUNE 187 183 437 383
JULY 265 183 473 373
AUGUST 499 190 707 394
SEPTEMBER 370 204 667 421
OCTOBER 233 233 488 476
NOVEMBER 266 266 544 540
DECEMBER 287 287 591 567
TOTAL ANNUAL 3252 2669 6227 5494
Notes:
EA: Average Monthly Enecgy
EF: Monthly Firm Energy
(2200): Reservoir full supply level
TABLE F.6-PLAN 1.2-ENERGIES
Sl AGE j Sli\GE 3(1) SFAGE 1i
Watana (2000) Raise Watana (2200) Add Oev~l Canyon
MONTH 400 MW Add 400 MW (1450) 400 MW EA EF EA EF EA EF
(GWH) (GWH) (GWH) (GWH) (GWH) (GWH)
JANUARY 13B 137 264 263 542 53B
FEBRUARY 130 129 250 249 514 511
MARCH 117 116 224 224 452 45B
APRIL 103 57 201 201 394 406
MAY 100 100 1B6 1B6 41B 405
JUNE 154 102 1B7 1B3 437 3B3
JULY 322 103 2B5 1B3 473 373
AUGUST 355 365 499 190 707 394
SEPTEMBER 269 1BB 370 204 667 421
OCTOBER 131 123 233 233 48B 478
NOVEMBER 140 139 266 266 544 540
DECEMBER 150 149 287 2B7 591 5B7
TOTAL ANNUAL 2109 1708 3252 2669 6227 5494
Notes:
EA: Average Monthly Energy
EF: Monthly Firm Energy
(2000): Reservoir full supply level ( Ft)
(1) Stage 2 is as For Stage 1 on Table F.6 (Plan 1.3)
TABLE F.7-PLAN 1.3-ENERGIES
~I AGE j SfAGt: 2 SfAGt: 3
Watana (2200) Add 400 MW to Add Devil Canyon
MONTH 400 MW Watana (2200) (1450) 400 MW
EA il" EA EF EA EF
(GWH) (GWH) (GWH) (GWH) (GWH) (GWH)
JANUARY 263 263 264 263 542 538
FEBRUARY 250 249 250 249 514 511
MARCH 224 224 224 224 452 458
APRIL 201 201 201 201 394 406
MAY 186 186 186 186 418 405
JUNE 187 184 187 183 437 383
JULY 245 183 285 183 473 373
AUGUST 333 190 499 190 707 394
SEPTEMBER 315 204 370 204 667 421
OCTOBER 233 233 233 233 488 478
NOVEMBER 266 265 266 266 544 540
DECEMBER 287 287 287 287 591 587
TOTAL ANNUAL 2990 2669 3252 2669 6227 5494
Notes:
EA: Average Monthly Energy
EF: Monthly firm Energy
(2000): Reservoir full supply level (ft)
TABLE f.B-PLAN 2,1 -ENERGIES
stAGE 1 STAGE 2
MONTH High Devil Canyon Add Vee (23.S>)
(1750) BOO MW 400 MW EA Ef EA Ef
(GWH) (GWH) (GWH) (GWH)
JANUARY 235 232 368 368
fEBRUARY 222 219 349 350
MARCH 197 151 303 313
APRIL 173 30 268 276
MAY 169 171 Z.S4 258
JUNE 231 172 290 247
JUlY 480 173 526 319
AUGUST 5>4 307 7>2 298
SEPTEMBER 429 303 >75 280
OCTOBER 219 213 394 366
NOVEMBER 239 233 403 393
DECEMBER 257 2>4 425 401
TOTAl ANNUAL 3405 245B 4907 3869
~:
EA: Average Monthly Energy
Ef: Monthly firm Energy
(1750): Reservoir full supply level (ft)
TABLE F.9-PLAN 2.2-ENERGIES
SfA~E i STA~E 2 STAGE J
Raise H~gh Devil Add Vee (23Jo)
Hi~h Devil Canyon Canyon (1750) 400 MW
MONTH 1610) 400 MW Total 1200 MW
EA EF · EA EF EA EF
(GWH) (GWH) (GWH) (GWH) (GWH) (GWH)
JANUARY 117 116 235 232 368 368
FEBRUARY 110 109 222 219 349 350
MARCH 99 98 197 141 303 313
APRIL 89 87 173 30 268 276
MAY 92 87 169 171 254 258
JUNE 265 93 231 172 290 247
JULY 292 291 480 173 526 319
AUGUST 290 292 554 307 752 298
SEPTEMBER 270 243 429 303 575 280
OCTOBER 150 105 219 213 394 366
NOVEMBER 120 119 239 233 403 393
DECEMBER 129 127 257 254 425 401
TOTAL ANNUAL 2023 1767 2759 2415 4907 3869
Notes:
EA: Average Monthly Energy
EF: Monthly Firm Energy
(1610): Reservoir full supply level ( ft)
TABLE F.10 -PLANS 2.3 and E2.3 -ENERGIES
gTii~j ~ :lTAgn S~I\G[ ~ H~rhev1 anyon Md40 MW to Add ee ( .l.IOJ
MONTH 1750) 400 MW High Devil Canlon 400 MW
EA EF EA EF EA EF
(GWH) (GWH) (GWH) (GWH) (GWH) (GWH)
JANUARY 23'; 232 235 232 368 368
fEBRUARY 222 219 222 219 349 350
MARCH 197 141 197 1S2 303 313
APRIL 17> 30 173 30 268 276
MAY 169 171 169 171 254 258
JUNE zoo 172 231 172 290 247
JULY 275 173 480 173 526 319
AUGUST 288 286 554 307 7S2 298
SEPTEMBER 285 292 429 303 575 280
OCTOBER 219 213 219 213 394 366
NOVEMBER 239 232 239 233 403 393
DECEMBER 257 254 257 254 425 401
TOTAL ANNUAL 2759 2415 J405 2459 4907 3869
Notes:
EA: Average Monthly Energy
Ef: Monthly firm Energy
( 1750): Reservoir full supply level (ft)
TABLE F.11 -PLAN 3.1 -ENERGIES
51 AGE 1 siAGE 2
Watana (2200) Add Tunnel
MONTH BOO MW 380 MW
EA EF EA EF
JANUARY 264 263 490 488
FEBRUARY 250 249 463 467
MARCH 224 224 411 423
APRIL 201 201 364 376
MAY 186 186 345 351
JUNE 187 183 332 332
JULY 285 183 390 321
AUGUST 499 190 633 337
SEPTEMBER 370 204 574 364
OCTOBER 233 233 419 417
NOVEMBER 266 266 483 481
DECEMBER 287 287 529 527
TOTAL ANNUAL 3252 2669 5433 4885
Notes:
EA: Average Monthly Energy
EF: Monthly Firm Energy
(2200): Reservoir full supply level ( ft)
TABLE f.1Z-PLAN 4.1 -ENERGIES
~TiiG[ 1 STAG£ 2 STiiG£ 3
Watana (22oo) Add H.D.C. Add Portage Creek
MONTH 800 MW (1450) 400 MW (1020) 150 MW
£1\ tr tA EF EA £f'
(GWH) (GWH) (GWH1 (GWH) (GWH) (GWH)
JANUARY 264 263 447 444 504 501
fEBRUARY 250 249 424 422 478 476
MARCH 224 224 379 378 428 426
APR1L 201 201 334 335 379 378
HAY 186 186 338 330 391 376
JUNE 187 183 349 313 406 356
JULY 285 183 419 306 481 347
AUGUST 499 190 670 323 799 366
SEPTEMBER 370 204 583 346 661 392
OCTOBER 233 233 400 393 454 445
NOVEMBER 266 265 499 446 507 503
DECEMBER 287 287 488 485 550 546
TOTAL ANNUAL 32.>2 2669 .>281 4522 5997 5112
Notes:
EA: Average l-1onthly Energy
Ef: Monthly firm Energy
(2200): Reservoir full supply level ( ft)
TABLE F.13-PLAN E1.2-ENERGIES
STAGE 2 STAGE 3 STAGE 4
watana Ra1se Dam Add 400 MW to Add Oev1l Canyon
MONTH (2200) 400 MW Watana (2200) (1450) 400 MW EA Ef EA EF EA EF
(GWH) (GWH) (GWH) (GWH) (GWH) (GWH)
JANUARY 263 263 264 263 544 560
FEBRUARY 250 249 250 249 515 516
MARCH 224 224 224 224 450 460
APRIL 201 201 201 201 396 408
MAY 186 186 186 186 419 406
JUNE 187 184 1B7 183 436 385
JULY 245 183 285 183 453 375
AUGUST 333 190 499 190 616 395
SEPTEMBER 315 204 370 204 606 423
OCTOBER 233 233 233 233 490 480
NOVEMBER 266 265 266 266 547 545
DECEMBER 287 287 287 287 594 5B9
TOTAL ANNUAL 2990 2669 3252 2669 6065 5520
~:
EA: Average Monthly Energy
EF: Monthly Firm Energy
(2200): Reservoir full supply level ( ft)
( 1 ) Stage 1 is as for Stage 1 on Table 2 Plan (1.2)
TABLE f.14-PLAN E1.3-ENERGIES
SIAGt 1 m:ct: z SliiGE 3
Watana (2200) Add 4oo MW to Add Oevil Canyon
MONTH 400 MW Watana (1450) 400 MW
EA tF EA Et EA Ef
(GWH) (GWH) (GWH) (GWH) (GWH) (GWH)
JANUARY 263 263 264 263 544 560
FEBRUARY 250 21;9 250 249 515 516
MARCH 224 224 224 224 450 460
APRIL 201 201 201 201 396 406
MAY 166 186 186 166 419 406
JUNE 187 164 187 183 436 385
JULY 245 183 285 183 453 375
AUGUST 333 190 499 190 616 395
SEPTEMBER 315 204 370 204 606 423
OCTOBER 233 233 233 ZJ} 490 480
NOVEMBER 266 265 266 266 547 545
DECEMBER 287 267 287 267 594 589
TOTAL ANNUAL 2990 2669 3252 2669 6065 5520
~:
EA: Average Monthly Energy
EF: Monthly Firm Energy
(2200): Reservoir full supply level (ft)
TABLE F.15-PLAN E2.4-ENERGIES
SfA~E 1 STA~E 2 srA~[ J
Add 400 MW to High
MONTH Hi~h Devil Canyon Devil Canyon and Par-Add Vee (2350)
1750) 400 MW tage Creek (150 MW) 400 MW
EA [F EA EF EA EF
(GWH) (GWH) (GWH) (GWH) (GWH) (GWH)
JANUARY 235 232 317 317 432 435
FEBRUARY 222 219 296 302 411 415
MARCH 197 141 261 270 360 372
APRIL 173 30 231 239 318 328
MAY 169 171 220 221 287 290
JUNE zoo 172 232 208 321 277
JULY 275 173 460 214 564 349
AUGUST 288 286 629 221 820 332
SEPTEMBER 2B5 292 492 241 646 315
OCTOBER 219 213 282 276 447 415
NOVEMBER 239 232 317 317 457 446
DECEMBER 257 254 346 346 480 456
TOTAL ANNUAL 2759 2415 40B3 3171 5543 4430
Notes:
EA: Average Monthly Energy
EF: Monthly Firm Energy
(1750): Reservoir full supply level ( ft)
Q
tt a::
~
Q.
..J
~ z z <
0
1-
•:..:
i5 Q.
>-..J
i= z
0
:I!
1.0
.9 .92
.B7
.B
.78 .BO
.7
.70 .70
.6 .64 .64
.62 .61
.5
.4 -
.3
.2
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT
MONTH
1995 MONTH/ANNUAL PEAK LOAD RATIOS
REF: WOODWARD CLYCE CONSULTANTS,
'! FORECASTING PEAK ELECTRIC
DEMAND FOR ALASKA's RAILBELT"
1.00
.92
NOV DEC
FIGURE F.l
Railbelt System ~1ill be developed in the future by means of an appropriate
continuation of existing and new proven generation alternatives to supply the
necessary demand.
The objectives of generation planning in the evaluation process is to determine
the preferred Susitna Basin development plan which will form part of the Rail-
belt System. The preferred Susitna Basin plan would be that plan which gives
lowest system present worth cost of generation for the energy and capacity
detmalnds and economic criteria se 1 ected.
-Introduction
Generation planning analyses were performed by making a comparison of Susitna
Ji::':>:po:~i n development alternatives with the aid of a production cost model to assess
""'~Lr•e system costs for the various development alternatives available. Standard
~~~n,umE!rical evaluation techniques were then used to make direct comparison of al-
rP•'no,~:ives. Initially, a set of variables was established for use in making
comparisons of available basin developments. In this preliminary evalua-
on, the study focused on the medium load forecast to identify various plans; a
plan which consisted of an all-thermal development, plans composed of ther-
plus various Susitna developments, and a plan composed of thermal plus other
hv(irc>e ectric developments.
second phase of generation planning assessed the impact of varying the load
System generation plans with and without the Susitna Basin develop-
plan were identified for the high and low load forecasts. A plan was also
1 for the low load forecast considering an additional reduction in load
n~,,wt·h due to conservation and load management. Also under this phase, a plan
developed considering a probabilistic forecast centered around the medium
oad forecast.
nee it is recognized that the selection of a generation plan may be sensitive
the underlying assumptions, the third phase of generation planning assessed
impacts of variable planning parameters and the sensitivity of these para-
meters with respect to the generation plans. This analysis dealt with variable
interest rates, fuel cost and escalation, retirement policies, and capital cost
estimates.
-Generation Planning Models
Selection of Planning Model
The major tool used in the economic evaluation of the various Railbelt gen-
eration plans is a computer generation system simulation program. There
are a number of generation planning models available commercially and ac-
cepted for use in the utility industry that will simulate the operation,
growth and cost of a electric utility system. Some of the more widely used
models include the following;
G-1
-GENOP by Westinghouse
-OGP5 by General Electric.
-PROMOD by Energy Management Associates.
-WASP by Tennessee Valley Authority.
The WASP program was not available for use at the start of this study so is
not considered or discussed further in this report.
Key considerations for use in selection of a model for this study are data
processing costs, method of production cost modeling, treatment of system
reliability, selection of new capacity, dispatching of hydroelectric capa-
city to meet load projections and ability of the model to address load
uncertainty. Although these items are handled differently in each program,
common traits of operation exist. Some of the salient features of each
model are shown on Table G.l. Major differences in the models are given
be 1 ow.
(i) Forced Outages
One significant factor which varies between the models is the method
of determining forced outages of the various units of system power
generation installations which are represented in the production cost
algorithm. The three methods used are:
-Deterministic methods which devote unit capacity by a multiplier or
by extend1ng planned maintenance schedules.
-Stochastic methods which can be reduced to deterministic methods.
Strictly speaking stochastic representations of outages is a random
selection of some units in each commitment zone to be put out of
service. The load previously served will be transferred to higher
cost units.
-Probabilistic methods, which are described by the modified Booth-
Baleriaux method of production simulation which all01vs for
probability distribution of generation unit outages.
The selection of one of these methods may be critical in the use of a
model for short-term outage scheduling. However, it is generally found
that virtually no difference in planning results is obtained from
models using the three methods available over a long term period.
( i i) Dispatching Hydropov1er Resources
The method of dispatching hydropower resources to meet load demands is
another significant feature which affects the model's representation
of the system. The GENOP program will dispatch or select, from avail-
ab1e units, hydroe1ecric units first to meet a given demand. Gen-
erally, the run-of-river units will meet load demand and units with
storage capability will be used to shave peak demands.
G-2
The OGP5 program uses a similar method, utilizing hydroelectric energy
as much as possible to minimize system operating costs. Hydropower is
scheduled first on a monthly basis to account for seasonal conditions.
An additional feature of the program is the ability to use dry year or
firm energy on a monthly basis to determine system reliability, while
using average annual energy to determine system production costs.
The PROMOD program allows for three levels of annual runoff and
associated hydroelectric energy. These energy levels can be entered
into the program in a probabilistic manner to be used in determining
reliability and production costing. Run-of-river and storage units
are dispatched as in the other programs.
Other factors are also important such as program availability and ex-
perience of staff in using the models. On the basis of this
assessment of model features, model availability and Acres' knowledge
of the intricacies of the model procedures, the OGP5 model was
selected for use in this stuqy. This model is believed to be the most
appropriate to accurately model the Railbelt generation system as it
exists today and in the future, with the various generation
alternatives available to the region.
OGP5 Model
The primary tool used for the generation planning studies was the mathema-
tical model developed by the Electric Utility Systems Engineering Depart-
ment of the General Electric Company. The model is commonly known as OGP5
or Optimized Generation Planning Model. The following information is para-
phrased from GE literature on the program.
The OGP5 program was developed over ten years ago 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
stuqy 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 program consid-
ers the existing and committed units (planned and under construction)
available to the system and the characteristics of these units includiny
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 reliabil-
ity criteria. This determines "how much" capacity to add and "when" 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
available 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.
G-3
The unit resulting in
added to the system.
costs is completed to
add to the system.
the lowest system production cost is selected and
Finally, an investment cost analysis of the capital
answer the question of "what kind" of generation to
The model is then further used to compare alternative plans for meeting
variable electrical demands, based on system reliability and production
costs for the study period. Further discussion on the load requirements,
load uncertainty and plant reliability is given below:
(i) Load Representation
Besides generation unit data and system reliability criteria, the
program uses a model of the system load including month to year peak
load ratios, typical daily load shapes for days and weekends, and
projected growth for the period of study in terms of capacity and
energy supply.
Load forecasts' used for generation planning are represented in detail
in Section 5, "Railbelt Load Forecast", of the main report. Figure
G.l depicts the four energy forecasts in the systemwide analysis.
The forecasts used for generation planning are based on Acres'
analysis of the ISER energy forecast. The energy forecast used by
Acres for establishing the "base case" generation plan is the medium
load forecast (Table G.2). Sensitivity analyses have also been
undertaken using variable loads developed from the ISER scenarios of
high and low levels of both economic activity and government spending.
Table G.2 gives the range of load forecasts considered.
The energy and load forecasts developed in Section 5 of this report
include energy projections for self-supplied industrial and military
sectors. These markets will not be a part of the future electrical
demand to be met by the Railbelt Utility Company. Likewise, the
capacity owned by these sectors will not be available as a supply to
the general market. A review of the industrial self suppliers
indicates that they are primarily offshore operations, drilling
operations and others which would not likely add nor draw power from
the system. The forecasts have been appropriately adjusted for use in
generation planning studies, as described in Section 5. Additionally,
although it is considered likely that the military would purchase
available cost effective power from a general market, much of their
capacity resource is tied to district heating systems, and thus would
be expected to continue operation. For these reasons only 30 percent
of the military generation total will be considered as a load on the
total system. This amount is about 4 percent of total energy in 1980
and decreases t~ 2.5 percent in 1990. This method of accounting for
these loads has no significant effect on total capacity additions
needed to meet projected loads after 1985. Table G.2 illustrates the
medium load and energy forecasts at five year intervals throughout the
planning period.
G-4
(ii) Load Uncertainty
The load forecast used to develop a generation plan will have a signi-
ficant bearing on the nature of the plan. In addition, the plan can
be significantly changed due to uncertainties associated with the
forecasted loads. To address the question of the impact of load un-
certainty on a development plan, two procedures will be used. The
first procedure will be to develop plans using the high and low load
forecasts assuming no uncertainty to the forecast. This will identify
the upper and lower bounds of development which will be needed in the
Railbelt. The second method will be to incorporate the variable fore~
casts and uncertainty of the load forecasts into the planning pro-
cess.
The medium load forecast (used in preliminary evaluation of plans) is
introduced into the program in detail. This would include daily load
shapes, monthly variability and annual growth of peaks and energy.
Additional variables are added which introduce forecast uncertainty in
terms of higher and lower levels of peak demand and the probability of
the occurrence of these forecasts. For example, in the year 2000 the
medium load forecast demand entered is 1175 NW. Variable forecasts
are entered for 950, 1060, 1530 and 1670 MW, with associated probabil-
ities of occurrence of 0.10, 0.20, 0.20 and 0.10, respectively. The
middle level forecast of 1175 MW would have a probability of occur-
rence of 0.40.
The OGP5 program uses this variable forecast in determining generating
system re 1 i abi 1 i ty only. A 1 oss of 1 oad probability is ca 1 cu 1 ated for
each projected demand level as compared to the available capacity and
a weighted average is taken. This loss of load probability is then
used for capacity addition decisions. After capacity decisions are
made, the program uses the medium load forecast detail for operating
the production cost model.
This method of dealing with uncertainty is directly applicable to the
data available on Railbelt load forecasts. There are five forecasts
which could be plugged into the reliability calculations, three by
ISER and two extremes calculated by Acres represented in Table G.2.
Subjectivity is reduced to the decision of placing probabilities on
the load forecasts. Based on commmunication with the ISER group in
Alaska as well as General Electric OPG5 personnel, the above example
probability set has been considered in the analysis. This is based on
the assumption that each extreme forecast is half as likely to happen
as the adjacent forecast which is closer to the medium. The loads and
probabilities analyzed are given in Table G.3.
(iii) Generation Plant Reliability
In order to perform a study of the generation system, criteria are
required to establish generating plant and system reliability. These
criteria are important in determining the adequacy of the available
G-5
generating capacity as well as the s1z1ng and timing of additional
units. Plant reliability is expressed in the form of forced and plan-
ned outage rates which have been presented within the individual re-
source descriptions in Section 6. System reliability is expressed as
the loss of load probability (LOLP).
An LOLP for a system is a calculated probability based on the
characteristics of capacity, forced and scheduled outage, and cycling
ability of individual units in the generating system. The probability
defines the 1 ikel ihood of not meeting the full demand within a one
year period. For example, an LOLP of 1 relates to the probability of
not meeting demand one day in one year; an LOLP of 0.1 is one day in
ten years. For this study, an LOLP of 0.1 has been adopted. This
value is widely used by utility planners in the United States as a
target for independent systems. This target value will be used both
for the base case plan and for sensitivity analyses dealing with the
effects of over or under capacity availabl il ity.
{iv) Economic and Financial Parameters
As a public investment, it was determined that the Susitna project
should be evaluated initially from an economic perspective, using eco-
nomic parameters. Initial analysis and screening of Susitna alterna-
tives employed a numerical economic analysis and the general aid of
the OGP5 model.
The differences between economic and financial {cost of power) ana-
lyses pertain to the following parameters:
-Project Life
In ecpnomic evaluations, an economic life is used without regard to
the terms (repayment period) of debt capacity employed to finance
the project. A financial (or cost of power) perspective uses an
amortization period that is tied to the terms of financing. A
retirement period (policy) is generally equivalent to project life
in economic evaluations; financial analysis may use a retirement
period that differs from project 1 ife.
-Denomination of Cash Flows and Discount Rates
Economic evaluations use real dollars and real discount rates that
exclude the effects of general price inflation with the exception of
fuel escalation.
-Market or Shadow Prices
Hhenever market and shadow prices diverge, economic eva 1 uat ions use
shadow prices (opportunity costs or values). Financial analysis
uses market prices projected as applicable. Fuel prices are
friscussed in detail in Section 6 and Appendix B.
G-6
It is important to note that application of the various parameters
contained herein will not necessarily provide an accurate reflection
of the true life cycle cost of any single generating resource of the
system. From the public (State of Alaska) perspective, the relevant
project costs are based on opportunity values and exclude transfer
payments such as taxes and subsidies. Further stuqy into this
comparative analysis of project economics will be continuing during
1981.
-Interest Rates and Annual Carrying Charges
The assumed generation planning study based on economic parameters
and criteria has a 3 percent real discount rate for the base case
analysis. This figure corresponds to the historical and expected
real cost of debt capacity. The issue of tax-exempt financing does
not impinge on these economic evaluations.
In comparison, analysis requires a nominal or market rate of inter-
est for discounted cash flow analysis. This rate is dependent upon
general price inflation, capital structure (debt-equity ratios) and
tax-exempt status. In the base case, a general rate of price infla-
tion of seven percent is assumed for the period 1980 to 2010. Given
a 100 percent debt capitalization and a three percent real discount
rate, the appropriate nominal interest rate is approximately 10
percent in the base case. The nominal interest is computed as:
Nominal Interest Rate= (1 + inflation rate) x
(1 +real interest rate)
= 1.07 X 1.03
To calculate annual carrying charges, the following assumptions were
made regarding the economic life of various power projects. As
noted earlier, these lives were also assumed as the plant lives.
• Large steam plants -30 years
• Small steam plants -35 years
• Gas turbines, oil-fired -20 years
• Gas turbines, gas-fired· -30 years
• Diesels -30 years
1 Hydroelectric projects -50 years
It should be noted that the 50-year life for hydro projects was
selected as a conservative· estimate and does not include replacement
investment expenditures.
-Cost Escalation Rates
In the initial set of generation planning parameters, it was assumed
that all cost items except energy escalate at the rate of general
price inflation (assumed in the economic sense to be 0 percent per
year). This results in real growth rates of zero percent for
. non-energy costs in the set of economic parameters used in real
dollar generation planning.
G-7
tl!
Base period (January 1980) energy prices were estimated based on
both market and shadow values. The initial base case analysis used
base period costs (market and shadow prices) of $1.15/million Btu
(MMBtu) and $4.00/MMBtu for coal and distillate respectively. For
natural gas, the current actual market price is about $1.05/MMBtu
and the shadow price is estimated to be $2.00/MI~Btu. The shadow
price for gas represents the expected market value assuming an
export market was developed.
Real growth rates in energy costs (excluding general price infla-
tion) are shown in Table G.4. These are based on fuel escalation
rates from the Department of Energy (DOE) mid-term Energy Fore-
casting System for DOE Region 10 (including the States of Alaska,
Washington, Oregon and Idaho. Price escalators pertaining to the
industrial sector were selected over those available for the commer-
cial and residential sectors to reflect utilities' bulk purchasing
advantage. A composite escalation rate has been computed for the
period 1980 to 1995 which reflects average compound growth rate per
year. Since the DOE has suggested that the forecasts to 1995 may be
extended to 2005, the composite escalation rates are assumed to pre-
vail in the period 1996 to 2005. Beyond 2005, zero growth in energy
prices is assumed.
Table G.5 summarizes the sets of economic and financial parameters
assumed for generation planning.
-Other Parameters
Other parameters considered in generation planning studies include
insurance and taxes. The factors for insurance costs (0.10 percent
for hydroelectric projects and 0.25 percent for all others) are
based on FERC guidelines. State and federal taxes were assumed to
be zero for all types of power projects. This assumption is valid
for planning based on economic criteria since all intra-state taxes
should be excluded as transfer payments from Alaska's perspective.
The subsequent financial analyses may relax this ass·umption if non-
zero state and/or local taxes or payments in lieu of taxes are iden-
tified. Annual fixed carrying charges relevant to the generation
planning analysis are given in Table G.5.
G.3 -Generation Planning Results
Generation planning runs were made for each of the Susitna development plans
identified in Section 8.6 • Formulation of Susitna Basin Development Plans, and
for system generation plans without Susitna developments. Plans ~1ithout Susitna
included alternative hydro and all-thermal generation scenarios.
A minor limitation inherent in the use of the OGP5 model is that the number of
years of simulation is limited to 20 years. To overcome this, the study period
of 1980 to 2040 has been broken into three separate segments for study purposes.
These segments are common to all system generation plans.
G-8
The first segment has been assumed to be from 1980 to 1990. The model of this
time period includes all committed generation units and is assumed to be common
to all generation scenarios. This ten-year model is summarized in Table G-8.
This table shows the 1980 to 1990 system configuration and details on committed
units and retirements that occur during the period. The end point of this model
becomes the beginning of each 1990-2010 model.
The model of the first two time periods considered (1980 to 1990, and 1990 to
2010) provides the total production costs on a year-to-year basis. These total
costs include, for the period of modeling, all costs of fuel and operation and
maintenance of all generating units included as part of the system. In
addition, the completed production cost includes the annualized investment costs
of any production plans added during the period of study. A number of factors
which contribute to the ultimate cost of power to the consumer, are not included
in this model. These are common to all scenarios and include:
-All investment costs to plants in service prior to 1981;
Costs of transmission systems in service both at the transmission and
distribution level; and
Administrative costs of utilities for providing electric service to the
public.
Thus, it should be recognized that the production costs modeled represent only a_
portion of ultimate consumer costs and in effect are only a portion, albeit
major, of total costs.
The third period, 2010 to 2040, was modeled by assuming that production costs of
2010 would recur for the additional 30 years to 2040. This assumption is
believed to be reasonable given the limitations on forecasting energy and load
requirements for this period. The addition period to 2040 is required to take
into account the benefit derived from the value of the addition of a
hydroelectric power plant which has a useful life of fifty years or more.
The selection of the preferred generation plan is based on numerous factors.
One of these is the cost of the generation plan. To provide a consistent means-
of assessing the production cost of a given generation scenario each production
cost total has been converted to a 1980 present worth basis. The present worth
cost of any generation scenario is made up of three cost amounts. The first is
present worth cost (PWC) of the first ten years of study (1981 to 1990), the
second is the PWC of the scenario assumed during 1990 to 2010, and the third is
the PWC of the scenario in 2010 assumea to recur for the period 2010 to 2040.
In this V/ay the long-term (60 years) PWC of each generation scenario in 1980
dollars can be compared.
The present worth cqst of the generation system given by Table G.6 is $873.7
million in 1980 values. This cost is common to all generation scenarios and is
added to all PWC values for each generation scenario during the modeling of the
system in the period of 1990 to 2040.
G-9
I
I I:
···1· .. · l ,:
I
L i•
I
Generation scenarios analyses include thermal generation with Susitna ~asin
plans, thermal generation with alternative non-Susitna hydro plans and all-ther-
mal generation. Details of the analysis of these three generation mixes are
given in the following sections.
(a) Susitna Basin Plans
(i) Base Case Medium Load Forecast
Essentially the Susitna Basin plans were developed from the studies
described in Section 8. Some of the plans are similar in location
and size but vary in staging concepts. Others are at totally dif-
ferent sites. These various Susitna plans were modeled in the.OGP5
model as part of the Railbelt system. The characteristics of the
Susitna plans are summarized in Table G.7 and their formulation is
described fully in Section 8. The results of the OGP5 model runs
assuming a medium load forecast for all the Susitna plans identified
through the procedures outlined in Section 8 are given in Table
G. 8.
The plans developed included 800 MW and 1200 MW capacity plans in
addition to variation in these plans to determine the effects on PWC
of delaying implementation of the plan, the elimination of a stage
in the plan, or staging construction of a particular dam in the
plan. Inspection of the results given in Table G.8 indicates the
fo 11 owing:
-The 1 owest present worth cost deve 1 opment at $5850 mi 11 ion is
either Plan El.l or Plan El.3 (see Table G.7). This result shows
that there is no effective difference between full powerhouse
development at Watana and staged powerhouse development;
-The highest present worth cost development at $6960 million is
Plan 1.3 with Devil Canyon not constructed;
Watana/Devil Canyon (Plan E1.1 or El.3) is superior to Watana/
Tunnel (Plan 3.1) by $680 million;
Watana/Devil Canyon (Plan E1.1 or El.3) remains superior to
Watana/Tunnel (Special Plan 3.1) when tunnel capital costs are
halved. Watana/Devil Canyon is superior by $380 million;
Watana/Devil Canyon (Plan E1.1 or El.3) is superior to High Devil
Canyon/Vee developments (Plan E2.1 or Plan E2.3) by at least $520
million;
-Replacement of Vee Dam with Chakachamna development lowers pre-
sent worth cost of Plan 2.3 to $6210 million. Watana/Devil
Canyon remains superior by $360 million;
G-10
-Watana/Devil CanYon development limited to 800 MW (Plan E1.4) is
$140 million more than full 1200 ~1W development (Plans El.l or
El.3) but remains superior to tunnel scheme or High Devil Canyon/
~e pla~; ·
-Delaying implementation of Watana/Oevil Canyon Plan E1.3 by five
years adversely affects present cost by an additional $220
million;
Staging powerhouse and dam construction at \~atana (Plan E1.2)
costs $180 million more than Plans El.l or El.3; and
Watana/High Devil Canyon/Portage Creek (Plan E4.1) is $200
million more than either Plan El.l or E1.3.
(ii) Variable Load Forecast
As discussed in Section 5, the many uncertainities of load forecast-
ing provide a wide range of possibilities for future generation
planning. The medium load forecast (with moderate government expen-
diture) used above to show the present worth cost of the develop-
ments identified through site screening and plan formulation steps
is thought to be the most likely load and energy forecast. However,
due to the uncertainty associated with the load forecasting, approx-
imate upper and lower limits to the load forecast have been
defined.
The high forecast assumes high economic growth and high government
expenditure whereas the lower bound, or low forecast, assumes low
economic growth and low government expenditure. In addition to
these two forecasts, the results of a determined effort at load
management and conservation have been incorporated into a fourth
load forecast. This very low forecast also assumes low government
expenditure in addition to low economic growth with load management
and conservation. Further details of these forecasts are given in
Section 5 and load forecast values in five-year periods in Table
G.8.
The results of the OGP5 analysis of the Railbelt generation system
with Susitna under these various load forecasts are given in Table
G.9. The· conclusions that can be drawn from inspection of Table
G.9 are:
-Watana/Oevil Canyon development (Plan El.4) has the least present
worth cost at $4350 million of all deve 1 opments under a 1 ow 1 oad
forecast;
-Watana/Devil Canyon with Chakachamna as a fourth stage (modified
P1an E1.3) has the least present worth cost of $10,050 million of
all developments under a high load forecast;
-Plan E1.4 is superior to special Watana/tunnel (tunnel cost
halved) by $380 mil1ion under a low load forecast;
G-11
Plan E1.4 is superior to High Devil Canyon/Vee (Plan E2.1) by
$320 million under a low load forecast;
Modified Plan E1.3 is superior by $650 million to Plan El.3 under
a high load forecast; and
~lodified Plan El.3 is superior to High Devil Canyon/Vee with
Chakachamna (modified Plan E2.3) by $990 million.
(iii) Economic Sensitivity
The Watana/Devil Canyon development known as Plan El.3 has been
identified as the most economic development of Susitna alternatives
under a medium load forecast (Table G.8). In addition, variations
of the Watana/Devil Canyon development have been identified as the
most economical under low and high load forecasts (Table G.9).
Consequently, the Plan E1.3 is obviously the most reasonable to
select as the one to determine the sensitivity of the plans to
variations in the economic parameters which are subject to
uncertainties.
Sensitivity analyses have been performed on critical parameters and
are based on Plan El.3 with a medium load forecast. The results of
these analyses are summarized in Table G.lO and are discussed below.
Base values for the parameters assumed in OGP5 modeling, particular-
ly with respect to thermal plant costs, etc. are given in Appendix
B.
Interest Rates
In the base plan selected (also in other plans) the interest rate
assumed is 3 percent. This rate represents the cost of money,
net of inflation. Variation of this rate to 5 and 9 percent has
been assumed to determine the effect of interest rate variation
on this capital intensive development. The effect of a 5 percent
interest rate is to lower the present worth cost of Plan El.3 by
$1620 mi 11 ion to $4230 mi 11 ion. The higher rate of 9 percent
1 owers the present worth cost to $2690 mi 11 ion.
-Fuel Cost and Fuel Cost Escalation Rate
The base plan has assumed a fuel cost ($/million Btu) of 2.00,
1.15, and 4.00, for natural gas, coal and oil respectively. The
effect of reducing fuel costs by 20 percent to 1.60, 0.92 and
3.20 $/million Btu for natural gas, coal and oil respectively is
to reduce the present worth cost of Plan El.3 by $590 million to
$5260. This reduction represents the 1 o~1er cost associ a ted with
operating the thermal generation component of the system.
Fuel cost escalation rates of 3.98, 2.93, and 3.58 percent have
been derived as typical for the Railbelt region (Appendix B).
The effect of lowering this escalation rate to zero percent for
all-thermal fuels is to lower the present worth cost of Plan El.3
G-12
to $4360 million. When coal cost escalation alone is set at zero
percent the effect is much less, giving a reduction of only $590
million. Again the fuel cost escalation rate shows that the hy-
droelectric alternatives would become economically superior if
thermal operation costs are lowered.
-Economic Life of Thermal Plants
Increasing the economic lives of thermal plants incorporated into
the generation system with Susitna Plan El.3 results in an in-
crease of the present worth cost of the system of $250 million.
This result was for a 50 percent increase in thermal plant life
and shows that the increase results in greater operational
costs.
-Thermal Plant Capital Costs
The effect of a reduction in thermal plant capital costs by 22
percent, to 350, 2135 and 778 $/kw for natural gas, coal and oil
respectively, results in a slight reduction in present worth cost
of the system. The reduction is $110 million and is a direct re-
sult of the lower capital costs of the thermal component of the
system.
-Hydro Plant Capital Costs
Various uncertainties in capital costs of the hydro development
exist due to possible variations in amounts of foundation treat-
ment, construction delays, etc. To take into account some of
these uncertainties, an assessment has been made of increased
hydro construction costs. An increase in construction cost of 10
percent to Devil Canyon results in an increase in present worth
cost of the system of $360 million. A 50 percent increase in
both Watana and Devil Canyon construction costs results in a $960
million increase in present worth cost.
The effects of the sensitivity analyses conducted above would be the same
for whichever development plan is selected; the relative ranking of the
various Susitna Basin development plans would remain essentially unchanged
and Plan El.3 would still be the most economic in terms of present 1~orth
cost under a medium load forecast.
Alternative Hydro Generation Plans
In Section 6 and Appendix C, alternative hydroelectric developments to
Susitna were identified. In Appendix C, the following ten sites were shown
to be the most economically viable and environmentally acceptable sites
outside of the Susitna Basin:
-Chakachamna:
-Keetna:
-Snow:
480 MW
100 MW
50 MW
G-13
-Strandline:
-Allison Creek:
-Cache:
-Talkeetna-2:
-Browne:
-Bruskasna:
-Hicks:
20 MW
8 r~w
50 MW
50 MW
100 MW
30 M\1
60 MW
In the OGP5 analyses these sites were combined into appropriate groups on
the basis of least cost energy and incorporated with thermal generation
sources to meet the medium load forecast defined earlier (Section 5). The
results of the OGP5 runs are given in Table G.ll.
The lowest present worth cost of the system with alternative Susitna hydro
is $7040 million. This represents an increase of $1190 million over the
lm;est cost Susitna development plan (Plan El.3) for the medium load fore-
cast. This alternative hydro scenario includes Chakachamna, Keetna and
Snow developments. The addition of Strandline Lake and Allison Creek to
the system has minimum effect on present worth cost ($7041 million) but
would eliminate the need of 55 MW of thermal generating capacity, thus
saving a non-renewable resource.
The maximum development
cost of $7088 rni 11 ion.
Table G.ll.
of alternative hydro considered has a present worth
The six sites included in this plan are given in
(c) Thermal Generation Scenarios
The therma 1 generating resources required to meet Rail belt energy and power
demands can be identified through the use of the same production cost model
as that which identified the most economic plan of development with Susitna
Basin alternatives and non-Susitna hydro alternatives.
Using information developed in Appendix B for thermal generating resources
available to the Railbelt and the five load forecasts outlined in Section
5, the OGP5 program was used to simulate the operation of the Railbelt
generating system over the 30-year study period. As in Susitna and non--
Susitna hydro alternatives, the long term present worth cost (in 1980
dollars) of the thermal system was determined.
The medium load forecast is currently believed to be the most likely load
to develop in the Rail belt over the next 40 years. Consequently, as before
for hydro developments, this forecast 'forms the basis of the majority of
OGP5 analysis.
(i) Medium Load Forecast:
The thermal generating plan for the medium load forecast is
presented in Table G.11. Two cases were modeled for the thermal
generation plan. The first model allowed the renewal of natural gas
turbines at the end of their economic life; the second assumed no
rene1~al s and required the permanent retirement of the natural gas
G-14
turbines at the end of their useful lives. This policy affects 456
MW of existing gas turbine units. The rationale behind these two
renewal policies is related to the implementation of the Fuel Use
Act (FUA) which prohibits the building of new generating units oper-
ating on natural gas. The FUA is discussed more fully in Section
6.6 where it was shown that Railbelt utilities would probably be
restricted to new gas facilities for peaking applications only.
The policy of renewal or non-renewal of gas turbines has a minimal
effect on 1 ong-terrn present worth cost of the therma 1 system mode 1.
This is clearly shown in Table G.11 where the present worth cost
difference between the two policies, under a medium load forecast,
is only $20 million. The natural gas turbines permanently retired
are in fact simply replaced by peaking-only natural gas turbines.
The long-term present worth cost of the thermal generating system is
$8110 million assuming gas turbine renewals.
The same 10-year generation plan (for 1981-1990) applies to the
thermal generating scenario as it does for the hydroelectric scenar-
ios given above. This period sees the installation of the Beluga
combine cycle Unit No. 8 by Chugach Electric Association and the 94
MW Bradley Lake hydro plant in 1988.
Under the medium load forecast the level of installed coal-fired
units increases from 54 MW in 1990 to 900 MW in 2010 with the first
coal unit addition in 1993 to meet loss of load probability require-
ments. The model selects 100 MW coal unit additions over 250 and
500 MW units. This selection is due in part to a relatively slow
demand growth from year to year and the generous reserve capacity of
peaking units in the existing Railbelt region. The 2010 system mix
is comprised primarily of natural gas turbines and coal units,
although energy dispatched is more reliant on coal plants operating
at approximately 70 percent plant factor.
(ii) Other Load Forecasts
Section 5 identified load forecasts which took into account combina-
tions of levels of economic growth and government expenditure.
These load forecasts also included the cases with load management
and conservation and the probabilistic variation on the medium load
forecast. As in the medium forecast, the two cases of gas turbine
renewal or non-renewal were determined.
High Load Forecast
The high load forecast requires the installation of a 100 MW
coal~fired plant in 1990. This is the same as was determined for
Susitna and non-Susitna hydro scenarios under the high load fore-
cast. The long-term present worth cost of the thermal generation
scenario under this load forecast is $13,630 million assuming a
renewal pol icy of gas turbines. There is a slight benefit of
$110 million if a policy of non-renewal is pursued. However, the
two cases can be assumed to be effectively the same.
G-15
-Low Load Forecast
The low load forecast requires approximately one third of the
capacity additions as the high load forecast (Table G.l1). The
present worth cost of the thermal system under the low load fore-
cast, and assuming renewals of gas turbine units, is $5910
million. With no renewals, the present worth cost is very
slightly increased to $5920 million.
-Load Management and Conservation Forecast
The thermal generation plan required to meet the low load fore-
cast with a determined policy of load management and conservation
was developed using the same principles and practice as for the
Susitna plans. As would be expected this forecast resulted in a
lower cost system than that found under the unadjusted low load
forecast. The present worth cost was found to be $4930 million
for this scenario (no renewals were assumed).
-Probabilistic Load Forecast
To complete the analysis of the thermal generation plan, the med-
ium load forecast was operated under the assumption of a prob-
abilistic load variation. The effect of assuming this variation
to the medium forecast results, as was found for Susitna Basin
developments, in an increase in long-term present worth cost.
The present worth cost for this system (Table G.ll) is $8320
million. This assumes no gas turbine renewals and represents an
increase of $190 million over the comparable medium load forecast
case.
(iii) Sensitivity Analyses
It is important to objectively determine the sensitivity of non-
Susitna or non-renewal resource dependent generation plans or
changes in costs and escalation of fuel, interest rates, construc-
tion costs, and plant life.
-Interest Rate Sensitivity
As in the Susitna development scenario and the investigation into
the sensitivity of the plan to economic parameter changes, the
assumed underlying escalation rate for the base case thermal plan
is zero percent and the interest rate is three percent. Sensi-
tivity of the thermal plan to changes in the interest rate to 5
and 9 percent was determined, again assuming a zero percent esca-
lation or inflation rate. Table G.l2 shows the change of the
present worth cost for the plan from $8130 million to $5170
million and $2610 million for five and nine percent interest
rates respectively.
G-16
If a comparison was to be drawn between thermal and Susitna scen-
arios studied under the sensitivity analyses, it would show that
the two plans would be economically comparable (in terms of
present worth cost} if interest rates were approximately eight
percent.
To provide reasonable comparisons between interest rate sensitiv-
ity analyses it was necessary to assume that the generation
system mix would be similar as that determined for the three per-
cent OGP5 run. If this was not the case, then OGP5 would select
cheaper generation units, particularly natural gas, which prob-
ably would not meet defined criteria on system components.
-Fuel Cost
The reduction of fuel costs by 20 percent produces significant
reduction in present worth cost of approximately $1060 million to
$7070 million. This reduction is due to the lower expense of
supplying the plants with the necessary fuel to power the units.
-Fuel Cost Escalation
Fuel cost escalation sensitivity was assessed in two methods.
The first was assuming zero percent escalation for all three
major fuels and the second was to assume zero percent for coal
only, with oil and natural gas remaining at an escalation rate of
3.58 and 3.98 percent respectively. In both cases escalation
rates were assumed to apply between 1980 and 2005 and progress-
ively dropping to zero in 2010.
The case of zero percent escalation for all fuels shows a dra-
matic reduction in present worth cost of $3570 rr1illion over the
base case thermal scenario (Table G.l2).
As would be expected for zero percent escalation in the cost of
coal, the reduction in production cost is less than for no esca-
lation in cost of any fuel. This reduction is, however, still
significant and amounts to an annual savings of $1210 million
over the base case thermal plan.
-Economic Life of Thermal Plant
The uncertainty associated with the probable plant life of in-
stallations in the Railbelt region naturally raises concerns. To
address these concerns the thermal plant life, in each category,
was extended by 50 percent. The plant life therefore became 45,
45, and 30 years for coal, gas and oil facilities respectively.
The extension of the economic life results in a gain in cost of
approximately $280 million for the thermal generation scenario.
G-17
-Thermal Capital Costs
Capital cost is another area of concern which has been addressed
in an attempt to negotiate the uncertainties associated with
costing work or structures in remote areas. Although the costs
developed are believed to be the best possible estimates that can
be made at this time, the costs of all-thermal plant types have
been reduced by 22 percent,
As would be expected from a logical inspection at the system, the
reduction in coal plant costs results in coal becoming more eco-
nomically viable as an energy scource. Capital costs reduction
therefore shows a gain in coal capacity generation of 200 MW over
the base case thermal plan. The long term present worth cost is
reduced to $7590 million, a reduction of $540 million from the
base case.
G-18
TABLE G.1 -SALIENT FEATURES Or GENERATION PLANNING PROGRAMS
Program/ Load Generation Oiittmt.zat1on ReltabLlity Product ton Ava.tlabihty and
Oevelo(!er Modeling Modeling Available Criterion Simulation Cost/Run
GENOP/ Done by two Done by one yes LOLP or Dete-rministic or $500 to validate
Westinghouse external external ~ reserve Modified Booth -Learning Curve
programs program Baleriaux Costs
$300 -$900/run
PROHOD/EMA Done by one Done by one no LOLP or Modified Booth -$2,500 to validate
external external ~ reserve Baleriaux on TYMSHARE
program program Learning Curve
Costs
$300 -$500/ run
OGP/GE Qone by one Done by one yes LOLP or De term inist ic or AAI validated
external external %: reserve Stochastic Columbia & Buffalo
program program Experienced
Personnel
$50 -$800/run
..'!!!!._
1980
1985
1990
1995
2000
2005
2010
~:
ow us
TABLE G,2 -RAILBELT REGION LOAD AND ENERGY fORECASTS
USED fOR GENERATION PLANNING STUDIES
L 0 A 0 C A S E
oa
Management and Low Medium
Conservation
(LES-GL)2 (HES-GH)3 (lES-GL Adjusted)1
Load load Load
MW GWh factor HW GWh factor HW CWh Factor
510 2790 62.5 510 2790 62.4 510 2790 62,4
560 3090 62,6 580 3160 62.4 650 3570 62.6
620 3430 63.2 640 3505 62,4 735 4030 62.6
665 3810 63.5 795 4350 62,3 945 5170 62.5
755 4240 63,8 950 5210 62,3 1175 6430 62.4
835 4690 64.1 1045 5700 62.2 1380 7530 62.3
920 5200 64.4 1140 6220 62.2 1635 6940 62.4
High
(HES-GH)4
load
HW GWh factor
510 2790 62,4
695 3860 63.4
920 5090 63.1
1295 7120 62.8
1670 9170 62,6
2285 12540 '62.6
2900 15930 62.7
( 1) LES-Gl low economic growth/low government expenditure with load management and conservation.
(2) LES-Gl low economic growth/low government expenditure.
(3) MES-CH Medium economic growth/moderate government expenditure.
(4) HES-CH High economic growth/high government expenditure~
TABLE G,3 -LOADS AND PROBABILITIES USED IN GENERATION PLANNING
fORECAST 1
LES-LG
LES-HG
MES-MG
HES-HG
HES-HG
Notes:
(1) LES
MES
HES
LG:
MG:
HG:
Low economic growth
medium economic growth
high economic growth
low government expenditure
moderate government expenditure
high government expenditure
PROBABILITY SET
.10
.20
.40
.20
.10
TABLE G,4 -fUEL COSTS AND ESCALATION RATES
Natural Gas
Base Period (January 1980)
-Prices ($/million Btu)
Market Prices
Shadow (Opportunity) Values
Real Escalation Rates (Percentage)
-Change Compounded (Annually)
1980 -1985
1986 -1990
1991 -1995
Composite (average) 1980-1995
1996 -2005
2006 -2010
$1.05
2,00
1,. 79%
6,20
3,99
3.98
3,98
0
Coal
$1.15
1,15
9.56%
2,39
-2.87
2.93 z. 93
0
o~stillate
$4.00
4,00
3.38%
3.09
4,27
3,58
3.58
0
TABLE G.5 -ANNUAL FIXED CARRYING CHARGES USED IN
GENERATION PLANNING MODEL
30-Year 35-Year
ProJect [1Fe71~Be
50-Year 20-Year
Thermal Thermal Hydro Thermal
(%) (%) (%) (%)
ECONOMIC PARAMETERS (0%-3%)
Cost of Money 3.DD 3.DD 3.DD 3.DD
Amortization 2.10 1.65 0.89 3. 72
Insurance D.25 0.25 0.10 0.25
TOTALS "5":-J> 4.9IT ).9"9" b.'17
FINANCIAL PARAMETERS (7%-10%)
Non-exem~l
Cost of f.'oney 10.00 1D.OD 10.00 10.00
1\mortization 0.61 0.37 D.D9 1.75
Insurance 0.25 0.25 0.10 0.25
TOTALS m:m-l"IJ':"b2" TO:l9" rr.uu
Tax-exem2t
Cost of Money 8.DD 8.DD 8.00 8.00
Amortization 0.88 D.58 0.17 2.19
Insurance 0.25 0.25 0.10 0.25
TOTALS 'T.l) 1l:llJ "9:"27 11J.1ili
TABLE G.6 -TEN YEAR BASE GENERATION PLAN MEDIUM LOAO rORECAST
SVS'IE~ !RI'IJ tOTAL
YEAR MW MW NG ore dll CAPABILITY
Committed Retired COAL GT GT DIESEL cc HY (MW)
1980 54 470 168 65 141 49 9471
1981 54 470 168 65 141 49 947
1982 60 cc 54 . 470 168 65 201 49 1007
1983 54 470 168 65 201 49 1007
1984 54 470 168 65 201 49 1007
1985 14 (NGGI) 54 456 168 65 201 49 993
1986 50 456 168 65 201 49 993
1987 4 (Coal) 50 456 168 65 201 49 989
1988 95 HY 50 456 168 65 201 144 1084
1989 5 (Coal) 45 456 168 65 201 144 1079
1990 45 456 168 65 201 144 1079
.!l!!!.!!!:
{1) This figures varies slightly from the 94J.6 MW reported due to internal
computer rounding.
TABLE G.7 -SUSITNA ENVIRONMENTAL DEVELOPMENT PLANS
umu a ve
Stage/Incremental Data System Data
Annual
Maximum Energy
Capital Cost Ear 1 iest Reservoir Seasonal Product-ian Plant
$ Millions fu-1 ine full Supply Draw-firm Avg. factor
Plan Stage Construction (1980 values) Date 1 level -ft. down-ft GWH GWH. 1.:
[1.1 Watana 2225 ft BODMW
andRe-Regulation
Dam 1960 1993 2200 150 2670 3250 46
2 Devil Canyon 1470 ft
40DMW 900 1996 1450 100 5520 6070 58
TOTAL SYSTEM 120CI>IW '2ll6lJ
E1.2 1 Watana 2060 ft 400MW 1570 1992 2000 100 1710 2110 60
2 Watana raise to
2225 ft 360 1995 2200 150 2670 2990 85
J Watana add 40DMW
capacity and
Re-Regulation Dam 230 2 1995 2200 150 2670 3250 46
4 Devil Canyon 1470 ft
40DMW 900 1996 1450 100 5520 6070 58
TOTAL SYSTEM 1200MW Jll61j
E1.3 1 Watana 2225 ft 400MW 1740 1993 2200 150 2670 2990 85
2 Watana add 40DMW
capacity and
Re-Regulalian Dam 250 1993 2200 150 2670 3250 46
3 Devil Canyon 1470 Ft
400 MW 900 1996 1450 100 5520 6070 58
TOTAL SYSIEI~ 1200MW "2l!91'f
TABLE G.7 (Continued)
Cumulative
Stage/Incremental Data System Data
Annual
Maxinun Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$ Millions On-line Full Supply Draw-Fir111 Avg. rector
Plan Slage Construct ion (1960 values) Date 1 Level -ft. down-ft. GWH GWH :;
E1.4 1 Watana 222S ft 400MW 1740 1993 2200 1SO 2670 2990 BS
2 Davil Canyon 1470 ft
40(].!W 900 1996 1450 100 5190 5670 61
TOTAL SYSTEM 80(].!W U4li
[2.1 High Davil Canyon
177S ft BO(].!W and
Re-Regulation Oam 1600 1994 3 1750 1SO 2460 3400 49
2 Vee 23S0ft 400MW 1060 1997 2330 1SO 3670 4910 47
TOTAL SYSTEM 12001!W U4li
E2.2 High Davil Canyon
1630 ft 400MW 1140 1993 3 1610 100 1770 2020 sa
2 High Davil Canyon
raise darn to 177S ft
add 400MW and
Re-Regulalion Dam 600 1996 17SO 150 2460 3400 49
3 Vee 2350 ft 400 MW 1060 1997 2330 ISO 3870 4910 47
TOTAL SYSTEM 1200MW 2ii1ili
E2.3 High Devil Canyon
177 S ft 4001!W 1390 1994 3 1750 1SO 2400 2760 79
2 High Davil Canyon
add 400MW capacity
andRe-Regulation
Dam 240 1995 1750 150 2460 3400 49
Vee 23SO ft 400MW 1060 1'997 2330 1SO 3670 4910 47
TOTAL SYSTEM 1200 2690
~~, Stage
E2.4 1
2
3
EJ.2 1
2
3
E4.1 1
NOTES:
2
3
4
Construction
High Devil Canyon
1755 ft 40(}.1W
High Devil Canyon
add 400MW capacity
and Portage Creek
Dam 150 ft
Vee 2350 ft
400MW
TOTAl SYSTEM
Watana
2225 ft 40G1W
Watana add
400 MW capacity
and He-Regulation
Oam
Watana add 5G1W
Tunne 1 Scheme 3 J[JiW
TOTAL SYSTEM 118[)-IW
Watana
2225 ft 400MW
Watana
add 40G1W capacity
and He-Regulation
Dam
High Devil Canyon
1470 ft 40G1W
Portage Creek
1030 ft 150MW
TOTAL SYSfEH 1350 MW
Capital Cost
$ Millions
(1980 values)
1390
790
1060
J27ilj
1740
250
1500
miT
1740
250
860
650 ;;mr
Stage/Incremental Data
Earliest Reservoir
On-line Full Supply
1 Date level -ft.
1995
1997
1993
1994
1995
1996
1998
2000
1750
1750
2JJO
2200
2200
1475
2200
2200
1450
1020
MaxitnURI
Seasonal
Draw-
down-ft.
150
150
150
150
150
4
150
150
100
50
umu a 1ve
System Data
Annual
Energy
Production Plant
Firm Avg. Factor
GWH GWH %
2400 2760
3170 4080
4430 5540
2670 2990
2670 3250
4890 5430
2670 2990
2670 J250
4520 52!lll
5110 6000
79
49
47
85
46
53
85
46
50
51
(f)-Allowing for a J year overlap construction period between major dams ..
(2} Plan 1.2 Stage J is less expensive than Plan 1.3 Stage 2 due to lower mobtlization costs.
(3) Assumes FERC license can be filed by June 1984, ie. 2 years later than for the Watana/Devil Canyon Plan 1.
TABLE G.B-RESULTS Of ECONOMIC ANALYSES Of SUSITNA PlANS-MEDIUM LOAD FORECAST
Sus1Ena Oevei~n£ Pian Inc. Installed Capac1ty (MW) by lotal System Total System
lXI ine Dates Category in 2010 Installed Present Remarks Pertaining to
Plan Stages OGP5 Run niermai R~ilro Capacity In Worth Cos~ the Susitna Basin
No. 1 2 3 4 Id. No. Coal Gas oll Other Sus1Ena 2010-MW $ Million Development Plan
E1.1 1993 2000 LXE7 300 426 0 144 1200 2070 5850
E1.2 1992 1995 1997 2002 l5Y9 200 501 0 144 1200 2045 6030
E1.3 1993 1996 2000 LSJ9 300 426 0 144 1200 2070 5850
1993 1996 L7W7 500 651 0 144 BOO 2095 6960 Stage 3, Devil Canyon Dam
not constructed
1996 2001 2005 LA07 400 276 30 144 1200 2050 6070 Delayed implementation
schedule
E1.4 1993 2000 LCK5 zoo 726 50 144 BOO 1920 5890 Total development limited
to BOO MW
t-Ddified
E2.1 1994 2000 LH25 400 651 60 144 BOO 2055 6620 High Devil Canyon 1 imited
to 400 MW
Ez.3 1 1993 1996 2000 L601 300 651 20 144 1200 2315 6370
1993 1996 LE07 500 651 30 144 BOO 2125 6720 Stage J, Vee Dam,. not
constructed
Modified
E2.3 1993 1996 2000 LEB3 300 726 220 144 1300 2690 6210 Vee dam replaced by
Chakachamna dam
3. 1 1993 1996 2000 L607 200 651 JO 144 1180 2205 6530
Special
3.1 1993 1996 2000 l615 200 651 30 144 1180 2205 6230 Capital cost of tunnel
reduced by 50 percent
E4.1 1995 1996 1998 LTZS 200 576 30 144 1200 2150 6050 Stage 4 not constructed
NOTES:
(1) Adjusted to incorporate cost of re-regulation dam
VERY LOW FORECAST 1
E1,4 1997 2005 L7B7 0 651 50 144 BOO 1645 3650
LOW LOAD FORECAST
E1. 3 1993 1996 2000 Law energy demand does not
warrant plan capacities
E1,4 1993 2002 LC07 0 351 40 144 BOO 1335 4350
1993 LAK7 200 501 80 144 400 1325 4940 Stage 2, Devil Canyon Dam,
not constructed
(2,1 1993 2002 LG09 100 426 30 144 BOO 1500 4560 High Devil Canyon limited
to 400 HW
1993 LBU1 400 501 0 144 400 1445 4850 Stage 2; Vee Dam, not
constructed
E2.3 1993 1996 2000 low energy demand does not
warrant plan capacities
Special
3.1 1993 1996 2000 L613 0 576 20 144 7BO 1520 4730 Capital cost of tunnel
reduced by SO percent
3.2 1993 2002 L609 0 576 20 144 780 1520 5000 Stage 2, 400 ~~ addition
to Watana, not constructed
HIGH LOAD FORECAST
E1,3 1993 1996 2000 LA7J 1000 951 0 144 1200 3295 10680
Modified
20052 E1.3 1993 1996 2000 LBV7 BOO 651 60 144 1700 3355 10050 Chakachamna hydroelectric
generating station (480 MW)
brought on line as a fourth
stage
£2.3 1993 1996 2000 LBVJ 1300 951 90 144 1200 3685 11720
Modified
20032 E2. 3 1993 1996 2000 LAY1 1000 876 10 144 1700 3730 11040 Chakacharnna hydroelectric
generating station (480 MW)
brought on line as a fourth
stage
NOTE:
(1) Incorporating load management and conservation
.... .... ~ ~ .. ~ ~ ~ ---.. .. ------IABLf G.9 -RESULTS Of ECONOMIC ANALYSES Or SUSITNA PLANS -LOW AND HIGH LOAD FORECAST
Sus1lna Devel~n[ Plan Inc. In s t a lled Capacity (RW) by Total Syale111 folal Syale~~~
frl 1n c Dales Cate~r~ In 2010 Installed Present Re•arks Perta i n1ng to
P lfm Sta9e s OGP~ Run Thermal R~dro Capacity In Worth ~at the Susltna Basin
No . 2 ~ li ld. No. Coal !:as !hi Dlfler SuaUna 2010-MW S Million Dave lopment P len
VERY LOW FORECAST 1
E 1.4 1997 2005 L7B7 0 6~1 ~0 144 800 164~ }6~0
LOW LOAD FORECAST
[l.J 1993 1996 2000 Low energy de111and does not
warrant plan capacities
[ 1.4 19 9 3 2002 LC07 0 }~1 40 144 BOO ,,~ 4no
1993 LRK7 200 ~01 80 144 400 132~ 4940 St&QH 2, Devil Canyon Oa ~,
not constructed
f2 .1 199J 2002 LG09 100 426 JO 144 BOO 1 ~00 4 ~60 High Devil Canyon liMited
to 400 MW
1993 LBU1 400 ~01 (I 144 400 144~ 41l ~O Stag e 2, Vee Da111, not
constructed
[2 .3 1993 1996 2000 Low energy deMand does not
warrant plan capacitlea
Speci Al
).1 19'.1) 1996 2000 :..60 0 ~76 7 (1 144 lBO 1~20 47 JO Capital cost or tunnel
r educed by ~0 percent
3 .2 1993 2002 L609 0 ~76 20 144 70 0 1 ~20 ~000 Stage 2, 400 HW addit ion
to Walan a , not constructed
HIGH lOAD fORECA ST
[ 1,' 19'}J 1996 2000 LA7 J 1000 9~1 0 144 1200 }29~ 10680
1-bd i f lt~d 200~2 [ 1, 3 1993 1Q96 2000 LBV7 800 651 60 144 1700 3J55 100 ~0 Chakachamna hydroe lect ri c
generating s tation (480 MW )
hrolHJhl on I ina as a fourth
stage
[2 .' 1993 1996 2000 LBV3 1JOO 9~1 90 144 lt'~:J 360'> 11720
Mod 1 r 1ed
2011}2 r 2.' 199} 199 6 20 00 LAY! 1000 876 10 144 1700 37 JO 11040 Chakachamna hydroelectr ic
generating alation (480 MW )
b rouqht on line as a fourth
stage
NOT [:
(1 ) Incorporating l oa d management and conservation
Interest Rate
fuel Cost ($ million Btu,
natural gas/coal/oil)
fuel Cost Escalatton (%;
natural gas/coal/oil)
Economic Life of Thermal
Plants (year, natural
gas/coal/oil)
Thermal Plant Capital
Cost ($/kl'l, natural gas/
coal/oil)
\1atan2/Devil Canyon Capital
Cost ($million, Walana/
Devil Canyon)
Probabilistic Load forecasl
!:!Qill.:
(1) Alaskan cost adjustment
(2) Excluding AfOC
TABLE G.10-RESULTS Of ECONOMIC SENSITIVITY ANALYSES fOR GENERATION SCENARIO
INCORPORATING SUSITNA BASIN DEVELOPMENT PLAN E1.3 -MEDIUM fORECAST
ota
System
by Present
liorth
Parameter OGPS Run
5% LfS5 300 426 0 144 1200 2070 4230
9% LfS7 300 426 0 144 1200 2070 2690
1. 60/0. 92/J. 20 L533 100 576 20 144 1200 2040 S260
0/0/0 L5S7 0 651 30 144 1200 2025 4360
3.9S/0/3.SS LS63 300 426 0 144 1200 2070 S590
45/45/30 LS8S 45 367 233 144 1200 1989 6100
3S0/213S/77S L[l)7 300 426 0 144 1200 2070 S740
1990/1110 LSG1 300 426 0 144 1200 2070 6210
2976/1350 LD75 300 426 0 144 1200 2070 6810
LST5 200 1476 140 144 1200 J160 6290
faclor reduced from 1.8 to 1.4 (see Sect ion a .. ) -
20% fuel cost ~eduction
Zero escalation
Zero coal cost escalation
Economic lives increasr:irl
by SO%
Coal capital cost reduced
by 22%
Capital cost for Devil
Canyon Dam increased by 23%
Capital cost for both dams
increased by SO%
Worth
All Thermal No Renewals Very Low 1 LRT7 soo 426 90 144 1160 4930
No Renewals Low L 7E1 700 300 40 144 138S S920
W ilh Renewals Low L2C7 600 657 30 144 1431 5910
No Renewals t-Ied lUll LHE1 900 801 50 144 189S 8130
With Renewals MediU11 LME3 900 807 40 144 1891 8110
No Renewals High L7f7 2000 1176 50 144 3370 13S20
With Renewals High L2E9 2000 576 130 144 3306 13630
No Renewals Probabilistic LOf3 1100 1176 100 144 3120 8320
Thermal Plus No Renewals Plus: Med i'-"1 L7W1 600 576 70 764 2010 7080
Alternative Chakachamna (500)2-1993
Hydro Keetna (120)-1997
No Renewals Plus: Medium LFL7 700 501 10 814 202S 7040
Chakachamna (500)-1993
Keetna (120)-1997
Snow (50)-2002
No Renewals Plus: Medium LWP7 500 576 60 847 1983 7064
Chakachamna (S00)-1993
Keetna (120)-1996
Strandline (20),
Allison Creek (B),
Snow (50)-1998
No Renewals Plus: Medi.urn LXf1 700 426 30 847 2003 7041
Chekachamna (500)-1993
Keetna (120)-1996
Strandline (20),
Allison Creek (8),
Snow (50)-2002
No Renewals Plus: Medium L403 soo 576 30 947 2053 7088
D1akacharnna (500)-1993
Keetna (120)-1996
Snow (50), Cache (50),
Allison Creek (B),
Talkeetna-2 (50),
Strandline (20)-2002
~;
(1) Incorporating load management
(2) lnslalled capacity
and conservation
TABLE G.12-RESULTS OF ECONOMIC ANALYSES FOR GENERATION SCENARIO
INCORPORATING THERMAL DEVELOPMENT PLAN -MEDIUM FORECAST
Installed Capacity (MW)
by in 2010
Parameter OGPS Run
Interest Rate 5~ LEA9 900 800 50 144 1895 5170
9% LEB1 900 601 50 144 1895 2610
Fuel Cost ($ million Btu,
natural gas/coal/oil)
fuel Cost Escalation (%,
1.60/0.92/3.20 L1K7 800 876 70 144 1890 7070 20% fuel cost reduction
natural gas/coal/oil) 0/0/0 L547 0 1701 10 144 1855 4560 Zero escalation
3.98/0/3.58 L561 1100 726 10 144 1980 6920 Zero coal cost escalation
Economic Life of Thermal
Plants (year) natural
gas/coal/oil 45/45/}0 L58J 1145 667 51 144 2007 7850 Economic life increased
50%
Thermal Plant Capital
Cost ($/kW, natural gas/ 350/2135/778 LAL9 1100 726 10 144 1980 7590 Coal capital cost reduced
coal/oil) by 22~
16
15
14
13
12
II
:r
LEGEND
HES-GH • HIGH ECONOMIC GROWTH + HIGH GOVERNMENT EXPENDITURE
MES-GM • MODERATE ECONOMIC GROWTH+ MODERATE GOVERNMENT EXPENDITURE
LES-GL • LOW ECONOMIC GROWTH +LOW GOVERNMENT EXPE('lDITURE
LES-GL ADJUSTED • LOW ECONOMIC GROWTH +LOW GOVERNMENT
EXPENDITURE + LOAD MANAGEMENT AND CONSERVATION
I
I
I
I
I
I
I
I
I
I
I HES-GH
I
I
I
I
I
I
I
I
~ 10
(!)
~
z
Q
tit
0:: w z w
(!)
>-1-
(3
0::
1-
0 w
-l w
9
8
7
6
I' ,"
5
2
I'
I' ,
I'
I'
I'
/
,
I'
,
, , , ,
I
I
------LES-GL
ADJUSTED
0~------~--------~--------~--------'---------L--------~
1980 1985 1990 1995
YEAR
2000 2005 2010
ENERGY FORECASTS USED FOR GENERATION PLANNING STUDIES
IX H -ENGINEER
the project planning studies outlined in Sections 6 and 7 were completed, a
was made with more detailed engineering studies for the selected Watana
and Devil Canyon sites. The major thrust of these studies was twofold:
To select the appropriate dam type for the two sites;
To undertake some preliminary design of the selected dam types.
is section briefly outlines the results of the studies to date. A more
iled description will be incorporated in the Project Feasibility Report.
-De vi 1 Canyon Site
Dam Type Studies
A major advantage of an arch dam relative to a comparable rock/earthfill
structure is the generally lower cost of the auxiliary structures, which
can be incorporated within the dam itself or reduced in overall length
corresponding to the reduced base width of the concrete dam. In order to
study the relative economics of different dam types it was necessary to
develop general arrangements of the sites including the diversion, power
facilities and spillways. A representative arrangement was studied for
each of the following dam types at the Devil Canyon site:
- A thick concrete arch dam;
- A thin concrete arch dam; and
- A rockfi ll dam.
None of these layouts are intended as the final site arrangement, but each
wi 11 be sufficiently representative of the most suitable arrangement asso-
ciated with each dam type to provide an adequate basis for comparison.
Each type of dam is located just downstream of where the river enters Devil
Canyon, close to the canyon's narrowest point, which is the optimum loca-
tion for all types of dams. A brief description of each dam type and con-
figuration is given below.
(i) Thick Arch Dam
As shown on Plates H.l and H.2, the main concrete dam is a single
center arch structure, acting partly as a gravity dam, with a vertical
cylindrical upstream face and a sloping do~mstrearn face inclined at
1V:0.4H. The maximum height of the dam is 635 feet with a uniform
crest width of 30 feet, a crest length of approximately 1400 feet and
a maximum foundation width of 225 feet. The crest elevation is 1460
feet. The center portion of the dam is founded on a massive concrete
pad constructed in the excavated river bed. This central section
incorporates a service spillway with gated orifice spillways discharg-
ing down the steeply inclined downstream face of the dam into a single
large stilling basin ~lith side1valls anchored into solid bedrock set
below river level, spanning the valley.
H-1
The main dam terminates in thrust blocks high on the abutments. The
left abutment thrust block incorporates an emergency gated control
spillway structure which discharges into a rock channel running well
downstream and terminating at a high level in the river valley.
Beyond the control structure and thrust block a low lying saddle on
the left abutment is closed by means of a rockfill dike founded on
bedrock. The powerhouse houses four 150 MW units and is located
underground within the right abutment. The multi-level intake is
constructed integrally with the dam and connected to the powerhouse by
vertical steel-lined penstocks.
The service spillway is designed to pass the 1:10,000 year routed
flood with larger floods discharged downstream via the emergency
spillway.
(ii) Thin Arch Dam
As shown on Plate 10, the main dam is a two-center, double curved arch
structure of similar height to the thick arch dam, but with a 20 foot
uniform crest width and a maximum base width of 90 feet. The crest
elevation is 1460 feet. The center section is founded on a concrete
pad and the extreme upper portion of the dam terminates in concrete
thrust blocks located on the abutments.
The main service spillway is located on the right abutment and
consists of a conventional gated control structure discharging down a
concrete-lined chute terminating in a flip bucket. The bucket
discharges into an unlined plunge pool excavated in the riverbed
alluvium and located sufficiently downstream to prevent undermining of
the dam and associated structures.
The main spillway is supplemented by orifice type spillways located
high in the center portion of the dam which discharge into a
concrete-lined plunge pool immediately downstream of the dam. An
emergency spillway consisting of a fuse plug discharging into an
unlined rock channel which terminates well downstream, is located
beyond the saddle dam on the left abutment.
The concrete dam terminates in a massive thrust block on each abutment
which, on the left abutment, adjoins a rockfill saddle dam.
The service and auxiliary spillway's are designed to discharge the
1:10,000 year flood. Excess flows for storms up to the probable
maximum flood will be discharged through the emergency left abutment
spillway.
(iii) Rockfill Dam
As shown on Plate 1, the rockfill dam is approximately 670 feet high.
It has a crest width of 50 feet, upstream and downstream slopes of
1:2.25 and 1:2 respectively, and contains approximately 20 million
H-2
cubic yards of material. The central impervious core is supported by
a downstream semi-pervious zone. These two zones are protected up-
stream and downstream by filter and transition materials. The shell
sections are constructed from blasted rock. All dam sections are
founded on sound bedrock. External cofferdams are founded on the
riverbed alluvium.
A single spillway consisting of a gated control structure, chute and
dmmstream unlined plunge pool is located on the right abutment. This
is designed to pass without damage the 1:10,000 year routed flood.
Excess capacity is provided to allow discharge of the probable maximum
flood with no damage to the main dam.
b) Construction Materials
Sand and gravel for concrete aggregates are believed to be available in
sufficient quantities immediately upstream in the Cheechako fan and ter-
races. The gravel .and sands are formed from the granitic and metamorph·ic
rocks of the area, and at this time it is anticipated that they will be
suitable for the production of aggregates after a moderate amount of
screening and washing.
Material for the rockfill dam shell would be blasted rock, some of it
coming from the site excavations.
It is anticipated that some impervious material for the core is available
from the till deposits forming the flat elevated areas on the left abutment
and that other suitable borrow materials will be available in high lying
areas within the three mi 1 e upstream reach of the river; hmvever, none of
these deposits have yet been proven.
c) General Considerations
The geology of the site is as discussed in Section 7 and it appears at this
stage that there are no geological or geotechnical concerns that would pre-
clude any of the dam types from consideration. A rockfill dam would be
more adaptable than a concrete arch dam to poorer foundation conditions
although, at present, foundation and abutment loadings from the arch dams
appear well within acceptable limits.
The thick arch dam allows for the incorporation of a main service spillway
chute on the downstream face of the dam which discharges into a spi 11 way
located deep within the present riverbed. This spillway can pass routed
floods with a return frequency of less than 1:10,000 years. For the thin
arch and rockfill alternatives the equivalent discharge capacity has to be
provided separately through the abutments.
Stresses under hydrostatic and temperature loadings within the thick arch
dam are generally lower than those for the thin arch alternative. However,
finite element analysis has shown that the additional mass of the dam under
seismic loading produces stresses of a greater magnitude in tt1e thick arch
dam than in the thin arch dam. If the surface stresses approach the
maximum allowable at a particular section, the remaining understressed area
of concrete is greater for the thick arch and the factor of safety for the
H-3
dam is correspondingly higher. The thin arch is, h011ever, a more efficient
design and better utilizes the inherent properties of the concrete. It is
designed around acceptable predetermined factors of safety and requires a
much smaller volume of concrete for the actual dam structure.
At the time of completion of layouts indications were that the thin arch
dam would be feasible. A thick arch dam layout was completed to determine
if it provided any outstanding advantages, and in case a thin arch, in
spite of indications, should prove infeasible. It did not appear to have
any outstanding merits compared to a thin arch dam and would be more
expensive due to the larger volume of concrete.
A rockfill dam constructed to the design currently assumed offers no cost
savings relative to the thin arch consideration of more conservative
designs in which the upstream rockfill slopes are revised from 1:2.25 to
1:2.75 to meet possibly more stringent seismic design requirements. These
cost increases 1'/0uld occur in the dam itself and in spillway and power
facilities because of the larger base width of the dam.
Studies have therefore continued in an effort to confirm the feasibility of
the thin arch alternative.
(d) Preliminary Arch Dam Design
Both thin and thick arch dam designs were originally analyzed by means of a
computer program based on finite element analysis. Results from these
analyses indicated significantly lower stresses for the thick arch under
hydrostatic and temperature loadings, as would be anticipated. Substan-
tially higher tensile stresses were found under seismic loading conditions
for both dams, a 1 though somewhat higher in the case of the thick arch dam.
Stresses close to the foundations and abutments were distorted by the
finite element Jnodel because of the coarse mesh spacing of the selected
nodes. To produce results which could more readily be interpreted, it was
decided to use the trial load method and the associated program Arch Dam
Stress Analysis System (ADSAS) developed by the USBR. The resu1ts of this
analysis are presented in the following paragraphs.
The thin, two-center arch dam design is located approximately norma1 to the
valley. There is a gradual thickening of the dam towards the abutments,
but the two-center configuration produces similar thickness and contact
pressures at equivalent rock/concrete contact elevations and a symmetrical
distribution of pressures across the dam. Under hydrostatic loads no ten-
sion is evident at the dam faces. Under extreme temperature distribution
as determined by the USBR program HEATFLOvJ, full reservoir conditions bring
about low tensile stresses on both faces across the crest of the dam. These
approach the allowable tensile stress of 150 psi.
Although analysis has still to be finalized for seismic loadings, indica-
tions are that the concrete thin arch dam at Devil Canyon will be
structurally feasible.
H-4
H.2 -Watana Site
(a) Dam Type Studies
A rockfill dam layout (Plate 12) has been studied at Watana with the dam
sited between the northwest trending shear zones of the "Fins" and the
"Fingerbuster". The dam is close to the alignment proposed by the Corps of
Engineers and is skewed slightly to the valley in a north-northwest
direction. The approximate height of the dam is 900 feet, the upstream and
downstream slopes are 1V:2.75H and 1V:2H respectively, and the volume is
approximately 62 million cubic yards. The assumed crest elevation of the
dam is 2225 feet, subject to completion of reservoir level optimization
studies.
For initial study purposes, the spillway has been assumed to discharge down
the right abutment with an intermediate stilling basin and a downstream
stilling basin founded below river level. Two 35 feet diameter diversion
tunnels are located on the right bank and an 800 MW underground power
station is located on the left abutment. Optimization studies of spilh1ay,
diversion and power plant facilities are continuing.
(b) Construction Materials
At this time it is assumed that 50 percent of the rockfill for the shell
material for the dam will be blasted rock, a small proportion of which will
be obtained from site excavations; the remainder will consist of blasted
rock from borrow areas. The remaining 50 percent will be gravel materials
obtained from the downstream alluvial riverbed deposits. Gravels for
filter zones are available from alluvial deposits in Tsusena Creek. Core
material is availabde from glacial tills located approximately three miles
upstream above the right side of the river valley. This material will
require very little processing.
(c) General Considerations
As an alternative to the rockfill dam, a three-center concrete thin arch
has been considered, and layouts are shown on Plates H.3 and H.4. The
volume of the dam is 8.25 million cubic yards with additional concrete
required for the abutment thrust blocks. The overall cost of concrete will
be approximately $1,300 million as compared to $950 million for the upper
limit cost estimate for fill within the rockfill dam. Although water
passages will be shorter for faci1 ities associated with the concrete darn,
it is anticipated that these will be offset by savings in the spillway
excavation associated with the rockfill dam where excavated material can be
utilized within the dam. The overall costs for both types of dam and their
associated facilities will be evaluated further in the Project Feasibility
Report. In the meantime, study of layouts associated with the rockfill dam
has proceeded.
(d) Preliminary Darn Design
A section has been tentatively established for a rockfill dam with a near
vertical impervious core (Plate 12). At this time, no stability analyses
have been conducted on the dam, but the section is conservatively based on
H-5
Acres' past experience and on general experience throughout the world
concerning similar dam sizes and locations of similar seismic activity.
There is a possibility that further analysis will lead to a reduction in
size of the dam.
The crest width of the dam is 80 feet, the upstream slope is 1V:2.75H and
the downstream slope is 1V:2H.
The core .is composed of materials from the fine till deposits and the shell
is presently to be constructed of blasted rock from site excavations and
from borrow and gravel material taken from the riverbed.
H-6
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ARGI-I GRAVITY DAM SC~EME
5E.CTIONS
~---fA~--------------------------~----~-f--~~~~-~~~~-'_'_D_E_C_.I_9_B_I __ ~~~~~~~
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GENERAL ARRANGEMENT
GEOMETRY TYPICAL ARCH SECTION
NOTES:
1.) 'PCC'tii.JCICATES POH-.li OF CHANGE OF CUR.IIA'TURE..
Z.} '!!:' INOICATI5.!:> CE.N~ OF 1!.)\,TAAI'OS ARCH.
a1 'I' INOICATE.!:> CENTe:ll! Of IN'TAAC>Q!! A.RC.H.
4.! THE sUS$CRIPT "o' INPIC.O.TE:!I oUTIR ~e::NT'.
!5.) TI-lE 51.165CRIPT' 'c • INOICAiES CENTI:tA.i.. SEGMENT.
G.) THE SUI!!SCI'!_IPT 't.:' INPICATE.S \.eFT 51011 OF ARCH i..OOKINI!> Ui>STREA.M.
Zl THE SUBSCRIPT 'R' INPICATIIIS RIGIIT SID!!. oF ARCI'i i..OOKII>o!G Ui>:oTRCAM.
8.1 TIIR.UST' EIL.O<::K!!I ARE NOT SHOWN.
!1.} CONTOUR I..INES ('!HoW GROUND SURI"ACE
DATE REVJ$10HS
ARCH El..I!'M ·cOMPOUND ce~1 ~LA(~}
NO. (FEET') ANSI.E ou.
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4 l&oo !51. 0 41.5 44-
:s 1~!50 t9.0 40.!S 41
(p 1!500 Z9.0 37 '!7
7 ,.;~o 0 Z'! Z!l
TABLE OF ARCH ANGLES
PLATE H 3
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJEC't
WA.TANA
ARCH DAM GEOMETRY
988 ... 189107'
( NOT TO SCAI...E )
SE
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PROFILE OF DAM LOOKING UPSTREAM
~--N----UI-JE OF INTRAOOS CENTERS
LINE 01" EXTRADOS CEIJTER5 I"OR
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SECTIONS ALONG PLANES OF CENTERS
DATE
SOUND ROCK SURFACa
( NOT OEV ELOPED l
4000
PLATE H4
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
WA.TANA
ARCH DAM GEOMETRY
APPENDIX I -ENVIRONMENTAL STUDIES
r While performing an environmenta 1 review of the various deve 1 opment options r within the-Susitna Basin, Acres I environmental subconsultant, TES, prepared two
l reports entitled "Preliminary Environmental Assessment of Tunnel Alternatives"
I· and "Environmental Considerations of Alternative Hydroelectric Development I Schemes for the Upper Susitna Basin". These reports as submitted are contained
! in this Appendix.
~ I.l -Summary .
" These reports, augmented by add it i ona 1 information that became avail ab 1 e
subsequent to their preparation, formed the basis of the comparison of the Devil
Canyon Dam with the tunnel alternative and the reach by reach comparison of
Watana/Devil Canyon versus High Devil Canyon/Vee development plans.
·The environmental assessments of thermal developments and of alternative
hydroelectric developments outside of the Susitna Basin are given in Appendix B
and C, respectively.
I
(a) Devil Canyon Dam versus Tunnel Alternative
(i) Environmental Comparison
The environmental comparison of the two schemes is summarized in
Table B.l. Overall, the tunnel scheme is -judged to be superior
because:
-It offers the potential for enhancing anadromous fish populations
downstream of there-regulation dam due to the more uniform·flow
distribution that will be achieved in this reach.
-It inundates 13 miles less of resident fisheries habitat in river
and major tributaries.
-It has a lower impact on wildl_ife habitat due to the smaller
inundation of habitat by the re-regulation dam.
-It has a lower potential for inundating archeological sites due to
the smaller reservoir involved.
-It would preserve many or the characteristics of the Devil Canyon
gorge, which is considered to be an aesthetic and recreational
resource.
(ii) Social Comparison
Table I.2 summarizes the evaluation in terms of the social criteria
of the two schemes. In terms of impact on state and local economics
and risks due to seismic exposure, the two schemes are rated
equally. However, the dam scheme has, due to its higher energy
yield, more potential for displacing nonrenewable energy resources
and therefore scores a slight overall plus in terms of the social
evaluation criteria.
I-1
(b) Watana/Devil Canton versus High Devil Canton/Vee
(i) Environmental Comparison
The evaluation in terms of the environmental criteria is summarized
in Table B.3. In assessing these plans, a reach by reach comparison
is made for the section of the Susitna River between Portage Creek
and the Tyone River. The Watana-Devil Canyon scheme would create
more potential environmental impacts in the Watana Creek area.
However, it is judged that the potential environmental impacts which
would occur in the upper reaches of the river with a High Devil
Canyon-Vee development are more severe in comparison overall.
From a fisheries perspective, both schemes would have a similar
effect on the downstream anadromous fisheries, although the High
Devil Canyon-Vee scheme would produce a slightly greater impact on
the resident fisheries in the Upper Susitna Basin.
The High Devil Canyon-Vee scheme would inundate approximately 14
percent (15 miles) more critical winter river bottom moose habitat
than the Watana-Devil Canyon scheme. The High Devil Canyon-Vee
scheme would inundate a large area upstream of the Vee site utilized
by three subpopulation of moose that range in ·the northeast section
of the basin. The Watana-Devil Canyon schemes would avoid the
potential impacts on moose in the upper section of the river;
however, a larger percentage of the Watana Creek basin would be
inundated.
The condition of the subpopulation of moose utilizing this Watana
Creek Basin and the quality of the habitat appears to be decreasing.
Habitat manipulation measures could be implemented in this area to
improve the moose habitat. Nevertheless, it is considered that the
upstream moose habitat losses associated with the High Devil
Canyon-Vee scheme would probably be greater than the Watana Creek
losses associated with the Watana-Devil Canyon scheme.
A major factor to be considered in comparing the two development
plans is the potential effects on caribou in the region. It is
judged that the increased length of river flooded, especially
upstream from the Vee dam site, would result in the High Devil
Canyon-Vee plan creating a greater potential diversion of the
Nelchina herd's range. In addition, a larger area of caribou range
would be directly inundated by' the V.ee reservoir.
The area flooded by the Vee reservo·ir is also considered important
to some k~ furbearers, particularly red fox. In a comparison of
this area with the Watana Creek area that would be inundated with
the Watana-Devil Canyon scheme, the area upstream of Vee is judged
to be more important for furbearers.
I-2
As previously mentioned, between Devil Canyon and the Oshetna River
the Susitna River is confined to a relatively steep river valley.
Along these valley slopes are habitats important to birds and black
bears. Since the Watana reservoir would flood the river section
between the Watana Dam site and the Oshetna River to a higher
elevation than would the High Devil Canyon reservoir (2200 feet as
compared to 1750 feet), the High Devil Canyon-Vee plan would retain
the integrity of more of this river vall~ slope habitat.
From the archeological studies done to date, there tends to be an
increase in site intensity as one progresses towards the northeast
section of the Upper Susitna Basin. The High Devil Canyon-Vee plan
would result in more extensive inundation and increased access to
the northeasterly section of the basin. This plan is therefore
judged to have a greater potential for directly or indirectly
affecting archeological sites.
Due to the wilderness nature of the Upper Susitna Basin, the
creation of increased access associated with project development
could have a significant influence on future uses and management of
the area. The High Devil Canyon-Vee plan would involve the
construction of a dam at the Vee site and the creation of a
reservoir in the more northeasterly section of the basin. This plan
would thus create inherent access to more wilderness than would the
Watana-Devil Canyon scheme. Since it is easier to extend access
than to limit it, inherent access requirements are considered
detrimental; the Watana-Devil Canyon scheme is judged to be more
acceptable in this regard.
Except for the increased loss of river valley, bird, and black bear
habitat, the Watana-Devil Canyon development plan is judged to be
more environmentally acceptable than the High Devil Canyon-Vee 'plan.
Although the Watana-Devil Canyon plan is considered to be the more
environmentally compatible Upper Susitna development plan, the
actual degree of acceptability is a question being addressed as part
of ongoing studies.
(ii) Social Comparison
Table B.2 summarizes the evaluation in terms of the social criteria.
As in the case of the dam versus tunnel comparison, the Watana-Devil
Canyon p 1 an is judged to h_ave a slight advantage over the High De vi 1
Canyon-Vee plan. This is because of its greater potential for
displacing nonrenewable resources.
).2 -TES Report
Reports prepared by TES on the environmental assessment of the Devil Canyon Dam
Versus the Tunne 1 alternative and Watana/Devil Canyon versus High Devil
Canyon/Vee development p 1 ans are given in their entirety be low.
I-3
0
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT .
PRELIMINARY ENVIRONMENTAL ASSESSMENT
OF TUNNEL ALTERNATIVES
by
Terrestrial Environmental Specialists, Inc.
Phoenix, New York
f~
Acres American Incorporated
Buffalo, New York
December 15, 1980
TABLE OF CONTENTS
Page
1 -INTRODUCTION.............................................. 1
2 -COMPARISON OF TUNNEL ALTERNATIVES.......................... 3
2.1. Scheme 1........................................ 3
2. 2 Scheme 2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
2.3 Scheme 3........................................ 3
2.4 Scheme 4 ........... ·............................. 5
2.5 Location of Devils Canyon Powerhouse............ 5
2.6 Disposal of Tunnel Muck......................... 6
3-COMPARISON OF SCHEME 3 WITH CORPS OF ENGINEERS' SCHEME.... 8
APPENDIX A -DESCRIPTIONS OF TUNNEL SCHEMES
APPENDIX B -AMENDED DESCRIPTION OF TUNNEL SCHEME 4
1 -INTRODUCTION
In response to a request by Acres American, Inc. for input into
Subtask 6.(}2 of th.e Susitna Hydroelectric Project feasibility study,
Terrestrial Environmental Specialists, Inc. (TES) did a preliminary
assessment of tunnel alternatives. ,The objectives of this assessment
were:
(1) to compare environmental aspects of four alternative tunnel
schemes;
(2) to compare the best tunnel scheme, as selected by Acres,
with the two-dam scheme (Watana and Devils Canyon) proposed by
the U.S. Army Corps of Engineers;
(3) to compare two revised locations for the downstream
powerhouse; and
(4) to comment on alternative methods of disposal of tunnel
muck, the rock removed to create a tunne 1.
The environmental assessment was based on both the project
descriptions in a letter dated October 29, 1980, from Acres to TES, as
amended by a letter dated December 11, 1980, and on conversations
between representatives of these ffrms. Copies of these letters may
be found in the appendices to this report. At the time this
assessment was performed complete information was not available on the
various tunnel schemes under consideration. Therefore, TES views this
assessment as only a preliminary study.
One assumption made by TES, and confirmed by Acres, is that the dam,
pool elevation, and pool level fluctuations of Watana are as described
by the Corps of Engineers and would not differ among the .five schemes.
r.: If, on the contrary, any of the tunnel schemes increase the
r probability that the pool level at Watana may be lower than that
' ii proposed by the Corps or if a particular scheme may moderate the poo 1
fluctuations,
;·.
may, in turn,
then the environmental
be affected.
1
assessment of the tunnel schemes
It is recognized that an environmental assessment for ranking
alternative schemes must include some subjective value judgements. A
given scheme may be preferable from the standpoint of one
environmental discipline (e.g. fisheries) whereas another scheme may
be better from another aspect (e.g. terrestrial ecology or
aesthetics). To·recommend any one scheme over another involves the
difficult task of making trade-offs among the environmental'
disciplines. Such trade-offs are likely to be controversial.
2
2 -COMPARISON OF TUNNEL ALTERNATIVES
2.1 Scheme 1
The environmental impacts associated with this tunnel scheme are
likely to be greater than those of at least one of the,other tunnel
schemes evaluated (i.e. Scheme 3). The main criterion for this
assessment is the adverse effects, particularly on fisheries and
recreation, of the variable downstream flows (4000-14000 cfs daily)
created by the Devils Canyon powerhouse peaking operation. ·other
negative impacts would result from construction of both the
re-regulation dam and a relatively long tunnel. Tunnel impacts are
similar to those of Schemes 2 and 4 and include disturbance of Susitna
tributaries as a result of tunnel access and the potential problems
associated with disposal of a relatively large volume of tunnel muck.
2.2 Scheme 2
Like Scheme 1, this scheme involves adverse environmental impacts
associated with variable downstream flows caused by peaking operation
at the Devils Canyon powerhouse (4000-14000 cfs). Without the
re-regulation dam, however, less land would be inundat~d and the
impacts associated with construction of this relatively small dam
would be avoided, although flow fluctuations above Devils Canyon would
be more severe. Like Scheme 1 too, the long tunnel proposed here will
have negative consequences, including disturbance of tributaries for
tunnel access and the potential problems connected with tunnel muck
di sposa 1.
2.3 Scheme 3
The overall environmental impact of this scheme is considered less
than that related to the two previous schemes, and also less than that
related to the fourth scheme as amended (Appendix B). The relatively
constant discharge (about 8300-8900 cfs) from the Devils Canyon
powerhouse is desirable for maintaining downstream fish habitat and
recreational potential. Since it may allow anadromous fish access to
3
a previously inaccessible 15-mile stretch of the Susitna River, Scheme
3 could, in fact, offer a rare opportunity for enhancement of the
fisheries resource. The newly available section of river could
perhaps be actively managed to create or improve spawning habitat for
salmon. This mitigation potential is dependent upon the location of
the downstream powerhouse (above or below the present rapids) and the
determination of whether project flows through Devils Canyon will
still constitute a barrier to fish passage. The data needed for this
determination are not yet available.
A compensation flow release of 1000 cfs at the re-regulation dam is
not the same as 1000 cfs at the Watana dam. Because fewer tributaries
will augment the compensation flow under this re-regulation scheme,
the compensation flow will need to be slightly greater than with the
other schemes to result in the equivalent flow at Devils Canyon.
Compensation flow should be sufficient to maintain a certain degree of
riverine character, and thus should be kept to a maximum even in the
absence of a salmon fishery. Of course, if the viability of a tunnel
scheme is jeopardized, the impacts of the alternative scheme must be
compared to the impacts of a lesser compensation flow.
As with any of the tunnel schemes, the wildlife habitat in the stretch
of river bypassed by the tunnel might improve temporarily because of
an increase in riparian zone vegetation. With Scheme 3, however, this
stretch of river is shorter than with the other tunnel schemes; so a
smaller area would benefit. The wildlife habitat downstream ·of Devils
Canyon powerhouse may well benefit from the flow from the
hydroelectric project, regardless of the tunnel scheme chosen. The
improvements to that habitat may be somewhat greater, though, with the
constant flows allowed in Scheme 3 than with the variable flows
resulting from peaking in the other tunnel schemes.
One environmental disadvantage of this scheme compared to the others -is the larger area to be inundated by the re-regulation reservoir.
This area includes known archeological sites in addition to wildlife
habitat. Nevertheless, it is felt that this di?advantage is offset by
the more positive environmental factors associated with constant
discharge from the Devils Canyon powerhouse.
4
' ' '
I
2.4 Scheme 4
Scheme 4, as originally described (Appendix A), was determined to be
environmentally. superior to the other tunnel schemes, because of
constant downstream flows combined with the lack of a lower reservoir.
However, Acres' analysis determined that this baseload operation is
most likely incapable of supplying the peak energy demand. ·Scheme 4,
as amended (Appendix B), is a peaking operation at Watana with
baseload operation at the tunnel. Since the net daily fluctuations in
flow below Devils Canyon would be considerable (i.n the order of
4000-13000 cfs), the amended Scheme 4 was judged as less desirable
than Scheme 3 from an environmental standpoint. Although Scheme 4
would avoid the impacts associated with the lower dam and its
impoundment (as planned under Scheme 3), the adverse impacts that
would result from fluctuating downstream flows are considered to be an
overriding factor.
Another, less significant disadvantage of Scheme 4 (and shared by
Schemes 1 and 2) in contrast to Scheme 3 is the longer tunnel length
planned for the former and, perhaps, the proposed location of the
tunnel on the north side of the river. The sites chosen for disposal
of tunnel muck and for the requ.ired access roads in any of these
schemes (as yet undetermined} will further influence this comparison.
2.5 Location of Devils Canyon Powerhouse
Alternative locations for the Devils Canyon powerhouse have been
proposed. These consist of an upstream location abqut 5 miles above
the proposed Corps of Engineers dam site and a downstream location
about 1.5 miles below Portage Creek, as alternatives to the site
illustrated in Appendix A. The major environmental consideration is
that a powerhouse upstream of Devils Canyon would preserve much of the
aesthetic value of the canyon. In addition, the shorter tunnel would
confine construction activities to a smaller area and may result in
slightly less ground disturbance, particularly if there are fewer
access points, as well as a smaller muck dispos.al problem. A
downstream powerhouse location, on the other hand, might create a
5
mitigation opportunity by opening up a longer stretch of river that
perhaps could be managed to create salmon spawning habitat. Until
large-scale aerial photographs and cross-sectional data on the canyon
have been received and analyzed, a determination cannot be made as to
whether project flows through the canyon will still constitute a
barrier to fish passage.
Our primary responsibility is to avoid, or at least to minimize,
adverse impacts to the environment, and it must take precedence over
our desire to enhance or expand a resource. It is our opinion that
losing a resource {the aesthetic value of the Devils Canyon rapids) is
worse than losing a possible mitigation opportunity. It is not yet
known if this opportunity even exists. Furthermore, there are always
other means by which to enhance the fishery, although not necessarily
so conveniently associated with the hydroelectric project. Thus, at
this time the upstream powerhouse location is preferred.
2.6 Disposal of Tunnel .Muck
There are a number of options to be considered for disposal of the
rock removed in creating the tunnel. These include: stockpiling the
material for use in access road repair, construction of the
re-regulation dam, or stabilization of the reservoir shoreline;
disposal in Watana reservoir; dike construction; pile, cover, and
seed; and disposal in a ravine or other convenient location. It is
unlikely that the most environmentally acceptable option will also be
the most economical. Because many unknown factors now exist, a firm
recommendation cannot be made without further evaluation. It is quite
likely, however, that a combination of disposal methods will be the
best solution.
Stockpiling at least some of the material for access road repairs is
environmentally acceptable, provided a suitable location is selected
for the stockpile. Perhaps the material could be utilized for
construction of any of the access road spurs or temporary roads that
are not already completed at the time the tunnel is dug.
6
Another acceptable solution might be to stockpile the material for use
in construction of the re-regulation dam. This rock c~uld also be a
potential source of material for stabilization of the reservoir
shoreline if required. As with the previous option, an
environmentally acceptable location of the stockpile would be
required. Disposal of the material in Watana Reservoir might also be
environmentally acceptable. Consideration should be given to the
feasibility of using the material in the construction of any
impoundment control structures such as dikes. A small amount of
tunnel muck could possibly also be used for stream.habitat
development. With any of these options, the possible toxicity of
minerals exposed to .the water should be first determined by assay, if
there is any reason to suspect the occurrence of such minerals.
To pile, cover, and seed the material is worthy of further
consideration, and would require proper planning. For example, borrow
areas used in dam construction could perhaps be restored to original
contour by this method .. The source of soil for cover is a major
consideration, as earth should only be taken from an area slated for
future disturbance or inundation. If trucking soil from the reservoir
area is determined to be feasible, it might also be worthwhile to
transport a portion of the muck back for disposal in the reservoir
area.
The most economical solution might be to fi,ll a ravine with the
material or to dispose of it in another convenient location. Unless
the chosen disposal site will eventually be inundated, however,
such an arrangement is environmentally unacceptable, especially since
better options are obviously available.
7
3 -COMPARISON OF TUNNEL SCHEME 3 WITH CORPS OF ENGINEERS' SCHEME
Scheme 3 emerged as superior in Acres' preliminary economic and technical
screening. After amendment of Scheme 4, Scheme 3 was also considered to be
the best scheme from an environmental standpoint. Therefore, Scheme 3 is
to_ be compared with the two-dam scheme proposed by the U.S. Army Corps of
Engineers.
Further analysis will be in order after complete details are available on
Tunnel Scheme 3. At present, many gaps exist in the available data.
Additional information on design, operation, and hydrology, combined with
environmental field investigations at the locations of project facilities,
would permit a much more detailed comparison of these two development
alternatives. Nevertheless, from what is presently understood about Scheme
3, there is little doubt that it is, by far, environmentally superior to
the Corps of Engineers' proposal. Of course, extensive additional study
needs to be performed on whatever scheme is selected to identify its
impacts and to develop mitigation plans.
Tunnel Scheme 3 has, by any measure, a less adverse environmental impact
than the Corps of Engineers' scheme. By virtue of size alone, construc-
tion of the smaller dam (245ft.) would have less environmental impact than
the Devils Canyon dam proposed by the Corps. The river miles flooded and
the reservoir area created by the Scheme 3 re-regulat ion dam would be about
half those of the Corps' plan for Devils Canyon, thereby reducing negative
consequences, such as loss of wildlife habitat and possible archeological
sites. In addition, the adverse effects upon the aesthetic value of Devils
Canyon would be substantially lessened with Scheme 3, particularly with the
powerhouse location upstream of the proposed Corps dam site. Furthermore,
Tunnel Scheme 3 may pos~ibly present a rare mitigation opportunity_ by
creating new salmon spawning habitat that could be actively managed. With
the increase in riparian zone vegetation allowed by Scheme 3, the wildlife
habitat in the stretch of river bypassed by the tunnel might be temporarily
improved. The impacts associated with tunnel access and disposal of tunnel
muck necessitated by Scheme 3 are more than offset by the plan's
advantages. Thus, Tunnel Scheme 3 far exceeds the U.S. Army Corps of
Engineers' proposal in terms of environmental acceptability.
B
APPENDIX A
DESCRIPTIONS OF TUNNEL SCHEMES
.... ff"id
Terrestrial Environmental Specialists, Inc.
R. D. 1
Phoenix, NY 13135
Attention: Vince Lucid
October 29, 1980
P5700.06
T507
Dear Vince: Susitna Hydroelectric Project
Subtask 6.02
We woufd 1 ike you to review the en vi ronmenta 1 aspects of the tunnel a Her-
native (Subtask 6.02), which you were introduced to on October 3, 1980.
Your environmental assessment will be included in the Subtask 6.02 close-out
report, November 1980. In order to complete this close-out report on
schedule the environmental assessment is required by November 13, 1980.
The environmental assessment should include a small section on each of the
four tunnel schemes (Schemes 1, 2, 3, & 4). Physical factors of the schemes-
and the COE selected plan.are presented in Table 1. Tunnel scheme plan view
and alignments are enclosed.
Scheme 1 is composed of the COE Watana Dam and powerhouse, and a small
re-regulation dam with power tunnels leading to a powerhouse at Devil Canyon.
Peaking operations will occur at both Watana and the Devil Canyon power-
houses. A constant compensation flow discharge will be provided between
Watana and Devil Canyon. Peaking operations will create daily water level
fluctuations of unknown magnitude downstream of Devil Canyon.
Scheme 2 is composed of the COE Watana Dam and powerhouse with power tunnels
from the Watana Reservoir to a powerhouse at Devil Canyon. Upon completion
of the tunnel scheme the Watana powerhouse will be reduced to 35 MW and will
supply a constant compensation flow between Watana and Devil Canyon. The
Devil Canyon powerhouse will operate as a peaking hydro facility. Water
level fluctuations downstream of Devil Canyon are similar to that of Scheme 1.
Scheme 3 is composed of the COE Watana Dam and powerhouse, and a re-regulation
dam with power tunnels leading to a powerhouse at Devil Canyon. The Watana
powerhouse will operate as a peaking facility which discharges into a
re-regulation reservoir. The re-regulation reservoir is capable of storing
the daily peak discharges and releasing a constant discharge into the power
tunnels. A four foot daily water level fluctuation in the re-regulation
reservoir is required. The Devil Canyon powerhouse will operate as a base
load facility, thus, no daily water level fluctuations will occur downstream
of Devil Canyon.
ACRES AMERICAN INCORPORATED
Consulting Engineers
The Liberty Bank Building. Main at Court
Buffalo. New York 14202
Telephone 71 €-853-7525 Telex 91-6423 ACRES BUF
Other Offices: Columbia, MD: Pittsburgh, PA: Raleigh, NC: Washington, DC
I
Vince lucid
Terrestrial Environmental Specialists, Inc.
October 29, 1980
-2
The general layout of Scheme 4 is similar to Scheme 2. Scheme 4 is a base
load scheme and has a very limited potential to produce additional peak
energy. Daily water level fluctuations downstream of Devil Canyon are
similar to Scheme 3.
Preliminary economic and technical screening showed Scheme 3 as superior.
Preliminary environmental assessment ranked Scheme 4 environmentally
superior. Scheme 4 is most likely not capable of supply the required peak
energy demand. Thus, Scheme 3, ranked second environmentally, was prelim-
inarily chosen as the best tunnel scheme. If you should disagree with the
selection of Scheme 3 please contact me as soon as possible.
The objective of Subtask 6.02 is to compare the best tunnel scheme with the
COE selected scheme (High Watana and Devil Canyon}. The environmental
assessment should include a section comparing the im'pacts of tunnel Scheme
3 with the COE selected scheme. Include conclusions and a description of
additional study required.
In regards to disposal of tunnel muck (rock removed to create tunnel} we
can assume that additional costs will be incured to dispose of the muck in
an environmentally acceptable manner. An environmental assessment of
alternative disposal methods would help to define this added cost. The
following lists only a few disposal ideas, feel free to consider others.
-Stockpile and use for access road repairs.
-Stockpile and use for dam material (Scheme 3 only}.
-Dump in Watana Reservoir.
-Fill the nearest ravine.
-Leave in the most convenient location.
-Pile, cover, and seed.
Please do not hesitate to contact me for any additional information that may
be required.
RJW:ccv
ACRES AMERICAN INCORPORATED
Reservoir Area
(Acres)
River Miles
Flooded
Tunnel length
(Miles)
Tunnel Volume
(Yd 1 )
Compensation
Flow (cfs)
Downstream
Reservoir Volume
(Acre-Feet)
Devil Canyon
Powerhouse
Discharge
Dam Height
(feet)
COE
Devil Canxon
7,500
31.6
1,100,000
Constant
520
TABLE 1
Susitna Tunnel Schemes
Physical Factors
1 2
320 -0-
2.0 -0-
27 29
10,749,000 11,545,000
500 500
·to to
1000 1000
9,500 -0-
reaki ng Peaking
75
I
I
I
3 4 I
3,900 -0-I
15.8 -0-I
15 .6 29 I
4,285,000 6.494.000 I
500 500
to tQ I 1000 1000
350.000 -0-I
I
Constant Constant
245 I
I
I
I
I
I
I
I
10 9
30C0 ~ w uJ
MAX-H. W.L, E.L.2'2C:Ol rL
! 5CHE.ME.5 '2~4 u
'2.?00 i
I
1-w -uJ
lL 'ZCX::O /~~~~~LJRE.
~
2
0 J500
~ AGGE..55 AD IT
~
_j
uJ Jcx::>o
sao
0
2500
2000 l-I.W.L.ELlSCO'
C) 3~
'
1500 ~=
3= !000
MAX.H.W-L E.L '2'200
1
1-'213..::)0 J:i-!E.ME:S '2 4 4 ~
w
uJ
w
"-
ttl
ri.
;;; \)
z '2000 1
"' 0 :J
1-
<!
VJ
1-
> uJ 15=
_j
lti
1000
sao
0
10 9
INTAKE
(sC~EME
B
SCHEMES '2 ~ 4
7
TUNNEL
SCALE.
POWER TUNNE:.L
FLOW -
6
PLAN
11\ILE.S
5
,;_
UJ w
d. u
=' > ttl n
4 3
f========~~E~I===========~=~~~~~-=======-=========-====-======~==-
5 10 IS 20
:~1 NOR.IHE.QN ALIGN MEHT (50-IE.ME.S 1, 2 q. 4)
===-==l
I
SURGE TANK.;
ACCE.~5 A.OIT
UNDERGROUND
POwE..RHOUSE.
2
JNDE.RGROLJNO
POWE."-f-IOuSE
"CW L. EL. 870'
30
NOTES:
1.) TUNNEL ALIGNMENT FO!C! SCHEME. 3 IS
5HOWN ON DRAWING N~ 5l00·C(o-;;-z.
2) ALL PLANS AND PROFJLE-5 FOR
CONCE.PTJAL STUDY PURPOSES ONLY.
T.\oV.L. EL 57 c'
~==~~============dLdd~ PLATE
5 1::> IS
DIQECT ALl G N MEN T ( SCI-F ME...S I, '2. 1 4 ')
A 7
20 25
3
CONCEPTUAL TUNNEL
SCHEMES
PLAN a SECTIONS
G
F
E
D
c
8
A
7
10 9 8 7
6
NORMAL
TW.L. ""12.:.0'
5
\__---------
6
ALL PLANS AND t..AYOUTS FOR
CONCE:.PTUA!.. STUDY PURP051':5
!5
4 3 2
G
POWE:R. .. OUSE.
F
G
-
F
E
D
c
8
~
:z
0 ;::
< >
1600
1500
1400
1!00
~ 1~00
"'
.... w
1100
1~00
~ 1600
z
0
;::: 1400
<t > ~
"'
:z
0
~
1300 l
I~ 00
ISOO
~ 1~00
1~00
DETAIL A..
10 9 a 7
MAX.OPERATING LEVEL ll CREST EL.I500'
EL. 1475' ~ ljJ ~ -=--COARSE fiLTER
2.25~1 ~
I
17
ROLLED ~~~~ 0
ROGKFILL ; ROLLED l
IMPERVIOI/5
CORE
RE-REGULATION DAM TYPICAL SECTION
MIN. NOR'-lAL
OPERATING LEVEL
EL-1470'
~
SCALE.: A.
I
"'"''''il'"' I · \. '"''"""'"''"' TIUSH RACK-'
-INTAKE. GATE
POWER TUNNEL INTAKE SECTION
--
NORMAL MAX.
EL.I475'
5CA.LE.: A.
--~
40W•40H VEf!T\CAL
L\~T GATES
!GOO
1500
1400
l.lOO ~
z
0
~ 1'200 >
"' ~
w
1100
1000
000
SPILLWAY PROFILE
ROCJc:BOLTS AS
REQUIRED
f
A
l
A
CAST IN PLKE
CoNCRETE UNI~ \ ' '
'
SCALE.; A
-,:+__ .,..,,
l.r SHOT<O<TE
I/
,-STEEL SET
"""""'
CETAILA~D
(TYP.I
I
SHOTCRETE~
·~
>-w w
LL
z
z
Q
~ w
_j
w
6 5 t 4 3 2
&OOr----t----i---~-----r----t----t----i-----r----t----t----1----4-----~---+----+---~----~----+----+----~
~00 L-----~----_L ____ _L ____ _L ____ ~ ______ L_ ____ L_ ____ ~ ____ _L ____ _L ____ __j ______ L_ ____ l_ ____ ~ ____ _L ____ _l ____ ~ ______ L_ ____ l_ ____ ~
0
jj! DRilLHOL~~ ~~ FAST ~TTING GROUT
ll---HEXNUT ~+~~l~,~fi:·l STEEL PL.UE
j'' DIA. ROCKe<>LT J r
DE.TAIL A
W.W.F.---::_ r
5 10
DISTANCE. IN MILE.5
TUNN.E.L ALIGNMENT
DEVIL CANYON POWER FACILITIES PROFILE
NOTE:
ALL sTRUCTU~ AND SUPPORT
DETA.ILS ARE CONCEPTUto.L AND
FOR STUDY PURPOSES ONLY.
SCALe A 0~~~100~-aii200~ FEE.T
,
a~ STEUPI.A>E~ ', /GROUT AS RE.QUik'ED
PLATE 3 L !~DETAIL o "EX NUT...._______ .:J (T"P)
I (TYP) ~-----+----1.' I I I .-.;.~
ROCK BOLTS I ROCK BOLTS 4 SHOTCRETE / .~.~ II I MIR ~~~1---~-u-':-, T-:-~--"-~-o-.-~-.-~-~-c-~-.U-1 c_T_H_• ~-0-~-~-cY_T __ _
UNLINED CONC. LINED w/5 TEEL SET SE.CTION A-A FAST SETTING/ Q 1t
G~OUT
TYPICAL TUNNEL SECTIONS (NOTTO SCt>.LE.) TYPICAL TUNNEL SECTIONS
DETAIL E)
PREFERRED TUNNEL
SCHEME 3
SECTIONS
(NOT TO SCALE)
II\ II\ 0 "" I k'CO AS SHOWN
1--:--f~-:::'\.:1!. ---------------:::,,:::v,=s•OHS:::-::-------· ----+::-:-J-:-:-:-+c-:::+·_-: ----c:::-:c=·+-"-'"_""_'"_'"_' -------!1 ~K'"'':''57~-C6·11".Jf\"'•· DATE .._. CH APP APP< ~$ AWRICAH IHCOlitPOIUT'ED P!lon;tT .... ...,. .. .,,
4 3 2
F
E
D
c
8
A
APPENDIX 8
AMENDED DESCRIPTION OF TUNNEL SCHEME 4
Mr. Vince Lucid
Terrestrial Environmental Specialists, Inc.
RD 1
Box 388
Phoenix, New York 13135
December 11, 1980
P5700.11. 30
T.606
Dear Vince: Susitna Hydroelectric Project
Revised Description of Tunnel Alternatives
Enclosed please find a memo from B. Wart outlining our revised
description of tunnel alternatives.
Please use this description in your assessment of tunnel alter-
natives.
In addition, I have completed your table outlining tunnel design
information.
Sincerely,
r-7
KRY/ljr
~~~::7j/~ /~ ~
. .Aevin Young
Environmental Coordinator
Enclosure
·ACRES AMERICAN INCORPORATED
Consulting Engineers
The Liberty Bank Buildong. Main at Court
Buftalo New York 14202
Telephone 716-853-7525 Telex 91-6423 ACRES BUF
Other Ofloces Columbia. MD: Pottsburgh. PA. Raleigh. NC: Washington, DC
OFFICE MEMORANDUM
TO :
FROM:
K. Young
B. Wart
D•te: December 11, 1980
File: P5700. 07.07
SUBJECT: Susitna Hydroelectric Project
Preliminary Environmental Assessment
of Tunnel Alternatives
The assumption made by TES that the dam, pool elevation, and pool
level fluctuations of Watana are as described by the Corps of
Engineers, and would not differ among the five schemes is correct.
The description of tunnel Scheme 4 has been revised so that Scheme
4 is capable of supplying a daily load curve similar to that of the
other schemes . The revised description of tunnel Scheme 4 follows:
The general layout of Scheme 4 is similar to Scheme 2. The operation
of Scheme 4 varies from that of Scheme 2 and is described below.
The Watana powerhouse will remain at the stage one installed capacity
or if necessary enlarged slightly. Peaking demands will be met with
the Watana powerhouse. At all times the Watana powerhouse will
generate a minimum of 35 MW to supplement base load demands and
supply the required compensation flow between Watana and Devil Canyon.
The Dev~l Canyon powerhouse and tunnel will operate as a base load
facility. Scheme 4 fails to develop the full head for the entire
flow and thus Scheme 4 is not expected to produce annual energy
comparable to other schemes. Daily water level fluctuations downstream
of Devil Canyon are similar to Schemes 1 and 2. Water level fluctuations
between Watana and Devil Canyon are expected to be large.
RJW/ljr
SUS[TNA TUNNEL SCHEMES -PHYS£CAL FACTORS (Addendum)
Typical COE 1 2 3 4
Range of discharge (cfs) daily 6,000 to 13,000 4 000 to 14,000 4,000 to 14 000 8 300 to a 900 4 000 to 13,000
at Devil Canyon Powerhouse seasonal Fluctuations are less than existing natural fluctuat wns and are smaller for all plans.
Range of river stage below daily Small J Large I Large I Small I Large
Devil Canyon powerhouse To date no detailed information is available.
(corresponding to discharges A.d plans have identical seasonal nuctuat1ons 1vhich are ... ess than natural tluctuations.
listed above) seasonal To date no information is available.
Maximum fluctuations ( ft) daily <1 Same as COE Same as COE Same as COE Same as COE
in Watana Reservoir seasonal See Graph Same as em: Same as COE Same as COE Same as COE
Maximum fluctuations (ft) daily 2 Larqe NA 4 NA
in downstream reservoir
seasonal None None NA None NA
Generating Capacity (MW) Watana 792 792 35 (792)* 792 792
Dev1l
Canyon 776 550 1 '1.50 365 365
Total Project Costs ($) 2,150 000,000 2, 502,100,000 2,394,600,000 2,144,300,000 i 2,074,200,000
Total Annual Enerqy (GwH) 6 895 5, 704 5,056 5 924 4 140
*Watana capacity is reduced after completion of tunnel project.
..
Appendix I
GRAPH C-12
C-147
...
"' "' ..
~
:i
0
0
~
~
~
pAJAMA tiOffTHl.Y STORAGE FREQUENCY
FOA TK'£ DEVlL C.A.WfO~ A..~ WATAN! SYSTEM
::·':""'-·-· .. :-· .. :
! •. "':. ...: :. : :' .t. :. . : : ..
-_,..---:----·-
m
~t::S<>~
~
1'\
·z.ll" ;;
~Jt>O g
~1.•'9•Z
... ,.
~ ...
SUT
-~:Terrestrial
~.. nvironmentai
peciaUsts, inc.
R.D. 1 BOX 388 PHOENIX, N.Y. 13135
Project Manager
Susitna Hydroelectric Project
Acres American, Inc.
Liberty Bank Building
Main at Court
Buffalo, New York 14202
Attention: Kevin Young
Re: Alternative Development Schemes
Dear Kevin:
January 16, 1981
218.443
In response to your request of December 10, 1980, and as discussed
in my letter to you on January 8, 1981, TES, Inc. has prepared some
comments on the Vee/High Devil Canyon/Olson scheme in comparison with
the Watana/Devil Canyon scheme. Enclosed for your review and comment
is a draft of a brief report entitled "Environmental Considerations of
Alternative Hydroelectric Development Schemes for the Upper Susitna
Basin 11 •
We will be pleased to discuss the contents of this report with
you.
VJL!vl
En c.
cc: R. Krogseng
Sincerely,
Vincent J. Lucid, Ph.D.
Environmental Studies Director
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
ENVIRONMENTAL CONSIDERATIONS
OF ALTERNATIVE
HYDROELECTRIC DEVELOPMENT SCHEMES
FOR THE
UPPER SUSITNA BASIN
by
Terrestrial Environmental Specialists, Inc.
Phoenix, New York
for
Acres American, Inc.
Buffalo, New York
January 16, 1981
TABLE OF CONTENTS
1 -INTRODUCTION
2 -APPROACH
2.1 The Development Schemes
2.2 Assumptions of Environmental Constraints
3 -DISCUSSION . .
3.1 Socioeconomics ..
3.2 Cultural Resources
3.3 Land Use
3.4 Fish Ecology
3.5 Wildlife Ecology
3.6 Plant Ecology
3.7 Transmission Line Impacts
3.8 Access Road Impacts
3.9 Summary
4 -CONCLUSION
·.
APPENDIX A -DESCRIPTION OF STAGING ALTERNATIVES
Page
1
2
2
2
3
3
3
4
5
. . . . 5
7
8
9
9
11
1 • INTRODUCTION
This report documents preliminary environmental considerations of
alternative hydroelectric development schemes for the Upper Susitna
Basin. The need for the report stems from discussion at a meeting held·
in Buffalo on December 2, 1980 between staff of Acres American and TES,
Inc. The alternative development schemes are described in a December
4, 1980 memo from I. Hutchison to K. Young for transmittal to TES, In.c.
(Appendix A). Additional details were obtained and the approach agreed
upon in subsequent conversations and data transmittal between K. Young
and V. Lucid concerning these alternative development schemes.
The following assessment is based upon a familiarity with the Watana/
Devil Canyon area obtained du~ing the first year of environmental
studies. At this writing, however, we do not have the benefit of
information to be contained in the 1980 Annual Reports, which are to be
completed byTES subcontractors by March 1981. Because much of the Vee
reservoir lies outside of the study area for many disciplines, comments
concerning this impoundment rely heavily upon intuitive judgement.
2 -APPROACH
2.1 The Development Schemes
Environmental considerations were preliminarily identified for two
different hydroelectric development schemes for the Upper Susitna
Basin: Watana/Devil Canyon and Vee/High Devil Canyon/Olson. The three
staging variations for each of these schemes (Appendix A) will likely
have different short-term impacts, but an attempt to address these
possible differences at this time would be too speculative in most
disciplines to be meaningful. In disciplines such as socioeconomics
and land use, however, the staging of the development will largely
determine the magnitude of impacts. Thus, the environmental
considerations identified in this report are based in most cases upon
the two ultimate schemes with occasional references to the staging
options. It was assumed that whatever staging alternative is selected,
all stages of develqpment would be completed. The result would be one
of the two schemes outlined in Table 1.
2.2 Assumptions of Environmental Constraints
The identification of potential advantages and disadvantages of the two
schemes, from an environmental standpoint, requires that certain
assumptions be made concerning environmental constraints that will
govern the design and operation of.the facilities. Among these are:
(a) that constant, or nearly constant,. downstream flows be maintained,
both during and after development, whether by means of a
re-regulation facility or operational constraints;
(b) that drawdown of the reservoirs would be similar in magnitude to
corresponding reservoirs in the other scheme (e.g. Watana vs. Vee),
and would be within environmental constraints; and
(c) that a minimum release or compensation flow be maintained (of a
volume to be determined) to preserve the riverine habitat between
the reserve irs.
2
Table 1
Descriptions of Twa Alternative Hydroelectric
Development Schemes for the Upper Susitna Basin(a)
Maximum pool
elevation (ft)
Darn Height {ft)
Installed Capacity ·(MW)
Probable On-Line Date
of Last Stage
Daily Peaking
Appraximate(b)
Reservoir Area (acres)
Apprax imate (b)
River Miles Flaoded(c)
Watana/Devil Canyon
2200/1450
750/570
800/600
2010 to 2020
Yes/No
40,000/7,500
(Total= 47,500)
60/30
(Tot a 1 = 90)
Vee/High Devil Canyon/Olson
2300/1750/1020
425/725/120
400/800/100+
2020
Yes/Yes/No
16,000/21,700/900
(Total -38,600)
95/58/7
(Total = 160)
a Derived from descriptions of three staging alternatives far each
scheme, which are presented in Appendix A.
b Preliminary values.
c Mainstream Susitna only, tributaries not included.
3 -DISCUSSION
Potential advantages and disadvantages of the two development schemes
are presented below for each of the major environmental study
disciplines.
3.1 Socioeconomics
There could be significant differences in type, degree,. and chronology
of socioeconomic· impacts resulting from the various plans under
consideration. An important concern relates to alternative staging
plans and associated factors such as: (a) cost of stage, (b) scheduling
of various stages (i.e., length of construction period per stage and
spacing), (c) construction manpower requirements by time period, (d)
access point of origin, and (e) whether or not a construction
"community 11 will be established. Impacts generally will fall into two
&ategori es: those associ a ted with project economics and construct ion,
and those associated with power production and sales. Both types of
impacts will exhibit a variety of local, Railbelt, and statewide
ramifications. In the absence of practically any project economics
information, detailed analysis is impossible at this time. In general,
however, it can be expected that a scheme involving on-line production
capability of 800 MW by the year 2000 will have greater and more
significant impacts than a scheme in which that capability is nat
attained until 2010 (e.g., Plan 1 compared to Plan 2). This difference
would occur because, in the latter plan, the demand on resources will be
spread aut over time. In addition, it is reasonable to expect that the
economic base of Mat-Su Borough will be larger in 2010 than in 2000, even
without the project. Therefore, there likely would be a greater capacity
to deal with project impacts.
3.2 Cultural Resources
Field surveys in the Watana/Oevil Canyon impoundment area during the
summer of 1980 have documented 37 archeological sites. A preliminary
assessment of the data indicates a greater number of archeological sites
3
towards the east end of the study area. In 1953, a pre·l iminary field
survey conducted for the National Park Service near Lakes Louise,
Susitna, and Tyone identified approximately six archeological sites.
There is a high potential for discovering many more sites along the
lakes, streams, and rivers in this easterly region of the Upper Susitna
River Basin. Additional sites are expected to be identified near caribou
crossings of the Oshetna River. In summary, a preliminary assessment of
available information suggests that there perhaps could be a greater
number of archeological sites associated with the Vee/High Devil
Canyon/Olson scheme than with the Watana/ Devil Canyon scheme.
3.3 Land Use
At present, much of the Upper Susitna Basin is subjected to almost
negligible human activity. Either of the development schemes (and any of
the staging plans) will cause changes in land use patterns in the Upper
Susitna Basin. Regardless of the scheme chosen, impacts on local land
usage and human activity in the Upper Basin will be significant in terms
of area inundated and land cover changes resulting from project
facilities. With either the Watana/Devil Canyon or Vee/High Devil
Canyon/Olson scheme, Deadman Falls will be inundated and Devil Canyon
will be greatly reduced in scenic value. The Vee/High Devil Canyon/Olson
scheme would also eliminate Tsusena Falls and would destroy the existing
aesthetics of Vee Canyon by dam construction at this site. Although the
Vee/High Devil Canyon/Olson scheme has a smaller reservoir area, it would
inundate approximately 70 miles more of the Sus~tna River than would the
Watana/Devil Canyon scheme (Table 1). Development of a recreation plan
for the project would vary according to the design scheme and staging
plan selected.
Broader concerns associated with land use are related to staging, as
discussed in the previous section regarding socioeconomics. The
influence of staging on land use impacts applies to land use factors
concerned with existing regional transportation systems. The existing
transportation systems (and communities and land uses associated with
them) which connect to the selected access route will be affected by
construction-related activity. In this context, the degree of
4
construction-related activity within a given time frame could be a
significant factor. This consideration is similar to the socioeconomic
concern identified previously. The proportionately greater degree of
construction activity associated with a plan in which 800 MW capability
would be achieved by 2000 -as compared with one in which this would not
be achieved until 2010 -concentrates impacts on land uses in a shorter
time frame.
3.4 Fish Ecology
All development schemes must be examined with the downstream anadromous
fishery receiving primary consideration. Any scheme or staging plan that
allows for daily peaking without are-regulation dam downstream could be
detrimental to this resource. Therefore, the maintenance of constant, or
nearly constant, downstream flows is an environmental constraint that
must be met for any development scheme to be acceptable.
The Vee/High Devil Canyon/Olson scheme has at least one major
disadvantage, with respect to fish ecology, in comparison to development
at Watana/Devil Canyon. It is that the Olson site is downstream of
Portage Creek, which is known to be a very important spawning stream for
salmon. Dam development at the Olson site would provide an obstruction
to anadromous fish passage and two miles of Portage Creek would be
inundated. Even with facilities for fish passage, the impacts on this
spawning area could be severe.
Because the Vee/High Devil Canyon/Olson scheme would inundate about 70
additional miles of the Susitna River, plus different tributaries, than
would the Watana/Devil Canyon scheme, impacts on resident fish can be
expected to differ between the two schemes. Data are not presently
available to permit an assessment of these impacts.
3.5 Wildlife Ecology
Although the area that would be inundated by the Vee reservoir has not
been thoroughly investigated, project pe~sonnel have sufficient
familiarity with the area to make a fairly strong recommendation at
~
this time. With the exception of impacts on avian species, it is felt
that the Watana/Devil Canyon scheme is superior from a wildlife impact
standpoint to the Vee/High Devil Canyon/Olson scheme. The basic trade-
offs associated with this comparison involve the areas to be flooded by
the Vee dam as opposed to the flooding of much of the Watana Creek
drainage and the higher portions of the canyon walls along the Susitna.
For a variety of reasons the area to be flooded by the Vee dam seems
more valuable for wildlife than the areas that would be inundated by
the Watana/Devil Canyon dams.
A Vee/High Devil Canyon/Olson scheme would flood roore acreage of
critical river bottom habitat than would the Watana/Devil Canyon
scheme. These areas are important for moose during severe winters and
the additional reduction in such habitat could have a major impact on
moose populations. In addition, the Vee impoundment would flood key
winter habitat for at least three subpopulations of moose that range
over large areas east of the Susitna and north of the MaClaren River.
The area that would be saved by the Vee dam scheme, the Watana Creek
drain age, is inhabitated by a subpopul at ion of rooose that appears to be
declining in condition and increasing in age, thus indicating that
within 10 to 15 years this subpopulation may be far less important than
at present. The habitat quality within the Watana Creek drainage also
seems to be decreasing. TES has previously recommended that the pool
elevation of Watana be lowered to preserve as much of the Watana Creek
drainage as possible. Nevertheless, the trade-off between Watana Creek
and the Vee impoundment favors flooding the Watana Creek area.
The area that would be flooded by the Vee dam is historically used by
the Nelchina caribou herd, particularly in moving to their calving
grounds near Kosina Creek. Although caribou movement patterns are
highly variable and appear to change as the size of the herd changes,
this area has been frequently traversed by members of this herd. The
potential for impacting caribou movement is greater than with the
present Watana scheme. Like Watana, the Vee reservoir would be subject
to large drawdown and possible ice-shelving. In addition, the
three-dam scheme would result in a greater division of the Nelchina
herd's range due to the greater length of the impoundments involved and
thus increase the likelihood of impacts on this herd.
6
There is an indication that the area to be flooded by the Vee dam is
more important to some key furbearers. the red fox in particular, than
areas such as Watana Creek that would be spared by a Vee dam. There is
also more trapping conducted by residents in the area upstream from the
Vee site than in areas downstream from that area. The Vee dam,
especially due to the drawdown schedule that would be operative with
this dam, also has the potential of more severely impacting both
muskrat and beaver populations.
It appears that only avian species might suffer less adverse impacts
from the Vee/High Devil Canyon/Olson scheme than from Watana/Devil
Canyon. Although the Vee dam would eliminate more river bottom
habitat, it would spare a considerable amount of deciduous forest
(birch and aspen) that exists along the south-facing slopes of the
Susitna canyon and along some of the tributaries. This is the only
area, of any extent, that contains this type of habitat, and its
associated avifauna, within the Upper Susitna Basin.
Although a more detailed recommendation could be made if a better data
base were available, the reasons given above seem to indicate that the
Watana/Devil Canyon scheme is superior to a Vee/High Devil Canyon/
Olson scheme. This is especially true if one considers that the
greatest potential for more severe impacts concern moose and caribou,
which are unquestionably the key big game species in the area.
3.6 Plant Ecology
Both schemes will primarily flood deciduous forests (white birch,
balsam poplar, and aspen types), coniferous woodlands and forests
(white spruce and black spruce), and shrub communities (alder, birch,
and willow types). The relative amounts of habitats flooded will vary
with the two schemes. The Vee/High Devil Canyon/Olson combination will
probably flood more floodplain habitats such as balsam poplar forests,
while the Watana/Devil Canyon scheme will probably flood more birch and
aspen forests.
7
The primary advantage of the Vee/High Devil Canyon/Olson scheme is that
approximately 9,000 fewer acres would be flooded (Table 1). The
primary disadvantages of this scheme are: more lakes and wetlands
flooded, more river floodplains flooded, and a greater amount of
associated floodplain habitats, such as balsam poplar, eliminated. The
amount of wetland eliminated would be a very small proportion of the
total wetland in the region. Nevertheless, the importance of wetlands,
floodplains, and associated habitats has been emphasized by Executive
Orders and various federal agencies.
3.7 Transmission Line Impacts
Because of the distance ·traversed, the construction of a transmission
line to the intertie from a Vee/High Devil Canyon/Olson project offers
several disadvantages when compared to a line constructed from a
Watana/Devil Canyon project. A line from the Parks Highway to Watana
would be approximately 50 miles in length. Following the same route to
Watana and extending the line to the Vee site would add approximately
40 miles to its total length, an increase in mileage of some 80
percent. Generally, the longer the line, the greater the impact. In
addition, the added length would cross a presently roadless remote
parcel of land, thereby necessitating additional miles of access road
construction. Additional vegetation clearing would be required due to
the longer route. Assuming a 300 foot wide right-of-way, approximately
1500 additional acres would need to be cleared during construction and
maintained during operation of this line, thereby potentially impacting
wildlife habitat. To the extent that land use, aesthetic and
recreational opportunities are impaired by transmission facilities, a
larger impact zone will be created. Similarly, areas of significant
cultural resource potential will be impacted to a greater degree than
with the shorter line. A greater number of streams tributary to the
Susitna River will need to be crossed, posing additional areas of
potential impact. In summary, constructing transmission facilities to
the Vee site considerably increases the potential impact of project
transmission lines.
8
3.8 Access Road Impacts
At present, an access route for the Watana/Devil Canyon scheme has not
been decided upon, and no information at all is available with regard to
access for the Vee/High Devil Canyon/Olson scheme. Also, it has not even
been determined which of the two schemes would have the shorter access
road. By virtue of the relative dispersion of the dam sites, however, the
two·schemes may differ with respect to the area opened up to access and
the resultant dispersion of human disturbance over the Upper Susitna
Basin. The Watana/Devil Canyon scheme may confine access to a smaller
portion of the basin, especially if access is from the west. The Vee/High
Devil Canyon/Olson scheme, especially if it is a staged development, may
be more likely to have access from both north (Denali Highway) and west,
thereby opening access to a larger area, and from several directions.
3.9 Summary
In each of the environmental study disciplines, differences exist in the
potential impacts of the Vee/High Devil Canyon/Olson scheme in comparison
to the Watana/Devil Canyon scheme .. The Vee/High Devil Canyon/Olson scheme
has more apparent disadvantages than advantages; most of these
disadvantages are due to the Vee impoundment rather than the High Devil
Canyon impoundment. In socioeconomics and in some aspects of land use,
the differences due to staging are of more significance than those due to
the location of the dams. Nevertheless, it is noteworthy that the
Vee/High Devil Canyon/Olson scheme may affect more canyons and waterfalls
of outstanding scenic value than would Watana/Devil Canyon. Existing
information suggests that there is a high potential for occurrence of
cultural resources in the vicinity of the Vee reservoir, perhaps even more
than in the vicinity of Devil Canyon and Watana. A major disadvantage of
the Vee/High Devil Canyon/Olson scheme is the impact of Olson on
anadromous fish spawning in Portage Creek; daily peaking from High Devil
Canyon without re-regulation is also environmentally unacceptable. There
is evidence that impacts upon big game (particularly moose and caribou)
and furbearers would be more severe with the Vee/High Devil Canyon/Olson
scheme than with Watana/Devil Canyon, although this is not necessarily the
case with birds. Although the Vee/High Oevil Canyon/Olson scheme would
9
flood less acreage than Watana/Devil Canyon, a larger amount of floodplain
and wetland habitat would be inundated. Because of the longer distance
traversed, potential impacts of the transmission line would be
proportionately greater with development at the Vee site. The dispersion
of the dam sites in the Upper Basin with Vee/High Devil Canyon/Olson would
also likely result in a larger impact zone due to increased access.
10
4 -CONCLUSION
Although some potential advantages and disadvantages have been
identified for both the Watana/Devil Canyon scheme and the Vee/High
Devil Canyon/Olson scheme, sufficient information is not yet available
upon which to base a firm recommendation. The evidence that is
available, however, when combined with intuitive judgement, suggests
that the Watana/Devil Canyon scheme may be preferable to the Vee/High
Devil Canyon/Olson combination. The comments contained in this report
will be reviewed and refined after the 1980 Annual Reports are
available and when more construction and operational details are known.
Comparison of the two schemes will still be hampered by the scarcity of
information concerning the Vee impoundment area.
11
APPENDIX A
DESCRIPTION OF STAGING ALTERNATIVES
.. ~ . ' .. ~ .
, ...•
~ Young · ·. December. 4, 1980
(for transmit~l-to TES)
·I ... Hutchison··· · · · . P5700~ 14. 06
{-~~~1~~~ ~-EP~~:·.. . . .. ... .. ... . . -··
:.~urr~~t .Sus1tna Basin Development Schemes
As re~iu;ested·~ the schemes currently being 1m·estigated· are .. sunm~u·ized on
the ·attached sheets. :Please· ·note that the probable on-line dates are
estimates at this stage and will be firmed up over the next two week~. . ~ . .. .. ... . . . -. '
IH:ccv
AttachiientS
cc: J.D. Lawrence
J.H .. Hayden·
P. Tu..:!.;.er (Col. )
A. Simon
G. Krishnan
D. Carlson
R. Hart v. s·ingh
P. Rodrigue
E.~!.. Shadeed
R. Ibbotson
1p tl. ~/~ !A I I
I. Hutchison
SCHEME Pl qn 1 (Total installed capacity= 1400 14\·1)
Stage I DeveloPJl!ent. Stage II Develop~ent ~tage III Development
I
Dam Site Watana (2200L Dam Site ·oevi], Canyon {j.450) Dam Site------
Height 750 ft.
Ins ta 11 ed
Capacity 800 t·1H
Probable on
Line Date 1995-2000
Daily
Mode of Operation peaking
Separate
Re-regulation Dam Possibly
Height 570 ft.
Ins ta 11 ed
Capac i ty _Q.Q.O_ t·1W
·Probable on
Line Date 2010-20
No Oai ly
Mode of Operation Peak jog
Separate
. Re-regul at ion Dam ...:.ff=o __
NOTE: Figures in brackers behind dam site name
indicate maximum water surface elevation in feet.
Height __ ft.
Installed
Capacity ___ ~1VI
Probable on
Line Date ---
Hade :of Operation __ _
Separate
Re-regulation Dam __ _
Stage IV Development
Dam Site ------
Height __ ft.
Installed
Capacity ___ ~tW
Probable on
Line Date ---
Mode of Operat1 on __ _
Separate
Re-regul ati on dam __ _
SCHEME -"~lan Z (Total installed capacity = 1409 f4W)
Stage I 'neve 1 o p!J1ent
Dam Site \4atana .. {2000}..
Height 550 ft.
Ins tall ed
Capacity 400 t4W
Probable on
Line Oil te 1995
·Daily
t-iode of Operation Peaking
?tage II Development
Dam Site .W.atana .{2200) _
Height 750 ft.
Installed
Capacity BOO HW
Probable on
.Line Date 2000-1~
· . Daily ·
· . Mode of Operation ~~A kj ng
Separate Separate
Re-regulation Dam Possibly Re-regulation DamPossibly
~la~tana Dam raised 200'
Installed Capacity
Increase~ by 400 MW
Stage III Develo~ment; ?tage IV Development
Dam Site Q~yjl,Cq·n~QO .01501) Dam Site------
Height 570 ft.
Insta 11 ed
Capacity 600. ·~1\JI
Height ___ .ft.
Installed
· Capacity ___ ~1W
Probable on Probable on
Line Date 2010-20 : . Line Date __ _
· . · · 'No Daily
l~de of Operation .eeaking · Mode of Operation· __ _
Separate . . ·Separate
11e-regulation Dam ,fiQ:. Re-regul ati on dam __ _
SCHEME P] ao 3
Stage I Develoement
Dam Site Watanct (?200)
Height 750 ft.
Installed
Capacity· 400 f4W
Probable on
Line Date 1995
Daily
f.1ode of Operation· Peaking
Separate
Re-regulation Dam Possibly
(Tota 1 ins ta 11 ed capacity = 1400 f-1\~)
§tage II Developmen~ .?wtage III Deve1opmen~
. Dam Site . W9tf.\na (2200)_· Dam 51 te .Oe\lil ,Caoyon
Heig.ht _1.5_o__ ft.
. .
·.Installed
Capacity 800 ~~
Probab 1 e .on
Line Date 2000-10
Daily
Mode of Operation _Pea ki pg. ·
Separate
Re-regulation Dam EossibJy
· In'stalled Capacity
Increased by. 400 t1W
Height. 570 ft~
Ins ta 11 ed
. Capacity · §QO ~tvl
Probable on .
Line Date 2010~20 .
· No Daily·
fo1ode 9f Operation e~sking
Separate .
Re-rf?gulation Dil;m .No ·.
?~age IV Develop~ent
Dam Site------
)-Ieight __ ft.
Installed
Capacity ___ ~1W
Probable on
· Line Date ---
Mode of Operation __ _
Separcte
Re-regulation· dam __ _
SCHEME Plan 4 '(Total installed capacity= 1300 f.1W)'
Stage I Development
Dam Site .~igh Q,C. (1Z5.5)
Height 725 ft.
· Installed
Capacity 800 I~
Probable on
. Line Date 1995-2000
· Daily
f.1ode of Operation Pea king
~tage II Developmen~ ..
Dam Site Vee, (?300) ..........
Height 425 ft.
. InstalJed
Capacity . !lQO J.fW
. Probab 1 e ·on
Line Date . 2Ql0-2Q.
. . · Daily ·
Mode of Operation .Peakiog
Separate Separate
Re-regulation Dam Possibly* ·Re-regulation nam No
.s.t,age III Development
. Dam 51 te .Ql son (lOlQ} , •
Height __ 12Q~_·ft.
· Installed ·
Capacity ±100 MH .
?tage IV Devel9pmen~
Dam Site ------
·.Height ___ . ft •
Installed
Capacity ___ ~1W
·Probable on _ Probable on
Line Date .2020 -· _ . . Line Oat~ __ _
· . · No Daily .. :·
. Hode of Operat1 on .eeaking . Mode of Operation __ _
Separate Separate
Re-regu 1 a ti on Dam . .. No Re-regulation dam __ _
* Olson may serve as the re-regulation dam in which case the Olson
dam would constitute part of· Stage I. The powerhouse· at Olson
could ~till be b~ilt at a later stage._ · ·
SCHEME _ ..... P ..... la ..... n ..... · 5..__ ___ _ (.Total installed capacity = 1300 HW)
?tage II Developmen.t
. . .
Dam Site .. High Devil CaD.Yon Dam Site High Qcvi]' Can~on
(1610) . . . . . ·. (1750)
Height 570 ft. · He1 ght .. · 725 · .. ft.
Installed
Capacity. 400 ·I~
Probable on
Line Date · 1995
Daily
Mode of Operation Peaking
·Installed :
Capacity 800 f·1W
Probab 1 e on . . .
:'Line Date . 2000:...10· .
Daily
Mode of Operation: Peaking
. '
?tage III Development.
. Dam Site .. y"ee (g~OPl.·
Heigh.t. 425 .~t,.
.,
Installed · .
. Capac.i ty · 400 : ~1W
Probable on .
Line Date · · 2010-20 · .· . . ·· .. Dani: ..
·.Hade of Operati.on .Pe~king
Separate ·Separate . Separaie .
Re·regu_lation Dam Possibly* Re-regulation Dam· Possibl.y*·. Re-r~gulation Dam No ·
·;High. Devil Canyon Dam
R a i sed 140 ': . .. · ·: ·
In'stalled capacity
·:Increased by 400 t1\~ ..
* Ol.soriilmay. servei"as·, the·::re~reguJ at ion .'danf: 1 n.:·wh1 ch: case: the Olson
· dam would constitute .part of Stage I.·~ The'powerhouse at Olson··
could still be .bu.i.lt._at .a.l_ater .. stage,: · · ·
'ltage IV Develoement
Dam Si.te Qlson (1020} _
·:· .H.eight ,120 ... _ft.
installed
Capnci ty ±100 ~tW .
P·robable on·
·.Line· Date 2020
No Oa11y
Mode of OperationPeaki~g
·Separa~e
:Re-regulati,on qam _N_o __
SCHEME PJ an 6
?tage 1 Develo~en~
Dam Site .High Qe'lil .Can;: on
Height 725 ft. {1750)
Installed
Capacity .. 40Q • HW
Probable on
Line Date 1995
Daily
Mode of Operati6n Peaking
{Total installed capacity a 1300 t1l~)
Stage II pevelopment
Dam Site .. High Qevil Cal)}'on
Height • Z25 . ft.
(1750)
Installed
Capac 1 t.Y _8.illL_ t·1W
Probable on
Line Date 2000-lQ
Daily
Mode of Operation Peaking
.s.tage I II Deve 1 opmef\t
Dam Site ~-~'"""e ..... e ____ , __ _
Height . 425 ft.
Installed
Capacity 400 .. Ail
Probable on
Line Date 2010-20
·Daily
tbde of Operation Peaking
Separate Separate Separate
Re-regul at. ion Dam Pass i b ly* Re-regul at ion Dam possi b]y* Re-r~gul at ion Dam· No
Installed Capacity increased
by 400 11H
*Olson may serve as the re-regulat1on dam in which case the Olson
dam would constitute part of Stage I. The powerhouse at Olson
could still be built at a later stage.
Stage }V Development
Dam Site Olson (1020)
Height .. l 20 . ft.
Installed
· Capacity ±100 ~M
Probable on
Line Date 2020
No· Daily
Mode of Operation peaking
Separate
Re-regulation dam. No
, ________ , ________________________ Aj)pi'ii"r.iill
f'ttv irormnmlol (DLffel't!tH:e;:; itt in*mcl
Allributc ---~~~----·------of t.wo schcmP.s}
fcoluqical:
-Dmm~ilreor:t r lSimr i~s
ond Wil,Jitfc
~es idenl f i.sher imu
\li I <II ife:
~:
(ffr.cl::; resul ~ iruJ
fr·om chmu]tl!''i in
water qtmnl il y atu1
quality.
Lotis a f res idcnl
fisheries hah ilal.
No si•JnifLcanl dtffer-
enco belwenn adtt!mmi
regardinu Hffeclu down-
stream of tJevi) Canyon ..
Difference in !'each
between Devil f.11nyon
dain and tunnel re-
rtH)ulal ion rJam.
Minimal differences
belween schemes ..
loss of wildlife Minimal differences
hahital. between schemes.
lnunnal ion of Putent ial differences
archeological siles. belween schemes~
ImHldal ion of Dev i 1
Canyon ..
Significant difference
bet ween schemes.
----------· SClleme jud<ted to have--
Irlent irieat tun lhe least potential impacl
__ o~f~d~·~·f~f~c~•·~··~n~c~e-----·--------~A~p~p~r~a~is~a~l~-~a~·d~q~e=m~e~n~l _________ ~lo=nn~e~.l~---~rn~:-
liilh the tunnc I scheme con-
trolled flows between retjulo-
l ion dut11 and duwnst ream power-
house offers potenl ial for
anadromous fisher i.es enhance-
•nenl in this II mile reach of
lhc l'iver ..
!lev il Canyon dam would inuodul e
27 miles of lhe Susitna River
and approximately 2 miles of
Devil Creek. The tunnel schUllle
16 miles of the
The must sensitive wildlife ha-
bit at in this reach is upstream
of the lunoel re-re9ulat ion da.n
where there ia no :Rignificant
difference between lhe schemes.
The Devil Canyon dam scheme in
a<ldit ion inundates the river
valley between the two dam
sites resulling in a moderate
in impacts to
Due lo the larger area inun-
dated the probabilily of inun-
dal lng archeolotJical siles is
increased.
The !lev il Canyon is cons Ide red
a unique resource,. 80 percent
of which would be inundated by
lhe Devil Canyon dam scheme.
This would result in a loss of
both an aesthct ic value plus
the ial for while wuter
Nol a faclor in cvaltmllon or
scheme ..
lf fisheries enhancement uppor-
tun il y can he realized the l un-
ne 1 scheme offers a pos il ive
mit i.qal ion measure nol avai lahlc
wil.h the llev il Canyon dam
scheme. This opportunity is
COIUJ ide red moderale and favors
the l unne I scheme.
Th ia reach of river is not con-
sidered lo be highly significant
fur res i<lt!nt fisheries and thus
the difference between the
and favors lhc
lhc difference in loss of wilfl-
life habilal is considered mod-
erate and favors the tunne I
scheme ..
A slanlficanl archeological
site, if ldenlified, can proba-
bly be excavaled. This concern
Is not a factor in
The aesthetic and to some extent
lhc recrt!al ional losses' associ-
ated with the development of the
!lev il Canyon dam is the rna in
aspect favorinq Lhe tunnel scheme.
X
X
X
llVfRAtl [VAUJAIIUN: The tunnel scheme hns ovct·all a lower impact on the environment.
Soc1al
Aspect
Potential
non-renewable
resource
displacement
Impact on
state economy
Impact on
local economy
Seismic
exposure
Overall
Evaluation
TABLE 1.2-SOCIAL EVALUATION OF SUSITNA BASIN DEVELOPMENT SCHEMES/PLANS
Parameter
Million tons
Beluga coal
over 50 years
J
Risk of major
structural
failure
Potential
impact of
failure on
human life.
Tunnel
Scheme
Dev i1 Canyon
Dam Scheme
High Devil Canyon/
Vee Plan
Watana/Dev il
Canyon Plan
80 110 170 210
All projects would have similar impacts on the state and
local economy.
All projects designed to similar levels of safety.
· Any dam failures would effect the same downstream
population.
1. Devil Canyon dam superior to tunnel.
2. Wat ana/Devil Canyon superior to High Devil Canyon/Vee plan.
Remarks
Devil Canyon dam scheme
potential higher than
tunnel scheme. Watana/
Devil Canyon plan higher
than High Devil Canyon/
Vee plan.
Essentially no difference
between plans/schemes.
Environmentol Attribute
Eco lo~icol:
1) Isheries
2) Wildlife
o) 1-!oose
b) Caribou
d rurbeorero
d) Birds end !leers
TABLE I.J -ENY_IROP<f!ENTAL EVALUATION or WATANA!DEVIL CANYON AND HIGH otVIL CANYON/VEE D£VELOPHENT PLANS
Pion CO!!J!sr leon
No significant difference In effects on downstream
onedromous fisher les.
HDC/V would Inundate opproximotely 95 miles of the
Susltno River ond 20 miles of tributary otreomo, In-
cluding the Tyone River.
11/0C would inundate opprodmotely 84 miles of the
Susltno River ond 24 miles of tributary streams,
including llstsno Creek.
Approisel Judge/!!ent
!A.oe to the avoidence of the Tyone River,
lesser Inundation of resident fisheries
hobltot ond no significant difference In the
effects on onodromous fisheries, the 11/0C pion
io judqed to hove less impoct.
BDC/V would inundate 12J mil eo of crItical winter river Oue to the lower potential for direct Impact
bottom hobltot. on moose populations within the Susltna, the
11/0C pion is judged super lor.
II/DC would inundate 108 miles of this river bottom
hobltot.
HDC/V would inundate n Iorge oren upstream of Vee
utilized by three sub-populotlons of moose thot ronqe
In the northeont section of the basin.
11/0C would Inundate the WntonD Creek area ut \!\zed by
moose. The condition of this sub-populot \on of moose
and lhe quality of the hobltot they ore using oppeoro
to be decreasing.
lhe Increased length of river flooded, eepedally up-
etroom from the Vee dam site, would result in the
HDC/V plan creating e greater potential division of
the ""'lchine herd's ronge. In oddlt ion, en increase
In range would be directly Inundated by the Vee res-
ervoir.
The area flooded by tho Vee reservoir is considered
Jr.1portant to oo111e key furbeerere, port lculorly red fox.
This area io jud!Jed lo be more Important then the
Wetono Creek area that would be lnundoted by the W/OC
pion.
roreot hebltet, important for birds nnd bloek beoro,
exisl along the volley elopes. The loss of thio habi-
tat would be greater with the 11/0C plan.
There is e high potential for discovery of ercheologi-
col sltee .In the easterly region of the ~per Susltno
Bosln. The HDC/V pion has e greeter potent tal of
affect lng these altes. for other reaches of the river
the difference betwt!en plans Is considered minimal.
!A.oe to the potential for e greater impact on
the ""'!chino caribou herd, the HDC/V ocheme
Is cons Ide red Infer lor.
Due to lhe lesser potential for Impact on fur-
bearers the 11/0C Is judged to be superior. ·
The HDC/V plan Is judged euper lor.
The 11/0C pion Is judged to hove ll lower po-
tent lsi effoct on orcheolog\col sites.
X
X
X
IAI\U I. J (Cnnl inw,.Ji
Acslhul ic/
l«Jnd Usc
OVUlAU f:VALUA ll!lN:
NOlES:
H = \'lalana Oam
DC Dev i 1 Can~on llam
llllC = II io)h De v il Canyon flam
V Vee Dnm
Wilh nil her schenlt!• lhu nuslhet ic qonl ily of holh
()cy{{ Canyon and Vf?t: Cnuyun would he i~Hlirorl. fhe
llllC/V plan "uuld olso inundate ll""'"''" ralls.
Dunlo cnnslrucl ion al Vee Dam sHe 'and lhe size of
lhe v.,., RtHl!H·vnir, lhe IHlC/V ;>luo would inhe1·enlly
r:realc aeeesn lo more wilderness area lhwt would lhe
1;/IJC plan.
IHX:/V plan.
Boll• plans impucl lhe vulley ooslhel h:s. lhe
OlfftH·tmce is cnnsidered minimal ..
As: il iu eas ler to extend nccess than lo
1 im i l lL, inht!cenl ncceas reqtt i remanls were
conuiderod detrimental and tho W/DC plan is
judged sup~rior. The ecological sensil iv ily
of lhe •we a openud ~y lho !IOC/V pI an rein-
forces lh is judt]crnenl.
with IIOC/V plan is considered lo be oulweigherl by all
APPENDIX J -AGENCY AND OTHER COMMENTS
The second draft of the Development Selection Report was distributed to the
following agencies for review and comment. This section of the report addresses
the comments received and responses to those comments.
Attachment 1, 2, 3, 4 and 5, which follow in their entirety, are the comments
received from the following agencies:
-Attachment 1: University of Alaska Arctic Environmental Information and Data
Center
-Attachment 2: State of Alaska, Department of Fish and Game
-Attachment 3: U.S. Department of Interior, Geological Survey
-Attachment 4: U.S. Department of Interior, National Park Service
-Attachment 5: State of Alaska, Department of Environmental Conservation
J.1 -Re ses to AEIDC Comments ---~--~---------------~
(a) Borrow Areas
It is agreed that there will be significant impacts due to development of
borrow areas for construction of all earth or rockfill dams considered.
For purposes of the study it has been assumed that the major portion of
borrow material will be obtained from areas which will be subsequently
submerged by the proposed reservoirs. The relatively short-term impacts of
earth-moving operations during dam construction are considered to be
similar for all alternatives considered and therefore not a significant
factor in comparisons. The longer-term impacts of borrow areas which will
be submerged were considered to be included in the comparisons of impacts
of the reservoirs in each case.
(b) Continuation of Environmental Studies
It is true that detailed environmental studies of only the selected plan
are continuing in support of the requirements of the FERC license applica-
tion. The purpose of these studies is to allow more precise assessments to
be made of such impacts and for development of mitigation plans where
appropriate. The comparisons of environmental impacts of all alternatives
considered have been based only on those aspects which will influence the
selection of a development plan. The report provides appropriate support
for these comparisons to be made and will not consider them further. Con-
sideration of impacts which are similar in magnitude or which are relative-
ly insignificant will not influence the selection process and have there-
fore been excluded.
J-1
J.2 -Responses to ADF&G Comments
(a) Page 1-4(g), Task 7 -Environmental Studies
The text has been revised as suggested.
(b) Pages 8-26 and 8-27, Environmental Comparisons
The background information used to support the environmental comparisons
made consists of published data together with visual observation of person-
nel undertaking the current studies. The report provides appropriate
references to and documentation of this information. The personnel
involved in the studies are amply qualified in their respective fields and
were approved as such by the Alaska Power Authority.
Appropriate mechanisms have been established for continuing the active
involvement of ADF&G, USFWS and all other concerned agencies in the deci-
sion processes being used in this study. The scope and methodology for
undertaking environmental studies have been reviewed by these agencies and
modified where appropriate as a result of such reviews.
J.3 -Response to USGS Comments
No response required.
J.4 -Response to USNPS Comments
The Susitna Project Feasibility Report will deal with the specific impacts of
the selected development plan and will not consider further the impacts of
alternative Susitna Basin development plans. Sufficient information has been
presented in the report to arrive at a selected development; further study of
other basin alternatives is unwarranted at this time.
The impact of reservoir siltation for the selected development will be studied
and the results presented in the Feasibility Report.
J.5 -Response to ADEC Comments
No response required.
J-2
rcHc f:nvitonmenlollnfotmalion and Dolo Cen!er
707 A Street
ATTACHMENT 1
PHONE 19071 27Q . .:5f
Anchorage, Alo~~.o 99501
UNJVEHSITY OF ALASKA
RECEIVED
August 4, 1981 /.'!G 5 1981
AlASKA POWER AUTHOI?ITY
Dave Wozniak
Alaska Power Authority
333 W. 4th AVenue, Suite 31
Anchorage, AK 99501
Dear Dave:
Per your request to the members of th~ Susitna Steering Committee, I
have quickly !eviewed the Development Selection Report prepared by
Acres. In general I found it logical in approach and complete in re-
gards to the relevant factors one should evaluate when reducing multiple
options.
I have only the following specific comments:
I. The location and environmental effects of developing borrow
material sites is not well documented and incorporated into
the first part of the report. Enormous qunatities would be
required for most of the dams, and the removal, stockpiling,
and transport of this material could be a significant factor
influencing the decision-making process.
2. Significant efforts are currently being expended in environ-
mental study of this region, the results of which are not yet
available. Factoring this new knowledge into the decision-
making process could have influenced the nature of the final
scheme; or is the current environmental study effort geared
only toward the effects of the "selected plan (page 9-1)" and
not for input to the overall selection process? In genera} I
found the environmental effects of the alternative options
addressed very superficially.
I hope my comments are of interest.
\UW/g
cc: Al Carson
Sincerely,
~, / .
fl.'·(. [. ( ~
William J. Wilson
Supervisor, Resource and Science
Services Division
Senior Research Analyst in Fisheries
ATTAOtMENT 2
MEMORANDUM State of Alaska
10
FAOM
Dave Wozniak
Project Engineer
Alaska Power Authority
D AlE.
ftl[ NO
l E LEPHONE NO
333 W. 4th Avenue, Suite 31
Anchorage, Alaska ~1 ~ RECEIVED SUBJECl Thomas W. Trent
Aquatic Studies Coordinator
Su Hydro Aquatic Studies /'.:.!3 4 1981
Anchorage ~POWER AUl HOiiJY
July 29, 1981
02-I-81-ADF&G-7.0
02-V-Acres-1.0
Review of Draft
Development Selection
Repot·t -Su Hydro
Project
I've reviewed the draft Development Selection Report for the Susitna
Hydroelectric Project and mY comments a r e as follows:
Page 1-4 (g) Ta~k 7 -Environmental Studies
Comment: I recommend the words in the last sen t e nce i .e ., large game
be changed to big game.
Page 8-26 Environmental Comp arison -2nd paragraph - a state ment regard1 .. g
enhancement potential for anadromous fish and , the statement on page 8-
27 Environmental Compari s on, 2nd para graph .
Comment : A ge neral observation add ress ed t o th es e s pecific sec tions, is
that development of the environme ntal com pari s ons has undoubt e dly been a -
subjective proce ss . The sta tement s made reall y don't provide any detailing
of the hows, whys, and rati on ale f o r the con c l usi on s drawn . I bel i eve
we can accept a subj e ctive proc e ss f o r eval uating the en vi ronmental
merits or de ficiePcies of a particu la r dam s ch eme, but it would have
be e n a helpful pr oc e ss fo r Acres Lo invol ve ADF &G, USFW S a nd ot hers in
such an analy s is t o d iscuss al ternative po s i t ive/negat i ve i mpact pos si bilities .
I thin k t hi s wo uld hav e l e d to a hea lthy exc hange of ideas . The expos ur e
of the fi s h pnd wildlife o r other r es ou rc e age ncies t o t he s ame des ign
or o pe rat io nal s c hemes l ai d out t o the Acr es e nviro nm ental r ev i ew t e am
may have l ed t o conc lu sions which were t he same or potenti ally qu ite
diffe r e nt from the Ac res ana l ysis o f th e s i tuation .
To s um up, we ca n't arg ue with Ac r e s repor t sin ce we do n't kno w t he
ba ckgroun d information used to suppor t their rationalizations or the
e xper i enc e of t he i ndi vi dua l s in vo l ve d in the report prepara ti on that
drew the co nc lu s i o ns on fi she ries.
cc : S. Zrak e -DEC
B. Wi l s on -AEIDC
G. St ack hous e -USF WS
R. La mk e -USGS
A. Car son -ADNR
.._ )2~0 1 IAo.o. 5./)S I
Al Carson
State of Al.aska
UNITED STATES
DEPARTMENT OF THE INTERIOR
GEOLOGICAL SURVEY
Water Resources Division
733 W. Fourth Ave., Suite 400
Anchorage, Alaska 99501
July 27, 1981
Department of Natural Resources
323 E. Fourth Avenue
Anchorage, Alaska 99501
Dear Mr. Carson:
ATTACHMENT 3
RECEIVED
.JlJL 3) 1981
ALASKA POW[!: ;..:;::-:OJ.:JTY
I have reviewed the Draft Development Selection Report for the proposed
Susitna Hydroelectric Project as requested in the APA transmittal of
June 18 7 1981, The review was limited to the evaluation process us4d
by Acres, the relative impacts of several alternative development plans
. of Susi·tna hydroelectric resources, and the conclusion that the Watana-
Deyil Canyon plan is the preferred basin alternative.
There were no problems involved in understanding the selection process
used by Acres and there were enough data and information presented to
compare the final candidate (alternative) plans. The relative impacts
of the candidates were presented in an understandable and credible manner.
Although enly a qualitative evaluation of impacts is presented (pending
reports of on-going studies), a reasonable conclusion is that the Watana-
Deyil Canyon plan is the preferred candidate for Susitna hydroelectric
devPlopment.
r j / ~u· J • -·j1 I . "") ,~...\/J AJ · /_-cv-'"'-' U
'Robert D. Lamke
cc: David D. Wozniak, Project Engineer, APA, Anchorage, AY
'" ai:PLY au1:a TO:
United States Department of the Interior
NATIONAL rAHK SEH \'ICE
ALASKA STATE OffiC£.
ATIACHMENT 4
:S:Sf Well F i rth Avenue, Suite 2SO
Anehorace . Alu .. a 99SOl RECEIVED
1201-03a
AUG ~ 1931
Mr. David D. Wozniak
Susitna Hydro Project Engineer
Alaska Power Authority
333 West 4th Avenue, Suite 31
Anchorage, AK 99501
Dear David:
f.JJG ? 1981
AlASKA POWER AUTHORITY
In response to your request I have reviewed the Draft Devel-
opment Selection Re p ort for the Susitna Project. Based UP,on
the information presented in the report, I would judge the
evaluation process to be satisfactory. However, I would not
want to recommend or otherwise c omment on a preferred basin
alternative prior to the completion of ongoing studies which
will further quantify the anticipated environmental impacts.
I assume the final report will reflect a more precise com~
parison of environmental impacts for the dam sites under
consideration .
An additional ite m of interest which should perhaps be
included in the final report is a comparison of the ex ~c cted
life of the project for each alternative dam site considering
the effect of silt accumulation in 'the r eservoirs.
Th ank you for the opportunity to review the report. The
above c omme nts are my own and should not be interpreted as
representing the off icial p osition of the National Park
Service .
Sincere ly,
___ __;; ~ ( '. :~L 1-jc-u, U>L · ) I~ V\.
L a r r y 7. W r 1. g h t Outdoo~ Rec reation Pl a nn e r
Sav~ Enn gy and Y o u Se n·~ A mnica!
n
~ . ,, . l'' . D r . ....:.v~-"-
Dave Wozniak
Project Engineer
Alaska Power Authority
333 W. 4th Avenue, Suite 31
Anchorage, Alaska 99501
Dear Mr. Wozniak:
' :'
I
/
I
ATTACHMENT 5
437 E Street
second Floor
Anchorage. AK 99~01
P.O. floY. 1207
Soldotna. Ala:.ka 99669
(90 7) .:'6Z :>210
P.O. Bor. i064
[J Wasilla. Alnska 99687
(907) 376·5038
August 14, 1981
We have reviewed sections 7 and 8 of the Susitna Hydroelectric Project
Development Selection Report (second draft June 1981). We find that the
plan tion methodology used in section 8 meets the objectives of
determining an optimum Susitna Basin Development Plan and of making a
preliminary assessment of a selected plan by an alternatives comparison •.
The increased emphasis over previous an:alyses'. of the environmental
acceptability of the alternatives is good.
At this time, this Department does not endorse any particular plan. We
wo~ld,·however, recommend the Steering Committee openly discuss the
\>'atana Dam -Tunnel option because of its reduced environmental and
aesthetic impact.
Thank you for the opportunity to review this document. We appreciate
your fort in soliciting Su-Hydro Steering Committee involvement. If
you have any questions regarding these comments please contact Steven
Zrake of this office.
cc: Steve Zrake
Dave Studevant
Al Carson -DNR
BH/SZ/mn
Sincerely,
fl#/)'h;~
Bob H:lrtin
Reglonal Environmental Supervisor