HomeMy WebLinkAboutAPA1284I
I
I
I
I
I
I
~
I
I
I
I
I'
I
I:
: •... ..
I
I
I.
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
/
TASK 6 -DtvELOPMENT SELECTION
SUBTASK.6.05
DEVELOPMENT SELECTION REPORT
APPENDICES A THROUGH I
JULY 1981
ACRES AMERICAN INCORPORATED
1000 Liberty Bank Building
f·1ain at Court
Buffa 1 o, New York 14202
Telephone: (716) 853-7525
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
SUSITNA BASIN DEVELOPMENT SELECTION
'JrJLUME II -APPENDICES A THROUGH I -
TABlE OF CONTENTS Page
LIST 0 F TABLEs·. . . e • • •••••••.•••• ., • • • • • • • • • • • • • • • • • • •• o • • • • • • a • • • • • • • • • • • i i i
LIST OF FIGURES ............................................... Cl • • • • • • • • • • • • • vi; i
A -GENERIC PLAN FORMULATION AND SELECTION METHODOLOGY
A.l -Plan Fonnulation and Selection Methodology .................... A-2
A.2 -Guidelines for Establishing Screening and Evaluation
Criteria ••••e··········································,···· A-2
A.3-Plan Selection Procedure ························c··········· A-5
B -THERMAL GENERATING RESOURCES
B.l-Fuel Availability and Costs ................................... B-1
8.2-Thennal Generating Options-Characteristics and Costs ..••.•. B-7
-B.3-Environmental Considerations .•..•.••.....•.•.•..•........•.. B-16
C = ALTERNATIVE HYDRO GE~ERATING SOURCES
C.l -Assessment of Hydro Alternatives .......•.••.••.•.•.•.•...... C-1
C.2-Sc~eening of Candidate Sites~ ....•.•.•.•••............••.•••. C-1
0 -ENGINEERING LAYOUT DESIGN ASSUMPTIONS
D.1 ... Approach to Project Definition Studies ..••.............•..•. 0-1
0. 2 -Electrical System Considerations • . • . . . • . • . . • . . . • • . . . . . . . . . . • D-1
0.3 -Geotechnical Considerations . • • . • . . . . • . • • . . . . . .. .• . . . . • • . . . . . . 0-2
0.4-Hydrologic and Hydraulic Considerations ....................... D-3
D. 5 ... Engineering Layout Considerations •.• . . • . . • • .. . . • • . . . .. .. • . • • • .. • .. D-3
0.6 -~chanical Equipment ......... ... . • •. .. . . . . .• • ... .. .. . . •• . •. .. .. . . D-3
0.7-Electrical Equipment··················~·····~····~·········· 0-4
D.S -Environmental Considerations .................. "............... D-4
E -St!SITNA BAS IN SCREENING MODEL
E.l -Screening Model ................. ,.,.............................. E-·1
E. 2 -Mode 1 Components •.•.....•••.•.•. ·• . • . • . • . . . . • . . . . . . . . . . . . • . • . E .... 2
E. 3 -. App 1 i cation of the Screening Mode 1 . . . • • . . • . . . . • • • . .. . • • . . • . . • E-3
E.4· .. Input oa-ta ................................... .:.••o•••····-······· E--3
E. 5 -Mode 1 Runs and Results ....••...•.••...•.........•...... " H ... • E-4
;
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
SUSITNA BASIN DEVELOPMENT SELECTION
VOLUME II -APPENDICES A THROUGH I
TABLE OF CONTENTS (Cont.)
F -SINGLE AND MULTI-RESERVOIR HYDROPOWER SIMULATION STUDIES
Page
F.l -Introduction ••• ~····················•co•···········~········· F-1
F .2 -Single Reservo·ir Model........................................... F-1
F.3-Multi-Reservoir Simulation.................................. F-3
F. ·4 -Arinua 1 Demand Fa,:tor •••••••••••••••.•••••.•• o • • • • • • • • • • • • • • • • F -3
F.5-Input to Simulation Models .•• · .. ·······················~······· F-4
F.6 -Model. Results................................................... F-5
F.7-Interaction of OGP5~········~·················•·o·•·········· F-6
G -· SYSTEMWIDE ECONOMIC .EVALUATION
G.l -Introduction .................................................. G-1
G.2-Generation Planning Models .••.•••.•..••• ~·············~······ G-2
ll.3-Generation Planning Results, ............................ ee••· G-8
H -ENGINEERIN3 STUDIES
H.l -Devi'l Cc·lnyon Site •• •r•............................................. H-1
H.2-Watana Site •.......•..................... c ••••••••••••••••••• H-5
I -ENVIRONMENTAL STUDIES
I • 1 -Sununa.ry ........................ ,. •••••••• o • • • .. • • • • • • • • • • • • • • • • • I -1
1.2-TES Report ........................................................ I-3
ii
I
I
I
"I
I
I
I
I
I
I
I
I
I
I
I
I
I
'I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I,
LIST OF TABLES
A. i
A.2
A .. 3
A .• 4
8.1
8.2
8.3
8.4
8.5
8 .. 6
B.,?
8.8
8.9
B.lO
B.ll
8.12
8.13
8.14
8.15
C.l
C.2
Step 2 -Select Candida~es
Step ~ -Screening Process
Step 5 -Plan Evaluation and Selection
Examples of Plan Forntulation and Selection
Methodo r ogy
Alaskan Railbelt Coal Data
Alaskan Gas Fields
Alaskan Oil Fields
Alaskan Railbelt Fuel Prices (1980)
SuDIIlary of Alaskan Fuel Opportunity Values
Generating Units Within the Railbelt -1980
Existing Generating Capacity .!n 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 Combinad Cyc1e Plant Cost ~stimates
Sunmary of Thennal 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 T~BLES (Cant~)
C.3 Evaluation Cirteria
C.4 Sensitivity Scaling
C.5 Sensitivity Scaling of Evaluation Criteria
C.6 Site Evaluations
Ce7 Site Evaluation Matrix
C.S Criteria Weight Adjustments
C.9 Site Capacity Groups
C.lv Ranking Results
C.ll Shortlisted Sites
Ce12 Preliminary Cost Estimate-Snow
C.l3 Preliminary Cost Estimate-Keetna
C .. 14 Pl"el iminary Cost Estimate -Cache
C.15 Preliminary Cost Estimate-Browne
C.16 Preliminary Cost Estimate-Talkeetna-2
C~17 Preliminary Cost Estimate-Hicks
C.18 Preliminary Cost Estimate-Chakachamna
C.19 Operating and Economic Parameters for Selected
Hydroelectric Plants
C .. 20 Alternative Hydro Development Plans
C.,21 Results of Economic Analyses of Alternative
Generation Scenarios
D.l Monthly Variations of Energy and Peak Power
Demand
0.2 Geotechnical Design Considerations
0.3 Initial Hydrologic Design Considerations . .
iv
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
••
I
I
I
I
I LIST OF TABLES {Cont.}
I 0.4
I 0.5
I D.6
D.7
I 0.8
I 0.9
I, D.lO
E. 1
I E.2
:
I E.3
E.4
I E.S
E.6
I E.7
I E.8
F.l
I F.2
F.3
I F.4
I F.S
F.6
I. F.7
I
I.
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 t-1odel
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
1. . ' ..
j ' .. ·
•, I,... ,.
F.a
F.9
F .10
F.lJ
F.l2
F.13
F.l4
F .15
G.l
G.2
(~. 3
G.4
G.S
G.6
G.9
G.lO
........... ..
' . .
P1 an 2~ 1 .,.. Ene.rgies
Plan 2.2 "" Energies
Plans 2,3 and E~213 ~ Energies
Plan 3.1 .,.. Energies
Plan 4,1 -.Energies
Plan E1.2 ~ En~rgies
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 £1.3-Medium Forecast
vi
··I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
:····· .~ '
I
I
I
I
I
I
I
I
I
I
I
I
I
I .,
I
I
I
I
I
LIST OF TABLES~ (Cont.}
G.ll
G.l2
I.l
I. 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
I
I
II LIST OF FIGURES
I
II
I
I
I
I
I
••
I
I
I
I
I
I
I
I
A.l
C.l
C.2
C.3
C.4
c.s
C.6
C.7
C.8
C.9
C.lO
c. 1'1
E. 1
E.2
E.3
E.4
F.1
G.l
H. 1
H.2
H.3
H.4
P'ian 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
Wa'tana Arch Dam Geometry -Sections Along Planes
of Centers
viii
0
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
.. APPENDIX A
GENERIC PLAN FORMULATION AND
. . SELECTION METHODOLOGY
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I,
I
I
I
I
APPENDIX A -GENERIC PLAN FORMULATION AND
SELECTION METHODOLOGY
On numerous occasions during the feasibility studies for the Susitna Hydro-
electric Project~ it is necessary to make decisions in which a single or a small
number of courses of action are selected from a larger number of possible alter ...
natives. ·
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 to be 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 envir-
onmental 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 developmertts in the pr·imary assessment of the economic feasibility of
the Susitna Basin development plan (Task 6).
-Selection of the preferred Susitn.a 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. tomparison
of Railbelt plans with and without Sus.itna).
-Optimization of the selected Susitna Basin development plan {i.e. determi.ning
the best dam heights, installed capacities, and staging sequr-~;ces) (Task c).
-Selection of the preferred transmission 1 ine rou.tes (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 f ac i 1 it i es ( Task 2 ) .
It is recognized that the above planning activities embrace a V'ery diverse set
of decision making pr·ocesses. The 9eneralized 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 u.sed for establishing screening and evaluation
criteria.
A-1
A.l -Plan Formul,tion and Selection Methodologx
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 planned course of action
-Step 2: Identify all feasible candidate courses of action
-Step 3: Establish basis to be used and perform screening of candidates
-Step 4: Formulate p·fans incorporating preferred alternatives
-Step 5: Re-establish basis to be used, evaluate_plans and select preferred
plan
Under Step 2, the ~andidate courses of action are i denti fi ed such that they sat-
isfy, ·either individually or in combinations, the stated ob,jectives (Table Al) ..
In Step 3, the basis of screening these candidates is established in items of
redefined, specific objectives~ assumptions, data base, cr·iteria and me.thodol-
ogy. This process follows a sub-series of 7 st~ps as sho•11n in Table. P..2 to pro-
duce a short list, idearlv of no more than 5 or.· 6 preferr··ed alternatives.. Plans
are then formulated in Step 4 to incorporate ~ingle alternatives or appropriate
combinations of alternatives. These plans ar·e then ·eva:Juated in Step 5, using a
further redefined set of objectives, criteria and methodology, to arrive at a
selected plan. This 6-step procedure is illustrated in Table A.3. Tables A.2
and A.3 a 1 so indicate the review process tnat must accompany the p 1 anni ng pro-
cess.
It is important that within the plan formulation artd selection methodology, thf!
objectives of each phase of the deci si 0'/1 process be redefined as nr~cessary. At
the outset the objectives wi 11 be broad and somewhat general in nature. As thra
process continues, there wi 11 be at le.ast two redefinitions of objectives. n,,e
first wi 11 take p 1 ace during Step 3 a11d the seco,nd <;Juring Step 5.. As an exam-
ple, the basic objectives at Step 1 might be the development and application of
an arJpropri ate procedure for selection of a single preferral cour~e of action.
Step 2 might involve the selection fJf those candidates which are technically
feasible on the basis of a defined data base cmd set of assumptions. The objec-
tives at Step 3 might be the estab'lishment and application of a defined set of
criteria for elimination of those candidates which are less acceptable from an
economi ca 1 and en vi ronmenta 1 standpoint. Th·i s wou 1 d be accomp 1 i shed on the
basis of appropriately modified c'Jata base and assumptions. Having developed
under Step 4, a series of plans 'incorporating the remaining or preferred alter-
natives, the objectives under St.ep 5 might be the selection of the single alter-
native which best satisfies ·an appropriately redefined set of criteria for say
economic, environmental and social acceptability.
A.2 -Guidelines for Establish~ing Screening and Evaluation Criteria
Definition of criteria. forth(.! screeninrJ and evaluation procedures will largely
depend on the preci·s~~ nature of the alternatives under consideration.. However
in most cases, compa('i·sons wi.ll be basf~d on technical, economic, envfronmentaJ
and socioecanomi c factors wh:i ch wi 1 1 u:sua 11 y involve some degree of trade-off in
A-2
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
1 ..
• -.~, < ""T.;;;~;;
••
I
I.
I
I
I
I
I
I
I
I
I
>
I
I.
I
I
I
I
·;·
'·.:.:.': ·. ·• .. ·. '~-·-
making a preferred selectiono It is usually not possible to adequately quantify
such trade-offs.
Additional criteria may also be. separately considered in some cas~s, such as
saf~ty or conservation of natural resources. Guidelines for consideration of
the more corrmon overa11 facto·rs are discussed in the following paragraphs.
(a) Technical Feasibility
Basically all options considered must be technically feasible, complete
within themselves, and ensure public safety. They must be adequately de-
signed to cope with all possible conditions including flood flows, seismic
events, and all other types of normal loadi-ng conditions.
(b) Economic Criteria
In cases where a specific economic objective can be met by various alterna-
tive plans:t the cr·iteria to be used is the least present worth cost. For
example, this would apply to the evaluation of the various Railbelt power
generation scena,rios, 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 b~ used as a basis of comparison. Fat" instance, energy cost in
say $/kwh would apply to screening a number of hydroelectric development
sites distributed throughout southern Alaska. Similarily, the screening of
alternative r.tc:cess or transmission line route segments would be based on a
$/mile comparison.
As the Susitna Basin development is a State .project, economic paramete\"S
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 pay-
ments such as taxes and subsidies are excluded, and opportunity values (or
shc~dow prices) are used to establish parameters such as fuel and transpor-
tation costs.
Extensive use should also be made of sensitivity analyses to ensure that
the concl~sions based on economics are valid for a range of the values crf
parameters used. For example, some of the more common parameters ~onsid
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 Criter·i a
Environmental criteria. to be considered in comparisons of alternatives are
based on the FERC ( } requirements for the preparation of the Exhibit E
"Environmental Report" 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 cu~tural 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 incorporated 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
Similarly, based generally on FERC requirements, the project impact assess-
ment should be considered in terms of socioeconomic criteria which
include:
-Impact on local conmunities and the availapility of public facilities and
services
-Impact of emp1oy.nent on tax and property values
Displacement of people, businesses and farms
-Disruption of desirable community and regional growth
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
••
I
I
A.3 -Plan Selection Procedure
As noted above~ for each successive screening exercise~ the criteria can be re-
fined 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 im-
pacts, in order to arrive at an overall numerical evaluation. It is considered
that 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 with-
out making tradeoffs. For example, the screening criteria used might be:
-•r ..... 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 ..... u
This approach is preferable to criteria which might state:
-
11
•••• alternatives will be excluded if the stm of their unit cost index plus
the environmental impact index exceeds Y .... "
Nevertheless, it is recognized that under certain circumstances, particularly
where a relatively 1 arge 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 qual ita-
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
II • • • •
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 per-
forming 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 evaluated
against Plan B, then the better of these two is evaluated against C to select
the best overall plan.
A-5
••
I
I
I
••
I
I;
I 0
I
I
I
I
I
••
"
I
I
I
I
I
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
-ass~tions
-data base
-screening criteria
-screening methodology
e 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 nllllber 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.J -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 cor_RParison technique to rank the plans as ( 1 ) the preferr-
ed plan, (Z) the second best plan, and (3) other plans;
-Identify tradeoffs and assUll~tions made in ranking. the plans.
Step 5.4 -Prepare draft plan select·ion report.
Step 5.5 -Review plan selection process via (as appropriaJ:e):
-Acres
-APA
-External groups
Step 5.6 -Prepare final plan selection report.
I
I
I
I
I
I
I
I
I
I
I
I
I
••
I
I
I
:1
---
Activity
Susitna Basin ..
Developnent
Selection
Access Route
Selection
---· ----.. ----
TABLE A.4 -EXAMPLES Of PLAN fORMUlATION AND SELECTION METHODOLOGY
f. Define
Objectives.
Select best
Susitna Basin
hydropower
development
plan
Select 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 aites in the
basin, e.g •. :
Devil Canyon;
High Devil Canyon;
Watana
Susitna UI;
Vee;
Maclaren;
Butte Creek;
Tyone;
Denali;
Gold Creek;
Olson;
Devil Creek;
Tunnel Alternative
All 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
3.. Screen
Screen out ·sites
~ich are too
small or are
known to have
severe environ-
mental impacts
Screen out links
Which ar:e either
11Dre costly or
have hicjler
environmental
impact than
equivalent
alternatives.
Ensure suffi-
cient links
remain to allow
formulation of
plans·
sites and associated
landing facilities
4.. Plan
formulation
Select several
combinations of
dams \tehich 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 -
Tt.11nel ~
Select several
different acce~s
plans, e.g.:
Gold Creek road
access;
Gold Creek road/
rail access;
rena li Highway
road access
5. Evaluation
'Londuct detailed
evaluation ~r
development. plans
Conduct detailed
evaluation of
development plans
---
-.. -. -; - -..... -· -.. - -.. , - - - --'
OEFlNE
OBJECTIVES
/
/
lNPUT FROM AVAILABLE SOURCES -PREVIOUS AND CURRENT STUDIES
S~LECT
CANDIDATES
. a
SCREEN
FEEDBACK
FEEDBACK.
PLAN FORMULATION AND SELECTION METHODOLOGY
.,
LEGEND
~ STEP NUMBER lN
. ·· 4 STANDARD PROCESS
( APPENDlX A)
FiGURE A.lliil
I
I
1:
I
I
I
I
I
I
I
I
·I
I
I
I
I
I.
I
I
APPENDIX B
THERMAL GENERATING RESOURCES
I'
I
I
I
I
<;
I
I
I
I
I
I
I
I
I
I
I
I
-·
I
APPENDIX B -THERMAL GENERATING RESOURCES
The purpose of this Appendix-is to define the thermal generating re.sources
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 ussoci ated 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.
B .. l -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 Raflbelt due
to public policy and high vaiue for other uses. Tables B.l, 8.2 and B.3 summar-
ize estimated fuel resel~ves.. 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 ( }:
-Nenana
-Matanuska
-Beluga
-Kenai
-Bering River
-Herendeen Bay
-Chignik Bay
Of these eight regions, only four have potential for Railbelt use. Table
8.1 lists pertinent information of these fJur coal reserves.
The Beluga field, which is part of the larger Susitna Coal District, is an
undeveloped source 1 ocated 45 to 60 mi·1es west of Anchorage on the west
bank of Cook Inlet. Coal mining at this location would require the estab-
1 ishment 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 mi i 1 ion tons can be stripped without
exceeding economic limits on coal/overbur·den ratios.
Tne existing Nenana coal field, which is located in the vicinity of Fai.r-
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 estintatect total in excess of 2 billion additional
tons of coal could be ·extracted by urufe'rground mining.
B-1
"
..
The Matanuska coal fields, east of Anchorage, occupy most of the Matanuska
Valley. Although stripping and underground mining of ~his 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 loc,a.lly~ potential as a significant Railbelt· source is unlikely
( ) .
The fourth poten~ial coal producing region is the Kenai coal field in the
Kenai lowlands 1• south of Tustumena Lake 9n the eastern shore of Cook Inlet.
Resources are e~stimated at 300 mi 11 ion tons. These coal seams are thin and
separated vertiically making mining extr,emely difficult.
. 0
Limited use of coal in the Railbelt at present is a result of an undevelop-
I
I
I
I
I
ed export market and the relatively small local demand for this fuel. Cur-I
rently the Usibe11i 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 cofTillercial coal operation in Alaskao The coal is •..
trucked several miles from the mine site to a 25 MW power plant owned and
operated by the Ciolden 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 .•.
Susi·tana for transport to Fairbanks, a distance of 111 miles. This coal is
deliverea 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 Wainwright 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 produc-I
tion.. In September 1980, a contract between Japan 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 I
available at this time. Other expansion options include:
-Enlarge the Healy generation p·l ant 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 e 1 ectri c power
capability. ·
-Transport Healy mined coal approximately 55 miles north via tne Alaska
Rai 1 road to Nenana and bui 1 d 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 ~pprox1mate1y 20.9 miles south vi a the Alaska
Railroad to Anchorage for utilization in new 200 or 400MW 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
I
I
I
I
rl
--I-
I
I
I
I
I
I
I
I
·I
I
I
I
I
I
••
I
I
I
I
II
fl
I
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 noldings was
completed in 1980 by the Alaska Division of Energy and Power Develop-
ment ( ) • This report summarizes the potenttal of development of the
Cook Inlet Region coal field. Several op.tions were shown to exist for
develOJlllent. The first ·option would be develollltent 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 Chugach Electric Association (CEA).
This option is depe11dent upon government mandated requests for util-
ities to convert from natural gas to coal. CEA has CUl"rently no firm
p 1 ans 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 CEA is required by govenment mandate to
replace natural gas units with coal units. This scenario would re-
quire moderate development of a work camp at Beluga, and would in-
clude two 200 MW generators using approximately 1.5 million tons per
yea~. Construction would be during the period 1980 -·1986.
-A sufficiently large (at least six million tons per yecLr (MMTPY))
export market is developed and no generating stations are construc-
ted. This figure is considered the minimum· amount necE~ssary for
cost effective exporting. In this case, a permanent work camp would
be established similar to the first scenario. ExportiJng ·would begin
in 1990 •
-Two 200 MW coal-fired generating plants and a six MMTPY coal export-
ing facility could justify the necessary f.ront•end capital invest-
ment to establish a permanent conmunity at Beluga. This would also
entail secondary economic development.
-There 1s.a distinct possibility that no development of the Beluga
coal field will occur before 1990. ·
Export scenarios also incluae barging 3500 miles to Japan or 2100
miles to San Francisco and a slurry pipeline scheme to the Pacific
Northwest ( ). Supplying Anchorage with coal via a ne~w railroad tie
does nat appear to be an option considered for the near future devel-
opment ( ) •
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 Clrluitna River Field was completed by Bechtel
Corporation in Apr~ 1 1980 ( ) • 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
Nor~west or to California were estimated in a 1977 Report on "Alaska
Coal and the Pacific .. 11 ( ) These prices were estimated and appear in
Table 8 .. 5.
The Beluga Coal studies done for Placer-Amex and the Bass-HuntWi1son 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 sup-
plies to future coal-fired gener·ating plants cofistructed in Alaska (Table
8.5).
A report issued in December 1980 by Battelle Pacific Northwest laboratory
( ) analyzed market opportunit·ies for Beluga Coal. Results reported in
this report were generally cons·istent with earlier Battelle and'DOE
studies.
(b) Natural Gas
Natural gas resources available or potentially available to the Rai1belt
region include the North Slope (Prudhoe Bay) reserves and the Cook Inlet
reserves. Information on these reserves is summarized in Table 8.2.
The Prudhoe Bay Field contains the largest accumulation of oil and gas ever
discovered on the North P.merican continent. The in-place gas volumes in
the field are estimated to be in excess .of 40 trillion cubic feet (Tcf).
With losses considered, recover·abl e gas reserves are estimated at 29 Tcf.
l:ias can be made available for s,ale from the Prudhoe Bay Field at a rate of
at least 2.0 ·bill ion cubic feet: per day ( Bcfd) and possibly sl ightl v mor,~
than 2.5 Bcfd. At this rate, flas deliveries can be sustained for 2o to j\5
years, depending on the sales r·ate 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. Two
overland pipeline routes (Alcan and Arctic) and a pipeline/LNG tanker (El
Paso) route were considered. The Alcan and Arctic pipeline routes tra-
versed Alaska and Canada for some 4000 to 5000 miles, terminating in the
central U.S. for distribution to points east and/or west. The El Paso pro-
posal involved an overland pipt:line route that would generally follow the
Alyeska oil pipeline utility corridor for approximately 800 miles. A liq-
uefaction plant would process approximately 37 mill ion cubic meters of gas
'8-4
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I ,.
:1
I
I
"
I
I
I
I
I
I
I
I
I
I
I
~•
'I
I
per day. Th~~ transfer station was proposed at Point Gravinia south of the
Valdez termination point. Eleven 165,000 cubic meter cryogenic tankers
would transpol'·t the LNG to point Conception in California for regasifica-
tion. · ·
The studies noted above have concluded with the initiation of a 4800 mile,
and costing between $22 and $40 billion, 2.4 Bcfd, Alaska-Canada Natural
Gas pipeline project, expected to be operational by 1984-1985. The pipe-
1 ine project passes approximately 60 miles northeast of Fairbanks ..
The Cook Inlet Reserves (Tab 1 e B. 2). are re 1 at i ve 1 y sma 11 in comparison to
the North Slope reserves. Gas reserves are estimated at 4.2 Tcf as com-
pared to 29 Tcf in JJrudhoe Say. 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 capabi.lity 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. Volume produced is .185 tv1MCFO with raw natural gas requirements of
70 percent from a platfonn in Cook Inlet and 30 percent from existing on-
shore fields.
In 1979, the Pa.cific 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. To date PALNG estimates 1.0 Tcf
is in place.
There is also some pot:ential 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 pl'·oject 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 Rai lbelt fuel alternatives since an existing mar·ket 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 a~d intersecting with the Alaska-Canada pipeline. The regu~
1 ated cei 1 ing 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 vi a the LNG tanker scheme as proposed by PALNG was estimated to
B-5
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/MMI.1tu} 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.
The current Japanese market price for natural gas sales from the Nikiski
LNG project is $4.50 to $4.65/MMBtu ( ). Based on information collected
from Nikiski, transportation and processing costs were estjmated 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 o ·n resources as seen in Tab 1 e B. 3. North S1 ope reserves are estimated
at 8375 mi 11 ion barre 1 s. Oi ·1 reserves in the Cook In 1 et region are est i-
mated at 198 mill ion barrels ( ) . As of 1979, the bulk of Alaska crtde
oi 1 production {92.1 percent) came from Prudhoe Bay, ~1itn the remainder
from Cook Inlet. Net production in 1979 was 1~4 mi11 1ion barrels per day
{ ) .
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.. Approximate.ly 2 percent (or 10 mill ion bar-
rels) of the Prudhoe Bay crude oil was used in Alaska refineries ·and ?.long
the pipeline route to power pump stations ( ). The North Pole Refinery,
located 14 miles southeast of Fairbanks, is supplied from the trans~J\laska
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 MW of oil-fired capacity.
Due to the high cost of oil, these utilities use available coal-fired ca.-
pacity as much as possible with oil used as standby and for peaking purpos-
es.
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
8-6
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
'I
I
I
I
I
'I
I
I
I
I
II I
I
I
I
I
I
I
I
I
I
expansion study, where oil is considered only available for standby units,
the price adopted for use is $4.00/MM8tu (Table 8.5).
8.2 -Thermal Generating Options -Characteristics and Costs
The analysis of thermal generating resources available tc 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 8.7}. The recent trend by both Anchorage Municipal Light and Power
Department (AMLPD} and CEA has been to meet future generating needs using com-
bined 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 Fairb?nks 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 aiffei~ent types of thermal generating plants consid-
ered available to the Railbelt rugion were estimated. Capital cost estimates
for coal-fired steam, combined cycle, gas turbines and diesels appear in Tables
8.8 to B.l3. Table B.l3 sunmari;tes the generation parameters necessary for the
production cost model in the genl~ration 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 costs 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 tasko The approach taken in this study has been to
develop generic coal-fired plant cost· estimates, largely based upon published
Lower 48 cost data, previous studies of Alaskan construction cost differentials
and recent Alaskan construction experiences.
Gas turbine comLJined 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
p1ant is operated by GVEA at Healy. Two more coal units, with total capa-
city of 6 MW, supply Fo-rt Wainwright and the University of Alaska at Fair-
banks with heat and e.lectric power. These two units supply FMUS on a con-
tractual basis, when available. All of these plants are small in compari-
son to new electric utility units typically under consideration in the
Lower 48. 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
. J'
-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 p1 ant 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 waul d 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. As typical plant unit
size required in Alaska are sub~tantially smaller for the typical Lower 48.
Previous studies have therefore incorporated relationships for economy of
scale, based upon Lower 48 data ( ). The regional differences in Alas-
kan construction costs can also be substantial, with the result that Alas-
kan location adjustmant factors have a1so been used in these recent studies
( ). Cost differences may be due to transportation requirements, labor
costs, climate and distance from equiJnent supplies.
A review of Alaskan construction cost location adjustment factors was un-
dertaken by Battelle in March 1978 ( ). These adjustment factors, identi-
fied for different locations in the Railbelt, ranged from 1.35 to 1.7 for
the 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
Healy-Fairbanks areas, respectively. The Battelle study included review of
both material cost additions due to transportation and labor cost varia-
tions due to 1 ack of developed soci a1 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
I
I
'I
I·
I
I
I
I
I
I
I
I
I
I
\1
I
I
I
·:.1
I
I
I
I
I
I
I
I
I
I
-I
I
I
I
I
'I
I
I
development of a largely.,uninha~:,ted area. Laod was considered to be lower
in cost than in other regions, and the site favored use of preassembled
plant modules 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 th~ 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 f~ctor. 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 ( ). Rec-
ognizing the inaccuracies associated with using capacity scaling factors,
the use of the exponent approach was limited and was reviewed for consis-
tency once applied. A further check was made by means of cost sensitivity
assessments in generation planning studies (Section 8}.
{ i-i) 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. ( ) 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 h.ave 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 acc~s~ available,
but at some distance from the site
- a river intake and pt.mping 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 piant design has assumed to include the following systems:
-co a 1 handling system
-auxiliary boi 1 er 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 wat.er 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
-;rotential devices
- 1 i ghtni ng arresters
-foundations
-control buildings
-supporting structures
-take-off towers
-single alumint.m 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 condensers would be cooled ·in
two mechanical draft cooling towers, with mai<e-up water coming by pipeline.
There is, of cou'l'se, the potential for open cycle cooling with the use of a
cooling pond w~th a potential cost savings. However, due to the scope of
this study, t~1is 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 a re-
mote ~r-ea. Accessories therefore included 15 miles of railroad and switch-
ing s'tation~ and 13 miles of water pipeline. This would adequately repre-
sent a remote development in the Beluga area.
B-10
,.
I
I
I
'I.
I
I
I
I
••
·I
I
I
I
.I
I
li
I
·I
I
I
I
I
I
I
I
I
I
I
·I
I
I
I
I
I
'I
I
I
Table B.6 summarizes the cost estimate of tlhe E.PRI 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 by use of the Handy-Whitman Indices
( ) . The Handy-Whitman indices are a wide 1 y used technique for cost up-
dating. They are developed bi-annually by ~4hitman-Requardt and Associates
and are based on extensive utility plant cost research in each of six re-
gions of the United States. The Handy-Whitman indices used for this study
are for the Region 6 -Pacific Northwest areao They are represented as a
ratio of the January 1, 1980 dollar values to 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 p 1 ant in the Lott~er 48 and therefore is required to be sea led
to reflect the cost of a unit size applicable to the Railbelt Region.
The scaling of the cost was considered by two methods. The first is devel-
oped from EPRI research which reported that approximately 54 percent of the
tot a 1 construction cost is attri but ab 1 e to the first unit ( ) • The cost
of a single 500 MW unit would thus be 54 pe~rcent of the cost of a 1000 MW
plant, or $428 million. The capacity scaling equation used is:
Cost of Unit A
~ost of Un.i t B = (~apabi lity of Unit A) exponent
( apa&rility of Unit B)
This equation was solved for the exponent by substituting the various ~osts
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 ( )~ inflation, high in-
terest rates and lengthened schedules have negated, to a 1 arge 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 obtai ned 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 in fact an accurate r::~resentatioo of
the current economy of scale in power plant estimation. Consequently tl1is
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 Batte 11 e for p 1 ants in the 100 to
200 MW range. Applying the 0.85 factor results in a more conservative fig-
ure for the 100 MW plant by almost $90 mil1lon 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 -... e a viable possibility for extension of
Railbelt generation capability. Ongoing studies in the Fairbanks region to
expand existing coal-fired capacity for ele1ctricity and district heating,
although for a smaller plant capacity than the 100 MW considered here, have
shown th-e cost of new mechanical equipment alone to be approximately 1.77
times more compared to a simi 1 ar installation in the Lower 48. This
result,·in addition to research by the U.S .. Army Corp of Engineers and
B-11
• •· I . . . . .
. '
• • 0 • •
. · .. · ... ' .· . . -·_. . . . . .. .. . .
' . . \ . -
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 op-
timized 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 Rai lbelt coal potential cost for a remote
Alaskan situation. The Beluga cost figures shown in Tables 8 .. 8 to 8.10 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 repor-
ted by Battelle ( ).
In addition to the direct costs shown in Tables 8.8, 8 . .9 and 8.10, a con-
tingency of 16 percent, 10 percent for utilities and other construction
facilities and 12 percent for engineering and administration were added.
Interest of 3 percent, net of escalation, during the construction period of
six years for the 500 and 250 MW p 1 ants and five years for the 100 r.n; p1 ant
wou 1 d be an added cost.
(iv) Operating Characteristics
Co a 1-fi red plant operating characteristics which are incorporated in the
generation pianning analysis are heat rate, unit availability and operation
and maintenance costs. The heat rates selected for the three plant sizes
is 10,500 Btu/kWh, whi.ch is consistent with the EPRI p 1 ant design.
Outages for co a 1-fi red steam p 1 ants are taken into account in terms of
scheduled (planned) and forced outages as a percent of time. Data publish-
r-:-d by the Edison Electric Institute (EEI) indicates a forced outage of ap-
Pl""OXimately 5.4 percent for large coal-fired plants ( ). 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 ll percent, which also correlates with
the EEI data, was adopted as the scheduled outage rate for coalfired plants
for this study. The parameters given above for thermal generating plant
are gi v en i n Tab 1 e 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 cost for typical U.S. plants are reported periodically in
the DOE publication, Steam Plant Construction and Annual Production
Expenses ( ) • Trends indicated in these r·eports 1 ed to adoption of values
for fixed cost of 0.50~ 1.05 and 1.30 $yr/kw for 500 MW, 250 MW and 100 MW
plants respectively. Variable costs in the DOE publication ( ) 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
0
:I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
.:I:
I
;I
I
I
I
I
I
I
I
I
I
I
I
-I
I
I
I
(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 l"ising fuel prices, ·increasing environmental requirements and
greater flexibility for mid-and base-load applications dictated_ by chang-
; ng 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 G.M. Sullivan plant and owned by AMLPD, consists
of three units which when operating in tandem produce a net capacity 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 cornmittments
for the Rai lbelt. For the longer term, a unit capacity of 250 MW for new
combined cycle plant~ was considered to be representative a·f 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
( ), was used as the ba~is of cost estimates for this type of plant.
A substantial quantity of natural gas could be available to utilities with
the i mpl ementati on of the A 1 ask an Natura 1 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 current 1 y
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 cycl~ plants. Therefore, the potential in-
stallation of combined cycle plants will most likely be limited to the An-
chorage area. This premise is based on the local electric utilities• most
recent gener·ation expansion programs and readily available Cook Inlet nat-
ural 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 1 arger· in-
stallations, extrapolated to apply to Alaska conditions.
Lower 48 costs for 250 MW combined cycle generating units are given in
Table B .13. These costs were obtai ned from General Electric Corporat.i on in
1980 do 11 ars ( ) . Esti.mates were made for costs of foundations and bui 1 d-
ings, ftfel handling facilities and other mechanical and electrical equip-
ment. An additional cost of 25 percent of the cost of the generating
equipment has been inc 1 uded for transportation of the basi-c unit -to the
Pacific Northwest. 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 (as recommended by
Battelle ( }, the account items wer·e adjusted for a plant located in the
Anchorage ar·ea. 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~ however, consiciering limited navigation
B-13
periods and 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 8.13 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&rvi) costs for large combined cycle plants,o as re-
ported in EPRI, AF-610 ( ) approximate $2. 75/yr/kW for fixed O&M and
$0.30/MWh for variable 0&~1. These were adopted for Alaskan application.
Based on information provided by At4LPO 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 repr,E:ientative of a moaern gas
turbine plant addition to the Railbelt system. The possibility of insta11-
i,ng 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
( ) • The base plant costs were obtained from the Gas Turbine World Hand-
hook ( ), which lists "turnkeyu bids in 1978 dollars for a gas turbine
project in Anchorage. These estimates are quoted in Table Bol4. 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 percem~ 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 r~presentative 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/~1Wh
for the fixed and variabie components. These values reflect intermediate
levels of O&M costs in the FMUS/GVEA Unit Study ( ) •
B-14
,I'
I
I
I
I
I
I
I
II
I
I
I
I
••
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
(d)
Three sources of data were consulted for plann~d 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 8.12.
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 sma11 diesel units. The installed capacity of these diesel
units is 64.9 ~1W ·and these units are solely used for load following. The
high cost of diesel fuel makes new diesel plants exp~nsive investments for
all but emergency use. ·
A unit size of 10 MW was selected to represent an addition of a small
amount of standby capacitj in the Alaskan Railbelt. To develop a capital
cost of these units, three manufacturers' quotes for generating units were
obtained. These were:
-Six 16 cylinder units totalling 10,685 kW at 900 KPM 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 develop-
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 $150,000, giv-
ing a total cost for 12 units of $1,800,000 F.O.B. A $5,000/unit trans-
portation cost was assessed and additional costs for mechanical con-
trols.
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-
tr-ation (14 percent) are added to costs.. An average cost of $7.67 million
1980 dollars (t:;xcl uding AFOC) was adopte~d 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 are quoted in the Williams Brothers Report for GVEA·and
FMUS ( ) are considered typical for srna\11 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
0
Diesel units have a low (1 percent) scheduled Qutage rate. This rate is
based on EEI utility experience. However, the EEI data corresponds to
units in locations where parts and service are for the. most part readily
available. Canadian Electrical Associates data for remote isolated units
with difficult access for parts and service is far worse. A_laska could be
somewhere between these extremes with heavy dependence on unit manufactur-
ers and location giving forced outages ratt.~s of between 4.0 -5.0 percent.
Consequently, 5 percent rate was adopted for the system planni~g study.
Diesel par.'"ameters are summarized in Table 8.12.
8.3 -Environmental Considerations
The investigation of thermal alternatives for inclusion in 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 measureso
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 the park. Class I I 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 Va1dezj may
not be acceptable sites for thermal plants.
Other environmental controls, such as those required for water use, effluer•t
discharge, solid waste disposal, noise control and construction activities, are
important with respect to the present qua·fity of the Alaskan environment. Tnese
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
~he cost of air pollution control equipment is based on satisfaction of the
national NSPS and National Jlmbient Air Quality Standards (NAAQS) ( ), It
is assumed that compliance with NSPS and NAAQS for the. final site selection
for specifi~ 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 ( ) . The State. may
also require measures for control of ice fog ( ).
Three New Source Performance Standards cover the plant types under consid-
eration. The NSPS for Electric Uti1 ity Steam Generating Units is appl ic-
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, tne use of highly efficient combustion technology is
8•16
••
~·
-II
II
~I'
I.
I
I
I
:I
I
I:
,J
I
I'
I
I.
I ,,
I
I'
I
I
I
I
I
I
I
I
I
I
I
I
accepted for control of NOx· Flue gas desulfur_ization is required for
SOz removal, and dry scruboer 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 sulfut by weight in coal. Typical Alaskan coals have s.ulfur con-
tents of around 1. 5 percent by weight.. Dry techno logy is appropriate a 1 so
for reduction of potential ice fog problems. Baghouses are preferred by
EPA for remov~al of particulate in facilities burning low sulfur fuel.
Pollution con1:ro1 for gas turbine units and for combined cycle units bur·n-
tng gas is de!ii gnated by the New Source Performance Standards for gas tur-
bines. Insta1.lation of gas turbine units requires wet control technology
such as water or steam injection for control of NOx emissions. Turbines
using the inje!ction process, however, are exempt_ from meeting the NOx
emissions standards during periods when ice fog is del~med a traffic hazard.
SOz emissions are limited by limitations on fuel sulful content. NSPS
for Stationary Internal_ Combustion Engines which apply .to the proposed die-
sel units require ~Ox 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 ( ).. Most -1reas of the state are designated Class II areas
{ ) in which implementation of NSPS technologies \'lill be sufficient to
satisfy the PSD increment. There are several exceptions to this status
( ).
Mt. McKinley National Park is designated as a Class I ;\r·ea. A plant locat-
ed in the vicinity of the Park would be subject to the restrictions based
on the effects of its er.Jissions on visibility and air quality within the
parko 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 incr~ment 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 was also included in cost esti-
mates. These controls are mandated by nati ona 1 and state 1r1ater discharge
standards~ solid waste disposal standards and occupational health and safe-
ty 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 handl-
i.ng and plant operations and mai"ntenance, and to the treatment faci 1 iti es
required for flue gas desulfurization wastes. However~ cCimpar·ed to the
costs of air pollution control, these costs are of minor significance.
B-17
.. -----..
ASTH
Coal field Rank
Beluga
Water fall Sub Bit C
Yentna #2 Lower Lignite
Kenai Cabin Sub B.it C
Nenana Sub Bit
Poker flat l4 Sub Bit C
Poker flat #6 Mid Sub Bit C
Hoose Seam Sub Bit C
Caribou Seam Sub Bit C
12 Seam Sub Bit C
Jarvis Creek Sub Bit c
Matanuska
Castle Mountain Uv Ab
Premier Uv Bb
Kenai Sub Bit C
Notes:
Sources: Reference ( )
Reference ( )
Approximate
Reserves
million
tons
2400
2000
100
(limited)
300
(1) Proximate and ultimate analysis
_, __________ _
Table 8.1 -ALASKAN RAILBELT COAL OATA1
Heating ,. IV % ,. Value ~ "' Moisture Volatile fixed Ash Btu/lb Ill ~ % ,. Slnlfur "' (range) Matter Carbon (ran!l!!) {ran~) c H N 0 {{JV.ange)
(12-33) (3-25) (7200-((tn.2)
8900)
20.56 36.62 34.68 8.14 8,665 49.9 6.0 0.56 35.2 .tl .. 15
29.80 38.26 28.61 3.3) 7 ,9l!3 45.2 6.8 0.53 44.1 (0 .. 11
23.01 35.63 32.71 8.65 8,028 47.2 6.1 0.62 37.2 ltl.23
(11-27) (3-13) (7500-
9400)
~lll .. 1-0.3)
' 25.29 32.51 32o55 9.85 7,779 45.3 6.3 1~10 37.1 'll.JJ
25.23 35.71 31.40 7.66 8,136 46.1 6.3 0.60 39.2 lO .. 12
21.42 36.62 34.88 7.68 8p953 51.7 6.3 0.81 33.3 ~o .. 1s
21.93 35.88 32.85 9.34 8,567 49.4 6.1 0.69 34.3 ;n~ 13
26.76 33.12 32.25 7.87 7,966 46.4 6.4 0.63 38.5 10.17
20.50 36.20 34.16 9.06 8,746 49.8 5.8 0.86 33.4 , .• o!i
(2-9) · (4-21)o {10,300-
14,000)
\0.2-1.0)
1.78 28o2J 52.20 17.78 12,258 69.3 4.7 1.60 6.3 i(:).46
5.B7 35.73 43.96 14.44 11,101 63.6 5.1 1.60 15.3 \().35
(21-30) {3-22) (6500-\t\ .. 1-0.4)
0500)
Table 8.2 -ALASKAN GAS FIELDS
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 ~ook Inlet
North Fork
Remaining Reserves1
Gas
(billion cubic feet)
29,000
Unknown
Unknown
Unknown
25
.29,025+
Unknown
250
767
20
80
5
1313
North Middle Ground Shoal
Sterling
Unknown
78
None
17
1074
20
125
23
300
120
7
Swanson River
West Foreland
West Fork
TOTAL: 4189+
Notes:
Scource~ Reference ( )
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)
Shllt-in
Shut-in
Shu1t-in
LNG Plant, Anchorage &
Kt:mai Users .
Shut-in
lOCl!tl
Field Abandoned
Graruite 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
I
I
I
I
I
I
I
I
I
I
I
I
I
I
·I
I
II
I
I
I
I
I
I
I
I
I
I
I
I.
I
I
I
I
I
Location/Field
~orth Slope:
Prvdhoe Bay2
Simpson
Ugnu
Umiat
TOTAL
Cook Inlet:
Beaver Creek
Granite Point
McArthur Rivet"
Middle Ground Shoal
Redoubt Shoal
Swanson River
Trading Bay
TOTAL
Notes:
Source: Reference ( )
Table BQ3 -ALASKAN OIL FIELDS
Rsmaining Reserves1
Oil
(million barrels)
8,375
Unknown
Unknown
Unknown
8,375+
21
118
36
None
22
4
198+
Product
Destination
or Field
Status
Pipeline to '!aldez
Shut-in
Shut-in
Shut-in
Refinery
Drift River Terminal
Drift River Terminal
Nikiski Terminal
Field Abandoned
Nikiski Terminal
Nikiski Terminal
( 1) Recoverable reserves est,aimed to ;3how magnitude of field only.
(2) Producing
Table 8.4 -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 lnlet/LNG export
to Nikiski
Average Lower 48
DOE Region 10
DOE U.S. Average
.Qll
Prudhoe Bay/Fairbanks
Utilities:
GVEA oos
Average Lower 48
DOE U .. S. Average
Notes:
(1) Healy Coal : 8,500 Btu/lb
(2) Natural ·Gas: 1,005 Btu/cf
OS
$80/MMSTU 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
.I
I
I
:1
I
I
I
I
I
I·
I
I
I
I
I
I
I
I
I '
. J
--,---~---~~---------
I
I
I Table 8.5 -SUM<tARY OF ALASKAN FUEL OPPORTUNITY VALUES
I
I
I
I
I
I
I
I
I
I
I
I
I
I
Fuel Market
Coal Pacific NW
Lower 48
Japan
Japan
Japan
Japan
Natural Region 10
Gas Region 10
Lower 48
lower 48
Japan
Oil Lower 48
Notes:
( 1) estimated
Market Price Transport Cost
Via $ftt.tBTU $/MHBTU
barge 1.55 o .. so
barge 1.46 0.63
barge N/A N/A
Placer-Amex N/A N/A
barge N/A N/A
8-H-W N/A N/A
LNG-tanker 4.89 2.50
Pipeline spur 4.89 1.97
LNG-tanker 3.58 2 .. 50
Pipeline spur 3.58 1.971
LNG-tanker 4.50-4.65 3.00
Pipeline-
tanker N/A N/A
Alaskan
Opportunity
Value
$/HHBTU
1.05
0.83
1.33
1.33
1.00-1.30
1.00-1.30
2.39
2.92
1.08 "
1.61
1.50-1.65
4.00
Table 8.6 -GENERATING UNITS WITHIN THE RAilBELT .-1980
Railbelt station Unit onu. Installation Heat Rate Installed Hini~rum Maxi ~rum fuel Retirement
• Utility Name # type Year (BTU/kWH) Capacity CBJ?acity Capacity Type Year . {MW) (MW) {MW) .
Anchorage AMlPO 1 GT 1962 15,000 14 2 15 NG 1992
Municipal J\.MlPO 2 GT 1964 15~000 14 2 15 NG 1994
light & Pon'Sl' .AMLPD 3 Gl 1968 14,000 15 2 20 NG 1998
De~artment AMLPO 4 Gl 1972 12,000 2.8.5 2 35 NG 2002
(AHLPD) 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 1.972 23,440 19.6 NA NA NG 2002
3 GT 1978 23,440 24.0 NA NA NG 2008
International 1 Station 1 Gl 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 51 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 14s500 17 .. 65 10 20 Oil 1991
2 GT 1972 14,5GO 17.65 10 20 Oil 1992
3 GT 1975 14,900 2.5 1 3 Oil 1995
4 G1 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
a 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 B.6 (Continued)
0
Railbelt Station Unit onn Installation Heat Rate Installed Minimllll Maximi.Jll Fuel Retirement
Utility Name I Type Year {BTU/kWH} Cal?acity Ca&?acity Ca&?acity Type Year
{MW) (MW) (MW)
Fairbanks Chen a 1 ST 1954 14,"000 5.0 2 5 Coal 1989
Municipal 2 ST 1952 '!4,000 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 199}
5 ST 1970 14,500 20.0 5 20 Coal 2005
6 GT 1976 12,490 23.1 10 29 ·on 2006
FOOS 1 IC 1967 11,000 2a 7 1 3 Oil 1997
2 IC 1968 11,000 2.7 1 3 Oil 1998
3 IC 1968 11,000 2 .. 7 1 J Oil 1998
Homer Elec. Homer=
Association· Kenal 1 IC 1979 15,000 0.9 NA NA Oil 2009
(H£A} Pt. Graham 1 IC 1911 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 lC 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 1 IC 1965 15,000 1.5 NA NA Oil 1995
Electric
System (SES) 2 lC 1965 15,000 1.5 cNA 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
51 = 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.
. . . . . . .
, .. I • . . .. ~
~ ' . . . . . . "'
TABLE 8.7 -EXISTING GENERATING CAPACITY IN THE RAILBELT REGION
o.
Type Units Capacity (HW)
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) 1 140.9
Hydro 2 45.0
TOTAL 53 943.6 MW
I
I
I
I
I
I
I
I
I
I
I
.I
I
I
I
I
I
I
I
I
••
I,
I
I
I
I
I
1:
I
I
I
I
••
I
I
I
I
TABLE 8.8 -1000' MW COAL-FIRED STEAM PLANT COST ESTIMATE -LOWER t~1
Account/Item
.
10 Concrete
20 Civil/Structural/Architsctural
21,22,24 Structural & M~sc •. Iron
& Steel
25 Architectural & Finish
26 Earthwork
28 Site Improveme~ts
30 Steam Generators
41 Turbine. Generators
42 Main Condenser & Auxiliaries
43 Rotating Equipment, Ex. T /G.
44 Heaters &: Exchangers
45 Tanks, D.rums & Vessels
46 Water Treatment/Chemical Feed
47 Coal/Ash/F'GO Equipment
47.1 Coal Unload~ng Equ~pment
47.2 Coal Reclaiming Equipment
47,3 Ash Handling Equipment
47 .. 4 Electrostatic Precipitators
47.6 FGD Removal Equipment
~7.S Stack_(Lining, lights, etc .. )
48
49
50
60
70
Other Mechanical Egui~ment
Incl. Insulat~on & ~agg~ng
Heatin~f Ventilating, Air
tona~ ioninq
Piping
Control & Instrumentation
Electrical ETuipment
(switchgear/ransformers/
MCCs/Flxtures)
80 Electrical Bulk Materials
81 ,82,8j tible Tray & Conduit
84,85,86 Wire &. Cable
Switchyard
CONSTRUCTION COST TOTAL
NOTES:
(1) Source: Reference ( )
. 1976
22.40
23.70
11.90
23.70
14 .. 80
119.70
48.4D
4.20
12.80
3.70
1.50
2.40
3.50
3 .. 40
1.40
61.30
87.90
5.20
9.70
1.70
44.60
11.10
11 .. 30
11.60
13.40
11.30
$566.·60
. -
$ M I L L f h N 5
Handy-Whitman
Adjustment
5/1,7/394
559/397
500/361
500/361
500/361
571/407
413/293
518/361
518/361
518/361
518/361
518/361
461/338
461/338
461/338
461/338
461/338
461/338
518/361
518/361
629/422
461/322
461/332.
173/123
173/123
173/123
1980
31"'10
33.37
16.76
32.82
20 .• 50
167 .. 93
68.22
6.03
18.36
5.31
2.15
3.44
4 • .77
4.63
1.90
83.60
119.Be
7.09
13.92
2 .. 43
66.47
15.41
15.69
16.31
18.85
15.89
$792.82
. ·I
"
TABLE 8.9 -500 MW COAL-FIRED STEAM COST ESTIMATES
rl-f I C C ! ll fLS
ACCOUNT/ITEM ·Cower 4U
10-20 Civil/Structural/Architectural $ 72.66
30-46 Mechanical Equipment 146.57
47 Coal/Ash/FGO 131.52
48-60 Other Mechanical 53.04
70-80 Electrical Equipment 36.05
CONSTRUCTION COST TOTAL: $ 439.84
Contingency ( 16~) 70 .. 37
Subtotal 510.21
Constru~~ion Facilities/
Utilities (10,.) 51.02
Subtotal 561.23
Engineering lr
Administration (1~) 67.35
TOTAL (EXCLUDIN:1 Af'DC) $ -628.57
0
·ngeoJ
Beluga
$ 130.79
263.82
236.73
95.47
64.89
$ 791.70
126.67
918.37
91.84
1010.20
121.23
$1131.43
-
I
. 'I
I
I
'I
,I
I
:I
I
I
I
,I
,I
.I
I
I
I
I
I
I
I
,I
I
I
·~
I
I
I
I
I
I.
I
1:
.I
I
I ·' .,
. . ·::·1.:
TABLE 8.10-250 MW COAL-fiRED STEAM COST ESTI~~TES
$ R 1 l t I o N s {1980)
ACCOUNT/ITEM lower 48 Beluga
10~20 Civil/Structural/Architectural $ 39.2:> $ 70.61
30-46 Mechanical Equipment 79.15 1·42 .• 47
47 Coal/Ash/FGO Tl.52 139.53
48-60 Other Mechanical 28 .. 65 51.57
70-Bil Electrical Equipment 9.46 35.02
CONSTRUCTION COST TOTAL $ 244.01 $ 43ST.20
C~ntingency (16~)
Subtotal 283.05 509 .. 47
Construction Facilities/
Utilities ( 10~)
Subtotal 311.35 560.t•1
Engineering &
Administration (12~)
TOTAL (EXCLUDING AFOC) $ 348.71 $ 627.65
TABLE 8.11 ·-100 HW COAL-FIRED SJEAM COST ESTIMATES
$ R ! l l 1 o N s (198o)
ACCOUNT /ITEM tower 48 Beluga
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
Construetion Facilities/
Utilities { 1~)
Subtotal
Engineering &
Administration (12%)
TOTAL (EXCLUDitG AFDC)
..
$ 21.19 $ 38 •. 14
42.74 76.93
22.08 39.74
15.47 27.85
10.50' 18.90
$ 111.98 $ 201.56
129.89 233.80
257.19
$ 160.03 $ 288.05
I
I
••
••
I
I
I
I
I
~•
I
I
I
I
I~
·jl····. . .
I
I
I
I
I
I
1:
I
I
I
I
I,
I
I
I
I
I
I
I ..
TABLE 8.12-250 MW COMBINED CYCLE PLANT COST ESTIMATES . -~
ACCOUNT/ITEM
20 Civil/Structural/Architectural
21,22,23 Buildings/structures -
26,28 foundations Site Work
40 Mechanical
41=47 Generating Units
45 Fuel Handling
48 Other Mechanical
70/80 Electrical Equipment
100 Transportation: (25~)(41-47 total) Pacific NW
(50"}( 41-47 total) Anchorage
CONSTRUCTION COST TOTAL
Contingency (16~)
Subtotal
Construction Facilities/
Utilities (10~)
Subtotal
Engineering & Administration (12%)
TOTAL (EXCUDIOO AFOC)
$ M 1 L L I 0 N 5 {1980)
Lower 48 Beluga
2.83 4.53
5 .. 63 9.00
37.50 60.00
1.40 2 .. 24
5.28 8.45
11.79 18.86
9.38 18.75
73.81 121.,83
85.61 141.34
94.17 155.47
$105.47 $174.13
Notes:
(1) Including AfDC at 0 percent escalation and 3 percent interest.
--------------------;-
••
I
I
I
I
I
I ,,
I
I
I
I
I
I
I
I
•• ,,
I
TABLE 8.14-GAS TURBINE TURNKEY COST E3TIMATE 1
Installed
Capacity
Notes:
63
75
77
78
{1} Source: Reference (19)
Turnl.:ey
Bids
(.$ mill ion 1978)
13.95
18.10
18.80
14.32
----~.--------:-;----------,-------.-~--.------;--------------. -_--,.------:-.---,-------
l!!L~E 8.15 -GAS 75 MW GAS TURBINE COST ESTIMATE
Item
Turnkey Cost
Constr~ction. Facilities/Utilities {10%)
Engineering and Admioistrat ion (14~}
Cost
($ million 1978) ($million 1980) 1
18.10 20.58
2.06
3.16
--~--------------------------·~-------------------------------------TOTAL (EXCLUDING AFOC) 25.80
Notes: -
( 1) Adjusted by Han·dy-Whitman Cost Indices for Steam Plants (258/227)
I
I
I
I
I
I'
I
~I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I-
I
I
I
I
" APPENDIX C
ALTERNATIVE HYDRO GENERATING SOURCES
. .,
I
I
I
I
I
I
I
I
I
I
I
I
i •.
I
I
I
I
I
I
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. r--~ general application of the five-step methodology
(Figure A.l) for the select)\;)n of non-Susitna plans is presented in Section 6 of
this report. Additional data and explanation of the selection process is pre-
sented in more detai 1 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 yielded candidates which could be refined to include into the
formulation of Railbelt generation plans (step 4).
Detai 1 s of each of the above p 1 anning steps are given below. The objective of
the process is to determine the optimum Railbelt generation plan which incorpor-
ated 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 inc 1 udi ng
the then Federal Power ·commission, the U.S. Army Corps of Engineers (COE), the
United States Bureau of Reclamation (USSR), 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 uf the above studies and in particular the inventories of potential sites
published in the U.S. Army Corps of Engineers National Hydropower Study { } and
the Alaska Power Administration (APAd) 11 Hydroelectric A1ternatives for the
Alaska Rai1belt 11
( ) identified a total of 91 potential sites (Figure C.1).
All of these si tesare technically feasible and, under step 2 of the p 1 anni ng
process, were identified for inclusion in the subsequent screening exercise.
G .2 -. Screening of Candid ate Sites
The screening process for this analysis required the app li cation of four i tera-
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 eco~iomic 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 phaseo:· of
the selection process.
C-1
.'.,_'
(b)
Cost data provided in published COE and .APAd reports were updated to repr-e-
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!\ ne't; of general inflation. Construction costs were developed by
making 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!1 1980 price level based on the "Handy-Wh·itman
Cost Index for Hydropower Production in the Pacific Northwest 11
( ). --
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. Typic a 1 factors considered were construction period, annua 1 invest-
ment carrying charges, and operation and maintenance expenditures. Plant
capacity factors ranged from 50 to 60 percent9 based on source data. A
range of average annual production costs resulted for most of the sites,
simi 1 ar 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.l. 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.
Second Iteration -
The inclusion of environmental criteria into the planning proce~s required
a significant data survey to obtain information on the location of existing
and published sources of environmental data. The 27 reference sources
used 'ltt preparing the evaluation matrix include publications and maps for
which data was 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
I
I
I
I
I
I
I
I
I
I
I
I
,J
.. -_,.;._:;;;....:......::.._..;;,......_ ----
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I·
I
·I
I
I ,,
I
I
• .. • • • ~ b t / t ; . : ; r . . ·.... . ·. . .. : , , v :', : ~ • .,;-.. • • I
. . .. . . . ,_.:-~ . 4:: ... < . • • • . ~ • ' ~ -~4 ~-"l . ,. \~ --.
• • • • • • .. • ~. ~ f '. • ~ • • .. • ..
In addition, representatives of state and federal agencies (including
AEIDC, ADNR, ADF&G, ADEC and Alaska Power Admin·istration) were interviewed
to 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 unacceptnble 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 existingrestrictions to
deNelopment of hydropower in certain classified land areas. Information
rragarding 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 landse 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 designationa Note that no sites coincided with either Wild and Scenic
Rivers or Wilderness Areas, thus these wera not included as exclusion cri-
teria.
At the time of evaluation, the Alaska Lands Bill had not yet been passed by
the U.So 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
Feder a 1 Land Policy and Management Act of 1976.-The Lands Bi 11 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 w~s determined to be so highly sensitive to
hydro development and so important to the State that it a1one 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 account of transmission
line costs to lin!· 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 accept-
able sites. The remaining 28 sites were subjected to a fourth iteration
which en.tailed a more detailed numerical environmental assessment~ rne 18 ·
sites rejected in the third iteration are given in Tab1e C.l.
(d) Fourth Iteration
To facilitate analysis, ~he 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 \-lere incorporated.into the selection 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 that represent existing and potential
land use and management plans.
C-4
I ,.
I
I
I
I
I
I
·I
I
I
I
I
I
II
I 1 :
. '
' I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
••
' I
••
I
I
-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 cr·iteria, it was necessary to
define the signif-icance 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, ~ or D) was assigned to each site for ~ach of the eight criteria to
rel)resent 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 e~
played 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 we 11 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
lar·ge area designated as "moose present" or .. moose distributianu.
Within that large distribution area, smaller areas were identified as
seasona 1 concentration areas or ca 1 ving· areas. These sma 11 er areas
were considered to be more s,ensitive to development than the large
areas because they satisfy specific needs within the 1 ife cycle of the
moose, and because the availability of appropriate land is limited •
Of the references inspected, 11 A.laska's Wildlife Atlas, Vol 1" was
regarded as the most authoritative source, and took precedence in the
case of conflicting information. References 11 Musk Oxen and Caribou"
and 11 Large Mamma 1 s" generally added to the body of knowledge. Refer-
ences "Bear Denning and Goat Range 11
, "Dall Sheep, Deer and Moose Con-
centrations" and 11 Distribution of Caribou Herds in .l\laska 11 were
reviewed!i but had little input which corresponded with the sites
surveyed. ·
c~s
J ' I +( .. '•\ ( ·~ •• ,.r ' ~
. .• ""
.• i
' " . . .
(ii) Argicultural Potential
Agricultural potential was assigned a relatively high importance. This
is because it is an i ndi cat on of the potent i a 1 for the se 1 f suffi-
ciency of any are;a, 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 1 atter was i denti fi ed as
c limati ca 11y margi na 1.
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 11 Cultivatable Soils 11 and "Alaska Resources Inventory,
Agricultural and Range Resources .. were used to identify lands with
agricultural potential in the Rai lbelt.
(iii) Waterfowl, Raptors and Endangered Species
The Rai lbe1t provides extensive habitats for many species of waterfowl
as we 11 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 t.tnd ecologists. As an evaluation cri-
teria, this was considered to b~ slightly less important than the big
game o.r fisheries criteria beca1..1se 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: 11 Alaska's
Wildlife Atlas Vol II" provided information regarding waterfowl and
seabirds, 11 Migratory Birds: Seabirds, Raptors & Endangered Species 11
had information regarding seabirds and rapto~" habitats: and 11 Bi rdsu
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.
( i v) 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 tht.~ development i tse 1 f 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
deve 1opment, the anad\'"Omous fisheries resource was very highly con-
sidered in this evaluation.
C-6
I
I
I .
I
I
I
I
I
I
I
I
I
I
·I
I
I
I
I
I
I
I
I
I
I
I
I
I
a·
' I
I
I
I
I
I
I
I
The comparative sensitivity of the sites was based on the number of
species identified as present or spawning in the vicinityo 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 i denti fi ed as major 1ocati ons for fish
passage (greater than 50,000 annuaiiy.) 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 uAlaska Fisheries Atlas" Volume I,
which indicated on USGS topographi ca 1 maps the presencf.~ of each of
five species of salmon and their spawning areas for all areas of _
interest. Two map overlays were used to determine mort~ generally the
presence of anadromous fisheries: "Fi sheri es 11 and "Mar;i ne Mamma 1 s and
Fi sh 11
• TI1i s information was a 1 so checked against the ChzM-Hi 11
report "Review of South Central Alaska Hydropower Potent1al 11 for some
of the sites.
(v) Wilderness Consideration
National and State interest in the preservation of natUl'·al aesthetic
qualities in Alaska continue to be the impetus for studies and land
use 1 egis 1 ati on. Substant1 a 1 amounts of 1 and have been i denti fi ed and
protected. under State and Feder a 1 1 aw. Howev.gr, other 1 ands 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 Feder a 1 -State Land Use Pl ann·i ng
Conmi ssi on were used: nselected Primitive Areas in Alaska. for Consi d-
eration for Wilderness Designation 11 and 11 Scenic, Natural and Primitive
Values 11
•
(vi) Cultural, Recreatton and Scientific Features
These criteria reflect the importance piaced on the historical, t:u1""
tural and recreational values of certain· landmarks~ as well as the
values of scientific resources at identified locations. AreasQof
varying significance were identified by the reference sources and com-
parative sensiti viti es were assigned accordingly if potentia 1 hydro
sites corresponded with identified areas.
Three map overlays were used" to substantiate these criteria: "Recrea-
tion, Cultural and Scientific Features", "Nationally Significant Cul-
tural Features", and "Proposed Ecological Reserve System for Alaska".
C-7
(vii)
·.
(viii)
(i x)
Restricted Land Use
A significant amount of land in Alaska is classified as national or
state parks~ wildlife areas, monuments, etc. These classifications
·afford vai'ying.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 !'estrictions 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
fJ·om further consideration. Other 1 and classifications were 1 ess
severe. Th i s cri t eri on~ although it may be more of an i ndi cat i on 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: nGenerali zed State Land Activity•, 11 Game Refuges,
Critical Habitat Areas and Sanctuaries 11
, and federal sources, USGS
Alaska Map E and Quadrangle Maps, 11 Administration National Monument
Proclamation and FLDMA Withdrawa1s 11 , uAlaska Illustrated Land Status 11 •
It should be noted that this evaluation was per-formed before. the
passing of the Alaska National Interest Lands Conservation Act {PL
96-487). The results of the application of this criterion were
subsequent 1 y compared against the mandates of this Feder a 1 Act. No
substantial effects on the screening results were found.
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 ~he
sites which were the farthest from exiting infrastructure, indicating
areas with the greatest potential for impacts. Lower sensitivities
were assigned to areas where roads, transmission lines already reach
and settlements 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 ~n
existing small Sl~tt1ement would be more adamantly opposed to devel\Jp-
ment in an area where nobody has presently settled.
Information was garnered from notes in "Review of the Southcentra1
Hydropower Potentia 111 and road maps of the area,
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
I
I
I
I
I
I
I
I
I
I
I
I
I .,.,.
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
' I
I
I
I
protection and careful management due to their. position in the Alaskan
environment, their roles ;·.n the existing p·atterns of life of the state
residents and their impor·tance in the future growth and economic inde-
pendence of the State. These four criteria were vi e\ved 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, re~tricted·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 tlJ 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 ccmsidered less important
in the comparative weighting of critt1ria mainly because of the subjec-
tive nature and lower degree of reliability on the facts collected.
Data re 1 at i ng to each of these criteria was comp 1 i ed separate 1y and
recorded for each site, forming a data-base matrix. Then, based on
this data, a system of sensitivity scaling v~as developed to r·epresent
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.s.
.;
A -Exclusion (used for sites excluded in preliminary screening)
s·-High Sensitivity
C -Moderate Sensitivity
D -Low ~2nsitivity
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 was 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 by which
a relative comparison of sites cou1d 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 fo~;ow
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 c1·iteri a wei ~~t,~ts for the first four criteria were then adjusted
down, depending rn 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 _i150': Rank +
-Height 150' -350 • : Rank ++
-Height ~350': 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 (++) \'las 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 1 and flooded by creation of a teservoi r 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 -lOOsOOO 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 minima) (+).
C-10
I
I
I
I
I
I
·I
I
I
I
I
·I
I
I
I _,
I
I
• -
I
t~
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
a
I
------~~ ,----~~-
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
ad.justed 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) Evaluation
The evaluation of sites took place in the following manner: Sites
were first divided into three groups in terms of their capacity.
Sased on the economics, the best sites were chosen for environmental
evaluation •. Table C.lO lists the number of sites evaluated in each of
the capacity groups. The sites were then evalu=?Lted as described
above. They were listed in ascending order of their total scores for
each of the groups. The partial score was also compareda The sites
were then grouped, as better, acceptable, questionable, or unaccept-
able, based on the scores. The same general standards (e.g, cut off
points} were used for all groups.
(xi i) Analysis
The partial and total scores for each of the sites, grouped according
to capacity~ are given in Table C.lO.
-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 partia1 score was used. Sites scoring higher
were eliminated .. TI1e seven sites scoring lower were re-examined.
Three deve 1 opments at Bruskasna, Brad1 ey Lake, and Snow were the
best :ites identified.
C-11
Of the remaining four, Coffee and Seetna were identified as ques-
tionable because of anticipated salmon fisheries problems. Lowe and
Ca.che scored only s·i ightly better, but Lowe has minimal fisheries
problems, and the Cache site is farthest upstream on the Talkeetna
River, bey'Dnd which the salmon migrate only about five miles.
->100 M\~
Again, the same cutoff point for acceptable sites with total scores
134 and partial scores of 100 used. The sites fell easily into the
two groupings of acceptable and unac~eptable.
f.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 caracity group were to be
chosen, Tabl~ 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 w.any of the other sites which had also passed the economic
screening.
The Chakachamna site had both a very high economi'c ranking and a good
environmental ratjng in terms· of the sensitivity of its natural
resources to development. Chakachamna was also ideneified 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 1 ittle direct effect on the wi 1 derness area. Because the
Chakachamna site is desirable in other r·espects, it is being consid-
ered as a viable alternate competing with the Susitna Project.
Three sites were chosen on· the Ta lke·etna River. Toese 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
. I ,I I
~I
I
\I
I
I
I
I
·I
I
I
I
I
I
I
·I
I
I
.. I
I
I
I
I
I
I
I
I
I
I
I
•
I
I
I
I
I
I
I
is believed 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 camp lete 1 y
separate rivers. The integrated system not only improves the economic
potential of the operating capacity, but also allow~ for better
control over regulation of stream flows as needed by the downs~ream
ecosystems. Secondly, the choice of the TaH:eetna River was made over
other rivers with potential for development of similar systems,
because the environmental sensitivity of the Talkeetnt 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
anadromous fish or big game. And finally, the Talkeetna River
developments· 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 evalu.ation as being the be5t environmentally of the 2.8
economically superior sites.
(e) Plan Formulation and Evaluation
Steps 4 and 5 in the p1 anning 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 environmental
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 gre-ater, and site specific construc-
tion cost' estimates pr•Jpared on the basis of this more detailed information
(Tables C.l2 through_C.l8). For the three remaining sites, construction
costs were developed by a process of judgemental interpolation on the basis
of the estimates-for the se.v:.!n 1 arger deve 1 opments. Costs and parameters
associated with all ten sites are surrmarized in Table C.l9. These c-osts
incorporate a 20 percent allowance ·for contingencies and 10 percent for
engineering and owners administration. Cost of money has again been
assumed to be three percent, net of i nfl at ion.. Energy and power capability
was determined for each of tha sites using a monthly streamflow simulation
program (Appendix F):: The annual average energy for each of the the sit~·~
are also given in Table C.l9. Installed capacities were generally assumed
that would yield a plant factor for the developments of approximately 50
percent. This ensures general· consistency with Susitna developments and·
Railbelt system requirements.
The formulation of the ten sites into development plans resulted in the
identification .,;f five plans incorporating various combinatitins 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 evaluation of alternative generation scenarios for the Railbelt are
discussed in detail in Section a. The criteria on which the preferred plan
was finally selected in these activities was least present worth cost based
on economic parameters established in Section 8.
C-13
The selected potential non-Susitna hydro developments {Table C.l9) 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 mi 11 ion. can be achieved by the ~ntroduc
tion of the Chakachamna, Keetna _and Snow projects (Plan CG2). 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.ll. 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 ~nergy resource
consumption.
,.
C-14
·I
I
I
I
I
I
I
·I
·I
I
I
I
I
I
I
I
I
I
I
---- -··--------
TABLE C.1 -SUMMARY OF RESULTS OF SCREENING PROCESS
t:limmat 1on Elimination El1minatmn Elim±rmttion
Iteration 'Ite.ration Iteration Iterat::iiun
1 1 ," 1 1
Site 'I 2 3 4 Site 1 2 3 4 Site 1 2 J 4 Site '1 ~I )) 4 -
Allison Creek Fox * Lowe * Talachulitna River * Beluga lower .. Gakona * Lower Chulit iua * Talkeetnna R. -Sheep * Beluga Upper .. Gerstle * Lucy * Talkeetna - 2
Big Delta * Granite Gorge * McClure Bay .. lanana 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 * Hooae Horn * Tiekel Ri.ver * Bruskasna Healy .. Nellie Juan River * Tokichitna * Cache Hicks Nellie Juan R. -Upper * Totatlanika * Canyon Creek * Jack River * Ohio * Tustumena * Caribou Creek * Johnson * Power Creek * Vachon Island ..
Carlo * Junction Island .. Power Creek - 1 * Whiskers '* Cathedral Bluffs * Karhshna River * Ratnport * Wood Canyon * Chakachamna Kasilof River * Sanford * Yanert -2 * Chulitna £7F. * 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 * 'Solomon 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.
.,
I
l
TABLE C.2 -SITES ELIMINATED IN SECOND ITERATION
Site
Healy
Carlo
Yanert - 2
Cleave
Tebay lake
P.anagita
Gakona
Sanford
Lake Creek Upper
McKinley River
Teklanika
Crescent Lake
Kasilof River
Million Dollar
Rampart
Vachon Island
Junction Island
Power Creek
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
I
I
I
I
I ,.
I
I
I
I
·I
I
I
f
~
I ~
-
~--------------------~~----
I
I
I
I
I
I
I
I
I
I·
I
I
I
I
I
••
I
.I
TABLE C.3 -EVALUATION CRITER~
Evaluat1on Eriter1a
(1) Big Game
(2) Agricultural Potential
(3) Waterfowl, raptors &
endangered species
( 4) Anadromous fisheries
(5} Wilderness Consideration
(bJ Cultural, recreation
& scientific features
(7) Restricted land use
(8) 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
TABLE C.4 -SENSITIVITY SCALING
Scale Rating
A.. EXCLUSION
Bo HIGH SENSITIVITY
C. lOlERATE SENSITIVITY
D. LOW SENSITIVITY
Definition -·
The significance of one factor is great
enou~~ 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 w&re less important than
those .in "8 15 above.
1) Areas c:f concerns are comron 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 ..
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
---.. -
Evaluation Criteria
Big Game:
Agricultural Potential
- - --, .. -.. -
TABLE C.5 -SENSITIVITY SCALING OF fVALUATION CRIT~RIA
seAL£ -----------r------------------------~---------=
Exclusion High
-seasonal concentration
a~e key range areas
-calving areas
-upland or lowland
soilfl suit able for
Moderate
-big game present
-bear denning area
-marginal farming soils
. . I
·-..
-habitat or distribu-
tion area for bear
-no identified agri-
cultural potential
farming ------------------------------------------------------~~~ .. ---------------·----------------------------------------------------
Waterfowl, Raptors and
Endangered Species
Anadromous fisheries
Wilderness Consideration
Cultural, Recreational and
Scientific F eature,s
-major anadromous fish
cor~idor'for three or
more species
-more than 50,000
salmon passing site
-nesting area.s for:
• Peregrine falcon
• Canada Geese
o Trumputee Swan
-year round hab\tat
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
consideration
-existing or proposed
historic land~ark
-rese~ve proposed for
the Ecological Reserve
System
-high density \'taterfowl
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
-~ad 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
., racreat ional potential
~ historic feature
• historic trail
• archeological site
• ecological reserve
nomination
cultural feat.ure
-medium or low densit't
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
... ..
. . . : • ., ' l • \ ' • ~-· • • •
1 , • • l 1 '" 0 t ,.
' . . I -• . . . . . . I I I . . . . .
. : . . . ) . ' . . . . ...
. I . . .. . I ·,. • .~ :· . . • . • . . /· l
-
• I · I l". . . · . 1
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 Prcclaima-
tions
-- -
High
-Impact to:
.• National Wildlife
Range
State Park
a State game refuge,
range, or wilderness
preservation area
-no existing roads,
railroads or airports
-terrain rough and
access difficult
-increase access to
wilderness area
---
SCA.
Moderate
-Increase:
~ National Forest
• Proposed wild and
scenic river
• National resource
area
• Forest land withdrawn
for mineral entrr
-existing trails
-proposed roads or
-existing airports
-close to existing
roads
low
-In one of the
following:
• State land
Native lancl
~ None of A, B, C
-existing roads or
railroads
-existing power line.$
- -- - ----
--- - ---- -------- -- -
iA!LE t.6 -SIIE EYAiUATIOHS
Allison £reek -Bleck end r~lzzly bear -None lde•\llr&ed -Y .. r round hcbtlN for -Spawning area fn l -Hts~t t.u good ~llty -ltlne ldenll fled -Near ~ad!
prea.ll nerltle •mltda ~ ul801'1 apeetee eeenlc erea NaUonal rcreat
upiora
-r.re~tn. falcon
nut no"" -w.tarfa.l fl!~l
Bradley ldie -Black_ ~d Ctlzzly beer -U to JO puc:ant of -Nrrr,l~ falcon • ~ ldantlfled -Cooci to high qual Uy -Brat lnq area -f!Dna htDntUied c• eGll .. rqlnall autl-neet no areH act~nery
-H preNnt able far fat•lfli -hlp qu!l Uz.. fonata
-Blade tncS Grlinly bear -ttlre then SO .-rcant -low .. u, of "fflllt--Nona ~ fUia -~j;.!nq pot.m lel -Nona ldent I fled
=·.W .. rglnally eutlWbl• r-a ~ -oea· praHnt for faflllng .,
-twlbou wlnlell' ranQe
llrullk8MI -a•ack.end Crlzzly beer -Hone ldenllfted -low denalty of water--None -toed ta hlclt ~lily -Boeltog polenllel -None ldenUrle.lt =::.1101 fowl 8Cti(ICitJ -PtopoiC~ ecologlcel
-preeent · -Nltallng and 110IUng r .. erve ells
-terlboul' •lnhr .-.nqa area
DlskachlliiWla -8llic:k bear habitat ·-t,tJiend epruce. hard--llabrtawl neeUng .rut -T.a ~cleG present -Afee under wllderneee -fll!ellng etell\1 -None ldo!nll flrd
-ilollu pre11ent wod fore.d. .,lU09 area COMtdeetlan,
-liood to hlgh q~Mllt r
~rl -Prl•lt •• and naturaa
feelUHe
Coffee -Bleck end Crbzb bear -Mara then SOl .or upper -Kay waterfowl ht!blht -four apa.:ln preeent, -NOna ldenllilad -E!oat:lnq ar .. -None Identified
~:a ant lende eultlble for t.a .pawning tn area
-OM preeant agrlt:ultursl
-Cood foreilta
Calhe~el Bluff• -Bleck and GrizZly beu -tbre than ~ of lend -tow dlmelty of water~ -Dno ~clee praaenl -Good acenuy -None ldenllfled -lble ldent tried
~aenl .-rglnal for fer•lng , ...
-ee .r,:,eent. -~lind ~ruc:e~ardwood -MlaUng and .,lUng
-bell preaenl foreel area
-HiloH ctn:enlraUan IU'II
HI dee -Black end Gr luly beer -None tdantlflad -War fowl neat tng . ..a -fer ctawn.tn .. or all• -None ldllnUfled -NOna ldentlfled -No rreHnt ceent , .,Uing arae mly ros rlctlonu
-lboUpreaant
-HDoee wintering an
-Black end Gdnl~ beer -2S lo SOl or Uf'lartd -lCRi den5lly w-.terfowl -Saiaan ~~wntng eree. -~fane . .ldentlfled -9aellnq polenllel -,..,...., lchnl Ule!l
pre~t. eol! ault.ble far ana e-.-~p~~Ciee presant
-Hooee, car lbou and fer•lng · -Naat lng end .,lu~
bl..xt F•-* -~lend ..,ruce-herM~ 111'111
roraet
Keelne -llleck end Ctlnlr bear -Hone ldanllfled -finJ ldant.lf led -roor apeolu pre1Jant, -Good la hllr~llly -Hlgh boating polenllal -lble Odentifled
preeent CII1C apectee ••Nil!ng prl•lllvtt.
-C.rlbau winter •rea near all•
-HDaiC fall/wlnlar
concenlrallan ., ••
Kenal llllf(e -&lie~ ~ Grizzly beer -None ldanllfled -~arfawl. naallng end -faur epeclee praeenl, • Hl~ quelllr acenery -Boating potent tel • lllugach Ha't tonal c:•aant -Costal hn!ock-.,ltlng ..... ho ep~~M~lng • Ha ural fee urea rare at
-ll llheep hlibJht allke epruce foraal
-Mlloee rall/o:~nter
c:aru:enlr~(an uee
. I . I ' ' • • • -• • • • • • • • J ·; ·. . . . \ I . " . . . •. . . •
,' . . .. :· . . . •' . . . . ' . '~.
I . ·_ . . . .·· . . . . .· . . ' ~-
.I • , • • ~ ' • . • • . ~-. • •
IMilE C.6 (Continued)
[vaJUi1129 ~ri(erla site lil~rfawle ll;tere, wn•ma• tullural, Ricreillonal, Air leull..r•i Mid.._.. lllablclaa
81, '-POtent! .I £rwtan!llr~ plea fhlherla• C..ick[ellon 81111 Scl.ntUic flaherl .. land die
Kl14inti ~ lUeck and1tfbzlv bear -» to SO percent of -law dantllty ..tarfowl .. ti'O tpiCIH pfUri, -~I(Ulllltr ICtlnery -loallng potent tal -.._ tdlont &red
pca•nl eolia -.anal for era a -..-c••• ...... In ~ el fenatlana
-C.r!bou c•unt fan log -._. lftJ and llllll lng vlclnlly af.altu -Prlaltlve· 1~
•ltNIMfal~r•-· -tli..te ..,,IMl for area -!elected (or wlldlr-
lion Et'llll ,.,. ... t~plirill epnu:lli-Mila can11 h .. ret ion hat...,. f.nel
l--lla::k. &leer pr~ -itere \tiM M ,.rant -loll 4Mn11Ur ..terfi!Wl -r~v· '.,.Cl&a praaanl -None ldentlfled -loa\~ opportunltlaa -.... ldtnl5rtact
-.._. pratlllnl ., the .u. "' ...-r-arC! II a~MI lljllllll\ In • It• ldlntl lad
-l'arlbuu fiteMRl linda auSteble.r~ -'-•Ung 'ilnd .,lUng vlclnlly.
fu•l:y area
-Ball• ~ .:r--
l!!!elw far --
lClllia -lUICk ~d Cduly llnr ... iGne ldentlfled -PetlfJI'IInll falcon -Dna . .,aclaa ~e111nt. .. flood to hlllt quellty -Nlaleth:al feetura -touted t•ar the.· c::ct -C..tal•lll•rn ta.loctc.-Mllllng llrlta el~ra doMnt~r• .. o ICIIf'ollf)' .. , "" PtopoNd eco!otJic:al -·t ltf~.· -· pt'eHnl allka~ruea forea\ •ll• -Atea •lachd fc:~ raaatwCII aile Nltlonal roreat ••!•!:!!!!•• conetderetlan -Lo-r D-.uUtna -•llac!c .u1 Grlzzlr be!lf -tfare then sa ptrc:en\ or -Midi~ denatty wa\arro•l -reta -.c:tM praaflfll, ~ A:aa aelac:ted far -8o•Un<J potential ~ *.:..~ ldent.lUe4
•Mill lhl ~lend aal~~aull• ••• lhrc . w-tng ln •llderneu can• l!ie!fllllon
-~ribaU prellilnl 11bla or-IaNing -Hlatlng ~·~tttng vlei'nl~)'
area
Slhar bb -Black and .(il'luly 'baar ··None ~Uld -Year rOI.Ild bebltat ror -on. apeclaa pr•.tnl, -toed. to hi~ c;uaUtr • !Dating area pclenllal -~ Hlltlonal
preuot -C.•hl wsltarn tt.lodc-narltlc· .. abtrda end .on tiDIIMtre• ~""I r.,..
-'rilE dmelti or •ela altke ~ fAraat Hlllwa -Prlall: ve vel~~~t
Slluanlna -Block andCrlzzlr bear -50 r•reent .r .. rl .. -lOti donelty ..tarrewl -thrn .-elaa pre...t • -Hone ldeollfled -laat ~~ ·arao -lbna ldanUflad
-~-=~Inter ~r•-aul able fOil' f~m~lng at fila .,.._..~In sras -Hlator c:al tralla
• l0t1l...a IIPAU --tfaot.lnJ' ..,.. ••tlnt
Uanaree hardw!~Mf.....t .,. •.
'Snol; -Blr.ck beltr c-l -~ i~lf!cd -NitiUng 'lnd..,tUng _._ -.., .... ldent I fled -f'ropooed ac:alogh:al -loc:alad in Ql~,
-bll ~ ttah era a raHrwa alta National f'oreat
-lb»M wl n cancentra-
ti~ on1
.S:handUna l-'<• -·Hooee;·hl~~•r " iS to 50 1!41f~ Mrgl-.. Hlat log and .., ltlllq! -tmoa pre~ -Good to hl!ll quality -Nbna· Identified -'*-ldllnttrt.d
Mblhl nal rar•~ •ll• ..... oc-r~ -Crlnll bear arceint -Aletne t • -Prl•U WI Iande
........ fill~ -llock and IZrlzdy Mat -Jb1a ldlnUflad -Hone ldanllflad .. ro.,.. ~·~~· prannl. .. Good lo hi~ quallty -ftolltl!l9 potent lal -Dbw Qdli!Uflad
r=' one~····..-* w:t~Mrr
... f11UivJntar cro-alt. 4 Pr~U.blir :iii'G'
Ctlfttrellon area
-C...lboY winter c•wae
tache -8~-c:ic end ~bllr Mar -tbla· '<tlntlrlad -Hone· tdenUriad -fOUl' r.••a or •• ,., -: QJod to high quollly -Boating potential .. 1t1na ldan\1 flm
-~In&.;;~ concan-
preSet 1 ap-lnt are!Aa _,,
''~:Urted -Pr!•lttve land•
hatlon ilrea
-C...lbilu wlntl'lr r•ll:le
fadlna -Black ~ti Grlzdr hear -None ldanllrlad -Midha danellr wal:ar--11'0 apectaa preeen\ -fblll ldenll fl ftl -Baatlngpolantlal -,... lclent lfled
-r:..:a.n;w., r-. -lawhnd !lpruce..ha~ fOMI ... .t alta . .nd uputra ..
roreat -'-Ill lng and .oltlillg
-Car~ wWar l'lllnCIII area -
totdl:hUna -Block &lear p(~~:;.nt -ltlra .thiln :.CrceM. of -.-.en~ danaliy wcter--rour apecle• praaent. -Border prtaitbo area -loallng polent,lal -None ~denllflad
-Ho0111 pro-.\ aalla •• 1• rar fi!Wl erae · three ~claa ~ .In
-1M lboil enault fahll2:!1 Un ._., lendl} -••t!!!g lnil .ollli!!!l araa . site lllclnltt
--·· --- -
•• -------
'~ : .
'. -.
--- --•• - --- - ----
1ABL£C.$ (tGnllnued)
·-" --------------------~AQD~r~l~c~untl~vr~••r-----J.t~------a~~~:1&mt;~------~~~~~~~-~~~~~~~~-~-~cu~kt~u~r78~1i-~ir•Ml~~il.~r~rTie~l~ea~~~~
------------~~~~q~c..==·------~------~~~~~~·~•-------------~--~--~~~~--------~·~~------------~~~~~~--------~Wd.-~Se~l~•~m~l~t~le~.~rt=~~r~I=•~~~L=~~u.==~---------
fual.-era
~per 8111uga
Yentna
-81ec:k bear helbltat -NDna identified
-Dsll aheop hlbltat
-Bleck .wt Crlzdv ben -=.--nt -tar 111oct p~
-..,. Jd.nt.Jflld • -eo .. tel wealern tt.loc:lc-
•ltka ~· fatal\
-50 par~ or ~rlande
aul~lbJe ror farming
-&U•l.-nd epun:a-
paplar foraat
-ftldJ~ dllflalll ~tar
Fowl araa
-MlaUng !Wid aolUnt
ar-ea
-..,.,.. !dtni lfltid
._ low dena~\., waterfowl ••• -JiaiUACJ 1lnd ~lUng
aNa
-zs to 50 percent or -Kltdl"' dana tty ... t•r·
~ll• In lowllllleh are fowl area .
aalhbla ror far~~lng -Hntlng end a:~ltlng
-lloll•l-' epru:e-poplar .na
roraat
-M:sna ldontlrled
-Four ap9elaa praasnt, two apeelaa .,._ In
area
-tble ldlnt.lrllld
-Fba ~111 ,reeant,
l.a epiMR· I~ area
-rtva apecl•• ~ in
area
-ftinll tdetlt I rlld
-~ ldtnUi'lad
-tbla ldant I fled
-Boat lng area
-llcat lag potent tal
-Boating polentlal
-Localld In f(-l
Mitt_. ...... .,. -sn. wllhln •
d11lgnel.M Mat!-t
lflldemen .,. ..
-1tme lderlllfled
-Olugal:h Ntt lon11l
•orhl -
-ftlnct ldent lfi"d
-·None ldantlfled
0 --I
1
I
fABLE C.7 :J§IIE EVALUAJION HAJRlX
WaterFowl,
8lg Agricultural Rapt.or11, lnsdta.oua VUderneaa Cult-. Recte11, Aeatrlct.ed
CMe PohnUal [ndg. Species rlaberles ConelderaUon & ScianUfJ;: l..t U.. Acceaa
CtaSCtJnt l.:ake c D 0 c A 8
c D c c B c 8 c
" Lower Bltluga c c B 0 0
toffee c a c 8 0 D 0
f%Jper Oeluga c 8 8 D D 0
Slrandiln• lake c c D c. 0 0 D
C. c 0 0 c c 0 0
Kasilof Riv!lr c 8 0 c 8 0
lust.-ena c D D D 8 D 8 8
l(enal loNer c 8 c 8 c c 8 D
Kana l lake B D c B c D c 0
c c c c c 0
Grant lake 8 0 c 8 c c D
Snow B 0 c D 0 c c D
lt:Clure S.y D 0 B c 8 0 c c
t\!)Jler Nellie .1.1_8(1 R C 0 0 0 8 c c
AU laon Creek D D 8 c 0 0 0 D
D 0 8 c D D D D
c D B t c D 0
Silver lake D 0 a c c c c
Po~r Creek D 9 c c c
Kl H lnn Dol.lar D A 8 c c c
-----------
lnslailid
Capacity
(tlf)
>!DO
<25
1)..100
ZS-100
<2S
<25
•It .ftft · ~,_nAr
->UiO
<25
<25
25-100
<25
<Z5
<25
<ZS
2)..100
<25
-
lifid
0.. flooded
Halc#lt (ft) (Acree)
RIMnolr <1SO
w'Dlveralon
fle•rvalr <1SO
WOheralon
lbanolr <150
.-.d 0..
0.. end (1St!
Renrvo.lr
~ ~ 150-350
Aear~lr
llaHrl1tllr <150
w/DlvaralllTI
Reaarvolr <ISO
lt/Obnalon
Ranrvole; 150-lSD
llf/Dl'4eralon
Re .. rvolr <1SO
w/Dtveralon
... Md (1Sil
W.8e.r'4Dtr
0.. ll1d >lSO
Rlaervotr
Reaervolr <1$0
w/Oheralon
fteaervoit <1SO
w/Dlver•lon
Re•rvo1r 1~l50
w/Divers1on
fte811t''40lr' (150
WOlverslon
Re&ervolr (150
lC/Olverslon
Reservoir (l~n
';:1/0lverelon
Aeeervolr <150
w/Oheralon
n... and 150-.lSO
Reservoir
Ruervolr • <150
w/Oher.sion
Rieaervolr <1~0
w/Dlverelnn
<l50
-
(5000
<5000
5000 to
100,000
<~
>100,000
<5000
<5000
5000 to
100,000
<5000
<5000
5000 to
100;000
<5000
<5000
<SOOO
<5000
5000 to
100,00f)
<5000
<5000
5000 to mo,ooo
----
-
•
------ -----
iABt.£ t.7 (Continued)
·wa£erlowi,
Big Agrlcullural Raptora1 AnMfroiiOUa Mllderneaa Cult, Recrea, Realrlcled. ·--------ea.e= Potential Endq. Species rishedea Conaldetation A Sclenllflc land Use Acceaa
Ina£ ailed
Capacity
(ttl)
Cleave
Wood Canyon
Tebay l!IJ<e
Uanaglta
Klullna
fazl ine
Calc una
Sanford
Cullcena
Yentna
T:ai&Chultnli
Sk""ltnlna
lake Creek itJper
luke= Creek lower
c
c
c
c
8
0
8
8
8
8
8
c
c
D
D.
D
D
c
D
c
c
D
8
0
B
D
e
lower Otulltna ~ 0
foklchltna C 8 ·
lhla 0 0
D11.1lllna B D
11\laSccn-.s ·c 8
tilO-.l C B
B
c
D
D
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
0
8
8
c
0
c
c
c
c
c
8
8
B.
t
8
8
c
c
c
8
B
D
8
9
8
8
' _.
0
D
D
0
0
D
D
c
0
c
c
c
c
0
D
c
c
8
D
D
c
c
c
8
c
c
c
D
c
c
c
c
c
c
c
c
A
A
A
0
c
A
A
8
D.
D
D
A
D
D
D
D
D
0
D
D
D
D
8
8
D
D
D
c
c
c
D
D
D
0
D
c
c
c
25-100
>tOO
25-100
>100
25-100
25-100
25-100
>100
25-100
25-100
25-100
25-100
>100
.25-100
- --
Caiid -
Da• flooded
~lght Crt) (Acres)
Dati Dlld
Reservoir
1.5R-l59
0. and >JSO
Reaervolr
Reaervoir <150
w/Dlveralon
Reaervoir <150
w/Dlveralon
On and
Reservoir
0... eod
Reat~rvalr
o-. and
Reservolr
150-}50
150-150
Reservoir 150-150
w/Oiveralon
Doll end <150
Resorvotr
Out IWld < 150
Aeaervolr
v-and )]50
Reservoir
Raservolr <1SO
.qoivaralon
0.. and 150-150
tleaervo lr
Dolt end
Reservoir
Dall and
Reservoir
OM and
Reaervolr
na.. end
Reservoir
Dan! end
Reservoir
01111 end
fteeervolr
Dell end
Reservoir
.... and
Reservoir
150-}50
150-l~O
150-l!iD
150-)50
150-)!il)
(150
>J$U
5000. t.o
100,000
.>100,000
<SOOO
<SOOO
·--
sooo t\}
100,000
!iOOO to
100,000
5000 to
fOO,OOO
>too.ooo
~to mo,noo
SOOO lo
100,000
<5000
<5000
<5000
5000 lo
100,000
(5000
<5000
(5000
<5000
<SOOO
<5000
--
-
IABL£ C.7 (Continued)
Keclna
Gcenlta Cotge
ralkeetno-2
Cache
tUcks
Rallpart
Vachon leland
.l.Jnc:llon Island
Kaoliahoa River
tt:Klnley River
leklenllce River
Browne
tmaly
Carlo
Yenert-2
Cersllt~
Johns0f1
Cathedral SluHa
-'-
Big
Caae
8
8
8
0
0
0
c
0
B
c
8
B
B
8
B
0
8
c
B
-
·lfiledo•l,
Agrlcult.urol Raptora, lnlllka.oua \fUde.rnaaa Cult, Recrea, Realdcted
Potentiel Endg. Seeciaa rtd\erlea Can.lderatlon l SclenlJfle t.., Uae Acceaa
D D B D c c
D D 8 c c D c
0 D 8 c c D c
D D 8 c c D c
0 D 8 c D c
D c D 0 D D
8 8 D c c
B c D c D. c
8 c A D D c
B c 8 D c D c
D c 8 c
D 0 D 8 0 A B
c D D D c D D
c D D 8 8 A D
D D D 8 c A D
D D D 8 c A D
D c D D 8 D D
B c B D D 0
8 c c c D c
0 t c D c D 0
c c D D 0 D
-------
!i\ihUed
CofHIClt.Y
(tlf)
25-100
25-100
25-100
2!)-100
25-100
)100
>100
>100
25-100
HOO
25-100
ZS-100
)1(HJ
lirid
0.. rtoodad
lld!i!t (rt) (Acrea)
OM and >l~O
Aaurvotr
a. .. rvolr 150-150
w/Dlveraloo
0.. lind > JSO
ll .. ervolr
.AIIaervolr \50-JSD
w/Olvaralan
0. Wld lS0-)50
Resarvbtr
0..... ·~)50
Alleervolr
OM*"'
Reaervoir
0.. and
9nert~oir
~ ...
Reurvolr
0.. and
P.aaervoir
0.. and
Reeervoir
0.. end
Reservoir
0... Gnd
Reaervolr
0.. and
Reeervoit
.08111 and
Reoenoir
-
>lSO
(J50
150-)~
})50
1SD-1SO
150-.S!i'>O
150-)50
150-lSO
150-)50
(150
150-J5P
-
5000 to
100.000
<SOOO
5000 to
100,000
0000
<SOOO
<SOOO
)100,000
>~00,000
<5000
)000 to
100,000
5000 to too,aoo
SOOD to
100,000
<SDOO
5000 to
100,000
5000 to
Ulll,OOO
·sooo to
1Dil,OOO
<SOOO
SOOO to
100,000
5000 !a
100 000
"
.....
> . .. -••
I
I
I
I TABLE C.8 -CRITERIA WEIGHT ADJUSTMENTS
I Initial
1Sam Height
Ad.;ust!_d We1.ghts
Reserv. Area
Weight + ++ +++ + ++ +++
I Big Game 8 6 7 8
Agricultural
Potential 7 5 6 7
Birds 8 6 7 f I
I Fisheries 10 8 9 10
I TABLE C.9 -SITE CAPACITY GROUPS
I No. of Sites No. of s~tes
Site Graue Evaluated Acceeted
< 25 MW 5 3 -
2>-100 MW 15 4-6 I
I
>100 MW 8 4 -
I
I
I
I
I
TABLE C.10-RANKING RESULTS I
Site Grouo Partial Score Total Score
Sites: < 25 MW I
Str.andline Lake 59 85
Nellie Juan Upper 37 96
Tustumena 37 106
Allison Creek 65 82 I
Silver Lake 65 111
Sites: 25 -100 MW
Hicks 62 79 I
Bruskasna 71 104
Bradley Lake 71 104
Snow 71 106
Cache 86 127 I
Lowe 89 122
Keetna 89 131
Talkeetna -2 98 134
Coffee 101 126
Whiskers 101 134 I
Klutina 101 142
Lower Chulitiua 106 139
Beluga Upper 117 142
Talachultna River 126 159 I
Skwentna 136 169
Sites > 100 MW
Chakachama 65 134
Browne 69 94
Tszlina 89 124 <>
Johnson 96 121
Cathedral Bluffs 101 126 I
Lane 106 139
Kenai Lake 112 ·t47
Tokichitna 117 150 I
I
I
I
I
I
I·
I
I
TABLE C.11 -SHORTLISTED SITES
I
Environmental Caeacity
Rating 0 -25 MW 25 -10ll MW 100 MW I
Good Strandline Lake* Hicks* Browne*
Allison Creek* Snow* Johnson
TustlJilena Cache* I
Silver Lake Bruskasna*
I Acceptable Keetna* Chakachamna*
I Poor Talkeetna-2* Lane
Lower Chulitna Tokichitna
I * 10 selected sites
I
I
I
0
I
I
I
Table C.12 -PRELIMINARY COSI ESTIMATE-SNOW I
Cost/On~€ Alrio~t lotgls
OescriEticn Qt~antiti Unit $ $10 $10
Diversion Tunnel 2,000 LF 3,060.00 6.12
Earth Cofferdams , 132,000 cy 10.25 1 .. 35
Excavation -Overburden 768,000 cy 4.50 3.46
-Spillway
Impervious Fill 638,000 cy 5.00 3.19
Perv iolJ5 Fill 3,028,000 cy 5.00 15.14
Filter Stone 83,000 cy a.oo 0,.,66
C~arse Rock Fill 57,000 cy 8.50 0.49 I Concrete Spillway 1,600 LF 24,900.00 39.80
9 Ft ~ Power Tunnel 10,000 LF 1,978.00 19.78
22 Ft ~ Surge Shaft 200 VLF 7,000.00 1.40
50 MW Underground Powerhouse 1 ea 25.00
Tailrace Tunnel 505 LF 1,978.00 1.00 I
Tailrace Channel 2,000 LF 510.00 1.02
Subtotal 118.41
Land/Damages .98
'I
Reservoir Clearing 4 .. 16
Switch yard 3.00
Transmission 7.20
Roads 4.20 I
Bridges
On-site Roads 5.00
Buildings/Equipment 8.00
Mobilization 7.54 I
Subtotal 158.49
Camp 20.00
Catering 14 .. 40 I
Subtotal 192.89
Engineering, Administration
Contingency 61.72 I
TOTAL 254.61 I
~·
I
I
I
I
I
I
I
I
I
,I
I
I
I
I
I
I
I
I
I
I
I
I
~ ..
to-'~*
Table Ca13 -PRELIMINARY COST ESTIMATE-KEETNA
Cost/Unit
Descrietion Quantit>;: Unit ~$
Diversion Tunnel 2.,000 Lf 9,460.00
Earth Cofferdams 82.4,000 cy 10.2.5
Excavation -Overburden 1,474,000 cy 4.50
Impervious Dam fill 1,850,000 cy 5.00
Pervious Dam fill 8,513,000 cy 5.00
filter Stone 193,000 cy 8o00
Coarse Rock -Rip Rap 148,000 cy 8.50
Spillway Excavation 410,000 cy
130 Ft Concrete Spillway 1,000 Lf 100,500.00
Power Tunnel 2,100 Lf 4,110.00
100 MW Surface Powerhouse 1 ea
Subtotal
Lands/Damage t
Reservoir Clearing
Switchyard
Tranemission
Roads
Bridges
On-site Roads
Buildings/Equipment
Mobilization
Subtotal
Camp
Catering
Subtotal
Engineering, Administration,
Contingency
TOTAL
Airiognt
$10
Totgls
$10
18.92.
8.45
6.63
9.2.5
42.50
1.54
1.26
100.50
8.64 ;o.oo
247.69
1.66
12.18
3.00
3.20
3.60
5.00
5.00
8.00
14.47
303.80
30.00
27.30
361.10
115.55
476.65
I
Table C.14-PRELIMINARY COST ESTIMATE-CACHE I
Cost/Om.£ Airio~nt fotgls
Oescrietion Quantit:l Unit $ $10 $10 I
Diversion Tunnel 2,200 LF 8,390.00 18.45
Earth Cofferdams 301,000 cy 10c25 3 .• 09
Excavation -Overburden 2,946,000 cy 4.50 13.25
-Spillway 490,000 cy I
Impervious Fill 2,750,000 cy 5.00 13.75
Pervious Fill 12,018,000 cy 5.00 60.09
Filtl!r Stone 284,000 cy 8 .. 00 2.27
Coarse Rock Fil~ 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
I
· 50 MW Surface Powerhouse 1 ea 25.00
Subtotal 286.11 I
Lands/Damages 1 • .89
Reservoir Clearing 13.96
Switchvard 3.00
Transmission 8.80 .I
Roads 12.00
Bridges 5.00
On-site Roads 5.00
Buildings/Equipment 8.00 I
Mobilization 17.19
Subtotal 360.95
Camp 33.75 I
Catering 32.40
Sulltotal 427.10
Engineerinth Administration, I
Contingt~c~ 136.67
TOTAL 56).77 'I
I
I
I
I
'I
I
~
I
I Table Co15 -PRELIMINARY COST ESTIMATE -BROWNE
I. Cost/On:tt Ailio~nt Tot~ls
Oescrietion Quantit~ Unit $ $10 $10
I Diversion Tunnel 1,000 Lf 1Z,OOO.CU 12.00
Earth Cofferdams 196,000 cy 10.25 2 .. 00
Excavation -Overburden 7,197,000 cy 4.50 32.39
-Spillway "
I
I
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 2o80
Concrete Spillway 1,100 LF 128,000.00 141 .• 00
23 Ft ~ Power Tunnel 1,000 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
I. Lands/Damages 4.62
Reservoir Clearing 28.21
Switchyard 3 .. 00
I Transmission 2 .. 00
Roads 4.20
Bridges 5.00
On-site Roads 5.00
Buildings/Equipment 8.00
I Mobilization 19.03
Subtotal 399.61
I
Camp 37.50
f.!tering 36.00
Subtotal 473.11
I Engineering, Administration,
Contingency 151.40
TOTAL 624.51
I
I
I a
I
I
I
I
I
I
Table C.16 -PRELIMINARY COST ESTIMATE -TALKEETNA-2 I
Cost/Om.£ Airio~E Totgls
iiescrietion Qusntitl: Unit $ $10 $10 I
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 I
Impervious Fill 2,932,000 cy s.oo 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 I
12.5 ft ~ Power Tunnel 2,400 LF 2,750.00 6.60
50 MW Surface Powerhouse 1 ea 25.00
Subtotal 269.06 I
Lands/Oama.ges 0.48
Reservoir Clearing 3.27
Switch yard 3.00
Transmission 5.60 'I
Roads 7.20
Bridges 5.00
On-site Roads 5.00
Buildings/Equipment 8.00 I
Mobilization 15.33
Subtotal 321.94
Camp 27.50 I
Catering 29.10
Subtotal 378.54
Engineering, Administration, I
Contingency 121.13
TOTAL 499.67 I
0
I
I . Table C.17 -PRELIMINARY COST ESTIMATE-~ICKS
I Cost/Om.t Amount totals
Description Quantity Unit $ $106 $106
Diversion Tunnel 2,400 LF 8,450.00 20.28
Earth Cofferdams .641' 000 cy 10.25 . 6.60
Excavation -Overburden 2,136,000 cy 4.50 9.60
-Spillway 292,000 cy
Impervious f'ill z, 1609000 cy 5 .. 00 10.80.
Pervious Fill a, 71.3,ooo cy 5.00 43.60
I
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 3,342o00 6.35
Surge Shaft
60 MW Surface Powerhouse 1 ea 30.00
Subtotal 273.43
Lands/Damages 1.76
Reservoir Clearing 1.48 I
Switchyard 3.00
Transmission 20.00
. Roads 3.00
Bridges 5.00
On-site Roads 5.00 I
Buildings/Equipment a.oo
Mobilization 16.05
Subtotal 336.72 I
Camp 33.75
Catering 30.30
Subtotal 4oo.n I
,
Engineering, Administration,
Contingency 128.25
TOTAL 529.02 I
I
I
I
I
I
I
I
Table C.18 -PRELIMINARY COST ESTIMATE -CHAKACHAMNA
Description
22.5 Ft Concrete Lined
Power Tunnel
Adit Tunnels
34.75 Ft Tailrace Tunnel
88 ft ~ Surge Shaft
16 Ft ~ Penstocks
480 MW Underground PowerhQuse
Div,,ersion Tunnel
St.btotal
Lands/Damages
Reservoir Clearing
Switchyard
Transmission
Roads
Bridges
On-site Roads
Buildings/Equipment
Mobilization
Subtotal
Camp·
Catering
· Sub~otal
Engineering, Administration,
Contingency
TOTAL
Quantity c
57,000
14,000
1,000
500
3,700
1
2.000
Unit
LF
Lf
Lf
LF
LF
ea
LF
Cost/Unit Amo~t
$ $10
8,050.00 459.00
1,680.00 23.50
3,500.00 3.50
50,000.00 25.00
5,090.00 18.85
262.50
9,580.00 19 .. 15
·-~·-
0.50
3.00
14.00
31.80
10.00
10.00
8.00
44.40
72.50
84.00
348.71
I
I
Tot~Is
$10 •••
I
.._..Tz::ns''r:S ·-~ I
811.50·
I
I
933.20 I
1089.00 I
1438.41 I
I
I
I
,I
.I
I
I
.I
:;;.
I
I
I
I
I
I
I
I
••
••
I
I
I
I
I
I
I
I
I
I
Table C.19 -OPERATING AND ECONOMIC PARAMETERS FOR SELECTED HYDROELECTRIC PLANTS
Max. Average Economic
Gross Installed Annual Plant Capitf-Cost of
Head Capacity Energy Factor Cos~ Energy
No • Site River Ft. (MW) (Gwh) (%) ($10 ) ($/1000 Kwh)
1 Snow Snow 690 50 220 50 255 45
2 Bruskasna Nenana :.. \5 30 140 53 238 113
3 Keetna Talkeetna })0 100 395 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 Chakacha:nna Chakachatna 945 480 1925 46 1438 29
9 Allison Allison Creek 1270 8 33 47 54 125
10 Strandline
Lake Beluga 810 20 85 49 126 115
NOTES:
(1) Including engineering and owner's administrative costs but excluding AFOC.
TABLE C.20 -ALTERNATIVE HYDRO DEVELOPMENT PLANS
Installed
Plan Description Capacity
:c~
A.1 Chakachamna 500
Keetna 120
Ae2 Chakachamna 500
Keetna 120
Snow 50
A.3 Chakacharrria 500
Keetna 120
Snow 50
Strandline 20
Allison Creek 8
..
A.4 Chakachamna 500
Keetna 120
Snow 50
Strandline 20
Al).ison Creek 8
A.5 Chakachamna 500
Keetna 120
Snow 50
Talkeetna -2 50
Cache 50
Strandline 20
Allison Creek 8
On-lin"!
Da\:~
1993
1997
1993
1997
2002
1993
1996
1998
1998
1998
1993
1996
2002
2002
2002
1993
1996
2002
2002
2002
2002
2002
,·1
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
••
--------~----------
TABLE C.21 -RESULTS OF ECONOMIC ANALYSES OF ALTERNATIVE GENERATION SCENARIOS
Installed Capac1ty (HW) by Total System felt~} System
Categor~ in 2010 Installed PJ:esent Worth
Generation Scenario OGP5 Rm Tfiermai R:tCiro Capacity in Cost-
l}:~e Descr:IEtton Load Forecast Id. No. Coal Gas [hl 2010 (MW) ($1Jii6)
All Thermal No Renewals Very low 1 LBT7 500 426 90 144 1160 i4930
No Renewals L'JW L7£1 700 300 40 144 1385 $-920
With Renewals low l2C7 600 657 30 144 1431 :5:9'10
No Renewals ~1edium lt£1 900 801 50 144 1895 af130
With Renewals Medium U£3 900 807 40 144 1891 lif1 ~to
No Renewals High L7f7 2000 1176 50 144 3370 'Ul.'520
With Renewals High l2E9 2000 576 130 144 3306 'lJ:$30
No Renewals Probabilistic LOFJ 1100 1176 100 144 3120 al}20
Thermal Plus No Renewals Plus: Medium L7W1 600 576 70 764 2010 ~
Alternative Chakachamna (500)2-1993
Hydro Keetna (120)-1997
No Renewals Plus: Medium lfl7 700 501 10 814 2025 Q.n40
Chakach~~a (500)-1993
Keetna (120)-1997
Snow (50)-2002
No Renewals Plus: Medium LWP7 500 576 60 847 1983 1G64
Chakachamna (500)-1993
Keetna (120)-1996
Strandline (20),
Allison Creek (B),
Snow. (50)-1998
No Renewals Plus: Medium LXF1 700 426 30 847 2003 1~1
Chakachamna (500)-1993
Keetna (120)-1996
Strandline (20),
Allison Creek (8),
Snow (50)-2002
No Renew&ls Plus: Medium l403 500 576 JO 947 2053 7008
Chakachamna (500)-1993
Keetna (120)-1996
Snow (50), Cache (50),
Allison Creek (B),
T alkeetna-2 (50),
Strsndline (20)-2002
Notes:
(1) Incorporating load management and conservation
(2) Installed capsc.i,ty
154°
y
8 :cc.n
fiP..I --<rn 0-25 or
:OrrJ L Strandline L~ 13. on 2. Lower Beluga 14. rn--t rrn 3. Lower Lake Cr. 1 5 • fT1 O· 4. Allison Cr. 16. ("')
-il> 5. Crescent Lake 2 17. !£ [f 6. Grant Lake 18. om 7. McC1 ure Bay 19. '::0 8. Upper Nellie Juan 20, (I'J z
::j)>. 9, Power Creek 2L
m::l lO. Silver Lake 22. en< 11. ,Solomon Gulch 23~ m lZ. Tus ~umena ~~~
HI t:J.
148°
E1
25 ... 100
Whiskers 26.
Coal 2 7.
Chulitna 28.
Ohio 29.
Lower Ch u 1 i tna 30.
Cache 31.
Greens tone 32.
Talkeetna 2 33.
Gran·} te Go t"9Gt 34 j
Kee tna Jr. ::),
Sheep Creek 36.
s~.wantnt, 37 f
Tn l 6 cfl u 11 Lrttl 3fL
KEY PLAN
">0
--e=•?o•a->'"~~ ,_ ~ .~.:,-~:c=·~-, '
SCALE· MILES
liNCH tOUAI S APPROXIMAT(LY 40 Mit f c;
0
f.1W >100 MW
Snow 39. Lane
Kenai Lower 40. Tokichitna
Gers tl e 41. Yentna
Tanana R. 42. Cathedra 1 B 1 u f fs
Bruskasna 43. Johnson
Kant i shna R. 44. Browne
Upper Be 1 u\Ja 45. Junction Is .
Coffee 46. Vachon Is.
Gulkona R. 4 7 j Tatilna
Klutinu 48. Kenai Lake
Urad 1 P.Y L<:1ke 49. Chil ka ch(111Wlil
Hir.k'll sf I; a
L OW(f
' i
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
le
I
I
I
.-------------~------------------------------------____;_....,;....____. _______________ ~------------:..__.. ·j
. I ...
:; GRAVEL-
BLANKET
GRAVEL SU RF"ACe
£NORMAL MAX. WL(AS INDICATED ON PLAN)
r-CRESl ~ELEVATION (AS INDICATED ON PLAN)
"....... ~-5
ROCKFILL '........, ) l
U/S COFFERDAM
COMPAC'TED PERVIOUS
FILL
lr\1PERVJOUS
CORE COMPACTED PERVIOUS
FlLL
D/ 5 COFFE.RDA.M
ALTERNATIVE HYDRO SITES
TYPICAL DAM SECTION
·a
SCALE.: 0 '200 400-FEET
., ---·~-------.,
FIGURE ·c.2
I
1
I
I
I'
I
I
I
I
I
I
I
I
I
1:
I
I
I
I
I
I
I
I
' ;
ISOQ /'
1300
1200
1100
1000
• . •
,..
~ ..
\
\
~'
\
• !\ \ ·. • • •
...
" \
' . ;
.I .
l ~
0
0
..
. ~--.
' •
j
l
/
0
0
\
.
'
' ,../F~·-·.,-..._~--..""""''JI'?v .... ~ if
",
I
jl
{
8o 0~
•
\
\
" . '
'"
• .. •
·~
• 0 •
/ • • •
l i
ALTERNATIVE HYDRO SITES
SNOW
----------~~~ -\t "oii
i4TAILRACE
UNOE~GRQUNO POWERHOUSE 50 MW CAPA
--__ [ .. ~----
--11.:25 DIA. POWER
,,"3"6
~~
SURGE SHAFT £L. J260D•
TUNNEL
POWER INTAKE
PLAN -OF DEVELOPMENT
SCALE• B
i
l
SCALE:A
I
I~
I
I
I
I
I
I
I
~I
I
I
I
I
I
I
I
~•:
I
NORMA'-MA~.
W L. EC;S>4S'
Po.N;R INTAKE SURFACE. POWE.RI-lOUSE"
100 MW CAPACITY
o l=LtPBUCKE'r
ITA'itwATSR~'EL. Gl5.o'i
.,..._;3r---_.,=:o/S COFFER~DAM
r
\ . ~ i . _________.)
I r' ..... ··. ~ .· .. ·· .•. ·.· .r---. .
\ ~.····t
\ ALTERNJ~T~IVE .. HYDRO SITES
,. KEf~TNA
; ;'t
I
I
I
I
I
I
I
I~
I
I
I
I
I
I
I
I
I
I
"I·
Jeeo
l"'l'Oo
J=-oo .:::"ft~.----:w.:-~~~~R. RESERVOJI'"i -. · "'"' ·· ..... ·.· .. · .. ·· · ~ LEVEL ---------.. ··-···-:·:·.·.·-:-.·.·... . . . . .
.... ·.·.·.·-.·-:·:·-:·.··:·.··~·:·.:·:·~·:·.-;: ... ·.:-·-·-.·.·..:..···-·.--·.·.--.. ·.··
i500
NORMAL MA'/.. WL
EL_ \630
\400 U/S COFFEROAtv\ ·~ -----. . ~=--------...
1400 ......
lSOO ---..____ ___ .-------------------.-.-·-----
\(00
i
·' I • I /~ L"'",.. ..
I
I
SPl LLWA't CONTR.OL
STRUCTURE
TA\LWAfER
EL_l32.0 1
•·.
.. • •
SURFACE POWERHOUSE
50 · MW CAPAC\TY
.. J700
I
I
/I
I,
I
1:
·I
I.
I
I
I
I
I'
I
I
I,
I;
I
I
I
... --.. ------·---~ ........
-·-
1 'N'O'RM.· Al MAY>. WL I EL.'77S' .
'•
~--·POWER iNTAKE
0\VERS\ON
TUNNE:.L
j•'
~r-CREST E.l-995.0
·_SURFACE. .POWERHOUSE:
.IOO.MW CAPAC.lTY
c ~--·------···---
N E:. N A. i-1. P't? R \ \1 E. R
---···L._..,...~·-
. .
~-( ______ ._. .... -.. ..._
. ~ . ....._. ------··-------
FLIP8UC~E.T
-ALTERNATIVE HYDRO SITES
BROWNE
SCALE:
· FIGURE C.6
I
I
I
I
I
I
I·
I
I
I
I
I
I
I
.ll
14
'I
I,
•••
J4oo
"NORMAL MAX .
W. L. E.L. f ~45'
U/5
COFFERDAM / .
\\cl)
1000 -~..........,._------:-----
. '
TUNNE-L
ALTERNATIVE HYDRO SITES
TALKEETNA 2.
cAPACITY
' 1 ...
SCALE. 0 I 0.1 0. '2. MU.~.E..S
.·1~ -----~ ..... --........... _,,
~ .~
FIGURE C~7 iii
I
I
t·
I
I
I
I
I
I
I
I
I
I
I
.·.1. ·_.'.
~. ' J
·1,
~~
••
I
' \J
NORMAL MA>c
· W. L. E.L~ lc:DS;;; 1
0,.--
\~0 \IJPO
\ADO \·sao-·
ujs COFFEROAM
5PJL..LWAY CONTROL
STJ<UCTURE..
ALTERNAT.I:VE HYDRO SITES
! HICKS
-
2too
----2oao
----------------~----
.__1800
-~---------------JSIOO
---------?.CX::C>
i . FIGURE C.e .lilt
' ; ·~.
:-1··_ . . "·
1;--
-1-
I
I
I
I
I
I.
I
I
I
il ..
••
_!_,_.,._,,
~~
f
.[~
'I)·
I
I
I
·coNSTRtJ
ADlT
ALTERNATIVE HYDRO SITES
-CHAKACHAMNA
/ UNDE.R.GROUNO
POWS<.HOUSE. -
450 M)N' CAPAClTY
i
' 0 ! J '2 MU ... ES ~r ~~~~(~95i1· -· -iiiiiiiiiiiiiiiiiiiiiiiiiiiHI r ' .
l
·I
1.·
I
I
I
I
I
I
I·
.I
I
I .,
I
·I)
I· .. -
I
I
I
• [ii 6000
Ulsooo ll . .
z 4000
z_5000
o eooo -~ !000 fi· 0
_j w
1 tAAXIMUM -
-~SER\OiR -
EL.ll48.o·
I
. ./ I
I ~ _.,.-l _.. I
~.
~~ ~ I
1\
L:POwa~ J _ lNTA"KE t
0 ' 3 4
POWER 'TUNI\JEL SECTIO~
SURGE $1--4AFT
L I ;-~ r-. !
------~ ! --/ / --/ ......_ ./ ~ ~.~ ~ / ' """"" -~ ~ .. ...,, ~ I L L_ ! t .. 0 .....
I t ·~
"PONERHOUSE
480 MW CAPACITY
f
TAILWATER EL. lBS
f l 1 ~ Ll ~
-~ ~ . ll l t ~
ILFOWER TUNt4EL f-FENSTOCK-' ' J2"l.O: CIA., '
5 7 8 9 10 II
HORlZONTAL D1STANcE.\N MlL'E.S
"UNLJNED OR. SHOTCRETE
TAlLRACE TlJNNf::L
ALTERNATIVE HYDRO SITES seAL.,; .o 1 2o 4bFEET
CHAKACHAMNA· PROFIL'E AND SECTIONS ;.p _ .. {111· JF--------'-lf
FIGURE C.IO I•l
'1,,
I
••
I.
••
I
I
I
I
I
I
I
'I-
I
IJ .i
I
'I
:1
3
3: .
~2
0
0 -
I
> !:::
(..)
-~
<t
(..)
10
8
:r
~6
0
0
0
>-
(!)
ffi4 z w
2
·'
.,1980 1990
LEGEND
D HYDROELECTRIC
• COAL F1REO THERMAL
l:Z] GAS FIRED THERMAL
2000
OIL FIRED THERMAL(NOT SHOWN ON ENERGY DIAGRAM
'
NOTE : RESULTS OBTAINED FROM
OGPS RUN L FL 7
TOTAl. DISPATCHED
ENERGY.
KEETNA
CHAKACHAMNA
EXISTtNG AND COMMITTED
L954
2010
0~--~--------~------------------------------------~------~ 1980 1990 2000 ...
TIME
GENERAT'ION SCENARIO INCORPORATJNG THERMAL
AND ALTf~R-NATIVE HYDROPOWER' , __ DEVELOPMENTS
-ME·OIUM LOAD FORECAST· FlGURE C.ll
2010
[iJ
-...;.-~
I~
I
<I
I
:I
I;
I
I,
APPENDIX 0 ,,
I ENGINEERING' LAYOUT DESIGN ASSUMPTIONS
I
I
I
I
I)
I
I
I I
;I
;::":'
I·
:I
,1:
I
I
I
I
I
I
I
I
I
I
I
ll
I
I
I
I
APPENDIX 0 -ENGINEERING LAYOUT DESIGN ASSUMPTIONS ·------
The objective of documenting the fo7tlowing design considerations is to faci 1 i-
tate a standarized approach to the r;:ngineering layout work being done as part of
Subtasks 6.02 ·~Investigate Tunnel Alternative", 6.03 .. _Evaluate Klternative
Susitna Developments .. and 6 .• 06 "Staged Development... It is emphasized that for
purposes of these inifial project definition studies, layouts a're essentially
conceptual and the material presented is based on published data, approximately
modified by means of judgement and experience.
D.l -Approach to Project Definit1on Studies
The general approach to the project definition studies involves three steps:
(a) Single Si~e Developments
All sites are treated as single projects.
(b) Multisite Developments
Two or three sites are deve1ooed 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 Developmen~
Development at a site may be staged, i.e. in subsequent stages of develop-
ment, the dan crt~st level. may be incr1~ased 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 essent·ially addresses the step (a} type studies. Careful inter-
pretation of the inf,)rmation is required when applying it to stage (b) and (c)
studies. ·
0.2 ... Electr·ical System Considerations
The ;:urrent total system plant factor is reported tobe of the order of 50 to
55 percent. Study projections (Section 5) ;ind<~icate that this factor may go up
to between 56 and 63 percent in future years.
Initially, all pro,jects should be sized for a 45 to 55 percent plant factor and
should incorporate daily peaking to satisfy this requirement. As a later step 11
som:e of the proposed developments could h~vt! higher or lower plact factors~ if
thfs is justified in economic studies.
0-1
' .!
I .. , • • ~. • • •• I. f •• • • I
All projects should be capable of meeting a seasonallY-varying power demand.
Tijb]e 0 .. 1 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
ru 1 es used in this study are estab 1 i shed 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 ~1onth 1 y or Annua 1 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 ta .the energy produced during the second lowest energy producing
year on record. Thjs corresponds roughly to an anll'lual 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 av~ilable for production
of saleable power~
0.3 -Geotechnical Considerations
(a) Main and Saddle Dams _w=-
Geotechnical considerations inherent for each of the dam sites are
surrrnarized in Table 0.2.
{b) Temporary Cofferdams
It is assumed that all cofferdams are offill-type. Since much of the
ori gi.na 1 river bed material under the main dam she 11 may have to be ex ca.,.
vated, all cofferdams have been located outside the upstream and downstream
1 imits of the main dam in each case.
D-2
:II 'it·
I
I
I
I
••
I
I
,J
I
"• I -.
I
I
I.
(··
'I
I
I
•••• '
I
I ,,
I
••
I
I
11
I
I'
I
I
-1.
I '· ·:·
I
,I
' '
I
,I:
0.4 -Hydrologic and Hydraulic Considerations
Tables 0.3, 0.4, 0.5 and 0.6 list the provisional hydrologic and hydraulic
parameters used ·in initial project definition studies·. Tabla D. 7 details
preliminary freeboard requirements. An example is worked out in Table 0.8 to
calculate freeboard requirements.
(a) General
Figures 0.1 to 0 .. 8 illustrate the storage capacity and reservoir area at
each Susitna Basin dam site for the applicable range of water levels.
(b) Sizing of Hydrau~ic Components
Power Conduits -.For dam schemes the sizes should be ~)ased on the maximum
velocities listed ir~ Table 0.6. For long tunnel schemes the diameter is
determined such that the :ost 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:
Diversion tunnel si.zed for maximum velocity permissible (Table 0 .. 6)
for the design diversion flow. Top of upstrean cofferdam is then
determined by computing head loss through tunnel and adding to
elevation of energy grade line at the outlet portal, plus a 10 feet
freeboard o.11c;;,,·lnce.
--Downstream t.offerdam height is determined fr.om available stage-
discharge relationship with similar freeboard ·allowances.
-Spillway -, Spi 11way size wa<> based on the accorrmodat ion of the project
Design "Flood shown in Table 0.3 and 0.4. Supplementary emergency
spillways are used where necessary. A 11 service spillways have
downstream stilling ba.sins. The capacity 0f each structure is checked
for the PMF f1 ow with a reduction up to 9 feet in freeboard (Tab 1 e D .. 7) •
The energy to l,": dissipated by the spillway structure was set at 45,000
hp per foot width under ·PMF conditions.
0.5 -Engineering Layout ~onsid~ration~~
Table 0.9 lists the components that are incorporated in the engineering layouts
and dettribes the types of compon~nts to be used. Table 0.9· was used as a guide
to design for all layouts.
0.6 -Me.ch-.!\nita1 Equipment
i'ln;~~.
(a) Powerhouse
-Number of Units -
In general~ a decrease in the number of units will result in a reduction
in powerp1~nt ct'st-_ For preliminary studies it has been assumed that
·unit capacities ·range f"~"'{)m 100 to 250 M\". The minimum number of units
assumed is two and the itrax .:WW!t number is four.
-Turbines
The rated net head has been assumed to oe approximately equal to the·
minimllll net head plus 75 percent of the difference between maximum and
minimum net heads. For rated heads above 130 feet, v.ertical Francis type
units with steel spiral cases have been assumed._ Vertical Kaplan units
are used for heads 1 ower than 130 feet. Turbines are directly connected
to vertical synchronous generators in all cases.
(b) .Qyerflow Spillway Gates
The spillway gates have been assumed to be fixed wheel vertical lift gates
o.perated by double drum with rope hoists located in an enclosed towet" and
bridge structure. Maximum gate si.ze for pre1 iminary design has been set at
50 feet width and 60 feet height. In all t:a5e:s a provision of 3 feet
freeboard for gates over ~aximum operating level has been assumed. The
gates are heated for winter operation.
(c) Miscellaneous Mechanical Equipment
Cost estimates provide for a full range of power station equipment
including craness gates, valves, etc.
0.7 .... Electrical Equif?ment
(a)
(b)
Powerhouse
·----~-
Generators are of the vertical synchronous type with separ·ate 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 inc1ucing where ·necessary allowance for remote station
operations.
Switchyard and Tran~mission Line~; --
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 D. 9) ..
0.8 -Environmental Considerations
Previous investigations have shown that a prime environmental consideration is
th~ effect of possible development on fisheries. In order· to avoid a severe
detrimental impact on the fisher·i~s habitat, tentative water level fluctuations
and downstream flow release cons.traints have been developed. These are
guidelines or)ly for the present studies and will be further addressed and
refined as ~ork proeeeds.
0·4
(I
I
' ,·-·1
I
I
I
I
I
I
••
'I
I
I
I
(I i
I
I
J,
I
I I•
I
I
I
I
I
I
I .,
I
I
I
I
I
li
I
I
I
01
(a)
(b)
Flow Constraints
Table D.lO lists preliminary values of minimum flows required downstream of
any development at all times.. The lower flows are based on preliminary
assessment of reqyirement of resideHt fish while the higher flows are
estimated anadromous fish needs ..
Water Level Constraints
Daily reservoir level fluctuations should be kept below 5 feet while
season a 1 drawdown should be 1 imited to between 100 and 150 feet.
D-5
I·
I
I
I
I
I
I
I
••
I
I
I
I
I
I ;
-1
I .• -_.
-'
TABLE D.1 -MONTHLY VARIATIONS OF ENERGY AND PEAK POWER DEMAND
Rontli Ene£gY. 9ar~at~on PeaK Deman6
October o086 .so
November .101 .92
December .109 1.00
January .. 100 .92
February .094 .87
March .086 .7-S
April .076 .70
May .069 .64
June <;067 .62
,July .066 .61
August .070 .64
Saetsmber o076 .70
Notes:
Source Reference ( )
Gene1cal Conditions
Dam Type
U/S Slope
0/S Slope
General foundation Conditions
Required foundation Exca\'ation.
(in addition to overbarden)
Required foundation Treatment and
Grouting
Seismic Considerations
(MCE = Maximum Credible Earthquake)
Powerhouse location
Permafrost
Construction Mab:rrial Availability
Remarks
NOTES:
TABlf_ 0.2 -Gf.OTECHNICAL DESIGN CONSIDERATIONS
Oenal1 ·
Earth-Rock fill
4:1 (H/V)
4:1
All structures would ha\'e soil
foundations. Depth to bedrock
is believed to be 200 1+. Inter-
stratified till and alluvium
foundation material, 1 ocal
liquefaction potential .. 40 1 +
a] luvium in \'alley.
Abutment
Channel
Total Excavation Depth
Core Shell
3ll"' 10'
70 1 50'
Assune core-grout in five rows
of holes to 70 percent of head
up to a mar.imum of 300'.
Probable drain curtain oi' drain
blanket under downstream shell.
Foundation surface -no special
treatment.
High exposure, no known site
faults. MCE = Richter 8.5 ® 40
Underground powerhouse unsuitable.
>100' deep in abutments, probable
lenses under riv~r.
No borrow areas identified.
Assume suitable materials a1·e
available within a fivo-mile -~
radius. Processing of impervious
material will be required.
Based on ~achadoorian, 1959.
Eal'th-Rockfill
4:1
4:1
Assume soil foundations. Depth
to bedrock estimated at 200'.
Compressible, permeable and
liqucf.lab le zones probably
exist.
Unknown.
Denali~
Assume same as for
Assume same as for Denali.
High exposure, no known site fau 1 ts.
MCE = 8.5 ® 40 miles.
Underground powerhouse unsuitable.
Probably >100'.
Assure same as for Dena 1 i.
No report en site. Parameters
based on regional geology.
{1) Actua 1 estimates on Watana and Devil Cal1t·~n have been taken from overburden contour maps.
{2) Data conlJiled prior to January 1·, 1981. i-stimates made after this date have used updated excavation criteria.
'--;-- - -'-·---IIIII
Vee
Earth-Rockfill
2.25:1
2:1
River alluvium 125 1 , dr~iflt or talus on
abutments is 10-40' th.tdk... Saddle dam
located on deep permafr~ alluvium.
Assume: Core -Remove ~+el'age of 50' of
rock
·Shell -Remove t~ 1 0' of ror·k
Assume grouting same as. ~.fur Watana. No
special treatment under 'S:tlell. Assune
extensive sand drains in saddle datil
permafrost area.
High exposure, no known site fa1Jlls.
MCE = 8.5 ® 40 miles.
Unknown. Assume suitab,le for underground
with substantial rock su~PQrt.
>60 1 in saddle area, spQrottdic in abut-
~rents.
Assume available 0.5 to Smile L'adius.
Impervious will require, i;lt'Ocessing.
Based on USSR studies.
----..
-- -
TABLE 0.2 {Continued)
General Conditions
Dafn Type
U/S Slope
0/S Slope.
-
General foundation Conditions
'Required r oundntion Excavation
{in addition to overburden)
Required Foundation Treatoont and
Grouting
Seismic Co~diderations
{MCE = Maximum Credible Earthquake)
Powerhouse Location
Perma1:'rost
Construction Material Availability
Remarks
---
Susitna
Earth-Rockfill
2.25:1
2:1
Unknown but rock probable over
50' in depth. Possible perme-
able compressible and liquefiable
strata.
Assume saroo as for Watana.
Assume grout and drain system full
width of dam, dependent on founda-
tion quality. Drain gallery and
d1·ain holes.
High exposure. MC£:8. 5 Ill 40 miles.
Also near zone of intense
shearing.
Unknown. Asstme suitable for
underground with substantial roc!-<
support.
Probably sporadic and deep.
Assume available within five
miles. Processing similar to that
at Watana.
No repol'ts available. Parameters
based on I'egional geology of the
area.
f)
---
Earth-Rockfill or concrete arch
2.25:1 {fol" earth)
2:1
-
Abutments-assume 15' overburden {OB)
Valley bottom -48-78' alluvium.
Assume 70'. Right bank upstream -
appro}\imat.ely 475' deep relict
charme l on right bank, upstream of
dam site.
Core: Remove top 40 • of .rock.
She 11: Remove top 1 0' of rock.
Extensive grouting to depth = 7~
of head but not to exceed 3001 •
Drain gallery and drain holes.
MCE = Richter 8.5 ~ 40 miles ~r
7.0~10miles. -
Underground favorable, extensive
suppoi"t may be required.
>100' on left abutment. More
prevalent and deeper on north
facing slopes.
Available with 0-5 miles.
PL·ocessing L'equired.
Based on Corps sttJdies and 1980
Acres exploration.
--
High Devil T!"anyon
Earth-Rockfill
2.25:1
2:1
--
Assume 30-60'. overburden am«:~ alluvium.
Core: Remove top 40' of ~t:k.
Shell: Remove top 15' of ~~.
Assure same as for Watan~ ...
Same as for Watana.
Probably favorable for und't~t'gl·ound but
assume support needed.
Spo~adic, possibly 100'+~
' No borrow areas defined, Assume ava H-
able within 5 miles.
No geotechnica 1 data ava:i.. h\b le. P.ara-
neters based on regional g')ology.
----------------·~-------------------------------------~--------------------------------------------~-----------------------------------
TABLE 0.2 (Continued)
General Conditions
Dam Type
U/S Slope
0/5 Slope
General foundation Conditions
Required Foundation Excavation
(in addition to overburden)
Required foundation Treatment and
Gr-outing
Seismic Considerations
(l.f:E = t-1aximum Credible Earthquake)
Powerhouse location
Perm<ifrost
Construction Material Availabi Uty
Remarks
-·-1--;-
-uevii Canyon
Concrete arch or gravity Rockfill
2.25:1
2:1
Assume 35' alluvium in river bottom. Shears and fault zones ·~n both
abutroonts, 35-50' of weathered rock. Saddle dam overburden up to 90'
deep. Assume excavation for spillway totals 90' to sound rock on
vallt~y walls.
Remove 50' of rock. Extensive
dental work and shear zone over-
excavation will be required.
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. Oeep cutoff under saddle
dam, 15' into rock.
Same as for Watana.
Favo(·able for undergcound power-
house, assune moderate support.
None expected, but possibly
sporadic.
Concrete aggregate within 0.5
miles, enbanknent material -
assume with~n 3 miles.
Based on USSR, Carps and 1980
Acres exploration.
Cot·e: · E>-.cavation 40' into rock
Shell: Excavate 15' into rock
Extensive grouting to 1a% of head,
limited to 300 1 • Extensive dental
treatment under core. Deep cutoff
under saddle dam, 15' into rock.
Same as Watana.
favorable for underground power-
house, assure moderate support.
None expected, but possibly
sporadic.
Concrete aggregate within 0.5 miles,
embankment Jl!3teria 1 -assume within
3 miles.
Bs.sed on USBR, Corps and 1980
Acres exploration.
~---.. ·----
Portage Creek
Concrete gtavity
lliknown -assume same t3S f.or Oev i l Canyon
Rock type is similar to t\levi l Canyon, so
assume foundation conditions are
similar.
Asstlme same as Devil Ccu.~~n ..
MCE = Richter B. 5 ® 40 ltJliles or 7. 0
at 10 miles.
Probably favorable for ooderground
powerhouse, assure tnod:>t~ate suppotL
None expected, but may ~ local areas
on north exposures or in overburden.
Unknown -C)l.pect adequate sources 2-5
miles downstream.
No previous 1rwest igatiQflS are available
on this site.
-•• ., -
--- -----
TABLE 0.3·-INITIAL HYDROLOGIC DESIGN CONSIDERATIONS
Susitna Devil Portage Tunnel
Parameter Denali Maclaren Vee III Watana Can~ on Creek Alternative Remark~
Catchment ,2 1,269 2,320 4,140 4,225 5,180 5,760 5,810 5,840 area-sq.m1.:
Mean annual flow-cfs: 3,290 4,360 6,190 6,350 8,140 9,140 9,230 9,230
Spillway design flood-cfs: 89,800 106,000 133,000 137,000 175,000 198,000 200,000 200,000 175,000 1 :10,U«ml')•ear
flood~
witrou.t: :r.outing
Construction diversion
20,0001 2o,ooo1 flood cfs: 42,500 50,000 63,000 64,600 82,600 93,500 94,400 1:50 y,~~'l.' flood peak ·
50 year sediment
accumulation Acre-ft 1: * 290,000 243,000 162J.ooo 165,000 204,000 248,000 252,000 as sume.Si lilO up-
stream, ~velop-
ment
Notes:
(1) Assumes upstream reservoir.
--
TABLl 0.4 -REVISED DESIGN flOOD fLOWS FOR COMBINED DEVELOPMlNT
O£Q£[lJPRE:FJT
Pal"ameters Scheme 1 .., Scheme T"
(Watana & Devil Canyon)
(Hid\ Devil
( Canyon
Spillway design
flood -cfs 115,000 135,000 145,000
Construction diversiQn 89,100 20,000 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 0.3 for Wotana and High Devil Canyor;t first developrrents.
&
Portage
Creek
150,000
20,000
270,000
&
-- ---·----}-
)
Vee )
10.5,001)
71,200
189,000
--
Remarks
1:10,000 year flood routed)
through the reservoir at
as in Table 0 .. 5
fSll
Subseqwnt developaents
enjoy regulation by upstream
reservoir(s).
-' ----
--.. ' ' -' --- -
.. ;.
TABLE 0.5 -SITE SPECIFIC HYDRAULIC DESIGN CONSIOERJ\TIONS
Susitna
Parameter Denali Maclaren Vee III Watana
Reservoir full 2,540 2,395 2,330 2,340 . 2,220/
Supply Level -ft 2,000
Dam Crest Level -ft 2,555 2,405 2,350 2,360 2,225/
2,060
Average Tail Water
Level -ft 2,405 2,320 1r-925 1,810 1,465
Installed Capacity -MW 50 10 230 :no 800/400
Maximum Power Flow -5,400 2,000 8,300 9,000 18,000/
cfs 11,000
Minimum Compensation 600 1,200 1,500 1,500 2,_ooo
Flow -cfs
Lm-4 leve 1 Out 11t
Capacity -cfs 8,900 4,700 8, '300 10,000 20,800
Notes:
(1) Considered only as second developments after u/s dam(s) is built.
(2) Includes 4' high wave wall on top of dam.
(3) Ellf)ties r&servoir to 10 percent ~apacity in 12 months.
High Devil Devil Portage1
Can~on Can~o'l Creek
1,750 1,445 1,020
1, 775 1,465 1,030
(rock fill)
1,459
(concrete)2
1,030 880 850
800 400 150
18,000 10,00~} 15,000
2,000 2,000 2,000
15,600 10,60(} 9,300
--''._
' -
'~·
Tunne 11 Re0arks l'unr'l~ll
Albrnative ~,.!\ ... ! tt1rnati ve Oit:ll~
2,200/ Tunnel alte.;t~ive
1,475 consists of W~t.ana
and re-reg&.tl.a.ltion
dams
2,225/ See above rem~:rks
1,490
1,465/ Watana/Re-re~la-
1,2~0/ t ion _ dam@e'().l
900 Canyon, resp.e~
tively
8,400 In T unn~ l be:·t~oon
rt!-regulatit.Jfi\ ~nd
Oevi! tanyon ~~war
House
1,000 In reach bet~~n
tunnel out fall nt
Devil Canyon
20,800
TABLE 0.6 -GENERAL HYDRAULIC DESIGN CONSIDERATIONS
Waterpassage1
st~el penstocks:
Pm:er tunnels -lined:
TEtitrace -lined:
-unlined:
D:i version t1.11nels -lined:
Notesz
Max~mum
Velocity·
fps
20
15
15
1!1
5fl
(1) For tunnel-alternative schemes (tunnel length greatel'
than 5 miles) optimize velocity with respect to cost
of tunneling and enel'gy loss in frict::.cn.
I
I
••
I
I
I
I
I
I
I
I
I
I
I
I
I
I •. ··, . ' .
i: .· '·\' ...
H •
I
I
I
I
I
I
I
I
I
I
·I
I
I
I
.
TABLE 0.7-PRELIMINARY FREEBOARD REQUIREMENt
Parameter
Design Conditions
-Dry freeboard -ft
Wave run JJP and wind set up -ft
Flood surcharge over full supply level
{FSL) -ft
Allowance for post-construction
set tlerr.ent
Total freeboa~d -ft
Dam crest level -ft
Extreme Conditions for Checking Design
Seismic slump 1
PMF surcharge over FSL allowable
Notes:
Rockf1.ll/
Earthfill
Dam
3
6
5
1% dam height
14'
FSL + 14' +
1% dam heig,t
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 crest level. If seismic
slump >14' dam crest level = FSL + seismic slump + 1 percent allowance for
post-construction settlement. -
·.
TABLE D.B -EXAMPLE CALCULATION OF FREEBOARD REQUIREMENT AT DEVIL CANYON
Parameter
Design Conditions 1
Dry f~eeboard -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
E>ttreme Conditions
Seismic slump (1-1/2%) -ft
Seismic slump < 14 feet
Thus, dam crest level remains the
same as calculated above
PMF condition
Maximum allowble water level
Notes;
~
-nackfl1i
Dam
3
6
5
600
6
0 AM
1445 + 14 + 6 = 1465'
9
1445 + 14 =
1459'
(1) Full supply level -1445 ft; dam height = 61)0 ft
T I{ P £
Concrete"'
Dam
3
6
5
600
nil
1445 + 14
1459'
nil
=
1445 + 14 =
1459'
I
I
I
I
I
I
I'
'
I
I
I
I
I
I
I
I
I
, 1-
I
------------------- -
Components
Dam
Spillway
Power facilities
Intake:
Power Tunnel:
Penstocks:
Powerhouse:
Tailrace Tunnel:
Low Level Outlet Works
Intake gnd Tunnel:
Construction Facilities
U/S & 0/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
Dena:-i
(1
Maclaren Vee Susitna III Watana High Devil Canyon Devil Canyon Tunnel Alter.na~J!.ves
~ Conventional earth/rockfill-----------------------Concrete Earth/rock fill
f-Service: Gated, open chute with downstream stilling basing-------------------------)
f-Emergency: (if required) as above with downstream flip bucket ~-~
., ~Single level--7 f--Multilevel-----------------------------------------------------4'
~ Single concrete-] (---Minimum of two, concrete lined --------"-----------
lined
Two partially l.tned
tunnels (1/3 ~rete
lined, 1/3 shat.-
cretcd, 1/3 ~ltned)
~Steel lining where necessary (near U.G. Powerhouse) (l~ngth = 1/5 turbine head)----------------~
~ Underground if feasible
~~elfu~~nl~ed~~T~lin~~nliood------------------------------~)
(Lined or unlined -based on cGst/energy loss optimization
t-One or two with gates -use diversion tunnel(s) if possible ---------------------~·---4)
t-Earth or rockfill ----------------------------4 Fill or~ f-----Fill-----4
~cellular
t-Minimum of two ---------------~--=------------------------------4
f-To Denal.i Highway --7 ~to Gold Creek ------------·-------------------------4
~fu Cantwell along~ ~to ~ld Creek--------------·-------------~~~4 Denali Highway
~~ads/tunnels and bridges as req~ired-------------------------------~~~4
~ Independent intake with .control valve discharghing through low level outlet works or independlmt conduit-.......---
t--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··----"""·-----------......_ _______ 4 r Size differential surge chambers for all locations where required ---. ---. ---. -----------· .. --·-:-.--4)
(1) Portage Creek development will be similar to Maclaren except that
access roads and transmission lines will be to Gold Creek.
-
---
Site
Denali
Maclaren
Vee
Susitna I!l
Watana
High Devil Canyon
Devil Canyon
Alternative Tunnel
Sch~me
Notes:
TABLE 0 .. 10 -TENTATIVf. fNVIRONMENTAL fLOW CONSTRAINTS
Required Hin.1mum
Flow Release -cfs
Wl.th ProJect W1thout Pro~ct
located located
Downst.ream 1 Downstream 1
300 600
600 1,200
~on 1,500
800 1,500
1,000 2,000
1,000 2,000
1 ,ooo 2,000
1,000
Maximum Allowable
Flow for Daily
Peaking O~erations
CfS Remerl<s
5,000
6,500
9,500
9,500
12,000
13,500
14,000
14,000 In the l'each between
rc-reg. dam and tail-
race outfall at
Devil Canyon
(1) Does not apply if downstream dam backs up to tail water leve 1 of dam above.
(2) Would not necessarily apply if scheme considered did not include a substantial amount of st~asonal
regulation •
• -----.-.., ------t-' ' --;-
I
I ·)o
I
I
I
I
I APPENDIX E
SUSITNA BASIN SCREENING MODEL
I
I ,,
~
I
I
ll
I
I
I
I'
I
I ..
I
I
I
I
I
I
I .,
I l
I
I
I
I
I
I
I
I
I
I
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 Basin deve.lopment plans. The
purpose of this Appendix is to provide the required background information to
establish the validity and reasonableness of the screening model used to deter-
mine these optimum basin developments for the s'election 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 Mod~l
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 given the information available. The net result is a reduction i·n the
amount of analyses and investigations required to produce definitive conclusions
~ as to se 1 ect ion or rejection of deve 1 opment alternatives ..
Development selection is determined through mathematical programming techniques
(optimization). The advantages .Jf this techn·ique are:
-Developments are never fully rejected from the 1 ist 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
eff~cient;
-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 simpli·fying assum~tions.
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;
0
E-1
-Mixed integer prograrrming offers one of the fc.,stest_algorithms for solving
optimization problems;
-Standard software for MIP is avai 1 ab 1 e;
-Mutually exclusive situations can br; modelled through zero-one variables
and logical constraints; -
-Sensitivity analyses are usually part of the program;
-The M!Pmodel 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 soma 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 ar·e 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 mode 1 are the unknowns. Genera 11 y the vari ab 1 es can
be divided into three groups:
I
I
I
,I
I
I
I ,,
~I
I
-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 va\"ious decision
variables.
No physical difference exist between state and decision variables and in
some model cases are reversible .. Each variable can be continuous or dis-
crete (integer). In the model of the Susitna Basin~ state variab1es 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 mode·l. Linear inequalities
can also be replaced by, or supplemented with, equations linking several
_variables. to a 1 imiting condition.
The constraints included in the Susitna Basin mode1 are: reservoir water
balance, maximlln 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 mutua11y exclusive alterna-
tives.
E-2
a
I
I
I
I
I
I
::1
I
I
I
I
I
I
I
I·
I
I
••
I
I
I.
I
I
I ,,
I
{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
suppl.e!nentary upstream flow regulation.
The main criterion (objective function) in seler:ting the Susitna Basin develop-
ment plans is economic (see Figure 8.1).. Environmental consider::tions 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 appl'·oximate dam height and installed capacity at each site. The model
is provided with basic hydrologic data, dam volume-cost curves at all the sites,
and 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
systemat i ca ll,y searches out the 1 east cost system of reservoirs and se 1 ects
i nsta 11 ed capacities to meet the specified power and ener'gy 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 thP. 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 t_hirty years at all dam sites
except Devil Canyon~ Vee, Maclaren and Denali. Streamflow records used are
historical data col, __ ted at the four gaging stations in the Upper Susitna
Basin, which have been extended were necessary to thirty years by corre 1 a-
tion 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.l to
E. 7.
(b) Site 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 lo\'1er 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 as
solely 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 Demand
The model is supplied with a power and energy demand-that is representative
of the future load requirements of the Railbelt 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 demandc The values used are discussed in Sec-
tion E.S.
E.S -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 i~ 1993 and the end of the
planning period in 2010:. approximately 2210, 4210 and 9620 GWh at addi-
tional energy would be required for the low, medium and high energy fore-
casts respective.ly. Consequently 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
I
I
'I
I
I
I
I
II
I
I
I
I
I
I
I
I
I
I
I
I ,,
I
I
I
I
I
I
I
·I
I
I
I
I
I ,,
I~
I
I
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% 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% more costly;
-For energy requirements of between 3500 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/Devi 1 Canyon option by 11% which is within
the accuracy of the model;
-T.te total energy production capability of the Watana/Devil Canyon develT>
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' 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 -COMPUTE-'11 STREAMFLOW AT DEVIl CANYON
OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG
5758-.• 2 240o4·7 1342.5 951.3 735.7 6-'o o r . t 002;2 10"'90.7 18<460,6 21393.4 1ae2o\o 795~;8
3652.0 1231.2 1030 .• 8 905.7 767.5 697.1 1504.6 13218.5 1 9"978. 5 21575.9 18530.0 1979~-.. 1
5221.7 2539.0 1757.5 1483.7 943.2 828.2 878.5 4989.5 30014.2 24861.7 19647.2 134-'t<l '\ 1
7ql7,6 5?:32.6 ~::iS<1~1 -'19~ .~ .. 745.6 7*6.~7 ts:st.a !tf -e a 252i3<h7 ;-910"•9 .19g.o-; *o 1 a 2 ~'76 :; -t ;.:: ·~ .., ... ;.· · .. --~ .. , . ~ . .. . :. ., . fi.J~ t .~
5l09.;.; .. 1921• 3 l~~7~1 1 ?~4 • ., 92'1•7 729~4 ~130,6 16296.0 431a.e.1 19l54·1 24071.6 1151'~,.. 1 . . ~ ::· . .· ~~ •. ~-·
48~0.4 2506~8 lS6a.o t64.9 • .1 1275.2 .1023 t 6 l107.4 8390.1 26081.9 26212.8 24959.6 tJ9a~ .. 2 --.. ' -~-' 22609.8 4647.9 1788.6 1206.6 92t~7 993 • .1 -952t3 067+3 15979.0 31137.1 29212.0 1o496'1f·s
5235.3 2.773 + 8 1986.6 158'3 6 2 1388.9 1105.4 1109.0 12473.6 28415.4 22109.6 19389.2 1802'51~0
7434~5 3590.4 2904.9 1792.0 1212.2 1085.7 1437.4 11849.2 24413.5 21763.1 21219.8 69SS-.S
.. -;.;eo a-~999.tf3 .,1376 t9 ·• t.3.16.. 'l 1179' 1. 977t9 l.ll9•9 13960t9 2153i"J7 ;23390fi ~QS9i¥..; l532.S';o ·. ~<:.~~ f~-·~-
6060.7 .2~2~~7 '2011 ;5 16a6.2 lJ4Q.2 1112~8 1217~$ 14802.9 i4709.a 21739.3 2~066.1 1S9~~~-~
7170.9 2759 .. 9 . ~ . .. \ . 2436·~ ~ ?? 1"'• 0 ...... _ ~' . l-593 .. 6 143f3t9 2405~4 16030.7 27069 + 3. 22680.6 21164·4 122-tS"o
5459tot\ 2544•1 1979.7 1796.0 1~13;4 132(h3 1613.<4 12141·2 11\0679;7 24990.6 22241.9 14?67t2 -6307.7 2696.0 1896.0 1496.0 1387.4 938.4 810.9 17697.6 24094,1 32388.4 22720.5 117J'ij.2
5998.3 2085o4 1387.1 978.0 900.2 663.8 696.5 4046.9 47816.4 21926.0 15585.8 884\)140
5744.0. ~~4.;i tl !leO.~ 925,;& 8.2.~·~ 8&4,9 ~J~:4·4. l22.7v1 24110~;& 4el~ii.7 197i9,~ 1~~1~.~
~4.96~5 1278~7 . .. ' ..
~907.8 1478.4' 1187.4 1187~4 1619,l 8734.0 30446.3 19536.~ 20244.6 10S44~~
t •38~4,0 1"457 & 9 l364i9 1357.9 1268.3 1089.1 1053,.7 14435.5 27796.4. 250S 1. 2 , 30293.t 0 157~~s ~, -· ~--45ac:;.3 1"03.c; 1929 I 7• 1851.2 17'78.7 1179,7 1791.0 14992.4 2~462.1 24271.0 16020.5 8:?25-.S ·-... I
3576.7 1531t8 836.3 686.6 681.8 769.6 1421.3 10429.9 14950.7 15651.2 8483.6 4795._5
2866.5 1145.7 810.0 756.9 708.7 721.8 1046.6 10721.6 17118"9 21142.2 18652.8 844;3. 5
4145.~ .~0~~ d1 ~Q74.S ~l~S.~ 94l-6 . e44.~ ';12,.2 . :3427.~ llOJl,O 22Q4+·'-1~;1;;. 9 t161£.o l 5537.0 29~2.3 ")31':l 6 2036.1 ~{336.4 1659~8 1565.5 19776.9 31929.8 21716.5 1S654.1 118S4,2 l. ,.;.. ... f-t .
4638 f4, 2154·8 1387.9 1139.8 1128.4 955,0 986.7 7896.4 26392t6 17671.~ .19478.1 8726,~()
3491.4 1462~9 997;4 9-i\2;7 745.9 699.5 949.1 1:5004.6 1676647 17'790\0 15257.0 ! r-:1;-e;; t
3506.8 1619.4 1486.5 1408.8 1342.2 1271.9 1456.7 14036.5 30302.6 26188.0 17031.6 15154~t7
7003.3 1853 .. 0 1007.9 896.8 876.2 825.2 1261.2 11305.3 22813.6 18252.6 19297.7 6463.3 iosa.4 aa91w7 g!~7 •. .S 16e57.~ 1~69.? 13q1•0 ;so9.e 11i:L1t9 .:35606¥7 2l;?~e,s lS371.i: 1t916;'1 .I -p ••• -"
15326~g I 6936.3 3210.8 2371.4 1861.9 1525 .• 0 1480.~ 159.7;1 11693.4 1S4t6.a 20079t0 8080t4
4502.3 23~4r3 ~549 .4 !304t1 1.203.6 11640&7 1402.8 13·334 t (). 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 ~UL AUG:
5675.8 2379.2 1328.8 ~40.5 728.3 662.0 792.5 10345.1 18307.0 21209.6 18669.2 79.@~.8
36:24.0 1221:3 102o.9 a.9a.o 760.o 69i~o i4aa.s 13094.0 19862.6 21433•9 18367.1 195~3.~5
• -------..~.-?._ ;;iH~i~!-,7~. ~!!--. .,~@t-_ .·~-'.~"-~!!M.J'!HiJ~>~ jt-. ~t :{f-:. __ ._--.:. --,:'!""'~.· --~~--~~-l..,#,....,..,_ 1.r.,. . ...__ -~ .. -· !~4't1_ ~~-Ff-. ...,. ~...... ~-. ,-..... i,_c;I...,J~_; > .. ~tt-,. --..,..__ -~~~-~111(-!0~ .• M~ -~---...... ---~~..,;zt'-1. ;l.r.._: 'rl, It• .. -. -4~9~. ~Wi. a •.. ,..,, ~!li:-.. ~-. ;il!f-.i'lf-,_ ••. 1.-r-.:;,.,., •.. .,.., .... -:Ale-. "t-1 ..... '+-4 4* __ ._..,.., +~--1r9fJ'-. '*"'" ~~--. ~iit-. .,.., +~. ":"'"". ~* i6-. a=i:E. ~~-. -~·;Q,_,_::j.iJ---
'74J9'~~ ·. _419~:t9.~· ~;s29tl ~tS5.~ ~ 735.Q~. ·-7S9t1 'lf;'ii<ft? ~754~.4 24932~~l t90~8i9 19006.6. !37'3£~/
;:;Q~~.? !89~~7 ~J11tQ ·l~Jla·~4 '1:\.9.,4 12?1l 11.15·' 150o~.1 22a93~5 18991·~ 237a1.9 ~l:l&:Y.~.
---~~~4~/'53.3 . 2470.9 1842;(1r 1·.S28;io\ 12-5-,13 1012·1' 1094.2 82~7.4 2,827.9·-26029'. 4 24946.7 149,,,2
4c.o4.6 1112.1 1193.3 913.4 aa2.2 B39.a B55.4 15738.9 30B22.4 28943.6 2233s.s 1o2l:S~a
51L53.7 2734.3 1964.4 1566.5 .1373.0 109t.s 1096.0 12291.3 28166.1 21938.1 .19224.a 17~'1-b.o
.7:'-l!:S.:*~·-·-~~3e .. ~ ~et:l;$,4 1!6?.~ ·1·1'~~1--·-. JOi'tH~ ~~~~ta. 116~9\-1 ,2;22iit 2i403+P 2lO~t .• 2. 6-~~:8·,.6
4 ~! 4-4 • s · 1 97S • 4 -~ 3 5 Q ; 6 · 12 9 ~ ~ 2 11 ~ o • 9 • · e &~ • J 11 o 1 • 3 13 6 o ~ 11 5 212 a 3 • 1 2 316 o t s 2 a 2 2 5 • .1 ts, t ()~ • 4
s?e9.6 2~90.2 1984.6 1663.5 tJ24.2 11oo., t206.t 14663.4 14592~6 21562tl 21a4a.4 1a1o4.1
----+y~,9 2725.6 2399,9 ~~1?1'.7 ~--·157911? 1614.5 2370.4 16-&4-/J,a -26-1'29.2 226a9.3 910\30•7 12051,2
5394.2 2521.8 1961.4 1781.2 1401.0 1308.9 ~601.0 1207'7.1 40309.6 24867.8 22055.0 14Stl6.S
6 2 4 8 <-3-2 6 S 1 • 2 1 8 8 1 • 2 :L 4 B 1 • 2 1 3 71 • 3 9 52 • 5 8 0 B • 2 1 7 50 7 • 2 23 8 21 • B 3 21 0 1 ; 0 2 2 58 4 • 9 11 a i'-'9 • 6
__ ,_..,5~4.0 ;104·2-,<l .. ?.:i:zl.i 9,s,o s~o.g. •~•A . oa9., 49{)9.9 4·1-42h& 2177'1,"7 l:e4&6.ak· &14-t,,
ei6oS.9 262~.2 1153.6 920.4 B24 .. 4 ao2.2 13o7.9 12163.9 .23sso.4 2596o,e 19599~2 1~0t7A.a
6395.3 1sao.6 t4S6.5 l261.4 1111.3 1'71.3 1~96.9 a6oJ.a .Jooaa.6 19347.1 20019.1 1071s.o
J;z~e.-4 14l;z,, 1;145,.5 ·1iJ?.e 1*4Jit,a 10'J~-J· iOJ7..a -~486a.b 29960.6 1aii&~.o
4540.4 218J.1 1911.8 1832,7 1761.4 1761.4 '1774.0 14811.3 29163.9 24649.7 15936.3 8141.5
3541.6 1517.7 829.7 681.2 675.9 762.9 1408.6 10341.3 14872.3 15587.1 8427.1 47S3.o
28#9,? t~a~,a.. Q(ta,.o. 7~7, ~ 7o(}.a ;z14d~ ao~1 ,a lOaa1.t3 1o9G3,:\: zo9ae,~S46~.2 Si~-6.7
4~67 il ~ ao35. 3 ~2044 .1 ·· l.J01. 2 . 93o. s ass to 912 ~s. 33a2. 6 30759.7 22797. s· 3ooaa. 2 13S2l. 2
. ;5492-. 7 . 2S86 t 5 2264 • 5 2007 ~, 1 1809 tO i636 .s 1ei4.4. 9 t94 75 ~0 31572 t 6 2J .. 566 •0 19563 • 3 1 iStO • 5
---..... 11-14 6&-1:r· -r1 ~. H8-~2-:t-1..rJ-tr-f16'"'rt..,7!Lo...o--=tJ:~3nr~!'s'M,:-fSi-"'""']1~1~-:3¥1~.~2~. -iT-1-:l 1:1-~ E+B T"+ s~-'¥9•4-se"T. ~s:-----,9'+-St-t:Oh-"• ~.. 7 e .-1 o + 1 2 6191 • s 1 :r 4? s • o 1 9 3 6 2 • 1 B& 7 ~n a
3456.9 1454.3 .992.2 838.3 741.5 684.5. 943.0 14836.7 16609.0 17645.7 15119.5-11244·4
3473.6 1607.9 1469.6 1393.5 1323.8 1253.6 1437.2 13848.9 30015.8 25969.1 1~880.4 14989.7
---,--e,e 7 e ~4 ~ 1: ~~ ;rre-e ---99--.. ~"'-7r-,...."*'----ee-a~s~ .. •·'7C, ae-· • ---as-tts· ss-_ . T'• 6-lr __ --:SB+~ *4 ~, 6~. -+t~2 ~1s-~..-~ ~2-+t 1--1: +1 +·t 7/"':".:55.~2~255~89'1-7'. eft_:-+tiifS+t-55.~47'-~ *4--+t 9-'J-9-2~~-55"&". "il-~-*411f1:A:6~s-:-. _:;1,7--~,,
·3~06,4 2354~8 2111~C 1632,9 l442.6 134t~l ~4SStti 11002,2 35269tl 2157~.l 18247.1 1l812i7 1
6645·7 3165.9 2340.3 1844·9 1504.6 1462.a 1Sa2.2 t16S6.a 18126.4 19944.6 15174.5 aoos.2 ~~
--·44-4-4-'l"itS~-:2~2~9~·4..,._~.1-t---.,·--i-5-3-G-.6-129&.9 -1-i-9-1•9 i159;9 1396.1 13.257'+5 2396:1:;3 2726&.3 1691:.3.3 1:6699;0 .
---------
TABLE E. 3 -COMPUTED STREAMFLOW AT WATANA
ocr NOV DEC fEB MAR APR MAY JUN JUL AUG SEP'
3269.8 1202.2 1121.6 1102.2 1031.3 889.5 849.7 12555 .. 5 24711.9 '21987.3 26104~5 1367~.9
4019.0 1934.3 1~04.2 1617.6 1560.~ 1560.4 1576.7 12826.7 25704.0 2iOS2.B 14147.5 7163,6
' .. a1a~gQ · ia54.•9.,._ .. :r§.~.,·r . 9l9+~-·::907"S. 9a4,f! .. :t26i•6. . 9J1,h? 15.9·6;2•1 li~-la.~. 7771•9 4a6u,o
2403~1 10?0~9 .: ·70.9t3 . q3~··2 . ~O~t1 424.~ .· ·9~~·4 95<36.4. 14399~0 l.-e41<h1 l6263t-S 7224't1
··· · ~]6at·o ·2496.~ · t6~7t4 \097-.1.: 777.4 · 7l.7t1. el13t7 2837.2 276t2rS.· ,2.1121.u4 27446.6 ~2taa~1l
4979.1 258~d~. 1957.4 ·-1670.9° 119.1;·4 1366.0 1"505.4 15913·:1: 27~29+3 19020•3 17509;5 10955;7
3773.9 1944.9 L312.6 1136.9 1055.4 1101.2 1317.9 12369.3 22904.8 24911.7 16670.7 9096.7
--
...
.,
'.
1 •
TABLE E. 4-COMPUTED STREAMFLOW ATSUSITNA 3
OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG
~7~t~4>,:9~l~·t:r·-·7,~t~ 9~9tJ ~2<itQ,",~~~.,~ .993~a 925?~41o2_92.-lt79~0.~·o tJistJt t~as:3,.3
.. --~~~4~B. · t~o7~9.·-J.~~o .. 2 ·-?gehq 6es,a · ,~9~h~ ~>~<>··2 ao3a.s ~9Jl1··~ l?i~~.1 1.4t365 .. 3~ .ti7~t~,.
. . 4 4 09 • 6 2 03 1 • c ' : e 7i~ & .. ' 64 3 • s 4 0 ,. .. 6 s 2 4 ' s 1 i 6 3 I 8 1 0 B 9 0 .. 7 1 67 3 9 ' e 14 6 6 8 ' 7 128 3 3 • 3 ?eaa * 7
3801.4 1590.0 1155.3 964.9 832.2 730.1 844.6 10364.3 10983.7 16103.2 15143.3 1175!.6
4340.1 1669.3 1267.0 1121~5 864.9 a&t.a 1294.o 9991.8 16254.2 15206.1 16913.9 &sss.··
;Jias .. 4 ~~~i!-' .. 1~~7.7 ~d.~4dl l9t~.e ·.9::.i,4. .l#.t~~ ~o1oa.6 2~~1a,2. 2iQe4.t4 ~'~~9,9 9&&<:s,,. ~420~9 f!22;ltil· ·t4~4~~ l023~Q fl7S•7 769,f5. ·.724t4 l1~44.6 15435t~ 23249.8 1B4Q7.0 9311~1
_39St.~ '337t6 ~01.4 6~o~o 601·0. ·440f2 · 476t1 2865.4. 35261•7 17274.1 11705,2 SSI¥.1
~259,0 194.&,2 962~§ 7&7,9 e87w:i 71ew6 1!07,4 B983s2 :l6?97,9 18?25.8 1374-4,2 !3145,()
· i~si.ij 'as~t4. 9~7.t 921~B 757,o 6~Q·i s37,3 ao69.4 2'1aa.o 19~28.4 12223.6 ?904,,
3661~3 1217t2 675.6 546,0 S40t7 ·4SSt~ 733.1 S332t7 15k97t~ 15129,9 17015.6 4566.0
20S1.J 121S.t is~., Q:ZS.1 79, •. 2 72~.-h 7~G.& 4~1 24870.7 1e'0~.2 :!:4424.3 862,,?.
4053.2 1783.5 1382.8 1135.9 875.5 915.4 1120.8 10527.7 15540.5 15804.2 10494.9 5688.4
2664.0 1366,9 951.8 BBl.B 829.4 1004,4 1188.5 10899t3 21155.9 21024,3 12958.6 7~57.5
0
--------------·----.•
TABLE E. 5 -COMPUTED STREAMFLOW AT VEE
. ' .
OCT NOV DEC fEB MAR APR MAY "UN JUL AUG
\•. ' -.................. _ .. , . ·.· ~,-_:· •. ;s~-~~~.9~:~-~.n:>·;~sri~::·~;.?~~.:::.}~~~~-~~: ··· ,. §9<?_•-~·_·:~•·-·· __ ~.+t-~-~ _~,~•
· ...• ~?l.·P·t:~r'>>·,··'·9-~·t:\l: ·, 7~9 .• § . q46:.~ ··:·.p~7,9
. ···3sss,o .. : 156ft0 '1077;6 929•0 '672•2
: .4Q~-.,~ .· ~ris-iE; · Q:~27~+·l~Q7Q-~a: ... ·~Ei~7a, •. ;i ,~7~-.s.s..
··. -'·-492•3 .-«1.os~i ·-· 9o6o._2 l&106.6.'i6aJ:.f."a ·1lo-9.o.s ~. : 5 a i ; 1 . . . 6 a 0 I 7 . 2 9 4 0 • 3 i a 7 7 2 i '9 . 1 ~56 9 ~ '8 i 3 S7 -l • 4
. 6~:1'~"':~ ..
12~~4\ .. ()
8 ~:Qii.:a:9 .
4252.1 1971.2 836.8 520.6 390.6 512.3 1134.8 10545.2 15261~4 14336.5 12512.6.
2749.0 10tl8t5 848.3 862.7 594.1 4 a 7 • ·a 6 3 2 • 4 57 71 • s tl34 9 • 9 13 4 o o • 4 14 3 9 3 • 4 s1 $t ,. 2
g2fltl.t~-lg~~t§· *<1*4'? ,._.?S1t7· ... q:?p? •. ~
. ·:~~-Ql. t if';:~ ~~~-:;t·"~ .. •. :?~lt g . 9~3. ~ ·:· 5?4 ·' i.
gt;f.t , .. 46~+7 J?5.StQ 1'i59f3•Q *'1'1S"t? 2t.1fHl•ei l4SS'$--·"'~.,._-
.•• ;l;3~Q. f\.1?t.::r··t~~a.~tt ~042s.:~·.2o~~o~6 1344.7t6 7'l4i~t<t~
. ~5:5. ~· . . ~ 74_. ~ ~~ij3. ~ 20Q9o., v .J ols~ ~ 1. 13a.9~. 2 9~:'1~rt 6
788.4 981.5 6835.5 18275.1 16433.9 149~0.4 43llai
2512.t1;: 1.465t9. 124fl·3 ·.l025't9 858.9 i~i4.5 i~5~~· 1i,1.4 . r~6i~s. 766.1
2455.1 1283.2 69~.8 691.5 569.0
3687.7 1538.0' 1112.2 928 •. 6 806.6
390.5 499.1 3933.0 13033.6 13710.3 16257.6 7741.2
710.Q 825.8 10141.0 10796.2 15819.6 14795.0 11390.4
Al?~Yi .~6l1w4 .. li§§,i '066t6 pap,a
~~st~o 1ijOOtO -t4oo.o 13oo.o ~sooo,Q ·
43~6.0 ·i2og~o t~oo.o tooo~o aso,Q
384Bv0 1300.o B?~.o 644,0 586.0
e22 * 7 t4.3el * * . 99$Q, o j57tQ ~ o 1402Q! o *~7QQ. o 61·ars .• o
?4.0~0-. l~OO~O lQQOOtQ 2S320~~ 2QS90d) l4000.Q 9410'\0
76o.o 7zo*.:o 1134o.o t~ooo.o 2279o.o lS19o.o 9l.S?~o
429tO 46s,o ~eo6.o 346JG.o 11o4o.o tlslo.o s;sa,o
3134.0 1911.0 921.0 760.0 680.0 709.0 1097.0 8818.0 16430.0 18350.0 1~440.0 12910.0
3116.0 1000.0 750.0 700.0 650.0 650.0 875.0 4387.0
.... ;9,; t9 . • ._._ .?QO, o ... ; .· 1~0. o . ~JJo, ~ _
1
. __ ; _ _.,~0o .!_-
0
o __ ._... ;:;oo, o _.
1
.--~~_3a •
0
Q._ 9'ilS2" o ~0~-t,Q 14?<ho· ; .. ~43.~.0 1ga2,0. ~v .:1~09tQ , .,.~..:--~ .. · 9>~48+0
.2 4 ~> ~ • Q · : 1 o q J , o · ~ l a • o · so i:h o 4 e s • o o 4 a • P ~ 9 a t ·<r 1 4 71 • o
i6se+o s.ts.o 543.0 437.0 "l2o.o -t63+0 aa7.o rseo-.o
~1ss.o 153o.o 1o4a.o 731.o soJ.o 47o.o 529.o 191s:o
4058.0 2050.0 1371.0 1068.0 922.0 8~1.0 876.0 9694.0
3!4'4*:3 ,.lpQ9t0 ~Ol:,.t6 05.2+.6 70Q,.2 riGf1 , 79_,,a. .42f31t0 2~aa .•. s··. 1174~0 ·a2J.o 693~~;' ~97~S 524t1 7"14.~5 939lu5
249€t~7-123~.0 · 93o.s 897.3" 727.6 o6o •. ~ ao~t1 77~9.2
14~1~1· 11&5.~ •sa,9 saa.4 5~9 4&~.5 727.5 ~.0:12.2
2017.8 1159.1 928.2 838.9 762.3 697.8 ~~7.7 4207.1
3908.1 1711.7 1333.1 1099.1 842.8 987.0 1096.8 10469.1
.;
~~''·~ l~1~.7 92~~7 i4Q,6 810,6 996.~ ''~'9' 10776,~
18500.0 12220.0 12680.0 6523.0
19~2.Q.o. 16flEHi•Q 19*9~h-O .1oga~~(7
1?~oo.o.174ao;b ~a94o.o S4to.o
l2~3o.o 13~Jo.o 6597.0 3316\D
9909¥~ 13900.0 12320.0 5211;0
21970.0 18130.0 22710.0 9800.0
20000.0 16690.0 15620.0 9423.0
'9677•i i4~~~,o 16604·~ ~o,s.a
l~502,1 12970.6 10642.4 7171·6
20724t2 1887S.2 ll981•7 · ~642•5.
1~JJ9.4 1-497==t~i 14900.8 4470.5
24330.5 16351.0 14225.7 8462.2
15395.8 15589.1 10251.8 5568,0
2101o.a ~0700,J 12,49,J '3~0.9
TABLE E. 6 -COMPUTED STREAMFLOW AT MACLAREN
"•--·---.. --... ~--... -·--------------------------------~--------------~,~---·-t
OCT NOV DEC ~AN FEB HAR APR MAY JUN JUL AUG SEP
1851.5 "r30.0 557.2 340.3 308.0 229.9 296.0 3345.8 85'15.6 11824.2 9947.8 3%3;2.9
t-1579-.-9--·-52-9. 7 40&-.-8 ~48-,-9 2-7-9-r-7 2~ 2 §b6-r3-5-4~0-.9 1-0·6(}5-.-6-1-2·6-3·1-,-5-9898-,-4-B·tii'«l-,-3~-. --~
( 2043.6 845.0 58.3.8 544.9 436.3 384t7 441.3 2224.2 12442.8 13272.1 10301.1 5241.9
i 2392.9 1158,0 490.4 326.4 240.8 288.2 705,]' 7047.4 11176.5 11216.7 9206.1 454f7.9
. -----.1778 •. J ·----620 •. a 4 BJ:-.-7--53-2-.-7--363-,-1-30"7-.-0--368-.·5-36·1·6 .-3-B·9:r5 .·5-1 0546-.-4-1·0528-.-9~a.J;l,S·,·<>__.._ __
14 oa • 2 a1 a • 3 s 6 2 • 2 s 3 2 • a 3 7 o • 2 3 7 9 • 6 3 90 • 1 2 753 • 9 13 o J a • 6 13 3 a1 • 9 15 813 •. a a 2:~5 • s
1 9 61 • 5 7 0 9 • 6 4 54 • 1 416 • 2 2 B 5 • 3 2 6 3 • 4 2 8 9 , 2 6 3 7 2 • 9 18 316 • 8 1 6 7 50 • 4 1 :~54 4 • 8 6 S&:O • 6
----1932. 0---1040......5 783-..2-576-.-9 484-.-6-3~-9--. ~ 4·3-6..-9 4-7-08-t.:§-1-'5-59-0-.-9-,1-3406-,-0-1-1-540-.-4-64)~.2-. .. 9·------
2 32 7 t 0 11 4 4 ~ 3 6 7 5 t 6 53 9 • 7 411 • 7 4 0 6 i ? 54.1 t {) :~59 6 • 5 12 61 7 • 6 12 2 7 4 t 8 1 0 132 t 9 2922 i 4 '
1589.4 773.2 394.3 364.6 290.4 191.3 238.7 2704.8 10668,2 11497.9 11475.1 4747~3 1
--,2482.5 --1093 t 8--805···5--65-1-.-9___;52·9-.3 46-2-r0-505.-.~6-6262 .-8·-76-21-.·9-1-1·947-.-9-10863 +:; ·-i'63:7·.-0 -1 l
2817.8 1069.4 794.1 646.6 510"0 513.4 768.1 5845.7 10400.8 10970.3 11305.8 44:23.9~·-
2144.1 1160.5 851.8 717.6 566.0 528.9 674.7 5544.5 17338.0 14797.4 12262.2 6120,5 .
~--24 72 t 0·--1·235-,..()-7-~7-.-6---;-5-74.-rS-4·96-.-0 440·t·2 4~8-.-8.-6·7.g-2-.-:-3-1·0~·96-t-7'-:1.·5Y-7-r.-4-1-3633·,-4-6·19~~ ... l . i. 2179.0 723.3 481.9 356,2 331.3 246.9 273.7 1723.4 21497.0 11636.6 8679.0 3'1919 •. 5 l
2182.7 1220.7 554~4 451.7 405.9' 422t9 653.3 5189,9 9701.9 11729.8 9057.0 9509.7
L--··-1 8~2 .-1-·---hOO •. J ·4 58-.-8 4 20-.-2-393·.-1 3CF3·.-1--535-.-J-2.81-2-.--2-1··t84-7 ,.:.9--997-4 .-3-9112~.·4-··4a2S~·6---
1891.8 637.5 504.2 485.6 411.5 430.0 362.0 6395.0 13647.0 13610.8 13784.5 6091.5
2256&2 926.3 771~4 674.9 694.7 708.5 648.9 4428.6 12364.3 14259.6 10303.3 3572.5
--1-431 . .-9--6211-.-6 3-63.....3-.----30.0~.-7 288...-Q ~~-~-· -ei5B..-9' 4-2-1.4-.-6-9-9-4.0..-9-. 1-1-1-BB..-:9-5067-•-9-2-711 ... -9.------.-
1274.8 635.7 42dt5-338.8 308.9 ;308~8 S62t7 451.3.7 7~13.,4 10790.3 883·4.6 3346.7
J226b0 881.9 607.2 410.7 287.2 270t1 304.0 1180.7 14049~7 13721.9 15681.0 6081.6
2334.2--1152 .. 4 B05-.-1-6ts1-.-7---57o-.-e--541...-3--·-53.o .. o.--6.t3.9-•:0-1~2326-.-9-13t~2,7···0-1-1648-··1-· 5o2S .• -7------
19B7.2 907.7 . 555~7 467.4 431.8 404.9 428.1 3289.5 11719,7 ld915.7 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 ,
!a~l-48; 1--91~~..-1-ol·o·ri 556-.-.2 42·6~-9-7-.-7 460~.~Q-426-9...:.-4~1-2-9-:10··-5-:t.-S0..1-3-... 6-9305·.·6---617S···-~~'------------
2377~3 722.6 379.2 290.6 280,1 252t4 -382.3 3189.5 9971.8 11309.9 13006.1 295S.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
2J3a. 1· ... ·-1·10o .-6-B-22-.-·6-·-o·'J0-.--2-532-.-9 · 52·1--.·0-6~-o-.-'7-5650-.-9---9602. 5--1-l822·t·1--~9333-.-7--:445o···S---------..
1597.1 830.1 573.6 519.4 478.5 543.3 648.0 6216.9 13381.,5 14301t2 10667.2 5717.0
---.. ·--· • , . -·119 :. ---~---~--..
•.
-.••. ,..... . -•. -' .•'-. . . 11!11'• --••
TABLE E. 7 -COMPUTED STREAMFLOW AT DENALI
OCT NOV DEC JAN FEB HAR APR MAY ,JUN JUL AUG
1493.5 618.9 398.2 2.1.9.4 220.1 149.6 218.8 2531.9 6232./ 10078;0 8015.0 247'S*t8
--899.-0--3-1-0-.2 2-50-.-9 1-7-3.-.-1 1-4-1-•9 1-51.-,-8 3·6"3+-7--5·4-5-6-r3-7·j;89T2-1-055-2-i-8--B506T8-58rS . ..-0---
1216•4 488.0 338.6 359.1 309.3 282.9 298.1 2065.4 9767.3 1-1392.7 8965.7 375&.5
1600.3 780.5 362.2 269.1 193.9 166.9 ~ 456,8 5754.4 9952.4 9773.~ 7960.8 349.~4
-~----14 as .-a --4-4-E-.-a 309-.-4 351.-.-t:, 2-5·1-~-6--2·ts-.-9----2·6-z-.-s-a-7·5!J...-7-75o9~.-7--94 67-.-0--94·1·6-.-6 ---31 s~.-a---·
1247.9 680.9 371.8 341.6 248.0 237.1 264.7 2669.5 9680.5 9760.9 12473.6 523~.0
1297.5 396.4. 305.7 296.6' 172.0 212.7 224.6 6666.0 18527.2 15779.2 15313.5 729G-9
--2000 •. g.--9~2-.-3 5-7-3-.-3-34-2-.-6 30-1-r4 2·2-1-. 9 :~38-r7-45-J-7-.-1-1-c3750-.-6-·1-22-5·0-.-0-l0785-.-2-558t~: ... 9-· --
1963.6 931.1 605.1 .371!-8 233.7 175t0 ;.:!94.4 2090.9 9503-..0 101·36.3 7701.8 2~~'7'4 .• 6
1299.5 522.6 295.5 . 234,7 193.9 131 •. 9 '"157.9 3626.7 10464 .. 8 9754.3.10165.1 39QI~~4
--·20 16. a--960·· 7 7-4·1-.-4--584-• ..!.2---4-1-9-.-7--34 9-.-4 331'-.-6--421.-1-.-a-~59 61-.~J--1 o 13 4·.·5·-· 9255·. 6 ·--62t~ l"'J----.
2331.2 B72.0 710.3 543.0 412.6 432.l 631.0 4132.8 8514.2 9569.8 "8079.2 3711.7
1693.2 817.7 547.1 371.8 316~5 290.4 35665 2593.3. 11374.3 10978.9 10609.2 4640~4
--1 4 4 s. r··--6 o1-.-a-4 o-1-,.-a 3 ·1-t-.-a--. 3·2·9-.-:s--2·3 6-.-7 2.!26-6·8---:4·41.f.9-.-o-a 4 4 6·.-o--1-2 2;; 6-.-3-1·-t o 4 a-.-4-4 4 2s .• ~3---
t323.o 435.4 ·279.4 201.s 198.1 153.5 172~s 1139.7 14070.3 B4B1.2 7306~3 321&.5
1951.0 837.9 323.4 250.6 227.5 237t2 360.2 3102.3.6068.4 8~!08.0 6939.0 794~~3
---·-1545 ·-' ··---468. <>-·--37-4. 8---3·1-·7-.-1 299. 5~--2-9·9-.-5--41-7-.-=J-2433-. 5--9060.8--9455-. 9---_;,7832. 0-3999 .... /--·~-~~--
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.)
--916 t 6 .... -390-... 8-21~2-.-4 1-78-.-0--1-76-.-4 1-86-...() 30-h-3-2-J-1-5-.-6-8631-.·-0--984·1-.~3~·268-.-1--24'75-. /f---~
1229.4 562.2 388~4 324.2 .273.3 240.9 348.~ 2791.4 6347.3 9794.3 7388.0 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
---·~--1 312 • ""). ~~-~ 6 37. •. 6--5 54-.-3--51-8 ~ 2 47-6--..2 43 0-.-1---3-9-'7-•. 6-53 3 4· ... 0-8 16·9:.. 8 --1~1~3 8 0 .-2---9 2 2 5 • ·5 -~·3 2 33 .~ --·..,.
832.5 409.8 279.9 231.2 227.0 192.8 188.6 1341.0 6983.8 8944.8 7984.9 2752.3
1089.4 515.1 398.3 337.6 298.5 265.5 299.9 3578.9 6616.3 10438.9 10142.3 6229~0
.... -· 2 3 4 o • 1 ··---7 4 4 .-1 4 a 3-.-9-~-9-4·+-7 -~.J.-J ...... :l J-1-3-t-,-3-2~0-....4-2-~ 9-.-9--a a 1-2-.-6--1-3.4·6 2-.·B-a 22 9-. 6--45 91 ~··1---
2188.6 498.6 233t6 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 t 4··~-:· .9:.J9 .• 4-631-·-2--490.;3 426....-3. 355 t-9-' -355.-6--22.5.]. ... 6--.-580-9-•. 1.-9823 .~9--:-9583 .. -1~-... 4087. 0---
. 1222.3 649.1 428.2 345·1 301.7 234t2 291.7 3264.3 8213.0 10755.5 10373.0 5039.7
' • l p G • ' •
-• I • • • "' ~ I . .
• I • ' . . . I . -· . . ~ , . . .
TABLE E.S -RESUlTS OF SCRE[NING MODEL
Total Demand
0 a
Cap. Energy Site Site Cost 6 Site Cost
Run MW GWh Names Names i ~ 10 Names $X 106 ..
1 400 1750 Hi!il 1500 400 885 Devil 1ll50 400 970 Watanr.1 1950 400 980
Devil Canyon
Canyon
2 800 3500 Hi~ 1750 800 1500 Watsna 1900 450 1130 Watana 2200 BOO 1860
Devil
Canyon
Devil
Canyrm 1250 350 710
TOTAL 800 1840
3 1200 5250 Watana 2110 700 1690 _High 1750 800 1500 ·High 1750 82ll 1500
Devil Devil
Canyon Canyon
Devil 1350 500 800 Vee 2350 400 1060 Susitna 2300 380 1260
Canyon III
TOTAl 1200 2490 TOTAL 1200 2560 TOTAL 1200 2760
4 1400 6150 Watana 2150 740 1770
N 0 S 0 L U T I 0 N N 0 5 0 L U T I 0 N•
Devil 1450 660 1000
Canyon
-• --• •• • - ---• -t ... --• -• ~ ..
I
I
t
.I
I
I
I
I
I·
I
I
I
I
I
I
I
I
I
I
100+ 1000
800
LEGEND -(£)
Q e ~~~N~~p~yg~LY FROM
)C' ... COST BASED ON ADJUSTMENTS TO
O VALUES DETERMINED FROM LAYOUTS
t;
0
(.)
~r
00 200 400 600 800 1000 ..
1200
RESERVOIR STORAGE ( 103x A F }
DEVIL CANYON
1500 .~1500
1000 -t.Do
)C .. ~
~
tJ)
0
(.) 500
0~----~------~------_.------~----~~~ 0 1000 2000 3000 4000 5000
RESERVOIR STORAGE ( 103 x A F)
HIGH DEVIL CANYON
DAMSITE COST VS RESERVOIR STORAGE CURVES
FIGURE E.l
t
' 2.400
t
2000
I 1860 LEGEND
• ~~N~~T:r8~v~~iTU' FROM
I .. -1-
(/)
0
COST BASED ON ADJUSTMENTS TO
O VALUE$ OETERMINEO FROM LAYOUTS
u ,,
I
t 0~--~----~--~----~--~----~----~--~ 0 2000 4000 6000 8000 10000 12000 14000
RESERVOIR STORAGE (I03x AF)
WATANA
I ,, 1500
1390
I
I
1000
(Do
• ...
I -1-
(/)
0
(.)
500
I
I· 0~----~------~------------------· 0 1000 2000 3000 4000
'
RESERVOIR STORAGE ( to3x A F)
SUSITNA lii
I·
I DAMSJTE COST VS RESERVOIR STORAGE CURVES
.I FIGURE E.2 . ..
I
I
I-
I
·I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
800
-600
~
1060 '
LEGEND
• COST DEVELOPED DIRECTLY FROM
ENGINEERING LAYOUTS
. COST BASED ~ ADJUSTMENTS TO
0 VALUES DETERMINED FROM LAYOUTS
200 400 GOO 800 1000 12.00 1400
RESERVOIR STORAGE ( t03x A F)
VEE
~ L500
-400 1-~ 350
(,)
0~'----'~--~----~--_., ____ ._ ____ , ____ .,_ ••
800
-t;400
8
0 200 400 600 800 1000 1200 1400
RESERVOIR STORAGE ( 103x A F)
MACLAREN
-------------440
1000 2000 3000 4000
RESERVOIR STORAGE (I03xAF)
5000
DENALI
DAMSITE COST VS RESERVOIR STORAGE CURVES
FIGURE E.3 IiiJ
-·-------·--··-·-··
GOLD
CREEK OLSON DEVIL
CANYON
·HIGH
DEVIL
CANYON
DEVIL
CREEK WATANA SUSITNAm VEE MA.CLAREN . DENALi
HIGH DEVIL CANYON ~llllililll1iltlttlttlil
LEGEND
COMPATIBLE ALTERNATIVES
D. ?'·:::L':·.:··_:,·~:.::····"::::··
···: .·· ,.·: .···,·c_.. •. :
-::_.?~:,_. ->>. : :
MACLAREN.
MUTUALLY EXCLUSIVE ALTERNATIVES DENAU
-BUTTE CREEK
TYONE
MUTUALLY EXCLUSIVE DEVELOPMENT ALTERNATIVES
I
BUTTE
CREEK 'TYONE
FIGURE ;:.4111RI
I
I
I
• (f)
I
I
I
I
I
I
I
I
I
I
I
IQ
I
I
I
I
APPENDIX F
SINGLE AND MULTI-RESERVOIR HYDROPOWER SIMULATION STUDIES
0 .
' . ~~
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
APPENDIX F -SINGLE AND MULTI-RESERVOIR HYDROPOWER SIMULATION STUDIES
The economic comparisons of various Susitna Basin damsites described in Section
8, both individually and in combination~ was 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 simu-
late energy yields given storage and hydrology available at the various dam
sites.
F.l -Introduction
The reservoir simulation models determine the energy yield from the Susitna
deve 1 opments 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 ft~ the Rail-
be 1 t Region as discussed in Section 5. The monthly di stri buti on of the gener-
ated energy is" assumed to be equal to the monthly peak load, times the load
factor in that month.
Environmental constraint incorporated into the model include a maximum seasonal
reservoir level fluctuation, a maximum daily reservoir fluctuation and a minimum
downstream flow requirement. These constraints are pr-eliminary at this stage
and are only used to provide consistency between energy estimates at the respec-
tive 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 deficit 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 simu1 at ion.
(b) Utilization of Monthly Inflow·
The average monthly inflow in any month is utilized as follows in order -of
priority:
-Powerhouse flow to meet demand;
-Fi 11 reservoir;
-Generate secondary energy; and
-Spill.
If inflow is inadequate to meet demand energy under constant head condi-
tions, then storage from the reservtJir is used to supplement the inflow and
the reservoir is -drawn down. Conversely, if available inflo'IJ exceeds power
demand needs, the reservoir storag,a 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 followi-ng actions are taken:
( i) M.inimum 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
month. If discharge is inadequate to meet the energy demand, a fail--
ure is recorded.
(ii) Maximum Reservoir Level
I
I
I
I
I
When the reservoir is full, the total capacity of the plant is theor-I
etically available if the inflow is adequate. Consequently, the dis-
charge is set equa 1 to the i-nflow except 'llhen the inflow exceeds the
installed capacity. In this case, the discharge equals the plant I
capacity and the surplus water is spilled. Energy generated above
demand is designated secondary energy.·
(d) Simulation Procedure I
(i) Monthly ~imulation
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 combi na.ti on d1 scharge
flow and head necessary to meet demand. For these preliminary
studies it has been assumed that if the energy generated is within 5
percent of energy, demand fm' 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 as the powerhouse flow is
assumed equal to inflow giving no change in reservoir level.
(ii) Daily Simulation
The monthly simulat.ion 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 is determined so that the sum
of each da i ly generation for any month equa 1 s the energy determined
in the monthly simulation. In effect, monthly. peaking capacity is
equal to the ratio of monthly peak to annua 1 peak given in Figure F .1
times 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
F-2
I
I
I
I
'I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
li
I
I
I
I
I
is only used when the reservoir is full and would have to spi 11.
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.. Seco~dary 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 ~o
violate the minimum reservoir level boundary. !f baseload powerhouse
flows have to be set equal to downstreilll 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-Reser,{oir 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:
where:
E .. lJ
H •• = f. ~. J rl-! • lJ
Ej ::: the energy demand in month j
E;j = the fraction of the energy demand in month j allocated to
the hydropower plant i
H; j = the net head in month j of the hydropower p 1 ant i
H;j = 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
simurat ion 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 ~lso 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 demarrd.
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
I
I
I
I
I
I
I
The storage curves for the seven dams identified in the Sus itna .1 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 giv.en 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 effects 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 p 1 ant at
least gives approximately the historical winter flow in the reach
ill1Tiediately downstream of the dam site. Flow constraints are given
in Table F.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
(3asin developments (.l~ppendix E). In some cases phased powerhouse
e1lternatives 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
I
••
I
I
I
I
I:
I•
I
I
I-
I
I
I
I
I
I
I
I
I
I
,.'
I ,,
I
I
I
(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 geomety·y 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 discu~~sed 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 Go 1 d Creek with 30 years of record from 1949 to 1979, the others have
shorter and intermittent records.
The records at the three gages with 1 ess 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 to
the nearest upstream gage records the flow difference between the nearest
upstream and downstream gages prorated to reflect the dra·i nage area at the
dam site with respect to the nearest downstream gage. These streamflow
relationships are given in Table F.2. Streamflow at each dam site for the
30 year period are given in Tables E.l to E. 7 of Appendix E.
F.6 -Model Results
The screening model identified potential Susitna developments consisting of
either single dr.ms 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 fir·stly from the single
reservoir developnents (Watana and High Devil Canyon) and then from basin
develoiJ11ents (Watana/Oevil Canyon and High Devil Canyon/Vee) ..
The average annual energy obtained from the various development plans possible
(staged powerhouse, staged dams, etc.} are given in Table F.3 .,Jd F.4. Details
of monthly average energy and monthly firm energy are given in Tables F.5 to
F.l5.
F~7 -Interaction of OGP5
The final plant factor and the monthly peak ratios or demand curve is determined
in an interactive run with OGPS. Basically, the input of the simulation results
to OGPS 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 basi's for new reservoir simulation work.
F-6
I
I
',.
I
I
I
I
I
I
I
I
I
I
.I
I
I
,I
I
••
I
I
I
I
I
I
I
I
I
••
I
I
I
I
I
I
I
I
Dam
Devil Canyon
High Devil Canyon
Watana
Vee
TABLE F.1-RESERVOIR.AND FLOW CONSTRAINTS
Maximum DOwnstream NOrmal
Seasonal Compensation Tail water Maximum
Drawdown Flow Elevation Elevation
(ft) (cfs) (ft) (ft)
100 2000 880 1450
100 2000 1020 1750
150 2000 1465 2200
150 2000 1905 2350
TABLE r.2-DAM SITE STREAMfLOW RELATIONSHIP
Site
Gold Creek (g)
Cantwell (c)
Denali (d)
Devil Canyon (DC)
High Devil Canyon (HOC)
Watana (W}
Susitna III (S)
Vee (V)
Denali (D)
Maclaren (M)
Dra~nage
Area
6160
4140
950
5810
5'760
5180
4225
4140
950
2319
Discharge Relationship
DC : 0.827 (Q -Q ) + Q
l) g c c
QHDC : Oa802 (Q -Q ) + Q g c c
a = a.s1s <a -a } + a w g c c
Q = 0.042 (Q -Q ) + Q s g c c
Qy :: Qc
a = o.15J <a -a } +a
l) g c d
a = o.429 <a - a > + a · ~ c d d
I
I
!···
I
I
I
I
I
I
I
I
I
I
I
I
~I
.I
I'
I
- - - - - - - -·-- - -·-- - -.......
TABLE F. 3. SUSITNA DEVELOPMENT PLANS
Cumulative
Stage/Increw~ntal Oata Sl:stem Oata
Annual
Maximum Enel'gy
Capital Cost Earliest Reservoir Seasonal Production Plant
$ Millions On-line Full Supply Oraw-firm Avg. Factor
( 1980 values) 1 Level -ft. ~ Plan ~tage Construction Date down-ft GWH GWH.
I
1.1 1 Watana 2225 ft BOOMW 1860 1993 i .. 2200 150 2670 3250 46
2 Devil Canyon 1470 ft
600 MW 1000 1996 1450 100 5500 6230 51
TOTAL SYSTEM 1400 HW mrr
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 M\'1
capacity 130 2 1995 2200 150 2670 3250 46
4 Devil Canyon 1470 ft
600 M~l 1000 1996 1450 100 5500 6230 51
TOTAL SYSTEM 1400 HW '3mtr
1.3 1 Watana 2225 ft 400 MW 1740 1993 2200 150 2670 2990 85
2 Watana add 400 MW 0
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 'W1rr
0
TABLE f.3 (Continued)
Cumulative
Stage/Incremental Data. System.Datf!
Annual
Maximum Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$ Millions On-line full Supply Draw-firm Avg. factor
(1980 values) 1 level -ft. down-ft. GWH GWH Plan Stage Construction Date ~
<
2.1 1 High Oevi 1 Canyon
1775 ft 800 HW 1500 1994 3 1750 150 2460 3400 49
2 Vee 2350 ft 400 HW 1060 1997 2330 150 3870 4910 47
TOTAL SYSTEM 1200 MW "Nil'
2.2 1 High Devil Canyon
1630 ft 400 MW 1140 1993 3 1610 100 1770 2020 58
2 High Devil Canyon
add 400 MW Capacity
raise dam to 1775 ft 500 1996 1750 150 2460 3400 49
3 Vee 2350 ft 400 HW 1060 1997 2330 150 3870 4910 47
TOTAL SYSTEM 1200 MW nrm
2.3 1 High Devil Canyon
1775 ft 400 MW 1390 1994 3 1750 150 2400 2760 79
2 High Devil Canyon
add 400 HW capacity 140 1994 1750 150 2460 3400 49
3 Vee 2350 ft 400 MW 1060 1997 2330 150 3870 4910 47
TOTAL SYSTEM 1200 HW mrr
3.1 1 Watana 2225 ft 800 MW 1860 19?3 2200 150 2670 3250 46
2 Watane add 50 HW
tunnel 330 HW 1500 1995 1475 4 4890 5430 53
TOTAL SYSTEM 1180 MW ;mr
-------------------
--.. -- -------------
TABLE F.3 (Continued)
l Cumulative
.... >= Stage/Incremental Oat a System Oata
Annual
Maximum Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$Millions On-line Full Supply Oraw-firm Avg. Factor
(1980 values) 1 GWU Plan Stage Construction Oate level -ft .. down-ft. GWH ~
<
3.2. 1 Watana 2225 ft 400 HW 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 HW to· Watana 1500 1995 1475 4 4890 5430 53
n9'0'
4.1 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 HW 860 1998 1450 100 4520 528'0 50
4 Portage Creek
1030 ft 150 MW 650 2000 1020 50 5110 6000 51
TOTAL SYSTEM 1350 MW 17iiTir .
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 due to lower mobilization costs.
(3) Assumes fEfl.t:: license can be filed by June 1984, ie. 2 years later than for the Watana/Oevil Canyon Plan 1.
I
• TABLE f .4. SUSITNA ENVIRONMENTAL DEVELOPMENT PLANS
.. Cumulat~ve
b
Stage/Incremental Data System Oat(!
iSl\Oual
Ma"imum Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$ Millions On-line full Supply Draw-firm Avg. Factor
(1980 values) 1 level -ft. GWH GWH. ~ Plan Stage Construction Date down-ft
£1.1 1 Watana 2225 ft 800MW
and Re-Regulation
1993 150 3250 46 ... 1960 2200 2670 uam
2 Devil Canyon 14 70 ft
401lotW 900 1996 1450 100 5520 6070 58
TOTAl S'tSTEH 120~W '2tmT
[1.2 1 Watana 2060 ft 400HW 1570 1992 2000 100 1110 2110 60
2 Watana raise to
2225 ft 360 1995 2200 150 2670 2990 85
3 Watana add 400MW
capacity and
Re-Regulation Dam 230 2 1995 2200 150 2670 3250 46
4 Devil Canyon 1470 ft
40().t~f 900 1996 1450 100 5520 6070 58
TOTAL SYSTEM 120(}1W JOm
£1.3 1 Watana 2225 ft 400MW 1740 1993 2200 150 2670 2990 85
2 Watana add 400MW
capacity and
150 2670 3250 46 Re-Regulation Dam 250 1993 2200
3 Devil Canyon 1470 ft
400 uw 900 1996 1450 100 5520 6070 58
TOTAL SYST£M 1201}1W "2ll9tf
---~------~-----~--
- - - - - -.. -.. , .. --· ---.... - - -
TABlE f.4 (Continued)
Cumulative
Sta!j2/Incremental Data System Data
Annual
Maximum Ene'tgy
Capital Cost Earliest Reservoir Seasonal Protiuction 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 1.470 ft
40fl-1W 900 1996 1450 100 5190 5670 81
TOTAl SYSTEI.f BO!l4W '26'40 , ...
[2.1 1 High Devil Canyon
1775 ft 8~W and
He-Regulation Dam 1600 1994 3 1750 150 2460 3400 49
' 2 Vee 2350ft 400HW 1060 1997 2330 150 3870 4910 47 -TOTAL SYSTEM 12000W 2660
E2.2 1 High Devil Canyon
1630 ft 40[J.tW 1140 1993 3 1610 100 1770 2020 58
2 High Devil Canyon
raise dam to 1775 ft
add 4.0()1W and
He-Regulation Dam 600 1996 1150 150 2460 3400 49
3 Vee 2350 ft 400 MW 1060 1997 2330 150 3870 4910 47
TOTAl SYSTEM 1200MW 2iffiii
E2.3 1 High Devil Canyon
1775 ft 40[t1W 1390 1994 3 1750 '150 2400 2760 79
High Devil Canyon
@dd 400HW capacity
and Re..:Reguiation
Dam 240 1995 1750 1')0 2460 3400 49
3 Vee 2350 ft 40tJ.tW 1060 1997 2330 150 3870 4910 47
TOTAL SYSTEM 1200 2690
TABLE F .. 4 (Continued)
Cumulative
Stage/Incremental Data S~ste11,Data
Ailnual
Maximum Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$Millions On-line full Supply Draw-firm Avg. factor
Plan Stage Construction (1980 values) 1 level -ft. Date down-ft. GWH G\lft-l . ., ..
Q -r\'....,_.
£2.4 1 High Oevi l Canyon
1755 ft 4£01W 1390 1994 3 1750 150 2400 2760 79
2 High Devil Canyon
adl: 40()IW capacity
&d~ ~o~tage Creek
~~150ft 790 1995 17$t.i 150 3170 4080 49
3 Vs"J 2350 ft
IOIOOOW 1060 1997 2330 150 4~30 5540 47
TOTM.. SYSTEM ~
E3.2 1 Watana
2225 ft 400HW 1740 1993 2200 150 2670 2990 85
2 Watan.a add
400 HW c ... ':pacity
and Re-Regulation
Dam 250 1994 2200 150 2670 3250 46
Watana add 5lMf
Tunnal Scheme 331)tW 1500 1995 1475 4 4890 5430 53
·roT Al. . SYSTEM 118cttW miT
£4.1 1 Watana
2225 ft 40£tlW 1740 1995 3 2200 150 2670 2990 85
2 Watana
add 400HW capacity
and Re-Ragulation
Dam 250 1996 2200 150 2670 3.250 46
3 High iJey!! ~ .... !'>yon
1470 ft 4\liJtW 860 1998 14.50 100 4520 5280 50
4 Po!."tage Creek
1o:;o ·rt 15(}1W 650 2000 1020 50 5110 6000 51
TOTPJ.. SYSTEM 1350 MW '15mT
NOTES;
(lj Allowing for a 3 year overlap construction period between fll8jor dams.
(2} Plan 1.2 Stage 3 is less expansive than Plan 1.3 Stage 2 due to lowe.r mobili-zation costs.
(3) Assumes FERC license can be filed by June 1984, ie. 2 years. later than for the Watana/Oevil Canyon Plan 1.
I}
-.. -.. --- -
.. ------••• -· <·-. 1
. .' ..
I
I .,
I
I
I
I
I
I
I.
I
I
I
TABL£ F.5-PLAN 1.1 -ENERGIES
STAGE i
MONTH Watana (2200)
800 MW
EA Ef
(GWH) (GWH)
JANUARY 264 263
FEBRUARY 250 249
MARCH 224 224
APRlL 201 201
MAY 186 186
JUNE 187 183
JULY 285 183
AUGUST 499 1.90
SEPTEMBER 370 204
OCTOBER 233 233
NOVEMBER 266 266
DECEMBER 287 287
TOTAL ANNUAL 3252 2669
Notes:
EA:
EF:
(2200):
Average Monthly Energy
Monthly Firm Energy
Reservoir full supply level
stAGE 2
Add Dev J.! Canyon
(1450)
600 MW
EA EF
(GWH) (GWH)
542 538
514 511
452 458
394 406
418 405
437 383
473 373
707 394
667 421
488 478
544 540
591 587
6227 5494
TABLE F.6 -PLAN 1.2 -ENERGIES
~1~C£ , . !;T1iC~ :Jt1 ~
Watana {Zdbo) Raise Watana (2200)
MONTH 400 MW Add 400 MW
£A £f' EA tF
(GWH) (GWH) (GWH) (GWH)
JANUARY 138 137 264 263
FEBRUARY 130 129 250 249
MARCH 117 116 224 224
APRIL 103 57 201 201
t-1.~Y 100 100 186 186
JUNE 154 102 187 1B3
JULY 3ZZ 103 285 183
AUGUST 355 365 499 .190
SEPTEMBER 269 188 370 204
OCTOBER 131 123 233 233
NOVEMBER 140 139 266 266
DECEMBER 150 149 287 287
TOTAL ANNUAL 2109 1708 3252 2669
Notes:
EA: Average Monthly Energy
EF: Monthly Fi~m Ene~gy
(2000): Rese~voi~ full supply level (ft)
(1 ) Stage 2 is as for Stage 1 on Table f.6 (Plan 1.3)
~TAn!': 4
Add tlev1l ~anyon
(1450) 400 MW .
£A EF
(GWH) (GWH)
542 538
514 511
452 458
394 406
418 405
437 383
473 373
707 394
667 421
488 478
544 540
591 587
6227 5494
" . . . ,. . '"~]
·'.·1: I i
I
~I
I .• -
I
'I
I
;I
I
I
I
I
I ~ .
I
II
I
·~
I
·t
I
I
I
I
I·
I
I
I,
I
I
I
I
I
I' (;}
/
,.r
I
I,
I
.i
TABLE f.7-PLAN 1.3-ENERGIES
rt.."~ ~TAC£: ,
watana (22oo)
MONTH 400 MW
EA Ef
(GWH) (GWH)
JANUARY 263 263
FEBRUARY 250 249
MARCH 224 224
APRIL 201 201
MAY 186 186
JUNE 187 184
JULY 245 183
AUGUST 333 190
SEPTEMBER 315 204
OCTOBER 233 233
NOVEMBER 266 265
DECEMBER 287 287
TOTAL ANNUAL 2990 2669
Notes:
EA:
EF:
(2000):
Av.erage Monthly Energy
Monthly Firm Energy
Reservoir full supply level (ft)
!;TAC~ 2
Add 400 MW to
Watana (2200)
EA EF
(GWH) (GWH)
264 263
250 249
224 224
201 201
186 186
187 183
285 183
499 190
370 204
233 233
266 266.
287 287
3252 2669
~T7iC£: )
Add Devil Canyon
(1450) 400 HW
£A Et
(GWH) (GWH)
542 538
514 511
452 458
394 406
418 405
437 38:S
473 313
707 394
667 421
488 478
544 540
591 587
6227 5494
'"
TABLE F.B-PLAN .2.1 -ENERGIES
~TACE: , ~T~CE 2
t«lNTH High Devil Canyon Add Vee. (2355)
(1150) 800 MW 400 MW
EA Ef EA ; Ef'
(GWH} (GWH) (GWH) (GWH)
JANUARY 235 232 368 368
FEBRUARY 222 2.19 349 350
MARCH 197 151 303 313
APRIL 173 JO 268 276
MAY 169 171 254 258
JUNE 231 172 290 247
JULY 480 173 526 319
AUGUST 554 307 752 298
SEPTEMBER 429. 303 575 280
OCTOBER 219 213 394 366
NOVEMBER, 239 233 403 393
DECEMBER 257 254 425 401
TOTAL ANNUAL 3405 245S 4907 3869
Notes:
E.A: Average Monthly Energy
EF: Monthly Firm Energy
(1750): Reservoir full supply level (ft)
I
~I
I
J jl
I
!I
I
I
I
••
I
I
••• ••
.
. . 1:
I
I
I
I·
I
I
I
I
I
I
I
I
I
I
I
I
I
TABLE F.9-PLAN 2.2-ENERGIES
~TArit l ~TA~E ~
Raise High Dev n
Hi{h Devil Canyon Canyon (1750)
MONTH 1610) 400 MW .
EA EF EA EF
(GWH) (GWH) (GWH) (GWH)
-JANUARY 117 11.6 235 232
FEBRUARY 110 109 222 219
MARCH 99 98 197 141
APRIL 89 87 173 30
MAY 92 87 169 171
JUNE 265 9) 231 172
JULY 292 291 480 173
.-AUGUST 290 292 554 307
SEPTEMBER 270 243 429 303
OCTOBER 150 105 219 213
NOVEMBER 120 119 239 233
DECEMBER 129 127 257 254
TOTAL ANNUAL · 2023 1767 2759 2415
Notes:
£A: Average Monthly Energy
EF: Monthly Firm Energy
(1610): Reservoir full supply level ( ft)
~T~~£ )
Add Vee (ZJ3o}
400 MW -
Total 1200 MW EA EF
(GWH) (GWH)
368 368
349 350
. 303 313 ..:
268 276
2~4 258
290 247
526 J19
·752 298
575 280
394 366
403 393
425 401
4907 3869
0 TABLE F.10-PLANS 2 .. 3 and E.2o3-ENERGIES
~AC£, ~TAG£: 2
Hi{h Devil ~anyon Add 400 RW tu
MONTH 1750) 400 MW High Devil·Canton EA EF EA F
-(GWH) (GWH) (GWH) (GWH)
JANUARY 235 232 235 232
f;EBRUARY 222 21.9 222 219
MARCH 197 141 197 152
APRIL 173 30 173 30
MAY 169 171 169 171
JUNE 200 172 231 172
-JULY 275 173 480 173
AUGUST 288 286 554 307
SEPTEMBER 285 292 429 303
OCTOBER 219 213 219 213
NOVEMBER 239 232 239 233
DECEMBER 257 254 257 254
TOTJ\i. ANNUAL 2759 2415 3405 2459
Notes:
EA:
EF:
(1 750):
Average Monthly Energy ·
Monthly Firm Energy
Reservoit full supply level ( ft)
~T~r 3
Add vee (2)3o)
400 HW
EA Ef
{GWH) (GWH)
368 368
349 350
3!)3 313
268 276
254 258
290 247
526 319
752 298
575 280
394 366
403 393
425 401
4907 3869
••
I
. ~I
I
I
I
I
I ,.
I
I
I
I
I
I
¥1
I
1.'
I
i
.. <:
I
-•.
••
..
I
I
I
I
I
I
I
I
I'
.i
I
I
f. . I
i
..
' ,.
TABLE F .. 11 -PLAN 3.1 -ENERGIES
sTAGE 1 sTAG£ 2
Watana (22do) Add Tunnel
MONTH 800 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 543J 4885
Notes:
EA: Average Monthly Energy
Ef: Monthly Firm Energy
(2200): Rese.rvoir full supply level ( ft)
...
TABLE f.12-PLAN 4.1 -ENERGIES
~TA~t: i
watana (22oo)
MONTH 800 MW -n Ef
(GWH) (GWH)
JANUARY 264 263
FEBRUARY 250 249
MARCH 224 224
APRIL 201 201
MAY 186 186
JUNE 187 183
JULY 285 183
AUGUST 499 190
SEPTEMBER 370 204
OCTOBER 233 233
NOVEMBER 266 265
DECEMBER 287 287
TOTAL ANNUAL 3252 2669
Notes:
EA:
EF:
(2200):
Average Monthly Energy
Monthly Firm Energy
Reservoir full supply level (ft}
~TACt: 2
Add H.D.C.
(1450} 400 MW
EA EF
(GWH} (GWH)
447 444
424 422
379 378
334 335
338 330
349 313
419 306
670 323
583 346
400 393
499 446
468 485
5281 4522
~TAG£: :r
Add Portage Creek
(1020) 150 w,.t EA EF
{GWH) (GWH)
504 501
"478 476
428 426
379 378
391 376
406 356
481 347
799 366
661 392
454 445
507 503
550 546
5997 5112
J
. l lj
I
I
I
••
I
I
I
I
I
I
I
I
I
I
' . 'I
I
I
I
I,
.:
I
I
I
I
I
I
I
I
I
I
••
I,
I
I
I
TABLE F .13 -PLAN E1.2 -ENERGIES
STAGE 2ti'
Watana RaJ.se Dan
MONTH ( 2200) 400 HW tA £F " (GWH) (GWH)
JANUARY 263 263
FEBRUARY 250 249
MARCH 224 224
APRIL 201 201
MAY 186 186
JUNE 187 184
JULY 145 183
AUGUST 333 190
SEPTEMBER 315 204
OCTOBER 233 233
NOVEMBER 266 265
DECEMBER 287 287
TOTAL ANNUAL 2990 2669
Notas:
EA:
Ef~
(2200):
Average Monthly Energy
Monthly Firm Energy
Reservoir full supply level ( ft)
STAGE 3
Add 40o Rw to
Watana (2200) EA EF
(GWH) (GWH)
264 263
~50 249
224 224
201 201
186' 186
187 183
285 183
499 190
370 204
233 233
266 266
287 287
3252 2669
{1 ) Stage 1 is as for Stage 1 on Table 2 Plan (1.2)
STAGE 4
Ado bevJ.l Canyon
(1450) 400 MW
EA EF
(GWH) (GWH)
544 560
515 516
450 460
396 408.
419 406
436 385
453 375
616 395
606 423
-490 480
547 545
594 589
6065 5520
~
TABLE F.14 -PLAN E1.3 -ENERGIES
~TA~~ 1 ~TAC£ 2
Watana (2200) Add 400 MW to
MONTH 400 M\\ Watana
EA Ef EA Ef
(GWH) (GWH) (GWH) (GWH)
JANUARY 263 263 264 263
FEBRUARY 250 249 250 149
MARCH 224 224 224 224
APRIL 201 201 201 201
MAY 186 186 186 186
JUNE 187 184 187 183
JULY 245 183 285 183
AUGUST 333 190 499 190
SEPTEMBER 315 204 370 204
OCTOBER 233 233 233 233
NOVEMBER 266 265 266 266
DECEMBER 287 287 287 287
TOTAL ANNUAL 2990 2669 3252 2669
Notes:
EA: Avet'age Monthly Energy
EF: Monthly Firm Energy
(2200): Rese~voir full supply level (ft)
~TACt :3
Add Devil Canyon
(1450) 400 MW
E. A EF
{GWH) {GWH)
544 560
515 516
450 460
396 408
4'19 406
436 385
453 375
616 395
606 423
490 480
547 545
59 A 589
6065 5520
., I
I ,
. I
I
I
I
I
I
I
0
••
I
I
I
I
I
I
I
I
I
I
I
I
I
••
I
I
I
I
I
TABLE F.15 -PLAN EZ~4-ENERGIES
Si'Ai'i~ 1 sTAi'iE: ~
Add 4oo MW to High
MONTH Hi{h Devil Canyon Devil Canyon and Par~
1750) 400 MW tage Creek (150 MW) EA £t EA £f
{GWH) (GWH) (GWH) {GWH)
JANUARY 235 232 317 317
FEBRUARY 222 219. 296 302
MARCH 197 141 26.1 270
APRIL 173 30 231 239
t~AY 169 171 220 221
JUNE. zoo 172 232 208
JULY 275 173 460 214
AUGUST 288 286 629 221
SEPTEMBER 285 292 492 241
OCTOBER 219 213 282 276
NOVEMBER 239 232 317 317
DECEMBER 257 254 346 346
TOTAL ANNUAL 2759 2415 4083 3111
Notes:
EA: Average Monthly Energy
EF: Monthly Firm Energy
(1750): Reservoir full supply level (ft)
sTAi'iE: :3
Add Vee (2350)
400 MW tA EF
(GWH) (GWH)
43.2 435
411 415
360 372
318 .328
287 290
321 277
564 349
820 332
646 315
447 415
457 446
480 456
5543 4430
I
I
I
I
I
I
I 0
ti
I a:
~
<(
!U a..
I ...J
<(
:::) z z
I
<(
~
~
<(
I UJ a..
>-_J
~
I .... z
0
~
I
I
I
I ;
I
I
I
1.0
1.00
r-.92 .92 "'
.9
.87
.a r-
.78 .80
.7 -.70 .70
'-'! .. .64 .64
.62 .51 ~
.6
.5
. 4 ..
.3 ~
.2 ..
• t i-
I
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
MONTH
1995 MONTH/ANNUAL PEAK LOAD RATIOS
REF: WOODWARD CLYDE. CONSULTANTS,
" FORECAS11NG PEAK ELECTRIC
DEMAND FOR ALASKA'S RAILSELT"
~IGURE F.l li11e}
APPENDIX G
SYSTEMWIDE ECONOMIC EVALUATION
,,
" ' ' • '... < '"· ~·
I
I
I
••
•••
I
I
I
I
~.
I
I
-·,
I.
I
I'
I
I
I
APPENDIX G -SYSTEMWIDE ECONOMIC EVALUATION
The Railbelt System will 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 BcrSin plan would be that plan which gives
the lowest system present worth cost of generation for the energy and capacity
demands and economic criteria selected ..
Gol -Introduction
Generation planning analyses were performed by making a comparison of Susitna
Basin development alternatives with the aid of a production cost model to assess
the system costs for the various development alternatives availableo Standard
numerical evaluation techniques were then used to make direct comparison of al-
ternatives. Initially, a set of variables was established for use in making
broad comparisons of available basin developments. In this preliminary evalua-
tion, the study focused on the medium load forecast to identify various plans; a
base p 1 an whi ':h consisted of an a 11 therma 1 deve] opment, p 1 ans composed of ther-
mal plus various Susitna developments, and a plan composed of thermal plus other
hydroe1 ectt"ic developments ..
The second phase of generation planning assessed the impact of varying the 1oad
forecast. System generation plans with and without the Susitna Basin develop-
ment plan were identifi(~d for the high and low loaq forecasts .. A plan was also
developed for the low load forecast considering an additional reduction in load
growth due to conservation and load management. Also under this phase, a plan
was developed considering a probabilistic forecast centered around the medi001
load forecast.
Since it is recognized that the. selection of a gener~-'c:ion plan may be sensitive
to the underlying assumptions, the third phase of generation planning assessed
the 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.
G.2 -Generation Planning Models
(a) Selection of Pta~lning 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 colllnercially 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:
Q ... l
-GENOP by Westinghouse
-OGPS by General Electric.
-PROMOD b.y Energy Management Associates.
by Tennessee Valley Authority. -WASP
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,
coflll10n traits of operation exist. Some of the salier.t features of each
model are shown on Table G.l. Major differences in·the models are given
below.
( 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 extending planned maintenance schedules.
-Stochastic methods which can be reduced to deterministic methods.
Strictly speaking stochastic rtipresentations of outages is a random
selection of some units in each conmitrnent 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 allows for
probabilitydistribution of generation unit outages.
The selection of one of these methods may be critical in the use of a
model for shcrt-term outage scheduling, however it is generally found
that virtually no difference in p Tanning results is obtai ned from
models using the three methods available over a long term period.
(ii) Dispatching Hydropower Resources
The method of di spat chi ng hydropower resources to meet 1 oad demands is
another signifi.cant feature which effects the model's representation
of tha system. The GENOP program wi 11 dispatch or select~ from avai 1-
abla units, hydroelecric units first to meet a given demand. Gen-
erally, the run-of-river units will meet load demand and units with
storage capability used to shave peak demands~
G-2
••
I
I
I
I
I
I
I
I
I ,.
I
I
;I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
••
I
••
I
I
I
t.
I
I
The OGPS 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 re-liability, while
using average annual energy to determine system production costs.
The PROMOD program· allows for three levels of annual runoff ana
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 a 1 so import ant such as program av ai 1 ab i 1 i ty and ex-
perience of staff in using the models. On this basis of this assess-
ment·of model features, model availability and Acres knowledge of the
intricacies of the model procedures, the OGP5 model was selected for
use in this study. 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.
(b) OGPS 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 conmonly known as UGPS
or Optimized Generation Planning Model$ The following information is para-
phased from GE literature on the program •
The OGPS 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.
OGPS will automatically develop optimum generation expansion patterns in
terms of economics5) reliability and operation. Many utilities use OGP5 to
study load management, unit size, capital and fuel costs, energy storage,
forced outage rates and forecast uncertainty.
The OGPS 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 conmitted units (planned and under construction)
available to the system and the characteristics of these units includin~J
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 11 how much" capacity to add and nwhen 14 it
should be installe1. 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 ~ .. esulting in the lowest system production cost is selected and
added to the system. Finally, an investment cost analysis of the capital
co.sts is completed to answer the question of 11 What kind" of generation to
add to. the system.
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 reliaoility 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 detai 1
in Section 5, "Railbelt Load Forecast .. , of the !~ain Report. Figure
G .. l depicts the four energy forecasts in the systemwide ana1ysis.
The forecasts to !Je 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 p1an is the medium
load forecast (Table G.2). Sensitivity analyses have also been
undertaken using variable loads developed using 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 forecast:) 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 cf the industrial self suppliers
indicates that they are primarily offshore operations, orilling
operations and others which wo,lld not likely add nor dr--aw power from
the system. The forecasts have been appropriately adjusted for use in
generation planning stud·ies, as described in Section 5. Additionally,
although it is considered likely that the militaty 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 to 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
meoi llll load and energy forecasts ~t five year intervals throughout the
planning period.
....
'· ~
I
I
I
••
;I
11
I
I
I
I
I
I
I
I
I
1.···.
'
I
-1······ . .
I
I
1
I
I
I
••
I
I
I
I
I
·-
I ,,
I
I
I
I
~
( i i) Load Uncer~~ainty
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 1 oads. To address the question of the impact of 1 oad un-
certainty of 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 s.econd method will be to incorporate the var? ~:ble fore-
casts and uncertainty of the load forecasts into the planning pro-
cess.
The meditiTl 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 l.evels of peak demand and the probability of
the occurrence of these forecasts. For example: in year 2000 the
medil.ITI load forecast demand entered is 1175 MW. Variable forecasts
are entered for 950, 1060, 1530 and 1670 MW, with associated probabil-
ities of occurrence of .10, .20, .20 and .10, respectively~ The
middle level forecast of 1175 MW would have a probability of occur-
rence of .40.
The OGP5 program uses this variable forecast in determining generating
system reliability only. A loss of load probability calculated for
each projected demand level as compared to the available capacity and
a weighted average 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, the three by
ISER and the two extremes calculated by Acres represented in Table
G .. 2r Subjectivity is reduced to the decision of placing probabilities
on the load forecasts. Based on commmunication with the ISER group in
A1aska, as well as General Electric OPGS 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 adj ac.ent forecast which is c 1 osel" to the med i urn. The 1 o ads and
probabilities analyzed are given in Table G.3.
(iii) Generation Plant Reliabilitx
In order to perform a study of the generation system, criteria are
required to establish generating plant and system reliability. These
cr-iteria are important to determine the adequacy ot -the--available
generating capacity as well as the sizing 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).
A LOLP f'or a system is a calculated probability based on-the charac-
teristics of capacity, forced and scheduled outage, and cycling abil-
ity of individual units in the generating syst:em. The probability de-
fines the 1 ikel ihood of not meeting the full demand within .a one year
period. For example~ a LOLP of 1 relates to the probability of nat
meeting demand one day in one year; a 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 p1 an and for sensitivity analyses dealing w~th the effects
of over or under capacity availablility.
{iv) Economic and Financial Parameters-
As a public investmsnt, it was determined that the Susitna project
should be evaluated initially from an economic perspective, using eco-
nomic parameters. Initial ana·lysis and screening of Susitna alterna-
tives employed a numerical economic analysis and the general aid .of
the OGPS model.
The differences between economic and financial (cost of power) ana-
lyses pertain to the following parameters ..
-Project Life
In economic evaluations, an economic life is used without regard to
the terms {repayment period) of debt capacity employed to finance
the project. Financial (or cost of power) perspective used an amor-
tization period that is tied to the terms of financing. Retirement
period (policy) is generally equivalent to project life in economic
eva.luations; financial analysis may use a retirement period that
differs from project life.
-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
Whenever market and shadow prices diverge, economic evaluations used
shadow prices (opportunity costs or values) .. Financial analysis,
uses market prices projected as applicable. Fttel prices are discus-
sed in deta.il in Section 6 and Appendix B.
G-6
I
I
I
~I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
•• • :
I
I
I
I
Q. ... ~ :., t( • • • ·~· ~ • 9 .
Cl • • ~ II t } "' q ,_ ~-·~ • • . • . y • ~
It is important to note that application-of the various parameters
contained herein -wi 11 not necessarily provide an accurate reflection
of the true life cycle cost of any single generating r·esource of the
system.. rrom 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 study into this
comparative analysis of project economics will be continuing during
1981.
-Interest Rates ~nd Annual Carrying Charges
The assumed generation p 1 anni ng 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
rea 1 cost of debt capacity. TI1e 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)
= L,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 a·lso 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
-Di ese1s -30 years
-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 initi&l 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 rea.l growth rates of zero percent for
non-energy costs in the set of economic parameters used i.n real
do 11 ar generation p 1 anni ng. · --
G-7
•
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 estimted to be $2.00/MMBtu. The shadow
price for gas represents the expected market value assuming an
export mar~et were developed.
Real growth rates in energy costs (excluding general price infla-
tion~ are shown in Table G .. 4. These are based on fuel esca.1ation
-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
corrmercial and residential sectors to ref1ect utilities' bulk
purchasing advantage. A composite esc a 1 ati on rate has been computed
for the period 1980 to 1995 reflecting average compound growth rate
per year. As DOE has suggested that the forecasts to 1995 may be
extended to 2005, the composite escalation rates are assumed to
prevail in the period 1996 to 2005. Beyond 2005~ zero growth in
energy prices is assumed.
Table G.S summarizes the sets of economic and financial parameters
. assumed for generation planning.
-Other Parameters
Other parameters considered in generation p 1 anni ng studies inc 1 ude
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 Feder a 1 taxes were assumed
to be zero for all types oTpower projects. This assumption is
valid for planning based on economic criteria since all intra-state
taxes should be excluded as transfer pajfllents from Al aska• s
perspective. The subsequent finan~i al analyses may relax this
assumption if non-zero state and/or local taxes or pa)111ents in lieu
of taxes are identified. Annual fixed carrying charges relevant to
the generation planning analysis are given in Table G.5~
G.3 -Generation Planning Results
Gene.ration planning runs were made for each of the Susitna development plans
identified in Section 8.6 -Formulation of Susitna Basin De'Jelopment Plans~ and
for system generation plans without Susitna developments., Plans without Susitna
inc 1 uded alternative hydro and a 11 thermal generation scenarios.
A minor 1imitation inherent in the use of the OGP5 model is that the number of
years of si mul ati on is 1 imi ted 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 co11111on to a 11 system generation p 1 ans.
G-8
I
I
••
I
I
1 .. . '
I
••
I
I
I
I ,,
I
~I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
••
I
••
I
I
I
I
I
I
The first segment has bean assumed to be from 1980 to 1990. The model of this
time period included all comnitted generation units and fs assumed to be common
to all generation scenarios. This ten-year model is summarized in Table G-8.
This tab 1 e shows the 1980 to 1990 system configuration and detai 1 s on cortmi tted
urri ts and retirements that occur during the period. The end point of this mode 1
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 tot a 1 production costs on a year-to-year basis. · These tot a 1
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 p 1 ans 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 colllT1on 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
-Admi ni strati ve costs of utilities for providing electr..,i c 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 at
least take into account the benefit derived or value of the addition of a hydro-
electric 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 p 1 an-. 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 thre= 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 the
PWC of the scenario in 2010 assumed to recur for the period 2010 to 2040.. In
this way the long-term (60 years) PWC of each generation scenario in 1980
dollars can be compared.
The present worth cost of the generation system given by Table G.6 is $873.7
million in 1980 values. This cost is common to all generati.on scenarios and is
added to all PWC values for each generati.on scenario during the modeling of the
system in the period of 1990 to 2040. ·
G-9
Generation scenarios analys,es include thermal generation with Sus~itna Basin
plans~ 'th(:rmal 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 areat totally dif-
ferent sites. These various Susitna plans were modeled in the OGPS
model as part of the Railbe1t 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 medit.m load forecast for all the Susitna plans identified
through the procedures outlined in Section 8 are give~·~ in Table.
G.B.
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 dan in the
p 1 an. Inspection of the results given in Tab lje G .. 8 indicates the
following:
-Jhe lowest present worth cost dev~lopment at $5850 million 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 ana ~taged powerhouse development;
The highest present wortn cost development at $6960 million is
Plan 1.3 with Devil Canyon not constructed;
-Watana/Devil Canyon (Plan El.l or El.3) is superior to Watana/
Tunnel ·(Plan 3.1) by $680 million;
Watana/Devil Canyon (Plan El.l 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 El.l or El.3) is superior to High Devil
Canyon/Vee developments (Plan E2.1 or Pla;A 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
I
I
I
I
I
I
I
I
I
I
I
I
••
I
I
I
I
I
I
••
I.
••
I
I
I
I
··-
1
••
I
I
I
I
I
I
I
I
G
I
Watana/Devi 1 Canyon development limit-ed to 800 MW (Plan f:.l.4) is
$140 million more than full 1200 MW development (Plans El.l or
E1.3) but remains superior to tunnel scheme or High Devil Canyon/
Vee plans;
.... Delaying implementation of ~Jatana/Devil Canyon Plan El.3 by five
years adversely effects present cost by an additional $220
mi ll·i on;
-Staging powerhouse and dam construction at Watana (Plan E1.2}
costs $180 million more than Plans El.l or El.3; and
-Watana/H1gh Devil Canyon/Portage Creek (Plan E4.1) is $200
million '1l1ore than either Plan El.l or El.3.
(ii) Variable Load Forecast
As discussed in Section 5, the many uncertainities of load forecast-
ing provide a \IJide 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 i denti fi ed through site screening and p 1 an formul at·; on steps
is thought to be the most likely load and energy forecast. However 9
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 has been incorporated into a fourth load
forecast. This very low forecast also assumes low government expen-
diture in addition to low economic growth with load management and
conservation,. Further details of these forecasts are given in Sec-
tion 5 and load forecast values in five-year periods in Table G.B.
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/Devi 1 Canyon development (Plan El.4} has the least present
worth cost at $4350 mi 11 ion of a 11 deve 1 opment s under a 1 ow load
forecast;
-Watana/Devi 1 Canyon with Chakachamna as a fourth stage (modified
Plan El.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
ha 1 ved) by $380 million under a 1 ow load forecast;
G-11
Plan El.4 is superior to High Devil Canyon/Vee (Plan E2~l) by
$320 million under a low load forecast;
-Modified Plan El.3 is superior by $650 mi1ilun to Plan £1.3 under
a high load forecast; and
-Modified Plan El.3 is superior to High Devil Canyon/Vee with
Chakachamna (modified Plan £2.3) by $990 million.
{iii) Economic Sensitivity
The Watana/Devil Canyon developmertt known as Plan EL.3 has been
identified as the most economic de\le1opment of Susitna alternatives
under a medit.m load forecast (Tiible G~a). In addition, variations
of Watana/pevil Canyon development have been identified as the most
economical under low and high load forecasts (Table G.9). Conse-
quently, the Plan El .. 3 is obviously the most reasonable to select a~
the one to determine the ~~nsitivity of the plans to variations in
the economic parameters which are subject to !.lncertainties.
Sensitivity analysis have been performed on critica1 parameters and
are based on Plan El. 3 \'lith a medi t.m load forecast. The result·s of
these analyses are summarized in Table G.lO and are discussed below.
Base values for the parameters assumed in OGP5 modeling, particular-
1Y in respect to thermal plant costs, etc. are given in Appendix Bo
Interest Rates
In the base p 1 an se.l ected {a 1 so in other p 1 ans) the interest rate
asst.med is 3 percent. This rate represents the cost of money,
net .of inflation. Variation of this rate to.5 and 9 percent have
been asslJJled 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 million to· $4230 mill ion. The higher rate of 9 percent
1 ower'S the present worth cost to $2690 mi"ll ion.
-· Fuel Cost and Fuel Cost Escalation Rate
The base p1an has assumed a fuel cost ($/mi.llion Btu) of 2.00,
1.15, and 4.00, fOt"' ratural ~as, 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 respect·ively is
to reduce the present worth cost of Plan El. 3 by $590 mi 11 ion to
$5260. This reduction represents the lower cost associated ~·ith
operating the thermal generation component of the system.
~ue 1 cost esc al at ion rates of 3. 98, 2 .. 93, and 3. 58 percent have ·
baen derived as typical for the Railbelt region (Appendix B).
ihe effect of lowering tHis escalat·ion rate to zero percent for
all thermal fuels is to lower the present worth cost of Plan El.3
G-12
I
I
I'
I
I
I
;I
••
I
I
I
I
I
I
I
:I
I
I
I
. " . ..
, • ... • • • <J. ll • . ~· · ~ • e , ·.. •
. ~.. . ... . ' . ... ' '
I
I :.
I
I
I
I '
j
' I
I
I
I
I
I
I
I
I
I.
l l
< "··. --·~:" .:::_ -, "'" ... "" '"""
to $4360 mi 11. ion. When cJa 1 cost esc a 1 ati on alone is set at zero
percent the effect is much less, giving a reduction of only $590
mill ion. Again the fue1 cost escal aticm 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 1 ives 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 cap·ital costs of the thermal component of the
s~t~. ·
-Hydro Plant Capital Costs
Various uncertainties in \;,;apital costs of the hydro development
exist due to possible vartations 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 analysis conducted above would be the same
for whichever development plan is selected.. That is, the relative ranking
of the various Susitna Basin d{welopment plans would remain essentially un-
changed and Plan E1.3 would still be found to be the most economic in terms
of present worth cost under a medi t.m load forecast.
(b) t_ltern_!tive 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
.0 .·
G-13
(c)
-Strandline:
-Allison Creek:
-Cache:
-Talkeetna-2:
-Browne:
-Bruskasna:
-Hicks:
20 MW
8 MW
50 MW
50 MW
100 MW
30 MW
60 MW
In the OGPS analyses these sites were combined into appropriate groups on
the basis of least cost energy and i ncc,rporated with thermal generation
sources to meet the medium load forecast defined earlier (Section 5). The
results of the OGP5 runs are given in Tabie G.ll. ·
The lowest present worth cost of the system with alternative Susitna hydrJ
is $7040 mi 11 ion. This represents an increase of $1190 mi 11 ion over the
lowest cost Susitna development plan {Plan E1.3) 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 sav-
ing a non .. ,.renewab 1 e resource.
Th.a maximum development of alternative hydro considered has a present worth
cost of $7088 million. The six sites included in this plan are given in
Table G.ll.
Thermal Generation-Scenarios
The thermal generating resources required to meet Railbelt 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 de.ve loped in Appendix B for therma 1 generating resources
available to the Railbelt and the five load forecasts outlined in Section
5, the OGPS program was used to simulate the operation of the Rai lbelt
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 Railbelt over the next 40 years. Consequently~ as before
for hydro developments, th·is 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.ll.. Two cases were modeled for the thermal
generation plan. The first model allowed the renewal of natural gas
gas-turbines at the end of their economic life; the second assumed
no renewals required the permanent retirement of the natural gas
G-14
I
I
I
I
' I
I
I
t
I
•
I
I
I
I
I
I
I
I
I
I
I
I ,.
I
I
I
I
I
I
I
I
-·
I
I
I
I
I
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 Fuel Use Act
(FUA) which prohibits the building of new generating units operating
on natural gas. The FUA is discussed more fully in Section 6.6
where it was shown that Railbelt utilities would probably be re-
stricted to new gas facilities for peaking applications only.
The pol icy-of renewal or non-renewal of gas turbines has a minimal
effect on long-term present worth cost of the thermal system model.
This is clearly shown·in Table GDll 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 systan is
$8110 million assuming gas turbine renewals.
The same 10-year generation plan {for 1981-1990) applies to the
thermal generating scenario as did for the hydroelectric scenarios
given above. This period sees the installation of the Beluga com-
bine cycle Unit No. 8 by Chugagh Electric Association and the 94 MW
Bradley Lake hydro plant in 1988.
Under the medium load forecast the level· of installed coal-fired
units increas~s 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 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 fon~~casts 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 meditlll load
forecast. As in the medium forecast, the two cases of gas turbine
renewal or nonfflrenewa1 was determined.
-High Load Forecast
Thehigh load forecast requires the installation of a 100 MW
coal-fired plant in 1990. This is the sam~ as was determin~d for
Susitna and non-Susitna hydro scenarios under the high load fore-
cast. The long-term present worth cost of the thermt);1 :generation
scenario under this load forecast is $13,630 million assuming a
renewal policy of gas turbines. There is a slight benefit of
$110 million if a policy of non-renewal is pursued~ Effectively,
however, the t\1¥'0 cases can be assumed to be 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.ll). The
present worth cost of the thermal system under the low load fare-
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 for~~cast 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 anr:lysis of the thermal generation plan, the med-
i urn load fqrecast 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 aver 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 fue 1, 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
of zero percent and the interest rate is three percent. Sensi-
tivity of the thermal plan to changes 1n the interest rate to 5
and 9 percent was determined, again assuming a zero percent esc a-
lation o.r 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
I .
I
I
I
I
I
I
I
I
I
I
I
I
a·
I
I.
I
I
I
I
I
I
I
I
I
I ,,
I
I
I
I
I
1-,,
I
I
I
If a comparison was to be drawn between thermal and Susitna scen-
arios studied under the sensitivity analyses it would show that
the twc\ plans would be economi,cally comparable (in terms of pre-
sent worth cost) if interest ratr~s were approximately eight per-
cent.
To provide reasonable comparisons to be ma.de between interest
rate sensitivity analysis it was necessary to assume that the
generation system mix would be similar as that determined for the
three percent OGPS run. If this was not the case, then OGP5
would select cheaper genE!ration units, particularly natural gas,
which probably would not meet defined criteria. on syster~ compon-ents. ·
Fuel Cost
The reduction of fuel costs by 20 per·cent produces significant
reduction in present worth cost of appro,v~mately $1060 million to
$7070 million. This reduction is due to the lower expense of
supplyi-ng the plants with the necessary fuel to power the units.
-Fuel Cost Escalation
Fuel cost escalation sensitivity was assessed in two methods.
The fir·st was assuming zero percent esc a 1 at ion for. all three
major fuels and the second was to assume zero percent for coal
only5 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 cast~ of zero percent escalation for all fuels shows a dra-
matic rE~duct ion in present worth cost of $3570 mi 11 ion over the
base case thermal scenario (Table G.l2)e
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 stil1 sig-
nificant and amounts to an annual savings of $1210 mi 11 ion \)Ver
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 1 ife therefore became 45,
45, and 30 years for· coal, gas and oil facilities respect.ively.
The extension of the economic 1 ife results in a gain in cost of
approximately $280 million for the thermal generation scenario.
G-17
"
~· ~~ermal Ca1utal Cos~
"
Capital costs are ;.mother area of concern 111hich has been· address-
ed in an attempt t.o negotiate the uncertainties associated with
costing work or structures in r·emote areas. Al_though the costs
developed ar·e believed to be the best possible -estimates that can
be made a.t this time, the costs of all thermal plant types have
been reduced. by 22 percent.
As would be e1-<pected from a logical inspection at the system~ the
reduction in coal plant costs results in coal becoming more eco-
nomically vi ab 1 e as an energy scource. Capital costs reduc~. ion
therefore shows a gain in coal capacity genelration of 200 MW over
the base case thermal plan. The long term present worth cost is
reduced to $7590 mill ion, a reduction of $540 mill ion from the
base case ..
G-18
I
I
I
I
I
I
I
I ,,
I
I
••
I
t
I
I
I
I
t
•• ... ~ -•
Program/
Developer
· GENOP/
Westinghouse
PROMOD/EMA
OGP/GE
load
Modeling
Oone by two
external
programs
Done by one
external
program
Done by one
external
program
'-.
•••• .,
TABLE G.1 -SALIENT FEATURES Of GENERATION PLANNING PROGRAMS
Generation $timization Re li86il fty Production Availability and
Modelirrn Available Criterion Simulation Cost/Run _,_,._
Done by one yes lOLP oL" Deterministic or $SOO to validate
external ~ reserve J.bdified .Booth -learning Curve
program Baleriaux Costs
$300 -$800/run
Done by one no LOLP or tlndif.ied Booth -$2 1 500 to validate
external % reserve Baleriaux on IYHSHARE
program learning Curve
Costs
$300 ·· $500/run
Done by one yes LOlP or Deterministic or ,MI validated
external % reserve Stochastic Colll!lhia & Buffalo
program Experienced
Personnel
$50 -$800/run
----~~~--~, .. -~ .............. , .............. ~ ......... -:~~-~-----............................................ ~
Year
1980
1985
1990-
1995
2000
2005
201'0
TABLE G.2 -RAILBELT REGION LOAD AND ENERGY fORECASTS
USED fOR GENERATION PLANNING STUDIES
L 0 A D CASE
"
Low Plus Load
Management and low Mediun
Conservation
(LES-GL)2 (MES-GM)3 (LES-GL Adjusted)l
--Load toad . Load
NW GWh Factor MW GWh Factor MW GWh factor
-\M·\
510 2790 62.5 510 2790 62.4 510 2790 62 .. 4
5.60 3090 62.8 580 3160 62.4 650 3570 62.6
620 3430 63.2 640 3505 '62 •. 4 735 4030 62~.6
685 J810 63.5 795 4350 62.3 945 5170 62.5
755 41'240 63.8. 950 5210 62.,3 1175 6430 62.4
835 4690 64.1 1045 57011 62.2· 1~180 7530 62.3
920 520.0 64.4 1140 6220 62 .. 2 tt:J5 8940 62.4
Notes:
High
(HES...CU)4
Load
MW GWh factor
510 2190 62.4
695 3860 63.4
920 5090 63.1
1295 7120 62.8
1670 9170 62 .. 6.
2285 12540 62.6
2900 15930 62.7
(1) LES-GL: low ~'conomic growth/low governlf.ent expenditure with load management and conservation.
(2) LES...GL: low ~w:anornic growth/low government expeqditure.
(3) MES..,;GH: Mediu,,• economic growttt/moderate governmt!nt expenditurE!.
(4) HES-GH: High ~11~omic. growth/high government expenditure.
..
I
I
I
I
I
I
I~
I
I
I
I
I
I
I
I
I
I
~-\
. ·. ... ... ~. . . . . . -.. . . . . . . .
I ,,
I
I
I
I
• t
I
I
I
I
I
I·
I
I
••
I ' r
I
I
TABLE G.,J -LOADS AND PROBABILITIES USED IN GENERATION PLANNING
FORECAST 1 PROBABILITY SET
LE.S-LG
LES-MG
MES-MG
HES-MG,
HES-HG
Notes:
( 1) LES:
MES:
HES:
LG:
MG:
HG:
Low economic growth
mediun economic growth
high economic growth
low gov~rnment expenditure
moderate government expenditure
high gov~rnment e~penditure
.10
.20
.40
.20
.10
-...:·
I ,,
I
TABLE G.4 -FUEL COSTS AND ESCALATION RATES I
Natural Cos Coal D~stlllate I
I -sase Period (Januarl 1980)
:::-··~--:-:-:-: :::-.. --:: -Prices ($/million Btu)
I Market Prices $1 .. 05 $1.15 $4.00
Shadow (~port unity) Values 2.00 1.,15 4.00
I
Real Escalation, Rates (Percentage)
-Olange Compounded (Annually)
1980 -1985 1.79~ 9.56!'0 3 .. 3ara
I 1~.186 .... 1990 6.20 2.39 3.09
1991 -1995 3.99 -2,.87 4.27
Composite (average) 1980 ... 1995 3.98 2a93 3.58
.1996 -2005 3.98 2.9J 3 .. 58
2006 -201G 0 0 0
..... -~ I
I
I
I
I
-::1 I
I
I
I
I
I·~ ,,
I
I
I
I
I
I
I
I
' I
ll
I
I ,,
t
I
I
TABLE G.5 -ANNUAL FIXED CARRYING CHARGES USED IN
GENERATION PLANNING HODEl
30-Year 35-Year
Project CiFe7f:z:ee
3b-Year
Thermal Thermal Hydro
(~} (~) (%)
ECONOMIC PARAMETERS (0%-3~)
Cost of Honey 3.00 3.00 3.00
Amortization 2.10 1.65 0.89
Insurance 0.25 0 .. 25 0.10
TOTALS ~ '4.9'0" T.'99'
FINANCIAL PARAMETERS (7%-1~) -
~pn-exe!!!Et
Cost of !obney ·m.oo 10.00 10.00
Plnortization 0.61 0.37 0.09
Insurance 0.25 0.25 0.10
TOTALS 1"0.86 TIJ:b! 10.19
Tax-e~
Co$t of fobney 8.0IJ 8 .. oo BoOO
Amortization 0.88 0.58 o •. n
Insurance 0.1'5 0.25 0.10
TOTALS n> F.'B'1 T.2j
.._.'f,,.,__.)
ZO-Year
Thermal
(%)
3.00
3.72
0.25
7l:9i
10.00
1.75
0.25
11.00
8300
2.19
0.25
1tr:'4'4'
' -' . ' . ~ . ~ . . .
' "' • ' • -: ..... • • • 0
TABLE G.6 • TEN YEAR BASE GENERATION PLAN MEDIUM LOAD FORECAST
SVS1£R~RRi totAL
YEAR MW HW lim ott ott CAPABILITY
Committed Retired COAL GT GT DIESEL cc HY (MW)
1980 54 470 168 65 141 49 947 1
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 (NGGT) 54 456 168 65 201 49 993
1986 50 456 168 65 201 49 993
1987 4 (Coal) 50 456 168 65 201 49 98.9
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 1-!'.t-4 1079
Notes:
(1) This figures varies slightly i~rom the 943.6 MW reported due to internal
co~uter rounding ..
I
·I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I ~'
I
~'*
I
--·--------·--·----
TABLE G.7 -SUSITNA ENVIRONMENTAL DEVELOPMENT PLANS
Cumulative
St~/Incremental Data S~stem Data
Aiinu~· ( C::...t.
Maximum Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$Millions fu-1 ine full Supply D&·aw-firm Avg. factor
Plan Stage Construction (1980 values) Date 1
level -ft. down-ft GWH GWH. ~
E1.1 1 \tlatana 2225 ft BOIJ.tW
and.Re-Regulation
Dam 1960 199) 2200 150 2670 )250 46
2 Devil Canyon 1470 ft
40lliW 900 1996 '!450 100 5520 6070 58 ;»~
TOTAL SYSTOt 120£ltW '2lJ6l]'
E1.2 1 ~latana 2060 ft 401.liW 1570 1992 2000 100 1710 2110 60
2 \iatana raise to
2225 ft 360 1995 2200 150 2670 2990 85
3 \~atana add 40CttW
capacity and
He-Regulation Dam 2JU 2 1995 2200 150 2670 3250 46
4 Devil Canyon 1470 ft
4000\1 900 1996 1450 100 55·20 6070 58
TOTAL SYSTEM 120£l1W Jmtr
[1.3 1 Watana 2225 ft 400MW 1740 1993 2200 150 2670 2990 85
2 \'latana add 40iJ.tW
capacity and
He-Regulation Dam 250 1.993 2200 150 2670 3250 46
J Devil Canyon 1470 ft
400 HW 900 1996 1450 100 5520 6070 58
TOTAL SYSTEM 1200MW '2lJ9lT
._
TABlE G.7 (Continued)
Cumulative
Stage/I.ncremental .Data System Data
Annual
Haximi..Hil Energy
Capilal Cost. Earliest Res2rvoir 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 ~
£1.4 1 Watana 2225 ft 400MW 1740 199.3 2200 150 2670 2990 85
2 Devil Canyon 1470 ft
40(J-1W 900 1996 1450 100 5190 5670 81
TOTAL SYSTEM BO(ltW 264ii
E2.1 1 High Devil Canyon
1775 ft 80()1W and
Re-Regulation Oam 1600 1994 3 1750 150 2460 3400 49
2 Vee 2J50ft 40ll·IW 1060 1997 2330 150 3870 4910 47
TOTAL SVSTEH 120()1W 2660
£2.2 1 High Devil Canyon
J6JO ft 41D1W 1140 1993 3 1610 100 1770 2020 58
2 High Devil Canyon
raise dam to 1775 fl
add 40()tW and
Re-Regulat ion Dam 600 1996 1750 150 2460 3400 49
3 Vee 2350 ft 400 NW 1060 1997 2330 150 3870 4910 47 -tOTAL SYSfEM 1200MW 2800
E2.3 1 High Devil Canyon
1775 fl ~Oll-tW 1390 1994 3 1750 150 2400 2760 79
2 High Devil Canyon
add 40lJ.t\~ capacity
and He-Regulation
Dam 240 1995 1750 150 2.460 3400 49
3 Vee 2JSO ft 400MW 1060 1997 2330 150 3870 4910 47
TllTAL SVSlEt-1 1200 2690
-
--···------------ -
TABLE G.7 (Continued)
Cumulative
Stage/Incremental Data S~stem Data
Annual
Maximum Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$ Millions On-1 ine. full Supply Draw-firrn Avg. factor
Plan Construction (1980 values) 1 level -ft. down-ft. GWH GWU % Stage Date -··
E2.4 1 High Devil Canyon
1755 ft 40ll-tW 1390c 1994 3 1750 150 2400 2760 79
2 High Devil Canyon
add 400HW ~apacity
and Portage Creek
Dam 150 ft 790 1995 1750 150 3170 4080 49
:; Vee .2350 ft
40lliW 1060 1997 2330 150 4430 5540 47
TOTAL S't'STEH 3m
[Jo2 1 Watana
2225 ft 40(}1W 1740 1993 2200 150 2670 2990 85
2 Watana add
400 H\~ capacity
ann Re-Regulation
Dam 250 1994 2200 150 2670 3250 46
3 \'iatana add 5il-1W
Tunnel Scheme 33£l.t\'i 1500 '1995 1475 4 4890 5430 53
TOTAL SYSTEM 118£J.IW 1490
E4.1 1 Watana
2225 fl 40ll-SW 1740 1995 3 2200 150 2670 2990 85
2 \'latana
add 400MW capacity
andRe-Regulation
Oam. 250 1996 2200 150 2670 3250 46
3 High Devil Canyon
1473 ft 40llw1W 860 '1998 1450 100 4520 5280 50
4 Portage Creek
1030 ft 15ll-1W 650 2000 1020 50 5110 6000 51
TOTAL SYSTEM 1350 NW 15l1lf
NOTES:
(f)-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 due to lower .mobilization costs.
(J) Assumes fEftC 1 icense can be filed by June 1904, ie. 2 years lale£' than for.-the Watana/Devil Canyon Plan 1.
TABLE G .. B -RESULTS Of ECONOMIC ANALYSES Of SUSlTNA PLANS -MEOiltt LOAD FORECAST
SusiEna. pevei~mnE Pian Inc. Installed Capacity (HW) by Total System fatal System
lkl 1ne ua"tes Categot~ in 2010 Installed Present Remarks Perta~1ng to
Plan St.a9!:s OGPS Run Tiiermai ll~dro Capacity In Worth Cos~ the Sus itna ru:asin
No. 1 ~ 3 4 Id. No. to a I Cas Oil OEfler Sus iEna 2010-MW $ Billion Oeve-lol;?,!!!!!nt P:h~n
E1.1 1993 2000 LX£7 JOO 426 0 144 1200 2070 5850
E1.2 1992 1995 1997 2002 L5Y9 200 501 0 144 1200 2045 6030
[1.3 1993 1996 2000 l8J9 300 426 0 144 1200 2070 5850
1993 1996 l7W7 500 651 0 144 BOO 2095 6960 Stage 3, Oe~i~ tanyon Dam
not construct.~
1998. 200'1 2005 LAD7 400 276 30 144 1200 2050 6070 0e layed impl~tat ion
schedule
£1.4 '1993 2000 LCK5 200 726 50 11-l4 BOO 1920 5B90 Total develo~t limited
to BOO HW
ltldified
E2.1 1994 2()00 LA25 400 651 60 144 800 2055 6620 High Devil C~6n limited
to 400 MW
E2 .. J 1 1993 1996 2000 L601 300 651 20 144 1200 2315 6370
1993 1996 L£07 500 651 30 144 BOO 2125 6720 Slage 3, Vee. na._,
constructed
not
Modified
£2.3 1993 1996 2000 LEB3 300 726 220 144 1300 2690 6210 Vee dam repl~ by
Chakachamna ~
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 ttf tunnel
reduced by ~n~ercent
E4.1 1995 1996 1998 LTZ5 200 576 30 144 1200 2150 6050 Stage 4 not ~tructed
NOTES:
{1) Adjusted to incorporate cost of re-regulation dam
-----------..
---.. .. -·------.... -...
-
TABLE G.lO-RESULTS Of ECONOMIC SENSifiVHY ANALYSES fOR GENERATION SCENARIO
INCORPIORATlNG SUSITNA BASIN OEVElOPf.iENT PLAN £1.3 -t£0IUM fORECAST
Installed Capacity (MW) by
Parameter OGP5 Run
Categor~ in 2010
[flermai Oeser ipt i<m
ParameEer 9aried Values ld.. No .. roai Cas Oil
R;tdro
Otf1er SusHna
Interest Rate 5~ Lf85 JOO 426 0
9% lf87 300 426 0
fuel Cost (~> million Btu,
natural gm~/coal/oil) 1.60/0.92/3.20 l533 100 576 20
Fuel Cost Ef;calatlon (%,
natural gau/coal/oil) 0/0/0 l557 0 651 30
3 .. 98/0/3.58 l563 300 426 0
Economic Life of Thermal
Plants (year, natural
45/45/30 gas/ coal/ oJll} l585 45 367 233
Thermal Plant Capital
Cost {$/kW 11 natural gas/
coal/oil) 350/2135/778 L£()7 300 426 0
\~atan~/Oev U Canyon Capital
Cost ($ mlill ion, \~atana/
Devil Canyon) 1990/1110 L5G1 300 426 0
2976/1350 L075 300 426 0
Probabil isl ic load forecast L8T5 200 1476 140
NOTES:
{1) Alaska11 cost adjustment factor reduced from 1.8 to 1.4 (see Section a._)
( 2) Excludic\g AFDC
---..
144 ... 1200
144 1200
'144 1200
144 1200
144 1200
144 1200
144 1200
144 1200
144 1200
144 1200
Total total
System System
Installed Present
Capacity Worth
In 2010 Cost
H\'l $ Million
2070 4230
2070 2690
2040 5260
2025 4360
2070 5590
1989 6100
2070 5740
2010 6210
2070 6910
3160 6290
Remarks
20% fue 1 cost ~uct ion
Zero escalati.~
Zero coal cos.l ~:sea lat. ion
Ecor.omic liVEf$; increased
by 50%
Coal capital ~st reduced
by 22%
Capital cost ftlt" Devil
Canyon. Dam in~\~nsed by 23%
Cap ilal cost ftl\' both dams
increased by s~
..
--.. -------.. --------
TABLE G.11 -RESULTS Of ECONOMIC ANALYSES Of ALTERNATIVE GENERATION SCENARIOS
Installed Capacity (MW) by Total System Total Sysi~m
Categor~ in 2010 Installed Present.~t.h
Generation Scenario OGP.5 Run 71iermai R~dro Capacity in Cost -
T~ee Descr ie[ion load forecast Id .. No. -coal Gas lHI 2010 {MW) {$106)
AU Thermal No Rene\'lals Very low 1 Lon 500 426 90 144. 1160 49)0
No Rene~1als low L7E1 700 JOO. 40 144 1385 5920
With Renewals low l2C7 600 657 30 144 1431. 5910
No Renewals Hedillll lH£1 900 801 50 144 1895 ,.., 8130
With Renewals Med illll U1E.3 900 807 40 144 1891 8110.
No Renewals High L7n 2000 "1176 50 144 3370 13520
With Renewals High 1.2£9 2000 576. 130 144 3306 13630
No Renewals Probabilistic LOfJ noo 1176 100 144 3120 8320,
Thermal Plus No Renewals Plus: MedilXll L7W1 600 576 70 764 2010 7080'
Alternative Chakachamna (500)2-1993
Hydro Keelna {120)-1997
No Renewals Plus: Medilh-n lfl7 700 501 10 814 2025 7040.
Ohakacharr~a (500)-1993
Keetna (120)-1997
Snow (50)-2002
No Renewals Plus: Hedium lWP7 .500 576 60 847 1983 7064·
Chakachamna (500)-1993
Keetna (120)-1996
Strandline (20).
Allison Creek (8),
Snow (50)-1998
No Renewals Plus: Medium LXf1 700 426 JO 847 2003 7041
01akachamna (500)-1993
Keetna (120)-1996 "
Strandline (20),
Allison Creek (8),
Snow (50)-2002
No Renewals Plus: MediuR l403 500 576 30 947 2053 7088.
Q)akachamna (500)-1993
Keetna (120)-1996
Snow (50)1 Cache {50);
· Ail ison ·Creek {8},
Talkeetna-2 (50),
Strandline (20)-2002
Notes:
(1) Incorporating load management and conservation
(2) Installed capacity
TABLE 8.12-RESIJlfS Of ECONOHIC ANALYSES fOR GENERATION SCENARIO
INCORPORATING THERMAL OEVELOP.ENT PlAN ~ MEOIUH fORECAST
Tolhl System fatal
Installed Capacity (Mtl) Installed System
by Category in 2010 Capacity Present
Descrietion Parameter OGP5 Run Thermal In 2010 Worth Cost
ParsmeEer Varied Value Id. No. ~oai Cas IHI .__lirdro Total HW $Million Remarks
Interest Rate 5~ lEA9 900 800 50 144 1895 5170
9~ lEB1 900 001 50 144 1895 2610
fuel Cost ($ million Btu,
1.60/0.92/3.20 natural gas/coal/oil) l1K7 600 876 70 l44 1890 7070 20% fuel cost ~lion
fuel Cost Escalation (~,
natural gas/coal/oil) 0/0/0 l547 0 1701 10 1il4 1855 4560 Zero escalationt
3.98/0/3 .. 56 L561 1100 726 10 144 1980 6920 Zero coal cost ~l~tion
Economic Life of lhermal
Plants {year~ natural
gas/coal/aU 45/45/30 l583 1145 667 51 144 2007 7850 Economic 1 i fe ~ased
50%
Thermal Plant Capital
350/2135/778 Cost ($/kW, natural gas/ LAL9 1100 726 10 144 1980 7590 Coal capital cos.t t-educed
coal/oil) by 22~
0
------... -------I
·I
I
I
I
.I
" I
I
.I
I
I
:1
I
I
I
1:
I
I
••
I
-:r.:
16 r-,_.. ______________________________ ..._.
15 .
14
13
12
11
LEGEND
HES-GH = HIGH ECONOMIC GROWTH + HIGH GOVERNMENT EXPENDITURE
MES-GM = MODERATE ECONOMIC GROWTH +MODERATE GOVERNMENT EXPENDITURE.
LES -GL : LOW ECONOMIC GROWTH 't LOW GOVERNMENT EXPE~OITURE
LES-GL ADJUSTED : LOW ECONOMIC GROWTH +LOW GOVERNMENT
EXPEt.JOITURE 1" 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~------------------~-------------------~-4~--------------~ (!) -I
I
0~--------._ ________ ~--------~--------~--------~--------~ 1980 1985 1990 1995
YEAR
2000 2005 • •. 2010
ENERG~ FORECASTS USEO FOR GENERATION PLANNING S.TUDIES_h.;;j
. . F.IGURE G.l •
I
I
I
I
I
I
I
I~
I
I
I
I
I
I
I
I
I
I
I
APPENDIX H
, ENGINEERING STUDIES
r,.
I
I
I
I
I
I
••
I
I
I
I
I
I
I:
I
I
I
I
I
APPENDIX H -ENGINEERING STUDIES
As the project planning studies outlined in Sections 6 and 7 were completed, a
start 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 dcrn type for the two sites;
-To undertake some preliminary design of the selected dam types.
This section briefly outlines the results of the studies to date. A more
detailed description will be incorporated in the Project Feasibility Report.
H.l -Devil Canyon Site
(a) Dam Type Studies ~
A major advantage of an arch dam re.lative 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 dan1. 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 has been 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 rockfill dam.
Not:t~ of these layouts are intended as the final site arrangement~ but each
will be sufficiently· representative of the most suitable arrangement
associated 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 nav-rowest point which is the optimum location
for all types of dam. A brief description of each dam type and
configuration is given below. ·
{i) Thick Arch Dam
As shown on Plates H.1 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 downstream 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 1,400 feet and
a maximum foundation width of 225 feet* The crest elevation is 1,460
feet. The center portion of the dam is-founded on a massive mass
concrete pad constructed in the excavated river bed.. This central
section incorporates a service spillway with gated orifice spillways
discharging down the steeply incline,<! downstream face of the dam into
a single large sti 11 ing basin set be! low river level and spanning the··
valley with sidewalls anchored into solid bedrock.
H-1
The main dam terminates in thrust blocks high on the abutments. The
left aeutment 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 hy means of a rockffll dike, which is
founded on bedrock. The powerhouse. houses 4 x 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 b 1 ocks 1 oc a ted on the abutments •
The main service spi 1lway is located on the right abutment and
consists of a conventiona1 gated contra 1 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 supp1emented by orifice type spillways located
high in the center portion of the dam and discharging into a
concrete-1 ined plunge poo 1 immediately downstream of the dam. An
emergency spillway consisting of a fuse plug discharging into an
un 1 ined rock channel 9 terminating we 11 downstream, is located beyond
the saddle dam on the left abutment.
The concrete dam terminates in a massive thrust b iock on each abutment
which, on the left abutment, adjoins a rockfill· saddle dam.
The service and auxiliary spillways are designed to discharge the
1:10,000 year flood. Excess flows for stof'ms up to the probable
maximum flood, wi 11 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, upstrean and downstream s 1 opes of
1:2.25 and 1:2 respectively, and contains approximately 20 million
H-2
I
I
I
·I
I
I
I
I
I
I
I
••
I
I
I
,'1
I
I
;I.,,
I~
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
1\
. '
cubic yards of material. The central imper'{ious core is suppor·,ed by
a downstream semi -pervious zone. These two zones are protected up-
stream and downstream by filter and transition materials. The she.11
sections are constructed from b 1 as ted rock. A 11 dam sections are
founded on sound bedrock. External cofferdams are founded on the
riverbed a-lluvium.
A single spillway consisting of a gated control structure, chute and
downstream unlined plunge pool is located on the-t-xigtrt abutment. This
is designed to_ pass without damage the 1:10,000 year routed flood.
Excess :apacity 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 imnedi ate ly upstream in the Cheechako fan and ter-
races.. The gravel and sands are fctrmed from the granitic and metamorphic
rocks of the area, and at this time it is anticipated that they will be
sui tab 1 e for the production of aggregates_ after a moderate amount of
screening and washing.
r~aterial 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 mile upstream reach of the river; however, 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-
c 1 ude any of the dam types from consideration.. A rockfi 11 dam wou 1 d 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 discharging into a spillway 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.
Under hydrostatic and temperature loadings stresses within the thick arch
~' dam are generally lower than for the thin arch alternative. However,
finite element· analysis has shown that the additional mass of the dam under
seismic loadi.ngs produces stresses of .a greater magnitude in the thick arch
dam than in the thin arch dam. At a particular section, if the surface
stresses approach the maximlln allowable, the remaining understressed area
of concrete is greater for the thick arch and the factor of safety for the
H-3
..
-------.;----:------o-----~-----,-----. -~~-. -.-· ---~----,--~----;:--. ,~. ----~~~~~-
factor of safety for the dam is correspondingly ~igher. The thin arch is,
hO\t~ever, a more efficient design and better utilizes the inherent proper-
ties of the concrete. It is designed around acceptable predetermined
factors of safety and requires a much smaller vo1ums 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 advantageous anrl 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 1 arger 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 de-
signs in which the upstream rockfill slopes are revised from 1:2.25 to
l:2o75 to meet possibly more ·stringent seismic design requirements would
led to increased costs. These cost increases would occur in the dam itself
and in spillway and power facilities because of the larger base v1idth of
the dam.
Studies have therefore continued on confirming the feasibility of the thin
ar.ch alternative.
.I
I
I
I
I
I
I
I
(d) Preliminary Arch Dam Design I
Both thin and thick arch dam designs were originally analyzed by means of a
computer program based on finite element analysis~ Results from these I
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
1
_
for both dams although somewhat higher in the case of the thick arch dam~
Stresses close to the foundati.ons and abutments were distorted by the
finite element model because of the coarse mesh spacing of the selected
nodes. To produce results which could more readily be inter-preted, it was
decided to use the trial load method and the associated program Arch Dam
Stress Analysis System (ADSAS) developed by the USBR. The results of this
analysis are presented in the· foJ lowing paragraphs.
The thifl, two-center arch dam design is located approximately normal 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 Joads no ten-
sion is evident at the dam faces. Under extreme temperature distribution,
as determined by the USBR progr~ HEATFLOW~ for full reservoir conditions
there are low tensiie stresses on both faces across the crest of the darn ..
These approach the allowable ten~ile stress of 150 psi.
Although analysis has still to be finalized for seismic loadings, indica-
tions are that the concrete thin arch dam at Devi 1 Canyon will be
structurally feasible~
H-4
I
I
·.I ,•
II
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I· I
l. " .
H.2 -Watana Site
(a) Darn Type Studies
A rockfi 11 dam 1 ayout, Plate 12, has been studied at Watana with the dam
sited between the northwest trending shear zones of the 11 Fins11 and the
11 Fingerbuster 11 • 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 2,225 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 spillway,
diversion and power plant facilities are continuing.
(b) ConstructiPn Materials
At this time it is assumed that 50 percent of the rockfill for the shell
materia 1 for the dam wi 11 be blasted rock of which a sma 11 proportion wi 11
be obtained from site excavations and 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 rockfi 11 dam~ a three center concrete thin arch
has b~en considered~ and layouts are sho\'.11 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 fCJ fill within the rockfill dam. Although water
passages will be shorter for facilities associated with the concrete dam it
is anticipated that these will be offset by savings in the spillway excava-
tion 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 Dam 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 ~hro~ghout the world on
similar sizes of dam 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 IV: 2H.
The core is composed of materials from the fine ti 11 deposits and the she 11
is presently considered to be constructed from blasted rock from site
excavations and from borrow and gravel material from the riverbed.
H-6
I
I
_I
I
I
I
I
I
I
I
I ,.
,·:1
{I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
FLOW
• ~11,000
\
l
I
" " "" '1
I
I
J
I
/
/
I
\
' I
I
~cP
/
-4~
·' • ... ~""'-""'
..... / --
.,...
!/
J' i'
,/ 1 ~0
0 If!?
0 "' ::> I
I
)
0
GENERAL ARRANGEMENT
:z
z
0
t=· g
ul
-1
lll
.£1-.1455
FOUHOA.,,.ION: GR~UTI~<i --·
A,.O pJ;"'IN<A-4 TU~I-Jiioi..S
'900·---~
1500-
'
+ -L----~---------~~
DOWNSTREAM ELEVATtON. OF DAM
c::;;.~~ ANGt.S.(~t:..)
'S'i. ~~~~~~F=~------~~---------~
IC'l ~~· ~ 1200--~--~--~~~~------------------~~~~-----t---
IL
;. Q~\ z: 1100 --------1J..-!p:;.=~H:o--------,-----"" :..-----+·
0
~ ::;;
~ 1000----~------~~~~~~~~------~~~--~~-~~---t
Ill
AJl2CJ4·· GRAVilY DAM GEOME.TRY
PLATE Hlt..
DE.VIL CAN>tON
ARCH GJ<A.VtTY OAM SCHa.E
PLAN AJ.JO SE:CTlONS
··~
••
I
I
I
I
I
I
I
I
I
I
I
I,
••
1-
.... ' ... ...... ;:-
UQO
~
-~-~--....
ARCH-GI<AVl"TY DAM LAYOUT
~ ICIQO --------1i\-----
'!
2
0
j:
~
1.11
..J
111
..._
til
Ill
b..
z
z
()
i= ~ ill
ii\
qoo.-
cOHc:t<li.TE
l..INING
,goo ------------!!''-.!..' . .!....!..'. !.! :! .• ..
SE..CilON AT SPILLWAY SECTION AT WEIR
1500-
l40o---/
1?.>00-..
e,
I'ZOO-...
A
1100 ...
PROFILE.. OF EM£R.GECV SPiLLWAY
I -1100
--1000
'\' ,\
••oo-··
MUt.il~UOVEL INTA\C£
ST~UCTO~e------~t~
l-
U!
Ul
I.L.
2 1'200-··
2
Q
~ ueo-
> ~-
CON~!:: UNING-
'2 .. ~
POWE-r<. F'ACIL.ITIES Pi<OFILE.
1500 ----
1400 --.-· -~ -
t 1'2.00 -~ .
Ill u.
~
z
0
-~
>
1100 -
~· 1000 ---
Ul
~00 -····
.BOO-
-IEOO
-r400
-1!100
.-1200
-lrOO
; . ...:--·-~-------..___;-
CONCQE."'!'£. i.INING
3' ,..tiC..
l
SECTION !.114R!.l DIVERSION TUNNEL
;-
1
l
·~-
14'50 --~·
~
% .-..... '*=""-<:':OI<'IGI~L. Gli!OONO
0 1-----f+o..! ---~RF..._CI!'.
1l 1!.50 --+---l ~ EtM~EJJC'f ePIL,lWA'{
... ~1"ME.NT
SE.CTION A·A. SE.CTlON B· B . ..
,
\' ~\
''\··. • .. \•,··· . MA_~. -rw. '-__ . 1. El.."l'2.S'
" ' ~·
-1000 PLATE H2~.
JIJIJI,~.-_A_lA_S_K_A_· P_O_W_E __ l_A_U_T_H_O_i!.J]_ .. _lf---.~
.. .t\ll!.lTNA tlYti'ftOE:Lf.t::UIIt: ·;tUt:.M-t;'l'
{)EVIL CANYON
ARCH GR.A.VliY .OAM SC~a£.
5E.CTIONS
I
I
I 0 •. /
?100~ •
I
I
I
I
I
I
I
GENERAL .. ARR~NG~MENT
GEOMETRY TYPlCAL ARCH SECTION
NOTES:
l) •"PCC.•It..~_OIC,t.,Te.S PCit.IT OF C~£ oF CURII.}iUitE..
Zl ~r:.; lNDIC~'t"!!S C!.N1Vt; Cit F..lttAAPOS AACHf
at "1·· l!o.IOICATE.5 C~ OF lN7AAOoS ARCtf, •
41 !WE 5UI'SCRIPr •r:l INOICI'T~ ~ ~~_:,
~~ THE svesc.RrPT •c• WOICA..~ CENTAA\. SE6t1elo.it.
Q 'Tl1E ,!)I.IIS~IPT \.• lNPl~T!lGc 'L$f'~ !>lOll_ . Ol"! ;,1,~1\ \..DOl(IN6 .. !JPSTR~~ ·.
41 T.HE, SU!!I~CRIPT •R' lNOic:.-.'tl!:$ ~KT ~ltl!: OF #.RC~ i.COl(l!-16 UP':mti:AM. .
&l TIIR.U~'!' ~U)CI(.~ Mil Nl;::r ~fiOV(liil. }
9l CONTO!.Ut: ~JNE.S ~OW MOUND SURI'".AC~ ~
f
I :
'
AA.Clol :~·-COMPOUND~ A~{Pl -AN61L · "l_1:1e.3 l NO. tt::tt"O·· ~?CC(ceG.}! \..EI"T ·~-::-
t leZiS =s.s l 51 se
z.. tloo ~3 •. 0 54 ~-
~ \9~0 3Z..5 ~s * -4 l&i:>O SI.O-4!.5 «
!:f t6!50 ~9,0 40.!5 "' ......
6o l&OO Z9,0 3? ~
7 t~ 0 z~ :e:s:
TABLE OF ARCH ANGLES
PLATE 113
WA.IANA .
ARCH DAM GEoM~
I
I
··I
I
I ,...,_,_c
I
••
1:
•••••
' .
I .. .~
;.,,_:_~-~~,---·-.>""---,-
·~
"(T'''
~ ~00
~ -
3
2 2'i00
w
V> ......
01
ifi 2ZOO
C'i ..... -('I t -
"Z 20CIO '•' 0
!i ':>
11.1 1eoo _, ...
lti>OO
2200.
16>00
1qoo
1200
1000
eoo
,.....
~~ .....
c1 u
}
~ ~00
0
200
9ee. teso~&7'
(NOT TO SCALE)
y·
ID
V)
N -
tJ)
"<r".·
0
""
2500'
--~---~-j ~ :: +----------~----~~-------~...._,.'--..::::>l:"=--'~-----------_jt _______ ~-::"'.-...-:-T-::'·~~--~.....--
7: /.,· ~r
0 E~CAVATION t.INE ~ fu ~ (t!OWNS"l'R£AM FACE o'F ABUTMENT) ·no:
~ 1700
..) w
1300
R,«<!$ o .. 410501
.a..i700'
PROFILE OF DAM LOOKING UPSTREAM
tNTRAOOS F..loCE. . CENTE~UNI'i
EXTRADOS F.ACE ~'T!:'tUN!::
G.to. I
. --·--" ,, . ....,._..,._,.,......__ .. __________ _
(NOT OEVEl..OPEO}
~~ 0 L---~4---~-L~~r--~~~*---~~~~~~~.-.--r~-.~~.-~rr~~----~---.---.~--,---~--~r---,---~--~r.~~~--~-x
2200 24oo uoo ~ 3oao ~o .:!4oo Ul:lO. .seoo 4000 1BOO 2000.
OIS'T.~Ce:. (Ft)
,~ .
I ZOO
j
~' '
to86.~e'
foe.1>. o11' PLATE H4
SECTIONS ALONG· PLANES. OF CENTERS
I ,~ ,.
I
I
I
I
I
I
I,
APPENDIX I
----· ENV IRONf4ENTAL STUDIES
I
I
I
••
I
I
I
I,
I
•-
;,::, -~ •'-
I
I
I
I
I
.I
I,
I.
I
I
I
I,
I
I
I,
I
I
,I
.·I
APPENDIX I -ENVIRONMENTAL STUDIES
On performing an environmental review of the various development options within
the Susitna Basin, Acres' environmental subconsultant, TES, prepared two reports
entitled "Prel·iminary Environmental Assessment of Tunnel Alternatives" and
''Environmental Considerations of Alternative Hydroelectric Development Schemes
for the Upper Susitna ·Basin... These reports as submitted are contained in this
Appendix.
I.l -Summary
These reports, augmented uy additional information that became available
subsequent to their preparation, formed the basis of the comparison of the Devil
Canyon Dam with·"tfie:tunnel alternative and the reach by reach comparison of
· Watana/Devi 1 Canyon versus Hi·~h Devi 1 Canyon/Vee deve 1 opment plans.
The environment a 1 assessments of therma 1 deve 1 opments and of Alter-n at i ve
Hydroelectric developments outside of the Susitna Basin are given in Appendix B
and c~ respectively.
(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 the re-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 wildlife 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 much of the characteristics of the Devil Canyon
gorge which is considered to be an aesthetic and recreational
resource.
(ii) ·Social Compariso[
Table 1.2 summat"izes 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
equa11y9 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
eva 1 uati on criteria.
1-1
(b) Watana/Devi 1 Canyon versus High Devi 1 Canyon/Vee
{i) Environmental Comparison
The evaluation in terms of the environmeotal.criteria is summarized
in Table 8.3., In assessing these p1ar:s, a reach by reach comparison
is made for the section of the Susi tna River between Portage Creek
and the Tyone River. The t-Jat ana-Devi 1 Canyon scheme wou 1 d create
more potential envi ronmenta 1 impacts in the vlatana Creek area.
However, it is judged that the potential environmental impacts which
would occur in the upper reaches of the river with a High De vi 1
Canyon-Vee dave lopment are more severe i. n comparison over a 11.
From a fisheries perspective, both schemes would have a similar
effect on the downstream anadromous fisheries although the High
Devi 1 Canyon-Vee scheme would produce a sli.ghtly greater impact on
the resident fisheries in the Upper Susitna Basin.
The High Oevi l Canyon-Vee scheme would inundate approximately 14
percent (15 miles) more critical winter river bottom moose habitat
than the Watana-Devi 1 Canyon scheme. The High Devi 1 Canyon-Vee
scheme would inundate a large area upstream of the Vee site utilized
by three subpopul ati on of moose that range in the. northeast section
of the basin;:; The Watana-Oevi 1 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 subpopu1ation of moose utilizing this Watana
Creek Basin and the quality of the habitat appears to be decreasing.
Habitat man~pu1ation 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 Oevi l
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 potentia 1 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 cre~ating a greater potential diversion of the
Nelchina herd's range. In addition, a larger area of caribou range
would be directly inundated by the Vee reservoir. -
The area flooded by the Vee reservoir is a 1 so considered important
to some key furbearers~ particularly red fox. In a comparison of
this area with the Watana Creek area that would be inundated with
the Watana-Devi 1 Canyon scheme, the area upstream of Vee is judged
to be more important for furbearers.
I-2
I
I
I
I
I
I
I
I
I
I
•••
I
I
••
I
3.
;I
I
I
I
·-
1
I
I
I
I
I
I
I
i
I
I
I
I
I
I
I
I
As pre"iously mentioned, between Devil c-anyon and the Oshetna River,
the Susitna River is confined to Q re1atively steep river valley.
Along these valley slopes are habitats important to birds and black
bears. As the Watana reservoir would flood the river sectic~
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 ~his river valley slope habitat.
f:~om the arch eo ~.ogi ca 1 studies done to date, there tends to be an
increase in site intensity as one progresses ~awards the northeast
section of the Upper Susitna Basin. TI1e High Devil Canyon-Vee plan
would result in more extensive inundation and incrPased access to
the northeasterly section of the basin. This plan is therefore
judged to have a greater potentia 1 for directly or indirectly
affecting archeological sites.
Due to the wilderness nature of the Upper Susi tna Basin, the
creation of increased access associated with project development
caul d have a si gni fi cant influence on futur·e 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 nQrtheasterly section of the basin. This plan
would, thus, create inherent access to more wilderness than would
the Watana-Devi 1 Canyon scheme. As it is easier to extend access
than to 1 imi t it, inherent access requirements are considered .
detriment a 1 and the Watana-Devi 1 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 Wataoa-Devi 1 Canyon development plan is judged to be
more environmentally acceptable than the High Devil Canyon-Vee plan.
Although the Watana-Devfl Canyon plan is considered to be the more
environmentally compatible Upper Susitna development plan, the
actual degree of acceptabi 1i ty is a question being addressed as part
of ongoing studies. o ·
(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.-Devi 1
Canyon plan is judged to have a slight advantage. over the High Devil
Canyon-Vee plan. This TS because of its great~r potential for
displacing nonrenewable resources.
I .. 2 -TES Report
Reports prepared byTES on the environmental assessment of the Devil Ca':lyon Dam
versus the Tunnel altel~nati ve and Watana/Devi 1 Canyon versus High Devi 1
Canyon/Vee development plans are given in their entirety below.
I
I
I
"I
I
I
I
••
I
I
I
I
I
I
I
I
I
I
I
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
PRELH~INARY ENVIRONMENTAL ASSESSMENT
OF TUNNEL ALTERNATIVES
by
Terrestrial Environmental Specialists, Inc.
Phoenix, New York
for
Acres American Incorporated
Buffalo, New York
December 15, 1980
·o
..
TABLE OF CONTENTS
1 ~ 'INTRODUCTION ..•... , •..•.•.... 0-...................... ~ ••• ~ ••••
2-COMPARISON OF TUNNEL ALTERNATIVES.a .•....•.•..•.•.......••
2.1. Schem~ l.e .. , •.....•••. , ..••.••.................•
2.2 Scheme 2 •••..••...•.•..••.•.....•.............. ~
2.3 Scheme 3 ..•...•..•..••...•.•....•..••.••..•.•.•.
2. 4 Sche·me 4 ......... tit ••• ~, ...................... = ........ .
2.5 Location of Devils Canyon Powerhouse .....•...•••
2.6 Disposa; of Tunnel Muck ........................... .
3 -COMPARISON OF SCHEI~E 3 WITH CORPS OF ENGINEERS' SCHEME .•..
APPENDIX A -DESCRIPTIOf\iS OF TUNNEL SCHEMES
APPENDIX 8 -AMENDED DESCRIPTION OF TUNNEL SCHEME 4
Page
1
3
3
3
3
5
5
·6
8
I
I
I
;I
I
I
I
;1.
I
I
·I
I
I
I
I
I
I
I
I
I
I
I
I
I
·a
I
I
I
I
I
I
·I
I
I,
I
I
I
I
1 -INTRODUCTION
fl
In response to a request by Acres American, Inc. for input into
Subtask 6.02 of the 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 Carps 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 firms. Copies of these ·letters may
be found in the appendices to this reporto 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 fluctua~ions of Watana are as described
by the Corps of Engineers and would not differ among the .five schemes.
If, on the contrary, any of the tunnel schemes increase the
probability that the pool level at Watana may be lower than that
proposed by the Corps or if a particular scheme may moderate the pool
fluctuations, then the environmental assessment of the tunnel schemes
may, in turn, be affected.
1
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 sclieme 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
.. 1 ,.
I "I
I
I
I
I
I
I
·I
I
I
I
I
I
I
I
I
I
I
I
••
I
I
I
I
I
I
I
I
••
I~
I
I·
I
·I.
I
I·
I
I
2 -COMPARISON OF TUNNEL ALTERNATIVES
2.1 Scheme 1
The environmental impacts associated with this tunnel scheme are
1 ikely to be greater than those of at least one of the other tunnel
schemes eva 1 uated (i.e. Scheme 3). The ma·in 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 Dev i 1 s 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 Devi 1 s Canyon powerhouse ( 4000-14000 cfs). Without the
re-regulation dam, however, less land would be inundated and the
impacts associated with can~;truction 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 potent i a.l prob 1 ems connected \'lith tunne 1 .muck
disposal.
2.3 Scheme 3
The overall environmental impact of this scheme is considered less
tharJ that related to the two previous schemes, and a]so 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 des irab1e for maintaining downstr~am fish habitat and ·
recreational potential. Since it. may allow anadromous fish access to
3
I '. f
• I .. , .
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 manage_ti 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 Canymi will
still constitute a barrier to fish passage. The data needed for this
determination are not yet avai 1 able.
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
wi 11 augment the compensation flow under this re-regulation scheme,
the compensation flow will netad to be slightly greater than with the
other schemes to result .;n the equivalent flow at Devils Canyono
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 bypas·sed 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 w·ith 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
improv~ments to that hatitat may be somewhat greater, though, '!lith the
constant flows allowed in Scheme 3 than with the variable flows
resulting from pe~aking in the other tunnel schemes.
One environmental disadvantage of this scheme compared-to the others
is the larger area to be inund·ated by the re-regulation res~rvoir.
This area includes known archt!ol\ogical sites in add·ition to wildlife
habitat. Nevertheless, it-is' felt that this di?advantage is offset by
the more positive enviJ"onmental factors associated with constant
disch.arge from the De 1iils Canyon powet-house.
4
I
I
I
I
I
I
I
I
I
I
·I
I
I
I
I
I ,,
I
••
I
I
I·
I
I
I
I
I
I
I
·-
1
I
I
I
I
I
I
I
2 .. 4 Scheme 4
Scheme 4, as originally described (Appendix A), was determined to be
environmentally.superior to the othertunnel schemes, because of
constant downstream flows combined with the lack of a lower reservoir • .
However, Acres • analysis determined that this base load operation is·
most likely incapable of supplying the peak energ-y demand. ·Scheme 4,
as amended (Appendix B), is a peaking operation at Watana \'lith
baseload operation at the tunnel. Since the net daily fluctuations in
flow below Devils Canyon would be .considerable (in 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 tunne.l 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 tunne 1 muck and for the required 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 about 5 miles above
the proposed Corps of Engineers dam s'ite and a downstream location
about 1.5 miles below Portage Creek; as alternatives to the site
illustrated in Appendix A. The major envirtmmental 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
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 f1 ows. through the canyon wi 11 st i 11 constitute a
·,.
barrier to fish p·assage.
Our primary responsibfl ity 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 thi-s 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, construct ion 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
reco111nendation cannot be made without further evaluation. It is quite
1 ikely, 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~ proviaed 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
. . .. . . t . .. • . ,// .. • . . ~
I
I
·I
I
I
••
.I
I
I
I
I
I
I
I
····0
I
_;.
I
I
I
I
I
I
I
I·
I
I
I
I
I
I
I
I
I
I
I'
I
I
..
Another acceptable solution might be to stockpile the material for use
in construction of the re-regulation dam. This-rock could also be a
potential source of material for stabilization of the reservoir s
shor~line 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 sh·ould be given·to the
feasibility of usi:1g 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 occur·rence of such minerals.
To pile, cover, and seed othe 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
ttansport .a portion of the muck back for disposal in the reservoir
area.
The most economical solution might be. to fill a ravine with the
material or to dispose of it in another convenient location. Unless
tt'le chosen disposal site will eventually be inundated, however,
such an arrangement is environmentally unacceptable, especially since
better opt ions are obviously ava i 1 ab 1 e.
7
3 -COMPARISON OF TUNNEL SCHEME 3 WITH CORPS OF ENGINEERS• SCHEME
Scheme 3 emerged as superior in Acres • preliminary economic and technical
screening. Aft·er 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 cLfter complete details are available on
Tunnel Scheme 3. At present, many gaps exist in the available data.
Additional information on design, (lperation, and hydrology, combined with
environmental field investigations at the locatians 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 additiona1 study
needs to be performed on whatever scheme is selected to identify its
impacts and to develop mitigation plans.
t
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 (245 ft.) 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-regulation dam would be about
half those of the Corps • plan f01r 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 le:ssened with Scheme 3, particularly with the
powerhouse location upstream of the proposed Corps dam .site. Furthermore,
Tunnel Sche_me 3 may possibly present a rare mitigation opportunity by
creating new salmon spawning hc1bitat that could be actively managed. With
the increase in riparian zone vegetation allowed by Scheme 3, the wildlife
habitat in the stretch of rive.r byp<tssed by the tunnel might be temporarily
improved. The impacts associated with tunnel access and disposal of tunnel
muck necessitated by Scheme 3 are mare 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.
8
. . . . . . • .I . ' '
• •' ' ' • ol
I
I
I
I
I
I
;I
·I
I
I
I
I
I
I
I
I
,I
·I
I
I I" I
I
I
I
I
I· APPENDIX A
I DESCRIPTIONS OF TUNNEL SCHEMES
I
I
I
I
I'
I
I ,,
I <)
I
I'
I
I
I
I
I
I
I
I
I
·I·
I
I
-I
I
70~·-···
I
I
I
·I·
I
I
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 would like you to review the environmental aspects of the tunnel alter-
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 wfll 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 powsi"house wi 11 be reduced to 35 ~1W 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 downstr'eam 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 whi.ch 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
Consulhng Engineers
The Liberty San!( B!!iidiog. Main at Cour!
Buffalo, New York 14202
Telephone 716'·853-75~5 Telex 91-6423 ACRES BUF
Other Offices: Columbia. MO: Pittsburgh. PA: Raleigh, NC: Washington, DC
-·-,_,. j! ,.
I ..... J
Vince lucid
Terrestrial Environmental Speci'alists, Inc.
0\..t.Ober' 29, 1980
2
The general layout of Scheme 4 is similar to Scheme 2. Scheme 4 is a base
1oad 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.
!'re1iminary 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 s:1ould disagree wi.th 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 impacts 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 wi·11 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 ~lnly).
-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 r_equired.
RJW:ccv
ACIZ'~es AMERICAN. INCORPORATED
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
,I
I
I
I
I
I
I
I ..
I
I
I
·I
I
I
I
I
I
I
I
I
I
I
Reservoir Area
{Acres)
River Miles
Flooded
Tunnel Length
(Miles) .
Tunnel Volume
(Yd 3 )
Compensation
Fl 0\'1 ( cfs}
Downs tt·eam
Reservoir Volume
{Acre-Feet)
Devfl Canyon
Pm\ferhouse
Discharge
Dam Height
{feet)
TABLE 1
Susitna Tunnel Sche.11es
Physical Factors
.. COE
Devil Canyon
7,500
31.6
--.
--
1,100,000
Constant
520
1
320
. 2 .. 0
10,749,000
500 .
·~·. · ·:·to-
'1000
9,500 .
Peaking
75
. 2
-0-:
-0-.
29
11~545~000
500
to
1000
-0-
Peaking
3
3,900
15 .. 8 .•
15. a: ~-..
4:285,.000
500
to · ..
1000
350;000
Constant
245
4
0 . -...
., --....
-0-
...
··29 :.: ~ . ... ~
6~494~000
500
to
1000
-0:.4
Constant
• .
D
c
•
A
.~ .
' 0
aooo
t f Ucul . .
~· noo
~
1
~ ··~ ~ '1000
GIOia • •
•
I
16
PI!•1ZINa. 11-oJ t-.-1U .... :'!.
I
1:5
J2!.~~ .AL.tcgNMt:NI (SO-fEMES 1,~44)
" -.:uilN4&. &.4 ..... 1 -·~ .••• ., !• •
.~
Pf~1l:NC!a. I NJ N'!IL.S.:!l
'
F
I
~
-
0
c
a'o
·-·-
10
0
,
c
. .,.... .
.. --
Plf>~E. it'& Mtl..&t.
-
I
10
_SC..UEM~--.3;-;At-JfiNME.NT
-
I
\'
..
•
~.
.. ... _ - -- --• -
t
G
... ._._ ~-..q
-~ ....... '-.C.~&&AUC~ -... --r-........ ' -...,_ . ....
c:>~ ....
~ ~·----~,~~~~~~~~
-
0
I
I·
I _.,
I
I
•=
I
I
I
I
I
I
-I
I
I
I
I
I
I
APPENDIX B
AMENDED DESCRIPTION OF TUNNEL SCHE~1E 4
I
••
I;
I
I
I
I
I
I
I
I
I
I
I
'I
I
I
I
:1
Mr. Vince_ Lucid ·
December 11, 1980
P5700.11.30
T.606
•
Terrestrial Environmental Specialists, Inc.
RD 1
Box .388
Phoenix, New York 13135
Dear Virice:. Susitna Hydroelectric Project
Revised Description etf Tunnel Alternatives
Enclosed please find a memo from B. Wart out1ining our· revised
descript·ion of tunnel alternatives.
Please use thi·s description in your assessment of tunnel alter-
natives. ·
.
In addit·ion, I have completed your table outlining tunnel design
information.
KRY/ljr
Enclosure
·ACRES AMERICAN INCORPORATED
Consulting Engineers
The Uberty Bank Building. Main at Court
Bu'ffalo. N&w Yori< 14202
Telephona 116·853-7525
Sincerely,
(-~-~;(~.;/ ------;~ ~~·
-~......-Kevin Young
Environmental Coordinator
OtMu Offices: Columbia. MD~ Pittsb~,~rgn. PA: Raleigh, NC: Washington. DC
•
I
I
f
l .
L· .
..
OFf!CE MEMORANO\UM
TO: K. Young Date: December 11, 1980
\.
FROM: B. Wart File: P5700.07.07
suBJECT: Susitna Hydroilectric Project
Pre1 il}linary En vi ronmentctl As,sessment
of Tunne 1 A 1 tern at i ve!S
"
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 da·ily load curve similar to that of the
other schemes. The revised description of tunnel Scheme 4 follows:
~·
',.
:a
D
I
I
I
I T~e. general layout of Sche~ 4 is s_imilar to Scheme 2. The operation
of Scheme 4 varies,, from that of Scheme 2 and is described bel ow.
The Watana powerhc1use will remain. at the stage one installed capacity .• ' . ,
or if necessary en1l arged s 1 i ghtly. Pea.k i·ng demands wi 11 be met with
the· Watana powerhouse. At all times ttJe Watana powerhouse wi 11
. generate-h.:a mi.nif!ium .~of ·35 Mw· tt? supfpll~mebnt basewload demdahd
0
s ~n1 dc. ; ·I
supply t e requ1ret.r c~mpensa lf>n o~~ · etween atana an e.v1 anyon. ·
The Devil Canyon p()werhouse 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 I
comparable to other schemes. Daily water level fluctuations do\'mstream · ·
of Devil Canyon are similar to Schemes 1 and 2. Water level fluctuations
bet'ween Watana and l)evil Canyon are expected to be large. I
RJW/ljr I
I
I
I
.I
I .,.
---~---------------
. ..
-~ ·susr;;~A TUNNE\. SCHEMES· .• PHYSICAL FACTORS· .. (Addendum)
• • • "<!' " • J
··;·· • t • . a \ I " • •• ~~.I. 4 .,. .~ .. . ·.. . ,... ... ~. -.. . . . . ,.
· · .. ·· ·Jf17ff~~-' .' . COE . 1 . . . :2. :· · •.. ; : . . . •. · .... 3· · . 4 .
·Range of r1ver stage
bel 0\11 Devil Canyon
powerhouse (cnrre-
sponding to
discharges listed·
above) · ·
Generat·i ng ·
Capacity 04W.l
: .. ...
. . .
. .
dai1Y.
•
seasonal
. .
: ~latana . . . . . . ..
... bev1 1 s .
Canyon .
2i1St>J 6at~, 6tJD
.... ,'f
. · ~.. ... . tB9~: .. . .. '",_, •· ....
.. NA ·
//S"~ ....
• . .
~~sor.·/~t)~P"~ ..... .2!~~-,~()~t:J~O ... . ' •. . . .· . . . .
.
. . $'7o."'' .. .. . : . . .. ;>oS't$ .... . -· . .. ·. ~-· ..
. .
. . A.v~. : NA. ... ., .
' . . .
79C!. . . . :'792:..
. ':?~ ,_.. .. ....... .,~
.
I .
Z.J kjLg.StxJ .Ja~ • 2. > ~ 74) aoo.,) ~oo . . .
. .
·. S"?2!..tf',. · ··f/~a
,.· ·• 0 . -. .. . . • • ..... ··.. j ,. • •. '
'.. . . ~ ., .. .. .. . . ·-. . . . .
~., !.
. . .
AP.pcndix I
GRAPH C-12
-...
"" t.J "'·
-
-trMi -
. i :·• ..
--: --~=-· .. '4 ! -. ~ ... --~ -~ ... •. ; ~: i l
.. -
. .
JIATANA ljQNTHl.Y ST()ftAGE FREQUENCY .
.f9R THE-DEVIL CAlC~ A.~ WATAN·f SYSTEM
~~··! ;·.;~ : :-i -~.; ~-r ':.:~;;~~·! .T i ;.·; .. ~· ~~ i ' : :
~· :-, : . · i. : -.. ! ! : t r ~ r .·: 1 ~ • ~ • : . i . . . .t . -: ' .
------
! l , ..
-
.-
:·.::..'; •. : ·.f' £ ~g;;~~
r : : : •
. . ~ .
. ;
.. -----
" I·
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
1:
I
I
~tiD errsstrial
nvironmentai
~~=?.P~=cialists. inc.
~.D. 1 BOX 386 PtiOENIX, N,'f. 13135
t:,
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
conments on the Vee/High Devil Canyon/Olson scheme in comparison with
the Watana/Devi 1 Canyon scheme. Encht::~d for your revie\~ and co11111ent
is a draft of a brief repor·t entitlej 11 f::uvironmental Considerations of
Alternative Hydroelectric Development .:>chemes for the Upper Susitna
Basin 11 •
We will be pleased to discuss the contents of this report with
you.
VJL/vl
Enc.
cc: R. Krogseng
Sincerely,
Vincent J. Lucid, Ph.D.
Environmental Stb~ies Director
. I
'l
I
·1
. ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
ENVIRONMENTAL CONSIDERATIONS
OF ALTERNATIVE
'JYDROELECTRIC DEVELOPMENT SCHEMES
FOR THE
UPPER SUSITNA BASIN
by
Terrestrial Environmental Specialists, Inc.
Phoenix, New 'York
for
Acres American, Inc.
Buffalo, New York
0
January 16, 1981
al
I
I
I
I
I
I
I
I
ll
I
I
I
I
I
I
:1
,,
,:.,./:·
··-' -·'.!...-
I
\-
c •.
••
I
•••••
I
I
I
I
I
I
I
I
I
I.
I
I:
I
I
I
.
TABLE OF CONTENTS
1 -.INTRODUCTION • • • • • • • o • • • • • ~ e • • • • • • • • •
2 -APPROACH • • • • c • • • • • • • • ~ • • • • • • • • • • •
Page
1
2
2.1 The Deve 1 opment Schemes • • • • ~ .. • • • • • • • • o • • • 2
2.2 Assumptions of Environmental Coestraints •• • • • • • • • •
3 -DISCUSSION • • • • • • • • • • • • Q • .• • • • • • • . . . ~
3.1 Socioeconomics • . • • • • • • • • • • • . . . • • • • • • •
3.2 Cultural Resources • • • • • . . . . . . . . ~ . . . . . . .
3.3 Land Use • • . . . . . . . ~. . . . . . . . . • • • 1J • • • •
3.4 Fish Ecology •••• • • • 0 • • • • • • • • • • • • • ~ • •
3.5 Wildlife Ecology .•••• • • • • • • . . . . . . . ~ . . .
3.6 Plant Ecology • • . • • • • • • • • • • • • a •· • • • . .. .
.
3.7 Transmission Line Impacts •.••••••.••..• • • •
3.8 Access Road Impacts . . . . . . . . . . . . . . . . . . . ..
3. 9 Summary .. • • • • u • • • • .., • • G • • • • • • • • • • •· •
2
3
3
3
4
5
5
7
8
9
9
4 -CONCLUSION • • • • • • • • • . " . • • • • • • • • • . . . . 11
APPENDIX A -DESCRIPTION OF STAGING ALTERN/\TIVES
.,
1 -INTRODUCTION
This report documents preliminary environmental considerations of"
alternative hydroelectric development schemes for~ the Upper Susitna
Ba~in. 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. Hutch is on ·to K. Young for transmittal to TES, I.n~.
(.Append:ix A). Additional details were obtained and the approach agreed
upon in subsequent conversations and data transmitta1 between K. Young
and V. Lucid concerning these alternative development schemes.
The following assessment is based upon a familiarity with the Watana/
Oevi 1 Canyon area obtained dur.ing the first year of environmenta 1
studies. At this writin·g, however, we do not have the benefit of
information to be contained in the 1980 Annual Reports, which are to be
completed by TES subcontractors by March 1981. Becausa much of the Vee .
reservoir lies outside of the study area for many disciplines, cor.ments
concerning this impoundment rely heavily upon intuitive judgement.
•'
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I 11"' ~
;<; I,
' ~
' -·· .. ..-::
••
I
I
i·' I I
·,·-••
I
I
I
I
I
I
I
I'
I.
I
I
I
I
I .
",.. ·~ ~ '-:-,;)-
2 -APPROACH
2.1 The Development Schemes
Environmental considerations were preliminarily identified for two
different hydroelectric development .. schemes for the Upper Susitna
a as in: Watana/Oevi 1 Canyon and Vee/High De vi 1 Canyon/01 son. 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 rnost
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 th1s report are based in most cases up.on
the two ulti·mate·' schemes with occasio~""".a1 references to the staging
options. It was assumed that whateve~-staging alternative is se 1 ected~
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 identi'fication of pQtential advantages and disadvantages of the two
schemes, from a:u 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·reservoirs.
2
Table 1
Descriptions of Two Alternative Hydroelectric .
Development Schemes for the Upper Susitna Basin(a)
'I
I
I
Watana/Oevil Canyon .Y.,ee/High Devil Canyon/01 son - -I
Maximum pool
elevation (ft)
Dam Height {ft)
Installed Capacity "{MW)
Probable On-Line Date
of Last Stage
Daily Peaking
Approximate( b)
. Reservoir Area (acres)
Approximate(b)
River Miles F1ooded(c)
2200/1450
750/570
800/600
;
2010 to 2020
Yes/No
40,000/7,500
(Total= 47,500)
60/30
(Total = 90}
2300/1750/1020
425/725/120
400/800/100+ -
2020
Yes/Yes/No
16,000/21,700/900
(Total -38~600)
95/58/7
(Tot a 1 = 160)
a Derived from des,criptians of three staging alternatives for each
scheme~ which are presented in Appendix A.
b Pre1 imin'ary values.
c Mainstream Susitna only, tributaries not included.
I
I
I
I
I
I
·I
I
••
·I
I
I
• ••
;I
.I
.,
I
I
I
I
I
I·
1:
I
I;
I
I
I
I
I
I
I
I
1:
. .
3 -DISCUSSION
.
Potential advantages and d~sadvantages 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 typ~, degree, and chronology
of socioeconomic· impacts resulting from the various plans under
consideration. An important concern relates· to alternative staging
p 1 ans and associated factors such as: (a) cost of stage, (b) schedu 1 ing
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
"eommunity" will be established. Impacts generally wi11 fail into tw·o
categories: those associated with project economics and construction,
and those associ.ated wit~ power producti:on and sa 1 es. Both types o-f
impacts will exhibit a variety of local, Railbelt~ and statewide
ramifications~ In th~ absence of practically any project economics .
info.rmation, detailed analysis is impossible at this time. In generai,
however, it can be expected that a scheme involving on-1 ine production
capabi 1 ity of 800 MW by the year 2000 will have greater and rrore
significant impacts than a scheme in which that capability is not
attained until 2010 (e·.g .. , Plan 1 compared to Plan 2). This difference
would occur because~ in the 1 atter p 1 an, the demand on res~urces· wi 11 be
spread out aver time. In addition, it is reasonable to expect that the
economic base of Mat-Su Borough Y~i 11 be larger in 2010 than in 2000~ even
without the project. Therefore, there 1 itcely would be a greater capaci;cy
to deal with project impacts.
3.2 Cultural Resources
·Field surveys in the Watana/Oevil Canyon impoundment area'··~during the
surrmer of 1980 have documented 37 archeological sites. A pFeliminary
assessment of the data ·indicates a greater number of archeologic~1 sites
3
towards the east end of the study area. In 1953, a pre 1 iminary field
survey conducted for the National Park Service rrear 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 cariL~ou
crossings of the Oshetna River. In summary, a preliminary assessment cf
available information suggests that there perhaps could be a greater
-
number of archeological sites as,sociated 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 deveJopment schemes (and any of
the staging plans) wfll cause changes i:t 1 and use patterns i.n the Up.pe't"'
Susitna Basin. Re.~ardless of the sr:heme 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/H5gh.Oevi1 .
Canyon/Olson scheme, Deadman Falls will be inundated and Devil Canyon
wi·ll be greatly reduced in scenic vaiue. The Vee/Hi.gh 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 ~.naller reservoir area 1 it would
inundate approxir.1ata1y 70 miles more of the Sus~tna River than would the
Wataaa/Oevil Canyon scheme (Table 1). Development of a. recreation plan
fot' the project wotf1cl 'w'ary accord.ing to the design scheme and staging
plan selectedo
Broader concerns associated with Jand use are related to staging, as
discussed in the previous section regarding socioeconomics.. The
influence of staging on land use in1pacts applies to land use factors
concerned with existing regional transportation systems. The existing
transportation systems (.and cormturritie:~ and land uses associated with
them) which connect to the selected ac._cess route will be affected by
construtction-rel ated activity. In this context, the degree of
I
I
I
I
,I
I
I
••
I
I
••
'I
I
I
ll
I
I
I
I
I
I
I
I
I-
I
I
I
I
11
I
I
••
I
I
I
I
I
••
.
construction-,.elated activity within a given· time frame could be a
significant factor.. This consideration is ·similat to the socioeconomic
concern identified previously. The proportionately greater degree of
construction activity associ_ated •t~ith a plan in which 800 MW capability
would be achieved by ZOOO -as compared with one in which this would not-
be achieved unt11 2010 -concentrates impacts on 1 and uses in a shorter
time frame.
3.4 Fish Ecalo~oc
All. development schemes must be examined with the downstre&m anadromous
fishery receiving primary consideration. Any sc~1eme or staging p 1 an that
allows for daily peaking without a re.-regulation dam downstream could be
detrimental to this resource. Tberefore, 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 De'J•il Canyon/Olson scheme has at least one majo:r
disadvantage, with respect to fish ecology, in comparison to development
at Watana/Oevil 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 mi 1 es of Portage Creek wou 1 d be
inundated. Ever~ with facilities for fish passage, the impacts on this
spawning area. cctuld be· severe ..
Because the Vee/H~ gh De vi 1 Canyon/01 son scheme li#Ould inundate about 70
additional miles of the Susitna River, p1us different tributaries, than
would the Watana/Oevi 1 Canyon scheme, impacts on res idt:nt fish can be
expected to differ between the two schemes. Data are 'not presently
avai 1 able to per·mit. an. assessment of these impacts.
3.5 Wi1d1 ife Ecol~gy
Although the area that. would be inundated by the Vee .reservoir has not
been thoroughly inves.tigated., project pel"sonnel have sufficient
fami1iarit!j with the. area to mak,e a fairly strong reconmendation at
this time. With the exception of impacts on avian species, it is felt
that the Watana/Oevil Canyon scheme is superior from a wfl d1 ife impact
. str.mdpoint to the Vee/High Oe't~il Canyon/Olson scheme. The basic trade-
offs associated with this comparison involve the areas to be flooded by
-~che 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 wi1dl ife than the areas that woulq 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/Oevi1 Canyon
scheme. These areas are important fo.r rr.oose during severe winters and
the additional reduction in such habitat could have a major impact on
moose populations. In add·ition, the Vee impoundment would flood key
winter habitat for at least three subpopu·l at~ons 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 Wat.ana Creek
drainage, is innabitated by a subpopulat ion of nXlose 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 pr-esent. The habitat quality within the Watana Creek drainage aiso
seems to be decreasing. TES has previously reconrnended that the pool
elevation of Watana be lowered to preserve as much of the Watana Creek
drainage as possible. Nevet .. theless:t the trade-off between Watana Creek
and the Vee impoundment favors f1ooding the Watana Creek area.
The area that would be flooded by the Vee: dam is historically used by
the Ne1china caribou herd, particularly in moving to their calving
grounds near Kosina Creek. Although caribou roovement patterns are
highly variable and dppear 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 reser"voir would be subject
to large· drawdown and p·ossible ice-shelving. In addition~ the
th.ree-dam scheme would result in a greater division of the Nelchina
herdes range .due to the greater length of the impoundments involved and
. .
thus increase the likelihood of impacts on this~,oherct.
• I • • • '
I
I
,I=
I
I
I
I
I
I
I
I
I
I
I
:I
I
I
I
I
I
I
I
I .,
I
••
I
I
I
I
••
••
I-
I
I
I
I
= .,
There is an indication that the area to be flooded by the Vee dam is
mai,.e important. to some key furbearers, the red fox in particular, than
areas such as W~tana Creek that would be spared by a Vee dam. There is
also more trapping conducted by resiaents 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
musk~a.t and beaver populations~
It appears that only avian species might suffer less adverse impacts
from the Vee/High Oevi 1 Canyon/Olson scheme than from Watana/Devil
Canyon.. Although the Vee dam would eliminate more river bottom
habitat~ it wou~d spare a considerable amount o'f decid~ous forest
(birch· and aspen) that ·!xists 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 roore. detailed reconmendation could be made if a better data
base 'Nere available, the reasons given ~bove 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 Ecologl
' B.oth schemes will primarily flood deciduous forests (white birch,
balsam poplar, and aspen types), coniferous woodlands and forests
(white spruce and black spruce), and shrub conmunities (alder, birch,
and willow types}.. The;· relative amounts of habitats flQoded will vary
with the two schemes. The Vee/High Devi 1 Canyon/Olson combination wi 11
probably flood more floodplain habitats such as balsam poplar forests~
while the Watana/Oevi1 Canyon scheme will probably flood more birch and
aspen forests.
7
--,• .---------,-::---~-
.
~rhe primary advantage of the Vee/High Oevi 1 Canyon/01 son scheme ·is that
approximately 9,000 fewer acres would be flooded· (Table l). The
primary disadvantage!s of this scheme are: more lakes and wet 1 ands
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
s,ecause of the distance ·traversed, the construct ion of a transmission
line to the interti~ from a Vee/High Devil Canyon/Olson projer-t offers
several disadvantages when compared to a line constructe~ from a
W.atana/Devi 1 Canyon project. A 1 ine from the Parks Highway to Watana
w•ould be approximately 50 miles in length. Following the same route to
Watana and extending the 1 ine to the Vee site would add approximately
40 miles to its total length, an increase in mileage of some 80
percent. Genera11y!t 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
cc)nstruction.. 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
wi 1dl ife 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 1 ine. A greater number of streams tributary to tha
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
I
I
,I
I
I
I
I
I
I
I
:•
I
I
••
I
I
I
I
I
I
I
I
I
I
I
I
,I
I
I
I
I
I
I
I
I
I
3o8 Access Road Impacts
At present, an access route for the Watana/Devi 1 Canyon scheme has not
been decided upon, and no information at all is available with regard to
access for the Vee/High Devil Canyon/01son 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/Oevil 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 lliJre 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/Devi 1 Canyon scheme •. The Vee/High Oevi 1 Canycn/01 son scheme . .
has more apparent disadvantages than advantages; most of these
disaivantages. are due to the Vee impoundment rather than the High Devil
Canyon impoundment. In socioeconomics and in some aspects of land usa,
the differences due to staging are of roore significance than those due to
the location of the darns. Nevertteless, it is noteworthy that the
Vee/High Devil Canyon/Olson scheme may affect rrore canyons and waterfa11s
of outstanding scenic va1ue 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 reservo·fr, perhaps even more
thao in the vicinity of Devil Canyon and Watana. A major disadvantage of
the Vee/Hi'gh De vi 1 Can~on/01 son scheme is the impact of 01 son 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 Ca.nyon/Olson
11 scheme· than 'liith Watana{Oevil Canyon, although_ this is not necessar·ily the
case with birds. Although the Vee/Hi,gh Devil. Canyon/Olson scheme 'ftould
9
flood less acreage than Watana/Oevil Canyon, a larger amount of floodplain
and wetland habitat would be inundated. Because of the longer distance
traversed, potential impacts of the transmission line wo1uld 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 1 ike1y result in a larger impact zone que to increased access.
10
I
I
I
I
I
I
I
I
I
I-
I
I
I
I
I
I
I
I
I
J·
I
I
I
I
I
••
I
••
·I
I
I
••
I
I,
••
I
I
I
4 -CONCLUSION
.
Although some potential advantages and disadvantages have been
identified for both the Wat-ana/Oev-i 1 Canyon scheme and the Vee/High
Devil Canyon/Olson scheme, sufficient information is not yet available
upon which to base a firm recorrmendation. The evidence that is
available~ however, when combined with intuitive judgement, suggests
that the Watana/Devi 1 Canyon scheme may be preferable to the. Vee/High
Devil Canyon/Olson crJmbination. The ~;orrments contained in this report
will be reviewed and refined after the 1980 Annual Reports are
available and when ;nore construction and operational details are -known.
Comparison of the two sc~emes wi 11 ;ti 11 be harapered by the scarcity of
information concerning the Vee impoundment area ..
11 ········~
I
I
I
I
APPENDIX A I
DESCRIPTION OF STAGING ALTERNATIVES I
I
I
I
I
I '
I
I
I
I
I
'\ I
I J
I 1
;
I
I
I
·~
I
I
. . .
•.
..
. . , ·:. ... ..
.... ~-· .:;~-... ... .... , ........ · . -: ... .
~·
. ·
P •
... A.
G.
... ·-
. .
.. . .
... : ..
·'
I ••• . .•
.. . . . . ,.. • '!"• . . . . ...
.• ..
... ·. .. ,. ... . .. .. \.
:.: "' ;~ . : .. ..... . . _..... .
-... .. .. ~.:;;,. .... ,.,
~ ... : .. ~~-··;~·!:; -~ .. ~ .. ,. .. ,... ....... __
. ..
•• J "'
. .
-.
. .. --.
... -.
... ~. +4 ........
• ..,..,.... 4o ~ ...... .,~ ... ,..""'-...
• ...... ~ ~--... .. ~-.. .•. ·. .... . "'
t ~ :,. ..... ,.. ..... .... ....
·-...
.· . .. .-.. . .
~ . ,. ...... . .
..... .. .
. .
• ~·;~ ........ ·-= ~.
: ..._: , .... tr.a_ .. .,, ..
•,. ' .~ .... ':"' .... -. .:· .. ~: ~--:·:.:,~--··· ....... . , ·-.. .
"' ·~"!"" • •• • .•• "'.,.'"!"".;. ... ' .. . ... . ... ~·-. .. : ........ -...:.
.-., .. ~. "-'o! -'"'~ ... .--·-. -.. ., .....
• -... ..
• • •. ~ "!!'• ...
. ... . ......... . • ..... .... ...... _
:~;.:..~.· .... ,. ......... ..,. ....
_; •.. ~ ... --:-:;-, -·
.
SCHEME _ Plqn 1 . (Total installed cap~citY = 1490 't~\·1)'
.
~tage I Oevelo~ent Stage· Il D~velopment · Stage III DevelofWe'll · ·
Dam Site Watana (2200l
t!ei ght 750 , ft.
Dam Site ·geyJ]~fDYOD {}450) Dam Site------..
Height 570. ft. ~: ·Height ___ ft. ~ · ·
lnsta lled
Capacity 800 t·l~
Probable on
line Date 1995-20PO
Daily ·.
f.1ode of Operation peaki'19 ·
Installed
Capacity -· 600_ t·tl
·Probable on · .
L 1 ne Date 2010-20
No Daily
. Mode of Oper.ati ~n e.eaking ·
Separate . ; Separate
·· Re~regulation Dam Possibly .Re-regulat~on Dam"..-...H.-..o _
•.
NOTE: figures in brackers behind dam site name
. . . .
indicate maximum \'later surface elevation in feet. ..
Installed
. Capaci .. tY __ fll ··
· Probab 1 e on
· line l)ate __ _
. .
ltlde:of Operatio.n __
. .
Separate
Re-r~gulation Dam __
. . .
.· . . . • ..
S~age IV Devel!Jlmefl.t
Dam Site __ ......._ __ _
.
Height ft •.
Installed
Capacity -· ·--l"'
o'
Probable on
Line Date ---
Mode of Operation
. Separate
Re-regulation dam
---
--
···------------------
-------------------
·.
.
SCHEME _.Plan 2 •.• .. (Total installed capacity = 1409 HW)
Stage I "oeveloJ?lllent.
Dam 51 te J~atanct {2000} ...
Height 550 ft •.
· Installed
Capacity ·400 f~
.·
. .
_Stage II peveloproep~ ·
.
Dam Site \4atana (2200) •
Height 7.50 ft.
Installed
· Capacity 800
.
. .
Probable on · Probable on
. . .
line Oilte 1995 . . .Line Date 20D0-10. · · .
. Daily · · . Daily · .
l·1od~r of. Operation. peq~iog · . Mode of Operation Pf:!akjng .
~ . .
. . . . . .
lt~ge IV Deve l911!ffient, . .
Dam Site~~11. .. C~DY9Ji.(li501) Dan_l Site------
.
Height .. ~70_ ft. . . : Height __ ~ft.. ·
Installed ... ... · ·: Installed
Capacity 600. · ·~~~·. : . : Capacity ;)\W . ~ " ~ . . .·
Probable on .· · : '· ... · .. :· Probable on
line Date 2010-20 : · ·. · : .Line Date __ ............,.
· . · · 'No· Daily · ·
. tbde of Operation .eea~1ng Mode of Operation· __ _
. .
Separate Separate . · Separate . . . ·Separate
Re:..regulation Dam .. fQ~~iqly
. '
. . . .
Re-regulation ~am_.fpssib]y Re-regulation Dam ........ NQ....,;_
~la.tana Gam raised 200' ·. .· . ·· .. .. . .
Installed Capacity ·
Increase~ by 400 ttl
.. ·
Re-regulation dam --
..
SCH~ME p··tan 3 · _ I:
t
.
Stage I DeveloPffient
Oam Site . "}atqn'!, (22QO} ...
. .
Height _ 7~Q. ft. _ ..
Installed
Capacity· 400 t~ ...
Probable on
line Date 1995
. Daily
. . . . . .· . I . . . . . .
. '
. ' . ..
·. (Total installed ·i;apacity .,. 1400 l·ft~) . .
..
Stage I I oe~Je lopment
~~ ~ ~
.itage lli.Deve1opnl!!l1 · · · § .. tage IV DevelJQpment. . . .
. ~Dam Site • Wauna 12200)_· :' Dam S~ te ..Delli] .. Cat~¥on . .
Heigpt .:..ZSIL. ft. Height. 570 f~~ .. . . . .
wu • '•
. . . ... .
Darn Site ------
}te1ght __ ft.
· · . lns ta 11 ed : .. · Insta 11 ed . . ·. Installed
. .
· Capacity ~O,Q_ . · : . Capacity · . §00 I ~~,f.·:: ·. · · ·· :. · Capacity __ ••\W
. .
Probable .on · · Probable on · . . . · Probab 1 e on
Line Date 2000-10 . · .. · line Date .. 201Q:2jJ · · · · . ···Line Date __ _
· ·. . 1·1ode of Operation· Peaking
· Daily · '-· . tjo Daily·: ·
:. Mode of Operation. P~fl~iP9. ·.· tbde Qf Operation l!t:eking :·: ~1ode_ o~ Operation __ .
Separate . · · Separate · Separate .
Re-regulation Dam .f!ls~ibl.y · Re-regulat1on Dam J?ossib.Jy Re-r~gulation D~m .-Np._.
• "l
.
· Installed Capacity
Increased bY. 400 t1W
. . . .; . . ; ,. . .. . '.
. ' .
• t
• t . ..
• ' I ~ •
Separate
. ~e-regulation'dam .. --
...
.. •
-------------------
-- - - -•· ----;--.• --- -·-·--
. ·.
SCHEME Plan 4
. .· . . . . .. . ... . .
· '(Total installed capac1 ty = 1300 1·1W) · ·.
.. .. . -. • &:· : •• ..
If ""• I t t I tl. ". t I ....
.. ..
' ... • -•• 4 .... . .· ... ·.··.t._~., .... ... • ..,..,...
Stag~ . I · Deve 1 OJ)II)ent · S_tage II Deve 1 oJ!ment; . ·. ' · .. : . s.t.ag e I II Oev~ 1· oPni~~~ .·: ',.-\ .· . S t~ g e IV Deve lOP!!,en t
. . .,
. ~ ' .. . ~,.
Dam Si~e. High o.c. (1155) ~ Dam Site Vee. (~~po) . :_ . ·.Dam Site Ql~oo·jiQlll}_~·::_. .~ ... Dan~ Site-----. .. .. .. " . .. ..-. .. . . ... . . "' '
· _Height 425 ft. · · Ueight .JlQ ~ .. ·ft. · :. · ·.· .. · . · ·Height ____ . ft ... ·Height 725 ft. · . . .
·Installed· · _; ·.Installed ·· · . ·Installed · .:. ·: .. · :.~·.:.·:.· .. Instal.led ~
Capacity· ·BOO l~t · . : ·. · ~ Capacfty 400 , I·M .... .' . · · · ·Capacity :1:100 · M\ol .. : ·,.=-· ·-': Capacity ____ ,. t-14
. . .
• I
l •
• ~-t,
Probable on . : .. Probable' on . :. -·-< ·: . -~ · Probable on . > ·'> . :<. · _): Probable on
Line Date 1995-2000 . Line Date .2010:-~0.. ··.·· .. line Date .2020 -· .. ·/:···.line Dat~ __ _
. · Oa i 1 y . . . . · Da i 1 y · ·. · · . · No Da 1ly. :. ·
f·1ode of Operation Peaking· : Mode of Operation . PeC;tkiD9 · ·. t~de of Operation .l!eDk1ng · .. Mode of Operation __ _
Separate ~ Separate Separate .. .
Re-regulat1on Dam Possibly* ·Re-regulation Uam ~e-r~gul.ation. Dam ...:.. tJo .. . ,, . . . . . . -. . . . . . I ·. .. . . . . . . * Olson f!laY serve as the re-regulation dam in -which case the 01 son :.
· dam would constitute part of· Stage I. The powerhouse· at Olson· ... ·
could ·still ~e b~ilt at a later stage •.. · · .. : .. · · ~-:·· ~:~
. . Separate
· · Re-regulation dam ~ . . --· -· -· ---. .
·.
SCHEME __ P_la_n_· 5 _____ . ·_(.Total installed capacity» llOO Hl~) '· ..
. . . . . .. . .. . ..,· .... ,.,.. . .. · ........ ~.· ......... .
·Stage I ·Dev~lopmef!t · .·· ,. ·' · ·~tage ·ii Development ·, :. Stage In DeveloP!!'~~~ <:~.:·-~::·,::-:·~tag~ J! Dev~1opmen~
Dam Site . JijgJl Devil ·Caflyon _-: :.Oain Si ie lli!!h. Dclt.il' ~iUIYOn ... Dam. Sfte • yee !Z~OQl · : .. .'~.··_.:-: D~ Si_te jjh!!l (102~) _
. . . . (1610) . .. . . . ·. (1750) : ... : . : ... :··~1·• ·· .. ,. . . .
·.~-Height 570~ .. , ft.:· .. :~ .-.·~:·:-.· .. ~:~eight .. 725 ·~ft. ;. -. .:·.· ... Heig_h.t 425 .~t.-:.:.:.::·~:~:.~:{·-:,~:\J_H.e1ght }20_ ft.,
,. ·~ ... ~ • .• .. ~; ·:. ... ..... : .. -• .. .. ,. • • • • -. • • ~ \t .. • ~. \ ~ . • .. ..... .. : r: ... : ·~-. ~ ...
..
. ..
• • . .
Installed ~ .. : ·.:·Installed · · Installed · · ·· .. :.: · . .' ~.:.~'·>_:; installed
Capacity. 400 · i4W ·. --:=.:~;. . Capacity 800 t·'W · ·: Capac.ity :_4oo : ~1W .. :·. ·::·~.::·::: · Capnci ty .~109;.~ ~IW
. • • ... ... : ... !· _. . . .. ~ • ... .. . .. . "' .... • •• ·-···· .
. Probable.on . · ." .. ,/·;··· .. Probable on . . . ~· · · . .~·Probable on ·. , )~. ... ::.:: ·.>.~·~:.~Probable on·
tine Date· 1995. · ::·t: .. ··.1.'Line Date .20QQ:..lO·· ::··.:Line Date ··2010-20·/ ·.:.J. f.:··.Line·Oate 2020
. . · Da 1 ly ···:-· · .. :. : ·. · u, •· ·-"Daily · ~ . . · : ... -oa 11y:·.:~::::·~.i· f. · ·-, No Oa 11y . . . "' . ·~·~· .. ~
t·1ode of ~peration Peaking.:.:.: ·;·.~ode of Operation_ Peaking · ·ttlde of Operat~on .re~kin9~:~4·-::. Mo~e of Operation~ea~if!g
.,, •• ~ .. • •• "' : t • .,.... • • • • _. ... .. • '' '·"':;" •• • • .: 'f/ •
Separate . .. . ~ ·Separate · ·. Separate . . · ·. ···<· .". : .. Separa~e
Re-regu.lation Dam Possibly*· Re-regulation Dam· Possibly*· Re .. t~gulat1on Dam No · ·_. < · -Re-regulati.on dam No
• .. .,. • "" • n * :""••~• .• • .. , ......_ __
• .... "·~--.. . . ~ .• · :·. ·. · :High.Oevil .canyon Dam
: • · ·.. -.:. · ·.! Ra1· sed 140' ·· · · · ; :.·· .: · -.· • . .... .:. ,t ... : ... I> ~ ,. • " • "" • ..... • "' • • • .·: ..-.. .. ,. ::9... \.... •• ... "' . " . ·~ . • •. 'f •• .,: ....... ·_ ': .. • .......
... • • • 4 • • • ... .. ,.~~: ... • ~
,. • ~. " ~ · ... .-... ' r.~ : . • ... ·:~ • "!. • • : • • ·.: , --·:· •• ~ • • t ,· ~ : • • • . • · ~··: · -.. ~ .. ~.-·~··:!:.··· .. Installed capacity ·· . · · .. ~ ~:··:_. :: ..
. . · ·· ....... ~~ ~~. :·Increased by 400 It\~ · ·::.' · :-.~ .~ • · ~ :
• , .. ,.• • • " ~. ..· ~ iii! • "' '! " • • .. • .. ,.. •z' ,. .. • ... l
.. • • • '* .. ,. .. .. • .. .. • • • . ! . .. • :. .. ' " •· •" • . ..... .. . _. '"• . .. .. . J • .. " ••• It
• • : ,. •• ... • ..... ·~~·..... • .. ; .... .,.;· • .; .......... ~. • ~,. ......... • :· <l ... 1"" 3, •; '* ..... • ...... -::·· .. ·
• • -~ • :·~.:" •• l • : .•: • . • • • •• • " .. .. • ' " ~ .Jf.. !· • • .. f .: ••• ' • • • • • •
• " • " •• a• f I '••: i t • .._ • .... ll ,.. •,. t • ' : 11, • )I "• I' •~ I • •
.. • .. • • .... .. t .. • • u ". :.. • ; t • .. ~.. .. • • t: ... .#. . • • .. ... • .. • :· . • : ;. • -.
, "'" • • lla ", ., .. •~ • f " " 11 • a. • ~ ~ • '"' "" ti '. • •' • ••
•. I • ~ iOt t '\ '!, ',: .... ~ !'". I • • • • • ~ t ~ •,., •" • ' " • 't •} • .. '· • ., • I • ~ J •• • •
• "'I -. ~. • • a' -.. I l.. 'ill " .. ,. ,. " ., " •• "• 'f • • f • li • f •• • •
, • • IJ • • ""'...... .. •• ~... .. lit .. "" ... --~ • .... • • • ,. .. •· •
1
••• •••• •• •• * 01 soriuma,y. servei"'as·z the::re~regu) at1on .dam: 1n.:·wh1 ch: case· the Ol_son;
~·:. ··. · · dam would constitute.part of s.ta.ge I.~. The'powerhouse at Olson··_::
· could still be built. at .a .later stage.: .. ·. :· ·~ t; <·. · ~. • · · ·
'-. . . ... . .. . . .. ..
------....... -------------
/
. .
SCHEME ... P] an 6 · (Total insta 11 ed capacity a 1300 lU-I)
..
. . .
. . .
•
· .
. . .
?tage II Oevelopme~! s.tage III Develof?.ment. · St,age IV pevel®m_en.t. ·
Dam Site .Hiob .O.e\l]] canxon Dam Site _lfjgh (Wvil Ca!!Yon Dam Site ..'Lee • . _ Dam Site .Qlsoo :(J02Q) _
(1750).. (1750) . . . . . ·. . . . .
Height 725 ft. ·. Height .. 725 . ft. · . · He1ght . gz5 . ft. . . . · Height .)20 . -~ ft.
· Ins ta 11 ed . Installed
Capacity. Q • 40Q. lt\W . capac1 cy _a on . t·i\~ . . ... ..
.Installed
Capacity
. .
... ·· .? : . Installed .
anD. ~\~1 . · ·. . . Capacity ilOO _ J.1H
Probable on
line Date
. .. Probable on Probable on Probable on .. . . ..
·· Line Date 2000-lQ . Line Date 2010-20 · · · Line Date 2020 • o,. • • ••r ., 1' ,.
Daily · Daily · ·: ·Daily · · . No-Daily
: f~ode of Operation Peaking :Mode of Operation ._Peaking ;. t4ode of Op.eration Jeakiflg · . Hade of Operation e~.shing
1995
.
Separate · · S~parate. . . Separate .
Re-regulat:ion Oam Possibly* Re-regulation Dam fp~sib]y*· Re-r~gulation.Dam·. No
· ·. Separate
Re-regulation dam .. Nri
installed Capacity increased.
by 400 li\~
.. .
• L .
~ " • !: • • • • '
· · · ·*Olson lllay serve as the re-regulation dam 1n which case the Olson ·
dam \~ould constitute part of Stage I. The powerhouse at 01 son · · ·
could still be built at a later stage. · ·
--.. .. ---.. -.. -1111 -.. ~·1\:.;:1;.;..11:...1 -=·~· L::J_N_V_li_CII_~_li_N_IA_I_I_V_AI_I~.J!L.!llVU t•l\tl~!_!\_N_O_I_Il_NI'_Il_l_:~
AflpraT:iiir--~--------------·-----------·-~1\ii*t-Jm~JOd lo have
luvu·Oflllll!Ulitl (lhffercncu.'i Itt ·~·meL fdtlilllfil:alaun Uti: a~uGL polenl ial icspud
Allribult~ _____ _____f!~-------uf twu schcmesL__ of dtffm·cmco ----~•raisnl .blijet!!elll lurvw.l Dt: _
I culm)icul;
-JlotHIUll'i:OII~ f' l.;hudtfS
and WH•H &fu
Resioorrl fisheries:
lH ldl ife:
Cultural:
lwld Uue;
(ffccts r.:ll<rH in•J
ft·nlll .changm; in
ttrtl c r •tt.:lllli l y .and
quulity.
Lous or res l•1tlnt
fisheries huhllal.
lnss or wildlife
hobilal.
No utrJI•lfu:wtl dlfrer-
tmcu lml wem'l ~r.hr.1111::>
r~t)ltl'ttifKj t!ffectu duttrr-
slruarll uf llevil l"..anyou.
0& ffurence m. reach
bulwcen Jlovil r..myoo
dOIII and tunnel ru-
r~cJular iun du.
Hinhaal rh(feruoces
belwcen sche~s.
Hini•al dlffereoces
b~lwuco sch~s.
Jnunr1ttlion of Polenliai dafferences
arclwnlogical siles. between schemes.
ltmnrlalitlll nf l>uv il
Canyon.
SigoHficanl differe~ICe
between schc~s.
11ilh lhu luriiMll schuJoo cui\-
l roliutl flown bt:lwucn rcrjula-
t icm dlllil ''"'' dmmutrtta~~~ powur-
hnuso offt!rs potent l~l for
~1adroooua ft!"".lriea enhaocu-
lllllnl ln lhiu 1. -!lllltl roach of
~hu civ~r. .
Oevi l C'81l)'U1\ ~~~~~ wuld UIUI\tlule
27 •llen of the Susilo,. Rivur
ami 8jlprox••uleJy 2 aUes of
Devil Creuk. Tt;e tunnel sdleae
would inund<Jle 16 •Hen· of the
Susilna Rlver.
Jhc lllllut scwuil ive wUdl ife ha-
bitat in lhis reach la upalruam
of thu luonel re-rugulal ion i1&3
~ere there is oo lligniflcool
difference between the schelll8s.
Jhe &vi l taoyon da. schl!CIIU in
adcht ion iriundules lhu r i vur
valley bul~c:n the hio dlllll
sites resulting in a ~rate
incruase in liiJl&Cls to
wildlife.
~~~ to the laa·quc arlia ii'Wfl-
datud the prubnhil ilr of inun-
dating urchl!otllgicul silos is
incruased.
lhe llevH Dlt1yoo is coosidered
a unique rusource 1 Of) percent
of which WJtdd be im;n~at.;::! by
Uw Duvil Canyon da~a sctle110.
lhis would rusull in s loss of
both an ooulhclic value plus
the p~-~ :~1t 1<11 for ~1ite walcr
Nol a factor in t''t~l•m!i~'>l or
fU!hUIIIIl.
If fisheries tlnhanceDI!fll 'lliJ•or-
lun ily can btl rualizt:d the ltHl-
nul ac.-t~ offei'll a positivu
a it hjntion lll!asure nol availuhlo
wlth the Devil Ca.ayon dlial
schttllltt. lhit~ opportunity in
conul•Jured IIIOtb!rftle and .favors
lhe tunnel sch.!HNh ·
111 i1t r~ach of rivur ia ool con-
su!u&·od lo be highly Significant
for rusit1enl fisheries and tho!!
lhu difference bel~a:n the
schulilds is ainor and favors lhu
lll!lflD l sche~~~e.
lhu difference in lriss nf wtld-
l ife hllbiht is cMS<idared ~d
erutu and favors the Lurllll1l
st.:hullle.
A sil)laificanl acciMlOioqicol
site, if identified, cliO pruba-
bly lMl t:t>~cavuled. lh111 concern
is not coosi~rt:d a factor in
in sche~~e evaluat lon.
fhe aesthet &c nod lo .tlUIIlll edeol
lhc recreational lrum<~s associ-
ated with thtt duvelopment of tl'to
Devil Canyon dnm is the llllill
aspect favoring lhe lunne l schuiiMl.
X
)(
X
X
--------------------------------~----------------------~--------------~r-e~c~rc~h~, ·~~·------------------------------------------------------------------------------
QYEUALL lVAtiiAlH.llh lhu lunMl nchu~ hau ovur.all a ltlifiH' iqmct 011 lhe cnv&rwliiMlnl.
--
-•• '
TABLE 1..2 -SOCIAl EVALUATION OF SUSITNA BASIN DEVELOPMENT SCHEt£S/PLANS
Soc1al Tunnel Devil Canyon
Dam Scl'leme
High Devil Canyon/
Vee Plan
WaEana/Dev il
Canyon Plan _A_s.e_e_c_t __________ ~P_a_r_a_m_e_ie_r _______ Scheme
PoteQtial
non-renewable
~·esource
displacement
Impact on
state economy
Impact on
local" economy
Seismic
exposure
Overall
Evaluation
Million tons
Beluga coal
ovel' 50 years
J
'isk of major
~tructural
failure
Potential
impact of
failure on
human life.
au 110 170 210
All projects would have similar impacts on the stat~ a~d
local t..conomy.
All projects designed to similar levels of safety.
• Any dam failures would effect' the same downstream
population.
1. Devil Canyon dan superior to tunnel.
2. Watana/Devl1l Canyon superior to High Devil Canyon/Vee plan.
Remarks
Dev ll 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.
-- -------------
----·-
Environ.ental Alhlbute,
2) Nlldllfe
a) Hoose
b) Caribou
c) rurbearara
d) Blrda and Beers
----------
lAet£ I.J -EH'(IROIH:NIAt EVALUAUDN or WATAHA/!l[Vll CANYON Aft) IUQI DEVIL CAN\'ON/V£[ !l£VElOPI£Nl PLANS
Phln CO!Par !son
ND alc;;pl1fJcant difference lq effects on downntream
DnadrO!IIOUa fisheries.
II>C/V -.auld inundate approdalllely 9) callas of the
Suallna. River end 28 •ilea of tributary atreo.a, In-
cluding Ute fycme River.
V/DC -.auld Inundate 8JIProxJ•alely 9* •ilea of the
Suallna River and 24 •lies or tributary slreaMa 1
Including Nat.na Creek.
Apprah;al Judge!ent.
Due to th~ avoidance of the Tyono River,
laaaor lnuncJaUoo or resident fluherlea
habltat and na algnlflcant dtrf$rmnce ln the
ef'recta on anadrOII'Oua rlahcarlea, \he W/OC plan
la judged la have. leas liipsd.
lflC/V would Inundate 121 •ilea of critical winter river Due 1o the .lower potential fot direct lwpttct
boUoa habitat. co lllooae populallona within the Sualtna, the
W/OC plon is judged superior.
W/DC -.auld inundate; 108 •ilea of this river bol:t011
habitat.
OOC/V MOUld int.Pdate • l•rr. area upstre .. or Veo
ut l1 bed by three sub-popu at lana or IADOIJ~ that rmge
ln lhs northeaat section of the basin.
N/OC would Inundate the Watana Creek area utilized by
JROoae. The condition of thls atJJ-populalion of 110081!
~nd the quality of the habitat they are using appears
to be decteaalng.
lhe lncreaaed length of river flooded, eapedally ~
slrena froa the Vee daM alte, would result ln the
HDC/V plan creatlng a greater potential dlvlslon or
the Helchlna herd's range. In .tdlt lon, an Jncresse
ln taoge would be directly Inundated by the Vee res-
ervoir.
The area flooded by tt.ts Vee reservoir la considered
J~rhnt to .ft018e Ice{ rurbearer•, particularly red fmc.
lhle ~ea Ia judged o be .are lllpOrlWlt th81'1 the
Watantf Creek aree that would be lnundatr~d by lhe W/DC
plan.
forest habitat, l~ortaol for birds and black beara 1
axial along lhe valley ·slopes. The loss or lhla habi-
tat would be greater with the W/DC plan.
There ls a high potential f•,r discovery of archeologi-
cal sites lo tho eeaterl) ri:glon or the I%Jper Sualtna
&sin. fhe mt/V plan has a greater potent lal of
affecting theso altea. ror other reaches or the rlver
the dirference between pl.na le coosldered mlnl•sl.
Due to the potent lal for a grealar lBipacl on
the Nolc:hlnt!> caribou herd, the tllC/V achet110
ls consldored infer lor.
Due to the Ieeser potential for !Npact on fur-
bearers lhe N/DC Is judged to be auper io1·.
The ii>C/V plan Is judged superior.
fhe W/OC plan la judged to have a lower po-
tentia! effect on archeologlcal sltea.
.. -
Plan ]Udgfid Eo have tho~
leaal V2lenll•l i~t Jllt/r · !
X
X
X
X
-· --
--
lAIII ·t I • .S \fuul inu•:•lJ
-·-----------· ---------· -~-• ·· -------------~--~-· · · --•· -· ·-·--... ---------------·-• •· ·---------------------·------l'liiii'"Jlitlijt:taTOlmveniu--
' uvHmlllll!nt al, Allnllutc ----·--·---· ----• .f.!!!!l l'u.•~mt•i:luu ·------Appntwul Jmtqe!OOnl --------· lcji}i;7\!olcitl inl itOtJtl
Ac:.Lhnl u~/
l11nd lim:
ti1U1 t~llh~·•· :.t:hc~~~<l 1 lim ltc!ithnl w •11111lil~ of lmlh
lluv •l l':tllt)'OII uud 1/&m t:ml)'•m utuald hn ifll!IIH ru11. fhu
llllf./V plnn \<Hatld ulsu lllll!ld.tlu lsum:ma fulls.
Uual lu Ct:ltl!ll rut:l ion ltl \lt:c Oa•B sit c IIIli I lhu :t ilti of
lhc Vt:u Ht:lillrv•li r 1 l hu II){' /V rahm \;tlllld iuhurunlly
rra:.tlt..\ accusu Lu a:toa·t~ w i ldurncss nrua lhun wtauld l111:
W/&)C plun.
lloth t•ltulU illipncl lhu vul h:y um>llmt acs. lhil
•h ffurum:H is coalS ult:n:d a~ hlllftU l.
Au tl lU eauier lo tlXlt:nd UCO::UUS llllll\ lo
Hail ll, inlwrunt acceut1 rc'r•irclllllnl!i wura:
COil~iduraal clt:lrtlllt.'ftlal nnd Um W/OC plnn is
ju•~d lll.lf)4lrior. fiiU ucuht.]lCal aeusil ivily
of lhu urea npenud by lhu lllC/V plan ru io-
furcus lhis judlJtliOOnl.
UVLIII\Il I VAliJAIHlfh lhu 1~/fll' plnn l!i jmi!JU<I to btl GUfillrtllr lo lhc I.)C/V a•lnn.
( fha lol'ltlr i"'1act on hl1·ds umi huars ansuch.alurl with II>C/V plun is cm11Hdurud lu l1ll atutw.uqhud by aU
Ulll oUtea· ll!lfltads which fovour the W/OC plnn.)
!!!.!f.§.;
U = \"lui 111111 Oam
Dr = riC" i l fCJ,{I)IOfl Ualll
II>C :. llia)h f>uv i 1 i:nnyun 00111
V : VtJc Un111
-------... -.. ---- -- -