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BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
APPLICATION FOR LICENSE FOR MAJOR PROJECT
SUSITNA HYDROELECTRIC PROJECT
DRAFT LICENSE APPLICATION
VOLUME 2
EXHIBIT B
PROJECT OPERATION AND RESOURCE UTILIZATION
ARLIS
Alaska Resources
Library &Infonnatlon ServICes
Anchorage,Alaska
November 1985
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NOTICE
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A NOTATIONAL SYSTEM HAS BEEN USED
TO DENOTE DIFFERENCES BETWEEN THIS AMENDED LICENSE APPLICATION
AND
THE LICENSE APPLICATION AS ACCEPTED FOR FILING BY FERC
ON JULY 29,1983
This system consists of placing one of the following notations
beside each text heading:
(0)No change was made in this section,it remains the same as
was presented in the July 29,1983 License Application
(*).Only minor changes,largely of an editorial nature,have been
made
(**)Major changes have been made in this section
(***)This is an entirely new section which did not appear in the
July 29,1983 License Application
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VOLUME COMPARISON
VOLUME NUMBER COMPARISON
LICENSE APPLICATION AMENDMENT VS.JULy 29,1983
EXHIBIT
A
CHAPTER
Entire
DESCRIPTION
Project Description
LICENSE APPLICATION
JULy 29,1983
AMENDMENT APPLICATION
VOLUME NO.VOLUME NO.
1 1
B
C
D
Entire
App.Bl
App.B2
App.B3
Entire
Entire
App.Dl
Project Operation and Resource
Utilization
MAP Model Documentation Report
RED Model Documentation Report
RED Model Update
Proposed Construction
Schedule
Project Costs and Financing
Fuels Pricing
2
3
4
4
5
5
5
2 &2A
2B
2C
1
1
1
E 1
2
Tables
Figures
Figures
3
General Description of Locale 6
Water Use and Quality 6
7
8
Fish,Wildlife and Botanical 9
Resources (Sect.1 and 2)
Fish,Wildlife and Botanical 10
Resources (Sect.3)
5A
5A
5A
5B
5B
6A
6B
6A
6B
Fish,Wildlife and Botanical
Resources (Sect.4,5,6,&7)
11 6A
6B
Socioeconomic Impacts
Geological and Soil Resources
4
5
6
Historic &Archaeological Resources 12
12
12
7
7
7
Project Design Plates 15
Supporting Design Report 16
Project Limits and Land Ownership 17
Plates
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:0iOo
11.0
1.0
I I'.('1)
('I)
F
F
G
7
8
9
10
11
Entire
Entire
Entire
Recreational Resources
Aesthetic Resources
Land Use
Alternative Locations,Designs
and Energy Sources
Agency Consultation
13
13
13
14
14
8
8
8
9
lOA
lOB
3
4
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SUMMARY TABLE OF CONTENTS
SUSITNA HYDROELECTRIC PROJECT
LICENSE APPLICATION
SUMMARY TABLE OF CONTENTS
EXHIBIT A
PROJECT DESCRIPTION
Title
1 -PROJECT STRUCTURES -WATANA STAGE I (**)••...·..
Page No.
A-1-2
• ••o.•
1.1 -General Arrangement (**)••
1.2 -Dam Embankment (**)•••••
1.3 -Diversion (**)•••••••••
1.4 -Emergency Release Facilities (**)
1.5 -Outlet Facilities (**)••••
1.6 -Spillway (**)•••••••••
1.7 -This section deleted •••••
1.8 -Power Intake (**)••••••
1.9 -Power Tunnels and Penstocks (**)•••
1.10 -Powerhouse (**)• • • • •
1.11 -Tailrace (**)••••••••••••••
1.12 -Main Access Plan (**)
1.13 -Site Facilities (**).
1.14 Relict Channel (***)•.••••••
A-1-2
A-1-4
A-1-6
A-1-9
A-1-10
A-l-13
A-I-15
A-1-15
A-1-18
A-1-19
A-1-22
A-1-23
A-1-25
A-1-29
2 -RESERVOIR DATA -WATANA STAGE I (**)••·..·.·..A-2-1
3 -TURBINES AND GENERATORS -WATANA STAGE I (**)
3.1 -Unit Capacity (**)•
3.2 -Turbines (***)••••
3.3 -Generators (**)
3.4 -Governor System (0)
. . . ..
o • • • • • • •
·.'
• 0 • • •
....
A-3-I
A-3-1
A-3-1
A-3-1
A-3-3
4 -APPURTENANT MECHANICAL AND ELECTRICAL EQUIPMENT -
WATANA STAGE I (**>'• • • • • • • • • • • • • • • •..A-4-1
4.1 -Miscellaneous Mechanical Equipment (**).".
4.2 -Accessory Electrical Equipment (**)••••
4.3 -SF6 Gas-Insulated 345 kV Substation (GIS)(***)
A-4-1
A-4-5
A-4-12
5 -TRANSMISSION FACILITIES FOR WATANA STAGE I (0)• •• ••A-5-1
5.1 -Transmission Requirements (0)
5.2 -Description of Facilities (0)
5.3 -Construction Staging (0)•••
.. .
A-5-1
A-5-1
A-5-11
851014 i
SUMMARY TABLE OF CONTENTS (cont'd)
8.1 -Unit Capacity (**).· · · ·
·•·A-8-1
8.2 -Turbines (**)·· ·
·A-8-1
8.3 Generators (0). . . . . .···. .· ·
.·.A-8-1
8.4 -Governor System (0). .•· ··•· ··A-8-2
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A-9-1
A-6-1
A-6-1
A-6-2
A-6-4
A-6-6
A-6-8
A-6-10
A-6-12
A-7-1
A-6-12
A-6-13
.1\-'6-14
A-6-17
A-6-17
A-6-18
Page No.
• •
·..
•._0 •
o • •
• •
· .
... .
. .
•0 ••.•..•.
• ••••• • • • •
EXHIBIT A
PROJECT DESCRIPTION
6.1 -General Arrangement (**)
6.2 -Arch Dam (**)••••.
6.3 -Saddle Dam (**)••••
6.4 -Diversion (**)•
6.5 -Outlet Facilities (**)••..••••••
6.6 -Spillway (**)••••
6.7 -Emergency Spillway •••
(This section deleted)
6.8 -Power Facilities (*)• . . • • • • • •••
6.9 -Penstocks (**)• • • • •••••
6.10 -'Powerhouse arid R.elated structures (**}••••.
6.11 -Tailrace Tunnel (*)• •••••••••
6.12 -Access Plan (**)•••.•••••••
6.13 -Site Facilities (*)••••••
9 -APPURTENANT EQUIPMENT -DEVIL CANYON STAGE II (0).
Title
7 -DEVIL CANYON RESERVOIR STAGE II (*)
6 -PROJECT STRUCTURES -DEVIL CANYON STAGE II (**)
··__·_·_-_·······__··---·9·.-1-··_·-Mi-s·~el·laneaus-Me~ha·n-i~al-Equi-pment--Ea1-..-.-.-.--.-.-A-9-1---
9.2 -Accessory Electrical Equipment (0)••• • •A-9-3
9.3 -Switchyard Structures and Equipment (0).• •A-9-6
11 -PROJECT STRUCTURES -WATANA STAGE III <***)0 • • •
A...,ll-1
11-1
A-1l-3
A-1l-5
A-U-6
A-1O-1••
••
• •
ii
c:.lL1 -GeneraI·ArrangemeriF{***}:
11.2 -Dam Embankment (***)• • • • ••••
11.3 -Diversion (***)••••••••.•••••
11.4 -Emergency Release Facilities (***)••••
10 -TRANSMISSION LINES -DEVIL CANYON STAGE II (**)
851014
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT A
PROJECT DESCRIPTION
Title Page No.
11.5 -Outlet Facilities (***)·····A-1l-6
11.6 -Spillway (***).····A-1l-7
II.7 -
Power Intake (***)· ··· · ·
.···.· · · ·
A-U-8
11.8 ~Power Tunnel and Penstocks (***)·A-ll-ll
II.9 -
Powerhouse (***)··········A-ll-ll
11.10 -Trailrace (***)· · ··A-11-13
11.11 -Access Plan (***)· ·
·· · · ·
·A-ll-13
11.12 -Site Facilities (***)··.A-ll-13
11.13 -Relict Channel.(***)····A-ll-13
12 -RESERVOIR DATA -WATANA STAGE III (***)••••·•••A-12-1
· . .
13 -TURBINES AND GENERATORS -WATANA STAGE III (***)
13.1 -Unit Capacity (***)•••• •
13.2 -Turbines (***)•••
13.3 -Generators (***)
13.4 -Governor System (***)•••
14 -APPURTENANT MECHANICAL AND ELECTRICAL EQUIPMENT -
WATANA STAGE III (***)••••••••••••••
·.
• •
A-13-1
A-13-1
A-13-1
A-13-1
A-13-1
A-14-1
14.1 -Miscellaneous Mechanical Equipment (***)•A-14-1
14.2 -Accessory Electrical Equipment (***)• . • • • •A-14-1
15 -TRANSMISSION FACILITIES -WATANA STAGE III (***)
15.1 Transmission Requirements (***)•
15.2 Switching and Substations (***)•
00.A-15-1
A-15-1
A-15-1
16 -LANDS OF THE UNITED STATES (**)• •G •e _ • • • •0 A-16-1
17 -REFERENCES
851014
• • • • • • • • • • • • • • • • • 0 0 • • •
iii
A-17-1
SUMMARY TABLE OF CONTENTS (cont I d)
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B-l-l
B-2-l
B-2-1
B-2-1
B-2-22
B-2-48
B-1-12
B-1-17
B-l-l
B-1-4
B-1-5
Page No.
• • • • •
...~.o 0 COl 0o..e
EXHIBIT B
PROJECT OPERATION AND RESOURCE UTILIZATION
1.1 -Previous Studies (***)• • • • • • •
1.2 -Plan Formulation and Selection Methodology (***).
1.3 -Damsite Selection (***).
1.4 -Formulation of Susitna Basin Development
Plans (***)• • • • • • • • • •...
1.5 -Evaluation of Basin Development Plans (***)
,-'2.1 S1.1si tna 'Hydt6electticDevel6pmenE ''(*'**)--
2.2 -Watana Project Formulation (***).• • • • • •
2.3 -Selection of Watana General Arrangement (***)••
2.4 -Devil Canyon Project Formulation (***)••••••
2.5 -Selection of Devil Canyon General
Arrang eme l1 t (***)..• • • • • • • • • • •B-2-60
Selection of Access Road Corridor (*~)B-2-67
"Selec'tionof 'rransmi-ssiori.-FaciTitfes-(***)-.-:-"':-:-:=B:'2:'S3
-Selection of Project Operation (***)B-2-131
2 -ALTERNATIVE FACILITY DESIGN,PROCESSES AND
OPERATIONS (**'*).....0 ..• ••••• •
Title
1 -DAMSITE SELECTION (***)..0 e •
2.6 -
-----2-.7
2.8
..,--------------4-----POWER-AND-ENERGY--PRODUC!f.ION-{-***}-..-.-.-.-.--.--.-.--.-.-.--B-4-1----
4.1 -Plant and System Operation Requirements (***)
4.2 -Power and Energy Production (***)• • •
5.1 -Introduction (***).
5.2 -Description of the RailbeltE:lectricSystems C***)
5.3 -Forecasting Methodology (***)••••••
5.4 -Forecast of Electric Power Demand (***)
•0 • • ••• • • • • •e 0 0 • •0 •.0.
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B-3-1
B-5-1
B-3-1
B-3-6
B-3-20
B-7-1
B-6-1
B-4-1
B-4-10
B-5-1
B-5-1
B-5-17
B-5-47
.... . .. ..
• •• •
o 0 0 0 ••• •
•••• ••••
3.1 -Hydrology (***)• • • • • • • •..• • •
3.2 -Reservoir Operation Modeling (***)••••
3.3 -Operational Flow Regime Selection (***)
FUTURE SUSITNA BASIN DEVELOPMENT (***)
3 -DESCRIPTION OF PROJECT OPERATION (***)
6
5 -STATEMENT OF POWER NEEDS AND UTILIZATION (***)
7 -REFERENCES
851014 ')
)
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT B -APPENDIX BI
MAN-IN-THE-ARCTIC PROGRAM (MAP)
TECHNICAL DOCUMENTATION REPORT
STAGE MODEL (VERSION A8S.I)
REGIONALIZATION MODEL (VERSION A84.CD)
SCENARIO GENERATOR
Title
Stage Model
1.Introduction ..··· · ·· ·
· ··· ·
·· ·2.Economic Module Description · ···3.Fiscal Module Description · ·
· ·· ·
·4.Demographic Module Description ·· ·· ·
·· ·
· ·5.Input variables · ·
· ·· · · ·
·..·· ·6.Variable and Parameter Name Conventions · · ·
·7.Parameter Values,Defini tions and Sources · ·
· ·· ·8.Model validation and Properties ·· · ·
·· ·
· ···9.Input Data Sources ·· · ·
.....· ·
····10.Programs for Model Use ·· ·· ·
··· ·
· ···11.Model Adjustments for Simulation ···· ···· ·
I )12.Key.to Regressions ··· · ·I J 13.Input Data Archives · · ··· ·· · · · ·
Regionalization Model
Page No.
1-1
2-1
3-1
4-1
5-1
6-1
7-1
8-1
9-1
10-1
11-1
12-1
13-1
1.Model Description · ·····1
2.Flow Diagram · ·
·· ·
5
3.Model Inputs . .··· ·· ·
7
4.Variable and Parameter Names ··· · · ·
9
5.Parameter Values ·· ··· · ·· ··· ·
· ·
13
6.Model Validation ··· ·
·· · · ·
·· ·
31
7.Programs for Model ····· · ·· ·
·· · ·
·38
8.Model Listing ··· ·
39
9.Model Parameters ·· ···· ·
·· · · ···57
10.Exogenous,Policy,and Startup Values 61
Scenario Generator
Introduction • • • • • • • • • • • • • •
1.Organization of the Library Archives ••••
2.Using the Scenario Generator •••••••
3.Creating,Manipulating,Examining,and
pri nting Library Files •••••• • • • •
4.Model Output •••••••••••
1
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8
14
22
851014 v
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT B -APPENDIX B2
RAILBELT ELECTRICITY DEMAND (RED)MODEL
TECHNICAL DOCUMENTATION REPORT (i983 VERSION)
7 -PRICE ELASTICITY.--.....-.•••
5 -THE RESIDENTIAL CONSUMPTION MODULE •
7-.1
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Page No.-I
1.1 I
2.1
3.1 I
4.1 il1
5.1
601 (
.-...~-.--.:-0
.0.
o 00.•00.
e 0 0 0
• 0 • •
• • •e • • • •eo.0 0 •
. . .
1 -INTRODUCTION •
3 -UNCERTAINTY MODULE •
Title
2 -OVERVIEW • •
6 -THE BUSINESS CONSUMPTION MODULE
4 -THE HOUSING MODULE • •
8 -THE PROGRAM-INDUCED CONSERVATION MODULE
• • 0 • • • • • • • • • 0
10.1
12.1
13.1
11.1
8.1
9.1. . .
• • 0 0 0 • •
. . . .
o 0
. . .. .. .. ...
vi
10 -LARGE INDUSTRIAL DEMAND
11 -THE PEAK DEMAND MODULE
12 -MODEL VALIDATION
13 -MISCELLANEOUS TABLES
9 -THE MISCELLANEOUS MODULE
851014
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT B -APPENDIX B3
RAILBELT ELECTRICITY DEMAND (RED)MODEL
CHANGES MADE JULY 1983 TO AUGUST 1985
2 -RED MODEL PRICE ADJUSTMENT REVISIONS
3 -RESIDENTIAL CONSUMPTION MODULE
6 -EFFECT OF THE MODEL CHANGES ON THE FORECASTS
Title
1 -INTRODUCTION
4 -BUSINESS SECTOR
5 -PEAK DEMAND
851014
..... .
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vii
Page No.
1.1
2.1
3.1
4.1
5.1
6.1
SUMMARY TABLE OF CONTENTS (cont'd)
1.1 -Access (*)... .. .·1.Z Site Facilities (**)·· · ·
··· ··1.3 -Diversion (**)·· · · ···1.4 -Dam Embankment (**)'.·· ·
·· ·· ··1.5 -Spillway and'Intakes (**)··· ·1.6 -Powerhouse and Other Underground Works (**)·1.7 -Relict Channel (**).···· ·
··· ·· ·
·1.8 -Transmission Lines/Switchyards (*)·· ·1.9 -General (**). . .
,;·· ·· ·
·· ··
2 ...DEVIL CANYON STAGE II SCHEDULE (**)•••• •• •
..• •
EXHIBIT C
PROPOSED CONSTRUCTION SCHEDULE
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C-2 ....1
C-I-Z
C-I-Z
C-I-2
C-I-2
C-I-3
C-I-3
C-I-3
C-I-3
C-I-3
C-l-1
C-2-1
C-Z-1
C-Z-1
C-2-1
C-2-Z
<::";'-1'=-2"
C-Z-Z
C-Z-Z
Page No.
•e e
·..
•e f)•e •
· . ..,
·.........
·.
Z.1 -Access (**)•••••••••••••
2.Z -Site Facilities (**)•••
Z.3 -Diversion (*)•
Z.4 -Arch Dam (**)•
2.5 -Spillway and Intake (*)
"Z-;;6 .;;';p'owernouse -and OElierUnae-rgroundWorKs~~(or·
Z.7 -Transmission Lines/Switchyards (*)••••
Z.8 -General (*)• • • • • • • • • • •
1 -WATANA STAGE I SCHEDULE (**)
Title
3.1 -Access (***)•••••••••••••C-3-1
3.Z -Site Facilities (***)• • • • • • • •••C-3-1
-..--------·---,---3.-3 ---Dam--Embankment··(-***}•-,;....-.-..•.-.-.---;-..'C--3-1
.....-~~._~.-~..-..~----....-3..4-""---Spil.l.wa:y-and-Intakes..-(.***.).~.·~.-.·-.-·.~-.~·.~·.·~.-·····.-..-.·-·~·G-3-2--..-..---..-.-.-...
3.5 -Powerhouse and Other Underground Works (**)C-3-2
3.6 -Relict Channel (***)•••••••••C-3-Z
3.7 -Transmission Lines/Switchyards (***)••••C-3-Z
3.8 -General (***)• • • ••.•• • •• •C-3-Z
viii
• • • • • 0 0 • • •
3 -WATANA STAGE III SCHEDULE (***)•
4 -EXISTING TRANSMISSION SYSTEM (***)
851014
• • •••• •·..••C-3-1
C-4-1
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SUMMARY TABLE OF CONTENTS (cont'd)
EmIBIT D
PROJECT COSTS AND FINANCING
Title Page No.
1 -ESTIMATES OF COST (**)• • • • • • 0 eo.• •G • • •D-1-1
1.1 -Construction Costs (**)•••••••.•••
1.2 -Mitigation Costs (**)•
1.3 -Engineering and Administration Costs (*)••••
1.4 -Operation,Maintenance and Replacement Costs (**)
1.5 -Allowance for Funds Used During
Construction (AFDC)(**)•••••••••
1.6 -Escalation (**)• •.'• • • • • • • • • • •
1.7 -Cash Flow and Manpower Loading Requirements (**).
1.8 -Contingency (*)•.•••••••••••••
1~9 -Previously Constructed Project Facilities (*)
D-1-1
D-1-6
D-1-7
D-1-10
D-1-11
D-1-12
D-1-12
D-1-13
D-1-13
2 -EVALUATION OF ALTERNATIVE EXPANSION PLANS (***)•...D-2-1
2.1 -General (***)•••••••••••
2.2 -Hydroelectric Alternatives (***)••••
2.3 -Thermal Alternatives (***)
2.4 -Natural Gas-Fired Options (***)•
2.5 -Coal-Fired Options (***)••••••
2.6 -The Existing Railbelt Systems (***)•••••.•
2.7 -Generation Expansion Before 1996 (***)
2.8 -Formulation of Expansion Plans Beginning in
1996 (***)•••••••••••••
2.9 Selection of Expansion Plans (***)•••••
2.10 -Economic Development (***)••••••
2.11 -Sensitivity Analysis (***)••••••••
2.12 -Conclusions (***)•••••••
D-2-1
D-2-1
D-2-10
D-2-10
D-2-19
D-2-24
D-2-27
D-2-28
D-2-33
D-2-39
D-2-44
D-2-46
3 -CONSEQUENCES OF LICENSE DENIAL (***)......D-3-1
3.1 -Statement and Evaluation of the
Consequences of License Denial (***).
3.2 -Future Use of the Damsites if
the License is Denied (***)• • • • • •
4 -FINANCING (***)• • • • • • • • • • • • • • •
4.1 -General Approach and Procedures (***)•
4.2 -Financing Plan (***)••••••••
4.3 -Annual Costs (***)••••••••••
•••• •
D-3-1
D-3-1
D-4-1
D-4-1
D-4-1
D-4-3
851014 ix
SUMMARY TABLE··OF CONTENTS (cont f d)
EXHIBIT D
PROJECT COSTS AND FINANCING
Title
4.4 -Market Value of Power (***)• •
4.5 -Rate Stabilization (***)
4.6 -Sensitivity of Analyses (***)
•0 0 _ • • • • 0
Page No.
D-4-4
D-4-4
D-4-4
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5 -REFERENCES (***)
851014
e-• • • • •0 • • • • • • • •D • • •
x
D-5-1
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SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT D -APPENDIX D1
FUELS PRICING
o • • • • • ••0 ~eo.•0 e _0
Title
1 -INTRODUCTION (***)
2 -WORLD OIL PRICE (***)• • •• • 0 • 0 • •eo.....
Page No.
Dl-l-l
Dl-2-1
. .
2.1 -The Sherman H.Clark Associates Forecast (***)
2.2 -The Composite Oil Price Forecast (***)
2.3 -The Wharton Forecast (***)••••
Dl-2-1
Dl-2-2
Dl-2-5
3 -NATURAL GAS (***)•0 •••....o G • •G.• • • • • •Dl-3-1
3.1 -Cook Inlet Gas Prices (***)•Dl-3-1
3.2 -Regulatory Constraints on the Availability of
Natural Gas (***)• • • • • • • • • • • • •Dl-3-10
3.3 -Physical Constraints on the Availability of
Cook Inlet Natural Gas Supply (***)••• ••Dl-3-12
3.4 -North Slope Natural Gas (***)•Dl-3-20
. .
4 -COAL (***)
4.1
4.2
4.3
4.4
..... ........ ........
-Resources and Reserves (***)
-Demand and Supply (***)• • • •••••
-Present and Potential Alaska Coal Prices (***)
-Alaska Coal Prices Summarized (***)•
.'Dl-4-l
Dl-4-1
Dl-4-3
Dl-4-4
Dl-4-10
• • •• •• ••••• ••••••5 -DISTILLATE OIL (***)
5.1 -Availability (***)••••
5.2 -Distillate Price (***)
. ... .
Dl-5-1
Dl-5-1
Dl-5-1
6 -REFERENCES
851014
.... ..................
xi
Dl-6-1
SUMMARY TABLE OF CONTENTS (cont'd)
-----~.._---~~.._~.._._--~~---_...--~-_._._.~---.~-~.._-~--~-~--~----~-~~----_.------_.~---_._---~---_.~--_.---.•.__.~..
•• 0 • • •e 0 eo.0 e •e c •e e eo.
EXHIBIT E -CHAPTER 1
GENERAL DESCRIPTION OF THE LOCALE
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Page No.
E-I-I-I
E-I-3-1
E-I-2-1
E-I-I-I
E..;,I-I..;,2
....
o 0 e 0
• •e <0 0••
o 0 0 Gee 0 •
"e 0 e
••0 • • D •0
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1.1 -General Setting (**)
1.2 -Susitna Basin (*)
3 -GLOSSARY • •
1 -GENERAL DESCRIPTION (*)••
Title
2 -REFERENCES
1
-)
xii ..
SUMMARY TABLE OF CONTENTS (conttd)·
EXHIBIT E -CHAPTER 2
WATER USE AND QUALITY
Title Page No.
I -INTRODUCTION (**)• • • •o • • • • ••• • •
o ..• •e E-2-1-1
1
I
2 -BASELINE DESCRIPTION (**)•..•co • • • • •·•·E-2-2-1
2.1 -Susitna River Morphology (**)· ··E-2-2-3
2.2 -Susitna River Water Quantity (**)E-2-2-12
2.3 -Susitna River Water Quality (**)•· ·
.•··E-2-2-19
2.4 -Baseline Ground Water Conditions (**)··..E-2-2-46
2.5 -Existing Lakes,Reservoirs,and Streams (**)E-2-2-49
2.6 -Existing Instream Flow Uses (0)E-2-2-50
2.7 -Access Plan (**),E-2-2-63...·2.8 -Transmission Corridor (**)..·E-2-2-64
3 -OPERATIONAL FLOW REGIME SELECTION (***)•• ••co ·...E-2-3-1
3.1 -Project Reservoir Characteristics (***)
3.2 -Reservoir Operation Modeling (***)..
3.3 -Development of Alternative Environmental
Flow Cases (***)•••••••••••••
3.4 -Detailed Discussion of Flow Cases (***).•
3.5 -Comparison of Alternative Flow Regimes (***).
3.6 -Other Constraints on Project Operation (***)
3.7 -Power and Energy Production (***)•••••
~4 -PROJECT IMPACT ON WATER QUALITY AND QUANTITY (**)co ..co
E-2-3-1
E-2-3-2
E-2-3-6
E-2-3-17
E-2-3-37
E-2-3-43
E-2-3-53
E-2-4-1
4.1 -Watana Development (**)••••••
4.2 -Devil Canyon Development (**)•••
4.3 -Watana Stage III Development (***).
4.4 -Access Plan (**)••••••
5 -AGENCY CONCERNS AND RECOMMENDATIONS (**)
·. .
·......
E-2-4-7
E-2-4-110
E-2-4-160
E-2-4-211
E-2-5-1
6 -MITIGATION,ENHANCEMENT,AND PROTECTIVE MEASURES (**)•
6.1 -Introduction (*)••••••••••••..••
6.2 -Mitigation -Watana Stage I -Construction (**)
6°.3 -Mitigation -Watana Stage I -Impoundment (**).
E-2-6-1
E-2-6-1
E-2-6-1
E-2-6-5
851014 xiii
Title
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 2
WATER USE AND QUALITY
6.4 -Watana Stage I Operation (**)• • • • • • • •
6.5 -Mitigation -Devil Canyon Stage II -
Construction (**)• • • • • • • •
6.6 -Mitigation -Devil Canyon Stage II -
Impoundment (**)•••••••• • • • • •
6.7 -Mitigation -Devil Canyon/Watana Operation (**)•
6.8 -Mitigation -Watana Stage III -
Construction (***)••••••••••
6.9 -Mitigation -WataUa Stage III-
Impoundment/Construction (***)•••
6 ..10 -Mitigation -Stage III Operation (***)•••••
6.11 -Access Road and Transmission Lines (***)••••
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E-2-6-7
E-2-6-13
E-2-6-15
E-2-7-1
E-2-6-13
E-2-6-13
E-2-8-1
E-2-6-16
E-2-6-16
E-2-6-18
....tI • •
• •e • •tI •tI.,....•••
•eo.• • •~•0 eo.•0 • • •e • • • •
7 -REFERENCES " •
8 -GLOSSARY
851014
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SUMMARY TABLE OF CONTENTS (cant'd)
EXHIBIT E -CHAPTER 3
FISH,WILDLIFE,AND BOTANICAL RESOURCES
Title Page No.
1 -INTRODUCTION (0)E-3-1-1
1.1 -Baseline Descriptions (0)
1.2 -Impact Assessments (*)••
1.3 -Mitigation Plans (*)••
E-3-1-1
E-3-1-1
E-3-1-3
2 -FISH RESOURCES OF THE SUSITNA RIVER DRAINAGE (**)o'J 0 0
· .
I]2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
-Overview of the Resources (**>••••
-Species Biology and Habitat Utilization
in the Susitna River Drainage (*)••••.•
-Anticipated Impacts To Aquatic Habitat (**)
-Mitigation Issues and Mitigating Measures (**)
-Aquatic Studies Program (*)• •••• •
-Monitoring Studies (**)•••••••"'•••
-Cost of Mi tigation (***)••••••••
-Agency'Consultation on Fisheries Mitigation
Measures (**)• • • • • • • • • • • • •
E-3-2-1
E-3-2-1
E-3-2-14
E-3-2-104
E-3-2-244
E-3-2-279
E-3-2-280
E-3-2-303
E-3-2-304
3 -BOTANICAL RESOURCES (**)·........'......E-3-3-1
3.1 -Introduction (*)····3.2 -Baseline Description (**)··.···3.3 -Impacts (**)..· · ·
.·3.4 -Mitigation Plan (**)·····
4 -WILDLIFE (**)..•.• • • •••••.•.•••• • •
E-3-3-1
E-3-3-6
E-3-3-34
E-3-3-63
E-3-4:-1
4.1 -Introduction (*)••••
4.2 -Baseline Description (**)• •
4.3 -Impacts (*).•••••.••
4.4 Mitigation Plan (**)
·. .
· . . . . .
E-3-4-1
E-3-4-3
E-3-4-110
E-3-4-248
5 -AIR QUALITY/METEOROLOGY (***)•............E-3-5-1
·. .
5.1 -Introduction (***)•••••••••••••
5.2 -Existing Conditions (***)••••••
5.3 -Expected Air Pollutant Emissions (***).
5.4 -Predicted Air Quality Impacts (***)••
E-3-5-1
E-3-5-1
E-3-5-2
E-3-5-3
851014 xv
SUMMARY TABLE OF CONTENTS (cant'd)
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E-3-7-1
E-3-6-1
E-3-5-3
Page No.
.........••..........
METHODS USED TO DETERMINE MOOSE BROWSE UTILIZATION
AND CARRYING CAPACITY WITHIN THE MIDDLE SUSITNA BASIN
STATUS,HABITAT USE AND RELATIVE ABUNDANCE OF BIRD
SPECIES IN THE MIDDLE SUSITNABASIN
EXISTING AIR QUALITY AND METEOROLOGICAL CONDITIONS
EXJ?I..ANATI()NA.l@ JUS'I'I:Fr.CA.1JQN:.O:F.,A.~'I'.I::F1CIA.I..:N~$T
MITIGATION (THIS SECTION HAS BEEN ,DELETED)
FISH AND WILDLIFE MITIGATION POLIC~
PERSONAL COMMUNICATIONS (THIS SECTION HAS BEEN
DELETED)
• •eo.G •0 • • • • • • • ••• ••0 •0
• •
5.5 -Regulatory Agency Consultations (***)••
EXHIBIT E -CHAPTER 3
FISH,WILDLIFE,AND BOTANICAL RESOURCES
E1.3
7 -GLOSSARY
E6.3
Title
E8.3
E3.3
E4.3
E9.3
Ell.3
E5.3
APPENDICES
6 -REFERENCE
E2.3 ENVIRONMENTAL GUIDELINES MEMORANDUM
(THIS APPENDIX HAS BEEN DELETED)
PLANT SPECIES IDENTIFIED IN SUMMERS OF 1980 AND 1981
IN THE UPPER AND MIDDLE SUSITNA RIVER BASIN,THE
DOWNSTREAM FLOODPLAIN,AND THE INTERTIE
PRELIMINARY LIST OF PLANT SPECIES IN THE INTERTIE
AREA (THIS SECTION HAS BEEN DELETED AND ITS
-.,.--.-----'.---.-.--r-NFORMA:TION~I'NCORPORA:TED--r-NTO=kPPENDIX~E3-.c3~~~)~
STATUS AND RELATIVE ABUNDANCE OF BIRD SPECIES
OBSERVED ON THE LOWER SUSITNA BASIN DURING GROUND
SURVEYS CONDUCTED JUNE 10 THE JUNE 20,1982
__-_._--_---_.- -.-.'-.-._------_--.._...._._._-_...-.
..E2•.3__.S.CI.ENT_IE.I.C_NAME.S_QF_MAMMAL_S.PECIES....EOUND_IN.....THE
PROJECT AREA
SUMMARY TABLE OF CONTENTS (cont I d)
EXHIBIT E -CHAPTER 4
HISTORIC AND ARCHEOLOGICAL RESOURCES
Title
1 -INTRODUCTION AND SUMMARY (**)0 co 0 0 ••co •co ..... ..
Page No.
E-4-1-1
1.1 -Program Objectives (**)
1.2 Program Specifics (**)
• • • • • " • 0
E.,.4-1-4
E-4-1-4
2 -BASELINE DESCRIPTION (**)co • o • o .. ..........co co ••E-4-2-1
(I
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2.1 The Study Area (**)••••••••
2.2 -Methods -Archeology and History (**)•
2.3 -Methods -Geoarcheology (**)•••
2.4 -Known Archeological and Historic
Sites in the Project Area (**)•••
2.5 -Geoarcheology (**)••••••••
ID 0 •"
. ..
E-4-2-1
E-4-2-2
E-4-2-10
E-4-2-12'
E-4-2-13
3 -EVALUATION OF AND IMPACT ON HISTORICAL
AND ARCHEOLOGICAL SITES (**)..co ......e 9 •e 0 0 • •E-4-3-1
3.1 -Evaluation of Selected Sites Found:
Prehistory and History of the Middle
Susitna Region (**)• • • • • • • • • • • • • • •
3.2 -Impact on Historic and Archeological Sites (**)•
4 -MITIGATION OF IMPACT ON HISTORIC AND
ARCHEOLOGICAL SITES(**)• •co ...... .. .. ..co e 0 .0 . . .
.E-4-3-1
E-4-3-4
E-4-4-1
4.1 -Mitigation Policy and Approach (**)•••••••
.4.2 -Mitigation Plan (**)•••••••••
E-4-4-1
E-4-4-2
5 -AGENCY CONSULTATION (**)• •••e •e e 0 e 0 0 0 •0 E-4-5-1
6 -REFERENCES •0 • • •eo.• • • • • • • • • • • • • •E-4-6-1
IJ
7 -GLOSSARY
851014
• •0 ••••• • • • • • • • ••• • • • • •
xvii
E-4-7-1
SUMMARY TABLE OF CONTENTS (cont ed)
2.1 -Identification of Socioeconomic
Impact Areas (**)• • • • • • •••• • • • • • •E-5-2-1
2.2 -Description of Employment,Population,Personal
Income and Other Trends in the Impact Areas (**)E-5-2-1
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E-5-3-49
E-5-3-35
E-5-3-39
E-5-3-65
E-5-4-2
E-5-3-1
E-5-2-1
E-5-3-59
E-5-4-1
E-5-4-1
E-5-4-2
E-5-1-1
Page No.
.,.,.,
. ..
fill •e 5 ..
..,
o • • •
...
.,.,.,• •• •
o •• • • ••0 ••$•e D
., .,
····xviii
3.1 -Impact of In-migration of People on Governmental
Faci Ii ties and·Services (**)••••••••••
3.2 -On-site Worker Requirements and Payroll,
by Year and Month'(**)• • • • • • • • •
3.3 -Residency and Movement of Project Construction
Personnel (**)•••••••••••••••••
3.4 -Adequacy of Available Housing in
Impact Areas (***)••••••••••••
Di-spl-ac'ement-and'"-!nfluenc'es-'on~Re-srde'trcce'$~ana-~-"
Businesses (**)'•••••••••••••••••
3.6 -Fiscal Impact Analysis:.Evaluation of
Incremental Local Government Expenditures
and Revenues (**)• • " • • • • • •
3.7 -Local and Regional Impacts on
Resource User Groups (**)• • • •
BASELINE DESCRIPTION (**)•
4.1 -Introduction (**)•••••••
4.2 -Background and Approach (**)
4.3 -Attitudes Toward Changes
(This section deleted)
4.4 -Mitigation Objectives and Measures (**)••
1014
EXHIBIT E -CHAPTER 5
SOCIOECONOMIC IMPACTS
3 -EVALUATION OF THE IMPACT OF THEPRO.JECT (**)
2
1 -INTRODUCTION (**)• •0 .,.,
Title
SUMMARY TABLE OF CONTENTS (eont'd)
EXHIBIT E -CHAPTER 5
SOCIOECONOMIC IMPACTS
Title
5 -MITIGATION MEASURES RECOMMENDED BY AGENCIES(**)....
Page No.
E-S-S-l
6 -REFERENCES ••••••• • •-.• • • • •0 • • • • • 0 E-6-6-1
. . .
II
IJ
S.l -Alaska Department of Natural Resources (DNR)(**)
S.2 -Alaska Department of Fish and Game (ADF&G)(*)
S.3 -U.S.Fish and Wildlife Service (FWS)(*)
S.4 -Summary of Agencies'Suggestions for Further
Studies that Relate to Mitigation (**)
E-S-S-l
E-S-S-l
E-S-S-2
E-S-S-2
8S1014 xix
SUMMARYTABI..E OF CONTENTS (cont'd)
3.1 -Reservoir-Induced Seismicity (RIS)(*)• •E-6-3-1
3.2 -Seepage (*)• • • • • • • • • • • • • • • • •E-6-3-4
3.3 -Reservoir Slope Failures (**)• • • • •E-6-3-4
3.4 -Permafrost Thaw (*)• • • • • • • • • • • •E-6-3-11
3.5 -Seismically-Induced Failure (*)• • • • • • •••E-6-3-11...-_._-~-~_.__._-----3-:-6-------Reservoir-FreeDo-ard---rcir-·Wind;--·Wav"es--_._~-**).-~.--~---.-=-_._~._~._---E--6=3=11
3.7 -Development of Borrow Sites and Quarries (**)• •E-6-3-12
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Page No.
E-6-1-1
E-6-3-1
E-6-2-1
E-6-2-2
E-6-2-3
E-6-2-4
E-6-2-11
E-6-2-17
E-6-2-23
E-6-4-1
E-6-5-1
E-6-2-1
••
· ..
·..
·...
....
o • •0 •
. .
.".
. . . .
· . .
·""
·.."
... .
••
• •
••••••
.. .
....
•• ••
• •••
...(*)
o .0.• • 0 •
•••••
• • • •••
(**)
xx
. . . . . ..• . . . ..0.. .eo.0 .
••• ••• • • 0 • • • • • 0 • • • • • •0 •
-Regional Geology (*)••••••••
-Quarternary Geology (*)
-Mineral Resources (0)• • • • • • • •
-Seismic Geology (*)• •
-Watana Damsite (**)••
-Devil Canyon Damsite (0)••••
-Reservoir Geology (*)• • • • • • • • •
EXHIBIT E -CHAPTER 6
GEOLOGICAL AND SOIL RESOURCES
2.1
2.2
2.3
2.4
2.5
2.6
2.7
1 -INTRODUCTION
Title
2 -BASELINE DESCRIPTION
3-IMPA.CTS (*)•..
5 -REFERENCES
4 -MITIGATION (**)•
6 ....GLOSSARY
851014
4.1 -Impacts and Hazards (0)• • • • • • •••E-6-4-1
4.2 -Reservoir-Induced Seismicity (0)• • •E-6-4-1
4.3 -Seepage (**).• • • • • • • • • • • •E-6-4-2
.........................,,4';-4 ReservoirSlope'FaUure's"(**),;,;....;...;···;·················..E.;..;6·~;;;;2·"···..·
....·~····..,4·.5·-Perma·f·rost~-Thaw··€-**~·~""• • • • •.'·;·;-·'E..6·4'-..3 ,~.
4.6 -Seismically-Induced Failure (*)• • • • • • •••E-6-4-3
4.7 -Geologic Hazards (*)• • • •E-6-4-4
4.8 -Borrow and Quarry Sites (*)• • • • • • • • •E-6-4-4
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 7
RECREATIONAL RESOURCES
Title Page No.
1 -INTRODUCTION (**)• •• • •
o • •'0 e ••••••eo • •E-7-1-1
11
1.1 -Purpose (**)
1.2 -Relationships to Other Reports (*)
1.3 -Study Approach and Methodology (**)•
1.4 -Project Description (**)••••~
2 -DESCRIPTION OF EXISTING AND FUTURE RECREATION
WITHOUT THE SUSITNA PROJECT (**)••0 •0 ••••
2.1 -Statewide and Regional Setting (**)•
2.2 -Susitna River Basin (**)••.•••
o •
E-7-1-1
E-7-1-1
E-7-1-1
E-7-1-3
E-7-2-1
E-7-2-1
E-7-2-8
3.1 -Direct Impacts of Project Features (**)
3.2 -Project Recreational Demand Assessment •••
(Moved to Appendix E4.7)[I
3 -PROJECT IMPACTS ON EXISTING RECREATION (**)•
4 -FACTORS INFLUENCING THE RECREATION PLAN (**)
e • • • •
.....
E-7-3-1
E-7-3-1
E-7-3-12
E-7-4-1
4.1 Chara'cteristics of the Project Design and
Operation (***)• • . • • • • • • • • • • . • • •
4.2 -Characteristics of the Study Area,(***)•
4.3 -Recreation Use Patterns and Demand (***)•.••
4.4 -Agency,Landowner and Applicant Plans and
Policies (***)•••••••••••••••
4.5 -Public Interest (***)"••••••••••
4.6 -Mitigation of Recreation Use Impacts (***)
E':'7-4-1
E-7-4-2
E-7-4-2
E-7-4-3
E-7-4-12
E-7-4-13
5 -RECREATION PLAN (**)• • • • • • • • •0 • • • • • • •E-7-5-1
6 -PLAN IMPLEMENTATION (**)
. . .
II--'
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5.1
5.2
5.3
5.4
851014
-Recreation Plan Management Concept (***)
-Recreation Plan Guidelines (***)• • • • • •
-Recreational Opportunity Evaluation • ••••
(Moved to Appendix E3.7.3)
-The Recreation Plan (**)
...............
xxi
E-7-5-1
E-7-5-2
E-7-5-4
E-7-5-4
E-7-6-1
SUMMARY TABLE OF CONTENTS (cont'd)
!.
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E-7-10-1
E-7-8-1
E-7-8-1
E-7-8-1
E-7-8-2
E-7-8-1
E-7-7-1
E-7-7-1
E-7-7-2
E-7-7-1
Page No.
E-7-6-1
E-7-6-1
E-7-6-2
E-7-6-3
..
. ..
..••.•• 0 •
• • • • ••••e e e 0 e 0 0
.'• • 0 • • • •~• • • • •eo.• • • •
xxii
RECREATION SITE INVENTORY AND OPPORTUNITY EVALUATION
EXAMPLES OF TYPICAL RECREATION FACILITY DESIGN
STANDARDS.FOR THE SUSITNA PROJECT
PHOTOGRAPHS OF SITES'WITHINTHE·PROJECT RECREATION
STUDY AREA
PROJECT RECREATIONAL DEMAND ASSESSMENT
DATA ON REGIONAL RECREATION FACILITIES
o 0
EXHIBIT E -CHAPTER 7
RECREATIONAL RESOURCES
7.1 -Construction (**)•••••••
7.2 -Operations and Maintenance (**)
7.3 -Monitoring (***)•••••••
8.1 -Agencies and Persons Consulted (**)•
8.2 -Agency Comments (**)••••.••
8.3 -Native Corporation Comments (***)
8.4 -Consul tation Meetings (***)
6.1 -Phasing (**)••••••••••••••.••
6.2 -Detailed Recreation Design (***)•••••
6.3 -Operation and Maintenance (***)••
6~4 -Monitoring (**)•••••••••
E5.7
APPENDICES
851014
10 -GLOSSARY
E1.7
E6.7.··
E4.7
8 -AGENCY COORDINATION (**)
Title
7 -COSTS FOR CONSTRUCTION AND OPERATION OF THE PROPOSED
RECREATION FACILITIES (**)••••••••••0 • ••
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E ~CHAPTER 8
AESTHETIC RESOURCES
Title
1 -INTRODUCTION (**)••...••.... .•Cl 0 • •
...·.
Page No.
E-8-1-1
· ..
1.1 -Purpose (*)...•.
1.2 -Relationship to Other Analyses (*)
1.3 -Environmental Setting (**)•••·. .
E-8-1-1
E-8-1-1
E-8-1-1
G eo.e 0 0 0 •••••.••••
2 -PROCEDURE (*)• • ••
3 -STUDY OBJECTIVES (*)
• •..0 • •• • • • • • • • •• •
E-8-2-1
E-8-3-1
• • • 0 :.Cl • • • • • • • • • •4 -PROJECT FACILITIES (*)
4.1 -Watana Project Area (*)• • • • • • • • • •
4.2 -Devil Canyon Project Area (*)r~>.• • • • • • • • •
4.3 -Watana Stage III Project Area (***)••••••
4.4 -Denali Highway to Watana Dam Access Road (*)
4.5 -Watana Dam to Devil Canyon Dam Access Road (*)
4.6 -Transmission Lines (*)
4.7 -Intertie •••.•.•••.•••••.•••.
(This section deleted)
4.8 -'Recreation Facilities and Features (*)••
E-8-4-1
E-8-4-1
E-8-4-1
E-8-4-1
E-8-4-1
E-8-4-2
E-8-4-2
E-8-4-2
E-8-4-2.
5 -EXISTING LANDSCAPE (**)•••••• • • • ••·.....E-8-5-1
5.1 -Landscape Character Types (*)••
5.2 -Notable Natural Features (**)••·. . .
. .· .
E-8-5-1
E-8-5-1
. . . . . . . . ... . ... . . ...4.6 -VIEWS (**)
6.1 -Viewers (***)
6.2 -Visibility (***)
. . .· . . .... .
E-8-6-1
E-8-6-1
7 -AESTHETIC EVALUATION RATINGS (**)·..•••••••••E-8-7-1
I
J
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7.1 -Aesthetic Value Rating (*)
7.2 -Absorption Capability (*)•
7.3 -Composite Ratings (**)••
· .·......· . . ...
E-8-7-1
E-8-7-1
E-8-7-2
851014 xxiii
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 8
AESTHETIC RESOURCES
Title Page No.
l
;(
(
)
. I
11 -AGENCY COORDINATION (**)•• • • •••• • •••·• •
E-S-ll-1
11.1 -Agencies and Persons Consulted (**)··.E-S-ll-l
11.2 -Agency Comments (**)•• •··• •
E-8-11-1
12 -REFERENCES •.0 ••0 • • • •••• . 0 0 •0 •0 • • •
E-S-12-1
9.1 -Mitigation Feasibility (**)•••••••••
9.2 -Mitigation Plan (***)•••••••••
9.3 -Mitigation Costs (**)••••
9.4 -Mitigation Monitoring (***)•••••
S.l -Mitigation Planning of Incompatible
Aesthetic Impacts (Now addressed in Section 9)
8.2 -Watana Stage I (***)• • • • • ••••
S.3 -Devil Canyon Stage II (***)••
S.4 -Watana Stage III (***). • • • • • • • • • •
8.5 -Access Routes (***)• • •.~•••••
8.6 -Transmission Facilities (***)••••••••••
,.\'
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1
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1
E-8-10-1
E-8-8-1
E-S-9-1
E"'S-9-1
E-8-9-2
E-S-9-11
E-S-9-12
E-8-8-1
E-8-8-2
E-S-8-3
E-S"'S-4
E-S-8-5
E-S-8-6
• • •0 •
e •0 • • •• • • •e e e
•0 e • • •e e 0 G •e 0 0 •0
xxiv
• • • 0 • • • • • • • • • • • • • • • 0 ••E-S-13-1
_..--"._---~~.-.~-_..__.._~_.~.__.._._----------_.._---~-_.._-_._---_._~._.__._---------_...---"----_.._-------------------_.._--------------_.._"-"--_..
SITE PHOTOS WITH SIMULATIONS OF PROJECT FACILITIES
EXCEPTIONAL NATURAL FEATURES
EXAMPLES OF EXISTING AESTHETIC IMPACTS
·PHOTOS OF PROPOSED PROJECT FACILITIES·SITES
-GLOSSARY •
E1.8
E2.8
APPENDICES
8-AESTHETIC IMPACTS (**)
E4.8
E3.8.
9 -MITIGATION (**)e e 0 0 • • 0
10 -AESTHETIC IMPACT EVALUATION OF THE INTERTIE
--"-~<-This.Section.DelectecL)-.~..~...".-....~._~
.851014
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 8
AESTHETIC RESOURCES
Title
APPENDICES (cont'd)
Page No.
J
E5.8
E6.8
E7.8
E8.8
E9.8
85~014
EXAMPLES OF RESERVOIR EDGE CONDITIONS SIMILAR TO THOSE
ANTICIPATED AT WATANA AND DEVIL CANYON DAMS
PROJECT FEATURES IMPACTS AND CHARTS
GENERAL AESTHETIC MITIGATION MEASURES APPLICABLE TO THE
PROPOSED PRO~ECT
LANDSCAPE CHARACTER TYPES OF THE PROJECT ARE~
AESTHETIC VALUE AND ABSORPTION CAPABILITY RATINGS
xxv
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E-CHAPTER 9
LAND USE
AREA (***)eo.• •C)• • •0 .'-.0 e _0
J.
.1
\
1
[
.I
1
I
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1
Page No.
E-9-2-l
E-9-1-1
E-9-4--1
E-9--3-1
E-9-2-l
E-9-2-1
E-9-5-1
E-9-6-1
....
....
.. .
.."..
• •Cl 0
..eo ..
......
...
• •C'•G Q.e
.".
•DO.• •0 0
""e
• 0 • 0 • • 0 •0
• • •e 0
•••• •
" " "
. ..
•.f)•"
....
o GO.
c a 0 •
2.1 -Historical Land Use (***)
2.2 -Present Land Use (***)
1 -INTRODUCTION (***)"""""e "..e ..
Title
3 -LAND MANAGEMENT PLANNING IN THE PROJECT
4 -IMPACTS ON LARD USE WITH AND WITHOUT THE
PROJECT (***).."..eo ".."..".."..•
2 -HISTORICAL AND PRESENT LAND USE (***)
5 -MITIGATION (***)"
6 -REFERENCES
851014 ,',.xxvi
\
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1
1
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 10
ALTERNATIVE LOCATIONS J DESIGNS J AND ENERGY SOURCES
Title Page No.
1 -ALTERNATIVE HYDROELECTRIC SITES (*)•0 • • • •G e o •E-10-1-1
1.1 -Non-Susitna Hydroelectric Alternatives (*)
1.2 -Assessment of Selected Alternative
Hydroelectric Sites (***)• • • • •
1.3 -Middle Susitna Basin Hydroelectric
Alternatives (0)••••••••••••
1.4 -Overall Comparison of Non-Susitna
Hydroelectric Alternatives to the
Proposed Susitna Project (***)
E-10-l-1
E-10-1-2
E-10-1-17
E-10-1-32
2 -ALTERNATIVE FACILITY DESIGNS (*)G •5 •• • • •0 • •E-10-2-1
2.1 -Watana Facility Design Alternatives (*)•••••
2.2 -Devil Canyon Facility Design Alternatives (0)
2.3 -Ae;cess Alternatives (0)•••••••••••••
2.4 -Transmission Alternatives (0)
2.5 -Borrow Site Alternatives (**)•••••.••••
E-10-2-1
E-10-2-3
E-10-2-4
E-10-2-24
E-10-2-53
3 -OPERATIONAL FLOW REGIME SELECTION (***)• •......E-1O-3-1
3.1 -Project Reservoir Characteristics (***)•••••
3.2 -Reservoir Operation Modeling (***)
3.3 -Development of Alternative Environmental
.Flow Cases (***)••••••••••••••••
3.4 -Detailed Discussion of Flow Cases (***)• • • • •
3.5 -Comparison of Alternative Flow Regimes (***)
3.6 -Other Constraints on Project Operation (***)
3.7 -Power and Energy Production (***)••••••
E-10-3-1
E-10-3-2
E-10-3-6
E-IO-3-17
E-10-3-38
E-1O-3-43
E-IO-3-53
4 -ALTERNATIVE ELECTRICAL ENERGY SOURCES (***)••••• •
E-10-4-1
u
4.1 -Coal-Fired Generation Alternatives (***)
4.2 -Thermal Alternatives Other Than Coal (***)
4.3 -Tidal Power Alternatives (***)••••
4.4 Nuclear Steam Electric Generation (***)
4.5 -Biomass Power Alternatives (***)
4.6 -Geothermal Power Alternatives (***)••
E-lO-4-1
E-lO-4-27
E-lO-4-39
E-lO-4-41
E-lO-4-42
E-lO-4-42
851014 xxvii
SUMMARY TABLE OF CONTENTS (cont I d)
EXHIBIT E -CHAPTER 10
ALTERNATIVE LOCATIONS:t DESIGNS:t AND ENERGY SOURCES
l
oj
\
Title
4.7 -Wind Conversion Alternatives (***)••••
4.8 -Solar Energy Alternatives (***)• • • • • •
4.9 -Conservation Alternatives (***)•••••••
• •e _e e 0 0 • 0 •••0 •G e $0 0 0 •
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E-lO-4-43
E-lO-4-44
E-lO-4-44
E-IO-7-l
Page No.
E-lO-6-l
E-lO-5-le•
xxviii
••0 • •e 0 e 0 0 ••c •e 0 0 • •eo.07 -GLOSSARY
5 -ENVIRONMENTAL CONSEQUENCES OF LICENSE DENIAL (***)
6 -REFERENCES
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 11
AGENCY CONSULTATION
Title Page No.
1 -ACTIVITIES PRIOR TO FILING THE INITIAL
APPLICATION (1980-February 1983)(***)
2 -ADDITIONAL FORMAL AGENCY AND PUBLIC
CONSULTATION (***)• • • • • • • • • •
••e G •e 0 0 •
••••• • • •0
E-ll-l-l
E-1l-2-1
I II.,
I IU
2.1 -Technical Workshops (***)•••••••••
2.2 -Ongoing Consultation (***)• • • • • •
2.3 -Further Comments and Consultation (***)•••••
E-1l-2-1
E-1l-2-1
E-1l-2-2
851014 xxix
SUMMARY TABLE OF CONTENTS (cont I d)
EXHIBIT F
SUPPORTING DESIGN REPORT (PRELIMINARY)
Title Page No.
1 -PROJECT DATA (***).... .. ....Cl o 0 0 e o Cl 0 0 .... ......F-1-1
• • • • • •e _ •e • •Cl •C F-2-1
F-2-1
F-2-1
F-2-1
F-2-1
F-2-1
F-2-2
. .
·. .
·. .
·..
..'••0 •
· . .
. .· ..
· . .
...2.1 -Topographical Data (0)
2.2 -Hydrological Data (**)••
2.3 -Meteorological Data (*)••••••••
2.4 -Reservoir Data (0)••
2.S -Tailwater Elevations (0)•••••••
2.6 -Design Floods (**)•••••••••
2 -PROJECT DESIGN DATA (**)
3.1 -Governing Codes and
3.2 -Design Loads (**)•
3.3 -Stability (*)•••
3.4 -Material Properties
...Standards (0)
(0)•
F-3-1
F-3-1
F-3-1
F-3-6
F-3-9
.. ..
. .
· . .
•• • •
· . .· . .
. .
Cl e • • •....
·..
·......3 -CIVIL DESIGN DATA (*)
4 -GEOTECHNICAL DESIGN DATA (**).... .. .. ...... ..•••••F-4-1
4.1 -Watana (**)• •••
4.2 Devil Canyon (**)· .
...• •G •· . .
F-4-1
F-4-10
S -HYDRAULIC DESIGN DATA (**)••0 • • •.'•.•• • • • •
F-S-1
S.l -River Flows (**)• • • • • • • • • • •F-S-l
S.2 -Design Flows (**)• • • • • • •F-S-1
..............._~.•.I=Re~~~yQi.?;I,._~.y~1§1 ..{~1._'.......•....••L'_.....F~S~L ..
S.4 -Reservoir Operating ..Rule (**).!..!.--"--'!._F~S-2_.
··----·S.5-Reservoir Data (**f-=-=--:--:'-=--=-.:.• • • • • • • •F-S-2
S.6 -Wind Effect (**)•••••••••••• • •F-S-3
5.7 -Criteria (***)• •F-5-3
6 -EQUIPMENT DESIGN CODES AND STANDARDS (**).... .. ....Cl ..F-6-1
6.1 -Design CQdesand Standards (*)
6.2 -General Criteria (*)•••••
• • 0 e 0 0,
~0 0 COD G D 0
F~6~1
F-6...2
851014
I
)
I
SJ.N3J.NOO :10 318'0'J.
ii
EXHIBIT B
PROJECT OPERATIONA.ND·RESOURCE UTILIZATION
1.5.1 -Evaluation Methodology (*)•...B-I-I7
(a)Initial Economic Analyses (*)B-I-20
(i)Plan EI -Watana/Devil
Canyon (*)• • • • • • •B-1-20
,··_·_-_·(-u-)'-Pl-anE2~-HigIiDeviT
Canyon/Vee ••••••B-I-20
(iii)Plan E3 -Watana-Tunnel (*).B-I-21
(iv)Plan E4 -Watana/High Devil
Canyon/Portage Creek (*)B-I-21
(b)Load Forecast Sensitivity
Analyses (*)• • • • • • •B-I-21
1.5.2 -Evaluation Criteria (*)• • •B-I-22
_(a)Economic{~)-..-............'·B-1-22
(Q}...'Environmen t..9_L._(~t__._..._.._.__•__•__.._-,.-B",,1=22
(c)Social (*).•.•~• . • . • .B-I-22
(d)Energy Contribution (*)• • • •B-I-23
1.5.3 -Results of Evaluation Process (*).B-I-23
(a)Devil Canyon Dam Versus Tunnel (*).B-I-23
(i)Economic Comparison (*)B-I-24
(ii)Environmental Comparison (*).B-I-24
-'Ciii)SocIaLCompar1sotl(~,)-.".....B-I-24
(:iv).FJIl~l:'gY:C::()lIIpa:t':il;()'l.C*);:-;:&--1"'"'25
(v)Overall Comparison (*)B-I-25
(b)Watana/Devil Canyon Versus High
Devil Canyori'/Vee (*)• • • • • •B-I-25
1.5 ...Evaluation of Basin Development Plans (*)••
I
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B-I-I7
B-I-14
B-I-I5
B-I-I5
B-I-15
B-I-I5
B-I-I5
B-I-I5
B-I-I6
B-I-I6
B-I-I6
B-I-I6
B-I-I6
B-I-I6
Page No.
......
•••
2.1 (*).
2.2 (*)•
2.3 (*)•
1.1 (*)•
1.2 (*)•
1.3 (*)
~ABLE.OF CONTENTS (cont'd)
Selected Basin Development Plans (*)
(a)Plan 1 ("!'C')• •
0)Subplan
(ii)Subplan
(iii)Subplan
(b)Plan 2 (*)••
(i)Subplan
(if)Subplan
(iii)Subplan
(c)Plan 3 (*)••
(i)Subplan 3.1 (*)•
(ii)Subplan 3.2 (*)•
(d)Plan 4 (*)• .
1.4.3 -
Title
851104
EXHIBIT B
PROJECT OPERATION AND.RESOURCE UTILIZATION
1.6 -Preferred Susitna Basin.Development Plan (**)••
TABLE OF CONTENTS (cont'd)
Title
(i)
(ii)
(iii)
(iv)
(v)
Economic Comparison (*)• • •
Environmental Comparison (*).
Energy Comparison (*). .
Social Comparison (*).
Overall Comparison (*)
Page No.
B-1-25
B-1-25
B-1-26
B-1-26
B-1-26
B-1-27
2 -ALTERNATIVE FACILITY DESIGN,PROCESSES AND
OPERATIONS (*)...........
2.1 -Susitna Hydroelectric Development (0)
2.2 -Watana Project Formulation (*)
2.2.1 -Selection of Reservoir Level (0)
(a)Methodology (0)••••••••••
.(b)Ecomonic Optimization (*)
(c)Relict Channel (**)•••••.•.
(d)Conclusions (0)••'•••••
2.2.2 -Selection of Installed Capacity (*).
(a)Installed Capacity (*). .
(b)Unit Capacity (*)••••
2.2.3 -Selection of Spillway Design Flood (*)
2.2.4 -Main Dam Alternatives (*)..
(a)Comparison of Exbankment and
Concrete Type Dams (0)• • • •
(b)Concrete Face Rockfill Type Dam (*).
(c)Selection of Dam Type (*)
2.2.5 -Diversion Scheme Alternatives (*).
(a)Design Flood for Diversion (*)•
(b)Cofferdams (*). . . . . . . . . . .
(c)Diversion Tunnels (*)••••
(d)Emergency Release Facilities (*)
(e)Optimization of Diversion Scheme (*)
(f)Selected Diversion Scheme (*)
2.2.6 -Spillway Facilities Alternatives (*)
(a)Energy Dissipation (*)•
(b)Environmental Mitigation (*)•
2.2.7 -Power Facilities Alternatives (*)•
(a)Comparison of Surface and
Underground Powerhouse (*).
B-2-1
B-2-1
B-2-1
B-2-2
B-2-2
B-2-3
B-2-4
B-2-4
B-2-5
B-2-5
B-2-6
B-2-7
B-2-9
B-2-9
B-2-9
B-2-11
B-2-13
B-2-13
B-2-14
B-2-14
B-2-14
B-2-15
B-2-16
B-2-17
B-2-17
B-2-18
B-2-18
B-2-19
851104 iii
EXHIBITB
PROJECT OPERATION,AND RESOURCE UTILIZATION
TABLEOF,CONTENTS (cont'd)
Title
(b)Comparison of Alternative
Locations (*)•••••••
(c)Underground Openings (*)• • • • • •
(d)Seleciion of Turbiries (*)•••••
(e)Transformers (*)• • • • • • • • • •
(f)Power Intake and Water Passages (*).
(g)Environmental Constraints (*)•••
2.3 -Selection of Watana General Arrangement (0)
(ii)
(iii)
"(iv)
(v)
(vi)
2.3.2
2.3.3
2.3.4
2.3.1 -Selection of Methodology (*)
(a)Preliminary Review (*)•••••••
(b)Intermediate Review (*)'
(c)Final Review (*)• • • •
-Design Data and Criteria (*)
-Evaluation Criteria (*)• •
-Preliminary Review (*)
(a)Basis of Comparison of
Alternatives (*)•••
(~b)"..Desc-r-iptionofAlternatives +*-)~~.•
(i)Double Stilling Basin
Scheme (*).
Alternative 1 (*)••••
Al ternatives 2 through 2D (*)
Alternative 3 (*)••••
Alternative 4 (*)•••••
Selection of Schemes for
¥~,~~h~_!_,__..~~_~gY ...J,_~.l._,.__!.__:_!_,._!!--..!.....•
2.3.5 -Intermediate Review (*)•••••••••_..__.~-------.-------...".-.-.-.-.-~._~-~-~[aJ Descr-iption of Alterna--EIves .
Schemes (*)•••••• • • •
(i)Scheme WP1 (*)••••••••
(ii)Scheme WP2 (*)• • • •
(iii)Scheme WP3 (*)
(iv)Scheme WP4 (*)••••••
-(b)--Coll1paI"is()n'ot SclleUi.es ,(*"-)
(c)Selec t:i.on~of Scheme s'-for Further
Sfudy "'(*)-~~:-'-:--':-':-:'-
2.3.6 -Final Review (*)•••••
(a)Scheme WP3(*)••••
(i).Main Dam (*)•••••••
851104 iv
I
i I
Title
EXHIBIT B
PROJECT OPERATION AND.RESOURCE,UTILIZATION
TABLE_OF CONTENTS (cont'd)
Page No.
(ii)Diversion (*)· ·(iii)Outle t Fac il ities (*)·(iv)Spillways (*)· ·(v)Power Facilities (*)
(vi)Access (*)···(b)Scheme WP4A (*).·· · · · · · ···(i)Main Dam (*)·· ···..
(ii)Diversion (*)·· · · ·(iii)Outlet Facilities (*)
(iv)Spillways (*)· ·(v)Power Facilities (*)
(c)Evaluation of Final Alternative
Schemes (*).· ··· · · · ·
·2.3.7 -Amendment to License Application (***)
(a)Staged Construction (***)· · ···(b)Diversion Tunnels and
Cofferd-ams (***)··· · ·(c)Excavation and Foundation
Treatment for Dam (***)· ·· · ·
·(d)Dam and Cofferdam Configuration
and Composition (***)
(e)Spillway (***)· · · · · ··· ·(f)Relocation and Reorientation of
Caverns (***)· · · · · · · · ·(g)Power Conduits and Intake (***)
(h)Power Intake and Spillway
Approach Channels (***)
(i)Turbine-Generator Unit Speed (***)·(j)Gas Insulated Switchgear and
Bus (***). .· ··· · ·
2.4 -Devil Canyon Project Formulation (0)
2.4.1 -Selection of Reservoir Level (*)...•
2.4.2 -Selection of Installed Capacity (*)
2.4.3 -Selection of Spillway Capacity (*)
2.4.4 -Main Dam Alternatives (*).•
(a)Comparison of Embankment and
Concrete Type Dams (*).
(i)Rockfill Dam (*)...•.
B-2-37
B-2-37
B-2-38
B-2-39
B-2-40
B-2-40
B-:2-40
B-2-40
B-2-41
B-2-41
B-2-41
B-2-42
B-2-42
B-2-43
B-2-43
B-2-44
B-2-44
B-2-45
B-2-46
B-2-46
B-2-47
B-2 47
B-2-47
B-2-48
B-2-48
B-2-48
B-2-49
B-2-50
B-2-50
B-2-51
851104 v
vi
EXHIBIT B
PROJECT OPERATION AND RESOURCE UTILIZATION
2.5 -Selection of Devil Canyon General
Arrangement (*)•••••
j
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B-2-60
B-2-57
B-2-52
B-2-53
B-2-53
B-2-54
B-2-54
B-2-55
B-2-55
B-2-55
B-2-56
B-2-57
B-2-57
B-2-58
B-2-58
B-2-58
B-2-59
B-2-59
B-2-60
B-2-60
B-2-60
Page No.
...B,.,..2",,60
.L ..]3~2.:':.6.L ---..".
B-2-62
B-2-63
B-2-63
B-2-64
B-2-65
B-2-65B__2__65
B-2...15.5
B-2-66
B-2-66
B-2-66
(c)
(d)
(e)
U)
TABLE OF CONTENTS (cont'd)
(ii)Thick Arch Dam (*)••~•
(iii)Thin Arch Dam (*)• ••••
(b)Comparison of Arch Dam Types (*)
-Diversion Scheme Alternatives (*)•
(a)General Arrangements (*).
(b)Design Flood for Diversion (*)•
.(c)Cofferdams (*)••••••
(d)Diversion Tunnels (*)
(e)Optimization of Diversion Scheme (*)
-Spillway Alternatives (*)••••
-Power Facilities Alternatives (*)
(a)Comparsion of Surface and
Underground Powerhouses (*)
(b)Comparison of Alternative
Locations (*)
Selection of Units (*)
Transformers (*)••.•
Power Intake and Water Passage (*)•
Environmental Constraints (*)
2.4.6
2.4.7
2.4.5
-Selection Methodology (*)
-Design Data Criteria (*)
-Preliminary Review (*)
(a)Description of Alternative
..]£h(~meLt~L .'..L'.'..•...•.•.•
(i)Scheme DC1 (*)•.-"....!......!..•
·····-~TiTr·Scheme 'DC2 (*)
(iii)Scheme DC3 (*).•..
(iv)Scheme DC4 (*)
(b)Comparison of Alternatives (*).
(c)Selection of Final Scheme
2.5.4 -Final Review (*)••••
(a)"Main DBili(*)•'.• • •e.'•••
(h)SpIilway~andOut1etFacilities(-A-)0···Ccy-··I:rrversioiiT*y··:·::··:···:······:·:·.. .0
(d)Power Facilities (*).0 0 ••••••
2.5.5 -Amendment to License Application (***)
2.5.1
2.5.2
2.5.3
Title
851104
I
EXHIBIT B
PROJECT OPERATION AND RESOURCE UTILIZATION
TABLE OF"'CONTENTS (con t 'd)
Title
2.6 -Selection of Access Road Corridor (*)
Page No.
B-2-67
2.6.1 -Previous Studies (*)····B-2-67
2.6.2 -Selection Process Constraints (*)B-2-68
2.6.3 -Corridor Identification and Selection (*)B-2-68
2.6.4 -Development of Plans (*)· · · ··B-2-69
2.6.5 -Evaluation of Plan (*)B-2-70
1
(a)Plan 13 'North'(*)B-2-71
i I (b)Plan 16 'South'(*)B-2-71
(c)Plan 18 'Denali-North'(*)·····B-2-72
2.6.6 -Comparison of the Selected Alternative
Plans (*)..··· ·······B-2-72
(a)Costs (*)····B-2-73
(b)Schedule (*)· · ·······B-2-73
(c)Environmental Issues (*)·B-2-74
(i)Wildlife and Habitat (*)B-2-74
(ii)Fisheries (*)····B-2-76
(d)Cultural Resources (**)B-2-79
(e)Socioeconomics (0)·· · · · ·
B-2-79
(i)Cantwell (0).B-2-7-9
(ii)Hurricane (0)····B-2-80
(iii)Trapper Creek and
Talkeetna (0)B-2-80
(Lv)Gold Creek (0).· ·
B-2-80
(f)Preferences of Native
Organizations (*)B-2-80
(g)Relationship to Current Land
Stewardships,Uses and Plans (**)B-2-80
2.6.7 -Summary (0).··········B-2-81
2.6.8 -Final Selection of Plan (0)···B-2-81
(a)Elimination of 'South Plan'(0)B-2-81
(b)Schedule Constraints (*)·B-2-82
(c)Cost Impacts (0)·····B-2-83
(d)Summary (*)· · · · · ·
B-2-83
(e)Plan Recommendation (0)B-2-83
(f)Environmental Concerns -Recommended
Plan (*)··········· ·
B-2-83
J 2.7 -Selection of Transmission Facilities (0)•····B-2-83
2.7.1 -Electric System Studies (0)· · ···B-2-84
851104 vii
Page No.
TABLE OF CONTENTS (contld)
EXHIBIT B
PROJECT OPERATION AND RESOURCE.UTILIZATION
I
J
:I
,I
J
I :J
J
:I
'j
]
,.~
'J
.1
J
]
B-2-11 1
B-2-105
B-2-106
B-2-108
B-2-111
B-2-112
B-2-112
B-2-112
B-2-114
B-2-85
B-2-85
B-2-86
B-2-87
B-2-87
B-2-87
(a)
(b)
(c)
Existing System Data (*)• •••
Power Transfer Requirements (**)
Transmission Alternatives (*)
(i)Susitna to Anchorage (**).
(ii)Sus itna to Fairbanks (0)
(iii)Total System Alternatives (*)•
(d)Configuration at Generation and
Load Ce,:lter s (0)• • • • • • • ••.•B-2~88
(i)Susitna Configuration (**)B-2-89
(ii)Switching at Willow (*)B-2-89
(iii)Switching at Healy (0)••••B-2-89
(iv)Anchorage Configuration (**)B-2-89
(v)Fairbanks Configuration (0)B-2-90
2.7.2 -Corridor selection (0)•••• •••B-2-90
(a)Methodology (0)••••••B-2-90
(b)Selection Criteria (0)• • •B-2-9l
(c)Identification of Corridors (0)B-2-9l
(d)Description of Corridors (0)• •••B-2-9l
(i)Southern Study Area (0)B-2-92
(ii)Central Study Area (0)B-2-94
(itt)-Norfnern -StuoyAr-ea (oJ • •••.:6=2=100
2.7.3 -Corridor Screening (0)•••••B-2-102
(a)Reliability{o)•••••••B-2-102
(b)Technical Screening Criteria (0)••B-2-103
(i)Primar.y Aspects (0)• •B-2-103
(ii)Secondary Aspects (0)•B-2-104
(c)Economic Screening Criteria (0)B-2-105
(i)Primary Aspects (0)• • • •••B-2-105
_______(.ii_)...Secondary_As·pects--(oJ-.-.--.-.--.·-B-2-105
._.tg,L..Envir.o.nme.ntal_S.cr-eening,--__..-_.-...---
Criteria (0)• • • • • • •
(1)Primary Aspects (0)••
(ii)Secondary Aspects (0)•
(e)Screening Methodology (0)
(i)Technical and Economic
Screening Methodology (0)•
(ii)EnvironmentaL.Screening
M~f:l:1,Q<iolQgy (Q)••••• • •
2.7.4 -Selected Corridor (0)••••
(a)Southern Study Area (0)
(b)Central Study Area (0)•
Title
851104 viii
II
EXHIBIT B
PROJECT OPERATION AND-RESOURCE UTILIZATION
TABLE OF CONTENTS (cont'd)
Title
(i)The Choice Between CD
and CF (0)•••••
(ii)The Choice Between ABC
AND AJC (0)• •••
(c)Northern Study Area (0)••••
2.7.5 -Route Selection (0)••
(a)Methodology (0)'••••
(b)Selection Criteria (0)• •••
(c)Environmental Analysis (0)•••••
(d)Technical and Economic Analysis (0).
(i)Selection of Alternative
Routes (0)••••••••
(ii)Evaluation of a Primary
Route (0)• • • • • • •
(e)Route Soil Conditions (0)
(i)Despription (0)••••
(ii)Terrain Unit Ana,lysis (0)•
(f)Results and Conclusions (0)••.••
2.7.6 -Towers,Foundations and Conductors (0)
(a)Transmission Line Towers (0)
(i)Selection of Tower Type (0)••
(ii)Climatic Studies and
Loadings (0)
(iii)Tower Family (0)••••
(b)Tower Foundation (0)• • • • • • • •
(i)Geotechnical Conditions (0)
(ii)Types of Foundations (0)
(c)Voltage Level and Conductor Size (0)
Page No.
B-2-116
B-2-117
B-2-119
B-2-120
B-2-120
B-2-120
B-2-121
B-2-122
B-2-122
B-2-122
B-2-123
B-2-123
B-2-124
B-2-125
B-2-126
B-2-126
B-2-126
B-2-127
B-2-128
B-2-128
B-2-128
B-2-129
B-2-131
3 -DESCRIPTION OF PROJECT OPERATION (***)
3.1 -Hydrology (**)
• 0 e _B-3-1
B-3-1
II
3.1.1 -Historical Streamflow Records (**)
3.1.2 -Effects of Glaciers (***)
3.1.3 -Floods (**)••••••
3.1.4 -Flow Variability (***)•••••••••
3.1.5 -Flow Adjustments (**)•
3.2 -Reservoir Operation Modeling (***)
3.2.1 -Reservoir Operation Models (***)
B-3-1
B-3-2
B-3-3
B-3-4
B-3-5
B-3-6
B-3-6
851104 ix
Title
x
B-3-16
B-3-21
B-3-8
B-3-9
B-3-I0
B-3-I0
B-3-I0
B-3-11
B-3-12
B-3-13
B-3-14
B-3-15
B-4-1
B-3-7
B-3-8
B-3-20
B-3-17
B-3-17
B-3-18
B-3-20
B-3-21
B-4-1
B-4-1
B-4-2
B-4-4
B-4-5
B-4.,..5
B-4-6
B-4-6
B-4-7
Page No.
. .
(***)3.3.1 -Reservoir Storage Characteristics
3.3.2 -Reservoir Operation (***)•
3.3.3 -Development of Alternative
Flow Regimes (***)
EXHIBIT B
PROJECT OPERATION AND RESOURCE UTILIZATION
TABLE OF CONTENTS (cont'd)
3.2.2 -Basic Concept and Algorithm
of Reservoir Operation (***)••••••
(a)Watana Stage I (***)••••••
(b)Watana Stage I or Stage III with
Devil Canyon Stage II (***)••.•
3.2.3 -Standard Weeks (***)••••••••
3.2.4 -Demand Forecast (***)• • • • • • • •
3.2.5 -Existing Hydroelectric Plants (***)
3.2.6 -Release Constraints (***)
3.2.7 -Reservoir Operation (***)•• ••• •
(a)Rule Curve Operat ion (***)• •
(b)Rule Curve Development (***)• •
(c)Operating Guide (***)••••
(d)OperatirigGuIdeDevelopment (***)
3.2.8 -Special Considerations for
Double Reservoir Operation (***).
3.2.9 -Reservoir Operation Computer
Programs (***)•••••••••••••
(a)Monthly RESOP Program (***)••••
(b)Week1y RESOP Program (***)• •
4.1.1 -System Reliability Criteria (**)
(a)Installed Generating Capacity (**)•
(b)Transmission System Capability (**).
(c)Summary (*~)'._!.'.'.•!'•••••
4.1.2 ....Economic Dispatch of Units (*)•••••
(a)Order-:of':""MeritSchedu.le ·(0)••••
(b)Optimum Load Dispatching (0)• •
(c)Operating Limits of Units (*)..
(d)Optimum Maintenance Program (0).
3.3 -Operational Flow Regime Selection (***)•
4.1 -Plant and System Operation Requirements (**)
851104
Title
EXHI.BIT B
PROJECT OPERATION AND RESOURCE UTILIZATION
TABLE OF .CONTENTS (con.t'd)
Page No.
4.1.3 -Unit
(a)
(b)
4.1.4
operation Reliability Criteria·(0)•
Power System Ana1ys.es (0)•••••
System Response and Load-Frequency
Control (*)•••••.•
(c)Protective Relaying System and
Devices (0)••.••••
-Dispatch Control Centers (*).
B-4-7
B-4-7
B-4-8
B-4-8
B-4-8
4.2 -Power and Energy Production (***)B-4-9
! ]
4.2.1 -Operating Capabilities of Susitna
Units (**)
(a)Watana (**)••.•
(b)Devil Canyon (**)••••
4.2.2 -Tai1water Rating Curve (0)
4.2.3 -Average Energy Generation (***).
4.2.4 -Firm Energy Generation (***)
4.2.5 -Dependable Capacity (***)•.
4.2.6 -Base Load and Load-Following
Operation (***)••••••.
5 -STATEMENT OF POWER NEEDS AND UTILIZATION.(**)•.. . .
B-4-l0
B-4-l0
B-4-11
B-4-11
B-4-1l
B-4-ll.
B-4-l2
B-4-l2
B-5-l
5.1 -Introduction (**)• •0 •• • • • •B-5-l \
5.2 -Description of the Rai1be1t Electric
Sys tems (**)••••••••••••B-5-l
851104
5.2.1 -The
(a)
(b)
Interconnected Rai1be1t Market (**)•
The Electric Utilities and Other
Suppliers (**)•••••...•••
(i)Anchorage-Cook Inlet
Area (**)••••.••
(ii)Fairbanks -Tanana Va11y
Area (**)•••••••••
(iii)Other Suppliers (*)•••
The Existing Electric Energy Supply
And Power Plant Capacity (**)
xi
B-5-l
B-5-2
B-5-2
B-5-4
B-5-6
B-5-6
xii
TABLE OF CONTENTS (cont'd)
1
]
]
1
l
j
]
,j
"'j
]
]
)
j
j
)
)
I
1
J
B-5-11
B-5-11
B-5-23
B-5-23
B-5-21
B-5-11
B-5-7
B-5-7
B-5-10
B-5-12
B-5-13
B-5-13
B-5-15
B-5-10
B-5-10
B-5-18
B-5-21
B-5-21
B-5-7
B-5-8
B-5-9
B-5-9
Page No.
Model Overview (**)• • • • • •
Alaska Petroleum Revenue Sensitivity
(APR)Model (**)• • • • • • • •
(i)Input Data (***)••••
(ii)APR Mode 1 Output (***)
Man';"ll1-the-Arctic'prograDl (}fAp)
Economic Model (*)..•.•
(T)-Scenario Generator
Submodel (*)
(ii)Statewide Economic
Submodel (*)...•..•••
(c)
(a)
(b)
EXHIBIT B
PROJECT OPERATION·AND RESOURCE UTILIZATION
5.2.2 -Railbelt Electric Utilities (**)••••
(a)Utility Load Characteristics (**)
(i)Monthly Peak and Energy
Demand (**)••••••.••
(ii)Daily Load Profiles (**)
(iii)Railbelt Load Diversity (**).
(b)Electricity Rates (**)••.••••
(i)Anchorage Municipal Light and
Power (AMLP)(**)• • •.'.•
(ii)Chugach Electric Association,
Inc.,(CEA)(**)•.••••
(iii)Fairbanks Municipal Utilities
System (mus)(**)
(iv)Goldel1ValleyElectric
Association,Inc.
(GVEA)(**)• • • • • • •
(c)Conservation and Rate Structure
Programs (*)••••••••••
(i)The Anchorage Municipal Light
and Power (AMLP}Program (**)
Eii)-.The··Go-lden~Val-leyc-Electric-·-
Association,Inc.(GVEA)
Program (*)•••••••••
(iii)Other Utility Programs (0)
(iv)Other Conservation
Programs (*).....
5.2.3 -Historical Data for the Market Area (**)
--,f:-3.I--='-Fore cas t ing Mode 1s(**)-~-•._-:--~-•-..-:--~--_.~_.-.-_...·:6=5=16····...
B-5-16
Title
851104
Title
851104
EXHIBIT B
PROJECT OPERATION .AND·RESO.ORe!UTILIZATION
TABLE OF.CONTENTS (cont'd)
(iii)Regionalization
Submodel (*)
(iv)Input Variables and
Parameters (*)
(v)MAP Model Output (*)
(d)Railbelt Electricity Demand
Model (*)....••..••...
(i)Uncertainty Module (*)
(ii)Housing Module (*)
(iii)Residential Consumption
Module (*).....
(iv)Business Consumption
Module (*)
(v)Program-Induced Conservation
Module (*).
(vi)Miscellaneous Consumption
Module (*)..•....
(vii)Peak Demand Module (*)
.(viii)Input Data (*)•....
(x)RED Model Output (*)....
(e)Optimized Generation Planning (OGP)
Model (*)•.•.••.•.....
(i)Reliability Evaluation (*)
(ii)Production Simulation (*)..
(iii)Purchases and Sales (*).
(iv)Conventional Hydro
Scheduling (*)
(v)Thermal Unit
Maintenance (*). . . . . . •
(vi)Thermal Unit Commitment (*).
(vii)Thermal Unit Dispatch (*)
(viii)Investment Costing (*).
(ix)OGP Optimization
Procedure (*).
(x)Input Data (*)
(xi)Output Data (*).
5.3.2 -Model Validation (*)
(a)APR Model Validation (***)• • • • •
(b)MAP Model Validation (0)•
(i)Stochastic Parameter
Tests (*)•.•••.
xiii
Page No.
B-5-25
B-5-25
B-5-28
B-5-28
B-5-30
B-5-31
B-5-31
B-5-32
B-5-33
B~5-33
B-5-34
B-5-34
B-5-34
B-5-35
B-5-36
B-5-37
B-5-38
B-5-38
B-5-38
B-5-39
B-5-39
B-5-40
B-5-40
B-5-41
B-5-42
B-5-43
B-5-43
B-5-43
B-5-43
Title
5.4 -Forecast of Electric Power Demand (**).
6 -FUTURE SUSITNA BASIN DEVELOPMENT.(*)
)
]
.}
,j-
Page No.
B-5-44 1
B-5-45 IB-5-46
B-5-46 .\
B-5-46 "(\.)\
B-5-47
B-5-48 !B-5-49
B-5-49
:8-5-50 31
B-5-51 /
B-5-53
B-5-53 I jB-5-54
B-5-54
B-5-54 ,'j
B-5-54 \
B-5-54 .j
B-5-56
B-5-57 )-B-5-57 --_.__._--"-.-.-_...•".-
B~5~58 ...
B-5-59
1B-5-59
B-5-60
B-6-1 J
.I
B-7-1
\
J
, J
1
]
o •~0 •• •e •
xiv
EXHIBIT B
PROJECT OPERATION.AND RESOURCE.UTILIZATION
TABLE OF.CONTENTS (cont'd)
(ii)Simulation of Historical
Economic Conditions (*)•
(c)RED Model Validation (**)
5.4.1 -Variables and Assumptions (**)
(a)APR Model (**)
(b)MAP Model (*)
(c)RED Model (*).• • • •
(d)OGP Model (0)••
5.4.2 -Load Forecasts (**)•
(a)StatePettoletilll Revenues (**)
(b)Fiscal and Economic
Conditions (**)•••••
(i)Population (***)
(ii)Employment (***)
(iii)Households (***)••
(c)Electric Power Demand (**)
~~~fi:)-~Househcol-ds-Servedand Va-eafit ....
Households (***)• • • •
(ii)Residential Electricity
Use Per Household (***)•
(iii)Business Use Per
E~ployee (***)•••••
5.4.3 -Forecast Comparison (***)••
5.4.4 -Sensitivity Analysis (**)•••
.......__....JaL_MAP_ModeLSensitivity---Tests-(-**J
(b)RED_Mode ISens i tivi ty-T_e_s_t_s_t~~>-
---------(c)-OGP Model Sensitivity Tests (**)
5.4 ~5 -Comparison with Previous Forecasts (**)•
5.4.6 -Impact of Oil Prices on Forecasts (**)
7 ..;;,REFERENCES
851104
Number
B.1.3.1
B.1.3.2
--I
B.1.3.3
B.1.4.1
B.l.4.2
B.l.4.3
B.l.4.4
B.1.4.S
B.1.4.6
B.l.S.1
B.l.S.2
B.l.S .3
B.l.S.4
B.l.S.S
B~l.S.6
B.l.S.7
851104
EXHIBIT B
PROJECT OPERATION AND RESOURCE UTILIZATION
LIST OF TABLES
Title
POTENTIAL HYDROELECTRIC DEVELOPMENT
COST COMPARISONS
DAM CREST AND FULL SUPPLY LEVELS
CAPITAL COST ESTIMATE SUMMARIES :SUSITNA BASIN DAM
SCHEMES COST IN $MILLION 1980
RESULTS OF SCREENING MODEL
INFORMA TION ON THE DEVIL CANYON DAM AND TUNNEL
SCHEMES
DEVIL CANYON TUNNEL SCHEMES,COSTS,POWER OUTPUT AND
AVERAGE ANNUAL ENERGY
CAPITAL COST ESTIMATE SUMMARIES TUNNEL SCHEMES COSTS
IN $MILL ION 1 980
SUSITNA DEVELOPMENT PLANS
SUSITNA ENVIRONMENTAL DEVELOPMENT PLANS
RESULTS OF ECONOMIC ANALYSES OF SUSITNA PLANS -
MEDI UM LOAD FORECAST
RESULTS OF ECONOMIC ANALYSES OF SUSITNA PLANS -LOW
AND HIGH LOAD FORECAST
ANNUAL FIXED CARRYING CHARGES
SUMMARY OF THERMAL GENERATING RESOURCE PLANT
PARAMETERS
ECONOMIC BACKUP DATA FOR EVALUATION OF PLANS
ECONOMIC EVALUATION OF DEVIL CANYON DAM AND TUNNEL
SCHEMES AND WATANA/DEVIL CANYON AND HIGH DEVIL
CANYON/VEE PLANS
xv
Number
B.lo5.S
B.lo5.9
B.l.5.l0
B.lo5.11
B.l.5.l2
B.l.5.13
B.lo5.l4
B.2.2.l
B.2.2.2
B.2.2.3
B.2.2.5
B.2.2.6
B.2.3.l
B.2.3.2
851104
EXHIBIT B
PRO.JECT OPERATION AND RESOURCE UTILIZATION
LIST OF TABLES (cont'd)
Title
ENVIRONMENTAL EVALUATION OF DEVIL CANYON DAM AND
TUNNEL SCHEME
SOCIAL EVALUATION OF SUSITNA BASIN DEVELOPMENT
SCHEMES/PLANS
ENERGY CONTRIBUTION EVALUATIGN OF THE DEVIL CANYON
DAM AND TUNNEL SCHEMES
OVERALL EVALUATION OF TUNNEL SCHEME AND DEVIL CANYON
DAM SCHEME
ENVIRONMENTAL EVAL UATIONOF'WATANA/DE\TIL cANYON AND
HIGH DEVIL CANYON/VEE DEVELOPMENT PLANS
ENERGY CONTRIBUTION EVALUATION OF THE WATANA/DEVIL
CANYON AND HIGH DEVIL CANYON/VEE PLANS
OVERALL EVALUATION OF THE HIGH DEVIL CANYON/VEE'AND
...........-.,..WATANKlDE VII;'CA:NYONDAM-PLANS-"--'_---_.--
CCMBINED WATANA AND DEVIL CANYON OPERATION
PRESENT WORTH OF PRODUCTION COSTS
DESIGN PARAMETERS FOR DEPENDABLE CAPACITY AND ENERGY
PRODUCTION
..WATANA -MAX.IMJ]~t ..CAPACI'IY.REQ_UIRED.,__01'.TION_L_.........----...
THERMAL AS BASE
WATANA -MAXIMUM CAPACIlY REQUIRED,OPTION 2 -
THERMAL AS PEAK
SUMMARY COMPARISON OF POWERHOUSES AT WATANA
DESIG~.,DA'rAA~!?_I:>r;~:I;G~_CRI1Ii:R1A,FOR FINAL REVIEW OF
LAYOUTS
EVALUATION CRITERIA
xvi
t,1
.~...~
f
i
")
j
')
,I
r
)
)
J
.i
I
Number
B.2.3.3
B.2.4.1
B.2.S.1
B.2.S.2
B.2.7.1
B.2.7.2
B.2.7.3
B.2.7.4
B.2.7.S
B.2.7.6
B.2.7.7
B.2.7.8
B.2.7.9
B.2.7.10
B.2.7.11
B.2.7.12
8S1104
EXHIBIT B
PROJECT OPERATION AND RESOURCE UTILIZATION
LIST OF TABLES (cont'd)
Title
SUMMARY OF COMPARATIVE COST ESTIMATES
DEVIL CANYON -.MAXIMUM CAPACITY REQUIRED
DESIGN DATA AND DESIGN CRITERIA FOR REVIEW OF
ALTERNATIVE LAYOUTS
SUMMARY OF COMPARATIVE COST ESTIMATES
POWER TRANSFER REQUIREMENTS (MW)
SUMMARY OF LIFE CYCLE COSTS (1993 $MILLION)
TECHNICAL,ECONOMIC,AND ENVIRONMENTAL CRITERIA USED
IN CORRIDOR SECTION
ENVIRONMENTAL INVENTORY -SOUTHERN STUDY AREA
(WILLOW TO ANCHORAGE/POINT MACKENZIE)
ENVIRONMENTAL INVENTORY -CENTRAL STUDY AREA
(DAMSITES TO INTERTIE)
ENVIRONMENTAL INVENTORY -NORTHERN STUDY AREA (HEALY
TO FAIRBANKS)
SOIL ASSOCIATIONS WITHIN THE PROPOSED TRANSMISSION
CORRIDORS -GENERAL DESCRIPTION,.OFFROAD
TRAFFICABILITY LIMITATIONS (ORTL)AND COMMON CROP
SUITABILITY (CCS)
DEFINITIONS FOR OFFROAD TRAFFICABILITY LIMITATIONS
AND COMMON CROP SUITABIL.ITY OF SOIL ASSOCIATIONS
ECONOMICAL AND TECHNICAL SCREENING SOUTHERN STUDY
AREA (WILLOW TO ANCHORAGE/POINT MACKENZIE)
ECONOMICAL AND TECHNICAL SCREENING CENTRAL STUDY
AREA (DAM SI TES TO INTERTIE)
ECONOMICAL AND TECHNICAL SCREENING NORTHERN STUDY
AREA (HEALY TO FAIRBANKS)
SUMMARY OF SCREENING RESULTS
xvii
EXHIBIT B
PROJECT OPERATION AND RESOURCE UTILIZATION
LIST OF TABLES (cont'd)
'Number Title=.;;.;;;..;~---------
B.2.7.13 ENVIRONMENTAL CONSTRAINTS -SOUTHERN STUDY AREA
(WILLOW TO ANCHORAGEJPO INT MACKENZIE)
:5.2.7.14 ENVIRONMENTAL CONSTRAINTS CENTRAL STUDY AREA (DAM
SITES TO INTERTIE)
B.2.7.15 ENVIRONMENTAL CONSTRAINTS NORTHERN STUDY AREA (HEALY
TO FAIRBANKS)
B.2.7.16 TECHNICAL,ECONOMIC AND ENVIRONMENTAL CRITERIA USED
IN CORRIDOR SCREENING
B.3 ..1.1 PERTINENT DATA FOR GAGING STATIONS
B.3 .1.2 USGS STREAMFLOW SUMMARY
B.3.1.3 WATANA NATURAL MONTHLY FLOWS (CFS)
:13.3.1.4 DEVIL CANYON NATURAL MONTHLY FLOWS (CFS)
B.3.1.5 GOLD CREEK NATURAL MONTHLY FLOW (CFS)
B.3 .1.6 WEEKLY STREAM FLOW AT WATANA (CFS)
:5.3.1.7 WEEKLY STREAM FLOW AT DEVIL CANYON (CFS)
B.3.1.8 WEEKLY STREAM FLOW AT GOLD CREEK (CFS)
B.3.1.9 SUMMARY OF ESTIMATED STREAMFLOW
B.3.1.10 INSTANTANEOUS PEAK FLOWS OF RECORD
B.3.1.11 ESTIMATED EVAPORATION LOSSES,
B.3•.l.12 WATER APPROPRIATIONS WITHIN ONE MILE
_.."-OFTFJJr§JI~Trn~J,U'iT_~g~'_~____
:I3~3~2~rRESERvotR OPERATfoNLEVEi.CONSTRAINTS
B.3.2.2 STANDARD WATER WEEKS FOR.ANY WATER YEAR N
851104·xviii
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Number
B.3.2.3
B.3.2.4
B.3.2.5
B.3.3.1
B.3.3.2
B.4.1.1
B.4.2.1
B.4.2.2
B.5.2.1
B.5.2.2
B.5.2.3
B.5.2.4
B.5.2.5
B.5.2.6
B.5.2.7
B.5.2.8
II B.5.2.9L_J
851104
EXHIBIT B
PROJECT OPERATION AND "RESOURCE UTILIZATION
LIST OF TABLES (cont'd)
Title
SHCA LOAD FORECAST
DISTRIBUTION OF RAILBELT MONTHLY ENERGY REQUIREMENT
EXISTING AND PLANNED RAILBELT HYDROELECTRIC ENERGY
GENERATION
WEEKLY MI'NIMUM MEAN FLOWS AT -GOLD CREEr.<
FOR FLOW CASE E-VI
ECONOMIC ANALYSIS OF ENVIRONMENTAL FLOW CASES
TRANSMISSION SYSTEM PERFORMANCE UNDER
DOUBLE CONTINGENCY
GENERATING UNIT OPERATING CHARACTERISTICS
ENERGY PRODUCTION AND DEPENDABLE CAPACITY
INSTALLED CAPACITY OF THE ANCHORAGE-COOK-INLET AREA
INSTALLED CAPACITY OF THE FAIRBANKS-TANANA VALLEY
AREA
EXISTING GENERATING PLANTS IN THE RAILBELT REGION
MONTHLY DISTRIBUTION OF PEAK POWER DEMAND
PROJECTED MONTHLY DISTRIBUTION OF PEAK AND ENERGY
DEMAND PERCENTAGE OF ANNUAL DEMAND
TYPICAL 24-HOUR LOAD DURATION RELATIONS
LOAD DIVERSITY IN THE RAILBELT
RESIDENTIAL AND COMMERICAL ELECTRIC RATES -
ANCHORAGE-COOK INLET AREA,MARCH 1983
RESIDENTIAL AND COMMERCIAL ELECTRIC RATES -
FAIRBANKS-TANANA VALLEY AREA,MARCH 1983
xix
Number
B.5.2.10
B.5.2.U
B.5.2.12
B.5.2.13
B.5.2.14
B.5.3.1
B.5.3.2
B.5.3.3
B.5.4.1
B.5~4.2
B.5.4.3
B.5.4.5
B.5.4.6
B.5.4.7
B.5.4.8
B.5.4.9
EXHIBIT B
PROJECT OPEBATION AND RE SO l:JRCE·UTILIZATION
LIST.OF TABLES (cont'd)
Title
ANCHORAGE MUNICIPAL LIGHT AND POWER,CUMULATIVE
ENERGY CONSERVATION PROJECTIONS
HISTORICAL ECONOMIC AND ELECTRIC POWER DATA
MONTHLY LOAD DATA FROM ELECTRIC UTILITIES OF THE
ANCHORAGE-COOK INLET AREA 1976-1983
MONTHLY LOAD DATA FOR THE FAIRBANKS-TANANA VALLEY
AREA 1976-1983
NET GENERATION BY RAILBELT UTILITIES 1976-1984
COMPARI SON OF RECENT FYf98S'PETROLEUM PRODUCTION
FORECASTS FROM PETREV
MAP MODEL VALIDATION SIMULATION OF HISTORICAL
ECONOMIC CONDITIONS
COMPARISON OF ACTUAL AND PREDICTED ELECTRICITY
CONS UMPTIONFORT980';;;T98T
FORECASTS OF WORLD OIL PRICE APR MODEL
MAJOR VARIABLES AND ASSUMPTIONS APR MODEL
VARIABLES AND ASSUMPTIONS MAP MODEL
..··················SUMMARY-OF···MAp····MODEL···PROJECTIONASSUMPTIONS
._JSHGA.AND_.GOMEOS.I.TE._CASESJ____....._._.
VARIABLES AND ASSUMPTIONS RED MODEL
FUEL PRICE FORECASTS USED BY RED -SHCA CASE
FUEL PRICE FORECASTS USED BY RED -COMPOSITE CASE
.....JIQUSIW.G J)EMAND .CQEFF'ICIENTS.
EXAMPLE OF MARKET SATURATIONS OF APPLIANCES IN
SINGLE-FAMILY HOMES FOR ANCHORAGE-COOK INLET AREA
xx
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Number
B.5.4.10
B.5.4.1l
B.5.4.12
B.5.4.13
B.5.4.14
B.5.4.15
B.5.4.16
B.5.4.17
B.5.4.18
B.5.4.19
B.5.4.20
B.5.4.21
B.5.4.22
B.5.4.23
B.5.4.24
B.5.4.25
B.5.4.26
851104
EXHIBIT B
PROJECT OPERATION AND ..RESOURCE UTILIZATION
LIST OF TABLES (cont'd)
Title
PARAMETER VALUES IN RED MODEL PRICE ADJUSTMENT
MECHANISM
PERCENT OF APPLIANCES USING ELECTRICITY
AND AVERAGE ANNUAL ELECTRICITY CONSUMPTION,
RAILBELT LOAD CENTERS,1980
GROWTH RATES IN ELECTRIC APPLIANCE C1\PACITY
AND INITIAL ANNUAL AVERAGE CONSUMPTION
FOR NEW APPLIANCES
PERCENT OF APPLIANCES REMAINING IN SERVICE
YEARS AFTER PURCHASE
RED BUSINESS SECTOR ELECTRICITY CONSUMPTION
PARAMETERS
VARIABLES AND ASSUMPTIONS -OGP MODEL ECONOMIC
PARAMETERS
SHCA CASE FORECAST·SUMMARY OF INPUT AND
OUTPUT DATA
COMPOSITE CASE FORECAST SUMMARY OF INPUT AND OUTPUT
DATA
SHCA CASE STATE PETROLEUM REVENUES
COMPOSITE CASE STATE PETROLEUM REVENUES
SHCA CASE STATE GOVERNMENT FISCAL CONDITIONS
COMPOSITE CASE STATE GOVERNMENT FISCAL CONDITIONS
SHCA CASE POPULATION
COMPOSITE CASE POPULATION
SHCA CASE EMPLOYMENT
COMPOSITE CASE EMPLOYMENT
SHCA CASE HOUSEHOLDS
xxi
EXHIBIT B
PROJECT OPERATION AND RESOURCE UTILIZATION
Number
B.S.A.27
B.S.4.28
B.5.4.29
B.S.4.30
B.5.4.31
B.5.4.32
B.5.4.33
B.5.4.34
B.S.4.35
B.5.4.36
B.5.4.37
B.5.4.38
LIST OF TABLES (cont'd)
Title
COMPOSITE CASE HOUSEHOLDS
SHCA CASE FORECAST NUMBER OF HOUSEHOLDS SERVED
COMPOSITE CASE FORECAST NUMBER OF HOUSEHOLDS SERVED
SHCA CASE FORECAST NUMBER OF VACANT HOUSEHOLDS
COMPOSITE CASE.FORECAST NUMBER OF VACANT HOUSEHOLDS
SHCA CASE FORECAST RESIDENTIAL ELECTRICITY USE PER
HOUSEHOLD
COMPOSITE CASE FORECAST RESIDENTIAL ELECTRICITY USE
PER HOUSEHOLD
SHCA CASE FORECAST BUSINESS ELECTRICITY USE PER
EMPLOYEE
COMPOSITE CASE FORECAST BUSINESS ELECTRICITY USE PER
SHCA CASE FORECAST SUMMARY OF PRICE EFFECTS
COMPOSITE CASE FORECAST SUMMARY OF PRICE EFFECTS
SHCA CASE FORECAST BREAKDOWN OF ELECTRICITY
REQUIREMENTS ANCHORAGE-COOK INLET AREA
I
I
....~~.__B.5_.A •.39_.~_._._~SH.CA..-CASEJORECAST~-BREAKDOWN-OF_~ELECTRICTTY.
REQUIREMENTS FAIRBANKS-TANANA VALLEY AREA
B.5.4.40
B.5.4.41
B.5.4.42
851104
COMPOSITE CASE FORECAST BREAKDOWN OF ELECTRICITY
REQUIREMENTS ANCHORAGE-COOK INLET AREA
COMPOSITE CASE FORECAST BREAKDOWN OF ELECTRICITY
~-'--""-"-_•..."_."-".."."_""..".,,,,..','"'',,",,..,.".,""",,,".."
REQUIREMENTS FAI RBANKS.,.TANANA VALLEY AREA
SHCA CASE END USE FORECAST PROJECTED PEAK AND
ENERGY DEMAND
···xxii 1
Number
B.5.4.43
B.5.4.44
B.5.4.45
B.5.4.46
B.5.4.47
B.5.4.48
B.5.4.49
B.5.4.50
851104
EXHIBIT B
PROJECT OPERATION AND RESOURCE UTILIZATION
LIST OF TABLES (cont'd)
Title
COMPOSITE CASE FORECAST PROJECTED PEAK AND ENERGY
DEMAND
WHARTON CASE FORECAST SUMMARY OF INPUT AND OUTPUT
DATA
RESULTS OF RED MODEL SENSITIVITY TESTS ON APPLIANCE
SATURATION
RESULTS OF RED MODEL SENSITIVITY TEST ON BUSINESS
SECTOR CONSUMPTION INTENSITY
RESULTS OF RED MODEL SENSITIVITY TEST ON OWN PRICE
ELASTICITIES
RESULTS OF RED MODEL SENSITIVITY TEST ON CROSS
PRICE ELASTICITIES TOTAL ELECTRICITY REQUIREMENT
WITHOUT LARGE INDUSTRIAL
RESULTS OF RED MODEL SENSITIVITY TEST ON ANNUAL
LOAD FACTOR TOTAL ELECTRICITY REQUIREMENT?WITHOUT
LARGE INDUSTRIAL
LIST OF PREVIOUS RAILBELT PEAK AND ENERGY DEMAND
FORECASTS (MEDIUM SCENARIO)
xxiii
Number
B.I.I.I
B.1.1.2
B.l.2.1
B.l.3.1
B.1.3.2
B.l.3.3
B~1.3.4
B.l.3.5
B.1.3 ..6
B.l.3.7
B.1.3.9
B.1.4.1
B.1.4.2
B.
B.I.5.1
B.1.5.2
B.1.5.3
B.2.2.1
851104
EXHIBIT B
PROJECT OPERATION AND RE SO DRCE UTILIZATION
LIST OF FIGURES
Title
LOCATION MAP
DAMSlTES·PROPOSED BY OTHERS
SUSITNA BASIN PLAN FORMULATION AND SELECTION PROCESS
PROFILE THROUGH ALTERNATIVE SITES
MUTUALLY EXCLUSIVE DEVELOPMENT ALTERNATIVES
DEVIL CANYON HYDRO DEVELOPMENT FILL DAM
WATANA HYDRO DEVELOPMENT FILL DAM
WATANA STAGED FILL DAM
HIGH DEVIL CANYON.HYDRO DEVELOPMENT
SUSITNA III HYDRO DEVELOPMENT
DENALI AND MACLAREN HYDRO DEVELOPMENTS
SCHEMATIC REPRESENTATION OF CONCEPTUAL TUNNEL
SCHEMES
PREFERRED TUNNEL SCHEME 3 PLAN VIEW
PREFERRED TUNNEL SCHEME 3 SECTIONS
GENERATION SCENARIO WITH SUSITNA PLAN El.3,MEDIUM
LOAD FORECAST
GENERATION SCENARIO WITH SUSITNA PLAN E2.3,MEDIUM
LOAD.FORECAST
GENERAtION SCENARIo wt'tHSUSITNA PLAN E3.1,MEDlbM
LOAD FORECAST
WATANA RESERVOIR DAM CREST EVEVATION/PRESENT WORTH
OF PRODUCTION COSTS
xxiv
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Number
B.2.2.2
B.2.2.3
B.2.2.4
B.2.2.5
B.2.2.6
B.2.2.7
B.2.3.1
B.2.3.2
B.2.3.3
I B.2.3.4l\
B.2.3.5
B.2.3.6
B.2.3.7
B.2.3.8
B.2.3.9
B.2.3.10
B.2.3.11
B.2.3.12
B.2.4.1
B.2.4.2
851104
EXHIBIT B
PROJECT OPERATION AND ..RESOURCE UTILIZATION
LIST OF.FIGURES (cont'd)
Title
WATANA -ARCH DAM ALTERNATIVE
WATANA ALTERNATIVE DAM AXES
WATANA DIVERSION HEADWATER ELEVATION/TUNNEL DIAMETER
WATANA DIVERSION UPSTREAM COFFERDAM COSTS
WATANA DIVERSION TUNNEL COST/TUNNEL DIAMETER
WATANA DIVERSION TOTAL COST/TUNNEL DIAMETER
WATANA PRELIMINARY SCHEMES
WATANA SCHEME WPI PLAN
WATANA SCHEME WP3 SECTIONS
WATANA SCHEME WP2 AND WP3
WATANA SCHEME WP2 SECTIONS
WATANA SCHEME WP4 PLAN
WATANA SCHEME WP4 SECTIONS
WATANA SCHEME WP3A
WATANA SCHEME WP4A
WATANA DAM STAGE I
DE VIL CANYON DAM STAGE II
WATANA DAM STAGE III
DEVIL CANYON DIVERSION HEADWATER ELEVATION/TUNNEL
DIAMETER
DEVIL CANYON DIVERSION TOTAL COST/TUNNEL DIAMETER
xxv
B.2.7.l
B.2.6.l
B.2.7.7
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ACCESS PLAN 18 (PROPOSED)
ALTERNATIVE ACCESS CORRIDORS
RECOMMENDED TRANSMISSION CORRIDOR -SOUTHERN STUDY
AREA
ACCESS PLAN 13 (NORTH)
ACCESS PLAN 16 (SOUTH)
xxvi
LIST OF FIGURES (cont'd)
RECOMMENDED TRANSMISSION CORRIDOR -CENTRAL STUDY
AREA
ALTERNATIVE TRANSMISSION LINE CORRIDORS -CENTRAL
STUDY AREA
RECOMMENDED TRANSMISSION CORRIDOR -SOUTHERN STUDY
AREA
Title
SCHEDULE FOR ACCESS AND DIVERSION
ALTERNATIVE TRANSMISSION LINE CORRIDORS -NORTHERN
STUDY-AREAo.-..--.-.----------0-·0··_••·0 ••_00-0
~..._.....--
RECOMMENDED TRANSMISSION CORRIDOR -CENTRAL "STUDY-
AREA
ALTERNATIVE TRANSMISSION LINE CORRIDORS -SOUTHERN
STUDY AREA
DEVIL CANYON SCHEME DC4
DEVIL CANYON SCHEME DCl
DEVIL CANYON SELECTED SCHEME
DEVIL CANYON SCHEME DC3
DEVIL CANYON SCHEME DC2
EXHIBIT B
PROJECT OPERATION AND.RESOURCE UTILIZATION
6
B.2.6.S
B.2.7.2
B.2.6.4
B.2.6.3
B.2.7.4
B.2.7.3
B.2.S.4
B.2.6.2
B.2.S.3
B.2.S.2
B.2.S.l
B.2.7.S
B.2.S.S
B.
Number
851104
Number
B.2.7.8
B.2.7.9
B.2.7.10
B.2.7.11
B.3 .1.1
B.3.1.2
B.3.1.3
B.3.1.4
B.3.1.5
B.3.1.6
B.3.1.7
B.3.1.8
B.3.1.9
B.3.1.10
851104
EXHIBIT B
PROJECT OPERATION AND RESOURCE.UTILIZATION
.LIST OF FIGURES (cont'd)
Title
RECOMMENDED TRANSMISSION CORRIDOR -NORTHERN STUDY
AREA
RECOMMENDED TRANSMISSION CORRIDOR -NORTHERN STUDY
AREA
RECOMMENDED TRANSMISSION CORRIDOR -NORTHERN STUDY
AREA
RECOMMENDED TRANSMISSION CORRIDOR -NORTHERN STUDY
AREA
STREAMFLOW GAGING AND WATER QUALITY MONITORING
STATIONS
AVERAGE ANNUAL FLOW DISTRIBUTION WITHIN THE SUSITNA
RIVER BASIN
DAILY DISCHARGE HYDROGRAPHS
1964 NATURAL FLOWS;CANTWELL WATANA,AND GOLD CREEK
DAILY DISCHARGE HYDRO GRAPHS
1967 NATURAL FLOWS;CANTWELL,WATANA,AND GOLD CREEK
DAILY DISCHARGE HYDRO GRAPHS
1970 NATURAL FLOWS;CANTWELL,WATANA,AND GOLD CREEK
ANNUAL FLOOD FREQUENCY CURVE,MACLAREN RIVER NEAR
PAXTON
ANNUAL FLOOD FREQUENCY CURVE,SUSITNA RIVER NEAR
DENALI
ANNUAL FLOOD FREQUENCY CURVE,SUSITNA RIVER NEAR
CANTWELL
ANNUAL FLOOD FREQUENCY CURVE,SUSITNA RIVER AT GOLD
CREEK
MONTHLY AND ANNUAL FLOW DURATION CURVES,SUSITNA
RIVER
xxvii
EXHIBIT B
PROJECT OPERATION.AND RESOURCE UTILIZATION
...._..·-B:-5-;t~1--··----MrLBELTAJmA-(jF-·AtAS!<A-SlmVrtNC-'£LlfCTRTCA:ttOAlJ
CENTERS
Number
B.3.2.1
B.3.2.2
B.3.2.3
B.3.2.4
B.4.1.1
B.4.1.2
B.4.1.3
B.4.1.4
B.4.1.5
B.4.2.1
B.4.2.2
B.4.2.3
B.4.2.4
B.5.2.2
B.5.2.3
B.5.2.4
B.5.2.5
851104
·,LIST.OF FIGURES (cont I d)
Title
RESE~R.vOIR AREA AND VOLUME VERSUS ELEVATION,WATANA
AND DEVIL CANYON
MONTHLY RULE CURVE ELEVATIONS
LEVELlZED THERMAL ENERGY GENERATION
WATANA OPERATING GUIDE CURVES
TYPICAL LOAD VARIATION IN ALASKA RAIL BELT SYSTEM
MONTHLY LOAD VARIATION FOR RAILBELT AREA
ANCHORAGE-FAIRBANKS TRANSMISSION RELIABILITY
EVALUATION,1999 INTERCONNECTED SYSTEM
ANCHORAGE-FAIRBANKS TRANSMISSION RELIABILITY
EVALUATION,2005 INTERCONNECTED SYSTEM
ANCHORAGE-FAIRBANKS TRANSMISSION RELIABILITY
EVALUATION-,·2025 INTERCONNECTED SYSTEM
WATANA UNIT OUTPUT
DEVIL CANYON UNIT OUTPUT
WATANA AND DEVIL CANYON TAILWATER RATING CURVES
SUSITNA DEPENDABLE CAPACITY
LOCATION MAP SHOWING TRANSMISSION SYSTEMS
MONTHLY LOAD VARIATION FOR RAILBELT AREA
WEEKLY LOAD CURVES -APRIL,.AUGUST,AND DECEMBER
1983
HISTORICAL POPULATION GROWTH
:It,viii
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Number
B.5.2.6
B.5.3.1
B.5.302
Bo 5.303
B.5.3.4
B.5.3.5
B.5.306
B.5.307
B.5.3.8
B.5.3.9
B.5.3.10
.B.5.3.11
B.5.3.12
B.5.3.13
B.5.3.14
B.5.4.1
B.5.4.2
B.5.4.3
B.5.4.4
B.5.4.5
851104
EXHIBIT B
PROJECT OPERATION AND RESOURCE.UTILIZATION
LIST OF FIGURES (cont'd)
Title
HISTORICAL GROWTH IN UTILITY NET GENERATION
RELATIONSHIP OF PLANNING MODELS AND INPlIT DATA,
APR SENSITIVITY MQDEL STRUCTURE
MAP MODEL S¥STEM
ECONOMIC MODULE,FISCAL MODULE AND DEMOGRAPHIC
MODULE
MAP REGIONALlZATION SUB-MODEL STRUCTURE
RED INFORMATION FLOWS
RED UNCERTAINTY MOD ULE
RED HOUSING MODULE
RED RESIDENTIAL CONSUMPTION MODULE
RED BUSINESS CONSUMPTION MODULE
RED MISCELLANEOUS CONSUMPTION MODULE
RED PEAK DEMAND MODULE
OPTIMIZED GENERATION EXPANSION PLANNING (OGP)
PROGRAM INFORMATION FLOWS
OPTlMAlZED GENGRATION PLANNING EXAMPLE OF
CONVENTIONAL HYDRO OPERATIONS
ALTERNATIVE OIL PRICE PROJECTIONS
ALTERNATIVE RAILBELT POPULATION FORECASTS
ALTERNATIVE RAILBELT HOUSEHOLDS FORECASTS
ALTERNATIVE ELECTRIC ENERGY DEMAND FORECASTS
ALTERNATIVE ELECTRIC PEAK DEMAND FORECASTS
xx~x
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851104
EXHIBIT B
PROJECT OPERATION AND RESOURCE UTILIZATION
1 -DAMSITE SELECTION (0)
This section summarizes the previous site selection studies and the
studies done during the Alaska Power Authority Susitna Hydroelectric
Project Feasibility Study (Acres 1982c,Vol.1).
1.1 -Previous Studies (*)
Prior to the undertaking of the Susitna Hydroelectric·Project Feasi-
bility Study by the Applicant,the hydroelectric development potential
of the Alaskan Railbelt had been studied by several entities.
1.1.1 -Early Studies of Hydroelectric Potential (*)
Shortly after World War II ended,the United States Bureau of
Reclamation (USBR)conducted an initial investigation of
hydroelectric potential in Alaska and issued a report of the
results in 1948.Responding to a recommendation made in 1949 by
the nineteenth Alaska territorial legislature that Alaska be
included in the Bureau of Reclamation program,the Secretary of
the Interior provided funds to update the 1948 work.The
resulting report,issued in 1952,recognized the vast
hydroelectric potential within the territory and placed
particular emphasis on the strategic location of the Susitna
River between Anchorage and Fairbanks as well as its proximity to
the connecting Railbelt (Figure B.1.1.1).
A series of studies was commissioned over the years to identify
damsites and conduct geotechnical investigations.By 1961,the
Department of the Interior proposed authorization of a two-dam
power system on the Susitna River involving the Devil Canyon and
the Denali sites (Figure B.1.1.2).The definitive 1961 report
was subsequently updated by the Alaska Power Administration (an
agency of the USBR)in 1974,at which time the desirability of
proceeding with hydroelectric development was reaffirmed.
The Corps of Engineers (COE)was also active in hydropower
investigations in Alaska during the 1950s and 1960s,but focused
its attention ·on a more ambitious development at Rampart on the
Yukon River.This project was capable of generating five times
as much annual electric energy as the prior Susitna proposal.
The sheer size and the technological challenges associated with
Rampart captured the imagination of supporters and effectively
diverted attention from the Susitna basin for more than a decade.
The Rampart report was finally shelved in the early 1970s because
of strong environmental concerns and the uncertainty of marketing
B-1-1
prospec~s for so much energy,particularly in light of .abundant
natural gas which had been discovered and developed in Cook
Inlet.
The energy cr1S~S precipitated by the OPEC oil boycott in 1973
provided some further impetus for seeking development of
renewable resources.Federal funding was made·available both to
complete the Alaska Power Adnlinistration's update report on
Susitna in 1974 and to launch a prefeasibility investigation by
the COED The State of Alaska itself commissioned a reassessment
of the Susitna project by the Henry J.Kaiser Company in 1974.
Salient features of the various reports to date are outlined in
the following sections.
1.1.2 -u.S.Bureau of Reclamation -1953 Study (*)
The USBR 1952 report to the Congress on Alaska's overall
hydroelectric potential was followed shortly by the first major
study of the Susitna basin in 1953.Ten damsites were identified
above the railroad crossing at Gold Creek.These sites are
identified ortFigtireB~1.1.2;artdare listed below:
o Gold Creek
o Olson
o Devil Canyon
o Devil Creek
o Watana
o Maclaren
o Denali
o Butte Creek
o Tyone (on the Tyone River).
Fifteen more sites were considered below Gold Creek.However,
more attention has been focused over the years on the upper
..................-Susitnabasin,where the.topography.is.bett er.suited .·to.dam
__cons truc tion andwhere.les simRac t on anadromous:f::i.§her:i.~.~i.1L_
expected.Field reconnaissance eliminated half the original
upper basin list,and further USBR consideration centered on
Olson,Devil Ganyon,Watana,Vee,and Denali.All of the USBR
studies since 1953 have regarded these sites as the most
appropriate for further investiga tion.
In 1961 a more detaIled feas{bIl{tystudyresult:ed rna
recommended five-stage development plan to match the load
growth curve as it was then projected.Devil Canyon was to be
the firs t development--a 635-foot high arch dam with an installed
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II
851104 B-1-2
851104
capacity of about 220 MW.The reservoir formed by the Devil
Canyon Dam alone would not store enough wa'ter to permit higher
capacities to be economically installed,since long periods of
relatively low flow occur in the winter months.The second stage
would have increased storage capacity by adding an earthfill dam
at Denali in the upper reaches of the basin.Subsequent stages
involved a4ding generating capacity to the Devil Canyon Dam.
Geotechnical investigations at Devil Canyon were more thorough
than at Denali.At Denali,test pits were dug,but no drilling
occurred.
1.1.4 -Alaska Power Administration -1974 Study (*)
Little change from the basic USBR 1961,five-stage concept
appeared in the 1974 report by the Alaska Power Administration.
This later effort offered a more sophisticated design,provided
new cost and schedule estimates,and addressed marketing,
economics,and environmental considerations.
1.1.5 -Kaiser Proposal for Development (*)
The Kaiser study,commissioned by the Office of the Governor in
1974,proposed that the initial Susitna development consist of
a single dam known as High Devil Canyon (for location,see
Figure B.l.l.2).No field investigations were made to confirm
the technical feasibility of the High Devil Canyon location
because the funding level was insufficient for such efforts.
Visual observations suggested the site was probably favorable.
The USBR had always been uneasy about foundation conditions at
Denali,but had to rely upon the Denali reservoir to provide
storage during long periods of low flow.Kaiser chose to avoid
the perceived uncertainty at Denali by proposing to build a
rockfill dam at High Devil Canyon which,at a height of 810 feet,
would create a large enough reservoir to overcome the storage
problem.Although the selected sites were different,the CaE
reached a similar conclusion when it later chose the high dam at
Watana as the first to be constructed.
Subsequent developments suggested by Kaiser included a downstream
dam at the Olson site and an upstream dam at a site known as
Susitna III (Figure B.l.l.2).The information developed for
these additional dams was confined to estimated energy potential.
As in the CaE study,future development of Denali remained a
possibility if foundation conditions were found to be adequate
and if the value of additional firm energy provided economic
justification at some later date.
1.1.6 -U.S.Army Corps of Engineers -1975 and 1979 Studies (*)
The most comprehensive study of the upper Susitna basin prior to
the current study was completed in 1975 by the CaE.A total of
B-1-3
23 alternative developments were analyzed,including those
proposed by the USBR,as well as consideration of coal as the
primary energy source for Railbelt electrical needs.The COE
agreed that an arch dam at Devil Canyon was appropriate,but
found that a high dam at the Watana si te would form a large
enough reservoir for seasonal storage and would permit continued
generation during low flow periods.
The COE recommended an earthfill dam at Watana with a height of
810 feet.In the longer term,development of the Denali site
remained a possibility which,if constructed,would increase the
amount of firm energy available in dry years.
An ad hoc task force was created by Governor Jay Hammond upon
completion ,of the 1975 COE study.This task force re'Commended
endorsement of the COE request for Congressional authorization,
but pointed out that extensive further studies,particularly
those dealing with environmental and socioeconomic questions,
were necessary before any construction decision could be made.
At the federal level,concern was expressed at the Office of
.Management and Budget regarding the adequacy of geotechriica 1 data
at the Watana site as well as the validity of the economics.The
apparent ambitiousness of the schedule'and the feasibility of a
thin arch dam at Devil Canyon were also questioned.Further
investigations were funded and the COE~roduced an updated report
in 1979.Devil Canyon and Watana were reaffirmed as appropriate
sites,but alterttative dam types were investigated.A concrete
~~-gravnyaamwasanalyzeQasanan:erna..tiv'e-~for~Elfe-t1t~in arch dam
at Devil Canyon and the Watana Dam was changed from earthfill to
rockfilL Subsequent cost and schedule estimates still indicated
economic justification for the project.
1.2 -Plan Formulation and Selection Methodology (*)
The proposed plan which is the subject of this License Application was
selected after ··a revi.ewand,-rea sses sment of all previous ly-considered ..
s_Ltes_(Ac.r_es..L9.82_c_,....V_o_L U..__~_..
This section of the report outlines the engineering and planning stud-
ies carried out as a basis for formulation 6f Susitna basin development
plans and selection of the 'preferred plan.
In the description of the planning process,certain plan components and
processesarefrequeniiy di.scussed..'it Is appropriate that ....three par-
ti.Ctlla.r .terllls be clearly defined:
o Damsite -An individual potential damsite in the Susitna basin,
re ferred to in the generic proces s as "candida te ."
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o Basin Development Plan - A plan for developing energy within the
upper Susitna basin involving one or more dams,each of'.specified
height,and corresponding power plants of specified capacity.
Each plan is identified by a plan number and subnumber indicating
the staging sequence to be followed in developin'g the full
potential of the plan over a period 6f time.
o Generation Scenario - A specified sequence of implementation of
power generation sources capable of providing sufficient power
and energy to satisfy an electric load growth forecast for the
1980-2010 period in the Railbelt area.This sequence may include
different types of generation sources such as hydroelectric and
coal-,gas-or oil-fired thermal.These generation scenarios
were developed for the comparative evaluations of Susitna basin
generation versus alternative .,methods of generation.
In applying the generic plan formulation and selection methodology,
~ive basic steps are required:gefining the objectives,selecting can-
didates,screening,formulation of development plans,and,finally,a
detailed evaluation of the plans (Figure B.1.2.1).The objective is to
determine the optimum Susitna basin development plan.The various
steps required are outlined in subsections of this section.
Throughout the planniag process,engineering layout studies were made
to refine the cost estimates for power generation facilities or water
storage development at several damsites within the basin.These data
were fed into the screening and plan formulation and evaluation stud-
ies.
The second objective,the detailed evaluation of the various plans,is
satisfied by comparing generation scenarios that include the selected
Susitna basin development plan with alternative generation scenarios,
including all-thermal and a mix of thermal plus alternative hydropower
developments.
1.3 -Damsite Selection (*)
In previous Susitna basin studies,twelve damsites were identified in
the upper portion of the basin,i.e.,upstream from Gold Creek.
These sites are listed in Table B.1.3.1 with relevant data concerning
facilities,cost,capacity,and energy.
The longitudinal profile of the Susitna River and typical reservoir
levels associated with these sites are shown in Figure B.1.3.1.Figure
B.1.3.2 illustrates which sites are mutually exclusive,i.e.,those
which cannot be developed jointly,since the downstream site would
inundate the upstream site.
It can be readily seen that there are several mutually exclusive
schemes for power development of the basin.The development of the
851104 B-1-5
Watana site precludes development of High Devil Canyon,Devils Creek,
Susitna III and Ve.e but fits well with Devil Canyon.Convers·e1y,the
High Devil Canyon site would preclude Watana and Devil Canyon but fits
well with Olson and Vee or Susitna III.These downstream sites do not
preclude development of the upstream storage sites,Denali or Butte
Creek and Maclaren.
.All relevant da ta concerning dam type,capital cost,power,and energy
output were assembled and are summarized in Table B.1.3.1.For the
Devil Canyon,High Devil Canyon,Watana,Susitna III,Vee,Maclaren,
and Denali sites,conceptual engineering layouts were produced and
capital costs were ~stimated based on calculated quantities and unit
rates.Decai1ed analyses were also undertaken to assess the power
capability and energy yields.At the Gold Creek,Devil Creek,Olson,
Butte Creek,and Tyone si tes,no de tailed engineering or energy studies
were undertaken;data from previous studies were used wit~capital cost
estimates updated in 1980 levels.Approximate estimates of the
potential average energy yield at the Butte Creek and Tyone sites were
under~a~en to assess the relative importance of these sites as energy
produce rs.
The data presented Iti TabieB.f::f~I sh6wthatDevlt CanyOn,fl.ighDevil
Canyon,and W~tana are the most economic large energy producers in the
basin.Sites such as Vee and Susitna III.have only medium energy
production,and are slightly more costly that the previously mentioned
damsites.Other sites such as Olson and Gold Creek are competitive
provided they have addi tiona1 upstream regulation.Sites such as
Denali and Maclaren produce substantially higher cost energy than the
-'-othersi tes but-cao·lilso··l)-e used·to-increase-regulliEiO·o·o-f·-flow-for·--
downstream use.
1.3.1 -Site Screening (*)
The objective of this screening process was to eliminate sites
which would obviously not be included in the initial stages of
the Susitna basin development plan and which,therefore,did not
--···-·deserve······further-studyat-thisst-age.··Three··basic-screening-.....__....
.--~c-r-i-te·r-ia-we·r.e-used:---en-vir.onmental,.--alter.na.tLve si tes,-andener.gy.
contribution.
The screening process involved eliminating all sites falling in
~he unacceptable environmental impact and alternative site
categories •.Those failing to meet the energy contribution
c:r:itgria Wg:re._~JSlgel.im.itl~.l:.egy.tlles stheyha,<Lt;Qmep()tetltia 1 for
upstream regulation.The result:s of this process were as
f(>llows:
o The "unacceptable site"environmental category eliminated
the Gold Creek,Olson,andTyones:i.tes.
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o The alternative sites category eliminated the Devil Creek
and Butte Creek sites.
o No additional sites were eliminated for failing to meet the
energy contribution criteria.The remaining sites upstream
from Vee,i.e.,Maclaren and Denali,were retained to
insure that further study be directed toward determining
the need and viability of providing flow regulation in the
headwaters of the Susitna.
1.3.2 -Engineering Layouts (*)
In order to obtain a uniform and reliable data base for studying
the seven sites remaining,it was necessary to develop
engineering layouts and reevaluate the costs.In addit~on,
staged developments at several of the larger dams were studied.
The basic objective of these layout studies was to establish a
uniform and consistent development cost for each site.These
layouts are consequently conceptual in nature and do not
necessarily represent optimum project arrangements at the sites.
Also,because of the lack of geotechnical information at several
of the sites,judgmental decisions had to be made on the
appropriate foundation and abutment treatment.The relative
accuracy of cost estimates made in these studies is on the order'
of pI us or minus 30 percent.
(a)Design Assumptions (*)
In order to maximize standardization of the layouts,a set
of basic.design assumptions was developed.These
assumptions covered geotechnical,hydrologic,hydraulic,
civil,mechanical,and electrical considerations and were
used as guidelines to determine the type and size of the
various components within the overall project layouts.As
stated previously,other than at Watana,Devil Canyon,and
Denali,little information regarding site conditions was
available.Broad assumptions were made on the basis of the
limited data,and those assumptions and the interpretation
of data have been conservative.
It was assumed that the relative cost differences between
rockfill and concrete dams at the site would either be
marginal or greatly in favor of the rockfill.The more
detailed studies carried out subsequently for the Watana and
Devil Canyon sites support this assumption.Therefore,a
rockfill dam has been assumed at all developments in order
to eliminate cost discrepancies that might result from a
consideration of dam-fill unit costs compared to concrete
unit costs at alternative sites.
851104 B-1-7
(b)General Arrangements (*)
Brief descriptions of the general arrangements developed for
the various sites are given below.Descriptions of Watana
and Devil Canyon in this section are of the preliminary lay-
outs and should not be confused with the proposed layouts in
Exhibit A and Exhibit F.Figures B.l.3.3 to B.l.3.9
illustrate the layout details.Table B.l.3.3 summarizes the
crest levels and dam heights considered.
In laying out the developments,conservative arrangements
have been adopted,and whenever possible there has been a
general standardization of the component structures.
(0 Devil Canyon (Figure B.l.3.-3)(*)
The development at Devil Canyon,located at the upper
end of the canyon at its narrowest point,consists of
a rockfill dam,single spillway,power facilities
incorporating an underground powerhouse,and a tunnel
diversion.-
The rockfill dam would rise above the valley on the
south abutment and terminate in an adjoining saddle
dam of similar construction.The dam would be 675
feet above the lowest foundation level with a crest
elevation of 1,470 and a volum~of 20 million cubic
The spillway would be located on the north bank and
would consist of a gated overflow structure and a
concrete-lined chute linking the overflow structure
with intermediate and terminal stilling basins.
Sufficient spillway capacity would be provided to
pass the Probable Maximum Flood safely.
-------------------.----The--power---fa-c-i-l-i-t-ies--wo u1-d-be-loca-ted-on-the north-.
.----._.~_--_..~_-_._--_.._-_._--___._------.__.._~_--_~_-----.._-----_.---~a-b.u.tmen.t-o--The~tIia:s.s.i1T~intake-:.s_truc~t_ure_+w.o.ul_d __b.e .__~
founded within the rock at the end of a deep approach
channel and would consist of four integrated units,
each serving individual tunnel penstocks.The
powerhouse would house four l50~vertically mounted
Francis type turbines driving overhead l65-MVA
synchronous gene~ators.
As an alternative to-the full power CievE!lqpml:!llt:ill
the first phase of construction,a staged powerhouse
alternative was also investigated.The dam would be
completed to its full height but with an initial
plant installed capacity in the300-MW range.The
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851104 B-1-8
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851104
complete powerhouse would be constructed t~gether
with penstocks and a tailrace tunnel for the initial
two 150-MW units,together with concrete foundations
for future units.
(ii)Watana (Figures B.l.3.4 and B.l.3.5)(*)
For initial comparative study purposes,the dam at
Watana is assumed to be a rockfill structure located
on a similar alignment to that proposed in the
previous COE studies.It would be similar in
construction to the dam at Devil Canyon with an
impervious core founded on sound bedrock and an outer
shell composed of blasted rock excavated from a
single quarry located on the south abutment.The dam
would rise 880 feet from the lowest point~on the
foundation and have an overall volume of
approximately 63 million cubic yards for a crest
elevation of 2,225.
The spillway would be located on the north bank and
would be similar in concept to that at Devil Canyon
with intermediate and terminal stilling basins.
The power facilities located within the south
abutment with similar intake,underground powerhouse,
and water passage concepts to those at Devil Canyon
would incorporate four 200-MW turbine/generator units
giving a total output of 800 MW.
As an alternative to the initial full development at
Watana,staging alternatives were investigated.
These included staging of both dam and powerhouse
construction.Staging of the powerhouse would be
similar to that at Devil Canyon,with a Stage I
installation of 400 MW and a further 400 MW in Stage
II.
In order to study the alternative dam staging
concept,it was assumed that the dam would be
constructed for a maximum operating water surface
elevation some 200 feet lower than that in the final
stage (Figure B.l.3.5).
The powerhouse would be completely excavated to its
fina I size during the first stage.Three oversized
135-MW units would be installed together with base
concrete for an additional unit.A low-level control
structure and twin concrete-lined tunnels leading
into a downstream stilling basin would form the first
stage spillway.
B-I-9
For the second stage,the dam would be completed to
its full height,the impervious core would 'be '
appropriately raised,and additional rockfill would,
be placed on the downstream face.It was assumed
that,before construction commenced,the top 40 feet
of the first stage dam would be removed to ensure the
complete integrity of the impervious core for the
raised dam.A second spillway control structure
would be constructed at a higher level and would
incorporate a downstream chute leading to the Stage I
spillway structure.The original spillway tunnels
would be closed with concrete plugs.A new intake
structure would be ~onstructed utilizing existing
gates and hoists,and new penstocks would be driven
to connect with the existing ones.The existing
intake would be sealed off.One additional 200-MW
unit would be installed and the required additional
penstock and tailrace tunnel constructed.The
existing 135~units would be upgraded to 200 MW.
(iii)HighDevilCal1 yon (Figure B'.1.3.6)(*)
The development would be located between Devil Canyon
and Watana.The 855-foot high rockfill dam would
be similar in design to Devil Canyon,containing an
estimated 48 million cubic yards of rockfill with a
crest elevation of 1,775.The south bank spillway
and the north bank powerhouse facilities woul,d also
'oesiliiTlaj:-in concept-to DeviT Cany'on;wiEn 'an -
installed capacity of 800 MW.
Two stages of 400 MW were envisaged,each of which
would be undertaken in the same manner as at Devil
Canyon,with the dam initially constructed to its
full height.
····(.iv}·Sus-itna-I-I-I-(Fig-ure .B.l.3.7)--(-*)
._--_.._---------_.._--------------_._-----------~.._____--------___---.._.
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851104
(v)
The development would involve a rockfill dam with an
impervious core approximately 670 feet high,a
crest elevation of 2,360,and a volume of
approximately 55 million cubic yards.A
concrete-lined spillway chute and a single stilling
basin would be located underground,with the two
diversion tunnels on the south bank.
Vee (Figure B.1.3.8)(*)
A 610-foot high rockfill dam founded on bedrock with
a crest elevation of 2,350 and total volume of 10
million cubic yards was considered.
B-1-10
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Since Vee is 10cate4 farther upstream than the other
major sites,the flood flows are correspondingly
lower,thus allowing for a reduction in size of the
spillway facilities.A spillway utilizing a gated
overflow structure,chute,and flip bucket was
adopted.
The power facilities would consist of a 400-MW
underground power house located in the south bank
with.a tailrace outlet well downstream of the main
dam.A secondary rockfill dam would also be required
in this vicinity to seal off a low point.Two
diversion tunnels would be provided on the north
bank.
(vi)Maclaren (Figure B.l.3.9)(*)
The development would consist of a l85-foot high
earthfill dam founded on pervious riverbed
materials.The crest elevation of the dam would be
2,405.This reservoir would essentially be used for
regulating purposes.Diversion would occur through
three conduits located in a open cut on the south
bank,and floods would be discharged via a side chute
spillway and stilling basin on the north bank.
(vii)Denali (Figure B.l.3.9)(*)
Denali is similar in concept to Maclaren.The dam
would be 230 feet high,of earthfill construction,
and with a crest elevation of 2,555.As for
Maclaren,no generating capacity would be included.
A combined diversion and spillway facility would be
provided by twin concrete conduits founded in open
cut excavation in the north bank and discharging into
i a common stilling basin.
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1.3.3 -Capital Costs (*)
851104
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For purposes of initial comparisons of alternatives,construction
quantities were determined for items comprising the major works
and structures at the site.Where detail or data were not
sufficient for certain work,quantity estimates were made on the
basis of previous development of similar sites and general
knowledge of site conditions reported in the literature.In
order to determine total capital costs for various structures,
unit costs have been developed for the items measured.These
have been estimated on the basis of review of rates used in
previous studies,and of rates used on similar works in Alaska
and elsewhere.Where applicable,adjustment factors based on
B-l-ll
geography,climate,manpower and accessibility were used.
Technical publications have'also been reviewed for basic rates
and escalation factors.
The total capital costs developed are shown in Tables B.l.3.l and
B.l.3.2.It should be noted that the capital costs for Maclaren
and Denali shown in TableB.1.3.1·have been adjusted to
incorporate the costs of generation plants with capacities of 55
MW and 60 MW,respectively.Additional data on the projects are
summarized in Table B.l.3.3.
1.4 -Formullitioti.of Susitna Basin Development Plans (*)
The results of the site screening process described above indicate that
the Susitna basin development plan should incorpora-te a combination
of several major dams and powerhouses located at one or more of the
following sites:
o Devil Canyon
a High 'nevi1 Canyon'
o Watana.
o Susitnli III
o Vee.
Supplementary upstream flow regulation could be provided by structures
at Maclaren and Denali.
A computer-assisted screening process identified the plans of Devil
Canyon/Watana or High Devil Canyon/Vee as most --economic.In addition
to these two basicde~elopmentplans,a tunnel scheme which provides
potentilil environmental advantages by replacing the Devil Canyon Dam
with a long power tunnel and a development plan involving Wa tana Dam
were also introduced.
The criteria used-at'this"stage of-the 'process'for selectron-o·f-pre.......--.---
-,-~--.-----..---ferred--Sus-i-tna---bas-in--deve-l-opment--plans-were-ma-in-l-y-econom-ic-(-F-igure--,----------
B.l.2.l).Environmental considerations were incorporated into the
further assessment of the plans finally selected.
The results of thes.creeningprocessareshown in TableB.1.4.2
Because of the simplifying asstnIlptions that were made in the screening
model,'the _three best solutions from an economic point of view are
included'in--the --tlible;
The most important conclusion!:!that can be drawn are as follows:
o For energy requirements of up to 1,750 GWh,the High Devil
Canyon,Devil Canyon or the Watana sites individually provided
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851104 B-1-12
the most economic energy.The difference between the costs shown
on Table B.l.4.2 is around 10 percent,which is similar to the
accuracy that can be expected from the screening model.
o For energy requirements of between 1,750 and 3,500 GWh,the High
Devil Canyon site is the most economic.
o For energy requirements of between 3,500 arid 5,250 GWh,the
combinations of either Watana and Devil Canyon or High Devil
Canyon and Vee are most economic.
o The total energy production capability of the Watana/Devil Canyon
development is considerably larger than that of the High Devil
Canyon/Vee alternative and is the only plan capable of meeting
energy demands in the 6,000 GWh range.
1.4.1 -Tunnel Alternatives (*)
A scheme involving a long power tunnel could conceivably be used
to replace the Devil Canyon Dam in the Watana/Devil Canyon
development plan.It could develop similar head for power
generation and might provide some environmental advantages by
avoiding inundation of Devil Canyon.Obviously,because of the
low winter flows in the river,a tunnel alternative could be
considered only as a second stage to the Watana development.
Conceptually,the tunnel alternatives wou~d comprise the
following major components in some combination,in addition to
the Watana Dam,reservoir and associated powerhouse:
o Power tunnel intake works;
o One or two power tunnels up to 40 feet in diameter and up
to 30 miles in length;
o A surface or underground powerhouse with a capacity of up
to 1,200 MW;
o A re-regulation dam if the intake works are located
downstream from Watana;and
o Arrangements for compensation flow in the bypassed river
reach.
Four basic alternative schemes were developed and studied.
Figure B.l.4.l is a schematic illustration of these schemes.All
schemes assumed an initial Watana development with full reservoir
supply level at elevation 2,200,and the associated powerhouse
with an installed capacity of 800 MW.Table B.l.4.3 lists all
the pertinent technical information.Table B.l.4.4 lists the
851104 B-l-13
851104
power and energy yields for the four schemes.Table B.1.4.5
itemizes the capital cost estimate.
Based on the foregoing economic information,Scheme 3 (Figures
B.1.4.2 and B.1.4.3)produces the lowest cost energy by a factor
of nearly 2.
A review of the environmental impacts associated with the four
tunnel schemes indicates that Scheme 3 would have the least
impact,primarily because it offers the best opportunities for
regulating daily flows downstream from the project.Based on
this assessment and because of its almost 2 to 1 economic
advantage,Scheme 3 was selected as the only scheme worth further
study.(See Development Selection Report for detailed analysis.)
The capital cost estimate for Scheme 3 appears in Table B.1.4.5.
The estimates also incorporate single and double tunn~l options.
For purposes of these studies,the double tunnel option has been
selected because of its superior reliability.It sh.ould also be
recognized that the cost estimates associated with.the tunnels
are probably subject to more varia tion than those associated with
the dam schemes,due to geotechnical uncertainties.·In an
attempt to compensate for these uncertainties,economIc
sensitivity analyses using both higher and lower tunnel costs
have been conducted.
1.4.2 -Additional Basin DevelOpment Plan (*)
As noted,the Watana and High Devil Canyon damsites.appear to be
l.ndIvTdualTY -superIor-Tn economlcterms-to--arr others:-An
additional plan was therefore developed to assess the potential
for developing these two sites together.For this scheme,the
Wa tana Dam would be developed to its full potential.The High
Devil Canyon Dam would be constructed to a crest elevation of
1,470 to fully utilize the head downstream from Watana.
1.4.3 -Selected Basin DevelOpment Plans (*)
------The-ess en·t-ia-1-ob-:iee-t-i-ve-o-f-t-h-is-s-t-ep-in-t-he-de-velopment-se-lec-t-ion---
process was defined as the identification of those plans which
appear to warrant further,more detailed evaluation.The results
of the final screening process indicate that the Watana/Devil
Canyon and the High Devil Canyon/Vee plans are clearly superior
to all other dam combinations.In addition,it was decided to
study'l'um!eLSchf:T!l.eJ fUJ::ther ..;3.s<1n.;3.:J.t:eI:"n<1tive.t:Qt:he liigh Devil
--------CanyonDam and-a plan combiningWatana and·High Devil-Canyon.
Associated with each of these plans are several options for
staged development.For this more detailed analysis of these
basic plans,a range of different approaches to staging the
developments was considered.In order to keep the total options
B-1-14
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to a reasonable number and also to maintain reasonably large
staging steps consistent with the total development size,staging
of only the two larger developments (i.e.,Watana and High Devil
Canyon)was considered.The basic stag~ng concepts adopted for
these developments involved staging both dam and powerhouse
construction or,alternatively,just staging powerhouse
construction.Powerhouse stages were considered in 400-MW
increments.
Four basic plans and associated subplans are.briefly described
below.Plan 1 involves the Watana/Devil Canyon sites,Plan 2 the
High Devil Canyon/Vee sites,Plan 3 the Watana-tunnel concept,
and Plan 4 the Watana/High Devil Canyon sites.Under each plan
several alternative subplans were identified,each involving a
different staging concept.Summaries of theseq'pl'ans are given in
Table.B.l.4.6.
(a)Plan 1 (*)
(i)Subplan 1.1 (*)
The first stage involves constructing Watana Dam to
its full height and installing 800 MW.Stage 2
involves constructing Devil Canyon Dam and installing
600 MW.
(ii)Subplan 1.2 (*)
For this subplan,construction of the Watana Dam
staged from a crest elevation of 2,060 to 2,225.
powerhouse is also staged from 400 MW to 800 MW.
for Subplan 1.1,the final stage involves Devil
Canyon with an installed capacity of 600 MW.
(iii)Subplan 1.3 (*)
is
The
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851104
This subplan is similar to subplan 1.2 except that
only the powerhouse and not the dam at Watana is
staged.
(b)Plan 2 (*)
(i)Subplan 2.1 (*)
This subplan involves constructing the High Devil
Canyon Dam first with an installed capacity of 800
MW.The second stage involves constructing the Vee
Dam with an installed capacity of 400 MW.
B-I-15
(ii)Subplan 2.2 (*)
For this subplan,the construction of High Devil
Canyon is staged from a crest elevation of 1,630 to
1,775.The installed capacity is also staged from
400 to 800 MW.As for subplan 2.1,Vee follows with
400 MW of installed capacity.
(iii)Subplan 2.3 (*)
This subplan is similar to subplan 2.2 except that
only the powerhouse and not the dam at High Devil
Canyon is staged.
(c)Plan 3 (*)
(i)Subplan 3.1 (*)
This subplan involves initial construction of
Watana and installation of 800-MW capacity.The next
stage involves the construction of the downstream
reregulation dam to a crest elevation of 1,500 and a
IS-mile long tunnel.A total of 300 MW would be
installed at the end of the tunnel and a further 30
MW at the re-regulation dam.An additional 50 MW of
capacity would be installed at the Watana powerhouse
to facilitate peaking operations.
This subplan is essentially .the same as subplan 3.1
except that construction of the initial 800-MW
powerhouse at Watana is staged.
(d)Plan 4 (*)
··_---c-··-This-·sing1:eplan-was--developed--to·jointly-eva-luatethe-
de-ve-1-opme·nt--o-f-the-two..:.mo st~eGonom-ic-dams-i-tes-,--Wa-ta-na-and--..---_...
High Devil Canyon.Stage 1 involves constructing Watana to
its full height with an installed capacity of 400 MW.Stage
2 involves increasing the capacity at Watana to 800 MW.
Stage 3 involves constructing High Devil Canyon to a crest
elevation of 1,470 so that the reservoir extends to just
downstream of Watana.In orcier to develop the full head
betweenWatanaandPortage·'Creek,'an-additional smaller dam
is:"a.dded:"dowtls ttea.m:"0 LHigh .DevilLCartyoo.Thi sdanLwoul d be
located just upstream from Portage Creek so as not to
interfere with the anadromous fisheries,and would have a
crest elevation of 1,030 and an installed capacity of 150
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MW.For purposes of these studies,this site is referred to
as the Portage Creek site.
1.5 -Evaluation of Basin Development Plans (*)
The overall objective of this step in the evaluation process was to
select the preferred basin development plan.A preliminary
evaluation of plans was initially undertaken to determine broad
comparisons of the available alternatives.This was followed by
appropriate adjustments to the plans and a more detailed evaluation and
comparison.
In the process of initially evaluating the final four schemes,it
became apparent that there would be environmental problems associated
with allowing daily peaking operations from the most downstream reser-
voir in each of the plans described above.In order to avoid these
potential problems while still maintaining operational flexibility to
peak on a daily basis,re-regulation facilities were incorporated in
the four basic plans.These facilities incorporate both structural
measures such as re-regulation dams and modified operational pro-
cedures.Details of these modified plans,referred to as El to E4,are
listed in Table B.l.5.l.
The plans listed in Table B.I.5.1 were subjected to a more detailed
analysis as described in the following section.
1.5.1 -Evaluation Methodology (*)
The apprnach to evaluating the various basin development plans
described above is twofold:
o For determining the optimum staging concept associated with
each basic plan (i.e.,the optimum subplan),only economic
criteria are used and the least-cost staging concept is
adopted.
o For assessing which plan is the most appropriate,a more
detailed evaluation process incorporating economic,
environmental,social and energy contribution aspects is
taken into account.
Economic evaluation of any Susitna basin development plan
requires that the impact of the plan on the cost of energy to the
Railbelt area consumer be assessed on a systemwide basis.Since
the consumer is supplied by a large number of different
generating sources,it is necessary to determine the total
Railbelt system cost in each case to compare the various.Susitna
basin development options.
B-1-17
851104
The primary tool used for system costs was the mathematical model
developed by the Electricity Utility Systems Engineering
Department of General Electric Company.The model is commonly
known as OGP5 or Optimized Generation Planning Model,Version 5.
The following information is paraphrased from GE literature on
the program (General Electric 1979).
The OGP5 program was developed over ten years to combine the
three main elements of generation expansion planning (system
reliability,operating and investment costs)and automate
generation addition decision analysis.OGP5 will automatically
develop optimum generation expansion patterns in terms of
economics,reliability and operation.Many utilities use OGP5 to
study load management,unit size,capital and fuel costs,energy
storage ,forced outage rates,and forecast uncertainty.·
The OGP5 program req uires an extensive system of specific da ta to
perform its planning function.In developing an optimal plan,
the program considers the existing and committed units (planned
and under construe tion)available to the system and the
characteristics of these units including age,heat rate,size and
Clutage rates a.s the ba.se generation plan.The program then
considers the given load forecast and operation criteria to
determine the need for additional system capacity based on given
reliabil.ity criteria.This determines "how much"capacity to add
and "when"it should be installed.If a.need exists during any
monthly iteration,the program will consider additions from a
list of alternatives and select the available unit best fitting
thesy s~tejjCiiEH:fds·~·····Un1 tSE!lEtcthm-is~-m1:l(:le-·by-coIl1puting~pr oduction~
costs for the system for each alternative included and comparing
the results.
The unit resulting in the lowest system production cost is
selected and added to the system.Finally,an investment cost
analysis of the capital costs is completed to answer the question
of "what kind"of generation to add to the system.
_~......~~__.!h.e_mo_d_e_l is then further used to compare alternative pJans for.
meeting variable electrical demands,based on system reliability
and production costs for the study period.
A minor limitation inherent in the use of the OGP5 model is that
the number ·of years of simulation is limited to 20.To overcome
this,the study period of 1980 to 2040 has been broken into three
separate·segtnents for study purposes.These.segments.are COlIlIllOn
to all system generation plans.·
The first segment has been assumed to be from 1980 to 1990.The
model of this time period included all committed generation units
and is assumed to be common to all generation scenarios.
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The end point of this model becomes the beginning of each
1990-2010 model.
The model of the first two time periods considered (1980 to 1990,
and 1990 to 2010)provides the total production costs on a
year-to-year basis.These total costs include,for the period of
modeling,all costs of fuel and operation and maintenance of all
generating units included as part of the system.In addition,
the completed production costs include the annualized investment
costs of any production plans added during the period of study.
A number of factors which contribute to the ultimate cost of
power to the consumer are not included in this model.These are
common to all scenarios and include:
o All investment costs to plants in service prior to 1981;
o Costs of transmission systems in service both at tha
transmission.and distribution level;and
o Administrative costs of utilities for providing electric
service to the public.
Thus,it should be recognized that the production costs modeled
represent only a portion of ultimate consumer costs and in effect
are only a portion,albeit major,of total costs.
The third period,2010 to 2040,was modeled by assuming that
production costs .of 2010 would recur for the additional 30 years
to 2040.This assumption is believed to be reasonable given the
limitations on forecasting energy and load requirements for this
period.The additional period to 2040 is required to at least
take into account the benefit derived or value of the addition of
a hydroelectric po~er plant which has a useful life of 50 years
or more.
The selection of the preferred generation plan is based on
numerous factors.One of these is the cost of the generation
plan.To provide a consistent means of assessing the production
cost of a given generation scenario,each production cost total
has been converted to a 1980 present worth basis.The present
worth cost of any generation scenario is made up of three cost
amounts.The first is present worth cost (PWC)of the first ten
years of study (1981 to 1990),the second is the PWC of the
scenario assumed during 1990 to 2010,and the third is the PWC of
the scenario in 2010 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.
A summary of the input data to the model and a discussion of the
results follow.
B-1-19
(a)Initial Economic Analyses (*)
Table B.I.5.2 lists the results of the first series of
economic analyses undertaken for the basic Susitna basin
development plans listed in Table B.l.5.l.The information
provided includes the specified on-line dates for the
various stages of the plans,the OGP5 run index number,the
total installed capacity at year 2010 by category,and the
total system present worth tost in 1980 for the period 1980
to 2040.Matching of the Susitna development to the load
growth for PlansEl,E2,and E3 is shown in Figures B.l.5.1,
B.l.5.2 and B.l.5.3,respectively.After 2010,steady state
conditions are assumed and the then-existing generation mix
and annual costs for 2010 are applied to the years 2011 to
2040.This extended period of~time is necessary to ensure
that the hydroelectric o~tions being studied,many of which
only come on line around 2000,are simulated as operating
for periods approaching their economic lives and that their
full impact on the cost of the generation system is taken
into account.
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(i)Plan El -Watana/Devil Canyon (*)
Staging the dam at Watana (Plan El.2)is not as
economic as constructing it to its full height
(Plan El.1 and El.3).The present worth advantage of
not staging the dam amounts to $180 million in 1980
dollars.
The results indicate that,with the level of analysis
performed,there is no discernible benefit in staging
construction of the Watana powerhouse (Plan E1.l and
EL3).However,Plan El.4 results indicate that,
should the powerhouse size at Watana be restricted to
400 MW,the overall system present worth costs would
increase.
Additional runsJ:)erformed for variations ofplan~El ..3_
indicate that system present worth would increase by
$1,110 million if the Devil Canyon Dam were not
constructed.A five-year delay in construction of
the Watana Dam would increase system present worth by
$220 million.
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851104
-_ucnLPlan E2--~High D-evir-CanY9ii/V€!eI-kr---
The res Ul.!iS for plan E2 .3:cndTcate t ha t the sy stem
present worth is $520 million more than Plan El.3.
Present worth increases also occur if the Vee Dam
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stage is not constructed.A reduction in present
worth of approximately $160 million is possible if
the Chakachamna hydroelectric project is constructed
instead of the Vee Dam.
The results of Plan E2.1 indicate that total system
present worth would increase by $250 million if the
total capacity at High Devil Canyon were limited to
~O~.
(iii)Plan E3 -Watana-Tunnel (*)
The results for Plan E3.1 illustrate that the tunnel
scheme versus the Devil Canyon Dam scheme (E1.3)
adds approximately $680 million to the total system
present worth cost.The availability of reliable
geotechnical data would undoubtediy have improved the
accuracy of the cost estimates for the tunnel
alternative.For this reason,a sensitivity analysis
was made as a check to determine the effect of
halving the tunnel costs.This analysis indicates
that the tunnel scheme is still more costly than
constructing the Devil Canyon Dam.
(iv)Plan E4 -Watana/High Devil Canyon/Portage Creek (*)
The results indicate that system present worth
associated with Plan E4.l,excluding the Portage
Creek site development,is $200 million more than the
equivalent El.3 plan.If the Portage Creek
development is included,the present worth difference
would be even greater.
(b)Load.Forecast Sensitivity Analyses (*)
The plans with the lowest present worth cost were subjected
to further sensitivity analysis.The objective of the
analysis was to determine the impact on the development
decision of a variance in forecast.The load forecasts used
for this analysis were made by ISER and are presented in
Section 5.4.5 of this Exhibit.These results are summarized
in Table B.l.5.3.
At the low load forecast,full capacity development of
Watana/Devil Canyon Scheme 1.3 is not warranted.Under
Scheme 1.4,the most economic development includes a 400-~
development at each site,as compared to Watana only.
Similarly,it is more economic to develop High Devil Canyon
and Vee,as compared to High Devil Canyon only,but at a
total capacity of only 800 ~.
851104 B-1-21
\
At this level of projected demand,the Watana/Devil Canyon
plan is more economic than the High Devil Canyon/Vee plan or
any singular development ($210 million,present worth ba-
sis).As individual developments,however,the High Devil
Canyon only plan is slightly superior economically to the
Watana project ($90 million,present worth basis).
At the high load forecast,the larger capacities are clearly
needed.In addition,both the High Devil Canyon/Vee and
Watana/Devil Canyon plans are improved economically by the
addition of the Chackachamna project.This illustrates the
superiority of the Chackachamna project to the addition of
alternative coal and gas projects using the study price pro-
jections.Similar to the low load forecast,the Wa tana/
Devil Canyon project is superior to the High Devil Canyon/
Vee alternative but the margin of difference on "a-present
worth basis is much greater ($1.0 billion,present worth
basis)•
1.5.2 -Evaluation Criteria (*)
The following criteria were used to evaluate the short-listed
basin development plans.These criteria generally contain the
requirements of the generic process with the exception that an
additional criterion,energy contribution,is added ,in order to
ensure that full consideration is given to the total basin energy
potential developed by the ~arious plans.
(a)Economic (*)
Plans were compared using lotig;;.;tetm present worth cos ts,
calculated using the OGP5 generation planning model.The
parameters used in calculating the total present worth cost
of the total RaUbel t generating system for the period 1980
to 2040 are listed in Tables B.1.5.4 and B.l.5.5.Load
forecasts used in the analysis are presented in Section
(b)Environmental (*)
A qualitative assessment of the environmental impact on the
ecological,cultural,and aesthetic resources is
undertaken for each plan.Emphasis is placed on identifying
major concerns so that these can be combined with the other
·€!V~ill'iJat:io·ll.··ifttribut'esin:an overall assessment of the plan.
(c)Social (*)
This attribute includes determination of the potential
nonrenewable resource displacement,the impact on the
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851104 B-1-22 ,I
state and local economy,and the risks and consequences of
major structural failures due to seismic events.Impacts on
the economy refer to the effects of an investment plan on
economic variables.
(d)Energy Contribution (*)
The parameter used is the total amount of energy produced
from the specific development plan.An assessment of the
energy development foregone is also undertaken.The energy
loss that is inherent to the plan and cannot easily be
recovereu by subsequent staged developments is of greatest
concern.
1.5.3 -Results of Evaluation Process~*)
The various attributes outlined above have been determined ·for
each plan and are summarized in Tables B.1.5.6 through
B.1.5.14.Some of the attributes are quantitative while others
are qualitative.Overall evaluation is based on a comparison of
similar types of attributes for each plan.In cases where the
attributes associated with one plan all indicate equality or
superiority with respect to another.plan,the decision as to the
best plan is clear cut.-·In other cases where some attributes
indicate superiority and others inferiority,differences are
highlighted and trade-off .decisions are made to determine the
preferred development plan.In cases where these trade-offs have
had to be made,they were relatively straightforward,and the
decision-making process can therefore be regarded as effective
and consistent.In addition,these trade-offs are clearly
identified so that independent assessment can be made.
The overall evaluation process is conducted in 'a series of steps.
At each step,only two plans are compared.The superior plan is
then taken to the next step for evaluation against a third plan.
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851104
(a)Devil Canyon Dam Versus Tunnel (*)
The first step in the process involves the comparison of the
Watana/Devil Canyon Dam plan (E1.3)and the Watana-tunnel
plan (E3.1).Since Watana is common to both plans,the
evaluation is based on a comparison of the Devil Canyon Dam
and the Scheme 3 tunnel alternative.
In order to assist in the evaluation in terms of economic
criteria,additional information obtained by analyzing the
results of the OGP5 computer runs is shown in Table B.1.5.6.
This information illustrates the breakdown of the total
system present worth cost in terms of capital investment,
fuel,and operation and maintenance costs.
B-1-23
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851104
(i)Economic Comparison (*)
From an economic point of view,the Watana/Devil
Canyon Dam scheme is superior.As summarized in
Tables B.l.s.6 and B.l.s.7,on a present worth basis
the tunnel scheme is $680 million more expensive than
the dam scheme.For a low demand growth rate,this
cost difference would be reduced slightly to $650
million.Even if the tunnel scheme costs are halved,
the total cost difference would still amount to $380
million.As highiighted in Table B.lo5.7,
consideration of the sensitivity of the basic
economic evaluation to potential changes in capital
cost estimates,the period of economic analysis,the.
discount rate,fuel costs,fuel cost escalation,and
economic plant life do not change the basic econ~ic
superiority of the dam scheme over the tunnel
scheme.
(ii)Environmental Comparison (*)
The eIlvironlIlental comparison of the two schemes is
summarized in Table B.1.5.8.Overall,the tunnel
scheme is judged to be superior because:
o 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-achi-eved-in this
reach;
o It would inundate 13 miles less of resident
fisheries habitat in the river and major
tributaries;
o It has a lower potential for inundating
.a rch eologicaL.sites.due__to_the_smaUer .
..reservoir involved;_and_______~_
o It would preserve much of the characteristics
of the Devil Canyon gorge which is considered
to be an aesthetic and recreational resource.
(iii)Social Comparison (*)
--Table B..l.s.9summarizes the eval-uation of the two
~_."~_.•..._-_...••._.-."..--.---_.....~--.
schemes in terms of the social cri teria.In terms of
impact on state and local economics and risks because
of seismic exposure,the two schemes are rated equal.
However,due to its higher energy yield,the dam
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scheme has more potential for displacing nonrenewable
energy resources and therefore has a slight overall
advantage in terms of the social evaluation
criteria.
(iv)Energy Comparison (*)
Table B.I.S.IO summarizes the evaluation in terms of
the energy contribution criteria.The results show
that the dam scheme has a greater potential for
energy produc tion and develops a larger portion of
the basin's potential.The dam scheme is therefore
judged to be-superior from the energy contribution
standpoint.
(v)Overall Comparison (*)
The overall evaluation of the two schemes is·
summarized in Table B.I.S.II.The estimated cost
saving of $680 million in favor of the dam scheme
plus the additional energy produced are considered to
outweigh the reduction in the overall environmental
impact of the tunnel scheme.The dam scheme is
therefore judged to be superior overall.
(b)Watana/Devil Canyon Versus High Devil Canyon/Vee (*)
The second step in the development selection process -in-
volves an evaluation of the Watana/Devil Canyon (EI.3)and
the High Devil Canyon/Vee (E2.3)·development plans.
I
(0 Economic Comparison (*)
In terms of the economic criteria (see Table B.I.S.6
and B.I.S.7)the Watana/Devil Canyon plan is less
costly by $520 million.Consideration of the
sensitivity of this decision to potential changes in
the various parameters considered (i.e.,load
forecast,discounted rates,etc.)does not change the
basic superiority of the Watana/Devil Canyon plan.
Under the low load-growth forecast,the Watana/Devil
Canyon plan is favored by only $210 million,while
under the high load-growth forecast the advantage is
$1,040 million.
851104
(ii)Environmental Comparison (*)
The evaluation in terms of the environmental criteria
is summarized in Table B.I.S.12.In assessing these
B-I-2S
plans,a reach-by-reach comparison was made.for the
section of the Susitna River between Portage Creek
and the Tyone River.The Watana/Devil Canyon scheme
would create more potential.environmental impacts in
the Watana Creek area.However,it is judged that
the potential environmental impacts which would occ ur
above the Vee Canyon Dam with a High Devil Canyon/Vee
development are more severe in overall comparison.
Of the seven environmental factors considered in
Table B.l.S.12,except for the increased loss of
river valley,bird and black bear habitat,the
Watana/Devil Canyon development plan is judged to be
more environmentally acceptable than the High
Canyon/Vee plan.
The other six areas in which Watana/Devil Canyon was
judged to be superior are fisheries,moose,caribou,
furbearers,cultural resources,aesthetics,and land
use.
(iii)Energy Comparison (*)
The evaluation of the two plans in terms of energy
contribution criteria is summarized in Table
B.l.S.13.+he Watana/Devil Canyon scheme is
assessed to be superior because of its higher energy
potential and the fact that it develops a higher
-proporfion o-f--Ehe DasTnrs-energy-pofentia.T~--
The Watana/Devil Canyon plan annually develops 1,160
GWh and 1,6S0 GWh more average and firm energy,
respectively,than the High Devil Canyon/Vee plans.
(iv)Social Comparison (*)
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..........o .__.•__Tab le-B.1.5.-9-8 umma·rcizes··t-he-evaluat-ion-in te·rms-of--··
....._..___._........J:_b.!!_s_o_cia.l_cri.ter.ia_•._As-in_the-ca·s e--o.f--the--dam--···-·---·__·-·_···-·
versus tunnel comparison,the Watana/Devil Canyon
plan is judged to have a slight advantage over the
High Devil Canyon/Vee plan.This is because of its
greater potential for displacing nonrenewable
resources.In other socia 1 impac t areas there are 1
minimal differences between plans..
(v)OveraU COIllparison (
The overall evaluation of the two schemes is
summarized in Table B.1.S.14.The $S20 million
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8S1104 B-1-26
estimated cost saving coupled with the lower
environmental impacts and a marginal social"advantage
make the Watana/Devil Canyon plan superior to High
Devil Canyon/Vee.
1.6 -Preferred Susitna Basin Development Plan (**)
One-on-one comparisons of the Watana/Devil Canyon plan with the Watana-
tunnel plan and the High Devil Canyon/Vee plan are judged to favor
the Watana/Devil Canyon plan in each case.The Watana/Devil Canyon
plan was therefore selected as the preferred Susitna basin development
plan.
In May 1985,the Applicant concluded that a number of benefits would be
derived from a modification of the Watana/Devil Canyon two-dam plan
providing for completion of construction in three stages.
Accordingly,the·Applicant has prepared al ternative facility designs
and operation studies of a construction plan that permits construction
in three stages:first,construction and operation of a facility at
the Watana site with a dam elevation of 2,025 feet (Stage I);second,
proposed Devil Canyon dam elevation of 1,463 feet (Stage II);and
third,further elevation of the dam at the Watana facility to the 2,205
foot level proposed in the July 1983 License Application (Stage III).
Although the three-stage construction plan will not alter the character
of the fully completed project,staging construction in th~ee steps
will accomplish certain desirable changes over the course of project
development.
The development of Watana to its full height results in concentration
of expenditures in the early years of the Susitna Project.Completion
of Watana Stage I at a 2,025 foot crest elevation would reduce the
initial materials requirements and construction time.The result would
be both a reduction in initial state financial commitments and improved
opportunity for private financing.Moreover,stretching out the pace
of development of project energy and capacity would permit a better
matching of load growth and capacity available,thereby ensuring
greater flexibility in responding to future ra tes of system growth.
851104 B-1-27
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2 -ALTERNATIVE FACILITY DESIGN,PROCESSES AND OPERATIONS (*)
2.1 -Susitna Hydroelectric Development (0)
As originally conceived,the Watana project initially comprised an
earthfill dam with a crest elevation of 2,225 and 400 MW of generating
capacity scheduled to commence operation in 1993.An additional 400 MW
would be brought on line in 1996.At Devil Canyon,an additional 400
MW would be installed to commence operation in the year 2000.Detailed
studies of each project have led to refinement and optimization of
designs in terms of a number of key factors,including updated load
forecasts and economics.Geotechnical and environmental constraints
identified as a result of continuing field work have also greatly
influenced the currently recommended design concepts.
Plan formulation and alternative facility designs considered for the
Watana and Devil Canyon developments are discussed in this section.
Background information on the site charact-eristics as well as addition-
al detail on the plan formulation process are included in the Support-
ing Design Report of Exhibit F and the referenced reports.
2.2 -Watana Project Formulation (*)
This section describes the evolution of the general arrangement of the
Watana-Stages I &III projects which,together with the Devil Canyon
project Stage II,comprises the development plan proposed.The process
by which reservoir operating levels and the installed generating
capacity of the power facilities were established is presented,
together with the means of handling floods expected during construction
and subsequent project operation.
The main components of the Watana development are as follows:
o Dam embankment
o Diversion facilities
o Spillway facilities
o Outlet facilities
o Emergency release facilities
o Power facilities.
A number of alternatives are available for each of these components and
they can be combined in a number of ways.The following paragraphs
describe the various components and methodology for the preliminary,
intermediate,and final screening and review of alternative general
arrangement of the components,together with a brief description of the
selected scheme.This section presents the alternative arrangements
studied for the Watana project.
851104 B-2-1
2.2.1 -Selection of Reservoir Level (0)
The selected elevation of the Watana Dam crest is based on
considerations of the value of the hydroelectric energy
produced from the associated reservoir,geotechnical constraints
on reservoir levels,and freeboard requirements.Firm energy,
average annual energy,construction costs,and operation and
maintenance costs were determined for the Watana development with
dam crest elevations of 2,240,2,190,and 2,140.The relative
value of energy produced in terms of the present worth of the
long-term production costs (LTPWC)for each of these three dam
elevations was determined by means of the OGP5 generation
planning model described in Section 1 of this Exhibit.The
physical constraints imposed on dam height and reservoir
elevation by geotechnical considerations were reviewed and
incorporated into the crest elevation selection process.
Finally,freeboard.requirements .for the Probable Maximum Flood
(PMF)and settlement of the dam after construction or as a result
of seismic activity were taken into account.
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(a)Methodology (0)
Firm and average annual energy produced by the Susitna
development is based on 32 years of hydrological records.
The energy produced was determined by using a multi-reser-
voir simulation of the operation of the Watana and Devil
Canyon reservoirs.A variety of reservoir drawdowns was
examined,an~drawdowns producing the maximum firm energy
consi~tent w~th~!lgin~~.!~l:J:g~fea.~ibilitLandcost of the
intake structure were selected.Minimum floW-requirements
were established at both project sites based on downstream
fisheries considerations.
To meet system demand,the required maximum generating
capability at Watana in the period between 1994 and 2010
ranges from 665 MW to 908 MW.For the reservoir level
determinations,energy estimates were made on the basis of
asslimed·-averageannual··capacity .requi-rementsof-680·····MW··at
...................__..----Wat·ana-in---l-99 4,-increasing·t-o-l-,-020-·MW--at-Wa·t-ana---i-n--20 07-,---·
with an additional 600 MW at Devil Canyon coming on line in
the year 2002.The long term present worth costs of the
generation system required to meet the Railbelt energy
demand were then determined for each of the three crest
elevations of the Watana Dam using the OGP5 model.
The construction cost estimates·usedin the OGP5·mo<:leling
proces sfor··l:heWal:anaand .Devil Canyon proJect sViere based
on preliminary conceptual layouts and construction
schedules.Further refinement of these layouts has taken
place during the optimization process.These refinements
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851104 B-2-2
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have had no significant impact on the reservoir level
selection.
(b)Economic Optimization (*)
Economic optimization of the Watana reservoir level was
based on an evaluation of three dam crest elevations of
2,240, 2,190,and 2,140.These crest elevations applied to
the central portion of the embankment with appropriate
allowances for freeboard and seismic settlement,and
correspond to maximum operating levels of the reservoir of
2,215, 2,165,and 2,115 feet,respectively.Average annual
energy calculated for each case using the reservoir
simulation model are given in Table B.2.2.l,together with
corresponding project construction costs.
In the determination of LTPWC,the Susitna capital costs
were adjusted to include an allowance for interest during
construction and then used as input to the OGP5 model.
Simulated annual energy yields were distributed on a monthly
basis by the reservoir operation model to match as closely
as possible ~~e projected monthly energy demand of the
Railbelt and 'then input to t]:1e QGP5 model.The LTPWC of
meeting the Railbelt energy demand using the Susitna
development as the primary source of energy was then
determined for each of the three reservoir levels.
The results of t~ese evaluations are shown in Table B.2.2.2,
and a plot showing the variation of theLTPWC with dam crest
elevation is shown in Figure B.2.2.1.This figure indicates
that,on the basis of the assumptions used,the minimum
LTPWC occurs at a Watana crest elevation ranging from
approximately 2,160 to 2,200 (reservoir levels 2,140 to
2,180 feet).A higher dam crest will still result in a
development which has an overall net economic benefit
relative to thermal energy sources.However,it is also
clear that,as the height of the Watana Dam is increased,
the unit cost of additional energy produced at Watana is
somewhat greater than for the displaced thermal energy
source.Hence,the LTPWC of the overall system would
increase.Conversely,as the height of the dam is lowered,
and thus Watana produces less energy,the unit cost of the
energy produced by a thermal generation source to replace
the lost Susitna energy is higher than that of Susitna.
In this case also,the LTPWC increases.
851104 B-2-3
I
(c)
(d)
Relict Channel (**)
On the north side of the reservoir created by the Watana
Dam,an infilled relict channel,reaching a depth of 400
feet,exists between the reservoir and Tsusena Creek.A
potential problem caused by the relict channel involves
subsurface seepage resulting in potential downstream piping
and/or loss of wa ter from the reservoir.Details of the
geology and potential impacts of the relict channel are
addressed in Exhibits A and F.In response to these
potential seepage problems,$57,100,000 have been provided
in the cost estimate for the construction of a downstream
toe drain during Stage I and a slurry trench cutoff across
the buried channel thalweg during Stage III.The Stage I
pool (el.2,000)is 185 feet low.er than Stage III (el.
2,18S);therefore minimal remedial measures have been
programmed,including observation device monitoring,during
this period.
Conclusions (0)
tt is important to establish clearly the overall objective
used as a basis for setting the Watana reservoir level.An
objective which would minimize the LTPW energy cost would
lead to selection of a slightly lower reservoir level than
an objective which would maximize the amount of energy which
could be obtained from the available resource,while doing
so with a technically sound project.
, 1
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The three values of LTPWC developed by the OGPS computer
runs defined a relationship betweenLTPWCand Watana Dam
height which is relatively insensitive to dam height.This
is highlighted by the curve ·of LTPWCversus dam height in
Figure B.2.2.1.This figure shows that there is only a
slight variation in the LTPWC for the range of dam heights
included in the analysis.Thus,from an economic
........_.......standpoint.,...the-opt-imum--c.rest--eleva·t·ion-could-becons-idered
___..__..__as_v:a.r~dng._oJl.e.r __a....Iange_.o.:L.eleYations--fr.om-2-,.140-.to.-2-,-220-.
with little effect on project economics.
The normal maximum operating level of the reservoir was
therefore set at elevation 2,185,allowing the objective of
maximizing the economic use of the Susitna resource still to
be satisfied.
I .!
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8S1104 B-2-4
.J
2.2.2 -Selection of Installed Capacity (*)
The generating capacity to be installed at both Watana and Devil
Canyon was determined on the basis of generation planning studies
together with appropriate consideration of the following (Acres
1982c,Vol.1):
o Available firm and average energy from Watana and Devil
Canyon;
o The forecast energy demand and peak load demand of the
system;
o Available firm and average energy from other existing and
committed plant;
o Capital cost and annual operating costs for Watana and
Devil Canyon;
o Capital cost and annual operating costs for alternative
sources of energy and capacity;
o Environmental constraints on reservoir operation;and
o Turbine and generator operating characteristics.
Table B.2.2.3 lists·the design parameters used in establishing
the dependable capacity at Watana.
(a)Installed Capacity (*)
A computer simulation of reservoir operation over 32 years
of hydrological record was used to predict firm (dependable)
and average energy available from Watana and Devil Canyon
reservoirs on a monthly basis.Seven alternative reservoir
operating rules were assumed,varying from a maximum power
generation scenario which would result in significant impact
on downstream fisheries through to a scenario that provides
guaranteed minimum summer releases which minimize the impact
on downstream fisheries.For the preliminary design,
predicted energies from a moderate flow case,referred to as
Case C,have been used to assess the required plant
capacity.
The computer simulation gives an estimate of the monthly
energy available from each reservoir,but the sizing of
the plant capacity must take into account the variation of
demand load throughout each month on an hourly basis.Load
forecast studies have been undertaken to predict the hourly
variation of load through each month of the year and also
851104 B-2-5
the growth in peak load (MW)and annual energy demand (GWh)
through the end of the planning horizon (2010).
The economic analysis for the proposed development assumes
that the average energy from each reservoir is availab Ie
every year.The hydrological record,however,is such that
this average energy is available only from a series of
wetter and drier years.In order to utilize.the average
energy,capacity must be available to generate the energy
available in the wet years up to the maximum requirement
dictated by the system energyciemand,less any energy
available from other committed hydroplants.
Watana has been designed to operate as a peaking station,if
required.Tables B.2.2.4 and B.2.2.S show the estimated
maximum capacity required in the peak demand month
(December)at Watana to fully utilize the energy available
from the flows of record.If no thermal energy is needed
(i.e.,in wetter years),the maximum requirement is
contrplled only.b.¥_the shape of the.demand curve •If
thermal energy is required (in average to dry years),the
maximum capacity required at Watana will depend on whether
the thermal energy is provided by high merit order plant at
base load (Option 1,Table B.2.2.4),or by low merit order
peaking plant (Option 2,Table B.2.2.S).
On the basis of this evaluation,the ultimate power
generation capability at WataGa was selected as 1,020 MW for
cl~sJgIJ,P1.l_l:'PQl:l~~..~o CiUQ~aIIlCil:'g ~J,l JQl:'hYcll:'Q_~pJl1J,li!lgl:'~s~:.rv ~
and standby for forced outage.This installation also
provides a margin in the event that the load growth exceeds
the medium load forecast.
(b)Unit Capacity (*)
Selection of the unit size for a given total capacity is a
compromise between the initial least-cost solution,
---------·····-·-g-en-erallyinvotV'inga-schemewi"t1:1asmaller-ntimberr ·0 f-1 arge
-.-----..--..-.-.c-a-pa-c-i-ty--uni-ts-,-and-the----{-mproved-p-l-an-t--e-fficiency--and---·----
security of operation provided by·a larger number of smaller
capacity units.Other factors include the size of each unit
as a proportion of the total system.load and the minimum
anticipated load on the station.Any requirement for a
minimum downstream flow would also affect the selection.
Growth of the actual -load.demand is-also a significant
factor,since the installationofcunits maybe phased to
......c __mat.ch .t.he-acfua-l-l oad-growEh .---The-numb er-of--tiriiEsaiid lih ei r
individual ratings were determined by the need to deliver
the required peak capacity i.n the.peak demand month of
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851104 B-2-6
J
December at the minimum December reservoir level with the
turbine wicket gates fully open.
An examination was made of the economic impact on power
plant production costs of various combinations of a number
of units and rated capacity which would provide the selected
total capacity of 1,020 MW.For any given installed
capacity,plant efficiency increases as the number of units
increases.The assumed capitalized value used in this
evaluation was $1.00 per average annual kWh over project
life,based on the economic analysis completed for the
thermal generation system.Variations in the number of
units and capacity will affect the cost of the power
intakes,penstocks,powerhouse,and tailrace.The
differences in the~e capital costs were estimated and
included in the evaluation.The results of this analysis
are presented below.
Capitalized
Rated Value of
Number Capacity Additional Additional
of of .Unit Energy Capital Cost Net Benefi t
Units (MW)($Millions)($Millions)($Millions)
4 250
6 170 40 31 9
8 125 56 58 -8
It is apparent from this analysis that a six-unit scheme
with a net benefit of approximately $9 million is the most
economic alternative.This scheme also offers a higher
degree of flexibility and security of operation compared to
the four-unit alternative,as well as advantages .if unit
installation is phased to match actual load growth.The
net economic benefit of the six-unit scheme is $17 million
greater than that of the eight-unit scheme,while at the
same time no significant operational or scheduling
advantages are associated with the eight-unit scheme.
A scheme incorporating six units,each with a rated capacity
of 170 MW,for a total of 1,020 MW,has been adopted for all
Watana alternatives.
2.2.3 -Selection of the Spillway Design Flood (*)
Normal design practice for projects of this magnitude,together
with applicable design regulations,requires that the project be
capable of passing the Probable Maximum Flood (PMF)routed
through the reservoir without endangering the dam.
.::
851104 B-2-7
In addition to this requirement,the project should have
sufficient spillway capacity to safely pass a major flood of
lesser magnitude than the PMF without damaging the main dam or
ancillary structures.The frequency of occurrence of this flood,
known as the spillway design flood or Standard Project Flood
(SPF),is generally selected on the basis of an evaluation of the
risks to the project if the spillway design flood is exceeded,
compared to the costs of the structures required to safely
discharge the flood.For this study,a spillway design flood
with a return frequency of 1:10,000 years was selected for
Watana.A list of spillway design flood frequencies and
magnitudes for several major projects is presented below.
Additional capacity required to pass the PMF be provided by
"an emergen'cy 'spillwayconsis'fing"of"'afuse'p[ug'aiid rOCK channel
on the right bank.
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]
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1
.1
1
Inflow Peak
326,000 cfs
1$6,000 cfs
B-2-8
1:10,000 years
Frequency
Probable Maximum
Spillway Design
Flood
851104
I I
Spillway
Spillw9-Y Design Flood I Basin ..I Capacity
I Peak I EMF"IAfter Routing
Project Frequency l!nfleM'(cfs)I (cfs)1 (cfs)*
I I I
Mica,Canada :EMf 1 250,000 1 250,000'1 150,000
I 1 I
Churchill'Falls,I 1 I
Canada 1:10,000 1 600,000 11,000,000 I 230,000
I I I
New Bullards,USA EMF I 226,000 I 226,000 I 170,000
I I I
Oroville,USA 1:10,000 I 440,500 I 711,400 I 440,500
I I I
- - --~-~------_._---_.....•.__.--Gui:i,Venezuela'
(final stage)PMF I 1,000,000 11,000,000 1,000,000
I I I
Itaip.1,Brazil EMF 1 2,195,000 12,195,000 I 2,105,000
I 1 I
Sayano,USSR 1:10,000 I 480,000 1 N/A 1 680,000
*All spillways except Sayano have capacity to pass PMF with
2.2.4 Main Dam Alternatives (*)
This section describes the alternative types of dams considered
at the Watana site and the basis for the selected alternative.
(a)Comparison of Embankment and Concrete Type Dams (0)
The selection between an embankment type or a concrete
type dam is usually based on the configuration of the
valley,the condition of the foundation rock,depth of the
overburden,and the relative availability of construction
materials.Previous studies by the CaE envisaged an
embankment dam at Watana.Initial studies completed as part
of this current evaluation included comparison of an
earthfi11 dam with a concrete arch dam at the Watana site.
An arrangement for·a concrete arch.dam alternative at Watana
is presented in Figure B.2.2.2.The results of this
analysis indicated that the cost of the embankment dam was
somewhat lower than.the arch dam,even though the concrete
cost rates used were significantly lower than those used for
the Devil Canyon Dam.This preliminary evaluation did not
indicate any overall cost savings in the project in spite of
some savings in the earthworks and concrete structures for
the concrete dam layout.A review of the overall
construction schedule indicated a minimal savings in time
for the concrete dam project.
Based on the above and the likelihood that the cost of the
arch dam would increase relative to that of the embankment
dam,the arch dam alternative was eliminated from further
considera tion.
j
851104
(b)Concrete Face·Rockfi11 Type Dam (*)
The selection of a concrete facerockfill dam.at Watana
would appear to offer economic and schedule advantages when
compared ~o a conventional impervious-core rockfi11 dam.
For example,one of the primary areas of concern with the
earth-core rockfill dam is the control of wa ter content for
the core material and the available construction period
during each summer.The core material will have to be
protected against frost penetration at the end of each
season and the area cleared and prepared to receive new
material after each winter.On the other hand,rockfi11
materials can be worked almost year-round and the quarrying
and placing/compacting operations are not affected by rain
a~d only marginally by winter weather.
The.eoncrete face rockfi11 dam would also require less
------foundation preparation,since the critical foundation
contact area is much less than that for the impervious-
B-2-9
core/rock foundation contact.The side slopes for faced
rockfill could probably be on the order of 1.5H:1V·or
steeper as compared to the 2.5 and 2.0H:1V for the
earth:"core rockfill.This would allow greater flexibility
for layout of the other facilities,in particular the
upstream and downstream portals of the diversion tunnels and
the tailrace tunnel portals.The diversion tunnels could be
shorter,giving further savings in cost and schedule.
However,the ultimate heightdf theWatafla Dam as currently
proposed is 885 feet,some 70 percent higher 'than the
highest concrete face rockfill dam buil tto date (the
525-foot high Areia Dam in Brazil completed in 1980).A
review of concrete face rockfill dams indicates that
increases in height have been typically in the range of 20
percent;for example,Paradela -370 feet completed in 1955;
Alto Anchicaya -460 feet completed in 1974;Ar,eia -525
feet completed in 1980.Although recent compacted rockfill
dams have generally performed well and a rockfill dam is
inherently stable even with severe leakage through the face,
a one-step increase in height of 70 percent over existing
structures is well beyond precedent.
In addition to the height of the dam,other factors which
are beyond precedent include the seismic and climatic
conditions at Susitna.It has been stated that concrete
face rockfill dams are well able to resist earthquake forces
and it is admitted that they are very stable structures in
th~ml!~lv.§~•__lloweYE:!!",__moyemE:!l1J:oJ~:t"Q.c::~_'l~ad:i.-l1g~9 .fl:lUllre of
the face slab near the base of the dam could resul t in
excessive leakage through the dam.To correct such an
occurrence would require lowering the water level in the
reservoir which would take many years and involve severe
economic penalties from loss of generating ci:lpacity.
No concrete face rockfill daIll has yet been built in an
arctic environment.The drawdown at Watana is in excess of
...------------------lOO'·-fe-~fta1:ia-tne-upJ.:j'e-i:'---sEn::t-i:'()n-of-the-fa-ce--sl-a;b .wi:'ll--be
-.-subjec-ted--to--severefreeze-!-thaw-cy c-J:es.-
Although the faced rockfill dam appears to offer schedule
advantages,the overall gain in impoundment schedule would
not be so significant.With the earth-core rockfill dam,
impoundment can be allowed as the dam is constructed.This
is not the case for a concrete face rockfill since the
concrete face slab is normally not constructed until all
'rockfill has beenpraced'ai:id'Corisfr~ucfioi:isettlement has
taken place.The slab is then poured in continuous strips
from the foundation to the crest.Most recent high faced
rock-fill dams also incorporate an impervious earth fill
cover over the lower section to minimize the risk of
,]
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851104 B-2-10
)excessive leakage through zones which,because of their
depth below normal water level,are difficult to repair.
Such a zone at Watana might cover the lower 200 to 300 feet
of the slab and require considerable volumes of impervious
fill,none of which could be placed until all other
construction work had been completed.This work would be on
the critical path with respect to impoundment and,at the
same time,be subject to interference by wet weather.
The two types of dam were not cos ted in detail because cost
was not considered to be a controlling factor.It is of
interest to note,however,that similar alternatives were
estimated for the LG 2 project in northern Quebec and the
concrete face alternative was estimated to be about 5
percent cheaper.-However,the managers,on the recommenda-
tion of their consultants~decided against the use of a
concrete face rockfill dam for the required height of 500
feet in that environment.
In summary,a concrete face rockfill dam at Wal:ana is not
considered appropriate as a firm recommendation for the
feasibility stage of development of the Susitna project
because of:
o the 70 percent increase ~n height over precedent;and
o the possible impacts of high seismicity and climatic
conditions.
(c)Selection of Dam Type (*)
Selection of the configuration of the embankment dam cross
section was undertaken within the context of the following
basic considerations:
o The availability of suitable construction materials
within economic haul distance,particularly core
material;
o The requirement that the dam be capable of
withstanding the effects of a significant earthquake
shock as well as the static loads imposed by the
reservoir and by its own weight;
o The relatively limited construction season available
for placement of compacted fill materials.
The dam would consist of a compacted core protected by fine
and coarse filter zones on both the upstream and downstream
slopes of the core.The upstream and downstream outer
supporting fill zones would contain relatively free draining
851104 B-2-11
851104
compa.cted gravel or rockfill,providing stability to the
overall embankment structure.The location and inclination
of the core are fundamental to the design of the embankment.
Two basic alternatives exist in this regard:
o A vertical core located centrally within the dam;and
o An inclined core with both faces sloping upstream.
A central vertical core was chosen for the embankment based
on a review of precedent design and the nature of the
available impervious mate.rial.
The exploration program undertaken during 1980-81 indicated
that adequate quantities of materials suitable for dam
construction were located within rea:sonable haul distances
from the site.The 'well-graded silty sand material is
considered the most promising source of impervious fill.
Compaction tests indicate a natural moisture content
slightly on the wet side of optimum moisture content,so
thai control of moisture contintwill be critical in
"achfeving a dense""core with 'high "shear strength.
Potential sources for the upstream and downstream shells
include either river gravel·from borrow areas along the
Susitna River or compacted rockfill from quarries or
excavations for spillways.
During the"intermediate review process·,··the upstream slope
of the dam was flattened from 2.5H:IV used during the
initial review to ~.75H:IV.This slope was based on a
conservative estimate of the effective shear strength
paramet'ers of the available construction materials,as well
as a conservative allowance in the design for the effects of
earthquake loadings on the dam •
....D~l:"iggt:J:J,~.fim3.J.l:"~.Yi?w:,§lt:.~g?,.t:1:1E:!.?~l:E:!l:"i.()l:"t:!P§ltl:"E:!gI:D."§lJQPg
of the dam was steepened from 2.75H:IV to 2.4H:IV,
reflecting-the··resul ts of thepre"timfnarystaticand-dy-namic
design analyses being undertaken at the same time as the
general arrangement studies.As part of the final review,
the volume of the dam with an upstream slope of 2.4H:IV was
computed for four alternative dam axes.The locations of
these alternative axes are shown on Figure B.2.2.3.The dam
..voltuneassoclated with each of the~four alternative axes islistedbelow:·:····"
I ]
I
1
,1
,']
Alternative
Axis Number
1
2
3
4
Total Volume
(million yd 3 )
69.2
71.7
69.3
71.9
A section with a 2.4H:1V upstream slope and a 2H:lV
downstream slope located on alternative axis number 3 was
used for the final review of alternative schemes.
2.2.5 Diversion Scheme Alternatives (*)
The topography of the site generally dictates that diversion of
the river during construction be accomplished using diver.sion
tunnels with upstream and downstream cofferdams protecting the
main construction area.
The configuration of the river in the vicinity of the site favors
location of·the diversion tunnels on the north bank,since the
tunnel length for a tunnel on the south bank would be
approximately 2,000 feet greater.In addition,rock conditions
on the north bank are more favorable for tunneling and excavation
of intake and outlet portals.
(a)Design Flood for Diversion (*)
The recurrence interval of the design flood for diversion is
generally established based on the characteristics of the
flow regime of the river,the length of the construction
period for which diversion is required and the probable
consequences of overtopping of the cofferdams.Design crit-
eria and experience from other projects similar in scope and
nature have been used in selecting the diversion design
flood.
At Watana,damage to the partially completed dam could be
significant or,more importantly,would probably result in
at least a one-year delay in the completion schedule.A
preliminary evaluation of the construction schedule
indicates that the diversion scheme would be required for
four or five years until the dam is of sufficient height to
permit initial filling of the reservoir.A design flood
with a return frequency of 1:50 years was selected based on
experience and practice with other major hydroelectric
projects.This approximates a 90 percent probability that
the cofferdam will not be overtopped during the five-year
construction period.The diversion design flood together
with average flow characteristics of the river significant
to diversion are presented below:
851104 B-2-13
o Average annual flow
o Maximum average monthly flow
o Minimum average monthly flow
o Design flood inflow (1:50 years)
7,990 cfs
42,800 cfs-(June)
570 cfs (March)
87,000 cfs
I]
1
(b)
(c)
Cofferdams (*)
For the purposes of establishing the overall general
arrangement of the project and for subsequent diversion
optimization studies,the upstream cofferdam section adopted
comprises an embankment structure approximately 100 feet
high placed in the dry.
Diversion Tunnels (*)
Concrete...lined tunnels and unlined rock tunnels were
compared.Preliminary hydraulic studies indicated that
the design flood routed through the diversion scheme would
result in a design discharge of approximately 80,500 cfs.
For conctete-linedtunnels,design velocities on the order
of 50 ft/sec have been used in several projects.For
unlined tunnels,maximum design velocities ranging from 10
ft/sec in good quality rock to 4 ft/sec in less competent
material are typical.Thus,the volume of material to be
excavated using an unlined tunnel would be at least 5 times
that for a lined tunnel.The reliability of an unlined
tunnel is more dependent on rock conditions than is a lined
tunnel,particularly given the extended period during which
-t-he-d-ivers-i-on--scheme--i-s-requir ed--to--operate.~""Based-on -these
considerations,given a considerably higher cost,together
with the somewhat questionable feasibility of four unlined
tunnels with diameters approaching 50 feet in this type of
rock,the unlined tunnels have been eliminated.
The following alternative lined tunnel schemes were examined
as part of this analysis.
o Pressure tunnel with a free outlet
o Pressure tunnel with a submerged outlet
o Free flow tunnel
]
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:-)
)
(d)Emergency Release Facilities (*)
The emergency release facilities influenced the number,
-type ,andarrangement-ofthediver-sion--tunnels selected for
the final scheme.
At an early stage of the study,it was established that some
form of low-level release facility was required to meet
instream flow requirements during filling of the reservoir,
and to permit lowering of the reservoir in the event of an
851104 B-2-14
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I
extreme emergency.The most economical alternative
available would involve converting one of the diversion
tunnels to permanent use as a low-level outlet facility.
Since it would be necessary to maintain the diversion scheme
in service during construction of the emergency facilities
outlet works,two or more diversion tunnels would be
required.The use of two diversion tunnels also provides an
additional measure of security to the diversion scheme in
case of the loss of service of one tunnel.
The low-level release facilities will be operated for
approximately three years during filling of the reservoir.
Discharge at high heads usually requires some form of energy
dissipation prior to returning the flow to the river.Given
the space restrictions imposed by the size of the diversion
tunnel,it was decided to utilize a double expansion system
constructed within the upper tunnel.
(e)Optimization of Diversion Scheme (*)
Given the considerations described above relative to
design flows,cofferdam configuration,and alternative
types of tunnels,an economic study was undertaken to
determine the optimum combination of upstream cofferdam
height and tunnel diameter.
Capital costs were developed for three heights of upstream
cofferdam embankment with a 30-foot wide crest and exterior
slopes of 2H:1V.A freeboard allowance of 5 feet for
settlement and wave runup and 10 feet for the effects of
downstream ice jamming on tailwater elevations was adopted.
Capital costs for the 4,700-foot long tunnel alternatives
included allowances for excavation,concrete liner,rock
bolts,and steel supports.Costs were also developed for
the upstream and downstream portals,including excavation
and support.The cost of intake gate structures and
associated gates was determined not to vary significantly
with tunnel diameter and was excluded from the analysis.
Curves of headwater elevation versus tunnel diameter for the
various tunnel alternatives with submerged and free outlets
are presented in Figure B.2.2.4.The relationship between
capital cost and crest elevation for the upstream cofferdam
is shown in Figure B.2.2.5.The capital cost for various
tunnel diameters with free and submerged outlets is given in
Figure B.2.2.6.The results of the optimization study are
presented in Figure B.2.2.7 and indicate the following
optimum solutions for each alternative.
851104 B-2-l5
I..
The cost studies indicate that a rel'atively small cost
differential (~to 5 percent)separates the various
alternatives for tunnel diameter from 30 to 35 feet.
'!Wo free flow tunnels 32.5
Two pressure tunnels 30
69,000,000
66,000,000
68,000,000
1,595
1,555
1,580
Cofferdam Crest
Elevation (ft)Total Cost ($)
35
Diameter
Type of Tunnel (feet)
'!Wo free flow turmels
(f)Selected Diversion Scheme (*)
An important consideration at this point is ease of
cofferdam closure.For the pressure tunnel scheme,the
invert of the tunnel entrance is below riverbed elevation,
and once the tunnel is complete diversion can be
accomplished with a closure dam section approximately 10
feel::high •The free flow tlinnel scheme-,howeVer,requires a
tunnel invert approximately 30 feet above the riverbed
level,and diversion would~involve an end-dumped closure
section 50 feet high.The velocities of flows which would
overtop the cQfferdam before the water levels were raised to
reach the tunnel invert level would be prohibitively higher,
resulting in complete erosion of·the c~fferdam,and hence
~···t1fe-d ua1~free ··f1ow~tun~ne l~;"scheme~cwa~s·d:ropp~e~d·'from
consideration.
Based on the preceding considerations,a combination of one
pressure tunnel and one free flow tunnel (or pressure tunnel
with free outlet)was adopted.This will permit initial
diversion to be made using both tunnels,thereby simplifying
the critical closure operation and avoiding potentially
............serious..delay.sinthe.schedule •.ThreeaLternati:v.es.-were ..
..........~_:r:.e.'::.eyal1la.t.e~.a.Lf.Q.LLows:__..__._~_._~..___.........._.
Tunnel
Diameter
(feet)
Upstream
Crest
Elevation
(feet)
Cofferdam
Approximate
Height
(feet)
30
35
36
··1595
1555-
1550
150··
·flO
100 'J
More detailed layout studies indicated that the higher
cofferdam associated with the 30-foot diameter tunnel
851104 B-2-16
alternative would require locating the inlet portal further
upstream into "The Fins"shear zone.Since good rock
conditions for portal construction are essential and the
36-foot diameter tunnel alternative would permit a portal
location downstream of "The Fins",this latter alternative
was adopted.As noted in (e),the overall cost difference
was not significant in the range of tunnel diameters
considered,and the scheme incorporating two 36-foot
diameter tunnels with an upstream cofferdam crest elevation
of 1,550 was incorporated as part of the selected general
arrangement.
2.2.6 Spillway Facilities Alternatives (*)
As discussed in subsection 2.2.3 above,.the project has been
designed to safely pass floods with the following return
frequencies:
..:
Flood
Spillway Design
Probable Maximum
Frequency
1:10,000 years
Inflow
Peak (cfs)
156,000
326,000
Total Spillway
Discharge (cfs)
120,000
150,000
Discharge of the spillway design flood will require a gated
service spillway on either the left or right bank.Three basic
alternative spillway types were examined:
o Chute spillway with flip bucket
o Chute spillway with stilling basin
o Cascade spillway.
Consideration was also given to combinations of these
alternatives with or without supplemental facilities such as
valved tunnels and an emergency spillway fuse plug for handling
the PMF discharge.
Clearly,the selected alternative utilizing one serv~ce spillway
will greatly influence and be influenced by the project general
arrangement.
(a)Energy Dissipation (*)
The two chute alternatives considered achieve effective
energy dissipation either by means of a flip bucket which
would direct the spillway discharge in the form of a
free-fall jet into a plunge pool well downstream from the
dam or a stilling basin at the end of the chute which would
dissipate energy in a hydraulic jump.The cascade type
spillway would limit the free-fall height of the discharge
851104 B-2-17
by utilizing a series of 20-to50-fpot steps down to river
level,with energy dissipation at each step.
All spillway alternatives were assumed to incorporate a
concrete ogee type control section controlled by fixed-
roller vertical lift gates.Chute spillway sections were
assumed to be concret~-lined,with ample provision for air
entrainment in the chute to prevent cavitation erosion,and
with pressure relief drains and rock anchors in the
foundation.
(b)Environmental Mitigation (*)
During development of the general arrangements for both the
Watana and Devil Canyon Dams,a restriction was imposed on
the amount of excess dissolved nitrogen permitted in the
spillway discharges.Supersaturation oceurs when aerated,
flows are subjected to pressures greater than 30 to 40 feet
of head which forces excess nitrogen into solution.This
occurs when wa;er is subj~cted to the high pressures that
occur in'deepplunge pools or at large hydraulic jumps.The
excess nitrogen would not be dissipated within the
dowtlstreaIlfDevil Caiiyou'reSfervoif'and a DU:iTdiip of ni tfogeri
concentration could occur throughout the body of water.It
would eventually be discharged downstream from Devil Canyon
with harmful effects on the fish population.On the basis
of an evaluation of the related impacts and discussions with
interested federal arid state agencies,spillway facilities
were designed to limit discharges of water from either
Wa:tana()r-Devil·~Ca:ny()ri-··thae-m·a:yc·b·e-cofuE:!~S\i:I;feysa:·tilratedwith ,.
nitrogen to a recurrence period of not less than 1:50
years.
2.2.7 -Power FaciUtie§.Alte:rnatives (*)
Selection of the optimum power plant development involved
consideration of the following:
o Geotechnical considerations
o Number,type,size and setting of generating units
o.Arrangement of intake and water passages
o Environmental constraints..'_"''._"_",','_4"_'__,_,_,_'_______'_'__'__'_'_'.w··,~••"••._••._.,,__·_,_
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,1
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).
I
I
851104 B-2-18 .J
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(a)Comparison of Surface and Underground Powerhouse (*)
Studies were carried out to compare the construction costs
of a surface powerhouse and of an underground powerhouse at
Watana.These studies were undertaken on the basis of
preliminary conce~tual layouts assuming four or six units
and a total installed capacity of 840 MW.The comparative
cost estimates for powerhouse civil works and electrical and
mechanical equipment (excluding common items)indicated an
advantage in favor of the underground powerhouse of
$16,300,000.A summary comparison of the cost estimates for
the two types of powerhouses is in Table B.2.2.6.The
additional cost for the surface powerhouse arrangement is
primarily associated with the longer penstocks and the steel
linings required.
The underground powerhouse arrangement is also better suited
to the severe winter conditions in Alaska,is less affected
by river flood flows in summer,.and is aesthetically less
obtrusive.This arrangement has ..the1i.",efore been adopted for
further development.
(b)Comparison of Alternative Locations (*)
Preliminary studies were undertaken during the development
of conceptual project layouts at Watana to investigate both
right and left bank locations for power facilities.The
configuration of the site is ,such that south bank locations
required longer penstock and/or tailrace tunnels and were
therefore more expensive.
The location on the south bank was further rejected because
of indications that the underground facilities would be
located in relatively poor quality rock.The underground
powerhouse was therefore located on the north bank such that
the major openings lay between the two major shear features
("The Fins"and the "Fingerbuster").
(c)Underground Openings (*)
Because no construction adits or extensive drilling in the
powerhouse and tunnel locations have been completed,it has
been assumed that full concrete-lining of the penstocks and
tailrace tunnels would be req.uired.This assumption is
conservative and is for preliminary design only;in
practice,a large proportion of the tailrace tunnels would
probably be unlined,depending on the actual rock quality
encountered.
851104 B-2-l9
The minimum center-to-center spacing of rock tunnels and
caverns has been assumed for layout studies to be 2.5 times
the width or diameter of the larger excavation.
(d)Selection of Turbines (*)
The selection of turbine type is governed by the available
head and flow.For the design head and specific speed,
Francis type turbines have been selected.Francis turbines
have a reasonably flat load-efficiency curve over a range
from about 50 percent to 115 percent of rated output with
peak efficiency of about 92 percent.
The number and rating of individual units is discussed in
detail in subsection 2.2.2 above.The final selected
arrangement comprises six units producing 170 MW each,rated
at minimum reservoir level (from reservoir simulation
studies)in the peak demand month (December)at full gate.
The unit output at best efficiency and a rated head of 680
feet is 181 MW.
(e)Transformers (*)
The selection of transformer type,size,location and stepup
rating is summarized below:
o Single-phase transformers are required because of
transport limitations on Alaskan roads and railways;
o Direct transformation from 15 kV to 345 kV is
preferred for overall system transient stability;
o An underground transformer gallery has been selected
for minimum total cost of transformers,cables,bus,
and transformer losses;and
o A grouped arrangement of three sets of three
f:fingre;;;;pliase''fransfOrmers fOr'····e'acli·setOftwOiiiiifs
h'a's'-b'e-en--s-e-tec't-e-d'-(-ato't-a-t-of-nine---t'ran-EffcH:mer's-)-tcf""
reduce the physical size of the transformer gallery
and to provide a transformer spacing comparable with
the unit spacing.
,I
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851104 B-2-20
i,j
(f)Power Intake and Water Passages (*)
The power intake and approach channel are significant
items in the cost of the overall power facilities
arrangement.The size of the intake is controlled by the
number and minimum spacing betw~en the penstocks,which in
turn is dictated by geotechnical considerations.
The preferred penstock arrangement comprises six individual
penstocks,one for each turbine.With this arrangement,no
inlet valve is required in the powerhouse since turbine
dewatering can be performed by closing the cantrolgate at
the intake and qraining the penstocks and scroll case
through a valved bypass to the tailrace.An alternative
arrangement with three penstocks was considered in detail to
assess any possible advantages.This scheme would require a
bifurcation and two inlet valves on each penstock and extra
space in the powerhouse to accommodate the inlet valves.
Estimates of relative cost differences are summarized
below:
Item
Cost Difference ($x 106)
6 Penstocks 3 Penstocks
Total
Intake
Penstocks
Bifurcations
Valves
Powerhouse
Capitalized Value of
Extra Head Loss
Base Case
o
o
o
o
o
o
-20.0
-3.0
+3.0
+4.0
+8.0
+6.0
-2.0
851104
Despite a marginal saving of $2 million (or less than 2
percent in a total estimated cost of $120 million)in favor
of three penstocks,the arrangement of six individual
penstocks has been retained.This arrangement provides
improved flexibility and security of operation.
The preliminary design of the power facilities involves two
tailrace tunnels leading from a common surge chamber.An
alternative arrangement with a single tailrace tunnel was
adopted to achieve significant cost saving.
Optimization studies on all water passages were carried out
to determine the minimum total cost of initial construction
plus the capitalized value of anticipated energy losses
caused by conduit friction,bends and changes of section.
For the penstock optimization,the construction costs of the
B-2-2l
intake and approach channel were included as a function of
the penstock diameter and spacing.Similarly,in the
optimization studies for the tailrace tunnel the costs of
the surge chamber were included as a function of tailrace
tunnel diameter.
(g)Environmental Constraints (*)
Apart from the potential nitrogen supersaturation problem
discussed,the major environmental constraints on the design
of the power facilities are:
o Control of downstream river temperatures,and
o Control of downstream flows.
The intake design has been modified to enable power plant
flows to be drawn from the reservoir at_four different
levels throughout the anticipated range of reservoir
drawdown for energy production in order to control the
downstream river temperatures within acceptable limits.
Minimum flows at Gold Creek during the critical summer
months have been studied to mitigate the project impacts on
salmon spawning downstream of Devil Canyon.These minimum
flows represent a constraint on the reservoir operation and
influence the computation of average and firm energy
produced by the Susitna development.
of Watana General Arrangement (0)
Preliminary alternative arrangements of the Watana project were devel-
oped and subjected to a series of review and screening processes.
The layouts selected from each screening process were developed in
greater detail prior to the next review and,where necessary,
additional layouts were prepared combining the features of two or more
of the alternatives.Assumptions and criteria were evaluated at each
····stage··and·additionaldata-incorporated--as·neces·sary~--····The selection··
......··_·_pI'-OC ess--·f.ol-1owed-~he--gene·t'-a-l-se-l-ec·t-ion-me·l;;hodo-l-ogy-~est·ab-H-shed-forthe-.
Susitna project and is outlined below.
2.3.1 -Selection Methodology (*)
The determination of the project general arrangement at Watana
was undertaken in three distinct review stages:preliminary,
·intermediate ,and finaL
1
851104 B-2-22
]
(a)Preliminary Review (completed early in 1981)(*)
This comprised four steps:
Step 1:Assemble available data,determine design criteria,
and establish evaluation criteria.
Step 2:Develop preliminary layouts and design criteria
based on the above data including all plausible
alternatives for the constituent facilities and
structures.
Step 3:Review all layouts on the basis of technical
feasibility,readily apparent cost differences,
safety,and environmental impact.
Step 4:Select those layouts that can be identified as most
favorable,based on the evaluation criteria
established in Step 1,and taking into account the
preliminary nature of the work at this stage.
(b)Intermediate Review (completed by mid-198l)(*)
This involved a series of five steps:
Step 1:Review all data,incorporating additional data
from other work tasks.
Review and expand design criteria to a greater
level of detail.
Review evaluation criteria and modify,if
necessary.
Step 2:Revise selected layouts on basis of the revised
criteria and additional data.Prepare plans and
principal sections of layouts.
Step 3:Prepare quantity estimates for major structures
based on drawings prepared under Step 2.
Develop a preliminary construction schedule to
evaluate whether or not the selected layout will
allow completion of the project within the required
time frame.
851104 B-2-23
Prepare a preliminary contractor's type estimate to
determine the overall cost of each scheme.
Step 4:Review all layouts on the basis of technical
feasibility,cost impact of possible unknown
conditions and uncertainty of assumptions,safety,
and environmental impact.
Step 5:Select the two most favorable layouts based on the
evaluation criteria determined under Step 1.
(c)Final Review (completed early in 1982)(*)
Step 1:Assemble and review any additional data from other
work tasks.
Revise design criteria in accordance with
additional available data.
Finalize overall~valuation criteria.
Step 2:
Step 3:
Revise or further develop the two.layouts on the
basis of input from-Step -Tand--determine overall
dimensions of structures,water passages,gates,
and other key item~.
Prepare quantity take-offs for all major
structures •
.RevIew-----c.o.st c·omp·oiient-s wiE1il n a·iireIIiDf-iiiir"y
contractor's type estimate using the most recent
data and criteria,and develop a construction
schedule.
Determine overall direct cost of schemes.
j
Step 4:Review all layouts on the basis of practicability,
...............---......-.technical feasibility,···cost-,·-impact-ofpossible
-.-----'-unknot'1:n-condi-t-i-ons-,-sa-fet~T-and-en:v-i.ronmenta!···
impact.
Step 5:Select the final layout on the basis of the
evaluation criteria developed under Step 1.
2.3.2 -DesigIl pata,and Criteria(*)
AS diScusSed above,the review process includeda.ssembling
relevant design data,establishing preliminary design criteria,
851104 B-2-24
]
and expanding and refining these data during the intermediate and
final reviews of the project arrangement.The design data and
design criteria which evolved through the final review are
presented in Table B.2.3.l.
2.3.3 -Evaluation Criteria (*)
The various layouts were evaluated at each stage of the review
process on the basis of the criteria summarized in Table
B.2.3.2.These criteria illustrate the progressively more
detailed evaluation process leading to the final selected
arrangement.
2.3.4 -Preliminary Review (*)
The development selection studies (Acres 1982c,Vol.1;Acres
1981)involved comparisons of hydroelectric schemes at a number
of sites on the Susitna River.As part of thase comparisons a
preliminary conceptual design was developed for Watana
incorporating a double stilling basin type spillway.
Eight further layouts were subsequently prepared and examined for
the Watana project during this preliminary review process in
review process in addition to the scheme shown on Figure B.l.3.4
These eight layouts are shown in schematic form on Figure
B.2.3.1.Alternative 1 of these layouts was the scheme
recommended for further study.
This section describes the preliminary rev~ew undertaken of
alternative Watana layouts.
(a)Basis of Comparison of Alternatives (*)
Although it was recognized that prov~s~on would have to be
made for downstream releases of water during filling of
the reservoir and for emergency reservoir drawdown,these
features were not incorporated in these preliminary layouts.
These facilities would either be interconnected with the
diversion tunnels or be provided for separately.Since the
system selected would be similar for all layouts with
minimal cost differences and little impact on other
structures,it was decided to exclude these facilities from
overall assessment at this early stage.
Ongoing geotechnical explorations had identified the two
major shear zones crossing the Susitna River and running
roughly parallel in the northwest direction.These zones
enclose a stretch of watercourse approximately 4,500 feet in
length.Preliminary evaluation of the existing geological
data indicated highly fractured and altered materials within
.:
851104 B-2-25
851104
(b)
the actual shear zones which would pose serious problems for
conventional tunneling methbds and would be unsuitable for
fbunding of massive concrete structures.The originally
proposed dam axis was located between these shear zones;
since no apparent major advantage appeared to be gained from
large changes in the dam location,layouts generally were
kept with~n the confines of these bounding zones.
An earth and rockfill dam was used as the basis for all
layouts.The downstream slope of the dam was assumed as
2H:lV in all alternatives,and upstream slopes varying
between 2.5H:lV and 2.25H:lV were examined in order to
determine the influence of variance in the dam slope on the
congestion of the layout.In all preliminary arrangements
except the one shown on Figure B.l.3.4,cofferdams were
incorporated within the body of-the main dam.
Floods greater than the routed l:lO,OOO-year spillway design
flood and up to the probable maximum flood were assumed to
be passed by surcharging the spillways,except in cases
where an unlined cascade or stilling basin type spillway
served as the sole discharge facility.In such instances ,
under large surcharges,these spillways would not act as
efficient energy dissipators but would be drowned out,
acting as steep open channels with the possibility of their
total destruction.In order to avoid such an occ urrence,
the design flood for these latter spillways was considered
as the routed probable 'maximum flood.
On the basis of information existing at the time of the
preliminary review,it appeared th~t an underground
powerhouse could be loca ted on either side of the river.A
surface powerhouse on the north bank appeared feasible but
was precludec!from the south bank by the close proximity of
the downstream toe of the dam and the adjacent broad shear
zone.Locating the powerhouse further downstream would
___~~.qE.~_;'~__t tJ!1.~~JJ.!1:g_.~£;'2.~1!...th ~_.~h_~~t::_,~g.!1:~,.._~.h!i:J1l\f2.u.1c:l .....l:l~_,
expensive and would require excavating a talus slope.
Furthermore,it was found that a south bank surface
powerhouse would either interfere with a south bank spillway
or would be directly impacted by discharges from a north
bank spillway.
Description of Alternatives (*)
(I)DoublELStiUing Basin Scheme (*)
The scheme as shown on Figur~B.l.3.4 has a dam axis
location similar to that originally proposed by the
B-2-26
l
.'
J
,J
851104
COE,and a north bank double stilling basin spillway.
The spillway follows the shortest line to the river,
avoiding interference with the dam and discharging
downstream almost parallel to the flow into the
center of the river.A substantial amount of
excavation is required for the chute and stilling
basins,although most of this material could probably
be used in the dam.A large volume of concrete is
also required for this type of spillway,resulting in
a spillway system that would be very costly.The
maximum head dissipated within each stilling basin is
approximately 450 feet.Within world experience,
cavitation and erosion of the chute and basins should
not be a problem if the structures are properly
designed.Extensive erosion downstream would·not be
expected.
The diversion follows the shortest route,cutting the
bend of the river on the north bank,and has inlet
portals as far upstream as possible without having to
tunnel through "The Fins."It is possible that the
underground powerhouse is in the area of "The
Fingerbuster,"but the powerhouse could be located
upstream almo.s.t as far as the system of drain holes
and galleries just downstream of the main dam grout
curtain.
(ii)Alternative 1 (*)
This alternative (Figure B.2.3.l)is recommended for
further study and is similar to the layout
described above except that the north side of the dam
has been rotated clockwise,the axis relocated
upstream,and the spillway changed to a chute and
flip bucket.The revised dam alignment resulted in a
slight reduction in total dam volume compared to the
above alternative.A localized downstream curve was
introduced in the dam close to the north abutment in
order to reduce the length of the spillway.The
alignment of the spillway is almost parallel to the
downstream section of the river and it discharges
into a pre-excavated plunge pool in the river
approximately 800 feet downstream from the flip
bucket.This type of spillway should be considerably
less costly than one incorporating a stilling basin,
provided that excessive pre-excavation of bedrock
within the plunge pool area is not required.Careful
design of the bucket will be required,however,to
prevent excessive erosion downstream,causing
undermining of the valley sides and/or buildup of
B-2-27
material downstream which could cause elevation of
the tailwater levels.
(iii)Alternatives 2 through 2D (*)
Alternative 2 consists of a south bank cascade
spillway with the main dam axis curving downstream
at the abutments.The cascade spillway would require
an extremely large volume of rock excavation,but it
is probable that most of this material,with careful
scheduling,could be used in the dam.The excavation
would cross "The'Fingerbuster"and extensive dental
concrete would be required in,that area.In the
upstream portion of the spillway,velocities would be
relatively high because of the narrow configuration
of the channel,and erosion could take place in this
area in proximity to the dam.The discharge from the
spillway enters the river perpendicular to the
general flow,but velocities would be relatively low
and should not cause substantial erosion problems.
The powerhouse is in the most suitable location for a
surface alternative where the bedrock is close to the
surface and the overall rock slope is approximately
2H:1 V.
Alternative 2A is similar to Alternative 2 exc~p~
that the upper end of the channel is divided and
separate control structures ar.e provided.This
diJ[i~i9n w9U IdaLLowthetute _ofone.s,tr,ucture _or
upstream channel while maintenance or remedial work
is being performed on the other.
Alternative 2B is similar to Alternative 2 except
that the cascade spillway is replaced by a double
stilling basin type structure.This spillway is
somewhat longer than the similar type of structure on
the north bank in the alternative described above.
'---------------libwever;-tne'sTop'eo fthe groiind Ts--ressEnaii'Ehe
-.._------'-----------'---rath'er-st'e'e'p-n'o'rth-'b'ank'--cmd-nray-b'e'-tfa--shfr---'to-'
construct,a factor which may partly mitigate the
cost of the longer structure.The discharge is at a
sharp angle to the river and more concentrated than
the cascade,which could cause erosion of the
opposite bank.
j
851104
Alternative 2C is adeI'iva.ti'ltebf 2B with a similar
-c-arrangeme n t,exce pt:'t:hat;~the~~clouble sti I Iing basin
spillway is reduced in size and augmented by an
additional emergency spillway in the form of an
inclined,unlined rock channel.Under this
B-2-28
851104
arrangement the concrete spillway acts as the main
spillway,passing the l:lO,OOO-year design flood with
greater flows passed down the unlined channel which
is closed at its upstream end by an erodible fuse
plug.The problems of erosion of the opposite bank
still remain,although these could be overcome by
excavation and/or slope protection.Erosion of the
chute would be extreme for significant flows,
although it is highly unlikely that this emergency
spillway would ever be used.
Alternative 2D replaces the cascade of Alternative 2
with a lined chute and flip bucket.The comments
relative to the flip bucket are the same as for
Alternative 1 except that the south bank location in
this instance requires a longer chute,partly offset
by lower construction costs because of the flatter
slope.The flip bucket discharges into the river at
an angle which may cause erosion of the opposite
bank.The underground powerhouse is located oQ:o;.,the
north bank,an arrangement which proy-ides an overall
reduction of the length of the water passages.
(iv)Alternative 3 (*)
This arrangement has a -dam axis location slightly
upstream from Alternative 2,but retains~the
downstream curve at the abutments.The main spillway
is an unlined rock cascade on the south bank which
passes the design flood.Discharges beyond the
l:lO,OOO-year flood would be discharged through the
auxiliary concrete-lined chute and flip bucket
spillway on the north bank.A gated control
structure is provided for this auxiliary spillway
which gives it the flexibility to be used as a backup
if maintenance should be required on the main
spillway.Erosion of the cascade may be a problem,
as mentioned previously,but erosion downstream
should be a less important consideration because of
the low unit discharge and the infrequent operation
of the spillway.The diversion tunnels are situated
in the north abutment,as with previous arrangements,
and are of similar cost for all these alternatives.
(v)Alternative 4 (*)
This alternative involves rotating the axis of the
main dam so that the south abutment is relocated
approximately 1,000 feet downstream from its
Alternative 2 location.The relocation results in a
B-2-29
851104
reduction in the overall dam quantities but would
require siting the impervious core of the dam
directly over "The Fingerbuster"shear zone at
maximum dam height.The south bank spillway,
consisting of chute and flip bucket,is reduced in
length comp~red to other south bank locations,as are
the power facility water passages.The diversion
tunnels are situated on the south bank;there is no
advantage to a north bank location,since the tunnels
are of similar length owing to the overall downstream
relocation of the dam.Spillways and power
facilities would also be lengthened by a north bank
location with this dam configuration.
(vi)Selection of Schemes for Further Study (*)
A basic consideration during design development was
that the main dam core should not cross the major
shear zones because of the obvious problems with
treatment of the foundation.Accordingly,there is
very little scope for realigning the main dam apart
from a slight-rotation toplace-,-it more at right
angles to the river.
Location of the spillway on the north bank results in
a shorter distance to the river and allows discharges
almost parallel to the general direction of river
flow.The double stilling basin arrangement·would be
_~extremel:y:".expe nshTe,~par.tic.ul arly_._iL.Lt.must.b.e.
designed to pass the probable maximum flood.An
alternative such as 2C would reduce the magnitude of
design flood to be passed by the spillway but would
only be acceptable if an emergency spillway with a
high degree of operational predictability could be
constructed.A flip bucket spillway on the north
bank,discharging directly down the river,would
appear to be an economic arrangement,although some
sc6ur··1iiignCOcc·urifi.-·tne-pTunge.pooiarea·~-Acascade-·
spi-l-lway-on-the-south-b-anrc-ou·td--be-an-a-c-cep·tabl.e·····---.·
solution provided that most of the excavated material
could be used in the dam,and adequate rock
conditions exist.
The length of diversion tunnels can be decreased if
they are located on the north bank.In addition,the
tunnels would be accessible bya preliminary access
-·-"road-from·-the--north,-which-is-the·most likely ·route.
This location would also avoid the area of "The
Fingerbuster"and the steep cliffs which would be
B-2-30
encountered on the south side close to the downstream
dam toe.
The underground configuration assumed for the
powerhouse in these preliminary studies allows for
location on either side of the river with a minimum
of interference with the surface structures.
Four of the preceding layouts,or variations of them,
were selected for further study:
o A variation of the double stilling basin
scheme,but with a single stilling basin main
spillway on the north bank,a rock channel and
fuse plug emergency spillway,a south bank
underground powerhouse and a north bank
diversion scheme;
o Alternative 1 with a north bank flip bucket
spillway,an underground powerhouse on the
south bank,and north bank diversion;
o A variation of Alternative 2 with a reduced
capacity main spillway and a north bank rock
channel with a fuse plug serving as an
emergency spillway;and
o Alternative 4 with a south bank rock cascade
spillway,a north bank underground powerhouse,
and a north bank diversion.
2.3.5 -Intermediate Review (*)
For the intermediate review process,the four schemes selected as
a result of the preliminary review were examined in more detail
and modified.A description of each of the schemes is given
below and shown on Figures B.2.3.2 through B.2.3.7.The general
locations of the upstream and downstream shear zones shown on
these plates are approximate and have been refined on the basis
of subsequent field investigations for the proposed project.
(a)Description of Alternative Schemes (*)
The four schemes are shown on Figures B.2.3.2 through
B.2.3.7.
(i)Scheme WPI (Figure B.2.3.2)(*)
This scheme is a refinement of Alternative 1.The
upstream slope of the dam is flattened from 2.5:1
851104 B-2-31
to 2.75:1.This conservative approach was adopted to
provide an assessment of the possible impacts on
project layout of conceivable measures which may
prove necessary in dealing with severe earthquake
design conditions.Uncertainty with regard to the
nature of river alluvium also led to the location of
the cofferdams outside the limits of the main dam
embankment.As a result of these conditions,the
intake portals of the diversion tunnels on the north
bank are also moved upstream from "The Fins".A
chute spillway with a flip bucket is located on the
north bank.The underground powerhouse is located on
the south bank.
(ii)Scheme WP2 (Figur~s B.2.3.4 and B.2.3.5).(*)
This scheme is derived from the double stilling basin
layout.The main dam and diversion facilities are
similar to Scheme WP1 except that the downstream
cofferdam .i~relocated further downstream from the
..spillway outlet and the diversion tunnels are
correspondingly extended.The main spillway is
located on the north bank,but the two stilling
basins of the preliminary scheme (Acres 1981)are
combined into a single stilling basin at the river
level.An emergency spillway is also located on the
north bank and consists of a channel excavated in
rock,discharging downstream from the area of the
relict channel.The channel is closed at its
---~-upstream-end~Dya-c()mpactedearthfIlr:tusepItiiand
is capable of discharging the flow differential
between the probable maximum flood and the surcharged
capacity of the main spillway.The underground
powerhouse is located on the south bank.
(iii)Scheme WP3 (Figures B.2.3 •.3 and B.2.3.4)(*)
Thiss chemei-s-simi-lart oScheme-WPl-inaH-res peets·..
._..excapt_that.au__emer_gency__spiUway_is_added-----..-..
consisting of north bank rock channel and fuse plug.
(iv)Scheme WP4 (Figures B.2.3.6 and B.2.3.7)(*)
The dam location and geometry for Scheme WP4 are
similar to that for the other schemes.The
diversion is on the north bank and discharges
dQwos.t.ream fromthe.pow.erhouse.tailrace outlet.A
rock cascade spillway is located on the south bank
and is served by two separate control structures with
·l
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851104 B-2-32
1
downstream stilling basins.The underground
powerhouse is located on the north bank.
(b)Comparison of Schemes (*)
The main dam is in the same location and has the same
configuration for each of the four layouts considered.
The cofferdams have been located outside the limits of the
main dam in order to allow more extensive excavation of the
alluvial material and to ensure a sound rock foundation
beneath the complete area of the dam.The overall design of
the dam is conservative,and it was recognized during the
evaluation that savings in both fill and excavation costs
can probably be made after more detailed study.
The diversion tunnels are located on the north bank.The
upstream flattening of the dam slope necessitates the
location of the diversion inlets upstream from "The Fins"
shear zone which would require extensive excavation and
support where the tunnels pass through this extremely poor
rock zone and could cause delays in the construction
schedule.
A low-lying area exists on the north bank in the area of the
relict channel and requires approximately a 50~foot high
saddle dam for closure,given the reservoir operating level
assumed for the comparison study.However,the finally
selected reservoir operating level will require only a
nominal freeboard structure at this location.
A summary of capital C0st estimates for the four alternative
schemes is given in Table B.2.3.3.
The results of this intermediate analysis indicate that the
chute spillway with flip bucket (Scheme WPl)is the least
costly spillway alternative.
The scheme has the additional advantage of relatively simple
operating characteristics.The control structure has
provision for surcharging to pass the design flood.The
probable maximum flood can be passed by additional
surcharging up to the crest level of the dam.In Scheme WP3
a similar spillway is provided,except that the control
structure is reduced in size and discharges above the routed
design flood are passed through the rock channel emergency
spillway.The arrangement in Scheme WPl does not provide a
backup facility to the main spillway,so that if repairs
caused by excessive plunge pool erosion or damage to the
structure itself require removal of the spillway from
service for any length of time,no alternative discharge
\
851104 B-2-33
facility would be available.The additional spillway of
Scheme WP3 would permit emergency discharge if it were
required under extreme circumstances.
The stilling basin spillway (Scheme WPZ)would reduce the
potential for extensive erosion downstream,but high
velocities in the lower part of the chute could cause
cavitation even with the provision for aeration of the
discharge.This type of spillway would be very costly,as
can be seen from Table B.Z.3.3.
The feasibility of the rock cascade spillway is entirely
dependent on the quality of the rock,which dictates the
amount of treatment required for the rock surface and also
the proportion of the excavated material which can be used
in the dam.For determining the capital cost of Scheme WP4,
conservative assumptions were made regarding surface
treatment and the portion of material that would have to be
wasted.
The diversion tunnels are locate~on the north bank for all
alternatives examined in the intermediate review.For
Scheme WPZ,the downstream portals must be located
downstream from the stilling basin,.,resulting in an increase
of approximately 800 feet in the length of the tunnels.The
south bank location of the powerhouse requires its placement
close to a suspected shear zone,with the tailrace tunnels
passing through this shear zone to reach the river.A
LOJlger_acces_s__tunneLisalsorequired,_together with an -
additional I,000 feet in the length of the tailrace •The
south-side location is remote from the main access road,
which wi 11 probably be on the north side 6f the river,as
will the transmission corridor.
(c)Selection of Schemes for Further Study (*)
Examination of the technical and economic aspects of Schemes
,,-----------------WPr-tlirougli--WP~--indi-caEes--tner-e-Ts-rit t ie--scopefor'"
-----~adJus-tmen-t-'o-f-th-e-d-am aX:ls,owing r:o-ffie confinement -imposed
by the upstream and downstream shear zones.In addition,
passage of the diversion tunnels through the upstream shear
zone could result in significant delays in construction and
additional cost.
From a comparison of costs in Table B.2.3.3,it can be seen
thatth€f 'f 1-~p_bti_c:~_et__~)TpE'i ~pDJ~l3,ii_~._t;li€i~c>sJec onomi caI ,
'but because-of the 'potentialfor'erosionund-er extensive
operation it is undesirable to use it as the only discharge
facility.A mid...;level release will be required for
emergency drawdown of the reservoir,and use of this release
-
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851104 B-Z-34
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851104
as the first-stage service spillway with the flip bucket as
a backup facility would combine flexibility and safety of
operation with reasonable cost.The emergency rock channel
spillway would be retained for discharge of PMF flows.
The stilling basin spillway is very costly and the operating
head of 800 feet is beyond precedent experience.Erosion
downstream should not be a problem but cavitation on the
chute could occur.Scheme WPZ was therefore eliminated from
further consideration.
The cascade spillway was also not favored,for technical and
economic reasons.However,this arrangement does have an
advantage in that it provides a means of preventing nitrogen
supersaturation in the downstream discharges from the
project which could be harmful to the fish population.A
cascade configuration would reduce the dissolved nitrogen
content;hence,this alternative was retained for further
evaluation.The capacity of the cascade was reduced and the
emergency rock channel spillway was included to pass the
extreme.floods.
The results of the intermediate review indicated that the
following components should be incorporated into any scheme
carried forward for final review:
o Two diversion tunnels located on the north bank of the
river;
o An underground powerhouse also located on the north
bank;
o An emergency spillway,comprising a rock channel
excavated on the north bank and discharging well
downstream from the north abutment.The channel is
sealed by an erodible fuse plug of impervious material
designed to fail if oyertopped by the reservoir;and
o A compacted earthfill and rockfill dam situated
between the two major shear zones which traverse the
project site.
As discussed above,two specific alternative methods exist
with respect to routing of the spillway design flood and
minimizing the adverse effects of nitrogen supersaturation
on the downstream fish population.These alternatives are:
o A chute spillway with flip bucket on the north bank to
pass the spillway design flood,with a mid-level
B-2-35
851104
release system designed to operate for floods with a
frequency of up to about 1:50 years;or
o A cascade spillway on the south bank.
Accordingly,two schemes were developed for further
evaluation as Part of the final review process.These
schemes are described separately in the paragraphs below.
2.3.6 -Final Review (*)
The.t'tYoschemes considered in the final review process were
essentially deri va tions of Schemes WP3 and WP4.
(a)Scheme WP3A (Figure B.2.3.8)C*)
This scheme is a modified version of Scheme WP3 described
above.Because of scheduling and cost considerations,it
is extremely important to maintain the diversion tunnels
downstream from "The Fins."It is also important to keep
the dam axis as far upstream as possible to avoid congestion
of the dbwl1strealll structures.For these reasons,the inlet
portals to the diversion.tunnels were located in the sound
bedrock forming the downstream boundary of "The Fins."The
upstream cofferdam and main dam are maintained in the
ups tream locations as .shown on Figure B.2 .3.8.As ment ione d
previously,additional criteria have necessitated
modifications in the spillway configuration,and low-level
·an-d~emergency··drawdown~outl-e-tshave-bee·n·lnU'bducecl-.-Tne-
main modifications to the scheme are as follows.
(i)Main Dam (*)
Continuing preliminary design studies and review of
world practice suggest that an upstream slope of
2.4H:1V would be acceptable for the rock shell •
......Adoptionofthisslope.resultsno_Lonl~in a_
reduction in dam fill volume butalso.~re<luc..tio.!!..in ~
the base width of the dam which permits the main
project components to be located between the major
shear zones.
The downstream slope of the dam is retained as 2H:1V.
The cofferdams remain outside the .limits of the dam
.•in.order foalloW complete ex:ca;V'a.t:iooof the·riverbed
alluvium.
B-2-36
.(
]
851104
(ii)Diversion (*)
In the intermediate review arrangements,diversion
tunnels passed through the broad structure of "The
Fins,"an intensely sheared area of breccia,gouge,
and infills.Tunneling of this material would be
difficult,and might even require excavation in open
cut from the surface.High cost would be involved,
but more important would be the time taken for
construction in this area and the possibility of
unexpected delays.For this reason,the inlet
portals have been relocated downstream from this zone
with the tunnels located closer to the river and
crossing the main system of jointing at approximately
45°.This arrangement allows for shorter tunnels
with a more favorable orientation of the inlet and
outlet portals with respect to the river flow
directions.
A separate low-level inlet and concreta7lined tunnel
is provided,leading from tqft reservoir at
approximate Elevation 1,550 to downstream of the
diversion plug where it merges with the diversion
tunnel closest to the river.This low-level tunnel
is designed to pass flows up to 12,000 cfs during
reservoir filling.I~would also pass up to 30,000
cfs under 500-foot head to allow,emergency draining
of the reservoir.
Initial closure is made by lowering the gates to the
tunnel located closest to the river and constructing
a concrete closure plug in the tunnel at the location
of the grout curtain underlying the core of the main
dam.On completion of the plug,the low-level
release is opened and controlled discharges are
passed downstream.The closure gates within the
second diversion tunnel portal are then closed and a
concrete closure plug constructed 'in line with the
grout curtain.After closure of the gates,filling
of the reservoir would commence.
(iii)Outlet Facilities (*)
As a provision for drawing down the reservoir in case
of.emergency,a mid-level release is provided.The
The intake to these facilities is located at depth
adjacent to the power facilities intake structures.
Flows would then be passed downstream through a
concrete-lined tunnel,discharging beneath the
downstream end of the main spillway flip bucket.In
B-2-37
-'
order to overcome potential nitrogen supersaturation
problems,Scheme WP3A also incorporates a system of
fixed-cone valves at the downstream end of the outlet
facilities.The valves were sized to discharge in
conjunction with the powerhouse operating at 7,000
cfs capacity (flows up to the equivalent routed
50-year flood).Eight feet of reservoir storage is
utilized to reduce valve capacity.Six cone valves
are required,located on branches from a steel
manifold and protected by individual upstream closure
gates.The valves are partly incorporated into the
mass concrete block forming the flip bucket of the
main spillway.The rock downstream is protected from
erosion by a concrete facing slab anchored back to
the sound bedrock.
(iv)Spillways (*)
As discussed above,the designed operation of the
main spillway facilities was arranged to limit
discharges of potentially nitrogen-supersaturated
water from Watana to flows having an equivalent
return period greater than 1:50 years.
The main chute spillway and flip bucket discharge
into an excavated plunge pool in the downstream river
bed.Releases are controlled by a three-gated ogee
structure located adjacent to the outlet facilities
and power intake structure just upstream from the damce;iterl ine:-""Thadesign-di sella rge -I s a-pprox Ena t;ely ---"
120,000 cfs;corresponding to the routed
1:10,OOO-year flood (150,000 ·cfs)reduced by the
31,000 cfs flows attributable to outlet and power
facilities -discharges.-Maximum reservoir level is
2,194 feet.The plunge pool is formed by excavating
the alluvial river deposits to bedrock.Since the
excavated plunge pool approaches the limits of the
-cd-cu-rated-maximum-scour-ho-le-,--iti-s-no tant icipa t ed
------------------------------tha-t,--g-i-ven-t-he-i-n-f-r-eq-uen-t--d-i-scha-r-ges-,--s-i-g-n-i-f-i-can-t-
downstream erosion will occur.
An emergency spillway is provided by means of a
channel excavated in rock on the north bank,
discharging well downstream from the north abutment
ill the directi.on of_TSltlsenaCreek.The channel is
sealed 'by an erodible fuse plug of impervious
mater-ial-de signed.tofai l"'ix-o"\t-ertopped by the
reservoir,although some preliminary excavation may
be necessary.The crest level of the plug will be
set at Elevation 2,230,well below that of the main
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851104 B-2-38
851104
dam.The channel will be capable of passing,in
conjunction with the main spillway and outlet
facilities,the probable maximum flood of
326,000 cfs.
(v)Power Facilities (*)
The power intake is set slightly upstream from the
dam axis deep within sound bedrock at the
downstream end of the approach channel.The intake
consists of six units with provision in each unit for
drawing flows from a variety of depths covering the
complete drawdown range of the reservoir.This
facility also provides for drawing water from the
different temperature strata within the upper part of
the reservoir and thus regulating the temperature of
the do~stream discharges close to the natural
temperatures of the river or temperatures
advantageous to fishery enhancement.For this
preliminary conceptual arrangement,flow withdrawals
from different levels are achieved by a series of
upstream vertical shutters moving in a single set of
guides and operated to form openings at the required
level.Downstream from these shutters each unit has
a pair of wheel-mounted closure gates which will
isolate the individual penstocks..
The six penstocks are 18-foot diameter,
concrete-lined tunnels inclined at 55°immediately
downstream from the intake to a nearly horizontal
portion leading to the powerhouse.This horizontal
portion is steel-lined for 150 feet upstream from the
turbine units to extend the seepage path to the
powerhouse and reduce the flow within the fractured
rock area caused by blasting in the adjacent
powerhouse cavern.
The six 170-MW turbine/generator units are housed
within the major powerhouse cavern and are serviced
by an overhead crane which runs the length of the
powerhouse and into the service area adjacent to the
units.Switchgear,maintenance room and offices are
located within the main cavern,with the transformers
situated downstream in a separate gallery excavated
above the tailrace tunnels.Six inclined tunnels
carry the connecting bus ducts from the main power
hall to the transformer gallery.A vertical elevator
and vent shaft run from the power cavern to the main
office building and control room located at the
surface.Vertical cable shafts,one for each pair of
B-2-39
transformers,connect the transformer gallery to the
switchyard directly overhead.Downstream from the
transformer gallery the underlying draft tube tunnels
merge into two surge chambers (one chamber for three
draft tubes)which also house the draft tube gates
for isolating the units from the tailrace.The gates
are operated by an overhead traveling gantry located
in the upper part of each of the surge chambers.
Emerging from the ends of the .chambers,two
concrete-lined,low-pressure tailrace tunnels carry
the discharges to the river.Because of space
restrictions at the river,one of these tunnels has
been merged with the downstream end of the diversion
tunnel.The other tunnel emerges in a separate
portal with provision for the installation of
bulkhead gates.
The orientation of water passages and underground
caverns is such as to avoid,as far as possible,
alignment of the main excavations with the major
joint sets.
(vi)Access (*)
Access is assumed to be from the north side of the
river.Permanent access to structures close to the
river is by a road along the north downstream river
bank and then via a tunnel passing through the
concreteformingthe--f-Hpbucket-.kt unnel-fromthis
point to the power cavern provides for vehicular
access.As~co:g.daryaccess road across the crest of
the dam passes down the south bank of the valley and
across the lower part ()f the d8Jll.
(b)Scheme WP4A (Figure B.2.3.9)(*)
..'IbJJL .sch_gm_e._.i.s __sim_ila;J;'__in_l!to_s_t_r_esp~_cJ:_s to Sch emSlWP3A
.......previously discussed,excee..L for.the spillw~l_
arrangement s.
(i)Main Dam (*)
The main dam axis is similar to that of Scheme WP3A,
except for a slight downstream rotation at the
southabutlliertt at the sp~llWc:lycorttrol structures.
J
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-----·····Ti n fiivet'-sTon.-T*T .
The diversion and low-level releases are the same for
the two schemes.
851104 B-2-40
..1
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851104
(iii)Outlet Facilities (*)
The outlet facilities used for emergency drawdown are
separate from the main spillway for this scheme.
The outlet facilities consist of a low-level gated
inlet structure discharging up to 30,000 cfs into the
river through a concrete-lined,free-flow tunnel with
a ski jump flip bucket.This facility may also be
operated as an auxiliary outlet to augment the main
south bank spillway.
(iv)Spillways (*)
The main south bank spillway is capable of passing a
design flow equivalent to the 1:10,000-year flood
through a series of 5Q-foot drops into shallow pre-
excavated plunge pools.The emergency spillway is
designed to operate during floods of greater
magnitude up to and including the PMF.
Main spillway discharges are controlled by a broad
multi-gated control structure discharging into a
shallow stilling basin.The feasibility of this
arrangement is governed by the quality of the rock in
the area,requiring both durability to withstand'
erosion caused by spillway flows and a high
percentage of sound rockfill material that can be
used from the excavation directly in the main dam.
On the basis of the site information developed
concurrently with the general arrangement studies,it
became apparent that the major shear zone known to
exist in the s,outh bank area extended further
downstream than initial studies had indicated.The
cascade spillway channel was therefore lengthened to
avoid the shear area at the lower end of the cascade.
The arrangement shown on Figure B.2.3.9 for Scheme
WP4A does not reflect this relocation,which would
increase the overall cost of the scheme.
The emergency spillway consisting of rock channel and
fuse plug is similar to that of the north bank
spillway scheme.
(v)Power Facilities (*)
The power facilities are similar to those in Scheme
WP3A.
B-2-41
(c)Evaluation of Final Alternative Schemes (*)
An evaluation of the dissimilar features.for each
arrangement (the main spillways and the discharge
arrangements at the downstream end of the outlets)indicates
a saving in capital cost of $197,000,000,excluding
contingencies and indirect cost,in favor of Scheme WP3A.
If this difference is adjusted .for the savings associated
with using an appropriate proportio.n of excavated material
from the cascade spillway as rockfill in the main dam,this
represents a net overall cost difference of approximately
$110,000,000 including contingencies,engineering,and
administration costs.
As discussed above,although limited info'rmation exists
regarding the'quality of the rock 'in the downstream area on
the south bank,it is known that a major shear zone runs
through and is adjacent to the area presently alloca ted to
the spillway in Scheme WP4.This.,Jo?ould require relocating
the south bank cascade spillway several hundred feet farther
downstream'into an area.'Y7here the roc.k quality is unknown
and the topography less suited to the.gentle overall slope
of the cascade.The ,cost of the.excavation would
substantially increase compared to previous assumptions,
irrespective of the rock quality.III addition,the
resistance of the rock to erosion and the suitability for
use as excavated mate.rial in the main dam would become less
certain.The economic feasibility .of this scheme is largely
-",-,"'pt'E:roicateoon tllisla s'tfactof;'ffilfc'eEnea15iTity 'fo useYne'
material.as a source of rockfill for the main dam represents
a major cost saving.
In conjunction,with the,maiIlchute spillway,the problem'of
the occurrence of ni trogen.supersa tura tion can be overcome
by the use of a regularly operated dispersion-type valve
outlet facility in conj unction with the main chute spillway.
"h'h "1 l''h,.."..S:Lnce_.t:Ls_,SC emepresents..,a,,-more-econom:Lca.sout.lonW:Lt "
,,_.__,__._--._.f~.!'l..e_r_p.o_t,e,nt,i,aLp,r,o,b,Lem,s.:...co,ncerning_th.e ...geotechnicaLas,pects
of its design,the north bank chute arrangement (Scheme
WP3A)has been adopted as the final selected scheme.
Subsequent to adoption of the final scheme and prior to
submission of the July 1983 License Application,refinements
to the design were made as presented in Exhibit F.
Since the filing of the License Application,additional studies
and geotechnical investigations have been conducted.These
j
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851104 B-2-42
1
I
I.
have been directed toward reviewing and refining project design
concepts and estimating costs of alternative features and
layouts.With more information available after the completion of
two drilling programs conducted during the Winter of 1982-83 and
the Summer of 1984,estimated project costs have been reduced.
Studies of alternatives have also shown where cost reductions can
be made.Revisions of the project design concepts are therefore
shown in this amendment to the License Application and are
described below.
(a)Staged Construction (***)
In this amended License Application,the Susitna Project
will be constructed in three stages.The initial
construction of the Watana development will be for normal
maximum operating reservoir at el.2,000,and is designated
Stage I.Construction of the Devil Canyon ~evelopment for
normal maximum operating reservoir at el.1,455 is
designated Stage II and is scheduled after the Watana
initial construction.The raising of Watana dam for the el.
2,185 reservoir,its ultimate height,is designated Stage
III.The layouts of the three stages are presented in
Figures B.2.3.10,B.2.3.11,and B.2.3.12.
Constructing the Watana development in stages will reduce.
the initial financial commitment of the state and the burden
on electric rate payers "by providing more flexibility in
meeting load growth.
(b)Diversion Tunnels and Cofferdams (***)
The diversion tunnel concept shown in Exhibit F of the
initial application consists of two 38-foot diameter
tunnels.Tunnell was set high in order to pass ice without
pressurizing.Tunnel 2 was set below the river bed to
divert flow from the upstream cofferdam area,easing its
closure~Tunnel 1 would later be converted to an emergency
release facility,as previously described in the
application.
Studies were conducted to verify the necessity of passing
ice through a tunnel with free surface flow.It was
concluded that a pressurized tunnel can pass ice,therefore,
lowering Tunnel 1 is feasible to increase its hydraulic
capacity.The two 36-foot diameter diversion tunn~ls,as
proposed in this amendment,will pass the 1:50-year flood.
This same criterion was in the initial License Application.
851104 B-2-43
In the amended project,Tunnel 2 is raised by 25 feet to
avoid the potential for clogging by bed load deposition in a
continuously submerged tunnel.
These revisions will result in improved performance of the
diversion tunnels and reduce cost.
Cofferdam crest elevations have been increased,to provide a
greater level of protection to the dam foundation excavation
area during construction from a possible ice jam causing
higher river level.The combination of greater cofferdam
heights and reduced tunnel diameters still results in a
decrease in construction cost.
(c)Excavation and Foundation Treatment for Dam (***)
The main dam foundation treatment,as shoWn in this License
Application Amendment,would reduce rock excavation
beneath the core and shells and limit excavation of the
river valley alluvium to the central 80%of the dam
foundation.The areas of the dam in proximity to the
upstream and downstream toes of the embankment are now
planned to be founded on the riverbed alluvium.
Tp.e 1983 Winter Geologic Exploration showed that the bedrock
is of a better quality than originaHy anticipated.
Therefore,only limited excavation of bedrock beneath··the
embankment is foreseen.Fresh hard diorite in most
inELt~Il<:~~exis t.~.from the becl~ock_sU1;:face.!...._RemovaIQ~
foundation treatment (dental excavation of concrete
backfill)will be perfO'rmed in local areas beneath the
shells where erodible or otherwise'unsatisfactory foundation
bedrock is encountered.The quantity of rock to be removed
under the embankmertt will be reduced from that estimated in
the License Application by about 3.75 million cubic yards.
The License Application cost estimates assumed a trench
beneath the iIJ?pervious core and filters averaging 40 feet
·············-aee-p;--a-rt-d·-arc·av·€H..age-·-exc'a.'raEea "-aepth--under-tli-e-'sneTls"···0£······10·
.----------feet.--The--amended--de-srgn--provid-e-s-a-c-o-re--cren-ch-tO--re-et----··-
deep in the river section,and 20 feet deep on the
abutments.Excavation under the shells on the abutments
averages one foot.A reduction in the grout curtain
drilling and grouting was also made,in view of the better
quality foundation bedrock.
Cd)Dam and Cofferdam Configuration and Composition (***).
The License Application design for the dam cross section has
been essentially retained in this amendment,as it is
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851104 B~2-44
1,
considered to be satisfactory and will produce a stable
structure.To increase safety against seismic shaking,the
steepening of the exterior slopes near the embankment crest
has been eliminated.This results in the same exterior
slope from crest to toe both upstream and downstream.The
embankment internal zoning design has also been modified to
incorporate materials from the required excavations along
with by-product materials from the processing operations.
The amended layout includes the use of rock and processed
granular materials in the shells outside the impervious
core.This section increases the utilization of available
materials and will reduce required borrow as well as reduce
spoil requirements.
The cofferdam sections have been revised to a more
conservative design,and a positive slurry trench cutoff to
bedrock is provided.
(e)Spillway (***)
This License Application Amendment eliminates the emergency
spillway and increases the discharge capacity of the chute
spillway and flip bucket to pass the routed PMF.This
revision will reduce cost of ._the development and reduce
terrestrial and aesthetic impacts by reducing ground surface
disturbance •.
The capacity of the spillway will be increased by providing
larger gates and increasing the width of the chute and flip
bucket.Th~three gates will be increased from 36 feet wide
by 49 feet high to 44 feet wide by 64 feet high.
The width of the chute,which varied from 140 to 80 feet,
will be increased to vary from 164 to 120 feet.The flip
bucket will be increased from 80 feet to 120 feet wide.
In Stage I the crest of the spillway control structure will
be at el.1,950,and in Stage III the crest will be at
el.2,135.The ultimate crest will be 13 feet lower than
previously shown to accomodate the larger gates for the
increased discharge capacity.
This amendment also includes a rev~s~on of the type of
spillway gate from fixed wheel gate to radial gate and
revises the type of hoist from electric motor driven drum to
hydraulic cylinder operator.The revised type of gate will
cost less and will have improved operating characteristics.
851104 B-2-45
(f)Relocation and Reorientation of Caverns (***)
A review of the site geology indicated a major set of
fractures which trended N 50 0 W and a second minor set
perpendicular to these.The caverns for the powerhouse,
transformer gallery,and surge chamber,as shown in the
License Application,trend in a direction approximately N
20 o W,straddling between the major joint system and a
sub joint system.
Excavation of the longitudinal walls would be improved if
the major joint planes were to intersect the walls as near
to the perpendicular as possible.Consequently,the caverns
have been rotated accordingly,resulting in less overbreak
of rock in the cavern faces,fewer construction problems and
improved safety during construction.This change will also
be beneficial to the changes in the power conduits and
access tunnel geometry described below.
(g)Power Conduits and Intake (***)
The-LicenseApplication indicates a single structure power
intake with six intake passages located approximately
1,000 feet upstream from the dam axis.The power conduits
consist of six individual penstock tunnels and shafts with a
developed length of about 1,500 feet each connecting the
intake structure to the powerhouse,and two tailrace tunnels
approximately 2,000 feet long connecting the powerhouse to
---.------.~-~the~iv.e.r.~_....The~do_ws~t_r.eam_3.0~0.fee.t_o.LQne_o_f.~t.he.tail.-rg.c_e.
tunnels utilized the downstream portion of one of the
diversion tunnels.
To reduce the power conduit length in the amended design,
the intake structure was shifted to a location between the
spillway and the river channel and nearer to the dam axis,
resulting in relocation and shortening of the power
conduits.The number of penstock tunnels was reduced from
.......-···-·sIi--to -fl:iree-power-fi.iniiels~·-·eacnofwhTcliwilTbi furc·ate·t6 .-
~,----,--'_.,-_._---------,---------.---~--sma IIer pe nsf 0 ck~tUI111el-s-.--G{f(:frd--v~-lvl:fS~wi-ll---b~e-·-pr-ovid-ed·--fo·r·--·--
each turbine.-The net head on the generating units will be
greater,and the shorter,more efficient power conduits will
provide better unit operation.Vertical shafts are also
shown instead of sloping Shafts because excavation and
concreting of vertical shafts requires less time,personnel,
-and equipment,.and given the-geologic conditions,should
res~l 1:in less overbreak.
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851104 B-2-46
)(h)Power Intake and Spillway Approach Channels (***)
The hydraulic conditions of the approach channels to the
power intake and spillway as shown in the License
Application can be improved with the relocation of the
powerhouse and the power conduits.In the License
Application,the power intake is located such that it
appears to impede flow to the spillway.The amended
location of the power intake will eliminate this effect.
The approach channels as shown will require larger
quantities of rock excavation;however,this material can be
used for fill in the dam and for concrete aggregate.
(i)Turbine-Generator Unit Speed (***)
The synchronous speed of the turbine-generator units has
been increased from 225 rpm,as shown in the License
Application,to 257.1 rpm.Basically,the higher speed unit
required a deeper.setting of the turbine distributor below
tailwater.The depth shown in the License Application is,
however,greater than necessary for the 225-rpm turbine and
is sufficient for the 257.l-rpm turbine •..This increase in
speed will reduce the physical size and cost of the
turbine-generator set and also may possibly result in some
reduction in the powerhouse size at the time the final
design is made.
(j)Gas Insulated Switchgear and Bus (***)
Revisions of the high voltage conductors from the main power
transformers to the ground surface and elimination of the
ground level switchyard and bus are shown in Exhibit A.
These revisions include use of a single 9-foot diameter
vertical SF6 bus shaft instead of two vertical 7-foot 6-inch
diameter cable shafts from the transformer gallery to the
surface.All switching equipment will be underground,thus
simplifying maintenance.This will·provide an improved
environment for operation and maintenance by elimination of
the potential for icing of equipment in a ground level
switchyard.Substitution of SF6 buses for oil-filled cables
will improve safety,removing fire hazards from the cable
shaft area.Elimination of the switchyard will also reduce
environmental impact and improve aesthetics by the
construction of fewer and smaller surface structures.
851104 B-2-47
851104
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2.4 -Devil Canyon Project Formulation (0)
This section describes the development of the general arrangement of
the Devil Canyon project.The method of handling floods during con-
struction and subsequent project operation is also outlined in this
section.
The reservoir level fluctuations and inflow for Devil Canyon will es-
sentially be controlled by operation of the upstream Watana project.
This aspect is also briefly discussed in this section.
2.4.1 -Selection of Reservoir Level (*)
The selected normal maximum operating level at Devil Canyon Dam
is el.1,455.Studies by the USBR and COE on the Devil Canyon
project were-essentially based on a similar reservoir level,
which corresponds to the average tailwater level at the Watana
site.'Although the narrow configuration of the Devil Canyon site
and the relatively low costs involved in increasing the dam
height suggest that it might be economic to do so,it is clear
that the upper economic limit of reservoir level at Devil Canyon
.is the Watana tailrace level.
Although significantly lower reservoir levels at Devil Canyon
would lead to lower dam costs,the location of adequate spillway
facilities in the narrow gorge would become extremely difficult
and lead to offset ting increases in cos t."In the extreme case,a
spillway discharging over the dam would raise concerns regarding
safety from scouring at the toe of the dam,which have already
-led-to-reTectTon-'orsli"cn"scliemes ;
2.4.2-Selectionof·lnstalledCapacity (*)
The methodology .used f·or the preliminary selection of installed
capacity at Devil Canyon is similar to the Watana methodology
described in Section 2.2.2.
-..--The--decision ·toopera-te--De vil"-Canyon.primari1,,y,,~.as..a base.",.l 0 ad .
.._..''~_-plant_w.aL.gml.e.r-ne-d_b-y-the-fo.lLo.w:ing-ma.in_c_o.n.sJd_er.a.t.io.n.s..:.___..._
o Daily peaking is more effectively performed at Watana than
at Devil Canyon;and
o Excessive fluctuations in discharge from the Devil Canyon
Dam may h~ve an undesirable impact on mitigation measures
incorporated in the final design to protect.the downstream
fisheries!.
Given this mode of operation,the required installed capacity at
Devil Canyon has been determined as the maximum capacity needed
B-2-48
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851104
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to utilize the available energy from the hydrological flows of
record,as modified by the reservoir operation rule curves.In
years where the energy from Watana and Devil Canyon exceeds the
system demand,the usable energy has been reduced at both
stations in proportion to the average net head available,
assuming that flows used to generate energy at Watana will also
be used to generate energy at Devil Canyon.
Table B.2.4.l shows an assessment of maximum plant capacity
required at Devil Canyon in the peak demand month (December).
The Devil Canyon capacity is the same whether thermal energy is
used for base load or for peaking,since Devil Canyon is designed
for peaking only.
The selected total installed capacity at Devil Canyon has been
established as 600 MW for design purposes.This will provide
some margin for standby during forced outage and possible
accelerated growth in,.demand.
The major factors governing the selection of the unit size at
Devil Canyon are the rate of growth of system demand,the minimum
station output,and the requirement of standby capacity under
forced outage conditions.
The power facilities at Devil Canyon have been developed using
four units at 150 MWeach.This arrangement will provide for
efficient station operation during low load periods as well as
during peak December loads.During final design,consideration
of phasing of installed capacity to match the system demand may
desirable.However,the uncertainty of load,forecasts and the
additional contractual costs of mobilization for equipment
installation are such that for this study it has been assumed
that all units will be commissioned by 2002 •.
The Devil Canyon Reservoir will usually be full in December;
hence,any forced outage could result in spilling and ~loss of
available energy.The units have been rated to deliver 150 MW at
maximum December drawdown occurring during an extremely dry year;
this means that,in an average year,with higher reservoir
levels,the full station output can be maintained even with one
unit on forced outage.
2.4.3 -Selection of Spillway Capacity (*)
A flood frequency of 1:10,000 years was selected for the spillway
design on the same basis as described for Watana.An emergency
spillway with an erodible fuse plug will also be provided to
safely discharge the probable maximum flood.The development
plan envisages completion of the Watana project prior to
construction at Devil Canyon.Accordingly,the inflow flood
B-2-49
peaks at Devil Canyon will be less than pre"'project flood peaks
because of routing through the Watana reservoir.Spillway design
floods are:
Flood
1:10,000 years
Probable Maximum
Inflow Peak (cfs)
165,000
345,000
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The avoidance of nitrogen supersaturation in the downstream flow
for Watana also will apply to Devil Canyon.Thus,the discharge
of water possibly supersaturated with nitrogen from Devil Canyon
will be limited to a recurrence period of not less than 1:50
years by the use of fixed-cone valves similar to Watana.
2.4.4 -Main Dam Alternatives (*)
The location of the Devil Canyon damsite was examined during
previous studies by the USBR and COED These studies focused on
the narrow entrance to the cany~n and led to the recommendation
of a concrete arch dam.Notwithstanding this initial appraisal,
a comparative analysis was undertaken as part of this feasibility
study to evaluate the relative merits of the following types of
structures at the same location:
o Thick concrete arch
o Thin concrete arch~
o Fill embankment.
(a)Comparison of Embankment and Concrete Type Dams (*)
The geometry was developed fbrboth the thin concrete arch
and the thick concrete arch dams,and the dams were
analyzed and their behavior compared under static,
hydrostatic,and seismic loading conditions.The project
layouts for these arch dams were compared to a layout for a
rockfill dam with its associated structures •
.·-----Considera·t'ion-of-the·centra-l-·core-rockfi-H-dam-l-ayout··
indicated relatively small cost differences from an arch dam
cost estimate,based on a cross section significantly
thicker than the finally selected design.Furthermore,no
information was available to indicate that impervious core
material in the necessary quantities could be found within a
reasonabledistance.of thedamsite •...The ..rockfill dam was
accordingly dropped from further consideration.It is
further noted:that ,since .this~·al tercnat-ive dam s tudYT
seismic analysis of the rockfill dam at Watana has resulted
in an upstream slope of 2.4H:IV,thus indicating the
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851104 B-2-50
851104
requirement to flatten the 2.5H:IV slope adopted for the
rockfill dam alternative at Devil Canyon.
Neither of the concrete arch dam layouts was intended as the
final site arrangement,but were sufficiently representative
of the most suitable arrangement associated with each dam
type to provide an adequate basis for comparison.Each type
of dam was located just downstream of the point where the
river enters Devil Canyon and close to the canyon's
narrowest point,which is the optimum location for all types
of dams.A brief description of each dam type and
configuration is given below.
(i)Rockfill Dam (*)
For this arrangement the dam axis would be some 625
feet downstream of the crown section of the
concrete dams.The assumed embankment slopes would
be 2.25H:1V on the upstream face and 2H:1V on the
downstream face.The main dam would be continuous
with the south bank saddle dam,and therefore no
thrust blocks would be required.The crest length
would be 2,200 feet at el.1,470;the crest width
would be 50 feet.
The dam would be constructed with a central
impervious core,inclined upstream,supported on the
downstream side by a semi-pervious zone.These two
zones would be protected upstream and downstream by
filter and transition materials.The shell sections
would be constructed of rockfill obtained from'
blasted bedrock.For preliminary design all dam
sections would be assumed to be founded on rock;
external cofferdams would be founded on the river
alluvium,and would not be incorporated into the main
dam.The approximate volume of material in the main
dam would be 20 million cubic yards.
A single spillway would be provided on the north
abutment to control all flood flows.It would
consist of a gate control structure and a double
stilling basin excavated into rock;the chute
sections and stilling basins would be concrete-lined,
with mass concrete gravity retaining walls.The
design capacity would be sufficient to pass the
l:lO,OOO-year flood without damage;excess capacity
would be provided to pass the PMF without damage to
the main dam by surcharging the reservoir and
spillway.
B-2-5l
851104
The powerhouse would be located underground in the
north abutment.The multi-level power intake would
be constructed in a rock cut in the north abutment on
the dam centerline,with four independent penstocks
to the 150-MW Francis turbines.Twin concrete-lined
tailrace tunnels would connect the powerhouse to the
river via an intermediate draft tube manifold.
(ii)Thick Arch Dam (*)
The main concrete dam would be a single-center arch
structure,acting partly as a gravity dam,with a
verti~al cylindrical upstream face and a sloping
downstream face inclined at IV:0.4H.The maximum
height of the dam would be 635 feet,with a uniform
crest width of 30 feet,a crest length of approxi-
mately 1,400 feet,and a maximum foundation width of
225 feet.The crest elevation would be 1,460.The
center portion of the dam would be founded on a
massive mass concrete pad constructed inthe;t:excavat-
ed riverbed.This central section.would incorporate
the main spillway with sidewalls anchored into solid
bedrock and gated orifice spillways discharging down
the steeply inclined downstream face.of the dam into
a single large stilling basin set below river level
and.spanni ng the valley.
The main dam would terminate in thrust blocks high on
...theabutments.•..~.~Thesou-th abutment~.thrustblock_would.
incorporate an emergency gated control spillway
structure which would discharge into a rock channel
running well'downstream and terminating at a level
high above the river valley.
Beyond the control structure and thrust block,a
low-lying saddle on the south abutment would be
closed by means of a rockfill dike founded on
'·6earock~··""The·powerholis'e'wouldhouserour-T5<F·MW
--------u:nns~and'wouIdDelocateatmderground--Wnnin·tne-~'
north abutment.The intake would be constructed
integrally with the dam and connected to the
powerhouse by vertical steel-lined penstocks.
The main spillway would be designed to pass the
1:10,000-year ,routed flood.The probable maximum
W()ul<i)"eQ..a,ss!id'byc::()1l!1.'!.irie.ddis.c;1:'large s through the
main spillway;()utletfacility;and emergency
spillway.
B-2-52
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(iii)Thin Arch Dam (*)
The main dam would be a two-center,double-curved
arch structure of similar height to the thick arch
dam,but with a 20-foot uniform crest and a maximum
base width of 90 feet.The crest elevation would be
1,460.The center section would be founded on a
concrete pad,and the extreme upper portion of the
dam would terminate in concrete thrust blocks located
on the abutments.
The main spillway would be located on the north
abutment and would consist of a conventional gated
control structure discharging down a concrete-lined
chute terminating in a flip bucket.The bucket would
discharge 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 would be supplemented by orifice
type spillways located in the center portion of the
dam,which would discharge into a concrete-lined
plunge pool immediately downstream from the dam.An
emergency spillway consisting of a fuse plug
discharging into an unlined rock channel terminating
well downstream would be located beyond the saddle
dam on the south abutment.
The concrete dam would terminate in a massive thrust
block on each abutment which,on the south abutment,
would adjoin a rockfill saddle dam.
The main and auxiliary spillways would be designed to
discharge the 1:10,000-year flood.The probable
maximum flood would be discharged through the
emergency south abutment spillway,main spillway and
auxiliary spillway.
(b)Comparison of Arch Dam Types (*)
Sand and gravel for concrete aggregates are believed to be
available in sufficient quantities within economical
distances from the damsite.The gravel and sands are formed
from the granitic and metamorphic rocks of the area;at this
time it is anticipated that they will be suitable for the
production of aggregates after screening and washing.
The bedrock geology of the site is discussed in the 1980-81
Geotechnical Report (Acres 1982a).At this time it appears
851104 B-2-53
that there are no geological or geotechnical concerns that
would preclude either of.the dam types from consid·eration.
Under hydrostatic and temperature loadings,stresses within
the thick arch dam would be generally lower than for the
thin arch alternative.However,finite element analysis has
shown that the additional mass of the dam under seismic
loading would produce stresses o.fa greater magnitude in the
thick arch dam than in the thin'arch dam.If the surface
stresses approach the maximum allowable at a particular
section,the remaining understressed area of concrete will
be greater for the thick arch,and the factor of safety for
the dam would be correspondingly higher.The thin arch is,
however,a more efficient design and better utilizes the
inherent properties of the concrete.It is designed
around acceptable predetermined factors of safety and
requires a much smaller volume of concrete for the actual
dam structure.
The thick arch arrangement did not appear to have a distinct
technical advantage compared toa thin arch dam and would be
more expensive.because of the'larger volume of concrete
needed.Studies therefore continued on refining the
feasibility of the thin arch alternative.
2.4.5 -Diversion Scheme Alte:rnatives (*)
In this section the selection of general arrangement and the
.-..---·ba·s-is·"·for-cs-izing"·of....the~di-vers·ion"schemeare···pres ented..
(a)General Arrangements (*)
The steep",:"walled valley at the si teessentially dictated
that diversion of the river during construction be
accomplished using one or two diversion tunnels,with
upstream.and downstream cofferdams protecting the main
g()..ll.§t::r1,1(,:j:j&1l,.g.J:'~.g!.
.-______I "-___.._.
The selection process .for establishing the final general
arrangement included examination of tunnel locations on both
banks of .the river.Rock conditions for tunneling did not
favor one bank over the other.Access and ease of
construction strongly favored .the south bank or abutment,
the obvio.us,approach being via the alluvial fan.The total
·leilgth6f.tunnel'require'dfor tli¢<,s0tJth bank is
.approximately300feetgreater.;c.however,-.a.ccess to the north
bank cOuld nOi::be achievedwfEhou'i::···gr'eat:'·difficUlfY.
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851104 B-2-54
(b)Design Flood for Diversion (*)
The recurrence interval of the design flood for diversion
was established in the same manner as for Watana Dam.
According~y,at Devil Canyon a risk of exceedance of 10
percent per annum has been adopted,equivalent to a design
flood with a 1:10-year return period for each year of
critical construction exposure.The critical construction
time is estimated at 2.5 years.The main dam could be
subjected to overtopping during construction without causing
serious damage,and the existence of the Watana facility
upstream would offer considerable assistance in flow
regulation in case of an emergency.These considerations
led to the selection of the design flood with a return
frequency of 1:25 years.
The equivalent inflow,together with average flow
characteristics of the river significant to diversion,are
presented below:
o Average annual flow:
9,080 ds
o Design flood inflow (1:25 years routed
through Watana reservoir):
37,800 cfs
(c)Cofferdams (*)
As at Watana,the considerable depth of riverbed alluvium at
both cofferdam sites indicates that embankment-type
cofferdam structures would be the only technically and
economically feasible alternative at Devil Canyon.For the
purposes of establishing the overall general arrangement of
the project and for subsequent diversion optimization
studies,the upstream cofferdam section adopted will
comprise an initial closure section approximately 20 feet
high constructed in the wet,with a zoned embankment
constructed in the dry.The downstream cofferdam will
comprise a closure dam structure approximately 30 feet high
placed in the wet.Control of underseepage through the
alluvium material may be required and could be achieved by
means of a grouted zone.The coarse nature of the alluvium
at Devil Canyon led to the selection of a grouted zone
rather than a slurry wall.
(d)Diversion Tunnels (*)
Although studies for the Watana project indicated that
concrete-lined tunnels are the most economically and
851104 B-2-55
technically feasible solution,this aspect was reexamined at
Devil Canyon.Preliminary hydraulic studies indicated that
the design flood routed through the diversion scheme would
result in a design discharge of approximately 37,800 cfs.
For concrete-lined tunnels,design velocities of
approximately 50 ft/sec would permit the use of one
concrete-lined tunnel with an equivalent diameter of 30
feet.Alternatively,for unlined tunnels a maximum design
velocity of 10 ft/sec in good quality rock would require
four unlined tunnels,each with an equivalent diameter of
35 feet,to pass the design flow.As was the case for the
Watana diversion scheme,considerations of reliability and
cost were considered sufficient to eliminate consideration
of unlined tunnels for the diversion scheme.
For the purposes of optimization studies,only a pressure
tunnel was considered,since previous studies indicated th.at
cofferdam closure problems associated with free flow tunnels
would more than offset their other advantages.
(e)Optimization of Diversion Scheme (*)
Given the considerations described above relative to design
flows,cofferdam configuration,and alternative types of
tunnels,an economic study was undertaken to determine the
optimum combination of upstream cofferdam elevation (height)
and tunnel diameter.
____c~Gapital costs!,?er~L.develop~<!tQ.~~..'J;:angg,Q.Lp'J;:§L~sUI'~.t:tJ.J:l.n.§l
diameters and corresponding upstream cofferdam embankment
crest elevations with a 30-foot wide crest and exterior
slopes of2H:lV.A freeboard allowance of 5 feet was
included for.settlement and wave runup.
Capital costs for the tunnel alternatives included
allowances for excavation,concrete liner,rock bolts,and
steel supports.Costs'were also developed for the upstream
..····_-..··-·-and·downs·tre-am-por·tats·-;-tncl'uding-excavation-and··slippor·t-;-··.
..._.._--.-The..·co·st--of--an····intake--gate······s·t·ructure-and--associa·ted-·ga·te's····
was determined not to vary significantly with tunnel
diameter and was excluded from the analysis.
The centerline tunnel length in all cases was estimated to
be 2,000 feet.
Rating curves for the single pressure tunnel alternatives
are presented inFigur·e:8~2.4~:"1"::===The=~i'e.fati()i:ishipbetween
capital costs for the upstream cofferdam and various tunnel
diameters is given in Figure B.2.4.2.
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85.1104 B-2-56 ·l
The results of the optimization study indicated that a
single 30-foot diameter pressure tunnel results in'the
overall least cost (Figure B.2.4.2).An upstream cofferdam
cofferdam 60 feet high,with a crest elevation of 945,was
carried forward as part of the selected general
arrangement.
2.4.6 -Spillway Alternatives (*)
The project spillways have been designed to safely pass floods
with the following return frequencies:
Inflow Peak
Flood
Spillway Design
Probable Maxhnum
Discharge
Frequency
1:10,000 years
Inflow
(cfs)
165,000
345,000,
851104
A number of alternatives were considered singly and in
combina tion for Devil Canyon spillway facilities.These inc1 uded
gated orifices in the main dam discharging into a plunge pool,
chute or tunnel spillways with either a flip bucket or stilling
basin for energy dissipation,and open channel spillways.As
described for Watana,the selection of the type of spillway was
influenced by tQe general arrangement of the major structures.
The main spillway facilities would discharge the spillway design
flood through a gated spillway control structure with energy
dissipation by a flip bucket which directs the spillway discharge
in a free-fall jet into a plunge pool in the river.As noted
above,restrictions with respect to limiting nitrogen
supersaturation in selecting acceptable spillway discharge
structures have been applied.The various spillway arrangements
developed in accordance with these considerations are discussed
in Section 2.5.
2.4.7 -Power Facilities Alternatives (*)
The selection of the opthnum arrangements for the power
facilities involved consideration of the same factors as
described for Watana.
(a)Comparison of Surface and Underground Powerhouses (*)
A surface powerhouse at Devil Canyon would be located either
at the downstream toe of the dam or along the side of the
canyon wall.As determined for Watana,'costs favored an
underground arrangement.In addition to cost,the under-
ground powerhouse layout has been selected based on the
following:
B-2-57
o Insufficiertt space is available in the steep-sided
canyon for a surface powerhouse at the base of the
dam;
o The provision of an extensive intake at the crest of
the arch dam would be detrimental to stress conditions
in the arch dam,particularly under earthquake
loading,and would require significant changes in the
arch dam geometry;and
o The outlet facilities located in the arch dam are
designed to discharge directly into the river valley;
these would cause significant winter icing and spray
problems to any surface structure below the dam.
(b)Comparison of Alternative Locations (*)
The underground powerhouse and related facilities have been
located on the north bank for the following reasons:
o Generally superior rock quality at depth;
o The south bank area behind the main dam thrust block
is unsuitable for the construction of the power
intake;and .
o The river turns north downstream from the dam,and
hence the north bank power development is more
suitableforextending~the tailrace~tunneltodevelop
extra head.
(c)Selection of Units (*)
The turbine type seiected for the Devil Canyon development
is governed by the design head and specific speed and by
economic considerations.Francis turbines have been adopted
for reasons similar to those discussed for Watana in
The selection of the number and rating of individual units
is discussed in detail in subsection 2.4.2.The four units
will be rated to deliver 150 MW each at full gate opening
and minimum reservoir level in December (the peak demand
month)•
(d)Transformers (*)
Transformer selection is similar to Watana
subsection 2.2.7(e).
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(e)Power Intake and Water Passages (*)
For flexibility of operation,individual penstocks are
provided to each of the four units'.Detailed cost studies
showed that there 1s no significant cost advantage ~n using
two larger diameter penstocks with bifurcation at the
powerhouse compared to four separate penstocks.
A single tailrace tunnel with a length of 6,800 feet to
develop 30 feet of additional head downstream from the dam
has been incorporated in the design.Detailed design may
indicate that two smaller tailrace tunnels for improved
reliability may be superior to one large tunnel since the
extra cost involved is relatively small.The surge chamber
design would be essentially the same with one or two
tunnels.
The overall dimensions of the intake structure are governed
by the selected diameter and number of the penstocks and the
minimum penstock spacing.Detailed studies comparing
construction cost to the value of energy lost or gained were
carried out to determine the optimum diameter of the
penstocks and the tailrace tunnel.
(f)Environmental Constraints (*)
In addition to potential nitrogen-supersaturation problems
caused by spillway operation,the major impacts of the
Devil Canyon power facilities development are:
o Changes in the temperature regime of the river;and
o Fluctuations in downstream river flows and levels.
Temperature modeling has indicated that a multiple-level
intake design at Devil Canyon would aid in controlling
downstream water temperatures.
Consequently,the intake design at Devil Canyon incorporates
two levels of draw-off.
The Devil Canyon station will normally be operated as a
base-load plant throughout the year to satisfy the
requirement of no significant daily variation in power
flow.
851104 B-2-59
2.5 -Selection of Devil Canyon General Arrangement (*)
The approach to selection of a general arrangement for Devil Canyon was
a similar but simplified version of that used for Watana.
2.5.1 -Selection Methodology (*)
Preliminary alternative arrangements of the Devil Canyon project
were developed and selected using two rather than three review
stages.Topographic conditions at this site limited the
development of reasonably feasible layouts,and four schemes were
initially developed and evaluated.During the final review,the
selected layout was refined based on technical,operational and
environmental considera tions identified during the prel iminary
review.
2.5.2 -Design Data and Criteria (*)
The design data and design criteria on which the alternative
layouts were based are presented in TableB.2.5.i.Subsequent
to selection of the preferred Devil Canyon scheme,the information
was refined and updated as part-of the ongoing study program.
2.5.3 -Preliminary Review (*)
Consideration of the options available for types and locations of
various structures led to the development of four primary
layouts for examination at Devil Canyon in the preliminary review
-..phase-;~-Previous stud±eshad-l-edtoth·e se·lection-··of-a .thin-..
concrete arch structure for the main dam and indicated that the
most acceptable technical and economic location was at the
upstream entrance to the canyon.The dam axis has been fixed in
this location for all alternatives.
(a)Description of Alternative Schemes (*)
The s.ch emes.e'Va luated_.during_theprel im inaryreJdew.are
._..._.__~__~..._described below.In.each of the alternatives evaluated,_
the dam is founded on the sound bedrock underlying the
riverbed.The structure is 635 feet high,has a crest width
of 20 feet,and.a maximum base width of 90 feet.Mass
concrete thrust blocks are founded high on the abutments,
the south block extending approximately 100 feet above the
existing bedrock surface and supporting the upper arches of
the dam.The thrust block on the north abutillerif makes the
cross-river profile of the dam more sYmmetrical andc:on-td.btites .toa more unIfomsEressdIst:rIbtidon.
:[
]
851104 B-2-60
J
851104
(i)Scheme DC1 (Figure B.2.5.1)(*)
.In this scheme,diversion facilities comprise
upstream and downstream earthfill and rockfill
cofferdams and two 24-foot diameter tunnels beneath
the south abutment.
A rockfill saddle dam occupies the lower-lying area
beyond the south abutment running from the thrust
block to the higher ground beyond.The impervious
fill cut-off for the saddle dam is founded on bedrock
approximately 80 feet beneath the existing ground
surface.The maximum height of this dam above the
foundation is approximately 200 feet.
The routed 1:10,000~year design flood of 165,000 cfs
is passed by two spillways.The main spillway is
located on the north abutment.It has a design
discharge of 120,000 cfs,and flows are controlled by
a three-gated.ogee control structure.This
discharges down a concrete-lined chute and over a
flip bucket ,which ejects the water in a diverging jet
into a pre-excavated plunge pool in the riverbed.
The flip bucket is set at el.925,approximately 35
feet above the river level.An auxiliary spillway
discharging a total of 35,000 cfs is located in the
center of the dam,100 feet below the dam crest,and
is controlled by three wheel-mounted gates.The
orifices are designed to direct the flow into a
concrete-lined plunge pool just downstream from the
dam.
An emergency spillway is located in the sound rock
south of the saddle dam.This is designed to pass,
in conjunction with the main spillway and auxiliary
spillway,a probable maximum flood of 345,000 cfs,if
such an event should ever occur.The spillway is an
unlined rock channel which discharges into a valley
downstream from the dam leading into the Susitna
River.
The upstream end of the channel is closed by an
earthfill fuse plug.The plug is designed to be
eroded if ov~rtopped by the reservoir.Since the
crest is lower than either the main or saddle dams,
the plug would be washed out prior to overtopping of
either of these structures.
The underground power facilities are located on the
north bank of the river,within the bedrock forming
B-2-61
851104
the dam abutment.The rock within this abutment is
of better quality with fewer shear zones and a lesser
degree of jointing than the rock on the south side of
the canyon,and hence more suitable for underground
excavation.
The power intake is located just upstream from the
bend in the valley before it turns sharply to the
right into Devil Canyon.The intake structure is set
deep into the rock at the downstream end of the
approach channel.Separate penstocks for each unit
lead to the powerhouse.
The powerhouse contains four 150-MW turbine/generator
.units.The turbines are Francis type units coupled
to overhead synchronous generators.The units are
serviced by an overhead crane running the 'length of
the powerhouse and into the end service bay.
Offices,the control room,switchgear room,
maintenance room,etc.,are located beyond the
service bay.The transformers are housed in a
separate upstream gallery located above ..the lower
horizontal section of the penstocks.Two vertical
cable shafts connect the gallery to the surface.The
draft tube gates are housed above the draft tubes in
separate annexes off·the main powerhall.The draft
tubes converge in two bifurcations at the tailrace
tunnels which discharge under free flow conditions to
,.tlHLrill..eX.Ac..ce..s..s ..t.o_the.po..werhollse.isb..y ..means.of ...
an unlined tunnel leading from an access portal on
the north side of the canyon..
The switchyard is located on the south bank of the
tivet"justdoWnstream from the saddle dam,and the
power cables from the transformers are carried to it
across the top of the dam.
---___.._._.._-_-_..
The layout is generally similar to Scheme DCI except
that the chute spillway is located on the south
side of the canyon.The concrete-lined chute
terminates in a flip bucket high on the south side of
the canyon,dropping the discharge into the river
below.Thedesign.f1ow is 120,000 cis,and discharge
are controlled by ath·tee..;;gatedogee....crested control
structures{niIlarto that ·forScherne DCl;which abuts
the south side thrust block.
B-2-62
.(
../
851104
The saddle dam axis is straight,following the
shortest route between the control structure at one
end and the rising ground beyond the low-lying area
at the other.
(iii)Scheme DC3 (See Figure B.2.5.3)(*)
The layout is similar to Scheme DCl except that the
north-side main spillway takes the form of a single
tunnel rather than an open chute.A two-gated ogee-
control structure is located at the head of the
tunnel and discharges into an inclined shaft 45 feet
in diameter at its upper end.The structure will
discharge up to a maximum of 120,000 cfs.
The concrete-lined tunnel narrows to 35 feet in
diameter and discharges into a flip bucket which
directs the flows in a jet into the river below,as
in Scheme DCl.
An auxiliary spillway is located in the center of the
dam and an emergency spillway is excavated on the
south abutment.
The layout of dams and power facilities are the same
as for Scheme DCl.
(iv)Scheme DC4 (See Figure B.2.5.4)(*).
The dam,power facilities,and saddle dam for this
scheme are the same as those for Scheme DCl.The
major difference.is the substitution of a stilling
basin type spillway on the north bank for the chute
and flip bucket.A three-gated ogee control
structure is located at the end of the dam thrust
block and controls the discharges up to a maximum of
120,000 cfs.
The concrete-lined chute is built into the face of
the canyon and discharges into a 500-foot long by
l15-foot wide by 100-foot high concrete stilling
basin formed below river level and deep within the
north side of the canyon.Central orifices in the
dam and the south bank rock channel and fuse plug
form the auxiliary and emergency spillways,
respectively,as in the other alternative schemes.
The downstream cofferdam is located beyond the
stilling basin and the diversion tunnel outlets are
B-2-63
located farther downstream to enable construction of
the stilling basin.
(b)Comparison of Alternatives (*)
The arch dam,saddle dam,power facilities,and diversion
vary only in a minor degree among the four alternatives.
Thus,the comparison of the schemes rests solely on a
comparison of the spillway facilities •
.As can be seen from a comparison of the costs in Table
B.2.5.2,the flip bucket spillways are substantially less
costly to construct than the stilling basin type of Scheme
DC4.The south-side spillway of Scheme DC2 runs at a sharp
angle to the river and ejects the discharge jet from high on
the canyon face toward the opposite ~ide of the canyon.
Over a longer period of operation,scour of the heavily
jointed rock could.cause undermining of the canyon sides and
their subsequent instability.The possibility also exists
of deposition of material in the downstream riverbed with a
corresponding elevation of the tailrace.Construction of a
spillway on the steep south side of the river could be more
difficult than on the north side because of the presence of
deep fissures and large unstable blocks of rock which are
present on the south side close to the top of the canyon.
The two north-side flip bucket spillway schemes,based on
either an open chute or a tunnel,take advantage of a
..downs.tream..bend..intheriv.erto..di schar.ge .parallelto .the
course of the river.This will reduce the effects of
erosion but could still present a problem if the estimated
m.iiximum possible scour hole should occur.
t'hetunnel type spillway could prove difficult to construct
because of the large diameter inclined shaft and tunnel
paralleling the bedding planes.The high velocities
encountered in the tunnel spillway could cause problems with.·the-possT6ITIty of 'spIralIiig-flows an;r~sever ec·avi.t:atlon··...
The stilling basin type spillway of Scheme DC4 reduces
downstream erosion problems within the canyon.However,
cavitation could be a problem under the high flow velocities
experienced at the base of the chute.This would be
somewhat alleviated by aeration of the flows..There is,
however~little precedent forstilTirigbasin operation at
heads of over 500 feet;even where floods of much less than
the design capacity have been diSCharged,severe damage has
occurred.
I 1
851104 B-2-64
.\
Ij
(c)Selection of Final Scheme (*)
The chute and flip bucket spillway of Scheme DC2 could
generate downstream erosion problems which could require
considerable maintenance costs and cause reduced efficiency
in operation of the project at a future date.Hydraulic
design problems exist with Scheme DC3 which may also have
severe cavitation problems.Also,there is no cost
advantage in Scheme DC3 over the open chute Scheme DC1.In
Scheme DC4,the operating characteristics of a high head
stilling basin are little known,and there are few examples
of successful operation.Scheme DC4 also costs considerably
more than any other scheme (Table B.2.5.2).
All spillways operating at the required heads and discharges
will eventually cause some erosion.For all shemes,the use
of solid-cone valve outlet facilities in the lower portion
of the dam to handle floods up to 1:50 -year frequency is
considered a more reasonable approach to reduce erosion and
eliminate nitrogen supersaturation problems than the gated
high-level orifice outlets in the dam.Since the cost of
the flip bucket type spillway in the scheme is considerably
less than that of the stilling basin in Scheme DC4,and
since the latter offers no relative operational advantage,
Scheme DCl has been selected for further study as the
selected scheme.
2.5.4 -Final Review (*)
The layout selected in the previous section was further developed
in accordance with updated engineering studies and criteria.
The major change compared to Scheme DCl is.the elimination of the
high-level gated orifices and introduction of low-level
fixed-cone valves,but other modifications that were introduced
are described below.
The revised layout is shown on Figure B.2.5.5.A description of
the structures is as follows.
(a)Main Dam (*)
The maximum operating level of the reservoir was raised to
el.1,455 in accordance with updated information relative
to the Watana tailwater level.This requires r~ising the
dam crest to el.1,463 with the concrete parapet wall crest
at el.1,466.The saddle dam was raised to el.1,472.
(b)Spillways and Outlet Facilities (*)
To eliminate the potential for nitrogen supersaturation
problems,the outlet facilities were designed to restrict
851104 B-2-65
\'
supersaturated flow to an average recurrence interval of
greater than 50 years.This led to the replacement of the
high-level gated orifice.spil:J.way by outlet facilities
incorporating seven fixed-cone valves,three with a diameter
of 90 inches and four wi.th a diameter of 102 inches,capable
of passing a design flow of 38,500 cfs.
The chute spillway and flip bucket are located on the north
bank,as in Scheme DCl;however,the chute length was
decreased and the elevation of the.flip bucket raised
compared to Scheme DCl.
More recent site surveys indicated that the ground surface
in the vicinity of the saddle dam was lower than originally
estimated.The_emergency spillway channel was relocated
slightly""to the south to accommodate the larger dam.
(c)Diversion (*)
The prevtous twin diversiqn tunnels were replaced by a
single tunnel scheme.This was determined to provide all
necessary security and will cost approximately one-half as
much as the.two tunnel alternative.
"J
(d)Power Facilities (*)
The drawdown range of the reservoir was reduced,allowing
a reduction in height of the power intake.In order to
.1ocate.the--intake-wi-th-in--so-l-id--rock,·-it:·has-·been .move d into'"
the side of.the valley,requiring a slight rotation of the
water passages,powerhouse,and caverns comprising the power
fad lides.
Subsequent to the adoption oftflis schetne and-prior to
submission of the July 1983 License Application,refinements
to the design were made as presented in Exhibit F.
_,._--_._..•-~----,_._,.._.----_-_.-,.__._--_.•._,-.._-__.-..__..---.__._--._.,..-.
•....Am.endlllent to License Application (***)
The amended layout of Devil Canyon (Stage II)is presented in
Figure B.2.3.ll.This eliminates the emergency spillway and
increases the discharge capacity of the chute spillway and flip
.bucket to pass the rout~d PMF.This revis.ion will reduce cost of
the development and reduce terrestrial and .aesthetic impacts by
...reducing ground surface disturbance.
The capacity of the spillway will be increased by providing
larger gates and increasing the width of the chute and flip
851104 B-2-66
851104
I
bucket.Each of the three gates will be increased from 30 feet
wide by 56 feet high to 48 feet wide by 58 feet high.
The chute width,which varied from 122 feet to 80 feet,will be
increased to vary from 176 feet to 150 feet.The flip bucket
width will be increased from 80 feet to 150 feet wide.The crest
of the spillway control structure will be lowered from el.1,404
to el.1,398.
The type of gate and operator will be revised from fixed wheel
gate with electric motor driven drum hoist to tainter gate with
hydraulic cylinder hoist.The gate type revision will cost less
and provide improved operating cha~acteristics.
The flood hydrology for the higher frequency floods has been
reevaluated based on additional years of records.The peak
inflows for the 1:25 and 1:50 year floods routed through Watana
(Stage I)reservoir and the intervening flow are,respectively
43,300 and 46,900cfs.
The impact of this change will be principally on the construction
diversion,requiring the tunnel diameter to be increased from 30
feet to 35.5 feet while maintaining the upstream cofferdam crest
at elevation 945.This solution is conservative and during the
design phase optimization studies will be made to determine the
optimum cofferdam height versus tunnel diameter.
The outlet facilities of three 90-inch and four 102-inch fixed
cone valves operating at an 80 percent opening are capable of
passing the 1:50 year flood without surcharging the reservoir
above Elevation 1,456.
2.6 -Selection of Access Road Corridor (*)
2.6.1 -Previous Studies (*)
The potential for hydroelectric power generation within the
Susitna basin has been the subject of considerable
investigation over the years,as described in Section 1.1 of this
exhibit.These studies produced much information on alternative
development plans but little on the question of access.
The first report to incorporate an access plan was that of the
Corps of Engineers in 1975.The proposed plan consisted of a 24-
foot wide road with a design speed of 30 miles per hour that
connected with the Parks Highway near Chulitna Station,
paralleled the Alaska Railroad south and east to a crossing of
the Susitna River,then proceeded up the south side of the river
to Devil Canyon.The road continued on the south side of the
Susitna River to Watana,passing by the north end of Stephan Lake
B-2-67
and the west end of the Fog Lakes.In addition,a railhead
facility was to be constructed at Gold Creek.This plan is S1m1-
lar to one of the selected alternative plans,Plan 16 (South),
discussed later in this section.
Other studies concerning the Susitna Hydroelectric Project men-
tioned access only in passing and did not involve the development
of an access plan.
This section of the License Application outlines the studies
carried out asa basis for formulation and selection of the
preferred hydroelectric plans.These studies were conducted over
the period 1979 through 1982 and are based on cost data and load
forecasts from that period of study.These data were analyzed
consistently in each study iteration and the resulting
development plans are the most attractive alte'rnat ives.
2.6.2 -Selection Process Constraints (*)
Throughout the development,evaluation;,and selection of the
access plans,the foremost o~jective has been to provide a
transportation system that would supportconstruc.tion activities
and-allow for-the orderiy deveiopInemi:and'maint-Emance of site
facilities.
Meeting this fundamental objective involved the consideration not
only of economics'and technical re-ase of development,but also
many other diverse factors.Of prime importance was the
potential for impacts to the environment,namely impacts to the
~~tocar-fiSli and~game populations.--~lilaaaition,--sIncetl:ie Native
villages and the Cook Inlet Region will acquire surface and
subsurface rights adjacent to the project,their interests were
recognized and taken into account as were those of the local
communities and general public.
With so many different factors influencing the choice of an
access plan,it is evident that no one plan will satisfy all
interests.,The aim d uringthe ..selec,t:ion-pI'ocesshas-been ··to
consider a_l_Lfa..c_t_o_r_s,_in,_their_prop_er~per,s_pec_tiv_eand_,pr.oduce-a
plan that represents the most favorable solution to meeting both
project-'related goals and minimizing impacts to the environment
and surrounding communities.
2.6.3 -Corridor Identification and Selection (*)
'three generai corridor'swere iden'tified leading fr~m the existing
____.!=!,~!l,~PQ:C:~?l:iQ:9..n~l:wo:r:t<:tothe<ialI1si te.s..This network cons i st s
of the Parks Highway and the Alaska Railroad to the west of the
damsites and the Denali Highway to the north.The three general
corridors are identified in Figure B.2.6.L
,j
1
"1
'I
851104 B-2-68
Corridor 1 -From the Parks Highway to the Watana damsite via the
north side of the Susitna River.
Corridor 2 -From the Parks Highway to the Watana damsite via the
south side of the Susitna River.
Corridor 3 -From the Denali Highway to the Watana damsite.
The access road studies identified a total of eighteen alternative
plans within the three corridors.The alternatives were developed
by laying out routes on topographic maps in accordance with
accepted road and rail design criteria.Subsequent field
investigations resulted in minor modifications to reduce
environmental impacts and improve alignment.
2.6.4 -Development of Plans (*)
At the beginning of the study a plan formulation and initial
selection process was developed.The criteria that most
significantly au:£ected the initial selection process were
identified as:
o Minimizing impacts on the environment;
o Minimizing total project costs;
o Providing transportation flexibility to minimize
construction risks;and
o Providing ease of operation and maintenance.
During evaluation of the access plans,input from the public
agencies and Native organizations was sought and their response
resulted in an expansion of the original list of eight
alternative plans to eleven.These studies culminated in the
production of the Access Route Selection Report (Acres 1982b)
which recommended Plan 5 as the route which most closely
satisfied the selection criteria.Plan 5 starts from the Parks
Highway near Hurricane and traverses southeast along the Indian
River to Gold Creek.From Gold Creek the road continues east on
the south side of the Susitna River to the Devil Canyon damsite,
crosses a low-level bridge and continues east on the north side
of the Susitna River to the Watana damsite.For the project to
remain on schedule it would have been necessary to construct a
pioneer road along this route to facilitate bridge construction
prior to the FERC license being issued.
In March of 1982 the Alaska Power Authority (APA)presented the
results of the Susitna Hydroelectric Feasibility Report (Acres
1982c),of which access Plan 5 was a part,to the public,
agencies and organizations.During April,comment was obtained
from these groups relative to the feasibility study.As a result
of these comments,the pioneer road concept was eliminated,the
851104 B-2-69
evaluation criteria were refined,and six additional access
alternatives were developed.
During the evaluation process the Applicant formulated an
additional plan,thus increasing the total number of plans under
evaluation to eighteen.This subsequently became the plan
recommended by Applicant's staff to the Applicant's Board of
Directors,and was formally adopted as the Proposed Access Plan
in September 1982.
2.6.5 -Evaluation of Plans (*)
The refined criteria used to evaluate the eighteen alternative
access plans were:
o No pre-license construction
o Minimize environmental impacts
o Minimize construction duration
o Provide access·between sites during project operation
phase
o Provide access flexibility to ensure project is brought on
line within budget and schedule
o Minimize total cost of access
o Minimize initial investment required to provide access to
the Watana damsite
o Minimize.risks to project schedule t.
o Accommodate current land uses and plans
o Accommodate agency preferences
o Ac:(:~g'J.!l!ll()dat;~·"Rr~:l:e~~I!~_~~.QJl'1at:ive organizations
o Accommodate preferences of loc~l communities
o Accommodate public concerns
All eighteen plans were evaluated using these refined criteria to
determine the most responsive access plan in··each of the"three
basic corridors.
To meet the overall project schedule requirements for the Watana
··_··_'-··-·deve-Iopment;···it··-is·-neces·sary--··t·(f·-secure i"iriHaracc·e~fs-to th-e---
.----.------·--Wa"t-a·na~damsi-te-wi-th·in-one-con·st·ruc-tron-s·e-a·son-or-the-FERC--I-ic-ens-e--
being issued.The con~traint of no pre-license construction
resulted in the elimination of any plan in which initial access
could not be completed within one year.This constraint
eliminated six plans (plans 2,5,8,9,10,12)from further
consideration.
On completion of boththeWatan~andDevilC~nyonDamsCitis
·plariried-tOopera.t-e·and~II1ailit:a.inbothsite:s:fr()mone·central
location,Watana.To facilitate these operation and maintenance
activites,access plans with a road connection between the sites
were considered superior to those plans without a road
I 1
.\
851104 B-2-70
1
1
connection.Plans 3 and 4 do not have access between the sites
and were discarded.
The ability to make full use of both rail and road systems from
southcentral ports of entry to the railhead facility provides the
project management with far greater flexibility to meet
contingencies;and control costs and schedule.Limited access
plans utilizing an all-rail or rail-link system with no road
connection to an existing highway have less flexibility and would
impose a restraint on project operation that could result in
delays and significant increases in cost.Four plans with
limited access (plans 8,9,10 and 15)were eliminated because of
this constraint.
Residents of the Indian River and Gold Creek communities are
generally not in favor of a road access near their communities.
Plan 1 was discarded because plans 13 and 14 achieve"the same
objectives without impacting the Indian River and Gold Creek
areas.
Plan 7 was eliminated because it includes a circuit route
connecting to both.the George Parks and Denali Highways.This
circuit route was considered unacceptable by the resource
agencies since it aggravated the control of public access.
The seven remaining plans found to meet the selection criteria
were plans 6,11, 13, 14, 16,17 and 18.Of these plans,plans
13,16 and 18 in the North,South,and Denali corridors,
respectively,were selected as being the most responsive plan in
each corridor.The three plans are described below and the route
locations shown in Figures B.2.6.2 through B.2.6.4.
(a)Plan 13 'North'(see Figure B.2.6.2)(*)
This plan utilizes a roadway from a railhead facility
adjacent to the George Parks Highway at Hurricane to the
Watana damsite following the north side of the Susitna
River.A spur road,seven miles in length,would be
constructed at a later date to service the Devil Canyon
development.This route is mountainous and includes terrain
at high elevations.In addition,extensive sidehill cutting
in the region of Portage Creek will be necessary;however,
construction of the road would not be as difficult as under
plan 16.
(b)Plan 16 'South'(see Figure B.2.6.3)(*)
This route generally parallels the Susitna River,traveling
west to east from a railhead at Gold Creek to the Devil
851104 B-2-71
Canyondamsite,and continues following a southerly loop to
the Watana damsite.Twelve miles downstream of the Watana
damsite a temporary low-level crossing of the Susit~a River
will be used until completion of a permanent bridge.A
connecting road from the George Parks Highway to Devil
Canyon with a major high-level bridge across the Susitna
River is necessary to provide full road access to either
site.The topography from Devil Canyon to Watana is
mountainous and the route involves the most difficult
construction of the three plans,requiring a number of
sidehill cuts and the construction of two major bridges.To
provide initial access to the Watana damsite this route
presents the most difficult construction problems of the
three routes and has the highest potential for schedule
delays and related cost increases.
(c)Plan 18 'Denali-North '.(see-Figure B.2.6.4)(*)
This route originates at a railhead in Cantwell,utilizing
the existing Denali Highway to a point 21 miles east of
the junction of the George Parks and Denali Highways.A new
road will be constructed from this point due south to the
Watana da1l'lsite.The majority of the new roa.d win traverse
relatively flat terrain which will allow construction using
side borrow techniques,resulting in a minimum of
disturbance to areas away from the alignment..This is the
most easily constructed"route for initial"access to the
Watana site.Access to the.Devil Canyon development will
consist primarily of a railroad extension from the existing
AlasKaRaiTroadatGoTdCree1f--to-ci-raiTlieadfaci-n ty ----
adjacent to the Devil Canyon camp area.To provide access
to the Wat~na damsite and the existing highway system,a
connecting road will be constructed from the Devil Canyon
railhead following a northerly loop to the Watana damsite.
Access to the north side of the Susitna River will be
attained via_a high-level suspension bridge constructed
approximately one mile downstream of the Devil Canyon Dam.
----In-genera-l-,---the--al-ignment-c:t;'oss.e s---ter:t;'ain--with-gent 1e -to
____...._.__~~~mo_d_er_a_t_e_sLo_p_es __w:hic1Lwill_.aliow.....r.oadbed_cons.truction
without deep cuts.
2.6.6 -Comparison of the Selected Alternative Plans (*)
To determine which access plan best accommodates both project-
related goals and the concerns of the resource agencies,Native
organizations,andaffectedocommunities,thethreeselected
C1lt~I'Ilative ••pl.9.nsW~I'~s1Jb j ec:teel.f:o ~lll1J:lf:i-cl:i,$c:ip:litl~lrY
evaluation and comparison.The key issues addressed in this
evaluation and comparison were:
,]
!j
j
-----~85-a-04-----------B-2-72
(a)Costs (*)
For the development of access to the Watana site,the
Denali-North Plan has the least cost and the lowest
probability of increased costs resulting from unforeseen
conditions.The North Plan is ranked second.The North
Plan has the lowest overall cost while the Denali-North has
the highest.However,a large portion of the cost of the
Denali-North Plan would be incurred more than a decade in
the future.When converting costs to equivalent present
value,the overall costs of the Denali-North and the South
Plans are approximately equal.The costs of the three
alternative plans can be summarized as follows:
Estimated Total Cost ($x 10 6 )
Plan Watan~Devil Canyon Total Discounted Total
North (13)241
South (16)312
Denali-North (18)224
127
104
213
368
416
437
287
335
326
The costs are in terms of 1982 dollars and include all costs
associated with design,construction,maintenance and-
logistics.
(b)Schedule (*)
The schedule for providing initial access to the Watana site
was given prime cons~deration since the cost ramifications
of a schedule delay are highly significant.The elimination
of pre-license construction of a pioneer access road has
resulted in the compression of on-site construction
activities during the initial construction seasons.With
the present overall project scheduling,should diversion not
be completed prior to spring runoff in the fourth
construction season,dam foundation preparation work will be
delayed one year and hence cause a delay to the overall
project of one year.It has been estimated that the
resultant increase in cost would likely be in the range of
100-200 million dollars.The access route that assures the
quickest completion and hence the earliest delivery of
equipment and material to the site has a distinct advantage.
The forecasted construction period,including mobilization,
for the three plans is:
851104
o Denali-North
o North
o South
B-2-73
6 months
9 months
12 months
It is evident that,with the Denali-North Plan,site
activities can be supported at an earlier date than by
either of the other routes.Consequently the Denali-North
Plan offers the highest probability of meeting schedule and
hence the least risk of project delay and increase in cost.
The schedule for access in relation to diversion is shown
for the three plans in Figure B.2.6.5.
(c)Environmental Issues (*)
Outlined below are the key environmental impacts which have
been identified for the three routes.The specific
mitigation measures necessary to avoid,minimize or
compensate for these impacts are discussed in Exhibit E.
(i)Wildlife and Habitat (*)
The three selected alternative ~ccess routes are made
up of five distinct wildlife and habitat segments:
o Hurricane to Devil Canyon (Segment 1):This
segment is composed almost entirely of
productive mixed forest,riparian,and
wetlands habitats important to moose,
furbearers,and birds.It includes three areas
where slopes of over 30·percent will require
side hill cuts,all above wetland zones
vulnerable to erosion-related tDpacts.
,Ir .
~.~_.-~-~--
o Gold Creek to Devil Canyon (Segment 2):This
segment is composed of mixed forest and wetland
habitats,but includes less wetland habitat and
fewer wetland habitat types than the Hurricane
to Devil Canyon segment.Although this segment
contains habitat suitable for moose,black
bears,furbearers and birds,it has the least
potential for adverse impacts to wildlife of
the·~five ·"seglrien"tsconsIdered:~.-.~
o Devil Canyon to Watana (North Side)(Segment 3):
The following comments apply to both the
Denali-North and North routes.This segment
traverses a varied mixture of forest ,shrub,
and tundra habitat types,generally of
meditnn....to-~lowproductivity~as ·wildlife habitat.
However,it crosses the Devil and Tsusena Creek
drainages,which are 1mporfarit moose arid brown
bear habitat.
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851104 B-2-74
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o Devil Canyon to Watana (South Side)(Segment 4):
This segment is highly varied with respect to
habitat types,containing complex mixtures of
forest,shrub,tundra,wetlands,and riparian
vegetation.The western portion is mostly
tundra and shrub,with forest and wetlands
occurring along the eastern portion in the
vicinity of Prairie Creek,Stephan Lake,and
Tsusena Creek.Prairie Creek supports a very
high seasonal concentration of brown bears and
the lower Tsusena Creek area supports
concentrations of moose and black bears.The
Stephan Lake area also supports relatively high
densities of moose and bears.In addition to
habitat·loss or alteration and increased
hunting,significant human-bear conflicts would
probably result from access development in this
segment.
o Denali Highway to Watana (Segment 5):This
segment is primarily composed of shrub and
tundra vegetation types,with little productive
forest habitat present.Although habitat
diversity is relatively low along this segment,
the southern portion along Deadman Creek
contains important brown bear habitat and
browse for moose.This segment crosses a
peripheral portion of the range of the Nelchina
caribou herd which is occupied by a subherd
that uses the area year-round including during
calving.Althou~it is not possible to
predict with any certainty how the physical
presence of the road itself or traffic will
affect caribou movements,population size,or
productivity,it is likely that a variety of
site-specific mitigation measures will be
necessary to protect the herd.
The three access plans are made up of the
following combinations of wildlife habitat
segments:
North
South
Denali-North
Segmen ts 1 and 3
Segments 1,2,and 4
Segments 2,3,and 5
851104
The North route has the least potential for
creating adverse impacts to wildlife and
habitat,for it traverses or approaches the
fewest areas of productive habitat and zones of
B-2-75
species concentration or movement.The
wildlife impacts of the South Plan can be
expected to be greater than those of the North
Plan due to the proximity of the route to
Prairie Creek,Stephan Lake and the Fog Lakes,
which currently support high densities of moose
and black and brown bears.In particular,
Prairie Creek seasonally supports what may be
the highest concentration of brown bears in the
Susitna basin.Although the Denali-North Plan
has the potential for disturbances of caribou,
brown bear and black bear concentrations and
movement zones,it is considered that the
potential for adverse impacts with the South
Plan is greater.
(ii)Fi.sheries (*)
All three alternative routes would have direct and
indirect impacts on the fisheries.Direct impacts
include the effects on water quality and aquatic
habJtat wl1~I:'eas jncreased angling pressure is an
indirect impact.A qualitative comparison of the
fishery impacts related to the alternative plans was
undertaken.The parameters used to assess impacts
along each route included:the numbe.r,of streams
crossed,the number and length of lateral transits
(i.e.,where the roadway parallels the streams and
runoff from the roadway can run directly into the-stream);~thenumberorwa'terstiecfsaffected;and the
presence of resident and anadromous fish.
The three access plan alternatives incorporate
combinations of seven distinct fishery segments:
o Hurricane to Devil Canyon (Segment 1):Seven
stream crossings will be required along this
"route,including·rndianRiverwhich-is an···
.-~-..~.-~.~~-----~_-.--~----~-impor-t·an.r.--sa-lmon-s.pa~·m-i-ng--r-i~v:e·r-.-···~Bot-h-·t-he·-
Chulitna River watershed and the Susitna River
watershed are affected by this route.The
increased access to Indian River will be an
important indirect impact to the segment.
Approximately 1.8 miles of cuts into banks
greaf:En:tl1.ag3Q.degrees occur along this route
requiring erosion control measures to preserve
.thewater..quality--al1d aquatic habitat.
o Gold Creek to Devil Canyon (Segment 2):This
segment would cross six streams and is expected
851104 B-2~76 J
to have minimal direct and indirect impacts.
Anadromous fish spawning is limited to the
lower reaches of Jack Long Creek,the tributary
to Slough 21 at road corridor mile 43.3,
Waterfall Creek,and Gold Creek (ADF&G 1984a).
Approximately 2.5 miles of cuts into banks
greater than 30 degrees occur in this section.
In the Denali North Plan this segment would be
railroad,whereas in the South Plan it would be
road.
o Devil Canyon toWatana (North Side,North
Plan)(Segment 3):This segment crosses twenty
streams and laterally transits four rivers for
a total distance of approximately 12 miles.
Seven miles of this lateral transit parallels
Portage Creek,which is an important salmon
spawning area.
o Devil Canyon to Watana (North .Sider,-
Denali-North Plan)(Segment 4):The difference
between this segment and segment 3 described
above is that it avoids Portage Creek by
traversing through a pass.4.miles to the east.
The number of streams crossed is consequently
reduced to twelve,and the number of lateral
transits is reduced to two'with a total
distance of 4 miles.
o Devil Canyon to Watana (South Side)(Segment 5):
The portion between the Susitna .River crossing
and Devil Canyon requires nine steam crossings,
but it is unlikely that these contain
significant fish populations.The portion of
this segment from Watana to the Susitna River
is not expected to have any major direct
impacts;however,increased angling pressure in
the vicinity of Stephan Lake may result due to
the proximity of the access road.The segment
crosses both the Susitna and the Talkeetna
watershed.Seven miles of cuts into banks of
greater than 30 degrees occur in this segment.
o Denali Highway to Watana (Segment 6):The
segment from the Denali Highway to the Watana
damsite has twenty-two stream crossings and
passes from the Nenana into the Susitna
watershed.Much of the route crosses or is in
proximity to seasonal grayling habitat and runs
parallel to Deadman Creek for nearly 10 miles.
If recruitment and growth rates are low along
this segment,it is unlikely that resident
populations could sustain heavy fishing
pressure.Hence,this segment has a high
potential for impacting the local grayling
population.
o Denali Highway (Segment 7):The Denali Highway
from Cantwell to the Watana access turnoff will
require upgrading.The upgrading will involve
only minor realignment and negligible
alteration to present stream crossings.The
segment crosses eleven streams and laterally
transits two rivers for a total distance of 5
miles.There is no anadromous fish spawning in
this segment and little direct or indirect
impact is ,expected.
The three alternative access routes comprise the
following fisheries segments:
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o North
o South
o Denali-North
Segments I and 3
Segments 1,2,and 5
Segments 2,4,6 and 7
The Denali-North Plan is likely to have both direct
and indirect impacts on grayling fisheries given the
number of stream crossings,lateral transits,and
......water:sheds affected ...Anadromousg.!!herj.,es.._~mpac t~..
will be minimal and will only be of concern along the
railroad spur between Gold Creek and Devil Canyon.
The South Plan is likely to create significant direct
and indirect impacts at Indian River,which is an
important salmon spawning river.Anadromous
fisheries impacts may also occur in the Gold Creek to
Devil Canyon segment,as for the Denali-North Plan.
-------Io"-additi-orr,-indirect-impacts-may'occur in .the
.._--._-_..._~.."--·_--·-S-t;-eph-an-r.ake--a·rea-.-·_.._·-_....
]
851104
The North Plan,like the South Plan,may impact
salmon spawning activity in Indian River.Direct
impacts may occur along Portage Creek due to
temporary water quality changes through increased
erosion;indirect impacts,such as increased angling
pressure,could also occur.
With any of the selected plans,direct and indirect
effects can be minimized through proper engineering
design and prudent management.Criteria for the
B-2-78 .1
{J
development of borrow areas and the design of bridges
and culverts for the proposed access plan t0gether
with mitigation recommendations are discussed in
Exhibit E.
(d)Cultural Resources (**)
A preliminary evaluation of the relative cultural resources
sensitivity of the three access plans was made.This
consisted of a review of relevant literature and information
on previously recorded sites in the general area,and a
flyover of the three routes by archeologists.Random ground
checks were made during the course of the latter.The
Denali-North plan,because of its greater overall length and
its location parallel to Deadman Creek,is believed to have
the greatest potential for impacting archeological sites.
the South Plan,although it traverses less archeologically
sensitive terrain than the North Plan,by virtue of its
greater length,is believed to have a greater potential for
impacting acheological resources than the latter plan.The
ranking from the least to the highest with regard to
cultural resources impacts is therefore South,North,and
Denali-North.
Impacts on archeological sites can to be adequately
mitigated by avoidance or data recovery;consequently,this
issue is not critical to the selection process.It should
be noted,however,the less forested nature of the terrain
along the Denali-North and portions of the North Plan would
allow for more efficient identification of cultural·
resources in these areas than along the more forested Sout~
Route during pre-construction surveys.
(e)Socioeconomics (0)
Socioeconomic impacts on the Mat-Su Borough as a whole would
be similar in magnitude for all three plans.However,
each of the three plans affects future socioeconomic
conditions in differing degrees in certain areas and
communities.The important differences affecting specific
communities are outlined below.
(i)Cantwell (0)
The Denali-North Plan would create substantial
increases in population,local employment,business
activity,housing and traffic.These impacts result
because a railhead facility would be located at
Cantwell,and because Cantwell would be the nearest
community to the Watana damsite.Both the North and
851104 B-2-79
South Plans would impact Cantwell to a far lesser
extent •.
(ii)Hurricane (0)
The North Plan would substantially affect the
Hurricane area since currently there is little
population,employment,business activity or housing.
Socioeconomic impacts for Hurricane would be less
under the South Plan and considerably less under the
Denali-North Plan.
(iii)Trapper Creek and Talkeetn~(0)
Trapper C~eek would experience slightly greater
changes in economic indicators with the North Plan
than under the South or Denali-North Plans.The
South Plan would impact the Talkeetna area slightly
more than the other two plans.
(iv)Gold Creek (*)
With the South Plan,a railhead facility would be
developed at Gold Creek,creating significant
socioeconomic impacts in this area.The Denali-North
Plan includes construction of a railhead facility at
the Devil Canyon site,which would create impacts at
Gold Creek,but not to the same extent as with the
····_--Sou~hP·lan·.·--·M·inimal--impacts.would-resul ~in-Gold·
Creek under the North Plan.
(f)Preferences of Native Organizations (*)
The Cook Inlet Region Inc.(CIRI)and mosto£il:s
associated village corporations all prefer the South Plan
since it provides full road access to their lands south of
.........__.th~..§..t1~tl:!l.C1J~.iY~!:.!.....M:r.nf4.,..J:!lC ....l!!l(L!;h~_<;:;1!!lJ:.w~11YiJJ~g~
Corporation support the Denali-North Plan.None of the
Native organizations supports the North Plan •._....-.......
(g)Relationship to Current Land Stewardships,Uses
and Plans (**)
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851104
As described in Exhibit E,Chapter 9,much of the land
required for project devE!lopment ha.sbeen or may be
conveyed to Na.tive organizations.·.The remaining lands are
generally undersl:al:e'and federal Conl:roLTJieSoul:h'Plan
traverses more Native-selected lands than either of the
other two routes,and Native organizations have expressed an
B-2-80
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851104
IJ
interest in potentially developing their lands for mining,
recreation,forestry or residential use.
The other land management plans that have a large bearing on
access development are the Bureau of Land Management's (BLM)
recent decision to open the Denali Planning Block to mineral
exploration,and the Susitna Area Plan.In general,none of
the plans would be in major conflict with any present
federal,borough or Native management plans.
2.6.7 -Summary (0)
In reaching the decision as to which of the three alternative
access plans would be recommended,it was necessary to evaluate
the highly complex interplay that exists between the many issues
involved.Analysis of the key issues indicates that no one plan
satisfied all the selection criteria nor accommodated all the
concerns of the resource agencies,Native organizations and the
public.Therefore,it was necessary to make a rational
assessment of trade-offs between the sometimes conflicting
environmental concerns of impacts on fisheries,wildlife,
socioeconomics,land use and recreational opportunities on the
one hand,with project cost,schedule,construction risk and
management needs on the other.With all these factors in mind,
it should be emphasized that the primary purpose of access is to
provide and maintain an uninterrupted flow of materials and
personnel to the damsite throughout the life of the project.
Should this funda~ental objective not be achieved,significant
schedule and budget overruns will occur.
2.6.8 -Final Selection of Plan (0)
(a)Elimination of 'South Plan'(0)
The South route,Plan 16,was eliminated primarily because
of the construction difficulties associated with building
a major low-level crossing 12 miles downstream of the Watana
damsite.This crossing would consist of a floating or fixed
temporary bridge which would need to be removed prior to
spring breakup during the first ~hree years of the project
(the time estimated for completion of the permanent bridge).
This would result in a serious interruption in the flow of
materials to the site.Another drawback is that floating
bridges require continual maintenance and are generally
subject to more weight and dimensional limitations than
permanent structures.
A further limitation of this route is that for the first
three years of the project all construction work must be
supported solely from the railhead facility at Gold Creek.
B-2-81
This problem arises because it will take an estimated three
years to complete construction of the connecting road across
the Susitna River at Devil Canyon to Hurricane on the George
Parks Highway.Limited access such as this does not provide
the flexibility needed by the project management to meet
contingencies and control costs and schedule.
Delays in the supply of materials to the damsite,caused by
either an interruption of service of the railway system or
the Susitna River not being passable during spring breakup,
could result in significant cost impacts.These factors,
together with the"realization that the South Plan offers no
specific advantages over the other two plans in any of the
areas of environmental "or social concern,led to the South
Plan being eliminated from further consideration.
(b)Schedule Constraints (*)
The choice of an access plan thus narrowed down to the North
and Denali-North plans.Of the many"issues addressed
during the evaluation process,the issue of "schedule"and
"schedule risk"was determined to be the most important in
the final selection of the recommended plan.
Schedule plays an extremely important role in the evaluation
process because of the special set of conditions that exist
in a sub-arctic environment.Building roads in these
regions involves the consideration of many factors not found
in_other~_en"Vironment:s.~--Specificacl.ly~,~the--ch-iecf~conce~n -·is-
one of weather,and the consequent short duratio~of the
construction season.The roads for both the North and
Denali-North Plans will,for the most part,be constructed
at elevations in excess of 3,000 feet.At these elevations
the likely time available for uninterrupted construe tion in
a typical year is 5 months,and at most 6 months.
The forecasted construction period including mobilization is--....__.-~,_._-..----_._-----,----,-_._-----_._--.,---.-------~.·-6---monEh-s-~~--for-·---:·-Eli-e~-De'n'a-i-'i=··Nor-th p'I-aii~an'd-'-'-'~r-'month-s---'fo--r------t-il"e-~"----
----------"""NOI'"Elf-;;--Atfi r s cgTancea-------'---dTHerence inscneQ1.iTeof3·monEns
does not seem great;however,when considering that only 6
months of the year are available for construction,the addi-
tional 3 months become highly significant.
If diversion is not achieved prior to spring runoff in the
- -·-fourth year -ofconstruction,-dam-foundation--preparation work
will be delayed one year,and hgnce ca~sg a gelay to the
overall project of one year ~"
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851104 B-2-82
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(c)Cost Impacts (0)
The increase in costs resulting from a one-year delay have
been estimated to be in the range of 100-200 million
dollars.This increase includes the financial cost of
investment by the date of scheduled river diversion,the
financial costs of rescheduling work for a one-year delay,
and replacement power costs.
(d)Summary (*)
The Denali-North Plan has the highest probability of meeting
schedule and least risk of increase in project cost for
two reasons.First,it has the shortest construction
schedule (six month~).Second,a passable route could be
constructed even under winter conditions due to the
relatively flat terrain along its length.In contrast the
North route is mountainous and involves extensive sidehill
cutting,especially in the Portage Creek Area.Winter
construction along sections such as this would present major
problems and increase the probability of schedule delay.
1
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(e)
(f)
Plan Recommendation (0)
It is recommended that the Denali-North route be selected so
as to ensure completion of initial access to the Watana
damsite as soon as possible after receipt of a project
license,for it is considered that the risk of significant
cost overruns is too high with any other route.
Environmental Concerns -Recommended Plan (*)
The main disadvantage of the Denali-North route is that it
has a higher potential for adverse environmental impacts
than the North route alternative.These impacts have been
identified and,following close consultation with environ-
mental subconsultants,many of the impacted areas have been
avoided both by careful alignment of the road and the
development of design criteria which do not detract from the
semi-wilderness character of the area.Some environmental
impacts and conflicts are unavoidable,however,and where
these impacts occur,specific mitigation measures have been
developed to reduce them to a minimum.These measures are
outlined in detail within the relevant sections of
Exhibit E.
2.7 -Selection of Transmission Facilities (0)
The objective of this section is to describe the studies performed to
select a power delivery system from the Susitna River basin
851104 B-2-83
generating plants to the major load centers in Anchorage and Fairbanks.
This system will comprise transmission lines,substations,a dispatch
center,and means of communications.
The major topics of the transmission studies include:
o Electric system studies,
o Transmission corridor selection,
o Transmission route selection,
o Transmission towers,hardware and conductors,
o Substations,and
o Dispatch center and communications.
2.7.1 Electric System Studies (0)
Transmission planning criteria were deve10ped~to ensure the
design of a reliable and economic electrical power system,with
components rated to allow a smooth transition through early
project stages to the ultimate developed potential.
Strict application of optimmn,long-term criteria woulcI-.orequire
the installation of equipment with ratings larger than necessary,
at excessive cost.In the interest of economy and long-term
system performance,these criteria were temporarily relaxed
during the early development stages of the project.Although
allowing for satisfactory operation during early system
development,final system parameters must be based on the
ultimate Susitna potential.
The criteria are intended to ensure maintenance of rated power
flow to AnchClrage .ailc!Fairbanks during the outage .of any single
line or transformer element.The essential features of the
criteria are:
o Total power output of Susitna to be delivered to one or two
stations at Anchorage and one at Fairbanks;
o Overvoltages during line energizing not to exceed specified
limits;
o System vol tages to be within .established limits during
normal operation;
o Power delivered to the loads to be maintaLned and system
vol t:ages tabe kept:withines tablished limits for system
operation under emergency conditions;
·1
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851104 B-2-84
o Transient stability during a 3-phase line fault cleared by
breaker action with no reclosing;and
o Where performance limits are exceeded,the most
cost-effective corrective measures are to be taken.
(a)Existing System Data (*)
Data compiled in a report by Acres (1982c)have been used
J for preliminary transmission system analysis.Other system
,I.data were obtained in the form of single line diagrams from
the various utilities.
(b)Power Transfer Requirements (**)
The Susitna transmission system mtistbe designed to ensure
the reliable transmission of power and energy generated by
the Susitna Hydroelectric Project to the load centers in the
Rai1belt area.The power transfer requirements of this
transmission system are determined b~the following
factors:
o System demand at the various load centers;
o Generating capabilities~at the Susitna project;and
o Other generation available in the Rai1belt area
system •
The electric load demand in the Railbel~area is located in
two main centers:Anchorage and Fairbanks.The largest
load center is Anchorage,with most of its load concentrated
in the Anchorage urban area.The second largest load center
is'Fairbanks.Two small load centers (Willow and Healy)are
located along the Susitna transmission route.The
Glennallen-Valdez load center is not planned to be inter-
connected with the Railbelt nor to be served by the Susitna
project.It is therefore excluded from disscusion in this
License Application.
A survey of past and present load demand levels as well as
forecasts of future trends indicates these approximate load
levels at the two load centers:
851104
Load Area
Anchorage -Cook Inlet
Fairbanks Tanana Valley
B-2-85
Percent of
Total
Railbelt Load
83
17
Accordingly,it has been assumed for study purposes that
about 83 percent of the generation at Susitna will'be trans-
mitted to the Anchorage area and 17 percent to Fairbanks.
The potential of the Susitna Hydroelectric Project is
expected to be developed in three stages as the system load
grows over the next three decades.The transmission system
must be designed to serve the ultimate Susitna development,
but staged to provide reliable transmission at every
intermediate stage.Present plans call for three stages of
Susitna capacity additions:360 MW installed at Watana in
1999,600 MW at Devil Canyon in 2005,and an additional 660
MW at Watana in 2012.The 660 MW addition at Watana Stage
III reflects two additional units at 170 MW each (340 MW),
plus an incremental increase in the four existing units of
320 MW due to the increased~ead from the raised dam.
Development o~other generation resources could alter the
geographic load and generation sharing in the Railbelt,
depending on the location of this development.However,
current studies indicate that no other very large projects
are likely to be developed until the full potential of the
Susitna project is utilized.The proposed transmission
configuration and design should,therefore,be able to
satisfy the bulk transmission requirements for at least the
next three decades.The next major generation development
after Susitna will then require a transmission system deter-
mined by its own magnitude and location.
The resulting power transfer requirements for the Susitna
transmission system are indicat~d in Table B.2.7.1.
(c)Transmission Alternatives (*)
J
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Because of the geographic location of the various centers,
transmission from Susitna to Anchorage and Fairbanks will
result in a radial!)ystem configuration.This allows,-sIgnTfIcant-free-dom io-the--c.hoTce -of-transmIssion _.vortages~
_._--~._._-_._..._--_.__._------._._-~----_.-conduc tors,and other parameters for the two Htle--secEions,
with only limited dependence between them.Transmission
alternatives were developed for each of the two system
areas,including voltage levels,number of circuits
required,and other parameters,to satisfy the necessary
transmission requirements of each area.This work is
described by Acres (l982c)in their electrical system
studies closeout report.
851104
To maintain a consistency with standard ANSI voltages used
in other parts of the United States,the following voltages
were considered for Susitna transmission:
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o Watana and Devil Canyon
to Gold Creek and on
to Anchorage:500 kV or 345 kV
o Devil Canyon to Fairbanks:345 kV or 230 kV
(i)Susitna to Anchorage (**)
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(ii )
Transmission at either of two different voltage
levels (345 kV or 500 kV)could reasonably provide
the necessary power transfer capability over the
distance of approximately 132 miles between Gold
Creek and Anchorage.'This transfer capability is
higher than the projected load in year 2020.At 345
kV,either three circuits uncompensated or two cir-
cuits with series compensation are requir'ed to
provide the necessary reliability for the single
contingency outage criterion.At lower voltages,an
excessive number of parallel circuits are required,
while above 500 kV,two circuits are still needed to
provide service in the event of a line outage.
Susitna to Fairbanks (0)
Applying the same reasoning used in choosing the
transmission alternatives to Anchorage,two cir-
cuits of either 230 kV or 345 kV were chosen for the
section from Devil Canyon to Fairbanks.The 23D kV
alternative requires series compensation to satisfy
the planning criteria in case of a line outage.
851104
(iii)Total System Alternatives (*)
The transmission system alternatives mentioned above
were combined into five realistic total system
alternatives.Three of the five alternatives have
different voltages for the two sections.The
principal parameters of the five transmission system
alternatives analyzed in detail are as follows:
B-2-87
Susitnato Anchorage Susitna to Fairbanks
Number of Number of
Alternative Circuits Voltage Circuits Voltage
.~(kV)(kV)
1 2 345 2 345
J233452345
3 2 345 2 230
4 3 345 2 230 -}5 2 500 2 230
Electric system analyses,including simulations of
line energizing,load flows of normal and emergency
operating conditions,and transient stability per-
formance,were carried out to determine the technical
feasibility of the various alternatives.An economic
comparison of transmission system life cycle costs
was carried out to evaluate the relative economic
merits of each alternative.All five transmission
alternatives were found to have acceptable
performance characteristics.The'most significant
difference was that single-voltage systems (345 kV,
Alternatives 1 and 2)and systems without series
compensation (Alternative 2)offered reduced
complexity of design and operation and therefore were
likely to be marginally more reliable.The present
worth life cycle costs of Alternatives 1 through 4
were all within 1 percent of each other.Only the
-------._-----~--cost-~o-£-the~50 O/-2-30k-V-c scheme"(-A-Hoercna-tive-5 )was 14
percent above the others.A summary of the life
cycle cost analyses for the various alternatives is
shown in Table B.2.7.2.
A technical and economic comparison was also carried
out to determine possible advantages and
disadvantages of HVDC transmission,as compared to an
..._._...._5i.·c:·.J~y~~~IIl;J()J;J:EIi!I!~J.IlJ~~_t!!g§l!~_~t_ll,,!_..];>C>.w~_r:.~()_____
Anchorage and Fairbanks.HVDC transmission was found
'tObetechnically andoperationally -more complex -a-s-
well as having higher life cycle costs.
(d)Configuration at Generation and Load Centers (0)
Interconnections between generation and load cent'ers and the
transmission system were developed after reviewing the
existing system configurations at both Anchorage and
roariks as well as the possioiliHes arid currerit develop-
ment plans in the Susitna,Anchorage,Fairbanks,Willow,and
Healy areas.
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851104 B-2-88
(i)Susitna Configuration (**)
Preliminary development plans indicated that the
first project to be constructed (Stage 1)would be
Watana with an initial installed capacity of 360 MW.
The next project considered in this study (Stage II),
would be Devil Canyon,with an installed capacity of
600 MW.The last project (Stage 3)will be the
raising of the Watana Dam and addition of two more
generating units to increase the total generating
capacity at Watana to 1,020 MW.
(ii )
(iii)
Switching at Willow (*)
Transmission from Susitna to Anchorage is facilitated
by the introduction of ~n intermediate ~witching
station.This has the effect of reducing line
energizing overvoltages and reducing the impact of
line outages on system stability.Willow is a
suitable location for this intermediate switching
station;in addition,it would make it possible to
supply local load when this is justified by
development in the area.This local load is expected
to be less than 16 percent of the total Railbelt area
system load,but the availability of an EHV line tap
would definitely facilitate future power supply.
Switching at Healy (0)
A switching station at Healy was considered early in
the analysis but was found to be unnecessary to
satisfy the planning criteria.The predicted load at
Healy is small enough to be supplied by local
generation and the existing 138-kV transmission from
Fairbanks.
851104
(iv)Anchorage Configuration (**)
Analysis of system configuration,distribution of
loads,and development in the Anchorage area led to
the conclusion that a transformer station near Palmer
would be of little benefit.Most of the major loads
are concentrated in and around the urban Anchorage
area,at the mouth of Knik Arm.To reduce the length
of subtransmission feeders,the transformer stations
should be located as close to Anchorage as possible.
The routing of transmission into Anchorage was chosen
from the following three possible alternatives:
B-2-89
-Submarine Cable Crossing From Point MacKenzie
to Point Woronzof
This would require transmission through a very
heavily developed area.It would also expose the
cables to damage by ships'anchors,which has been
the e~perience with existing cables,resulting in
questionable transmission reliability.
-Overland Route North of Knik Arm via Palmer
This may be most economical in terms of capital
cost,in spite of the long distance involved.
However,overhead transmission through this
developed area may have,.-signi ficant environmental
consequences.A~longer overland route around the
developed area may be technically unacceptable
because of the mountainous terrain.
-Submarine Cable Crossing of Knik Arm,In the Area
of Lake Lorraine and Six Mile Creek
This option,approximately parallel to the new 230
kV cable -under construction for Chugach Electric
Association (CEA),includes some 3 to 4 miles of
submarine cable and involves a high capital cost.
Since the area is upstream from the shipping lanes
to the port of Anchorage,it will result in a
t"elia·blet:r;ansmission link,and--one.that does.not
have to cross environmentally sensitive
conservation areas.
(v)Fairbanks Configuration (0)
Susitna power for the Fairbanks area is recommended
to be delivered to a single EHV/138 kV transformer
Sl~<!it~.Ql:l._lo..5=at~j_at Ester.No alternatives were given
de ta i led cons idera'-tToti-~---------···---...
..........._-_._--_._-_.._----._~.__...-....
2.7.2 Corridor Selection (0)
(a)Methodology (0)
Development of the proposed Susitna Project will require a
transmission system to..deliver electric power to the
Rail bel t.area.The building of .t:h~Atlchorage to Fairbanks
trit:erEie sysfemwill result ,iii a defined cdrridor and route
for the Susitna transmission lines between Willow and Healy.
Therefore,three areas require study for corridor selection:
the northern area to connect Healy with Fairbanks,the
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851104 B-2-90
)
central area to connect the Watana and,Devil Canyon damsites
with the Intertie,and the southern area to connect Willow
wi th Anchorage.
Using the selection criteria discussed below,corridors
three to five miles wide were selected in each of the three
study areas.These corridors were then evaluated to
determine which ones meet the more specific screening
criteria.This screening process resulted in one corridor
in each area being designated as the recommended corridor
for the transmission line.
(b)Selection Criteria (0)
Since the corridors studied range in width from three to
five miles,the base criteria had to be applied in broad
terms.The study also indicated that the criteria listed
for technical purposes could reappear in the economic or
environmental classification.The technical criteria were
defined as requirements for the normal and safe performance
of the transmission system and its reliability.
The selection criteria were in three categories:technical,
economic and environmental.The criteria are listed in
Table B.2.7.3.
(c)Identification of Corridors (0)
As discussed previously,the Susitna transmission line
corridors studied are located in three geographical areas,
namely:
o The southern study area between Willow and Anchorage;
o The central study area between Watana,Devil Canyon,
and the Intertie,and
o The northern study area between Healy and Fairbanks.
(d)Description of Corridors (0)
Figures B.2.7.1 through B.2.7.3 portray the corridors
evaluated in the southern,central,and northern study
areas,respectively.For purposes of simplification,only
the centerline of the three-to-five-mile wide corridors are
shown in the figures.
In each of the three figures,each corridor under
consideration has been identified by the use of letter
symbols.The various segment intersections and the various
851104 B-2-91
segments,where appropriate,have been designated.Thus,
segments in each of the three study areas can be separately
referenced.Furthe~ore,the segments are joined together
to form corridors.For example,in the northern study area
Corridor ABC is composed of Segments AB and BC.
The alternative corridors selected for each study area are
described in detail in the following paragraphs.In
addition,Tables B.2.7~4,B.2.7.5 and B.2.7.6 contain
detailed environmental data for each corridor segment.
(i)Southern Study Area (0)
-Corridor One -Willow to Anchorage via Palmer (0)
Corridor ABC',consisting of Segments AB and BC',
begins at the intersection with the Intertie in the
vicinity of Willow.From here,the corridor
travels in a southeasterly direction,crossing
wetlands,Willow Creek,and Willow Creek Roa:d
before turning slightly to the so.utheast following
the drainage of Deception Creek.The topography in
the vicinity of this segment of the corridor is
relatively flat to gently rolling with standing
water and tall-growing vegetation in the vicinity
of the creek drainages.
At a point northw.est of Bench Lake,the corridor
turns in an eas!=~dyg:ixection,.cx.o.s.s.ingthe
'_·_-·southern f(;othills of the Talkeetna Mountains.The
topography here is gently to moderately rolling
with shrub-to trees ized vege tationocc urring
throughout.As the corridor approaches the
crossing of the Little Susitna River,it turns and
heads southeast again,crossing the Little Susitna
River and Wasilla Fishhook Road.
Pas s ing'nea:rWolf·LakE'f"ana·Gooain~rLake·;tfie'"..
.......~~__~._.._._-corti-dor-then"cTo's'ses-a-s'e'c-oucbrry-road-;--'some -.
agricultural lands,State Route 3,and the Glenn
Highway,before intersecting existing transmission
lines south of Palmer.In the vicinity of the
Little Susitna River,the topography is gently
rolling.As the corridor travels toward Palmer,
the land flattens,more lakes are present,and some
agricultural development .is Occutri'!1g.After
crossing the Glenn Highway,-the'corridor passes
through a residential area before crossing the
broad floodplain of the Matanuska River.
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851104
Just west of Bodenburg Butte,the corridor turns
due south through more agricultural land before
crossing the Knik River and eventually connecting
with the Eklutna Power Station.All of the land
south of Palmer is very flat with some agricultural
development.Just south of Palmer,the proposed
corridor intersects existing transmission
facilities and parallels or replaces them from a
point just south of Palmer,across the river and
into the vicinity of the Eklutna Power House.From
here into Anchorage,the corridor as proposed would
parallel existing facilities,crossing near or
through the communities of Eklutna,Peters Creek,
Birchwood,and Eagle River by using one of the two
existing transmission linec·rights-of-way in this
area.The land here is flat to gently rolling with
a great deal of residential development.This
corridor segment is the most easterly of the three
considered in the southern study area and avoids an
underwater crossing of Knik Arm.
Corridor Two -Willow to Point MacKenzie via Red
Shirt Lake (0)
Corridor ADFC,consisting of Segments ADF and FC,
commences again at the point of intersection with
the Intertie in the vicinity of Willow but
immediately turns to the southwest,first crossing
the railroad,then the Parks Highway,then Willow
Creek just west of Willow.The land in the
vicinity of this part of the segment is very flat,
with wetlands dominating the terrain.
Southwest of Florence Lake,the proposed corridor
turns,crosses Rolly Creek,and heads nearly due
south,passing through extensive wetlands west and
south of Red Shirt Lake.The corridor in this area
parallels existing tractor trails crossing very
fl~t lands with significant amounts of tall-growing
vegetation in the better drained locations.
Northwest of Yohn Lake,the corridor segment turns
to the southeast,passing Yohn Lake and My Lake
before crossing the Little Susitna River.Just
south of My Lake,the corridor turns in a generally
southerly direction,passing Middle Lake,and east
of Horseshoe Lake before finally intersecting the
existing Beluga 230-kV transmission line at a spot
just north of MacKenzie Point.From here,the
corridor parallels MacKenzie Point's existing
B-2-93
851104
transmission facilities .before crossing u~der Knik
Ann to emerge on the easterly shore of Knik Arm in
the vicini ty of Anchorage.'The land in the
vicinity of this segment is extremely flat and very
wet,supporting dense stands of tallgrowing
vegetation on any of the higher or better drained
areas.
Corridor Three -Willow to Point MacKenzie via
Lynx Lake (0)
Corridor AEFC is very similar to and is a
derivation of Corridor ADFC;it consists of
Segments AEF and FC.This corridor also extends to
the southwest.·of Willow.West of the Parks
Highway,however,just north of Willow Lake,this"
corridor turns and travels southwest of Willow and
east of Long Lake,passing between Honeybee Lake
and Crystal Lake.The corridor then turns
southeastward to pass through wetlands east of Lynx
Lake and Butterfly Lake before crossing the Little
Susitna R.Iver.The land is well developed iri this
area.It is very flat and,while it is wet,also
supports dense stands of tall-growing vegetation on
the better drained sites.Corridor Three rej~ins
Corridor Two at a point south of My Lake.
(ii)Central!tudyArea (0)
The central study area encompasses a broad area in
the vicinity of thedamsites.From Watana,the
study area extends to the north as far as the Denali
Highway and to the south as far as Stephan Lake.
From this point westward,the study area encompasses
the foothills of the Alaska Range and,to the south,
the foothills of the Talkeetna Mountains.Included
-------···-in-·this--study--area--a·re--lands--undet"-cons-iderat-ion-by....
t-he-Int-e·J:'.t-ie-P.r-o~ect-in:v:es.t.i.ga.to.r.s_.---'!he_aLter_na_ti:v:.e ..
corridors would connect both Devil Canyon and Watana
Dams with the Intertie at one of four locations,
which are identified in Figure B.2.7.2..
As for the southern study area,individual corridor
$egments a".t'e listed in the text.This is to aid the
reader both in determining corridor locations in the
figure-sand itl 'exatniningtheenvironmenta I invento-ry
data listed for each segment in Tables B.2.7.4,
B.2.7.5 and B.2.7.6.
B-2-94
1.
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851104
Corridor One -Watana to Intertie via South Shore,
Susitna River (0)
Corridor ABCD consists of three segments:AB,BC,
and CD.This corridor originates at the Watana
damsite and follows the southern boundary 6f the
river at an elevation of approximately 2,000 feet
from Watana to Devil Canyon.From Devil Canyon,
the corridor continues along the southern shore of
the Susitna River at an elevation of about 1,400
feet to the point at which it connects with the
Intertie,assuming the Intertie follows the
railroad corridor.The land surface in this area
is relatively flat,though incised at a number of
locations by tributaries to the Susitna River.The
relatively flat hills are covered by discontinuous
stands of dense,tall-growing vegetation.
-Corridor Two -Watana to Intertie via Stephan
Lake (0)
ABECD,.the second potential corridor,is
essentially a derivation of Corridor One and is
formed by replacing Segments BC with BEe.
Originating at Point B,Corridor Segment BEC leaves
the river and generally parallels one of the
proposed Watana Dam access road corridors.This
corridor extends southwest from the river,passing
near Stephan Lake to a point northwest of·Daneka
Lake.Here the route turns back to the northwest
and intersects Corridor One at the Devil Canyon
damsite.The terrain in this area,again,is
gently rolling hills with relatively flat benches.
Vegetation cover ranges from sparse at the higher
elevations to dense along the river bottom and
along gentler slopes of the Susitna River and its
tributaries.
Corridor Three -Watana to Intertie v~a North
Shore,Susitna River (0)
Corridor Three (AJCF),located on the north side of
the river,consists of Segments AJ and CF.
Starting at the Watana damsite,the corridor
crosses Tsusena Creek and heads westerly,following
a small drainage tributary to the Susitna River.
Once crossing Devil Creek,the corridor passes
north and west of High Lake.
B-2-95
The corridor stays below an elevation of 3,700 feet
as it crosses north of the High Lake"area,east of
Devil Creek,on its approach to Devil Canyon.From
Devil Canyon,the corridor again extends to the
west,crossing Portage Creek and intersecting the
Intertie in the vicinity of Indian River.In the
drainages,to elevations of about 2,000 feet,tree
heights range to 60 feet.Between Devil Creek and
Tsusena Creek,however,at the higher elevations,
very little vegeta tion grows taller than 3 feet.
Once west of Devil Creek,discontinuous areas of
tall-growing vegetation exist.
Corridor Four -Watana to Intertie via Devil
Creek Pass/East Fork Chulitna River"(0)
Another means of connecting the two dam schemes
with the Intertie is to follow Corridor One from
Watana to Devil Canyon and then exit the Devil
Canyon project to the north (ABCJHI).This
involves connec'ting Corridor Segments AB,BC,CJ,
HJ,·andHI.··With this ·alternative,the corridor
extends northeast at Devil Canyon past High Lake to
Devil Creek drainage.From there,it moves
northward to a point north of the south boundary of
the Fairbanks Meridian.The corridor then follows
the Portage Creek "drainage beyond its point of
origin to a site within the Tsu~ena Creek drainage.
·Likewis e·,".it~fol·lows~the~T~usena.·Creek-d~ai na·ge··to
a point near Jack River,at which point it
parallels this drainage into Caribou Pass.From
Caribou Pass,the corridor turns to the west,
following the Middle Fork·Chulitna River until
meeting the Intertie in the vicini ty of Summit
Lake.
While along much of this corridor the route follows".-.'.----..--."----.'---.-'---,.-.----·rl-ver'·'·-vaI"reys-;'the---·plan -a:I·s'o'--··'re-q ui res"'---cr o-fi sin g-hi-gIl
·----~-~--mountain passes inruggea-·terrailr;··Tl:1i-s···fs··_··_······
especially true in the crossing between Portage
Creek and Tsusena Creek drainages,where elevations
of over 4,600 feet are involved.Tall-growing
vegetation is restricted to the lower elevations
along the river drainages with little other than
low-growing forbsand~shrubs present at higher
elevci"!:iotls.
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851104 B-2-96
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851104
-Corridor Five -Watana to Intertie via .Stephan
Lake and the East Fork Chulitna River (0)
A variation of Corridor Four,Corridor Five
(ABECJHI)replaces Segment BC with Corridor
Segment BEC (of Corridor Two).This results in a
corridor that extends from the Watana damsite
southwesterly to the vicinity of Stephan Lake,and
from Stephan Lake into the Devil Canyon damsite.
From Devil Canyon to the Intertie,the corridor
follows the Devil Creek,Portage Creek,and Middle
Fork Chulitna drainages previously mentioned.As
before,the corridor crosses rolling terrain
throughout the length of the paralleled drainages,
with some confined,higher elevation passes
encountered between Portage Creek and Tsusena
Creek.
Corridor Six -Devil Canyon to the Intertie via
Tsusena Creek/Chulitna River (0)
Another option (CBARI)for connecting the dam
projects to the Intertie involves connecting
Devil Canyon and Watana along the south shore of
the Susitna River via Corridor Segment CBA,then
exitingWatana to the north on Segments AR and HI
along Tsusena Creek to follow this drainage to
Caribou Pass.The corridor then contains the
previously-described route along the Jack River and
Middle Fork Chulitna until connecting with the
Intertie near Summit Lake.The terrain in this
corridor proposal would be of moderate elevation
with some confined,higher elevation passes between
the drainages of Tsusena Creek and the Jack River.
Corridor Seven -Devil Canyon to Intertie via
Stephan Lake and Chulitna River (0)
This alternative uses Corridor Six but replaces
Segment BC with Segment BEC from Corridor Two.
This route would thu$be designated CEBAHI.
Terrain features are as described in Corridors Two
and six.
-Corridor Eight -Devil Canyon to Intertie via
Deadman/Brushkana Creeks and Denali Highway (0)
Yet another option to the previously-described
corridors is the interconnection of Devil Canyon
B-2-97
851104
with Watana via Corridor One (Segment CBA),with a
segment then extending from Watana northeasterly
along the Deadman Creek drainage (Segment AG).The
segment proceeds north of Deadman Lake and Deadman
Mountain,then turns to the west and intersects the
Brushkana Creek drainage.It then follows
Brushkana Creek north to a point east of the Kana
Bench Mark.This segment of the corridor would
parallel one of the proposed access roads.From
there,the corridor turns west,generally parallel
to the Denali Highway,to the point of
interconnection with the Intertie in the vicinity
of Cantwell.The ar~a encompasses rolling hills
with modest elevation changes and some forest
cover,especially at the lower elevations.
Corridor Nine -Devil Canyon to Intertie via
Stephan Lake and Denali Highway (0)
Corridor Nine (CEBAG)is exactly the same as
Corridor Eight with the exception of Corridor
Segment .BEe,uti 1 ized·to replace Segment BC.Each
combination of segments has been previously
described.
Corridor Ten -Devil Canyon to Intertie via North
Shore,Susitna River,.and Denali Highway (0)
,.
--····L;Ol:'-l"-],Cl(rt:'-Ten·connect.s~De·vilCanyon-Wa·tana·wi th the
Intertie in the vicinity of Cantwell by means of
Corridor SegmentsCJAG.Segment CJA is part of
Corridor Three and,as such,has been previously
described..Segment AG has also been described
above as part of Corridor Eight.As noted earlier,
the Corridor Ten terrain consists of mountainous
stretches with accompanying gently-rolling to
1ll()<i_~l:"_a.J;.e ~y-=-roll i !!gjli U~~.!!c:1ga.1:.pJa.J!!~coy_~re d ~n
._...E.~~c:es.!i:~ll..~a 1.!=gl"()w:i:.I!~!.e:.~r:..~~~~on~..._.......
-Corridor Eleven -Devil Canyon to the Intertie
via.Tsusena Creek/ChuU tna River (0)
Another northern route connecting Devil Canyon with
Watana is that created by connecting Corridor
SegmentCJA (part of Corridor Three)with Segment
......AHLof Corridor Six •..
B-2-98
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851104
-Corridor Twelve -Devil Canyon-Watana to the
Intertie via Devil Creek/Chulitna River (0)
Another route under consideration is Corridor
JA-CJHI.From north to south,this involves a
corridor extending from the Intertie near Summit
Lake,heading easterly along the Middle Fork
Chulitna drainage into Caribou Pass.From here,it
parallels the Jack River and connects with the
Portage Creek-Devil Creek route,Segment HJ.At
point J,located in the Devil Creek drainage east
of High Lake,the corridor splits,with one segment
extending westerly to Devil Canyon and the other
extending east to the Watana damsite along
previously-described Corridor Segments JC and JA,
respectively.Terrain features of this route have
been previously described.
-Corridor Thirteen -Watana to Devil Canyon via
South Shore,Devil Canyon to Intertie via North
Shore,Susitna River (0)
Corridor Segments AB,BC,and CF are combined to
form this corridor.Descriptions of the terrain
crossed by these segments appear in discussions of
Corridor One (ABCD)and Corridor Three (AJCF).
-Corridor Fourteen -Watana to Devil Canyon via
North Shore,Devil Canyon to Intertie via South
Shore,Susitna River (0)
This corridor would connect the damsites in the
directionally opposite order of the previous
corridor,and include Corridor Segment AJCD.
Again,as parts of Corridors One and Three,the
terrain features of this corridor have been
previously described.
Corridor Fifteen -Watana to Devil Canyon via
Stephan Lake,Devil Canyon to Intertie via North
Shore,Susitna River (0)
Corridor Two (ABEC)and Corridor Three (CF)form to
create this study-area corridor.Terrain
features have been presented under the discussions
of each of these two corridors.
B-2-99
(iii)Northern Study Area (0)
In the northern study area,four transmission line
corridor options exist for connecting Healy and
Fairbanks (Figure B.2.7.3).
Corridor One -Healy to Fairbanks via Parks
Highway (0)
Corridor One (ABC),consisting of Segments AB and
BC,starts in the vicinity of the Healy Power
Plant.From here,the corridor heads northwest,
crossing the existing Golden Valley'Electric
Association Transmission Line,the railroad,and
the Parks Highway before turning to the north and
paralleling this road to a point due west of
Browne.Here,as a result of terrain features,the
corridor turns northeast,crossing the Parks
Highway once again as well as the~existing
transmission line,the Nenana River,and the
railroad,and continues northeasterly to a point
northeast of the Cleat Missile Early Warning
S ta tion (MEWS).
Continuing;northward,the corridor eventually
crosses the Tanana River east of Nenana,then heads
northeast,first crossing Little Goldstream Creek,
then the Parks Highway just north of the Bonanza
----------------.--------,---~-----.---.----Creek Exper-imetrta~t-Fo-re-s~t_;---Be-·fo-·re----r·ea·ch~in-g---the----
drainage of Ohio Creek,this corridor turns back to
the northeast,crossing the old Parks Highway and
heading into the Ester substation west of
Fairbanks.
Terrain along this entire corridor segment is
relatively flat,with the exception of the
.foothill s-nor-th_oLthe_...Tana naRiv.er •Much _of the
..-.-~.-~.-_.._~..._._....._._.__.__..r.o.u.t.e.,.e.s.p_e_c ially~that __Rortion between.the Nenana
and the Tanana River crossings,is very broad and
flat,has-standing water during the summer months
and,in some places,is overgrown by dense stands
of tall-growing vegetation.This corridor segment
crosses the foothills northeast of Nenana,also a
heavily-wooded area.
·.t\Il()pti()Il~ot1:leabove (and not shown in the
figures),that of closely parallel and sharing
rights-of-way with the existing Healy-Fairbanks
transmission line,has been considered.While it
is usually attractive to parallel existing
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851104 B-2-100
corridors wherever possible,this option
necessitates a great number of road crossings and
an extended length of the corridor paralleling the
Parks Highway.,A potentially significant amount of
highway-abutting land would be usurped for
containment of the right-of-way.These features,
in combination,eliminated this corridor from
further evaluation.
Corridor Two -Healy to Fairbanks
Wood River (0)
via Crossing
The second corridor (ABDC)is a variation of
Corridor One and consists of Segments AB and BDC.
At point B,east ·of the Clear MEWS,instead of
turning north,the corridor continues to the
northeast,crossing Fish Creek,the Totatlanika
River,Tatlanika Creek,the Wood River,and Crooked
Creek befQ~e turning to the north.At a point
equidistant from Crooked and ,Willow Creeks,the
corridor turns north,crosses the Tanana River east
of Hadley Slough,and extends to the Ester
substation.North of the Tanana River,this
corridor segment also crosses Rose Creek and the
Parks Highway.
Where it diverges from the original corridor,this
corridor traverses extensive areas of flat ground,
with standing water very prevalent throughout the
summer months.Heavily-wooded areas occur in the
broad floodplain of the Tanana River,in the
vicinity of the river crossing,and in the
foothills around Rose Creek.
Corridor Three -Healy to Fairbanks via
Creek and Japan Hills (0)
Healy
851104
Corridor Three (AEDC),consisting of Segments AE
and EDC,exits the Healy Power Plant in an easterly
direction.Instead of proceeding northwest,this
corridor,following its interconnection with the
Intertie Project,heads east up Healy Creek,
passing the Usibelli Coal Mine.Near the
headwaters of Healy Creek,the corridor cuts to the
east,crossing a high pass of approximately 4,700
feet elevation and descending into the Cody Creek
drainage.From Healy to the Cody Creek drainage,
the terrain is relatively gentle but bounded by
very rugged mountain peaks.The elevation gain
from the Healy Power Plant to the pass between the
B-2-101
Healy Creek-Cody Creek drainages is apprqximately
3,300 feet.From here,the segment turns to the
northeast,following the lowlands accompanying the
Wood River.The corridor next parallels the Wood
River from the Anderson Mountain area,past Mystic
Mountain,and out into the broad floodplain of the
Tanana River east of Japan Hills.Near the
confluence of Fish Creek and the Wood River,the
corridor turns north and intersects the north-south
portion of Corridor Two (Segment DC),after first
passing through Wood River But tes.Much of the
area north of Japan Hills is flat and very wet with
stands of dense,tall-growing vegetation.
-Corridor Four -Healy to Fairbanks via Wood River
and Fort Wainwright (0)
Corridor Four (AEF)is a derivation of Corridor
Three and is composed of Segments AE and EF.Point
E is located just north of Japan Hills along the
Wood River.From here,the corridor deviates from
corridor Three by running north across the Blair
Lake Air Force Range,Fort Wainwright,and several
tributaries of the Tanana River,before reaching
the crossing of Salchaket Slough.Corridor Four
passes Clear Creek Butte on the east.A new
substation would be located on the Fairbanks side
of the Tanana River just north of Goose Island.
~~~__c __·•,~c_~~-~,cFr()m-Pcyint;-E-to~Po'int'F,.the...terrain'ofthe'"..
corridor is flat and very wet,and again,dense
stands of tall-growingvegeta tion exist both in the
better drained portions of the flat lands and in
the vicinity of the river crossing.
2.7.3 Corridor Screening (0)
_The.obje.c tives...of.the.scr.eening ...pro.ces.s..w.ere __t.o...:t:o.C.u~LQn_J:_h.e.p.~e=._
......__~..__viously::-selected corridors and select those best meeting ._
technical,economic,and environmental criteria.
(a)Reliability (0)
Reliability is an uncompromising factor in screening
alternative transmission line.corridors.Many of the
."'''crfi:::eriaiiti lizeCl forecoriorilic,en vir6tlI1ierital,arid te chri i cal
reasonsal·sorelate to the-selection of a corridor within
tiThich~iInec~n'be oPera.te dwI thmIollIltJm power
interruption.Six basic factors were considered in relation
to reliability:
.(
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851104 B-2-102
o Elevation:
o Aircraft:
o Stability:
0 Existing
Power
Lines:
-I 0 Topography:
I
0 Access:
Lines located at elevations below 4,000
feet will be less exposed to severe wind
and ice conditions,which can interrupt
service.
Avoidance of areas near aircraft landing
and takeoff operations will minimize
risks from collisions.
Avoidance of areas susceptible to land,
ice,and snow slides will reduce chance
of power failures.
Avoidance of crossing existing
transmission lines will reduce the
possibility of lines touching during
failures and will facilitate repairs.
Lines located in areas with gentle relief
will be easier to construct and repair.
Lines located in reasonable proximity to
transportation corridors will be more
quickly accessible and therefore more
quickly repaired if any failures occur.
(b)Technical Screening Criteria (0)
Four primary and two secondary technical factors were con-
sidered in the screening of alternative corridors.
(i)Primary Aspects (0)
-Topography (0)
-Climate and Elevation (0)
Low temperatures,snow depth,icing,and severe
winds are very important parameters in transmission
design,operation,and reliability.
Climatic factors become more severe in the
mountains,where extreme winds are expected for
exposed areas and passes.The Alaska Power
Administration believes that elevations above 4,000
feet in the Alaska Range and Talkeetna Mountains
are completely unsuitable for locating major
transmission facilities.Significant advantages of
reliability and cost are expected if the lines are
routed below 3,000 feet in elevation.This
851104 B-2-103
851104
elevation figure was used in the screening
process.
-Soils (0)
Although transmission lines are less affected by
soils and foundation limitations than railroads
and pipelines,it is more reliable to build a
transmission line on soil that does not appear to
be underlain by seismically-induced ground
failures.It is also desirable to avoid swampy
areas where maintenance and inspection may create
problems.These factors were utilized in the
screening process.Because of the vast areas of
wetlands in the study area,particularly in the
southern portion,it was not possible.to locate a
corridor that would avoid all wetland areas.
-Length of Corridors (0)
(ii)Secondary Aspects (0)
-Vegetation and Clearing (0)
Heavily-'forestedareas must be cleared prior to
construction of the transmission line.Clearing
the vegetation will cause some disruption of the
soil.If the cleared right-of-way is not properly
.~-~staonizea--tnrough~iestora t ic)n--ana re vegetaEroii~.-
increased erosion will result.If the vegetation
is cleared up to river banks on stream crossings,
additional sedimentation may result.During the
corridor screening,those corridors crossing large
expanses of heavily timbered areas were
el imina ted.
Highway and river crossings were avoided where
possible.
B-2-104
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(c)Economic Screening Criteria (0)
Three primary and one secondary aspect of the economic
criteria were considered.
(i)Primary Aspects (0)
-Length (0)
-Right-of-Way (0)
Whenever possible,existing rights-of-ways were
shared or paralleled to avoid problems associated
with pioneering a corridor in previously
inaccessible areas.
-Access Roads (0)
(ii)Secondary Aspects (0)
In addition to the major considerations concerning
economic screening of corridors,some other aspects
were also considered.These include topography
(since it is more economical to build a line on a
flat corridor than on a-rugged or a mountainous one)
and limiting the number of stream,river,highway,
road,and railroad crossings in order to minimize
costs.
(d)Environmental Screening Criteria (0)
Because of the potential adverse environmental impacts from
transm~ssion line construction and operation,
environmental criteria were carefully scrutinized in the
screening process.Past experience has shown the primary
environmental considerations to be:
o Aesthetic and Visual (including impacts on
recrea tion);
o Land Use (including ownership and presence of existing
righ ts-of-way)•
Also of significance in the evaluation process are:
o Length,
o Topo gra phy ,
o Soils,
851104 B-2-105
851104
o Cultural Resources,
o Vegeta tion,
o Fishery Resources,and
o Wildlife Resources.
A description and rationale for use of these criteria are
presented below.
(i)Primary Aspects (0)
-Aesthetic and Visual (o}
The presence of large transmission line structures
in undeveloped areas has the potential 10r adverse
aesthetic impacts.Furthermore,the presence of
,these lines can conflict with recreational use,
particularly those nonconsumptive recreational
act;iv:i.ti~s such as hiltitlg ~md b:i.rd watching where
.great emphasis is placed on scenic values.The
number of road crossings encountered by
transmission line corridors is also a factor that
needs to be inventoried because of the potential
for visual impacts.The number of roads crossed,
the manner in which they are crossed,the nature of
..('!:J(;~~t i1'lg_y('!g('!t:a ti.Q1'l.1!~_J::h('!_~r 0 s §:i,1'lg__~j.J;:~_(:i,.~~,.
potential visual screening),and the number and
type of motorists using the highway all influence
the desirability of one corridor versus another.
Therefore,when screening the previously-selected
corridors,consideration was focused on the
presence of recreational areas,hiking trails,
heavily utilized lakes,vistas,and highways where
views of transmission line facilities would be
-Land Use (0)
The three primary components of land use considera-
tions are:1)land status/ownership,2)existing
rights-of-way,and 3)existing and proposed
development.
I..andStatus/Ownershipc(e)-
The ownership of land to be crossed by a
transmission line is important because certain
B-2-106
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851104
types of ownership present more restrictions than
others.For example,some recreation areas such
as state and federal parks and areas such as game
refuges and military lands,among others,present
possible constraints to corridor routing.
Private landowners generally do not want
transmission lines on their lands.This
information,when known in advance,permits
corridor routing to avoid such restrictive areas
and to occur in areas where land use conflicts
can be minimized •
•Existing Rights-of-Way (0)
Paralleling existing rights-of-way tends to
result in less enviropmental impac~than that
which is associated with a new right-of-way
because the creation of a new right-of-way may
provide a means of access to areas normally
accessible only on foot.This can be a critical
factor if it opens sensitive,ecological areas to
all-terrain vehicles.
Impact on soils,vegetation,stream crossings,
and other inventory categories can also be
lessened through the paralleling of existing
access roads and cleared rights-of-way.Some
impact'is still felt,however,even though a
right-of-way may exist in the area.For example,
cultural resources may not have been identified
in the original routing effort.
Wetlands'present under existing transmission
lines may likewise be negatively influenced if
ground access to the vicinity of the tower
locations is required.
There are common occasions where paralleling an
existing facility is not desirable.This is
particularly true in the case of highways that
offer the potential for visual impacts and in
situations where paralleling a poorly sited
transmission facility would only compound an
existing problem •
•Existing and Proposed Developments (0)
This inventory identifies such items as
agricultural use,planned urban developments,
B-2-107
851104
existing residential and cabin developments,the
location of airports and lakes used for float
planes,and similar types of information.Such
information is essential for locating
transmission line.corridors appropriately,as it
presents conflicts with these land use
act i vi ties.
(ii)Secondary Aspects (0)
-Length (0)
The length ofa t.ransmission line is an
enviromnental facto.r and,as such,was considered
in the screening process.A longer line will
require more construction activity than a shorter
line,will disturb more land area,and will have a
greater inherent probability of encountering
environmental cons traint s Oil..,
-Topography.(0)
The natural features of the terrain are significant
from the standpoint that they offer both positive
and negative aspects to transmission line routing.
Steep slopes,for example,present both difficult
construction and soil stabilization problems with
_p_~tent~~lly_:I,ong::term L neg~~i.~~~!lJti~o11I!t~I.l~~J.
consequences.Also,ridge crossings have the
potential for visuai impacts.At the same time,
slopes and elevation changes present opportunities
for routing transmission lines so as to screen them
from both travel routes and existing communities.
Hence,when planning corridors the identification
of changes in relief is an important factor.
====..~_..__._.._.___---_._-.__~..-__.
Soils are important from several standpoints.
First of all,scarification of the land often
occurs during the construction of transmission
lines.Asa result,vegetation regeneration is
affected,as arE:!the related features of soil
stability arid erosion.potential.In addition,the
development and installation of access roads,where
.....·-necessary,are~~very-~dependent .upon soil types·.
Tower designs and locations are dictated by the
types of soils encountered in any particular
corridor segment.Consequently,the review of
existing soils information.is very significant.
B-2-108
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851104
This inventory was conducted by means of.a Soil
Associations Table,Table B.2.7.7.Table B.2.7.8
presents the related definitions as they apply to
the terms used in Table B.2.7.7.
-Cultural Resources (0)
The avoidance of known or potential sites of
cultural resources is an important component in
the routing of transmission lines.A level-one
cultural resources survey has been conducted along
a large portion of the transmission corridors.In
those areas where no information has been collected
to date an appropriate program for identifying and
mitigating impacts will be undertaken.This
program is discussed in more detail in Chapter 4 of
Exhibit E.
-Vegetation (0)
The consideration of the presence and location of
various plant communities is essential in
transmission line siting.The inventory of plant
communities,such as those of a tall-growing nature
or wetlands,is significant from the standpoint of
construction,clearing,and access road development
requirements.In addition,identification of
locations of endangered and threatened plant
species is also critical.While several Alaskan
plant species are currently under review by the
U.S.Fish and Wildlife Service,no plant species
are presently listed under the Endangered Species
Act of 1973 as occurring ·in Alaska.No corridor
currently under consideration has been identified
as traversing any location known to support these
identified plant species.
-Fishery Resources (0)
The presence or absence of resident or anadromous
fish in a stream is a significant factor in
evaluating suitable transmission line corridors.
The corridor's effects on a stream's resources must
be viewed from the standpoint of possible
disturbance to fish species,potential loss of
habitat,and possible destruction of spawning beds.
In addition,certain species of fish are more
sensitive than others to disturbance.
B-2-109
851104
Closely related to this consideration is.the number
of stream crossings.The nature of the soils and
vegetation in the vicinity of the streams and the
manner in which the streams are to be crossed are
also important environmental considerations when
routing transmission lines.Potential stream
degradation,impact on fish habitat through
disturbance,and long-term negative consequences
resulting from siltation of spawning beds are all
concerns·that need evaluation in corridor routing.
Therefore,the number of stream crossings and the
presence.of fish species and habitat value were
considered when data were available.
-Wildlife Resources (0)
The three major groups of wildlife which must be
considered in transmission corridor screening are
big game,birds,and furbearers.Of all the
wildlife species to be considered in the course of
routing studies for transmission lines,big game
species (together with endangered species)are most
significant.Many of the big game species,
including grizzly bear,caribou,and sheep,are
particularly sensitive to human intrusion into
relatively undisturbed areas.Calving groungs,
denning areas,and other important or unique
habitat areas as identified by the Alaska
Depa r"tnientof-F:LsnanGGame were·tdent-ifiedanG··
incorporated into the screening process.
Many species of birds such as raptors and swans are
sensitive to human dJstJJI."bance.Identifyingthe
presence and location of nesting raptors and swans
permits avoidance of traditional nesting areas.
Moreover,if this ca.tegory is investigated,the
.presence.ofendangered.species{viz,peregrine .
.....fa Ij~.onsJ_._c_a.IL-b.e--!ie_t_e_rm i ne_d.•_..~_._.
Important habitat for furbearers exists along many
potential transmission line corridors in the
Railbelt area,and its loss or disruption would
have a direct effec·tonthese animal populations.
Investigating habitat preferences ,noting existing
hablta t,a.nd ..,identIfYing .po pula t ion s through
.......•;,iY;,iil;,i1:>1~=~1l.j:()'I:TIl;,il;iQ11.C3.l:'.EL.impQI'l;ant ..st~ps in
addressing the selection of environmentally
acceptable alternatives.
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(e)Screening Methodology (0)
(i)Technical and Economic Screening Methodology (0)
The parameters required for the technical and
economic analyses were extracted from the environ-
mental inventory tables (Tables B.2.7.4 through
B.2.7.6).These tables,and Tables B.2.7.9 through
B.2.7.lS are derived from studies carried out prior
to the issuance of the Feasibility Report in March
1982;at that time the routing of the proposed access
route was undecided.Subsequent to the publication
of the Feasibilty Report the decision was made to
select the Denali-North Plan as the proposed access
route.Since the location of the aceess route is of
major importance in relation to the transmission line_
within the central study area,the tables have been
modified to reflect this decision and the ratings
assigned to each corridor adj~sted accordingly.The
reasons for changing these ratings are discussed in
more detail in subsection 2.7.4.
The tables,together with the topographic maps,
aerial photos,and existing published materials,were
used to compare the alternative corridors from a
technical and econoIlIic~"point of view.The parameters
used in the analysis were:length of corridors,
approximate number of highway/road crossings-,
approximate number of river/creek crossings,land
ownership,topography,soils,and existing
rights-of-way.The main factors contributing to the
economic and technical analyses are combined and
listed in Tables B.2.7.9,B.2.7.l0,and a.2.7.ll.It
should be noted that most of the parameters are in
miles of line length,except the tower construction.
In this analysis,it was decided to assign 4.S towers
for each mile of 34S-kV line.
In order to screen the most qualified corridor,it
was decided to rate the corridors as follows:
Corridor rated A -recommended,
Corridor rated C -acceptable but not preferred,and
Corridor rated F -unacceptable.
From a technical point of view,reliability is the
main objective.An environmentally and economically
sound transmission line was rejected if the line was
not reliable.Thus,any line that received an F
8S1104 B-2-11 I
technical rating was assigned an overall rating of F
and eliminated from further consideration •.
The ratings appear in each of the economic and
technical screening tables (Tables B.2.7.9,B.2.7.10,
and B.2.7.11)and are summarized in Table B.2.7.12.
(ii)Environmental Screening Methodology (0)
In order to compare the ~lternative corridors
(Figures B.2.7.1,B.2.7.2,and B.2.7.3)from an
environmental standpoint,the environmental
criteria discussed above were combined into
environmental constraint tables (Tables B.2.7.13,
B.2.7.14 and B.2.7.15)•These tables combine
information for eac~corridor segment into the proper
corridors under study.This permits the assignment
of an environmental rating,which identifies the
relative rating of each corridor within each of the
three study areas.The assignment of environmental
ratings is a subjective,qualitative technique
intended as an aid to corridor screening.Those
corridors that are recommended are identified with an
"A,"while those corridors that are acceptable but
not preferred are identified with a "C."Finally,
those corridors that are considered unacceptable are
identified with an "F."
The selected corridor consists·of the following segments:
o Southern Study Area:Corridor ADFC (Figures B.2.7.4 and
B.2.7.5),
o Central Study Area:Corridor AJCD(Figures B.2.7.6 and
B.2.7.7)
.0 -·Nor the rn-"Study--Area:-"Corridor-AB€--'(-F-igures-B.2.7.8
Specifics of these corridors and reasons for rejection of others
are discussed below.More detail on the screening process and
the specific technical ratings of each alternative are in Chapter
10 of Exhibit E.
(a)Southern Study Area (0)
In the southern study area,Corridor Segment AEF and,hence,
Corridor Three (AEFC)were determined unacceptable.This
results primarily from the routing of the segment through
the relatively well-developed and heavily-utilized Nancy
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851104 B-2-112
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851104
Lake state recreation area.Adjustments to this ~oute to
make it more acceptable were attempted but no alterations
proved successful.Consequently,it was recommended that
this corridor be dropped from further consideration.
Corridor One (ABC'),identified as.acceptable but not
preferred,was thus given the C rating.Its great length,
its traversing of residential and other developed lands,and
the numerous creek crossings and extensive forest clearing
involved relegate this corridor to this environmental
rating.Economically and technically,this corridor has
more difficulties than the other two considered.This is a
longer line and crosses areas which may require easements in
the area north of Anchorage.
Corridor Two (ADFC)was identified as the candidate which
would satisfy most of the screening criteria.This corridor
is shown in Figures B.2.7.4 and B.2.7.5 and stretches from
an area north of Willow Creek to Point MacKenzie in the
south.The corridor is located east of the lower Susitna
River and crosses the Little Susitna River.The corridor
also crosses an existing 138-kV line owned and operated by
Chugach Electric Association (CEA),which starts at Point
MacKenzie and extends to Teeland Substation.
Up to this point in the corridor selection study,Point;.
MacKenzie has been considered a terminal point for Susitna
power.It was assumed tha.t an underwater cable crossing
would be provided at this location.Upon further study and
data gathering it has become known that the existing
crossing at Point MacKenzie has experienced power
interruptions caused by ships'anchors snagging the
submarine cables.CEA,which owns the submarine cables,
required additional transmission capacity to Anchorage.
After thoroughly studying the matter,it has opted for a
combined submarine/overhead cable transmission across Knik
Arm and on to Anchorage.This was the most desirable option
to CEA from both the environmental and technical point of
view.
The CEA crossing will be located approximately 8 miles
northeast of Point MacKenzie on the west shore of the Knik
Arm and across 'from Elmendorf Air Force Base in the vicini ty
of Six Mile Creek.This crossing is located northeast of
Anchorage Harbor,away from heavy ship traffic,thereby
reducing the risk of anchor damage to the cable.
It is intended to terminate Corridor ADFC at this new
crossing point and extend the transmission corridor to
Elmendorf Air Force Base and beyond to Anchorage.
B-2-113
Although the crossing is approximately 8 miles no~theast of
Point MacKenzie,it does not influence the resul ts of this
corridor selection and screening process.The best corridor
has been selected and screened.During routing studies
minor deviations outside the corridor will have to occur in
order to terminate at the revised crossing point.However,
preliminary investigations indicate it will be possible to
select a technically,economically,and environmentally
acceptable route,particularly since an existing
transmission line can likely be paralleled frqm the selected
corridor to the revised crossing point.Furthermore,CEA
has received the necessary permits and is constructing an
underwater crossing at Knik Arm,indicating acceptable
levels of environmental impact.
(b)Central Study Area (0)
In the central study area,several corridor segments and
-their associated corridors were determined to be
unacceptable.The first of these ,Corridor Segment BEC,
appears laS.part of Corridors Two (ABECD),Five (ABECJHI),
Seven (CEJAHi),-Nine (C.EBAG),and Fifteen (ABECF).The
primary reason for rejecting this segment is that the
developed recreation area around Stephan Lake would be
needlessly harmed because viable options exist to avoid
intruding into this area.An acceptable modification could
not be found and,consequently,it is recommended that these
_________!i~e c()l:l:'idc~_rs _~~~ropp=-~fr.~mfurt~er_,=-~~l~ideration.
Corridor Segment AG was also determined not to warrant
further consideration,-because of its approximate 65-mile
length,two-thirds of which would pos sibly require a pioneer
access road.Also,extensive-areas of-clearing would be
required,opening the corridor to view in some scenic
locations.Finally,the impacts on fish and wildlife
habitats are potentially severe.These preliminary
findings,-coupledwi-th-the--fact--that-more-viable-options__to _
--Segment-AG--ex-i-st-,~-sugges-t--tha-t-_consideIa_t.ion __o_f_t.hLs____
corridor segment and therefore Corridors Eight (CBAG)and
Ten (CJAG)should be terminated.
Corridors Eleven (CJAHI)and Twelve (JA-CJHI)were
identified as not acceptable.This rating arose from the
_fact that ,aslilhown in Environmental Constraint Table
B.2.7.14,numerous constraints affect this routing.
Irifo:rIliation-frolllrecentlycompleted..:-fielci-:i,nye s t:i,gations
suggest that these constraints cannot be overcome and the
routes should be rejected.Furthermore,the technical and
economical ratings preclude these corridors from further
consideration.
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Corridor Segment HJ has been moved so that it no longer
parallels the Devil Creek drainage;the new location HC is
selected to avoid both High Lake and the Devil Creek
drainage.It then follows the Portage Creek drainage to the
point of intersection with Corridor Segment JH,near the
creek's headwaters.Subsequent investigations have con-
firmed that this corridor segment is not viable and,
consequently,Corridors Four and Five are eliminated from
further consideration.
Corridor Six (CBAHI)intrudes on valuable wildlife habitat
and would cross numerous creeks,none of which are currently
crossed by existing access roads.In addition,a high
mountain pass and its associated shallow soils,steep
slopes,and surficial bedrock constrain this routing.
Finally,its crossing of areas over 4,000 feet in elevation
makes it technically unacceptable,so this corridor is
dropped from further consideration.
The four remaining corridors (Corridors One,Three,Thirteen
and Fourteen)were each identified as being acceptable in
terms of the technical,economic and environmental criteria
described in subsection 2.7.3.
The Denali-North Plan was selected as the proposed access
route for the Susitna development (subsection 2.6.8).The
location of existing and proposed access is of prime
importance both from an economic and environmental
standpoint.Therefore,subsequent to the access decision,
each of the four corridors was subjected to a more detailed
evaluation and comparison.In order to more directly
compare the four corridors a preliminary route was selected
in each of the segments.The final route selection process
leading to the perferred route in the corridor,which was
subsequently recommended,is discussed in more detail in
subsection 2.7.5.The four corridors comprise the following
segments:
o Corridor One
o Corridor Three
o Corridor Thirteen
o Corridor Fourteen
ABCD,
AJCF,
ABCF,and
AJCD.
851104
Segments ABC and AJC link Watana with Devil Canyon and,
similarly,segments CD and CF link Devil Canyon with the
Intertie.
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851104
(i)The Choice Between CD and CF (0)
On closer examination of the possible routes between
Devil Canyon and the Intertie,segment CD was found
to be superior to segment CF for the following ,
reasons.
Economic (0)
A four-wheel drive trail is already in existence
on the south side of the Susitna River between
Gold Creek and the proposed location of the
railhead facility at Devil Canyon.Therefore,the
need for new roads along segment CD,both for
construction and oper~tion and maintenance,is
significantly less than for segment CF,which
requires the construction of a pioneer road.In
addition,the proposed Gold Creek to Devil Canyon
railroad extension will also run parallel to
segment CD.The lengths of Segments CD and CF are
8.8 miles and 8.7 miles,respectively--not a
sigtitfi~'antdifferen~e~'Among the secondary
economic considerations is that of topography.
Segment CF crosses more rugged terrain at a higher
elevation than segment CD and would therefore
prove mO.re difficul,t and costly to construct and
maintain.Hence,segment CD was considered to
have a higher overall economic rating.
Technical (0)
Although both segments are routed below 3,000 feet
elevation,segment CF crosses more rugged,
exposed terrain with a maximum elevation of 2,600
feet.Segment CD,on the other hand,traverses
generally flatter terrain and has a maximum
..elevation,ofl,.8,QO.,fJ:!et!_ThJL.Qj,~a,c:lya,I'!!=,a,g~.§l_2.t,
se~ent,CF._ar~_somewhat offset,however,by the
Susitna River crossing 'thatwITT'be needed a't-'--'
river mile 150 for segment CD.Overall,the
technical difficulties associated with the two
segments may be regarded as being similar.
,Environmental (0)
One of the main concerns of.the variousenv[cot111lenEaIgroups and agencies is to keep a.ny
form of access away from sensitive ecological
areas previously inaccessible other than by foot.
Creating a pioneer road to construct and maintain
B-2-116
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851104
a transmission line along segment CF would open
that area to all-terrain vehicles and public use,
and thereby increase the potential for adverse
impacts to the environment.The potential for
environmental impacts along segment CD would be
present regardless of where the transmission line
was built since there is an existing four-wheel
drive trail together with the proposed railroad
extension in that area.It is clearly desirable
to restrict environmental impacts to a single
common corridor;for that reason,segment CD is
.preferable to segment CF.
Because of potential environmental impacts and
economic ratings,segment CF was dropped in favor of
segment CD.Consequently,corridors Three (AJCF)and
Thirteen (ABCF)were eliminated from further
cons idera tion.
(ii)The Choice Between ABC and AJC (0)
The two corridors remaining are therefore corridors
One (ABCD)and Fourteen (AJCD).This reduces to a
comparison of segment ABC on the south side of the
Susitna River and segment AJC on the north side.The
two segments were then screened in accordance with
the.criteria set out in subsection 2.7.3.The key
points of this evaluation are outlined below:
Economic (0)
For the Watana development,two 345 kV
transmission lines will be constructed from
Watana through to the Intertie.When comparing
the relative lengths of transmission line,it was
found that segment ABC was 33.6 miles in total
length compared to 36.4 miles for the northern
route using segment AJC.Although at first glance
a difference in length of 2.8 miles (equivalent to
12 towers at a spacing of 1,200 feet)seems
significant,other factors were taken into
account.Segment ABC contains mostly woodland,
black spruce in segment AB.Segment BC contains
open and woodland spruce forests,low shrub,and
open and closed mixed forest in about equal
amounts.segment AJC,on the other hand,contains
significantly less vegetation and is composed
predominantly of low shrub and tundra in segment
AJ and tall shrub,low shrub and open mixed forest
in segment JC.Consequently,the amount of
B-2-1l7
851104
clearing associated with segment AJC is ~onsider
ably less than with segment ABC,resulting in
savings not only during construction but also
during periodic recutting.Additional costs would
also be incurred with segment ABC due to the
increased spans needed to cross the Susitna River
(at river mile 165.3)and two other major creek
crossings.In summary,the cost differential
between the two segments would probably be
marginaL
Technical (0)
Segment AJC traverses generally moderately-sloping
terrain ranging in height from 2,000 feet to
3,500 feet with 9 mile'S of the segment being at an
elevation in excess of 3,000 feet.Segment ABC
traverses more rugged terrain,crossing several
deep ravines and ranges in elevation from 1,800
.feet to 2,800 feet.In general there are
advantages of reliability and cost associated with
transmission lines routed under 3,000 feet.The 9
miles of segment AJC at elevations in excess of
3,000 fe.et will be subject to more severe wind and
ice loadings than _segment ABC,and the towers will
have to be designed accordingly •Hqwever,these
additional costs will be offset by the
construction and maintenance problems with the
more rugged topography and major river -and cree~k
crossings of segment ABC.The technical
difficulties associated with the two segments are
therefore considered simila r.
Environmental (0)
From the previous analysis,it is evident that
th er ear ~~l!Q__si g!l:..-iJ i <:i!..I!~_I;tiJ~f_ex.enc_e~~_betwee n_~th e~.
~~--~--two--s-egments in terms of technicaldi fficul ty and
economics.The deciding factor therefore reduces
to the environmental impacts.The access road
routing between Watana and Devil Canyon was
selected because it has the least potential for
creating adverse impacts to wildlife,wildlife
habitat and fisheries.Similarly,Segment AJC,
withinwhichtheacce$sroad is loca.fed,is
.en-v:ir0tnnel1tall;yl es s seIlS itive~ha.n .SegmE!tl t A.BC,
for it traver'ses or approaches fewer areas of
productive habitat and zones of species
concentration or movement.The most important
consideration,however,is that for ground access
B-2-118
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during operation and maintenance,it will be
necessary to have some form of trail along the
transmission line route.This trail would permit
human entry into an area which is relatively
inaccessible at present,causing both direct and
indirect impacts.By placing the transmission
line and access road within the same general
corridor as in Segment AJC,impacts will be
confined to that one corridor.If access and
transmission are placed in separate corridors,as
in Segment ABC,environmental impacts would be far
greater.
Segment AJC is thus considered superior to Segment
ABC.Consequently,Corridor One (ABCD)was
eliminated and Corridor Fourteen (AJCD)selected
as the proposed route.
(c)Northern Study Area (0)
Corridors Three (AEDC)and Four (AEF)were determined unac-
ceptable because of many constraints,and thus rated F.
They include:the lack of an existing access road;prob-
lems in dealing with tower erection in shallow bedrock
zones;the need for extensive wetland crossings and forest
clearing;the 75 riv.er or creek crossings involved;and the
fact that prime habitat for waterfowl,peregrine falcons,
caribou,bighorn sheep,'golden eagle,and brown bear would
be crossed.In addition,Corridor Four crosses areas of
significant land use constraints and elevations of over
4,000 feet.
Corridor Two (ABDC)was identified as acceptable but not
preferred,and thus rated C.Certain constraints indenti-
fied for this corridor suggest that an alternative is pref-
erable.Compared with Corridor One,Corridor Two crosses
additional wetlands and requires the development of more
access roads and the clearing of additional forest lands.
Corridor One (ABC),shown in Figures B.2.7.8 to B.2.7.11,
was the only recommended corridor in the northern study
area.While many constraints were identified under the
various categories,it appears possible to select a route
within this corridor to minimize constraint influences.
This corridor is attractive economically,because it is
close to access roads and the Parks Highway.The visual
impact can be lessened by strategic placement of the line.
This line also best meets technical and economical
req uirements •
851104 B-2-U9
2.7.5 Route Selection (0)
(a)Methodology (0)
After identification of the preferred transmission line
corridors,the next step in the route selection process
involved the analysis of the data as gathered and presented
on the base map.Overlays were compiled so that various
constraints affecting construction or maintenance of a
transmission facility could be viewed on a single map.The
map was used to select possible routes within each of the
three selected corridors.By placing all major constraints
(e.g.,areas of high visual exposure,private lands,endan-
gered species,etc.)on one map,a route of least impact was
selected.Existing facilities,such as transmission lines
and tractor trails within the study area,w~re also
considered during the selection of a minimum 'impact route.
Whenever possible,the routes were selected near existing or
proposed access roads,sharing werever possible existing
righ t s-of-way.
The data ..base used in this aria lysis wa.s obtain.ed from the
following sources:
o An up-to-date land status study,
o Existing-aerial photos,
o New aerial photos conducted for selected sections of
the previously-recommended transmission line
,
o Environmental studies including aesthetic
considerations,
o Climatological studies,
o Geotechnical exploration,
o Additional field studies,and
o Public opinions •
......."'...····(b}-Sele ction··Cr iter-ia{.o.)--.-..---__.__._....
The purpose of this section is to identify three selected
routes:one from Healy to Fairbanks,the second from the
Watana and Devil Canyon damsites to the Intertie,and the
third from Willow to Anchorage.
The previously-chosen corridors were subject to a process of
refinement and evaiut iotl based on the.s;:tme techriical,
~economic,;:tn<:i·gn'V'iroOIngntalcrit~r;8:.usgdin corridor sel-
ection.In addition,special eUlphasis was placed on the
following points:
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851104 B-2-120
o Satisfying the regulatory and permit requir~ments;
o Selection of routing that provides for minimum
visibility from highways and homes;and
o Avoidance of developed agricultural lands and
dwellings.
(c)Environmental Analysis (0)
The corridors selected were analyzed to arrive at the route
which is most compatible with the environment and also
meets engineering and economic objectives.The environ-
mental analysis was conducted by the process described
below:
o Literature Review (0)
Data from various literature sources,agency communi-
cations,and site visits were reviewed to inventory
existing environmental variables.From such an
inventory,it was possible to identify environmental
constraints in the recommended corridor locations.
Data sources were cataloged and filed for later
retrieval.
o Avoidance Routing by Constraint Analysis (0)
To establish the most appropriate location for a
transmission line route,it was "necessary to
identify those environmental constraints that could be
impediments to the development of such a route.Many
specific constraints were identified during the
preliminary screening;others were determined during
the 1981 field investigations.
By utilizing information on topography,existing and
pro~osed land use,aesthetics,ecological features,
and cultural resources as they exist within the
corridors,and by careful placement of the route with
these considerations in mind,impact on these various
constraints was minimized.
o Base Maps and Overlays (0)
Constraint analysis information was placed on base
maps.Constraints were identified and presented on
overlays to the base maps.This mapping process
involved using both existing information and that
acquired through Susitna project studies.This
information was first categorized as to its potential
for constraining the development of a transmission
851104 B-2-121
line route within the preferred corridor and then
placed on maps of the corridors.Environmental
constraints were identified and recorded directly onto
the base maps.Overlays to the base maps were
prepared indicating the type and extent of the
encountered constraints.
Three overlays were prepared for each map:one for
visual constraints,one forman-made,and one for
biological constraints (Acres,TES 1982).
(d)Technical and Economic Analysis (0)
Route location objectives are to obtain an optimum combina-
tion of reliability and cost with the fewest environmental
problems.In many cases,these objectives are mutually
compatible.
Throughout the evaluation,much emphasis was placed on
locating the route relatively clos.e to existing surface
transportation facilities whenever possible.
The factors that contributed heavily in the technical and
economic analysis were:topography,climate and elevation,
soils,length,and access roads.Other factors of less
importance were vegetation and river and highway crossings.
These factors are detailed in Tables B.2.7.3 and B.2.7.16.
The next step in the .routeselection process involved
analysis of the data presented on the base maps.The
da ta we'['e used to select pOSll3ible routes within
each corridor.By placing all major constraints on
one map,routes of smallest impacts were selected.
Existing facilities,such as transmission lines and
tractor.trails-within..the.studyarea.,were .a1so ..taken
..in to .cons i de.:c.a t i.o..1l.:.c.d tlr i ng.J;:lLe~s eJ,..e~t:io.n.Qfa l.e.a.s.t...
impact route.
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(ii )Evaluation of a Primary Route (0)
851104
The evaluation and selection of alternative routes to
arrive at'a primaryroute.involved a closer
examfna.tion of.each.ofothe"possible routes using
··J:Il~pp$Ilgpr()c=e~Sle§l:andcl~t:~p.z;.ev:i.(luslYclesC=l:i1:>ed!
Preliminary routes were compared to determine the
route of least impact within the primary corridors of
each study area.For.example,such variables as
number of stream and road crossings required were
B-2-122
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noted.Then,following the field studie~and through
a comparison of routing data,including the route's
total length and its use of existing facilities,one
route was designated the primary route.Land use,
land ownership,and visual impacts were key factors
in the selection process.
(e)Route Soil Conditions (0)
(i)Description (0)
Baseline geological and geotechnical information was
compiled through photo interpretation and terrain
unit mapping.The general objective was to document
the conditions that would significantly affect the
design and construction of the tranmission line
towers.More specifically,these conditions include
the origins of various land forms,noting the
occurrence and distribution of significant geologic
features such as permafrost,potentially unstable
slopes,potentially erodible soils,possible active
fault traces,potential construction materials,
active floodplains,organic materials,etc.
Work on the air photo interpretation consisted of
several activities culminating in a set of terrain
unit maps showing surface materials,geologic
features,and conditions in the project area.
The first activity consisted of a review of the
literature concerning the geology of the Intertie
corridors and transfer of the information gained to
high~level photographs at a scale of 1:63,000.
Interpretation of the high-level photos created a
regional terrain framework which assisted in
interpretation of the low-level 1:30,000 project
photos.Major terrain divisions identified on the
high-level photos were then used as an aerial guide
for delineation of more detailed terrain units on the
low-level photos.The primary effort o·f the work was
the interpretation of over 140 photos covering about
300 square miles of varied terrain.The land area
covered in the mapping exercise is shown on map
sheets and displayed in detail on photo mosaics (R&M
Consultants 1981a).
As part of the terrain analysis,the various bedrock
units and dominant lithologies were identified using
published U.S.Geological Survey reports.The extent
of these units was shown on the photographs,and,
851104 B-2-123
using exposure patterns,shade,texture,and other
features of the rock unit as they appeared on the
photographs,unit boundaries were drawn.
Physical characteristics and typical engineering
properties of each terrain unit were considered and a
chart for each corridor was developed.These charts
identify the terrain units as they have been mapped
and characterize their properties in numerous
categories.This allows an assessment of each unit's
influence on various project features.
(ii)Terrain Unit Analysis (0)
(1
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The terrain unit is a special purpose term comprising
the land·forms expected to occur from the ground '}
surface to a depth of about 25 feet.'..;~
The terrain unit maps for the proposed Anchorage-to-
Fairbanks transmission line show the aerial extent of 'J
the specific terrain units which were identified
during-the air photo investigation and were corrobo-
rated in part by a limited on-site surface investiga-,'.1
tion.The units document the general geology and
geotechnical ,characteristics of the area.
The north and south corridors are separated by J
several hundred miles and,not surprisingly,
eucoun-tet'··diffe-t'ent-,·geomot'ph-iG--pt'ov-iuGes and-c-l-imatic
condi tions.Hence,while there are many landforms ,,\,
(or individual terrain units)that are common to both )
corridors,there are also some landforms mapped in
just one corridor.The landforms or individual '..(
terrain units mapped in both corridors were briefly )
described.'
Several of the landforms have not been inde-
851104
pendently but rather as compound or complex terra
--,-uni~-Gompound---terrain units resuftwhen one -----
landform overlies a second recognized unit at a
shallow depth (less than 25 feet),such as a thin
deposit of glacial till overlying bedrock or a mantle
of lacustrine sediments overlying till.Complex
terrain units have been mapped where the surficial
exposure pattern of two landforms are so intricately
related that they must be mapped as a terrain unit
complex,Stich as some areas of bedrock and colltivit:lrii.
The compound and complex terrain units were described
as a composite of individual landforms comprising
them.The stratigraphy,topographic position,and
B-2-124
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aerial extent of all units,as they appear in each
corridor,were summarized on the terrain·unit
properties and engineering interpretations chart (R&M
Consultants 1981a).
(f)Results and Conclusions (0)
A study of existing information and aerial overflights,to-
gether with additional aerial coverage,was used to locate
the recommended route in each of the southern,central,and
northern study areas.
Terrain unit maps describing the general material expected
in the area were prepared specifically for transmission line
..studies and were used to loca te the route away from unfavor-
able soil conditions wherever possible.Similarly,environ-
mental constraint analysis information was placed on base
maps and overlays (Acres,TES 1982)and the route modified
accordingly.
Subsequent to the submission of the Feasibility Study (Acres
1982c),additional environmental and land status studies
made it possible to further refine the alignments to the
extent that most environmentally sensitive areas and areas
where land acquisition may present a problem have been
avoided.In the Fairbanks-to-Healy and the Willow-to-
Anchorage line sections,these refinements have resulted in
an improved alignment which is generally in close proximity
to the earlier proposal.
Also subsequent to the Feasibility Study,the proposals for
access to the power development were reassessed.As
mentioned earlier,this resulted in a decision to provide
access to Watana for the Denali Highway and build a
connecting road between the dams on the north side of the
Susitna River.The earlier line routing proposals were
accordingly reviewed to establish the optimum alignment.
The desire to limit environmental impacts to a single
corridor led to the routing of the transmission line more or
less parallel to the access road.Hence,between the dams,
the line shares the same general corridor as the access road
to the north of the Susitna River.From Devil Canyon to the
intersection with the Intertie (at a switching station
approximately four miles northeast of Gold Creek),the line
is located south of the Susitna River paralleling the
proposed railroad extension,and an existing four-wheel
drive trail.
The original corridors,which were three to five miles in
width,were narrowed to a half mile and,after final adjust-
851104 B-2-125
ment,to a finalized route with a defined right~of-way.The
selected transmission line route for the three study areas
is presented in Exhibit G.Preliminary studies have
indicated that,for a hinged-guyed X-configuration tower
having horizontal phase spacing of 33 feet,the following
right-of-way widths should be sufficient:
I J
o 1 tower
o 2 towers
o 3 towers
o 4 towers
190 feet,
300 feet,
400 feet,and
510 feet.
These right-of-way widths will be subject to minor local
variation where the need for special tower structures dic-
tates or where difficult terrain is encountered 'and will be
addressed fully in the final design phase of the project.
2.7.6 Towers,Foundations and Conductors (0)
The Anchorage and Fairbanks Intertie will consist of existing
lines and a new section between Willow and Healy.The new
s-ecEi6tiwilr be b'liilEE6345kVsbitida.rdsblit will be temporarily
operated at 138 kV and will be fully compatible with Susitna
requirements.
(a)Transmission Line Towers (0)
(i)Selection of Tower Type (0)
Because of the unique soil conditions in Alaska which
are characterized by extensive regions of muskeg
and permafrost,conventional self-supporting or rigid
towers will not provide a satisfactory solution for
the proposed transmission line.
Permafrost and seasonal changes in the soil are known
-tocaus e-largeearth-moveme nt s-at--someloca t io ns,-
..~r_eq_uidng_t.o.w_e.r.s._w_ith_a_.high_degr.ee_.o_f .._fl.exibili.ty__
and capability to sustain appreciable loss of
structural integrity.
A guyed tower is well suited to these conditions;
these include the guyed-V, guyed-Y,guyed delta,and
guyed portal type structures.The type of structure
·selected for·the construction o{the Intertie is the
hing~ci-"g'Uy~dl;t:~~lX:'::t:ow~:r,c9,r~JiI1~lll~I1t0 f theguyeci
structure concept.This type of tower is therefore a
prime candidate for use on the Watana transmission
system.Guyed pole-type structures will be used on
larger angle and dead end structures;a similar
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851104 B-2-l26
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851104
arrangement will be used in especially heavy loading
zones.
The design features of the X-tower include hinged
connections between the legs and the foundation and
four longitudinal guys attached in pairs to two guy
anchors,providing a high degree of flexibility with
excellent structural strength.The wide leg spacing
results in relatively low foundation forces which are
carried on pile type footings in soil and steel
grillage or rock anchor footings where rock is close
to the surface.
In narrow right-of-way situations,cantilever steel
pole structures are anticipated,with foundations
consisting of cast-in-lace concrete augered piles.
In the final design process,experience gained in the
construction and operation of the Intertie will be
used in the final selection of the structure type to
be used for the Watana transmission.
All tower structures will be of "weathering"type
steel which matures to a dark brown color over a
period of a few years and is considered to have a
more aesthetically pleasing appearance than either
galva~ized steel or aluminum.
(ii)Climatic Studies and Loadings (0)
Climatic studies for transmission lines were
performed to determine probable maximum wind and
ice loads based on historical data.A more detailed
study incorporating additional climatic data was
carried out for the Intertie final design.These
studies have resulted in the selection of preliminary
loading for the line design (Acres 1982c,Vol.4)•
Preliminary loadings selected for line design should
be confirmed by a detailed study,similar to that
performed for the Intertie,that will examine
conditions for the Healy-to-Fairbanks,
Willow-to-Anchorage and Gold Creek-to-Watana sections
of the route,together with an update of the
Healy-to-Willow study incorporating any data from
field measurement stations collected in the interim
period.
B-2-127
851104
(b)
Based on data currently available,it appears that
the line can be divided up into zones as far as
climatic loading is concerned as follows:
o Normal Loading Zone,
o Heavy Ice Loading Zone,and
o Heavy Wind Loading Zone.
The heavy ice and heavy wind zones will have an addi-
tional critical loading case included to reflect the
special nature of the zone.
(iii)Tower Family (0)
A family of tower designs will be developed as
follows:
o Suspension towers will be provided for both
standard span plus angle (up to 3°)application
.and for long span or light angle (0°to 8°)
application.
o Tension towers will be provided for light angle
and dead end (0°to 8°),for large angle and
dead end (8°to 50°),and for minimum angle and
dead end (50°to 90°).
The maximum wind span and weight span ratios to be
.-···uti-Uzed ~i:J:tDe-~ret infinal--di'fsignto-refl ectthe ..
rugged nature of the terrain along the line route.
Some triaL spotting.of towers in representa ti ve
terrains will be used to guide this selection.
Minimum weight ~pl:i..!ltowind span ratio limits will be
set during tower spotting and a "low temperature
template"used to check that unexpected uplift will
not develop at low weight .span towers for very low
The span to be used in design will be the subject of
an economic optimization study.A span of not less
than 1,200 feet is expected with spans in the field
varying to greater and lesser values in specific
cases depending upon span ratio and loading zone.
Geotechnical Conditions (0)
The generalized terrain analysis (R&M Consultants 1981a)
was conducted to collect geologic and geotechnical data
B-2-l28
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for the transmission line corridors,a relatively large
area.The engineering characteristics of the terrain
units have been generalized and described qualitatively.
When evaluating the suitability of a terrain unit for a
specific use,the actual properties of that unit must be
verified by on-site subsurface investigation,sampling,
and laboratory testing.
The three main types of foundation materials along the
transmission line are:
o Good material,which is defined as overburden which
permits augered excavation and allows installation
of concrete without special form work;
o Wetland and permafrost material which requires
special design details;and
o Rock material de fined as material-in which
drilled-in anchors and concrete footings can be
used.
Based on aerial,topographic,and terrain unit maps,the
following was not;:ed:
o For the southern study area:Wetland and
permafrost materials constitute the major part of
this area.Some rock and good foundation materials
are present in this area in a very small
proportion.
o For the central study area:Rock foundation and
good materials were observed in most of this study
area.
For the northern study area:The major part of this area
is wetland and permafrost materials.Some parts have
rock materials.
(.1.'1.')f 'Types 0 Foundat1.ons (0 )
851104
The types of tangent tower envisaged for these lines
will require foundations to support the leg or mast
capable of carrying a predominantly vertical load
with some lateral shear,and a guy anchor
foundation.
B-2-129
The cantilever pole structure foundation.is required
to resist the high overturning moment inherent in the
cantilever arrangement •
The greater part of the combined maxnnum reactions on
a transmission tower footing is usually from short
duration loads such as broken wire,wind,and ice.
With the exception of heavy-angled,dead end or
terminal structures,only a part of the total
reaction is ofa permanent nature.As a
consequence,the permissible soil pressure,as used
in the design of Quilding foundations,may be
considerably increased for footings for transmission
struc tures •
The permissible values of soil pressure used in the
footing design will depend on the structure and sup-
porting soil.The basic criterion is that
displacement of the footing not be restricted because
of the flexibility of the selected X-frame tower and
its hinged connection to the footing.The shape and
configU1:ation of the selected.tower are important
factors in foundation considerations.
Loads on the tower consist of vertical and horizontal
loads and are transmitted down to the foundation and
then distributed ~o the soil.In a tower placed at
an angle or used as dead end in the line,the--_.------.--···------------liofTion far -roads.·~i"re--res·ponsiorefor--·-a·Ta rge-·portion
of the loads on the foundation.In addition to the
horizontal shear,a moment is also present at the top
of the foundation,creating vertical download and
upl iftforces on the footing.
To enable the selection of a safe and economical
tower foundation design for each tower site,it is
.····-·--neces·saI'-y~-to·sele ct-·a·footing-which take saccount·o f·
.the_ac.l:.ual-soil__.condi..tio.ns_a.~-the-si.te..__This_is...done_..
by matching the soil conditions td a series of ranges
of soil types and groundwater conditions which have
been predetermined during the design phase to cover
the full range of soils expected to be encountered
along the line length.Preconstruction drilling,
soil saIllpling,and laboratory testing at
representative locations along the line enable the
design ofa familyoLfo·otings tobeprepa red for
each tower type from which a selection of the
appropriate footing for the specific site can be made
during construction.
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851104 B-2-130
The foundation types for structure legs and masts
will be grouted anchor where rock is very shallow or
at surface and steel grillage with granular backfull
where soil is competent and not unduly
frost-sensitive.In areas where soils are weak and
where permafrost or particularly frost-heave prone
material is encountered,driven steel piles will be
used.
Guy anchors will use grouted anchors in rock.
Grouted earth or helical plate screw-in anchors with
driven piles will be used in permafrost or very weak
soils.
Proof load testing of piles and drilled-in anchors
will be required both for design and to check on the
as-built capacity of these foundation elements during
construction.
(c)Voltage Level and Conductor Size (0)
Economic studies were carried out on transmission utilizing
500 kV,345 kV,and 230 kV a.c.At each voltage level an
optimum conductor capacity was developed.Schemes involving
use of 500 kV or 345 kV on the route to Anchorage and 345 kV
or 230 kV to Fairbanks were investigated.The study
recommended the adoption of two 345-kV units to Fairbanks
and three 345-kV units to Anchorage.Comparative studies
were carried out on the possible use of HVDC.However,
these studies indicated no economic advantage of such a
scheme.
The 345-kV system studies indicated that a conductor
capacity of 1,950 MCM per phase was economical with due
account for the value of losses.A phase bundle consisting
of twin 754-MCM Rail (45/7)ACSR was proposed as meeting the
required capacity and also having acceptable corona and
radio interference performance.Detailed design studies as
part of the final design will compare the economics of this
conductor configuration with the use of alternatives such as
twin 954-MCM Cardinal (54/7)ACSR and single 215.6-MCM
Bluebird (84/19)ACSR which could give comparable electrical
performance with better structural performance.Cardinal,
because of a 15 percent superior strength-to-weight ratio,
can be sagged tighter than Rail,thereby resulting in
savings in tower height and/or increased spans.Bluebird,
because of a smaller circumference and projected area
compared with a twin conductor bundle,attracts some 15
851104 B-2-131
851104
percent less load from ice or wind.Together with its
greater strength,this leads to less sag under heavy
loadings and lighter loads for the structures to carry.
Conductor swing angles will also be reduced,thus reducing
tower head size requirements and edge of right-of-way
clearing.
B-2-132
,\
I
3 -DESCRIPTION OF PROJECT OPERATION (***)
3.1 -Hydrology (**)
Operation of the Susitna project is dependent upon the hydrology of the
basin.A complete discussion of the Susitna basin hydrology appears in
Section 2.2 of Exhibit E,Chapter 2.A summary follows.
3.1.1 -Historical Streamflow Records (**)
Continuous historical streamflow records of various length (7 to
34 years through water year 1983)exist for gaging stations on
the Susitna River and its tributaries.USGS gages are located at
Denali,Cantwell (Vee Canyon),Gold Creek,and Susitna Station on
the Susitna River;near Paxson on the Maclaren River;near
Talkeetna on the Chulitna river;at Talkeetna on the Talkeetna
River;and at Skwentna on the Skwentna River.
In 1980 a USGS gaging station was installed near Susitna Station
on the Yentna River,and in 1981 a USGS gaging station was
installed at Sunshine on the Susitna River.Statistics on river
mile,drainage area,and years of record are shown in Table
B.3.1.1.A summary of the recorded maximum,mean,and minimum
monthly flows for water year 1951 s through 1981 are shown in
Table B.3.1.2.Because of the short duration of the streamflow
records at Sunshine and on the Yentna,summaries for these two
stations have not been included.The station locations are
illustrated on Figure B.3.1.1.
Monthly and weekly streamflow sequences for the Susitna River at
the Watana and Devil Canyon damsites and at Gold Creek were
estimated from the existing USGS data.The procedures are
outlined in a report by the Applicant (HE 1985).Tables B.3.1.3
through B.3.1.5 provide estimated monthly streamflow at Watana,
Devil Canyon,and Gold Creek,respectively.Tables B.3.1.6
through B.3.1.8 provide weekly streamflow for the same locations.
The streamflow sequences were used in weekly and monthly
reservoir operation simulations.The 1969 low flow year was not
modified for these sequences as it had been for the July 1983
License Application (APA 1983).Table B.3.1.9 compares the
estimated monthly mean,maximum,and minimum flows at several
sites in the basin..
Comparison of mean annual flows in Table B.3.1.9 indicates that
40 percent of the streamflow at Gold Creek originates above the
Denali and Maclaren gages.It is in this catchment that the
glaciers which contribute to the flow at Gold Creek are located.
Figure B.3.1.2 shows the average annual flow distribution within
the Susitna River Basin.The Susitna River above Gold Creek
851104 B-3-1
contributes approximately 20 percent of the.mean annua~flow
measured at Susitna Station near Cook Inlet.The Chulitna and
Talkeetna Rivers contribute about 20 and 10 percent of the mean
annual flow at Susitna Station,respectively.The Yentna
provides 40 percent of the flow,with the remaining 10 percent
from miscellaneous tributaries.
The variation between summer mean monthly flows and winter mean
monthly flows is greater than a 10 to 1 ratio at all stations.
This large seasonal difference is due.to the characteristics of a
glacial river system.Glacial melt,snow melt;and rainfall
provide th.emajority of .the annual river flow during the s~mer.
At Gold Creek,for example,almost 90 percent of the annual
streamflow volume occurs during the months of May through
September.
A comparison of the maximum and minimum monthly flows for May
through September indicates a high flow variability at all
stations from year to year.
3.1.2 -Effect of Glaciers (***)
The glaciated portions of the Susitna River Basin above Gold
Creek play a significant role in the hydrology of the area.
Located on thedsouthern slopes of the Alaska Range ;the glaciated
regions receive the greatest ameunt of snow and rainfall in the
basin.During the'summer months ,these regions contribute
significant amounts of snow and glacial mel t..The glaciers,
.CoverIng-aDDu!:290'square miresTor··.aboutfi·ve-perceii!:··o~f·Elie
tbtal drainage area above Gold Creek Station),act as reservoirs
that-may produce a significant portion 0.£the water in the basin
above Gold Creek during drought periods.In the record drought
year of 1969 ,thepropor.tionof flow at Gold Creek contributed
from upstream of the Denali and Maclaren gages was 53 percent.
On average,·the same area contributes only 40 percent.
··_·E-v·en-·though--the·re--is-e-vidence··that--the-gla-c-ier-s--ha·ve---been-wasting --
...._.._~---.~-since-L949-,--there-is ..lit-tle-da.ta-a:llailab-le-to-determine~wha.t-the
impact of wasting has been on the recorded flow at Gold Creek or .
what will occur in the future (R&M;1981 c and 1982a).Large
glaciers,such as those in the Susitna Basin,take decades to
attain equilibrium after a change in climate.
For years of very low precipitation,runoff from the glaciers
willbe.more·important ,and-theremaybesubstantialnet waste of
..-'gla c iers~L'--How.ever;:if .long~term:.mean.pr.e_cipitationrema ins
approximately the same,it is likely that net waste of glaciers
in one year will be replenished by excess snow in another.
j
.\
851104 B-3-2
1
The Applicant has analyzed the mass balance of the glaciers over
the 1981-1983 period (Harrison 1985)and refined the estimate of
glacier wasting from 1949 to the present (Clarke 1985).These
analyses are dicussed in Exhibit E,Chapter 2,Section 2.2.
It is difficult to predict future trends.If the glaciers were
to stop wasting due to,perhaps,a climate change,there could be
hydrological changes throughout the basin.On the other hand,
the wasting of the glaciers could easily continue over the life
of the project.There is no way to judge whether wasting will
continue into the future.Hence,no mechanism presently exists
for analyzing what will occur during the life of the project.As
a result,the recorded streamflow was not adjusted to account for
glacier wasting.
3.1.3 -Floods (**)
The most common causes of floods in the Susitna River Basin are
snow melt or a~~ombination of snow melt and rainfall over a large
area.This type of flood occurs between May and July,with the
majority occurring in June.Floods attributable to heavy rains
have occurred in August and September.These floods are
augmented by snow melt from higher elevations and glacial
runoff.
Examples"of flood hydrographs can be seen in the daily discharges
for 1964,1967,and 1970 for Cantwell,Watana,and Gold Creek
(Figures B.3.l.3 through B.3.l.s).The years 1964,1967,and
1970 represent wet,average,and dry hydrological years on an
annual flow basis;respectively.The daily flow at Watana has
been approximated using a linear drainage area-flow relationship
between Cantwell and Gold Creek.Figure B.3.l.3 shows the
largest snow melt flood on record at Gold Creek.The 1967 spring
flood hydrograph shown in Figure B.3.l.4 has a daily peak equal
to the mean annual daily flood peak.In addition,the flood peak
of 80,209 cfs is the fifth largest flood peak at Gold Creek on
record.Figure B.3.l.s illustrates a low flow spring flood
hydro gra ph.
The maximum recorded instantaneous flood peaks for Maclaren,
Denali,Cantwell,and Gold Creek,recorded by the USGS,are
presented in Table B.3.l.l0.Annual peak flood frequency curves
for these stations are illustrated in Figures B.3.l.6 through
B.3.l-9.
Based on the station record,estimates of the 100-year,1000-year
and 10,000-year floods at Gold Creek have been made.Since the
station records are only available for 34 years,estimates of the
95 percent one-sided upper confidence limit have been provided.
851104 B-3-3
Flood
Return Period
100-Year
1,000-Year
10,000-Year
Mean
Estimate (cfs)
108,000
147,000
190,000
95 Percent
One-Sided Upper
Confidence Limit (cfs)
138,000
200,000
270,000
851104
The mean annual flood at Go:l.d Creek is estimated as the flood
having a return period of 2.33 years (Chow 1964)or approximately
50,000 cfs.The mean annual floods at Watana and Devil Canyon
would be approximately 45,000 cfs and 48,000 cfs,respectively.
Probable maximum flood (EMF)studies were conducted for both the
Watana and Devil Canyon damsites for use in the design of project
spillways and related facilities (Acres 1982c).The EMF floods
were determined by using the SSARR watershed model developed by
the Portland District,U.S.Army Corps of Engineers (1975)and
are based on Susitna Basin climatic data and hydrology.The
probable maximum precipitation was derived from a maximization
study of historical storms.The studies indicate that-'the PMF
peak at theWatana-damsi-te is 326,000 cfs.
3.1.4 -Flow Variability (***)
The variability of flow in a river system is important to all
instream flow uses.To illustrate the :variability of flow in the
Susitna River,monthly and annual flow duration curve~showing
------~the--pl:opoI'_t-ion~oc£··~t~ime~tha-l;_the--di_sch-arge-:equa-lg--or--.-exceeds-·-a
given value were developed for three mainstem Susitna River
gaging stations (Denali,Cantwell,and Go1d.Cr.E!ek).These
curves,based on mean daily flows,are illustrated in Figure
B.3.1.1O.
The shape of the monthly and annual flow duration curves is
similar for each of the stations and is indicative of flow from
._l:lS'~tl:l~!!.gII:l~~o!IJ~!Y~.!:_!!(!i~111~J~~f)-"__litr~~m flQ'N_j~}~_--lg_Wj,!L.~l1,~.·
winter months,with little variation in flow and no unusual
peaks.Groundwater contributionsa-re the primary ·source of the
small but relatively constant winter flows.Flow begins to
increase slightly in April as breakup approaches.Peak flows in
May are an order of magnitude greater than in April.Flow in May
also shows the greatest variation for any month,as low flows may
continue into May before the high snow melt/breakup flows occur.
June has the highest peaks ..and the highestmedian ..f1ow for the
middlearid·uppei basiristati6ns.tbti!1llont::hs·6fJu:l.Y·and August
have relatively flat flow duration curves.This situation is
indicative of rivers with strong base flow characteristics,as is
the case for Susitna,with its contributions from snow and
B-3-4
1
851104
glacial melt during the summer.More variability of flow is
evident in September and October as cooler weather becomes more
prevalent accompanied by a decrease in glacial melt and,hence,
discharge.
The daily hydrographs for 1964,1967,and 1970,shown in Figures
B.3.1.3 through B.3.1.5,illustrate the daily variability of the
Susitna River at Gold Creek,Watana,and Cantwell.The years
1964,1967,and 1970 represent wet,average,and dry hydrological
years on an annual flow basis,respectively.
3.1.5 -Flow Adjustments (**)
Evaporation from the Watana and Devil Canyon reservoirs has been
evaluated to determine its significance.Evaporation is
influenced by air and water temperatures,wind,atmospheric
pressure,and dissolved solids within the water.However,the
evaluation of these factors'effects on evaporation is difficult
because of their interdependence on each ,ather.Consequently,
more simplified methods were preferred and have been utilized to
estimate evaporation losses.For Watana,only Stage III was
evaluated,since this would be the more critical case.
The monthly evaporation estimates for the reservoirs are
presented in Table B.3.1.11.The estimates indicate that
evaporation losses will be less than or equal to additions due to
precipitation on the reservoir surface.Therefore,a
conservative approach was taken,with evaporation losses and
precipitation gains neglected in the energy calculations.
Leakage is not expected to result in significant flow losses.
Seepage through the relict channel is estimated as less than
one-half of one percent of the average flow and therefore has
been neglected in the energy calculations to date.
Minimum flow releases ~re required throughout the year to
maintain downstream river stages.The most significant factor in
determining the minimum flow value is the maintenance of
downstream fisheries.After completion of Devil Canyon,flow
releases from Watana will be regulated by system operation
requirements.Because the tailwater of the Devil Canyon
reservoir will extend upstream to the Watana tailrace,there will
be no release requirements for streamflow maintenance of Watana
for the Watana/Devil Canyon combined operating configuration.
See Section 3.3 of this Exhibit for further discussion of the
flow release requirements.
Existing water rights in the Susitna basin were investigated to
determine impacts on downstream flow requirements.Based on
inventory information provided by the Alaska Department of
B-3-5
Natural Resources,it was determined that existing water users
will not be affected by the project.A listing of all water
appropriations located within one mile of the Susitna River is
provided in Table B.3.1.12.
3.2 Reservoir Operation Modeling (***)
3.2.1 -Reservoir Operation Models (***)
Two computer models used to simulate the operation of the Susitna
Project reservoirs are:the monthly reservoir operation program
(Monthly RESOP);and the weekly reservoir operation program
(Weekly RESOP).The monthly RESOP was originally developed for
the Susitna feasibility study and subsequently updated.The
weekly RESOP was developed using selected subroutines from the
monthly RESOP.The objective of-the reservoir ope~ation study ~s
to determine the operation which maximizes the Susitna Project
benefits under the specified constraints and to provide estimated
reservoir outflows and water levels for environmental impact
ana.lyses.
The time increment used for the simulation affects both the
computational effort required and the accuracy of the results
obtained.A weekly time step is used for flow regime studies
because the results more precisely show the fluctuation of water
surface elevation and reflect the critical conditions.Weekly
simulations also yield more gradual changes in outflow discharges
from week to week than monthly simulations.Both simulations
~yiera~-coinparaDre--es timatesorSusTEna-power-and-en~ergy
production.The monthly program is used to determine the project
capability for -the economic analyses while -the weekly simula tion
is used to provide input to the environmental analyses.
Either program simulates Susitna operation over 34 years of
historical streamflow records (January 1950-December 1983).Key
inputs to the models are the reservoir and powerplant
--------------cha-racter-ist-ics,---power-demand--distri-but-ion-,~--and~-env-i-ronmen-t-a-l--
---~--constraints-.--The~RESO-P-mode_ls--'-simu_la-te-the-reser-vo-i-r-storage-,--
power generation,turbine discharge,outlet works release,and
spill,as a function of time.
The resulting water levels,and releases from turbines,outlet
works,and the spillway,are used for evaluation of environmental
itnpacts OLflowstability,fij;hery _habi~at,flood fr:equency,
temperature,stage fluctuation,and ice conditions in the river
downstream.The _average energy _production_,__firmenergy
production,and capacity of the project for various operation
schemes are used by the electric generation expansion program in
the economic evaluation of alternative expansion plans.
-i
.j
'J
II
851104 B-3-6
851104
3.2.2 -Basic Concept and Algorithm of Reservoir Operation (***)
Reservoir operation simulation is basically an accounting
procedure which monitors the reservoir inflow,outflow,and
storage over time.The storage at the end of each time step is
equal to the initial storage plus inflow minus outflow within the
time step.The time step is either a month or a week,depending
on the program used.A key constraint on the simulation is the
minimum instream flow requirement at Gold Creek which must be
satisfied each time step.The minimum project release is the
minimum flow requirement at Gold Creek minus the intervening area
flow between the downstream project site and Gold Creek.A rule
curve or operation guide governs the release for power,with the
total powerhouse release restricted by the discharge required to
meet the system power demand.
The basic Susitna development scheme is as follows:
1.Watana Stage I is the initial project.At a normal
maximum reservoir level of el.2,000 feet above mean sea
level (ft,msl),and with 150 ft of drawdown,2.37
million acre-feet of active storage is provided.This
is roughly 40 percent of the mean annual flow at the
damsite,and affords some seasonal regulation.All
Stage I units will be operational _in 1999.
2.Devil Canyon is Stage II.It will be constructed in a
narrow canyon with a normal maximum reservoir level of
el.1,455 ft,msl and only 50 ft.of drawdown.Hence,
it mainly develops head,relying upon.Watana to regulate
flows for power production.All Stage II units will be
operational in 2005.
3.Stage III involves raising the Watana dam 180 feet to
its ultimate height,with a normal maximum reservoir
elevation of el.2,185 ft,msl and 120 feet of drawdown.
The active storage will be 3".7 million acre-feet,about
64 percent of the mean annual flow.Commercial
operation of the two new Stage III units will be in
2012.
The reservoir operation methodology attemps to keep the Devil
Canyon Reservoir close to its normal maximum operating level
while using Watana's storage to provide the necessary seasonal
regulation.Therefore,the modeling effort in both single and
double reservoir operation simulation is focused on the Watana
operation.The operation level constraints are summarized in
Table B.3.2.l.Curves of area and volume versus elevation for
both the Watana and Devil Canyon Reservoirs are shown on Figure
B.3.2.I.
B-3-7
(a)Watana Stage I (***)
An initial operation is done for each time step to begin the
simulation.This algorithm is explained in detail in
Section B-3.2.7 of this Exhibit.After the initial
operation,the energy generated is compared to the system
energy demand in each time step.If the energy produced is
greater than that which the system can use,the energy
production is reduced.This is done by decreasing the
discharge through the powerhouse.
A minimum instream flow requirement isp~escr~bed at Gold
Creek to ensure that the project will release flows for
environmental purposes.The historical intervening flow
between Watana and Gold Creek is assumed to be available to
supplement the project releases to meet the minimum flow
requirement.If the flow requirement is not met,more water
is released through the powerhouse in order to meet the
requirement.The instream flow requirement may cause more
energy to be generated than the required amount.The
powerhouse discharge must again be decreased.However,
....instead of reducing the total project outflow,discharge is
diverted from the powerhouse to the out'let works.This cone
valve release is called an environmental release since it is
made only to meet the environmental requirement and is not
used for power generation.
The outlet works capacity atWatana I is 24,000 cfs,while
.__._--~~t;.he--powerhouse-ca-pac-i-ty-is-about--14-;0 OO-·cis.··-Int;.he··event
that a flood could not be passed through the powerhouse and
outlet works,because ofe_ne..rgy ciemand and hydraulic
capacity limitations,the reservoir is allowed to surcharge
above the normal maximum water surface elevation.This
surcharging is done to avoid the use of the spillway for
floods less than the 50-year event !A maximtnn surcharge
level ·of el.2,014 is permitted before the spillway
11
l
IJ
.1
··--Tb-Y--watanasta:-ge--Ior-stage--rrrwt th DevilcanyOti-·_·
Stage II (***)
For simulation of double reservoir operation,the initial
operation for each time step is the.s.ame as .that for the
single reservoir.Devil Canyon operates as run-of-river as
long as the :reservoir is f tl1l.The DeyilCatlyotl reservoir
is-to be-refilled.if.the reservoir.is~n()i::full,and the
fotal irif10w is greaterthariEhe release required 1:0 meel:
the downstream flow requirement.After the initial
operation,the total energy generated at Watana and Devil
851104 B-3-8
Canyon is compared to the system energy demand.If the
energy produced is greater than that which the system can
use,the energy produc tion is reduced.This is done by
decreasing the discharge through the Watana powerhouse.
The intervening flow between Devil Canyon and Gold Creek is -
assumed to be available to supplement the project releases
to meet the minimum flow requirements.If the flow
requirement is not met,more water is released through the
Devil Canyon powerhouse in order to meet the requirement and
the Devil Canyon reservoir will draw down.If the increased
release through the Devil Canyon powerplant will cause the
total energy generation to be greater than the system
demand,the release from the Watana powerplant is reduced.
Continuous drawdown at Devil Canyon can occur in the summer
of dry ,years when the system energy demand is.low and the
downs tream flow req uirement is high.If the wa ter leve 1 at
Devil Canyon reaches the minimum eleva tion,of 1,405 ft,
Watana must then release water to satisfy the minimum flow
requirement.If the release from Watana for the minimum
flow requirement will generate more energy than the required
amount,part of the release is diverted to the outlet
works.
The powerhouse hydraulic capacity 'is about l4,QOO cfs for
both Watana Stage I and Devil Canyon,and about 22,000 cfs
for Watana Stage III.The outlet works capacity at Devil
Canyon is 42,000 cfs while the capacity at Watana is 24,000
ds in Stage land 30,000 ds in Stage III.In the event
that a flood could not be passed through the powerhouse.and
cone valves,because of energy demand and hydraulic capacity
limitations,Watana is allowed to surcharge above its normal
maximum.The maximum surcharge.level is el.2,014 ft for
the Watana Stage I dam and el.2,193 for the Stage III dam.
Since the capacity of the outlet works at Devil Canyon is
large,and flood flows are attenuated at Watana before
reaching Devil Canyon,a surcharge of only one'foot above
the normal maximum of el.1,455 is allowed,and the spillway
operates if the water surface exceeds el.1,456 ft.
3.2.3~Standard Weeks (***)
A system of standard weeks,in which the dates of weeks in a year
are the same every year,is used in the weekly simulation.In
accordance with the water year,standard weeks start on October 1
and end on September 30 with seven days a week in normal weeks
but with eight days for the last week in September.The last
week in February also has eight days in a leap year.A standard
week begins on Sunday and ends on Saturday.
851104 B-3-9
The weekly simulation is done on a calendar year basis"from
January to December.In applying the standard weeks in the
weekly simulation,the first week of a year starts on December 31
of the previous year and ends on January 6 of the current year.
The standard week numbers and corresponding dates are listed in
Table B.3.2.2.
3.2.4 -Demand Forecast (***)
The reservoir operation models use the system'energy requirement
at plant to define the expected demand.Since SHCA and composite
electric demand forecasts are similar (Exhibit B,Chapter 5,
Tables B.5.4.6 and B.5.4.17),reservoir operation studies were
conducted using the SHCA forecast.The annual peak and net
energy generation projections of the railbelt system based on the
SHCA forecast are listed in Table B.3.2.3.The monthly energy
requirements are obtained by applying the monthly distribution of
annual requirement as shown in Table 'B.3.2.4.
3.2.5 -Existing Hydroelectric Plants (***)
'Tlieexist:irig Railbelt hydrcfplarits are 'lUodeled as a.cOll1bined plant
in the simulation.These plants include Eklutna,Cooper Lake,
and Bradley Lake.Eklutna and Cooper Lake are currently
operating.Bradley Lake is assumed to go on-line in 1990.The
monthly average energy generation of'the existing hydroplants is
given in Table B.3.2.5.
~~Tb:e-'differE!n-C-Ef-Detweeff-tl'fe"tot:alsystern····e nergyrequ'iremenc·····atid
the energy production of existing hydroplants is the residual
requir.ement to be provided by either Susitna orthennal plants.
In order to determine the energy requirement on a weekly basis,
the monthly energy requirement and the ener,gy production of
existing hydroplants are converted to a weekly energy.The
weekly energies were estimated from the monthly energies so that
the sum of the weekly energy within a month equals the monthly
3.2.6 -Release Constraints (***)
An instream flow regime is a series of minimum and maximum
discharges for maintaining fish habitat.The degree of fish
protection provided varies with the flow regime.The maximum
limits at Gold Creek are,in general,about 15,000 cfs in winter
and 35 ,OO(jcfs in summer.With Susitna ..operati.ng,.the discharge
will I1()te:xc:eeCi:thisma:ximUIil limit.·Th~:t;"~f():t:'~,:I1()lllaximumlinti.t
on outflow discharge is set in the simulation.
The following definitions are used in describing the flow
constraints:
.I
851104 B-3-10
Minimum instream flow requirement -The m~n~mum instream
flow requirement is a minimum discharge level which must be
maintained at the Gold Creek gaging station.The minimum
release from the downstream damsite is the minimum instream
flow requirement at Gold Creek minus the intervening flow
between the damsite and Gold Creek.
Minimum turbine discharge -In the monthly simulation,the
m~n~mum turbine release is the discharge necessary to meet
the firm energy specified in the input.In the weekly
simulation,the minimum percentage of the expected turbine
flows defined in the input will set the minimum turbine
release.
Maximum tMrbine flow -The maximum turbine discharge is the
turbine hydraulic capacity or the discharge required to meet
the system energy requirement,whichever is less.
Maximum outlet works release -The outlet works will operate
in two cases;(1)the maximum turbine flow is less than the
release required to meet the minimum instream flow
requirement,and (2)the reservoir level is higher than the
normal maximum level.For case 1,the outlet works release
only the amount required to satisfy the downstream
requirement.
For case 2,the outlet works discharge up to their maximum
capacity to minimize surcharge above the normal maximum
reservoir elevation.
For Watana,the maximum outlet works discharge is limited to
24,000 cfs in both Stage I and Stage III,even though the
Stage III capacity is 30,000 cfs.This is to ensure that
inflows to Devil Canyon do not exceed the outiet works
capacity there for floods with return periods of 50 years or
less.
Maximum daily fluctuation -Because of limitations on the
accuracy of streamflow measurement,actual releases from the
downstream project may vary up to plus or minus 10 percent
of the weekly average flow for the week.
3.2.7 -Reservoir Operation (***)
To simulate the operation of the Watana development,two
approaches are used;a conventional rule curve,and an operating
guide.The monthly operation program (Monthly RESOP)uses rule
curve operation while the weekly operation program (Weekly RESOP)
uses the operating guide.The rule curve operation approach can
be thought of as "predictive"because it attempts to achieve a
851104 B-3-11
target end-of-period elevation based on the expected reservoir
inflow during the period (i.e.,a monthly period).The
historical record is used as a predictor of the inflow for the
monthly period being simulated.The operating guide approach can
be viewed as "nonpredictive"because its purpose is to achieve a
specific discharge rate through the powerhouse based only upon
the reservoir elevation at the beginning of the period.The
operating guide is a family of rule curves,with each curve
related to a powerhouse discharge rate.
The rule curve approach is easy to apply for simulation of the
operation,but is operationally difficult to achieve because
reservoir inflows are difficult to accurately forecast.The
operating guide approach is more difficult to model,but it is
more straightforward operationally.
The two approaches yield similar results in terms of overall
power and energy production.The operating guide approach is
used for input to analyses of reservoir temperature,river
temperature,and downstream fisheries habitat,because the
operating guides more closely simulate the expected project
releases •The rule'curve approach is used for input to economic
analyses because it is easier to apply and yields comparable
power and energy production.
The distinction between the rule curve and operating guide
approaches applies only to Watana reservoir operation.In both
cases,Devil Canyon operation is governed by a rule curve.The
'D-evilCanyono'p'eratingrule'is"~·t()=·ke=ep-t'h·e-:--re·s-ervoirasfull a's'
possible throughout the simulation.Hence,the Devil Canyon rule
curve is set equal to the normal maximum reservoir elevation
(el.1455 ft,msl)each period (Figure B.3.2.2).
(a)Rule Curve Operation (***)
The monthly simulation is governed by two primary
......._constraints •..TheconstrainLonminimuIlLenergy..,production,is...
a "target"value of firmenergy~.be generated.The ._.__.
constraint on maximtnIl energy production is the rule curve or
the system energy requirement,whichever results in less
energy production..
The target value of annual firm energy is first input to the
model.The corresponding monthly finn energy targets are
"]:nencompuEed "oased on a specified 'distribution.The model
....!,H!jll~~J.a l ••!y ••1II.altE!..the:rE!qtl~'I'E!d ..pOWE!:rhg uSE!.·rE!!e.a se to meet
the monthly firm energy target.The end-of-month reservo
elevation is then computed based on the starting elevation,
the powerhouse release,and inflow during the month.This
end-of-month water surface elevation (WSEL)is then compared
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851104 B-3-12
to the rule-curve elevation (RCEL)for the month.If the
WSEL is below the specified RCEL,no additional release is
made.If the WSEL is above the specified RCEL,the water
stored between these two elevations is released to generate
secondary energy.The secondary energy generated may be
limited by the system energy requirement.
The simulation continues for each month of the simulation
period until the annual firm energy is maximized.The
annual firm energy is maximized when the reservoir elevation
reaches the normal minimum reservoir elevation once during
the simulation (in the critical period)without any
shortfalls in firm energy production or in meeting the
minimum instream flow requirement.
(b)Rule Curve Development (***)
The rule curve is developed by trial and error.Figure
B.3.2.2 depicts example ru1~curves for Watana Stage I and
Stage III.Two distinct periods,the draw down season and
the filling season,are defined by the shape of the rule
curve.The drawdown season extends from the beginning of
October through the end of April.During these months,the
average natural inflow to the reservoir is less than the
reservoir outflow,and the reservoir level.decreases.The
filling season extends from the beginning of May through the
end of September.During these months,the average natural
inflow to the reservoir exceeds the reservoir outflow,and
the reservoir level increases.Hence,the general approach
to developing the rule curve is as follows:at the end of
the filling season,the reservoir should be full,and at the
end of the drawdown season,the reservoir should be at the
minimum rule curve elevation.
The higher the minimum rule curve elevation,the greater the
.firm energy production,because more water would be
available during a drought,resulting in higher energy
output.Alternatively,the lower the minimum rule curve
elevation,the greater the average energy production,
because there is more storage available for regulation on an
average annual basis.Different minimum rule curve
elevations will yield different values of firm energy and
total energy production.The acceptable minimum rule curve
elevation is selected based on an operationwhich provides a
reasonable trade-off between firm and average energy
production.
The maximum rule curve elevation is set equal to the normal
maximum reservoir elevation at the end of the filling
season.
851104 B-3-13
Once the minimum and maximum rule curve elevations have been
established,the rest of the rule curve elevations are
determined by trial and error.The objectives of this
procedure are to establish the monthly ReELs that distribute
the hydroelectric energy such that the costs of thermal
energy generation during the drawdown and filling seasons
are minimized.In this approach,equal quantities of
thermal energy are generated during each month within each
season.The thermal energy generation required in each
season is thus "levelized"as depicted in Figure
B.3.2.3.
(c)Operating Guide (***)
The operating guide comprises three main elements,as
described below.
Expected Powerhouse Discharge -This is a set of weekly
powerhouse discharges (cfs)which will produce the desired
distribution of energy production over a year.
Increasing Curves -This is a set of curves defining
powerhouse discharge rates as a function of Watana reservoir
elevation and time of yea~.The curves,which are expressed
in terms .of a percentage of the expected discharge for each
week,are used to decide .whether or not the present rate of
discharge should be increased (FigureB.3 .2.4).
-------..c--~---Dec-I'eas-in-g--Gu't'ves~---Thcis~is-a~-seconds et--o-f-c·ur-ves,.similaI'
to those descri~ed above,which are used to decide whether
or not the present rate of discharge should be decreased
(Figure B.3.2.4).
The expected powerhouse discharges represent the average
annual flow volume,distributed through the year to minimize
the costs of generating the thermal energy component of the
...~y~_~~!!!:.....e_I!~~gy._._~_~ql!.i:..~~~l!t .!......_!:I!-~l!.i.l;3 __~p._p.!:.Q~<;h.,_~q~!__.
quantities of thermal energy are produced during each week
·o£-thedrawdown season·ati-d also-each week of-thefITIiiig
season.
The operating guide can be viewed as a "family"of rule
curves.The guide is applied by comparing the current
discharge rate to that prescribed by the guide based on the
time of year and the water surface elevation.If the water
surface elevation at the begiritlingJ)ftJ:ie~week is higher
than the increasing curv-eofthe next higher rate ,the
discharge should be increased to the next higher rate in
this week.If the water surface elevation is lower than the
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851104 B-3-14
decreasing curve of the next lower rate,the rate.should be
decreased to the next lower rate in this week.
(d)Operating Guide Development (***)
The operating guide attempts to do the following:
o Keep the powerhouse discharge close to the expected
(100 percent)discharge;
o Maximize total energy production;
o Keep discharge rates nearly constant for at least
several weeks at a time;and
o Minimize cone valve releases (i.e.,meet environmental
flow constrants with powerhouse release)..
The expected discharges are determined by first performing a
monthly rule curve simulation.The weekly expected .
discharges are estimated from the monthly discharges through
the powerhouse.The resulting weekly expected discharges
will levelize the thermal energy requirement in the draw down
and filling seasons.Under average flow conditions,it
would be optimal to always release at 100 percent of the
weekly expected discharge.However,due to natural
variations in reservoir inflow,the release rates must
increase and decrease accordingly to optimize the power and
ener~y production.
The development of the operating guide curves is an
iterative process.The lowest decreasing curve (63%)is
selected by examining the most critical drought period.
Sixty-three percent was judged to be the highest percent
discharge that would enable the project to satisfy the
instream flow and minimum energy requirements through the
most critical drought.The highest increasing curve (140%)
is selected by examining the most extreme flood period.The
rate should be high enough to minimize spills when
streamflow is above average.The intermediate curves are
adjusted in order to maintain adequate storage during the
drought,minimize spills,and to keep the discharge rate
fairly constant.
The"increasing"curve rates which have been used are 80,
100 120 and 140 percent of expected discharge;the
"decreasing"curve rates are 120,100,80,and 63 percent.
If the reservoir is operating at 100 percent,only the 120
percent "increasing"and the 80 percent "decreasing"curves
are checked.This restricts the rate of change of discharge
851104 B-3-l5
in any iteration to the difference in the rates assigned to
the curves.If the water surface elevation is between these
curves,such as Point A in Figure B.3.2.4,the discharge
rate will stay at 100%.If the water surface elevation is
above 120 percent increasing curve (Point B,)the discharge
will increase to 120 percent.If the water surface
elevation is below the 80 percent decreasing curve (Point
C),the discharge will decrease to 80 percent.
3.2.8 -Special Considerations for Double Reservoir
Operation (***)
The previous discussion has focused on the operation of the
Watana Reservoir.
When both Watana and the Devil Canyon are operating,special
considerations come into play..These are:
o Ensuring that Watana generates enough energy each period
to permit peaking operation;and
o Ertstirirtgthat Devil Canyort cone valve releases are such
that low-temperature releases are minimized.
The downstream flow requirement is high from May to October but
the energy demand is low in this period.Releases to meet the
downstream requirement through the powerplants at Watana and
Devil Canyon could conceivably generate more energy than the
systemrequires~The·reservoi rcould o·p-er·crte··i:n·such away··that ....
Devil Canyon draws down to meet the,downstream requirement and
generates most of the system requirement.Only.a small part of
the requirement which is not satisfied by Devil Canyon would then
be satisfied by theWatana powerplant.In.prillciple,Watana is
operated for peak generation and Devil Canyon for base-load
generation.If Watana energy generation is too small,it cannot
satisfy the daily fluctuation of power demand.In order to
......permit_peaking_at..Wa.tana,.·a.minimum.Watana.ener.gy .generation..is
__J!ssi~ed in the inQut.For any_given time period,Watana is_
required to generate at least 30 percent of the total Susitna
output.
On the other hand,if Watana were to generate too much energy in
summer,then it could potentially meet the entire system demand
without generating at Devil Canyon.Consequently,Watana would
generate all of the.system energy r.equirernent ,with Devil Canyon
:;(it~:;~ying thlado'W'l1~treatn f1 ow·rl?qt.1iretnl?l1t)YJ:'.laJeas ingw(iter
through its outlet works.Because the outlet works intakes are
at a lower elevation than the powerhouse intakes,a release
through them during the summer period would be at a lower
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851104 B-3-l6
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temperature.As a result,the temperature in the downstream
channel would be lowered.
In order to avoid low streamflow temperature in the downstream
channel,a minimum Devil Canyon generation is also assigned.
When the total project release would generate more energy than
the system requirement,the program will attempt to meet the
minnnum target firm energy by generating at Devil Canyon.If
Devil Canyon does not satisfy total energy requirement,the rest
will be met by Watana.
3.2.9 -Reservoir Operation Computer Programs (***)
(a)Monthly RESOP Program (***)
The monthly reservoir operation program uses ~he rule curve'
approach to simulate the operation of the Susitna reservoirs
on a monthly basis.The snnulation is done on a water year
basis.Water year n begins on October 1 of year n-1,and
extends through September 30 of year n.A summary of the
program input requirements and output data follows.
Input Data.The input data are organized as follows:
o Titles,number of reservoirs,and snnulation period;
o Historical streamflow at damsites;
o Reservoir area-volume curves and tai1water rating
curves;
o Turbine characteristics curves;
o Reservoir minnnum,and maxnnum,and rule curve
elevations;
o Historical streamflow at Gold Creek and minnnum
instream flow requirement;and
o Annual energy demand,distribution of monthly demand,
energy production of existinghydroplants,and minimum
energy to be generated by each project.
Output.The output data is organ~zed into three parts:
o Echo of the input data;
o Annual snnulation results;and
o Summary results.
851104 B-3-17
/.
The input data echoed includes the streamflow record,
reservoir characteristics,tailwater rating,turbine
characteristics,reservoir control elevations,and rule
curve elevations for each reservoir,streamflow record at
the downstream station (Gold Creek),minimum instream flow
requirement at the downstream station,monthly energy
demand,energy production of existing hydroelectric
powerplants,distribution of monthly demands in a year,and
monthly firm energy.
The second part of the output is the annual simulation
results.For each year,simulation results for each
reservoir and a summary of energy production and powerplant
capability are printed.Reservoir inflow,turbine
discharge,spills,end-of-month storage,end-of-month
elevation,tailwater elevation,net head,plant efficiency
and capability,and total energy are printed.Totals and
averages are also print·ed.
The third part of the'output is the summary results.Tables
of reservoir inflow,turbine discharge,spill,net head,
water surface elevation,energy production,intervening
flow,and.flows at the downstream station with and without
the project are provided.Each table gives the monthly data
in chronological order'over the total simulation period.A
summary ta~le of plant capability and energy production is
also provided.Average and minimum capability,and minimum
energy production for each plant,are listed.
(b)Weekly RESOP Program (***)
The weekly reservoir operation program uses the operating
guide approach to simulate the operation of the Susitna
reservoirs on a weekly basis.The simulation is done on a
calendar year basis (January 1 through December 31).A
summary of the program input requir~ments and output data
Input Data.The input data are organized as follows:
o Titles,number of reservoirs,simulation period,and
output options;
0-Historical streamflow at damsitc:!.§;....
o Weeklyor1ll0litlilyexpected C100%)~discharge alid
increasing and decreasing curves of the operating
guide;
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851104 B-3-18 :)
851104
o Reservoir area-volume curves and tailwater rating
curves;
o Turbine characteristic curves;
o Maximum and minimum reservoir elevations;
o Historical streamflow at Gold Creek and minimum
instream flow requirement;and
o Annual energy demand,distribution of weekly demand,
energy production of existing hydroplants,and minimum
energy to be generated by each project.
Output.The output data is organized into thr~e part~:
o Standard output,similar t~that provided by the
monthly program;
o Flow duration and frequency output;and
o Output for Reservoir temperature studies.
Standard Output
The standard output is much the same as that described for
the monthly program.The major difference is that the
results are reported on a weekly,rather than monthly,
basis.
Output for Duration and Frequency,Curves
This output is designed for input to the environmental
studies.Tables of flow duration and frequency are provided
for:with-project flow at Gold Creek,reservoir inflow,
turbine discharge,excess release and water surface
elevation for each reservoir,and intervening flows between
reservoirs and between the downstream reservoir and Gold
Creek.For each parameter there are two tables;one
provides simula tion resul ts in chronological order by week,
and the other is in the form of duration relations,
expressing the percent of time a given flow is equaled or
exceeded.Water surface elevation',expressed as the
probability of occurrence within assigned ranges,is also
provided.
B-3-19
Output for Reservoir Temperature Studies
This output provides weekly turbine discharge,outlet works
discharge,spill,and wa ter surface elevation,in
chronological order for a specified period of years.
3.3 -Operational Flow Regime Selection (***)
3.3.1 -Reservoir Storage Characteristics (***)
Storage characteristics of the Watana reservoir will vary,
depending on whether Stage lor Stage III is operating.Devil
Can.yon.storage characteristics are unchanged throughout its
operation period.Area and voltnne versus.elevation curves for
both the Watana and Devil Canyon reservoirs are shown on Figure
B.3.2.1.
Watana -Stage I
The Watana Stage I reservoir will have a normalr:operating level
at el.2,000 ft,msl.At this elevation,the reservoir will be
approximately 39 miles long,with a maximtnn width on the order of
three miles.The total voltnne and surface area at the normal
operating level will be 4.25 million acre-feet and 19,900 acres,
respectively.The minimtnn operating leveL is at el.1,850 ft,
msl,resulting in a 150~ft maximum drawdown.The active storage
is 2.37 million acre-feet.
The Devil Canyon reservoir will have a normal operating level at
e1.1,455 ft,msl.At this levei,the reservoir will be
approximately 26 miles long,with a maximum width of
approximateIy one-half rolfe.-The total·voltnne and surface area
at the normal operating level will bel.l million acre-feet and
7,800 acres,respectively.The minimtnn operating level is at
e1.l,405ft,msl,resulting in a 50 ft.maximtnn drawdown.The--,-._.._-_.....__...,~-----.-,.,-'..'.,·····--------·------_····---"act"ive-----··s·'tor·a-g~-is----·-'35-(j~.(io"(j··-··'-afr~e-=·fe-et-·-:···,·'0 -------.--.~-----------....--.----.--"~--.-.--.-...,.'.--.,.._.-.-,'."0'_"--
Watana -Stage III
The Watana Stage III reservoir will have a normal'operating level
at el.2,185 ft,msl.At this eleva tion,the reservoir will be
approximately 48 miles long,with a maximum width on the order of
five miles ..Thetotalvoltnneand surface area at the normal
operating level will be 9.5 millionacre....feet:gJ.'l.4 38,000 acres,
respectively.TheminimUID operating levetts atel ~2 ,065 ft,
msl,resulting in a l20-ft maximtnn drawdown.The active storage
is 3.7 million acre-feet.
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851104 B-3-20
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851104
I
3.3.2 -Reservoir Operation (***)
The Applicant's goal is to operate the project to maX1m1ze power
and energy benefits within environmental and operational
constraints.Details of the reservoir operation are provided in
Section 3.2 of this Exhibit.
3.3.3 -Development and Comparison of Alternative
Flow Regimes (***)
Alternative flow regimes were compared,based on their
performance in meeting economic and environmental objectives.
The economic objective is to minimize the cost of producing
energy to meet projected Railbelt system energy demands.The
environmental objective is to provide sufficient -habitat to
~intain naturally producing populations,so called no-net-loss
of habitat.The environmental objective ma~be achieved by
providing the river flow.s necessary ,to meet l ~he objective 'or by ,-a
combination of flows and other compensation such as rearing
facilities.Environmentar flow requirements affect Susitna
energy product,ion and Il}ay require the construction and operation
of other generating facilities to meet Railbelt system energy
demand.Therefore,the costs resulting from the implementation
of environmental ",flow requirements are included in the economic
evaluation of the costs to meet Railbelt energy demand.The
economic and environmental objectives are combined in a single
evaluation criteria which is the total cost of providing the
Railbelt energy demand,including the costs of the Susitna
Hydroelectric P~oject,other generation facilities and the costs
of mitigation measures.
A complete description of each of the alternative flow reg1mes
and of the selection process undertaken to develop the preferred
flow regime is set out in Exhibit E,Chapter 2,Section 3.Based
upon this combined economic and environmental selection process
set out in that section,flow regime Cases E-VI and E-IV are
judged to be the superior flow cases.Case E-VI is selected as
the preferred case because of superior energy benefits.Table
B.3.3.1 shows the weekly minimum flow requirements at Gold Creek
for Case E-VI.Table B.3.3.2 shows the relative ranking of the
al terna tive flow regimes based upon bo th economic and
environmental costs.
B-3-21
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4-POWER AND ENERGY PRODUCTION (***)
4.1 -Plant and System Operation Requirements (**)
The main function of system planning and operation control is the
allocation of generating plant on a short-term operational basis so
that the total syste~demand is met by the available generation at
minimum cost consistent with the security of supply.The objectives
are generally the same for long-term planning or short-term operation
load dispatching,but with important differences in the latter case.
In the short-term case,the actual state of the system dictates system
reliability requirements,overriding economic considerations in load
dispatching.An important factor arising from economic and reliability
considerations in the system planning and operation is the provision of
stationary reserve and spinning reserve capacity.Figure B.4.l.l shows
the daily variation in demand for the Railbelt system during typical
December (winter)and August (summer)weekdays.The variation in
monthly peak demands as.estimated for the year 1983 is shown on Figure
B.4.1.2.
4.1.1 -System Reliability Criteria (**L
Reliability criteria for electric power system operation can be
divided into those criteria which apply tocgeneration capacity
requirements and those which apply to transmission adequacy
assessment.
The following basic reliability standards and criteria have been
adopted for planning the Susitna project.
(a)Installed Generating Capacity (**)
Sufficient generating capacity is installed in the system to
ensure that the probability of occurrence of load exceeding
the available generating capacity shall not be greater than
one day in ten years (Loss-of-Ioad probability (LOLP)of
0.1).The evaluation of generation reserve by probability
techniques has been used for many years by utilities and the
traditionally adopted value of LOLP has been about one day
in ten years (Sebasta 1978,IEEE 1982).Many utilities and
reliability councils in the lower-48 states continue to
employ such a criteria (IEEE 1977).
·Economic evaluation of expansion plans across a range of
LOLP levels from one day in ten years (0.1)to three days in
ten years (0.33)were analyzed.These results indicated
that the expansion plans and associated system costs of the
With-and Without-Susitna plans are not significantly
affected within the LOLP range studied.In addition,at
least one major utility has expressed the aim of achieving
851104 B-4-l
an LOLP of one day in ten years (Stahr,1983).
for the present level of study,an LOLP of one
years has been adopted.
There·fore,
day -in ten
The above generation reliability criteria was used as an
input to the generation planning model described in Section
5.3 of this Exhibit.This generation planning model was
used to evaluate generation expansion with and without the
Susitna project as presented in Exhibit D.
(b)Transmission System Capability (**)
Thehigh...,voltage transmission system should be operable at
all load levels to meet the following unscheduled single or
double contingencies without instability,cascading or
interruption of load:
o The single contingency situation is the loss of any
single generating unit,transmission line,
transformer,or bus (in addition to normal scheduled
or maintenance outages)without exceeding the
applicable emergency rating of any facility;and
o.The double contingency situation is the subsequent
outage of any remaining equipment,except for line if
outage of the line will resul t in the loss of the load
center served,'without exceeding the short time
emergency rating of any facility.
In the sIngle contingencysItuatIoJ:l.,the power system must
be capable of readjustment so that all equipment would be
loaded within normal ratings and,in the double contingency
situation,within emergency ratings for the probable
duration of the outage.
Duri~g any contingency:
---.---------------o--Suf-ficient-'·reactive--power--(-MVAR-}--capac±tywith
--------------._---------adeq.ua-te-con-tr.o.ls-i-s-inst-a-l-l-ed-t-o--ma-in-t-a-in-ae-cept-ab-l-e--
transmission voltage profiles.
o The stability of the power system is maintained
without loss of load or generation during and after a
three-phase fault,cleared in normal time,at the most
critical location.
-.Havingthetransmission':':-line s:"'itl.patallel,-:instead 0 fon e
line only,improves greatly the reliability of the trans-
mission system.Besides removing the necessity of hot line
maintenance,the frequency of failure of the transmission
system will be lowered by a factor of about 15.
851104 B-4-2
The transmission system performance was examined by
performing load flow and transient stability studies.Load
flow studies examined the system under normal operating
conditions with all-elements in service,then removal of one
line segment which verified adequate system performance
under single contingency.Double contingency operation was
verified by further removal of a second element (not
including a second line).The loss of two parallel line
circuits would result in loss of the load center served and
was not considered in double contingency studies.
The following criteria were used for the load flow studies:
1.For energization while the system is in normal status:
a.Voltage at the sending end should not be reduced below
.90 per unit.
b.Initial voltage at the receiving end should not exceed
1.10 per unit.
c.Following the switching of transformers and VAR control
devices onto the system,the voltage at the receiving
end should not exceed 1.05 per unit.
2.In case of normal status or single contingency and peak
load:
a.The voltages at all buses tapped for loading shall stay
between 0.95 and 1.05 per unit.
b.The voltage/load angle between the Susitna generators
and any point of the system should not exceed 45
degrees.
3.In case of double contingency and peak load:
a.The voltages at all buses tapped for loading shall stay
between 0.90 and 1.10.
b.The voltage/load angle between the Susitna generators
and any point of the system should not exceed 55
degrees.The transmission system configuration was
tested for energization (no load),and for peak load
flow conditions.The load flows were prepared for
normal transmission system conditions as well as
selected contingency conditions.In addition to the
load flow studies,dynamic stability studies were also
prepared (Acres 1982f).
851104 B-4-3
cc)
Figures B.4.1.3,B.4.1.4,and B.4.1.5 are one-line
diagrams showing system performance for the approximate
peak loadings in years 1999,2005,and 2025 under a
critical double contingency condition.This condition
assumes that one of the Gold Creek-Willow lines is out
of service and that there is an additional loss of one
of the Willow-Knik Arm lines.
The critical parameters of the above cases are shown in
Table B.4.l.1.As can be seen from the table,the
system performs within the criteria established above.
The loss of two circuits on the same right-of-way has a
low level of probability if the spacing between the two
circuits are set far apart to-minimize this potential
problem.Part of the generation reserve capacity will
be in the form of spinning reserve.As determined·in
the generation planning studies,this spinning reserve
will be from the next most economical increment of
capacity over those units required to meet load
considering the system as a whole.In addition to
spinning,reserve,standby reserve can be maintained by
the utilities in individual load centers using less
economical units.The cost of this spinning and standby
reserve has been included in the economic analyses
presented in Exhibit D,Chapter.2.
Operational reliability criteria thus fall into four main
categories:
o LOLP of 0.1,or one day in ten years,is maintained
for the recommended plan of operation;
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o The single and double contingency requirements are
maintained for any of_~~~,~'?E_~J)J:_()~~E!_E!()t:1_t._~ge~in thepTanF-oEErariSDils-s[on sys tem;
851104
o System stability and voltage regulation are assured
from the electrical system studies.The spinning
reserve capacity with six units at Watana and four
units at Devil Canyon will meet load frequency control
criteria;and
o The loss of all Susitna transmission lines on a single
right""of'""wayhasa-lCiw'lefvEH -of-'prooability.Ill.the
event of the loss of all lines serving a load center,
standby reserve in the affected load center can be
brought on line to meet critical loads.
B-4-4
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I 4.1.2 -Economic Dispatch of Units (*)
A Susitna Area Control Center will be located at Watana to
control both the Watana and the Devil Qanyon power plants.The
control center will be linked through the supervisory system
to a Central Dispatch Control Center near Anchorage.
Operation will be semi-automatic with generation instruction
inputs from the Central Dispatch Center,but with direct control
of the Susitna system at the Susitna Area Control Center for
testing/commissioning or during emergencies.The control system
will be designed to perform the following functions at both the
Watana and Devil Canyon power plants:
o Start/stop and loading of units by operator;
o Load-frequency control of units;
o Reservoir/water flow control;
o Continuous monitoring and data logging;
o Alarm annunciation;and
o Man-machine communication through visual display units
(VDU),and console.
In addition,the computer system will be capable of retrieval of
technical data,design criteria,equipment characteristics and
operating limitations,schematic diagrams,and
operating/maintenance records of the units.
The Susitna Area Control Center will be capable of completely
independent control of the Central Dispatch Center in case of
system emergencies.Similarly,it will be possible to operate
the Susitna units in an emergency situation from the Central
Dispatch Center,although this would be an unlikely operation
considering the size,complexity,and impact of the Susitna
generating plants on the system.
The Central Dispatch Control Engineer decides which generating
units should be operated at any given time.Decisions are made
on the basis of known information,including an "order-of-merit"
schedule,short-term demand forecasts,limits of operation of
units,and unit maintenance schedules.
(a)Order-of-Merit Schedule (0)
In order to decide which generating unit should run to meet
the system demand in the most economic manner,the Control
851104 B-4-5
Engineer is provided with information of the running cost of
each unit in the form of an "order-of-merit"schedule.The
schedule gives the capacity and fuel costs for thermal units
and reservoir regulation limits for hydro plants.
(b)Optimum Load Dispatching (0)
One of the most important functions of the Control Center
is the accurate forecasting of the load demands in the
various areas of the system.
Based on the anticipated demand,basic power transfers
between areas,and art allowance for reserve,the planned
generating capacity to be used is determined by taking into
consideration the reservoir regulation plans of the hydro
plants.The type and size of the units should also be taken
into consideration for effective load dispatching.
In a hydro-dominated power system (such as the Railbelt
system would be if Susitna is develo.ped),the hydro uni t
will take up a much grea~er part of base load operation than
in a thermal-dominated power system.The planned hydro
units at Watana typicany are wen-suited to load following
and frequency regulation of~the system and providing
spinning reserve.Greater flexibility of operation was a
significant:'factor in the selection of six units pf 170 MW
capacity at Watana,rather than fewer,larger-size units.
Opera.ting Limits of J]p.its!'C~)"
There are strict constraints on the minimum load and the
loading rates of machines;to dispatch load to these
machines requires a systemwide dispatch program taking these
constraints irtto consideration.Iii genera.l ,hyd ro units
have excellent start-up and load following characteristics;
thermal units have good part-loading chara.cteristics.
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851104
(1)Hydro Units (*)
o Reservoir regulation constraints resulting in
not-to-exceed maximum and minimum reservoir levels,
daily or seasonally.
o Part loading of units is undesirable in the zone of
rough turbine operation {typically from"above
no-load-speed to 50 percent load)due to vibrations
arising from hydraulic surges.
B-4-6
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(2)Steam Units (*)
o Loading rates are slow (10 percent per minute).
The units may not be able to meet a sudden steep rate
of rise of load demand.
o The units have a minimum econom~c shutdown period of
about twenty-four hours.
The total cost of using conventional units includes banking,
raising pressure,and part-load operations prior to maximum
economic operation.
(3)Gas Turbines (*)
o Eight to ten minutes are required for normal start up
from cold.
o Emergency start-up times are on the order of five to
seven minutes.
(d)Optimum Maintenance Program (0)
An important part of operational planning which can have a
significant effect on operating costs is maintenance
programming.The program specifies the times of year and
the sequence in which plants are released for maintenance.
4.1.3 -Unit Operation Reliability Criteria (0)
During the operational load dispatching conditions of the power
system,the reliability criteria often override economic
considerations in scheduling of various units in the system.Also
important in considering operational reliability are system
response,load-frequency control,and spinning reserve
capabilities.
(a)Power System Analyses (0)
Load-frequency response studies determine the dynamic
stability of the system due to the sudden forced outage of
the largest unit (or generation block)in the system.If
the generation and load are not balanced,and,if the
pick-up rate of new generation is not adequate,loss of load
will eventually result from under-voltage and under-
frequency relay operation,or load-shedding.The aim of a
well-designed high security system is to avoid load-shedding
by maintaining frequency and voltage within the specified
statutory limits.
851104 B-4-7
(b)System Response and Load-Frequency Control (*)
To meet the frequency requirements,it is necessary that the
effective capacity of generating plant supplying the system
at any given instant be in excess of the load demand.The
capacity of the largest thermal unit in the system has been
taken as a design criterion for spinning reserve to maintain
system frequency within acceptable limits in the event of
the instantaneous loss of,the largest unit.
In the system expansion studies,thermal units are run
part-loaded to provide sources of spinningxeserve.
Ideally,it would be advantageous to provide spinning
reserve with the hydroelectric generation as well,in order
to spread spinning reserves evenly throughout the system.
The quickest response in system generation could come from
the hydro units.The large hydro units at Watana and Devil
Canyon can respond in the turbining mode within 30 seconds.
(c)Protective Relaying Systems and Devices (0)
The primary protective relaying systems provided for the
generators and tr~nsmission system of the Susitna project
are designed to disconnect the faul ty equipment.from ..the
system in the fastest possible time.Independent protective
systems are installed to the extent-necessary to provide a
fast-clearing backup for the-primary protective syste~so as
to limit equipment damage,limit the shock to the system,
.allg.l3.pe.edres.toration..of.·..•.seryice._.The relay.ing.-sys.temsare ".-
designed so as not to restrict the normal or necessary
network transfer capabilities of the power system.
4.1.4 -Dispatch Control Centers (*)
The operation of the Watana and Devil Canyon powerplants in
relation to the Central Dispatch Center can be consi~ered to be
the second tier of a three-tier control structure as follows:
_...._.~_..__._.._...._---...--_._~~~·~--o·-Ce-ntra-t-Di-spatcn--COrft-ro t-Cerft e r-(-345~RV-netwo ff)--iiea r'"._..._..._....._...
Anchorage:manages the main system energy transfers,
advises system configuration ,and checks overall
security.
o Area Control Center (Generation connected to 345-kV
sy.stem;-for-example,·Watana and Devil Canyon):.deals with
the loadin~of~enerators connected directlY to the 345-kV
-network,switchingandsafetY·precaut{ons 'of local
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851104 B-4-8
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systems,and checks security of interconnections to main
system.
o District or Load Centers (138-kV and lower voltage
networks):manages generation and.distribution at lower
voltage levels.
For the Anchorage and Fairbanks areas,the district center
functions are incorporated into their respective area control
centers.
Each generating unit at Watana and Devil Canyon is started,
loaded and operated,and shut down from the Area Control Center
at Watanaaccording to the loading demands from the Central
Dispatch Control Center.Due consideration is given to:
o Watana Reservoir regulation criteria;
o Devil Canyon Reservoir regulation criteria;
o Turbine loading and de-loading rates;
o Part-loading and maximum loading characteristics of
turbines and generators;
o Hydraulic -transient characteristics of waterways and
turbines;
o Load-frequency control of demands of the system;and
o Voltage regulation requirements of the system.
The Watana Area Control Center is equipped with ~computer-aided
control system to efficiently carry out these functions.The
computer-aided control system allows a minimum of highly trained
and skilled operators to perform the control and supervision of
Watana and Devil Canyon plants from a single control room.The
data information and retrieval system will permit performance and
alarm monitoring of each unit individually,as well as the
plant/reservoir and project operation as a whole.
4.2 -Power and Energy Production (***)
The Watana-Stage I development will operate as a base load project
until the Devil Canyon Stage II development enters operation.Under
Stage II operation,the Devil Canyon development will operate on base
load and the Watana-Stage I development will operate on peak load and
as reserve.The power and energy output of both facilities are
increased when Watana-Stage III comes on-line.
851104 B-4-9
The operation simulation of the reservoirs and the power facilities at
the two developments is carried out on a monthly basis to assess the
dependable capacity and energy potential of the schemes.An optimum
reservoir operation pattern was established by an iterative process to
minimize net system operating costs while maximizing firm and average
annual energy production,as discussed in Section 3.2 of this Exhibit.
4.2.1 -Operating Capability of Susitna Units (**)
The operating capability of the Susitna units are summarized in
Table B.4.2.1 and are based on the three stages of project
development as follows:First,construction and operation of a
facility with four turbine/generators at the Watana site with a
dam crest elevation of 2,025 feet (Stage 1);second,completion
and -operation of the Devil Canyon facility with four
turbine/generators at the originally-proposed dam crest elevation
of 1,463 feet (Stage II);and third,construction of the dam
crest at the Watana facility to the 2,205-foot level (Stage III)
including the addi tion of two turbine/generato.rs,for a total of
six units,as proposed in the License Application (APA 1983).
(a)Watana (**)
The Watana powerhouse will have prov~s~ons for six
generating units.Four units will be installed during
Stage I construction and the remaining two units will be
installed during Stage III construction.Both sets of
units will have a capability of 170 MW when operating at
res~:ry<?i.J:'_E:!~~y~l:!on_~,J1Q f_~~~•ThX~_:r_f?_~~.!'_voi,Le I eyg t ion
corresponds to the average of the minimum December and
January elevations expected in Stage III,and define's the
unit capacity in relation to the occurrence of the peak
system demand.During Stage I,the average of the minimum
December-January reservoir--levels is at elevation 1,915
feet.The power output 'of each unit during this peak load
period with this reservoir elevation is approximately 90
MW.
-...------.-----.-----_·-·-·-·Th-e--f.ou];'---Wa-t_ana-S-t_age·-I~t_ur-bi_nes·-h-ave-been-se-l-ec:t;-ed--to--
operate within the expected reservoir elevation range of the
initial Watana dam and the raised Watana dam (Stage III).
These units will operate under net heads ranging from a
minimum of 384 feet in Stage I to a maximum of 719 feet in
Stage III operation;no modification is necessa.ry to the
units__f;o peI'l1l,it Stage III operation.
TheusUalmaxinitirii rangeofi5perafiori~of a Francis t.urbine
is from approximately 65 percent of its design head (the
head at which optimum efficiency is obtained)to
approximately 125 percent of its design head.Using these
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851104 B-4-10
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criteria,the design head for the Stage I turbines is
established at 590 feet in order to permit these units to
operate with suitable efficiencies with the reservoir raised
in Stage III.The two turbines which are installed in
Stage III will have their design head at 680 feet to have
their peak efficiency within the narrower range of heads
which will prevail in Stage III.
The generating unit output versus net head relationship for
the Watana Stage I and III units is shown on Figure
B.4.2.1.
(b)Devil Canyon (**)
The Devil Canyon powerhouse will have four generating units
each with a capability of 150 MW at the minimum reservoir
level (el.1,405)and a corresponding net head .of 545 feet
on the station.The generating unit output versus net head
relationship for the Devil Canyon unit is shown in Figure
B.4.2.2.
4.2.2 -Tailwater Rating Curves (0)
The tailwater rating curves for the Watana and Devil Canyon
developments are shown on Figure B.4.2.3.
4.2.3 -Average Energy Generation (***)
Based on the hydrology,reservoir operation,and flow regime E-VI
described above in Section 3,average energy generation from the
Susitna project has been determined.
Table B.4.2.2 provides the estimated average annual energy
production from the Watana Stage I development,from Watana Stage
I operating with Devil Canyon Stage II,and from Watana Stage III
operating with Devil Canyon Stage II.When Watana is raised
(Stage III),the additional storage available for flow regulation
at Watana increases the energy production of both Watana and
Devil Canyon.Also,two additional units are installed in the
Watana powerhouse to take advantage of the added head and flow
regulation.
4.2.4 -Firm Energy Generation (***)
The firm or reliable energy generation from the Susitna project
is taken as the energy generated with a 90 percent probability of
exceedance,based upon 34 years of water records.Therefore the
energy generation of the Susitna Project will be greater than or
equal to the firm energy 90 percent of the time.Table B.4.2.2
851104 B-4-11
shows the estimated firm annual energy production from the three
Susitna stages.
4.2.5 -Dependable Capacity (***)
The dependable capacity of a hydroelectric project is defined as
the capacity which,for a specified time interval and period,can
be relied upon to carry system load,provide assured reserve and
meet firm power obligations,taking into account unit operating
variables,hydrologic conditions,and seasonal or other charact-
eristics of the load to be supplied.
Section 4.2.1 of this Exhibit describes the-operating
characteristics of the units to be installed at Watana and Devil
Canyon based on the hydrologic conditions discussed in Section
3.1,the reservoir operation studies presented in-Section 3.2,
and flow regime E-VI as discussed in Section 3.3.Based on those
operation studies,the dependable capacity of the Susitna
project has been determined.
The Watana development will operate as a base load project until
the Devil Canyon development begins operation,at which time the
Devil Canyon development wIll operate ·oU·base and the Watana
development will operate on peak and reserve.The dependable
capacity of the three Susitna stages was estimated by inputting
to OGP the capability.(MW)of each stage,based on reservoir
operation studies,and tabulating the capacity dispatched at the
time of peak load from the OGP output.
--_···--~Fi gu re-B~~4:2~-4 ·s6.ows~Eh-eaeperidable--capacrty~of-Watana and De vi 1
Canyon in relation to the peak load forecast for the E-VI flow
regime.As can be seen from Figure B.4.2.4,in Stages II and III
the dependable capacity of the development increases as the peak
load increases.Table B.4.2.2 shows the dependable capacity for
the three stages as limited by load,and with no limitation of
load.
-----4.2.-6---Base-Load--and---Load-Fol-lowing Ope r a-tio n(-***}~.----
The Watana plant initially would operate on base to maintain
nearly uniform discharge from the power plant.The Watana
project could also be utilized for spinning reserve,which could
require that it follow load to some extent.When Devil Canyon
comes on line,Watana would change to a peaking operation,while
Devil Canyon operates on base.
Tht?ul t:ill1ateobject iveofanyllydro-electric:~pr.6jeC.t..opera t ion is
to have the flexibility to follow loads,regulate frequency and
voltage,provide spinning reserve,and react to system needs
under all normal and emergency conditions.The project should be
dispatched to minimize thermal operation and fuel costs.Conse-
)
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851104 B-4-12
quently,it would be desirable for the Susitna Project to follow
load as closely as practical as it fluctuates on an hourly and
seasonal basis.
To assess the economic impact of base load versus load following
operation,the power and energy data for the load following case
were input to the OGP model and an economic evaluation was made.
The With-Susitna plan,assuming base-load operation of the
downstream project,has a 1985 present worth of system costs of
$4,823 million.For the same plan,assuming load-following
operation,the 1985 present worth of system costs are $4,693
million.The difference of $129 million can be considered
foregone project benefits or mitigation costs.
851104 B-4-l3
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851104
5 -STATEMENT OF POWER NEEDS AND UTILIZATION (**)
5.1 -Introduction (**)
Electric power demand forecasts have been developed for the Railbelt
market that will be served by the Susitna Project.
The following sections present the existing electric power demand and
supply situation and the basic approach used to develop the electric
power forecasts for the Railbelt market that will be served by the
Sus i tna Proj ect.
Section 5.2 describes the electric power system in the Railbelt,
including utility load characteristics,conservation programs and
electricity rates.Section 5.3 presents the forecasting_methodology.
The section describes the four computer-based models that were utilized
in preparing the economic and electric energy forecasts and the
genera tion expansion plan for meeting the loads..Section 5.4 presents
the key variables involved in producing the forecasts,the results of
the forecasts,and the impact of world oil prices!··:on the forecasts.
5.2 -Description of the Railbelt Electric Systems (**)
This section describes the present Railbelt electric systems.This
includes a general description of the interconnected Railbelt market
and the electric utilities serving the market,the characteristics of
the loads,electricity rates,conservation programs,and historical
data covering Railbelt electricity demands and regional economic
factors.
5.2.1 -The Interconnected Railbelt Market (**)
The Railbelt region,shown in Figure B.5.2.1,contains two
important electrical load centers:the Anchorage-Cook Inlet
area and the Fairbanks-Tanana Valley area.These two load
centers comprise the interconnected Railbelt market.The
Glennallen-Valdez load center is not planned to be interconnected
with the Railbelt nor to be served by the Susitna Project.It is
therefore excluded from discussions in this document.
The existing transmission system of the Anchorage-Cook Inlet area
extends from Anchorage north to Willow and consists of a network
of 115-kV,138-kV,and 230-kV lines with interconnection to
Palmer.The Fairbanks-Tanana system extends from Fairbanks south
to Cantwell over a 138-kV line.The Anchorage-Fairbanks
Intertie,connecting Willow and Healy,was completed by the
Alaska Power Authority in October 1985 and is currently operating
at 138 kV.The existing transmission system in the Railbelt
region is illustrated in Figure B.5.2.2.
B-5-1
(a)The Electric Utilities and Other Suppliers '(**)
(i)Anchorage-Cook Inlet Area (**)
The Anchorage-Cook Inlet area has two municipal
utilities,three Rural Electrification
Administration (REA)cooperative associations,
a Federal power agency,and two military
installations,as follows:
o Municipality of Anchorage~unicipal
Light &Power Department (AMLP)
o Seward Electric System (SES)
o Chugach Electric Association,Inc.(CEA)
o Homer Electric Association,Inc.(HEA)
o Matanuska Electric Association,Inc.(MEA)
o Alaska Power Adminis tration (APAd)
o Elmendorf AFB -Military
o Fort Richardson -Military
All of these organizations,with the exception of
MEA,haveelec-trica-l generat-ing-£ae-ilit-iesc.~-MEA-buys-
its power from CEA and the APAd.HEA and SES
purchase power from CEA and maintain generating
facilities primarily for standby operation.
AMLP and CEA are the two principal utilities
servicing the AJlchorag~-C()ok Inlet area.AMLP serves
most areas within the City of Anchorage except for
some sections served-by CEA.In addition~AMLP
_____~~E":~~__~!t~~_~~_h 0 ~~_g~_~_Il:~~t'I!a ti:g~o!lJ_~!t'P~:r_t,__I!Il,SL__
provides electrical energy to Elmendorf AFB and Fort
--l'Hchardson on a'non-fIrm basis.AMLP also provides
bulk power to CEA.The customers and associated
sales of AMLP in 1984 are listed below.Residential
sales represented slightly over one fourth of total
commercial sales.Its most important load is the
downtown business and commercial district.
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851104 B-5-2
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851104
AMLP
1984
Customer Class Number Energy Sales
(MWh)
Residential 18,007 138,808
Commercial 3,921 523,088
Street Ligh ting 8,135
Sales to Public
Authorities 1 15,907
Total 21,928 685,938
CEA serves certain urban and most suburban sections
of Anchorage.In addition,CEA serves customers at
Kenai Lake,Moose Pass,Whittier,Beluga and Hope.
CEA also provides bulk power to AMLP.CEA's
residential load is greater than its commercial and
industrial loads.
Furthermore,CEA'save rage commer c ia 1 c us tomer is
consistently smaller than that of AMLP.Its 1984
sales are presented below:
CEA
1984
Customer Class Number Energy Sales
(MWh)
Residential 55,036 532,133
Commercial &Industrial
(50 kVA or less)5,874 410,812
Commercial &Industrial
(over 50 kVA)3 10,583
Public St.&Hwy.Lighting 5,444
Sales for Resale 3 834,228
Total 60,916 1,793,200
HEA,MEA and SES provide electricity service to
approximately 43,000 customers by purchases from CEA.
In 1984,HEA,MEA,and SES purchased about 349 GWh,
396 GWh,and 26 GWh of electrical energy,
respectively.REA serves the City of Homer and other
customers on the Kenai peninsula.MEA has a service
area encompassing Eagle River,the Matanuska Valley
and surrounding areas.SES serves the City of
Seward.These areas are depicted on Figure B.5.2.1.
B-5-3
851104
The Alaska Power Administration provides wholesale
power (firm and secondary)to MEA,CEA,and AMLP.
These utilities are interconnected with the Alaska
Power Administration on 115-kV lines owned by the
Administration.Fort Richardson and Elmendorf AFB
supply their own needs.Their electrical
requirements in 1984 were approximately 59 and 72
GWh,respective1y~Both bases have non-firm power
agreements with AMLP.Fort Richardson has a contract
with AMLP to purchase about 30 GWh on an
interruptable basis.
(ii)Fairbanks -Tanana Valley Area (**)
The Fairbanks-Tanana Valley area is currently served
by a municipal utility and an REA cooperative.,In
addition,a university and three military
installations have their own electric systems,as
follows:
o Fairbanks Municipal Utili ties System (FMUS)
o Golden Valley Electric Association,Inc.
(GVEA)
o University of Alaska,Fairbanks
o Eielson AFB -Military
o Fort Greeley -Military
o Fort Wainwright -~ilitary
Fairbanks Municipal Utilities System and Golden
Valley Electric Association,Inc.own and operate
generation,transmission,and distribution faci1i-
......ties.TheUniversity..andmilita rybas esmaintain...
h ',··d d''b'f '1',.te~r_o.wn.genera.t~o.n._an.._~s.t.r~..ut~o.n..a.c.~..~t~e.S..L ..._•...
Fort Wainwright is interconnected with GVEA and FMUS
and is providing both uti li ties with economy energy.
EMUS serves an area bounded by the city limits of
Fairbanks,except for several residential
subdivisions recently annexed by the city.The Chena
R.i.verflowsthrougll the northern part of the service
·areawith ·ForJWaitlwrig1:lJ:·Military.:R.fasfarva tion
providing a border on the east.The downtown
business district lies in the northeast corner of the
FMUS service area along the south bank of the Chena
River.There is an industrial area which is
B-5-4
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851104
contained in part within the City of Fairbanks.The
north bank of the Chena River provides the ·southern
boundary of this industrial area.In addition to
serving its own customers,FMUS provides economy
energy to GVEA.The 1984 sales of FMUS are as
follows:
FMUS
1984
Customer Class Number Energy Sales
(MWh)
Residential 4,802 29,132
Commercial 1,201 80,834
Sales to Public
Authorities 113 16,944
Street Lighting 2,500
GVEA 1 12,935
Total 6,117 142,345
The commercial customers are significant in number
and,more importantly,in terms of total energy
sales.The residential ~nd government sectors had
about the same level of energy sales in 1984.
GVEA serves the Fairbanks North Star Borough
including por·tions of the City of Fairbanks not
served by 'FMUS,the City of North Pole,the
communities of Fox and Ester,and the two military
bases -Eielson Air Force Base and Fort Wainwright.
Other communities within its service area include
Nenana,Healy,Cantwell,Clear,Anderson,and Rex.
In 1984,GVEA sales were as follows:
B-5-5
GVEA
1984
Customer Class Number Energy Sales
(MWh)
Residential 20,275 172,958
Commercial &Industrial
(50 kVA or less)2,239 50,505
Commercial &Industrial
(over 50 kVA)264 136,678
Public St.&Hwy.Lighting
Sales to Public Authorities 1 3,140
Sales for aesale 1 17,132
Total 22,780 380,413
The University of Alaska at Fairbanks,Fort
Wainwright,and Eielson AFB generate their own
electrical requir-eme~s.At the present time,Fort
WainwrighLsupplies all of Fort Greeley's electricity
needs with GVEA wheeling the power on their
transmission lines.Fort Wainwright provides economy
energy to EMUS and GVEA from coal-fired units.In
1984,Fort Wainwright had net generation of about 75
GWh and Eielson AFB generated about 49 GWh of
electricity.
Several major industrial companies in the RaUbel t
provide their own electric power supply.During
1983,the latest year for which data are available,
such generation accounted for nearly 361 GWh in the
Anchorage-Cook Inlet area.The major industrial self
suppliers are located in HEA's service area.The
main industrial firms with operations in Kenai
include Union Oil of Ca-lifornia;PhH-lipsPetrol-eum -
--Gompany-,-Ghe-vr-on--U-.S-.A.,----Inc-,,-,--and--1'esoro-A-l-a-skan-----
Petroleum Corp.
In 1983,industrial sources of electrical generation
in the Fairbanks-Tanana Valley area did not produce
any electrici ty.
(b)The Existing Electric Energy Supply And Power Plant
Cal'acity(**)
The Anchorage-Cook Inlet area is almost entirely dependent
on natural gas to generate electricity.About 92 percent of
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851104 B-5-6
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the total capacity is provided by gas-fired units.The
rema~n~ng are hydroelectric units (5 percent)and oil-fired
diesel units (3 percent).Table B.5.2.1 presents the total
generating capacity of the Anchorage-Cook Inlet utilities,
the two military installations,and the industrial sector~
For the Fairbanks-Tanana Valley area,the total generating
capacity of the utilities,the three military installations,
and industrial self suppliers,by type of unit is presented
in Table B.5.2.2.A large portion of the total installed
capacity consists of oil-fired combustion turbines (58
percent)and coal-fired steam turbines (32 percent).The
remaining capacity is provided by diesel units.The
transmission intertie between Anchorage and Fairbanks allows
Fairbanks utilities to purchase economy energy,fueled by
natural gas,from Anchorage.It also allows both load
centers to take advantage of reserve capacity available in
both load centers to provide greater reliability.
Tab1eB.5.2.3 provides a complete list of generating plants
of the Rai1be1t area.The plant data and characteristics
shown were developed by the Applicant from information
provided by the Rai1be1t utilities.
5.2.2 -Rai1be1t Electric Utilities (**)
(a)Utility Load Characteristics (**)
This section presents monthly peak and energy demand,hourly
load data for a typical week in April,August,and
December,and an analysis of load diversity between the two
load centers.
(i)Monthly Peak and Energy Demand (**)
Table B.5.2.4 presents monthly distributions of
peak and energy demand for the two load centers and
for the total Rai1be1t area.The average monthly
values for the period 1976-1982 are based on Alaska
Power Adminis tration da.ta.The monthly values for
1982 and 1983 and their averages are based on hourly
load data supplied by AMLP,CEA,mus and GVEA.
Figure B.5.2.3 shows the 1983 monthly load variation
for each load center.
851104
Both regions have winter peaks,
December,January or February.
lowest during the months of May
B-S-7
occ urring in
The peak demand
through August,
is
and
(ii )
the ratio of summer to winter peaks varies between
0.58 and 0.65.Although monthly peak demand varies
from year to year,mainly due to weather conditions,
Table B.S.2.4 shows that the pattern has remained
relatively constant during the period 1976-1983.
As denoted by the data in Table B.5.2.4,the monthly
distribution of energy (net generation)demand has
remained about the same for the period 1976-1983 with
both regions having a similar distribution.The
winter months,November through February,had an
average monthly demand of about 9.8 percent of the
total annual energy.The summer months,June through
August,had an average monthly demand of about 6.8
percent of the total annual energy.
The hourly load data for 1982 and 1983 have been used
in the generation expansion studies described in
Chapter 2 of Exhibit D.For these studies,monthly
ratios and hourly ratios have been developed f~the
historical load records.The technique used is
referred.to c'3.s the.Ml:t:1l.Q9.0f,Illg.iI:"~~tAveraging.
This method develops rank orders to compute load
magnitudes and time orders to compute load sequences.
Table B.S.2.5 summarizes the distribution of monthly
peak demand to annual peak demand and mo'nthly energy
requirement as a percentage of the annual energy
requirement resulting from the Method of IndirectA.veraging ana lysl~---,----------.-.-
Daily Load Profiles (**)
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FigureB.5.2.4 presents graphs of the hourly load
data for typical weeks in April,August,and
December 1983.The data from individual utilities
were combined to produce representative load curves
-...-----.--...'··-foreachl'oad-centerand·the·total RaUbe'lt'area~-'
..-The~-fol-low-i-ng-pa-ragra·ph's--de·s·cri·be··-the-·weekly-load'
profiles.
In April,th~re is usually a morning peak between 8
and 10 a.m.,and an evening peak between 6 and 8 p.m.
The evening peak is usually greater than the morning
peak.The night load is about 65-70 percent of the
daily load.The average daily load factor is about
85-percent •......
r
!
851104 B-5-8
In August,the load begins to rise from about 7 a.m.,
continuing to increase until 11-12 a.m.,wnen it
reaches a peak,it then decreases slowly to about
midnight before dropping off sharply.The night load
is about 55-60 percent of the daily peak load.The
average daily load factor is about 82 percent.
In December,there is usually a morning peak between
8 and 10 a.m.,and an evening peak between 6 and 7
p.m.The evening peak is usually about 10 percent
greater than the morning peak.The night load is
about 60 percent of the daily peak load.The average
daily load factor is about 85 percent.
Table B.5.2.6 presents twenty~,four hour load-duration
relations for typical weekday and weekend days for
the months of April,August,and December.These
data were developed from the utility hourly load data
as discussed above.Similar load duration data were
computed for the remaining months.These data have
been used in the generation expansion studies
described in Chapter 2 of Exhibit D.
(iii)Railbelt Load Diversity (**)
A system load diversity analysis w&s done by
comparing the peak days in 1982 and 1983.The peak
coincident and non-coincident loads were collected
from the hourly load data provided by AMLP,CEA,
FMUS,and GVEA and the load diversity was calculated
based on the data.Table B.5.2.7 shows the hourly
load demand for the Jariuary 6,1982 and January 10,
1983 peak days.The diversity measure in the total
Railbelt was about 0.99.The basic conclusion of the
analysis is that the total coincident peak load for
the Railbelt would be within two percent of the total
non-coincident peak demand.For the expansion
planning analysis,the Railbelt peak demand is
considered to be the sum of the projected peak demand
of the two load centers.
(b)Electricity Rates (**)
Tables B.5.2.8 and B.5.2.9 present the current residential
and commercial electric rates for the utilities of the
Anchorage-Cook Inlet area and Fairbanks-Tanana Valley area,
respectively.
Electric rates are considerably less in the Anchorage-Cook
Inlet area than in the Fairbanks-Tanana Valley area.The
851104 B-5-9
851104
average residential cost per kWh is approximately
6 cents/kWh in the Anchorage-Cook Inlet area,and
8.4 cents/kWh and 12.4 cents/kWh for FMUS and GVEA
respectively in the Fairbanks-Tanana Valley area.The lower
rates in Anchorage-Cook Inlet can be explained by the
relatively low cost natural gas supply and low capital cost
facilities used for electric generation.The relatively
high rates in Fairbanks-Tanana are a result of considerable
oil-fired generation,and high capital cost of coal-fired
facilities.A discussion of these rates is presented in the
following paragraphs.
(i)Anchorage Municipal Light and Power (AMLP)(**)
The AMLP tariff for residential service and small
general service customers comprises a fixed monthly _
customer charge and a flat energy charge per kWh.
The large general .service customer schedule has a
monthly demand charge in addition to a fixed customer
charge and a flat energy charge per kWh.In
addition,AMLP has an experimental program for
time.,..of.,..day rates for customers dependent upon
electric space heating.
(ii)Chugach Electric Association,Inc.,(CEA)(**)
CEA has tariffs for residential customers that
reflect a declining block rate structure.Small
"commercial .cus-tomer-schedules--pr-ovide-£ot'a·-f-ixe d
monthly customer charge and a flat energy charge per
kWh.CEA's schedule for large commercial customers
contains a demand charge as well as a fixed monthly
customer charge and a flat energy charge per kWh.
CEA has a wholesale electric power and energy
contract with HEA,MEA,and SES.MEA,HEA,and SES
have.tariffschedl1 les whiclldiffer .in specific
--de tails"DuE ~ii:-e-"simi1arrn struct"ure"to those"of the
-la-rger--Rattoert----eIectric utiTities ,-as shown In-Table
B.5.2.8.In addition,CEA has a rate schedule for
intertie with AMLP which contains a flat energy
charge and certain commitment and start/stop charges.
(iii)Fairbanks Municipal Utilities System (FMUS)(**)
In the Fairbanks-Tanan.a Valley area,EMUS has
residential,all electric;aifdgeneralservice rate
schedules which reflect declining rates as energy
consumption increases in blocks.For general service
customers with demand blocks of 30.kW or greater,
B-5-10
there is (in addition to an energy charge)a monthly
minimum charge per meter based on a fixed dollar
amount times the highest demand reading of the
preceding 11 months or times the estimated maximum
demand of the first year,whichever is greater.
(iv)Golden Valley Electric Association,Inc.
(GVEA)(**)
GVEA has a residential schedule with an energy charge
for the first 500 kWh and a lower charge for each
kWh over 500 kWh of consumption.There is a separate
schedule for general service customers depending on
their kW demand.'For GVEA's general service
customers with electrical demand not exceeding SO kW,
there,is only a decreasing energy charge associated
with three increasing blocks of consumption.General
service customers with loads exceeding SO kW have a
schedule which provides for a fixed demand charge per
kW pI us declining energy charges in correspolldenc;e
with four increasing consumption blocks.
(c)Conservation and Rate Structure Programs (*)
This section presents conservation and rate structure
programs initiated by the electric utilities and
government agencies.The effects of these existing programs
are reflected in current electricity consumption which
serves as the basis of the load forecast,described in
Section 5.4 of this Exhibit.
The utilities have various programs aimed at'supplying
information to the public concerning the dollar savings
associated with electricity conservation.In general,the
utilities rely on market forces;however,they promote
consumer recognition of those forces.Examples of
conservation and rate structure programs introduced by AMLP
and GVEA are described.
(i)The Anchorage Municipal Light and Power (AMLP)
Program (**)
The AMLP program addresses electricity conservation
in both residential and institutional settings.It
is a formal conservation program mandated by the
Powerplant and Industrial Fuel Use Act of 1978 (FUA).
The AMLP program is designed to achieve a 10 percent
reduction in electricity consumption.To achieve
this level of conservation,AMLP provides information
on available state and city programs to its
consumers.Additionally,it has programs to:
851104 B-5-11
o Distribute hot water flow restrictors;
o Insulate 1000 electric hot water heaters;
o Heat ·the city water supply,increasing the
temperature by 15°F (decreasing the thermal
needs of hot water heaters);
o Convert two of its boiler feedwater pumps from
electricity to steam;
o Convert city street lights from mercury vapor
lamps to high pressure sodium lamps;and
o Convert the transmission system from 34.5 kV to
US kV.
AMLP also supplies educational materials to its
customers along with "Forget-me-not"stickers for
light switches.The utility has a full time energy
engineer devoted to energy conservation program
development.
The projected impacts of specific energy conservation
programs are detailed in Table B.5.2.10 for the
period 1981-1987.The greatest impact will occur as
a result of street light conversion,transmission
line conversion,and power plant boiler feed pump
~co~nversio_n •....~.By ..L98:7~,_thes_e~programs~are_expected~to
provide 35,000 MWh of electricity conservation,or
72%of the total programmatic energy conservation.
In the case of conversion to new sodium lights,the
record shows that AMLP installed 96 kW by the end of
1980,an additional 8 kW in 1981,16.6 kW in 1982,
and 14.3 kW of additional sodium lights in 1983.In
addition to these conservation programs,AMLP has
also projected conservation due to ce-induced
e
(ii)The Golden valley Electric Association,Inc.(GVEA)
Program (*)
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GVEA has an energy conservation program based
plan established pursuant to REA regulations.
-utili-ty--employsan-Energy-Use-Advisor who:
on a
The
851104
0--Performsadvisory'{non-quantitative)audits;
o Counsels customers on an individual basis on
means to conserve electricity;
B-5-12
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851104
o Provides group presentations and panel
discussions;and
o Provides printed material,including press
releases and publications.
GVEA also eliminated its special incentive rate for
all-electric homes,and placed a moratorium on
electric home hook-ups in 1977.It has given out
flow restrictors.It has prepared displays and
presentations for the Fairbanks Home Show and the
Tanana Valley State Fair.
The efforts of GVEA,combined with price increases
and other socioe.conomic phenomena,produced a
conservation effect·in residential use per household.
Although much of the decline in average consumption
can be attributed to conversions from electric heat
to some other fuels,part of the reduction is the
direct result of conservation.A moderate upturn in
electricity consumption per household in 1982
indicates that the practical limit of conservation
may have been reached in the GVEA system.
Currently,GVEA's load management program is directed
toward commercial consumers.A significantly lower
rate schedule is available to commercial customers
whose demand is maintained at less than 50 kW.
Larger power customers are advised on ways to manage
their electrical load to minimize demand.In
addition,seasonal rates are available to those large
consumers who significantly reduce their demand
during the winter peak'season.A program is underway
to identify customers who operate large interruptible
loads during periods of system peak demand.Various
methods of residential load management are under
study,but none appears cost effective at this time
other than voluntary consumer response to education
programs.
(iii)Other Utility Programs (0)
Other utilities have programs similar to the ones
described above.For example,FMUS has two main
programs aimed at electric conservation and reducing
the consumer's electric bill.FMUS placed an
advertisement in a local newspaper about energy
conservation and offered to provide a free booklet on
the topic.Also,FMUS plans to advertise the
availability of an "Energy Teller"device to allow
B-5-13
851104
the customer to determine the direct cost of using a
given appliance.These instruments are exp~cted to
be available for free loan for a period of up to two
weeks.
(iv)Other Conservation Programs (0)
There are several efforts,both public and private,
under way throughout Alaska.The two main programs
that affect the Railbelt area are described in the
following paragraphs.
The State Program.The Alaska Department of
Community and Regional Affairs administers the United
States Department of Energy's low-income
weatherization program.The program is currently
directed at rural areas and is gradually being phased
out.It has involved the following activities;
o Training of energy auditors;
o Performance of residential energy audits,which
are physical inspections including measurements
of heat loss;
o Provid~ng grants of up to $300 per household,
or loans,for energy conservation improvements
based upon the audit;and
o Providing home retrofitting (e.g.insulation,
weatherization)for low income households.
The City of Anchorage Program.The City of Anchorage
Program is operated by the Energy Coordinator for
the City of Anchorage.This program also involves
audits,weatherization,and educational efforts.
Based on walk-through audits performed on city
-_.-'-··"Dfj-i-ldi"i·fg·S'---~~fna··--tfchoo'I-s--;"------de"-e'a'-ir-iid-----aua-r"t:'·s..,-"'fi'a-ve'---oe"Eiii"'---_.--~--_.,_._~._,-..
The city's weatherization program is available to low
income families and provides grants of up to $1,600
for materials and incidental·repairs.
---The educational-program-has involved working with
realtors,bankers,contra.ctors,and businessmen.It
-alsohas--involved-informalconta ct s wi thcommer cial
building maintenance personnel.Finally,it has
involved contacts with the general public.
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5.2.3 -Historical Data for the Market Area (**)
Historical economic and electric power data for Alaska and the
Railbelt are summarized in Table B.S.2.1l.The table shows the
rapid growth that has occurred in the state's and the Railbelt's
population,economy,and use of electric power.From 1960 to
1984,the state population has grown from 226,000 to 523,000,an
average annual growth rate of 3.6 percent.The Railbelt
population has grown at a faster rate of 4.1 percent,increasing
from 140,000 in 1960 to about 371,000 in 1984.The growth has
been especially rapid during the last five years.
Between 1960 and 1984,employment in the state grew from 94,000
to 1'64,000,an increase of 180 percent,or an average of '4.4
percent per year.Much of the population and economic growth
that occurred during this period is attributable to several
factors.During the 1960'S,oil and gas resource development in
Cook Inlet provided the beginning of a bax base and a stimulus to
infrastructure development.The 1964 earthquake in Anchorage and
the 1967 flood in Fairbanks resulted in significant construction
activity.The 1970's were dominated by the anticipation and
construction of the trans-Alaska pipeline.In 1979,a decline in
the economy resulted from the reduction in construction
employment,but it was significantly offset by expansion of state
and local government,made possible by the tremendous increase in
state petroleum revenues from Alaska's North Slope.The
quadrupling of the world oil price at the beginning of the decade
has provided the impetus for the current cycle of Alaska's
economic growth.
State petroleum revenues have grown from only $4.2 million in
1960 to $2.9 billion in 1984 while state general fund
expenditures have risen from less than $100 million per year to
$3.3 billion.Figure B.S.2.S illustrates the historical growth
in Rai1belt population,showing the annual growth rate for each
five-year period from 1960 to 1980 and from 1980 to 1984.
Consumption of electric energy in the Railbe1t has risen
significantly faster than the rate of economic growth.Between
1965 and 1984 total utility energy generation increased from 487
GWh to 3208 GWh,a six-fold increase,or an average of 10.4
percent per year.Figure B.5.2.6 illustrates the historical
growth in Rai1belt net generation,showing the annual growth rate
for each five-year period from 1965 to 1980 and from 1980 to
1984.
Tables B.5.2.12 and B.5.2.13 present monthly electric power use
and peak demand during the period 1976 to 1983 for the
Anchorage and Fairbanks load centers.These tables show that,
while there has been a steady rise in the use of electric energy
B-S-15
and in peak demand,there has been variation in monthly energy
use and peak demand from one year to the next,due mostly to
different weather conditions in the Railbelt.Table B.5.2.14
presents the annual net generation of each Railbelt utility
between 1976 and 1984.
5.3 -Forecasting Methodology (*)
Th1S section presents the methodological framework used for the
forecasts of economic conditions and electricity demand in the
Railbelt.First,the models used for forecasting purposes are
identified and explained.Next,model validation is discussed for the
petroleum revenue model (APR),economic model (MAP),and electricity
demand model (RED)and the optimized generation planning model (OGP).
5.3.1 -Forecasting Models (**)
(a)Model .Overview (**)
Four computer-based and functionally int~rrel~ted models
were used to forecast Railbelt economic growth and the
associateci·d~Ill~~ci f9I:'.~lecl:ric power,and for evaluating
alternative generation plans for meeting electric power
demand.The models and their relationship are 'graphically
displayed in Figure B.5.3.1.
The starting-point for the demand forecast is a series of
da ta inputs concerning 'the projected world oil price and the
pro je cted.Alas kagasa~cl()npric:~s .and.:pr od uc t io~l~Jlels_._
Aii:hIs stage 'of the'process,the world oil price forecast
is important because it affects the wellhead price of oil in
Alaska,and also affects the assumed price of na tural gas.
The first economic model in the series,the Alaska Petroleum
Revenue Sensitivity Model (APR),was designed by the Alaska
Department of Revenue (ADOR)to translate petroleum price
and production forecasts into forecasts of state petroleum
851104
The model is a simplified version of ADOR's PETREV model,
which the agency uses to make its quarterly petroleum
revenue forecasts.The price and production forecasts input
to the APR model are combined with assumptions about royalty
rates,severance tax rates,and certain adj ustment factors
to produce forecasts of state petroleum revenue.,·
The,state pe trol eum-revenue-forecast 'output by the APR model
becomes input to the second economic model in the series.
!he Man-in-the-Arctic Program (MAP)was developed by the
University of Alaska's Institute of Social and Economic
B-5-16
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851104
Research (ISER)for the purpose of forecasting economic
growth in Alaska.The MAP model was designed to take
assumptions concerning basic industrial development,state
petroleum revenue forecasts,fiscal policies,and several
national and state economic and demographic parameters,and
from these assumptions forecast growth in the state economy.
Railbelt economic growth in terms of population,households,
and employment is then isolated from the state totals.
The Railbelt economic growth forecast output by the MAP
model becomes input to the Railbelt Electricity Demand (RED)
model,a partial end use model developed by ISER and later
modified by Battelle Paci~ic Northwest Laboratories.The
RED model also incorporates many other assumptions,
incl uding:
o residential and business end use data,including
saturation rates for various electrical end uses
o an industrial/military load forecast
o estimates of heating oil,natural gas,propane,and
electricity prices to be paid by residential and
business consumers in the Anchorage and Fairbanks load
centers
o long term and short term price elasticities,which
define consumers'responses to changes in the price of
electricity and competing fuels
Given these assumptions and the MAP model's economic growth
forecast,the RED model produces a forecast of energy demand
and peak load through 2010.
The output of the RED model is the product of one iteration
of the demand forecasting process.The energy and peak load
forecasts become input to the Optimized Generation Planning
(OGP)model,which is part of the economic and financial
analysis component of the Susitna project evaluation
process.Given a load forecast,and the cost of building
thermal generation alternatives,the OGP model chooses the
optimal generation expansion path and calculates the cost of
electricity associated with that path.If the resulting
production cost of electricity is out of line with the
retail prices assumed in the RED model,the RED model is
rerun with new electricity prices,and OGP is rerun with the
new load forecast until the prices converge.
The following sections describe each of the four principal
models,including their respective submodels and modules,
B-5-17
key input variables and parameters,and primary output
variables.Additional information on the APR model
assumptions which,except for oil and gas prices,are the
same as the ADOR's PETREV model assumptions,is available in
the quarterly issues of Petroleum Production Revenue
Forecast (Alaska Department of Revenue 1985).Additional
information on the MAP modei may be found in the MAP model
system documentation (ISER 1985).The system documentation
presents a detailed description of the model,including a
complete listing of its equations and input variables and
parameters.Two other documents present similarly detailed
documentation of the RED model.The RED model·Technical
Documentation Report (Battelle 1983)was part of the Susitna
license applica.tion as accepted by FERC in July 1983.The
model documentation included in that report is still
current,except for those changes noted in a more recent
report prepared by Battelle (Scott,King and Moe 1985).The
OGP model is a proprietary program of General Electric
Company.The version used in the current study is presented
in .the Descriptive Handbook,Optimized Generation Planning
Program,by General Electric (GE 1983).
(b)Alaska Petroleum Revenue Sensitivity (APR)Model (**)
Petroleum revenues currently constitute a large proportion
of total state revenues.State revenues and expenditures
.also have considerable potential variability and are
important determinants of future state economic conditions.
T.b_e_.Al_a~.k:a.D_ep-ar_tme_nt ..of Reveuue.th_er_e_fore _pr.od_uces.
quarterly projections of the most important sources of
petroleum revenues,production taxes and royal ties.Those
projections·are generated by a.specialiiedriiodel,PETREV.
The APR model used for this load forecast is a special
submodel of PETREV.The PETREV model will be described
first,followed by a description of the APR model.
PETREV is structured to take into account the uncertainties-_.--------------------of --fufurEf·-oir-prfc-e::I--and--(fElier-faEfors-ass·ocTafedw nIl
----f-orl:c-a-s-ttn-g-I'etr()~I-eUfif-r-eV'enue-s-.--U-s-tn-'g-PETREV-;--th-e-----A:DOR-----------------
issues updated petroleum revenue projections on a quarterly
basis covering a 17 year period.The ADOR uses current data
available on petroleum production,a range of world oil
prices,tax rates,regulatory events,natural gas prices,
and iriflat ion ra tes •
PETREV is an -economic a.ccount ingriiodeltha.t ··uti 1 izes a
probability--distributionof·possiblevalues--for each of the
factors that affect state petroleum revenues to produce a
range of possible state royalties and production taxes.The
principal factors influencing the level of petroleum
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851104 B-5-18
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revenues are petroleum production rates,mainly on the North
Slope,the market price of petroleum,and tax and 'royalty
rates applicable to the wellhead value of petroleum.
Natural gas prices and production levels are also taken into
account,as are Cook Inlet petroleum prices and production
levels.This model description focuses on North Slope
petroleum,which accounts for over 90 percent of state
petroleum revenue.
For input into the PETREV model,wellhead value of oil is
estimated by a netback approach.The costs of gathering and
transporting crude oil and a quality differential value are
subtracted from the market value at its destination on the
West Coast or Gulf Coast of the United States.For
petroleum produced on the North Slope,the source of most of
the oil produced in Alaska subject to state royalties and
production taxes,future wellhead value is estimated as
follows.The projected world price of Ecuador Oriente
petrol eum11 is adjusted by subtracting (1)the projected
cost of pumping oil through the ]~ans Alaska Pipeline System
from Prudhoe Bay to Valdez,including the pipeline tariff,
(2)the projected cost of shipping the oil to refineries on
the West Coast and the Gulf Coast of the United States,and
(3)a projected quality differential factor representing the
difference in quality between North Slope petroleum and
Ecuador'Oriente grade.The result is the estimated value of
petroleum at Pump Station 4/:1 at Prudhoe Bay,Alaska.For
other North Slope fields,the price is lowered by the
respective pipeline charges between each field and Pump
Station if/:1.
Future royalties collected by the state are estimated by
multiplying total projected production in barrels from state
lands by the estimated per barrel price at the pump,
subtracting field costs,and multiplying the result by .125.
This amounts to a 1/8 royalty payment on oil produced after
all gathering and transportation costs are met.The State
of Alaska may receive the royalty either in kind or in
dollars.Future severance,or production,taxes are
estimated by multiplying forecasted production,net of the
12.5 percent taken by the state as royalties,by the
estimated pump station price and the tax rate adjusted by an
economic limit factor (ELF).The nominal tax rate varies
11 Ecuador Oriente is a common measure of petroleum grade and price.
Other standards include Saudi light and Saudi medium grade
petroleum.
851104 B-5-19
851104
between 12.25 and 15 percent of net production value,
depending upon the age of production wells.The e·conomic
limit factor (ELF)adjustment takes into account declining
well productivity and increased production costs.On the
North Slope most production will be subject to a 15 percent
nominal severance tax rate,but the effe~tive tax rate after
adj ustment varies from 0.0 to 15.0 percent.A decline in
the ELF in effect lowers the tax rate to which Alaskan
petroleum is subject.
Due to the many uncertainties involved in forecasting
revenues,the PETREV model projects a range,or frequency
distribution,of state petroleum revenues by year,so that
for each year a forecasted petroleum revenue figure may be
selected based on a given cumulative frequency of
occurrence.The model accomplishes this by iteratively
selecting a set of input variable values from among the
alternative values and computing a petroleum revenue figure
for each time period.Each projection is computed using a
set of accounting equations l!hat estimate royalties and
production taxes from each state oil and gas lease for each
time period.By selecting the average.value of all input
data,the model can also produce an average petroleum
revenue forecast.
For the Susitna Project evaluation it is necessary to
examine the implications of more than one world oil price
projection.This need is accommodated by ADOR through the
Al~§l_ka ..l'e tJ'oleumRg'l~J,'lU~·.S~n1dtiytty_JA1>R)_Mo.deL_...W.ithtwo
exceptions,this sensitivity accounting model,which is in
effect a submodel of the PETREV model,utilizes the
accounting equations and average values from PETREV.The
two exceptions are world oil price and Cook Inlet gas price.
By executing tn.esensitivity model with the alternative oil
and gas price projections,alternative petroleum revenue
projections are developed for use in projecting state
economic activity in the MAP model.The APR model structure
-i·ssnowil·in-Figure-B~S~3~Z~.__.
The process of projecting state petroleum revenues and the
functions of the PETREV model are presented in more detail
in the quarterly "Petroleum Production Revenue Forecast"
(ADOR 1985).The petroleum revenue projections used in
preparing the electric power market and economic forecasts
are based on the March 1985 average expected values of all
factors other than oil prices a.nd Cook Inlet gas prices.
Those·input assumptions are summarized in Section 5.4.1.
B-5-20
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851104
(i)Input Data (***)
As noted above,the APR model uses the mean values
for the input data used in the PETREV model.The
input includes both oil and gas revenue variables.
Oil revenue variables include:
o World oil price;
o Oil price adjustment factors for each field
expected to operate at any time during the
forecast period (Prudhoe Bay,Kuparuk River,
Milne Point,Endicott,Lisburne,West Sak
Sands,Seal Island,unspecified onshore North
Slope production,and Cook,rnlet);
o Petroleum production for each field;and
o Number of wells and economic limit factor for "
each field,nominal severance tax rate and
royalty rate gathering and cleaning charges by
field.
Gas revenue variables include
o North Slope and Cook Inlet gas price;
o North Slope and Cook Inlet gas production;
o Economic limit factor by field;and
o Severance tax and royalty rates.
(ii)APR Model Output (***)
The output data from the APR model includes oil and
gas severance tax and royalties for each oil field
and each gas producing area.The revenue estimates
by field are summed to produce the input used in the
MAP model,including:
o State severance tax revenue by year,1985-2010;
and
o State royalty revenue by year,1985-2010.
(c)Man-in-the-Arctic Program (MAP)Economic Model (*)
The MAP model is a computer-based economic modeling system
that simulates the behavior of the economy and population
B-5-21
of the State of Alaska and each of 20 regions of the state.
The regions correspond closely to Bureau of the Census
divisions.The Railbelt consists of six of those regions:
Anchorage,Fairbanks,Kenai-Cook Inlet,Matanuska-Susitna,
Seward,and S.E.Fairbanks.The model was originally
developed in the 1970s by the Institute of Social and
Economic Research of the University of Alaska,under a grant
from the National Science Foundation.The model has been
continually improved and updated since it was originally
developed.In addition to its use on the Susitna Project,
it has been used in numerous economic analyses such as
evaluations of the economic effects of alternative state
fiscal policies and assessments of the economic effec ts of
development of outer continental·petroleum shel f leases.
The MAP model functions as three separate but linked
submodels:the scenario generator submodel,the economic
submodel,and the regionalization submodel,as illustrated
in Figure B.5.3.3.The scenario generator submodel enables
the user to quantitatively define scenarios of development
in exogenous industrial sectors;i.e.,sectors whose
development is basic to.tl:t~.economy rather than supportive.
Examples of such'sectors are petroleum production and other
mining,the federal government,and tourism.The scenario
generator submodel also enables the user to implement
assumptions concerning state··revenues from petroleum
production.The economic submodel produces statewide
projections of numerous economic and demographic factors
based on quantitative relationships between elements oJ the
._..~~-~--Alaskan economy such as···em·ploYmentlli-basic i.ndustrIes,
employment in non-basic industries,state revenues and
spending,wages and salaries,gross product,the consumer
price index,and population.The regionalization submodel
enables the user to disaggregate the statewide projections
of population and employment to each of the 20 separate
regions of the state,using data on historical and current
economic conditions and assumptions concerning basic
...............industrial development.
--_._--.__...._..
Each of the three MAP submodels exists as a computer
program,and each program is supported by a set of input
variables and parameters.Each of these programs and the
supporting input variables and parameters are discussed
briefly in the following sections.Detailed information on
each submodel,including a complete model listing and the
input variables and parameters used ..in executing the model,
is provided in.thiS License Amendment:.
.J
851104 B-5-22
851104
(i)Scenario Generator Submodel (*)
In order to operate the MAP model,the user must make
a number of assumptions concerning the future
development of basic industries in the State.Such
assumptions are needed because the state economy is
driven by interrelated systems of endogenous and
exogenous demands for goods and services.Endogenous
demands are generated by exogenous industries and the
resident population which provides employment to all
industries.
Exogenous demands originate outside Alaska due to the
favorable position of the state to export its
minerals and other resources to other states or
countries.In Alaska,exogenous demands stem·from
the state's natural resource base,especially
petroleum;non-energy minerals;federal property;and
tourist attractions.Exogenous demands lead directly
to employment in basic sectors such as mining,
indirectly to employment and output in industries
such as oil field services that support basic
industry,and also to industries such as housing and
restaurants that support workers in basic industries
and their families.
The scenario generator model.permits the user to
build,from among a large number of alternative basic
industrial cases,economic scenarios that can be used
to project economic conditions in the State of Alaska
and,for purposes of the Susitna Hydroelectric
Project,the Railbelt.Input data for each of the
scenarios are in the form of employment projections
by sector and region of the state on an annual basis
over the forecast period.
The scenario generator model is also used to select
the level of state petroleum revenue that is assumed
available to the state's general fund for expenditure
on state government operations and capital
inves tment.
Key input and output variables and assumptions for
the scenario generator are summarized in Section
5.4.1 of this Exhibit.
(ii)Statewide Economic Submodel (*)
The statewide economic submodel is a simultaneous
system of more than 1,000 equations that
B-5-23
individually and collectively define the quantitative
relationships between economic and demographic
factors in Alaska.Some values for input variables
come from the scenario generator,whose values can be
expected to vary from one execution of the model to
the next.Other values come from files of necessary
exogenous data,such as files describing state fiscal
behavior,whose values generally do not change across
runs.Parameters,whose values are generally fixed
from one model execution to the next,are provided
from another input file.The equations are solved
algebraically each time the model is executed to
produce a unique set of values for the dependent
variables.
While the equations in the statewide economic model
are solved as a unit each time the model is executed,
they are grouped for organizational and conceptual
purposes into three modules:economic module,fiscal
module,and demographic module,as illustrated in
Figure B.5.3.4.
The equations in the economic module express
relationships be tween economic factors such as
employment in basic industrial sectors and output and
employment in support sectors.Important products
from the economic module include projections of
employment and payroll by industry and personal
j
"J
The fiscal m()dult:c01llputesstate government revenues
and .the mix of government expenditures.This
info:rmation is used as input to the economic module.
The fiscal module plays a key role in examining the
fiscal and economic effects of different future world
petroleum prices and state petroleum revenue levels.
............__.._...The.demographic module expresses~~.£.~lationshiI>~_
between both households and population and economic
factors recognized as key determinants of population.
Population is determined by such factors as
employment,labor force participation rates,
fertility and mortality rates,and unemployment and
wage rate differentials be.tween Alaska and the rest
of th e Urti te d S.~§l tE!$•
HouseholdfoiIllation is based lIpon a unique propensi ty
to form households in each age,sex,and racial
category.Over the last few years this household
'j
"J
.1
851104 B-5-24
:1
i \
lJ
formation rate has generally increased.The increase
is expected to continue at reduced rates.
(iii)Regiona1ization Submode1 (*)
Statewide employment,population,and household
projections are disaggregated by the
regiona1ization model,the third submode1 of the MAP
economic modeling system.Disaggregation is
accomplished by combining statewide projections with
regional industrial development data and regional
parameters based on historical,economic and
demographic relationships between each region and the
state.This process,illustrated in Figure
B.5.3.5,produces projections by region or region
group such as the Anchorage and Fairbanks greater
metropolitan areas.
(iv)Input Variables and Parameters (*)
As indicated above,some input variables are factors
whose values are provided by the user to the model
and whose values can be expected to change from one
execution of the model to the next.Parameter values
are generally fixed both over time within each
simulation and during the course of successive model
executions.
The scenario generator model produces 16 input
variables to define the exogenous economic
assumptions for each model execution:
o Agriculture Employment
o Mining Employment
o High Wage Exogenous Construction Employment
o Regular Wage Exogenous Construction Employment
o High Wage Exogenous Manufacturing Employment
o Regular Wage Exogenous Manufacturing
Employment
o Exogenous Transportation Employment
o Fish Harvesting Employment
851104 B-5-25
851104
o Active Duty Military Employment
o Civilian Federal Employment
o Tourists Entering Alaska
o State Production Tax Revenue
o State Royalty Income
o State Petroleum Lease Bonus Payment Revenue
o State Petroleum Property Tax Revenue
o State Corporate Petroleum Tax Revenue
Of these 16 variables,10 are used to define discrete
industrial development scenarios and are therefore
region specific.One variable defines the level of
tourism fon .the state~The remaining five input
variables are elements of state revenue forecasts.
Est imat:~~():fpetroleUlD p:rod1J~t:i,on taxes and royal ties
are obtained from the APR model.The Alaska
Department of Revenue's March 1985 estimates of state
petroleum.corporate taxes are used (ADOR 1985).
State petroleum property tax estimates are based on
ADOR projections adjusted for ISER estimates of
OCS-related activities.Future lease bonus payments
...._..~!:.~_~..J:s t !maE~~EL~SER.__...._
'The regionalization model is executed using a data
series for 40 exogenous variables,based on 20 state
regions in the scenario generator.For each region,
there are basic sector employment and the government
sector employment.Total state population,
households,and the ratio of support to total
employment are provided by the state economic
·····submodel.-·
In to the variables discussed above,the MAP
model utilizes three types of parameters:variable
state fiscal policy parameters;stochastic
parameters;and calculated,or non-stochastic,
parameters.
Variable state fiscal policy parameters are used
primarily in the fisca ltllodule torepreserit policy
options for the collection of revenues and the timing
and composition of state expenditures.The most
important function of these parameters is to
B-5-26
]
I
.---.•.,__.••••.•.__'~"'_"'~_".__.._._~_,..,_.8 ' '~'__'' ''_~".__••._.__•__,•••••••.••..••.••__._.••• .••~_••
851104
quantitatively define state expenditure and revenue
policies.In projecting economic conditions for the
Susitna Hydroelectric Project,the following
assumptions were made:
o State expenditures for operations and capital
improvements in 1985 dollars will rise in
proportion to state population as long as
revenues can support this level of expenditure;
this assumption is in accordance with a 1982
amendment to the Alaska State Constitution
setting a ceiling 'on state expenditures.
o When revenues from existing sources cannot
support expenditures at the constant real per
capita level,earnings from the permanent fund
will be made available for operating and
capital expenditures at the expense of the
Permanent Fund dividend program;as revenues
decline,state spending priorities shift from
subsidies and capital improvements toward the
operating budget.
o When revenues from Permanent=Fund earnings and
other sources are not sufficient to maintain
expenditures at.the constant real per capita
level,a state personal income tax will be
reimposed at its previous rate.
o When all of these revenue sources plus any
accrued general fund balances are unable to
support expenditures at the constant real per
capita level,both capital and operating
expenditures will be curtailed proportionately
so that they will not exceed revenues.
Stochastic parameters are coefficients computed using
regression analysis.They are used primarily in the
economic module of the statewide economic model to
express the functional relationships between economic
factors such as employment,wages and salaries,wage
rates,gross product,and other national and regional
economic factors such as unemployment and consumer
price indices.Stochastic parameters are also used
in the population module to express the relationship
between population migration into and out of Alaska
and wage rate and unemployment level differentials.
Calculated or non-stochastic parameters are generally
calculated rates or other quotients,and are used
B-5-27
primarily in the population~::and household formation
modules and the regionalization model.Calculated
parameters include factors such as survival rates for
the population by race,age group,and sex.
Calculated parameters used in the regionalization
model include factors such as the ratio of population
to residence adjusted employment by region.
(v)MAP Model Output (*)
Economic forecasts through the year 2010 are
generated for alternative oil and gas prices and
state petroleum revenue cases and other input
variables and parameters described above.Specific
MAP Model-output used directly as input to the
Railbelt Electricity Demand (RED)Model include the
following:
o Population by load center,Greater Anchorage
and Greater Fairbanks,by year,n!·985 through
2010
o Total employment by load center by year
o Total households in the state by age group of
head of household -24 and under years of age,
25-29,30-54,and over 55 -by year
.._.Q TQtalho.useholds byl0.ad.center by year
(d)Railbelt Electricity D~mand Model (*)
The Railbelt Electricity Demand Model is an end use -
econometric model that projects both electric energy and
peak load demand in the Anchorage-Cook Inlet and
Fairbanks-Tanana Valley load centers of the Railbelt for the
period 1980-2010.The Anchorage-Cook Inlet load center is
--aefinedtoincrudetlieAncnorage;Kena i=C()okfiiI e'E ;.-
---·'--M·at·anuska=S·us·i'tnli-;-anaSewara'census regions~.IKe
Fairbanks-Tanana Valley load center includes the Fairbanks
and SE Fairbanks census regions.
The RED model was originally written by the Institute of
Social and Economic Research (ISER)of the University of
.Alaska·(·ISER 1980.).-It was later modified and expanded by
-Battelle Pacific Northwest Laboratories (Battelle 1982,
.-Volume VITr).·The-present·version is a ftirthermodification
and improvement,and includes a validation of the model
performance.The resul ts of these e·fforts are fully
documented in Battelle (1983)and Scott,King and Moe
(1985).A summary description of the methodology used by
the RED model and an explanation of each module are
11
'1
851104 B-5-28
I .']
presented in the following paragraphs.These discussions
are followed by a description of the input and output data.
The RED model is a simulation model designed to forecast
annual electricity consumption for the residential,business
(commercial,small industrial,government),large
industrial,and miscellaneous end-use sectors of the two
load centers of the Railbelt region.The model is made up
of seven separate but interrelated modules,each of which
has a discrete computing function within the model.They
are the Uncertainty,Housing,Residential Consumption,
Business Consumption,Program-Induced Conservation,
Miscellaneous Consumption,and Peak Demand Modules.Figure
B.5.3.6 shows the basic relationship of the seven modules.
The model may be.operated probabilistica11y.In this mode,
RED randomly selects values for key model parameters from
frequency distributions in the model's data files.The
model may also be operated on a deterministic basis,whereby
only one set of forecasts is produced based on a single set
of average input variables.When operated
probabilistically,the RED model begins with the Uncertainty
Module,which selects a trial set of values for model
parameters to be used by other modules.These parameters
include price elasticities,appliance saturations,end-use
consumption per square foot of business floor space,and
regional load factors.Exogenous forecasts of population,
employment,and households from the MAP model,plus retail
prices for fuel oil,gas,and electricity are used with the
model's parameters by the Residential Consumption and
Business Consumption Modules to produce forecasts of
electricity consumption.These forecasts,along with
additional trial parameters,are used in the Program-Induced
Conservation Module to simulate the effects of government
programs that subsidize or mandate the market penetration of
certain technologies that reduce the need for power.This
program-induced component of conservation is in addition to
those savings that would be achieved through normal consumer
reaction to energy prices.The consumption forecasts of
residential and business (commercial,small industrial,and
government)sectors are then adjusted to reflect these
additional savings.The revised forecasts are used to
estimate future miscellaneous consumption and total sales of
electricity.These forecasts and separate assumptions
regarding future major industrial loads are used along with
a trial system load factor to estimate peak demand.
851104
After a complete set of projections is prepared,
begins preparing another set by returning to the
Module to select a new set of trial parameters.
B-5-29
the model
Uncertainty
After
851104
several sets of projections have been prepared,they are
formed by RED into a frequency distribution to allow the
user to determine the probability of occurrence of any given
load forecast.When only a single set of projections is
needed,the model is run in deterministic mode whereby a
specific default set of parameters is used and only one
trial is run.This deterministic formulation was used to
produce alternative load forecasts for the Susitna
Hydroelectric Project.
The RED model produces projections of electricity
consumption by load centers and sectors at five-year
intervals.A linear interpolation is performed to obtain
yearly data.
The outputa from the RED model runs are used by the
Optimized Generation Planning (OGP)model to plan and
dispatch electric generating·capacity for each year.The
remainder of this section presents a description of each
module in the RED model.
··(-0 Uncerta-intyModule-(*)
When used in probabilistic mode,the purpose of the
Uncertainty Module is to randomly select values for
individual model parameters that are-considered most
subject to forecasting uncertainty.These parameters
include the market saturations for major appliances
c"~~-in~-the~.residentcialc-sectorc;--the~pr"ice~elasHc i tyand
cross-price elasticities of demand for electricity in
the residential and business sectors;the intensity
of electricity use per square foot of floorspace in
the business sector;and the electric system load
factors for each load center.
These parameters are generated by a Monte Carlo
routine,which uses information on the distribution-of--eachparameter(such""asTfs·expectecf··val ueana.·_·
range)anClthe computer's ranClom numoergeneratoi'-fo-
produce sets of parameter values.An overview of
information flows within the Uncertainty Module is
given in Figure B.5.3.7.Each set of generated
parameters represents a "trial".By running each
successive trial set of generated parameters through
the rest of the modules,the model builds distribu-
tions of annual el.aC:tricityconsumptiona.nd peak
dem,fcid~The end points bf each distribtition reflect
the probable range of annual electric consumption and
peak demand,given the level of uncertainty.
B-5-30
1
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851104
The Uncertainty Module need not be run every time RED
is run.The parameter file contains "default"values
of the parameters that may be used to conserve
computation time.In the current study,the RED
model was used in deterministic mode for all
forecasts.Default values for the parameters were
set at their most probable level.
(ii )Hous ing Module (*)
The Housing Module calculates the number of
households and the stock of housing by dwelling
type in each load center.The Housing Module's
structure is shown in Figure B.5.3.8.Using regional
forecasts of households and total population,the
housing module first derives a forecast of the number
of households served by electricity in each load
center.Next,using·..,exogenous statewide forecasts of
household headship rates and age distribution of
Alaska's population,it estimates the distribution of
households by age of head and size of household in
each load center.Finally,it forecasts the demand
for four types of housing stock:single family
units,mobile homes,duplexes,and multifamily
units.
The supply of housing is calculated in two steps.
First,the supply of each type of housing from the
previous period is adjusted for demolition and
compared to the demand.If demand exceeds supply,
construction of additional housing begins
immediately.If excess supply of a given type of
housing exists,the model examine$the vacancy rate
in all types of houses.Each type is assumed to have
a maximum vacancy rate.If this rate is exceeded,
demand is first reallocated from the closest
substitute housing type,then from other types.The
end result is a forecast of occupied housing stock
for each load center for each housing type in each
forecast year.This forecast is passed to the
Residential Consumption Module.
(iii)Residential Consumption Module (*)
The·Residentia1 Consumption Module forecasts the
annual consumption of electricity in the
residential sector.The Residential Consumption
Module employs an end-use approach that recognizes
nine major end-uses of electricity,and a "small
appliances"category that encompasses a large group
B-5-3l
851104
of other end uses.In addition to space heating,the
major end uses are water heaters,cooking,-clothes
dryers,refrigerators,freezers,dishwashers,clothes
washers,and saunas and jacuzzis.Figure B.5.3.9
shows the calculations that take place in this
module.
For a given forecast of occupied housing,the
Residential Consumption Module first adjusts the
housing stock to net out housing units not served by
an electric utility.It then forecasts the
residential appliance stock and the portion using
electricity,stratified by the "type of dwelling and
vintage of the appliance.Appliance efficiency
standards and average electric consumption rates are
applied to that portion of the stock of each
appliance using electricity and the corresponding
consumption rate.to derive a preliminary consumption
forecast for the residential sector.Finally,the
Residential Consumption Module receives exogenous
forecasts of resident ial fuel oil,natural gas,and
electricity prices,al()ng wit1:J.values of price
elasticities and cross-price elasticities of demand
from the Uncertainty Module.It adjusts the
preliminary cons~ption forecast for both short-and
long-run price effects on appliance use and fuel
switching.The adjusted forecast is passed to the
Program-Induced Conservation Module.
The Business Consumption Module forecasts the
consumption of electricity by load center for each
forecast year.Because the end uses of electricity
in the commercial,small industrial,and government
sectors are more diverse and less known than in the
residential sector,the Busine$s Consumption Module
'forecasts'e-lectrical'useon-anaggregate-basisrather--.
~~~-l;-han-by-end-us·e,,·---:-F-igure-B.-5..3.10--pr'es·ent-s--a---------.--
flowchart of the module.
RED uses a proxy (the stock of commercial and
industrial floorspace)for the stock of capital
equipment to forecast the derived demand for
..electricity •.Usingan.exogenous forecast of regional
employment,the module forecasts the regional stock
·of·floorspace.-Next,.ecoI10111efric equatioI1s are used
to predict the intensity of electricity use for a
given level of floors pace in the absence of any
relative price changes.Finally,a price adj ustment
B-5-32
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1
j
similar to that in the Residential Consumption Module
is appl ied to derive a forecast of business'
electricity consumption.This total excludes large
industrial demand,which is exogenously determined.
The Business Consumption Module forecasts are passed
to the Program-Induced Conservation Module.
(v)Program-Induced Conservation Module (*)
Battelle developed this module for the State of
Alaska,Office of the Governor (Battelle 1982,
Volume VIII)to analyze potential large scale
conservation programs that would be subsidized by the
State of Alaska.This module permits explicit
treatment of government programs which could foster
additional market penetration of technologies and
programs that reduce the demand for utility-generated
electricity.The module structure is designed",to
incorporate assumptions on the technical performance,
costs,and market penetration of electricity-saving
innovations in each end use,load center,and
forecast year.
The module forecasts the additional electricity
savings by end use that would be produced by
government programs beyond that which would be
induced by market forces aione.It also forecasts
the costs associated with these savings,and adjusted
consumption in the residential and business sectors.
In the current study,this module was not used.
Existing conservation programs are being phased out
and there are many uncertainties regarding the future
of long term government conservation programs.The
impact of past program-induced conservation is
reflected,however,in the historical electricity
consumption values used to initialize the model.
851104
(vi)Miscellaneous Consumption Module (*)
The Miscellaneous Consumption Module forecasts total
miscellaneous consumption for second (recreation)
homes,vacant houses,and street lighting.The
module uses the forecast of residential housing stock
to predict electricity demand in second homes and
vacant housing units.The sum of residential and
business consumption is used to forecast street
lighting requirements.Figure B.5.3.ll provides a
flowchart of this module.
B-5-33
851104
(vii)Peak Demand Module (*)
The Peak Demand Module forecasts the annual peak
demand for electricity.The annual peak load
factors were based on an analysis of historical
Railbelt load patterns •.A two-stage approach using
load factors is used.The unadjusted residential and
business consumption,miscellaneous consumption,plus
load factors are used to forecast preliminary peak
demand.Separate estimates of peak demand for major
industrial loads are then added to compute annual
peak demand for each load center.Figure B.5.3.12
provides a flowchart of this module.
(viii)Input Data (*)
There are five input data files to the RED model.
One of the five,CONSER,which contains data on
program-induced conservation,was not used in this
project.The other four are described as follows.
The RDDATA file contains output data of the MAP
model,including load center population,households,
and employment,plus state households by age group.
The file also contains the real prices (in 1980
dollars)of fuel oil and natural gas,by load center
and end-use sector.
The RATE DAT file contains the real prices of elec-
.t:.:t:'i.~:i.ty ..by-I_Qild .~ellt_exandend ..usesec tor._These
prices are derived from present costs of electricity
adjusted to future conditions based on the OGP
results.
The PARAMETER file contains the numerical values for
certain parameters,incl uding housing demand
coefficients;saturation rate of electrical
appliances;floors pace elasticities;short-t.erm and
tong-;;;.-term'own.;;;,;price-,iindcro ss-;;;';price-eTast fcTEres for'
·_·---,-e-l'e-c·tri-crty-,-fue-r-o'i-l--;-atla-n:~ftur-a-l ga sT-and-ann u~n-
load factors.
The EXTRA DAT file contains information on the annua 1
electrical consumption and peak demand of large
industrial projects.
ex)RED Model Output (*)
The RED output report contains various tables
generated by the program.The main tables include
the following:
B-5-34
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II
o Number of households for each load center,
forecast year (1980,1985,and at five-year
intervals to 2010),and type of housing (single
family,multifamily,duplex,and mobile homes)
o Residential appliance saturations for each load
center,forecast year,and type of housing
o Residential use per household before price
elasticity adjustments for each load center,
forecast year,and appliance category (small
appliance)large appliance,and space heat)
o Business use per employee before price
elasticity adjustments,for each load center
and forecast year
o Electric energy requirements,including price
adjustments,for each load center,year,and
category of consumption.·(residential,business,
miscellaneous,incremental conservation
savings,large industrial,and total)
o Peak electric requirements for each load center
and year
Output from the RED model is used as input in the OGP
computer model for the purposes of analyzing
alternative expansion programs.
(e)Optimized Generation Planning (OGP)Model (*)
The OGP program was developed over 20 years ago by General
Electric Company (GE)for two reasons.First,to combine
the three main elements of generation expansion planning
(system reliability,operating costs,and investment costs),
and second,to automate the decision analysis for additions
to the generating system.The following description of the
model was extracted from GE literature and the Descriptive
Handbook (GE 1983).
The first task in selecting the generating capacity to
install in a future year is the reliability evaluation.The
evaluation uses either percent installed reserves or
loss-of-Ioad probability (LOLP)to answer the questions of
how much capacity to add and when it should be installed.A
production costing simulation is also done to determine the
operating costs for the generating system with the given
unit additions.Finally,an investment cost analysis of the
capital costs of the unit additions is performed.The
851104 B-5-35
851104
operating and investment costs help to answer the question
of what kind of generation to add to the system.-Figure
B.5.3.l3 outlines the procedure used by OGP to determine an
optimum generation expansion plan.
The next three sections (reliability evaluation,production
simulation,and investment costing)review the elements of
these computations.The OGP optimization procedure is then
described,followed by a discussion of the input and output
files.
(i)Reliability Evaluation (*)
Historically,electric utility system planners
measured generation system reliability with a
percent reserves index.This planning design
criterion compared the total installed generating
capacity to the annual peak load demand.However,
this approach proved to be a relatively insensitive
indicator of system reliabib~ty,particularly when
comparing alternative units whose size and forced
outage rate-varied..
Since its introduction in 1946,the measure that has
gradually gained widest acceptance in the inqustry is
"loss-of-load probability"(LOLP).The LOLP method
is a probabilistic de-termination of the expected
number of days per year on which the demand exceeds
.the~-avai-lable-Ga-paGit-Y-·cL~~It:~factorsintothe-
reliability calculation the forced and planned outage
rates of the units on the system as well as their
sizes.An LOLP of 1 da.y illl0 years a usual
industry standard.
Computing LOLP requires an identification of all
outage events possible (in a system with n units,
this means 2n events)and then a determination of"""Ehepr-obabTi":lty-of each-ouEag-ee-venE:-"However,··sInc-e
-LOLP-rs concerned-wrEnsys tem ca pad ty-outages-and---
not so much with particular unit outages,the
probability of a given total amount of capacity on
outage is calculated.
Utilizing a highly efficient recursive computer
technique ,capacityoutage--tables are -calculated
.directly ...from a.list of__JJll_:iJ:rcktings __cmd forced
oi.ifagera te s.
The LOLP for a particular hour is calculated based on
the demand and installed capacity for the hour.The
B-5-36
,I[;
reserves are given by capacity minus demand.On this
basis,a deficiency in available capacity CLe.,loss
of load)occurs if the capacity on forced outage
exceeds the reserves.The probability of this
happening is read directly from the cumulative outage
table and is the LOLP for a single hour.
In addition to calculating the percent installed
reserves,OGP can also calculate a daily LOLP
(days/year).The daily LOLP is determined by summing
the probabilities of not meeting the peak demand for
each weekday in the year.The hourly LOLP is
calculated by summing the probabilities of not
meeting the load for all the hours in the year.
(ii)Production Simulation (*)
Once a system with sufficient generating capacity has
been determined by the reliability evaluation,the
fuel and related operating and maintenance (O&M)
costs of the system must be calculated.OGP doe.s
this by an hourly simulation of a typical weekday and
weekend day for each month of system operation.
The program commits and dispatches generation so as
to minimize costs.However,the -user has the option
of biasing or overriding the normal economic
operation of the system.This can be accomplished in
two ways.The user may specify weighting factors for
various environmental parameters such that the
program will operate those units to minimize their
impact.The user may also limit,on a monthly basis,
the number of hours that units may run or the amounts
of different fuels that may be consumed.
The production simulation in OGP is performed in six
steps:
o Load modification based on recognition of
contructual purchases and sales;
o Conventional hydro scheduling and its
associated load modification;
o Monthly thermal unit maintenance scheduling
based on planned outage rates;
o Pumped storage hydro or other energy storage
scheduling;
851104 B-5-37
o Thermal unit commitrilentfor the rema~n~ng loads
based on economics and/or environmental
factors,spinning reserve rules,and unit
cycling capabilities;and
o Unit dispatch based on incremental production
costs and environmental emissions.The
production simulation is for a single utility
system or pool.Unrestrained power transfer
capability is assumed between areas or
companies internal to the pool represented.
(iii)Purchases and Sales (*)
The OGP production cost lo·ad model is an hour-by-hour
model of a typical weekday and weekend day for each
month,arranged in monotonically decrea'sing order.
These hourly loads are modified to reflect the firm
purchases and sales between the area being studied
and entities outside that area.Each contract has
associated with it a demand charge ($/kW/yr)and an
energy "'charge ($!kWh);,
(iv)Conventional Hydro Scheduling (*)
-]
I.
(v)Thermal Unit Maintenance (*)
.-------_._------_._-_._--_...-----._----------'----
851104
The power and energy availabl~from any conventional
hydroelectric project used in a simulation is
divided into two types:base load and peak load.The
basec l'oadenergythatmust beccproducedis account-ed
for by subtracting a constant capacity from every
hourly ~oad in the month as shown on Figure
B.5.3.14.This capacity value is referred to as the
plant minimum rating.A£terthis baseload energy is
used,any remaining energy available is used for peak
shaving.I.n such si tuations,the program uses the
remaining capacity and energy of the hydro unit to
-.J:'e.c:l.uc_ELthe .p-~JlltlQ~4~g~.~_l,ll;_1:l_g~_p()_~Sl ~'l>l§!-,,_!.t~llY
excess energy exists at the end of a month,a
user-specifi-ed maximUJiJ.storage amount can be-carifeci'
forward into the next month.
On a utility system,the planned maintenance of
iridi'ifiduaT -iiiiipr is--usually'performed oll a monthly
basis.During these periods,the units are
unavai.1a bie .fo-retle-rgy procltic Hon.Maintenance
scheduling is normally done so as to minimize the
effect on both system reliability and system
operating costs.A common strategy for scheduling
B-5-38
I
)
)
Ij
maintenance,and the method used in OGP,is the
levelized reserves approach.The monthly peak loads
are examined throughout the year,and incremental
amounts of generating capacity maintenance are
scheduled to try to levelize the peak load plus
capacity on maintenance throughout the year.
Increased maintenance levels which might be required
during the first few years of a unit's operation are
modeled using an immaturity multiplier.OGP also
allows the user to annually input a predetermined
maintenance schedule for units for which this
information is available.
(vi)Thermal Unit Commitment (*)
After modifications for contracts,hydro,unit
maintenance~Land energy storage,the remaining
loads must be served by the thermal units on the
system.In OGP,the units can be committed to
minimize either the operating costs,as is usually
done,or some combination of user specified
environmental factors and operating costs.The
operating costs are calculated from the fuel and
variable O&M costs and input-output curve for each
unit.Fixed O&M costs do not affect the order in
which units are committed,but are included in the
total p~oduction cost.
The unit commitment logic determines how many units
will be on-line each hour and also attempts to
provide an adequate level of operating reliability
while minimizing the system operating costs and/or
environmental emissions.The operating reliability
requirement is met by committing sufficient
generation to meet the load plus a user specified
spinning reserve margin.Units are committed in
order of their full load energy costs or emissions,
starting with the least expensive.
851104
(vii)Thermal Unit Dispatch (*)
If a unit is committed,the unit's m~nunum loading
level requires that its output be at that level or
higher.When the final commitment has been
established,each unit will be loaded to at least its
minimum.Typically the sum of the minimums does not
equal the load.Additional load will be served by
the units'incremental loading sections.The
dispatching function in the OGP production
B-5-39
851104
simulation loads the incremental sections of the
units committed in a manner which serves the demand
at minimum system fuel cost or emissions.This
dispatch technique is known as the equal incremental
cost approach.
(viii)Investment Costing (*)
The investment cost analysis in OGP calculates the
annual carrying charges for each generating unit
added to the system.This is computed based on a
$/kW installed cost,a kW nameplate rating,and an
annual levelized fixed charge rate.
(ix)OGP Optimization Procedure (*)
For the year under study,a reliability·eval.uation
is performed.This determines the need for
additional generating capacity.If the capacity is
sufficient,the program calculates the annual
production and investment costs,prints these values,
andproceeds ...to the next ..year •.
If additional capacity is needed,the program will
add units from a list of available additions until
the reliability index is ~et.For each combination
of units added to the system,OGP does a production
simulation and investment cost calculation for the
y-earunder s ..tudy.The....program~mLest ..he.....iJ;li9~J;J!I.a~i9 n
.gained from the cost calculations to logically step
through the different combinations of units to add,
eliminating from consideration comQinations that
'would produce higher annual costs than previously
found.This process continues until the expansion
giving the lowest annual costs is found.The
selected ~hits are added to the system,and the
proceeds to the next year of the study •
........
·-In-cas~e~s~..'tYh-e-r·e(:fJ:ferift·in·g~c·o·s·t-i:n·f·la·ti:on·-and-lor--time-·
variation in unit outage rates are present,the OGP
optimization logic utilizes a look-ahead feature.
The look-ahead feature develops levelized fuel and
O&M costs and applicable outage rates for use in the
economic evaluation.As part of the output informa-
·..tion·available:;theuserobtainsdocumentation of the·
relative costs of a.ll the alternatives examined.
Afterthe"generating unit selection,the reliability
and costing calculations are repeated for the chosen
alternative so that the expansion report available
for the user contains the correct annual values.
B-5-40
.1
851104
(x)Input Data (*)
There are two major input files to OGP:the
Generation file and the Load file.The Generation
file model is created for use as a data base
representing the in-service and on-order generating
units.For each unit,the following characteristics
are described:
o Types of Generator
o Unit sizes and earliest service year allowable
0 Unit costs
0 Fuel types and costs
0 Operation and maintenance costs...,
0 Heat rates
0 Commitment minimum uptime rule
0 Forced outage rates
0 Planned outage rates
The Load file is specified by the user to represent
peak and shape characteristics which are projected to
occur for the years included in the OGP study.The
user supplies the following load shape data:
o Annual peak and energy demand
o Month/annual ratios
o The 0 percent,20 percent,40 percent,and 100
percent points on the peak load duration curve,
by month
o Typical reference weekday and weekend-day
hourly ratios by month
In addition to these two input f~les,the user uses
the Data Preparation (DP)program and the Generation
Planning (GP)program to run the OGP model.The DP
program produces standard tables which describe the
thermal and hydro options.Included are tables for
plant capital,O&M,and fuel costs;inflation
patterns,planned and forced outage rates;minimum
B-5-41
851104
loading points;and environmental data.The GP
program includes input data on loss of load
probability criteria,hydro firm energy,economic
parameters,and output options.
(xi)Output Data (*)
Output options have been designed and included in OGP
to provide the user with flexibility in the level
of detail and volume of documentation received.
Complete output reports as well as summary outputs
are available.
The output available from the OGP program includes
the following info.rmation:
o Listing of the input data
o Standard tables,as defined by the user,for
various unit characteristics
o Listitlg ofth~lltl:i..t types and sizes available
for optimization and their characteristics
o Listing of the Load file for the study period
o Listing of the generating units o~the system
and their characteristics
o Year-by:-year summary 0 the fIrm contracts
input by the user
o Production simulation summaries,listing all of
the generating units of the system with their
energy output,fuel and O&M costs,fuel
consumption,and ~nvironmental emissions.
These summaries can be obtained on a monthly or
annual basis:;'for all"the decision pass esor
....~..-·~"j'ust~·t·he'opt'imum-~sys·tem------~"--·-"-'-'--..~---~~
o Summary of all the expansion alternatives,with
their associated costs and reliability
measures,evaluated during the optimization
oS.ummaries,of thefinaLsys tem expans ion through
time and the associated costs
B-5-42
!
]
.1
5.3.2 -Model Validation (*)
The APR,MAP,and RED models are used to simulate future
conditions based on alternative assumptions concerning world
and state economic conditions and electricity demand in the
Railbelt.Mea~ures that have been taken to ensure that the
models simulate economic and electricity utilization conditions
and relationships as accurately as possible are summarized below.
(a)APR Model Validation (***)
As noted earlier,the APR model is a simplified,
deterministic version of the Alaska Department of
Revenue's probabilistic PETREV model.To test the ability
of the APR model to reproduce PETREV's results,both results
were compared for the March 1985 mean petroleum revenue
case.The APR forecast performed as follows for the 17 year
PETREV forecast period:
Maximum underestimate
Maximum overestimate·"
Average difference
:0.1.6%
2.0%
0.9%
(b)
851104
The PETREV model is used..by ADOR to produce a probabil ity
distribution of new revenue forecasts each quarter.Table
B.5.3~1 -illustrates how the range and mean for FY1985 total
revenues have varied since the September 1983 forecast.
Each successive forecast becomes increasingly more reliable
as the forecast period draws nearer,reflecting the
increasing reliability of the data used in the model.The
curr~nt model formulation has not been in use long enough to
estimate its long term accuracy.
MAP Model Validation (0)
Validation of the MAP model has been accomplished using two
separate but interrelated techniques.First,a standard
set of statistics was computed for each of the stochastic
parameters used in the MAP model equations.These
statistics provide information on the expected accuracy of
each coefficient and the probability that each coefficient
expresses the correct relationship between variables •.
Second,the MAP Model was tested to determine the accuracy
with which it could simulate observed historical
conditions.
(i)Stochastic Parameter Tests (*)
Stochastic parameters are,as indicated previously,
coefficients computed using regression analysis,a
B-5-43
statistical procedure whereby the quantitative
relationship between variables is estimated by one or
more computed coefficients.
Most of the equations in the economic module of the
statewide economic model are computed using
regression analysis.
In estimating coefficients using regression analysis
a number of statistics are computed.These
statistics indicate the accuracy of the coefficient
and the overall efficiency of the equation in
estimating the true value of the dependent variable.
Among these statistics are t-values,R2,
Durbin-Watson statistic,and the standard error of
regression.They are used both in selecting the best
independent variables for estimating a given
dependent variable and in determining the expected
accuracy of the final equation.
These statistics have been computed for each
Sl:_O~bc1istic eqU.;ition tlseci i.J:ll:heMA:p Model.In each
equation efforts have been made to obtain the highest
possible values for these statistics .in order to
ensure that the model re-flects actual economic
relationships as accurately as possible.As a resul~
of this effo-rt all the coefficients used in the MAP
Model have a relatively high level of statistical
(iO Simulation of Historical Economic Conditions (*)
Although the MAP Model has 'been in use since 1975,
analyses condueted for the Susitna Hydroelectric
Project were the first applications of the model in
long range projection of economiccoJ:lditions.
Previous applications of the model had been in
--analys-es-e>f-ece>nomicef-fe e-ts --ofalt-ernative-s-tate ..'..-."--.
-..----.----------------npol-i-ci-es-.--Ii:-i-s-not--pos-si-b-le-,-there-fore,---to--tes-t
the model's long-term projection accuracy using old
forecasts.However,the model's accuracy was tested
by simulating historical economic conditions by
executing the model utilizing historical data and
input variables.Table B.5.3.2 summarizes the
results of simulation of selected.historical
conditions.The table shows that the MAP Model
reproducesh-i-stol:'-iccil--condit-ions -with remarkable
accuracy,in a period when significant growth and
structural change occurred.The model's performance
is acceptable for periods showing markedly different
.j
I
851104 B-5-44
growth characteristics,such as during pipeline
construction and during both pre-and post-pipeline
development.
(c)RED Model Validation (**)
The accuracy of the RED Model was assessed by utilizing the
MAP model's historical simulation of employment,popula-
tion,and numbers of households;actual historical heating
degree days;and actual historical energy prices to predict
electricity consumption by sector and load center.The MAP
historical simulation was considered superior to actual
employment and population statistics because the actual
series contain random and short-term disturbances that have
little to do with planning and developing stocks of
energy-using capital equipment.In addition,the model was
run and adjustments were made using the best e'stimates of
1980 through 1983 economic drivers and fuel prices.Table
B.5.3.3 summarizes the results of comparing the SHCA case
with actual utility data for 1980 through 1983.The ,.m
historical period used in the analysis was brief because of
the lack of available data for the end-use forecasting
model.Complete historical data on end-use (fuel mode
split,appliance saturation,end-use energy consumption,
etc.)are only available for 1980.Therefore,the accuracy
tests which can be performed on the model are limited.
Even though the RED model is a long-term forecas ting model
which uses 5-year interval inputs,it produces forecasts
that are fairly close to actual values in the short term.
When the forecast is adjusted for weather conditions and
price changes,the Anchorage-Cook Inlet residential and
business sectors and the Fairbanks-Tanana Valley business
sector closely match the actual values for consumption in
most years.The Fairbanks-Tanana Valley residential sector
is 15 to 20 percent high in all years but 1980.The
probable cause is that existing electric heating equipment
is not being utilized;rather,wood is being used to provide
much of the heat in the area's residential sector.In
Battelle-Northwest's residential survey (described in
Scott,King and Moe 1985),wood was listed as an alternative
heat source in 53.5 percent of dwellings ha.ving only one
alternative and as the primary fuel in 16.3 percent of all
homes.
The other difference is that Fairbanks-Tanana Valley
forecasted business consumption is growing faster than its
actual value as shown in Table B.5.3.3.This is partly due
to the fact that,until recently,square footage per
employee had been growing slowly to absorb the post-pipeline
851104 B-5-45
building stock.Fairbanks square footage per employee may
soon increase again in response to a downtown redevelopment
plan involving major hotel and convention facilities.
5.4 -Forecast of Electric Power Demand (**)
Two companion load forecasts,plus a third sensitivity case,have been
produced following the methodology discussed in Section 5.3.This
section discusses the three forecasts.First,there is a discussion of
the data input to the APR,MAP,RED,and OGP models for the two
companion forecasts.This is followed by a detailed presentation of
the two companion forecasts and a briefer discussion of the third
sensitivity forecast.Next,there is a discussion of the many
sensitivity tests performed to estimate the impact of various input
assumptions on model output.Finally,there is a brief discussion of
other load forecasts and their relationship to the Susitna project
studies.
5.4.1 -Variables and Assumptions (**)
Many variables and assumptions are used in the..APR,MAP,RED,and
OGP models etescribed.in Section 5.3 •....Inpuj:variables for each of
these models are discussed in the following paragraphs.
(a)APR Model (**)
State petroleum revenues from North Slope oil-production are
expected to account annually for between 93 and 99 percent
~...of s ta te .J>etroleum_~royalties an_(Lp-roductionl;c9..xe~<!l,g:j.!1cg the
period 1985 to 2012.Remaining royal ties and production
taxes will be generated by petroleum production on state
lands in Cook Inlet and from production of natural gas on
the North Slope and Cook Inlet.The input to the APR model
is therefore focused primarily on North Slope oil,and
secondari lyon Cook Inlet oil,North Slope gas,and Cook
Inlet gas •
.-.···-As--sta-te-d-in Si?H:tion-S;3-;-theint>uttoth·e·APR-tnodelts
.----~---.._.-..-.~-~-.taken-direc-t-ly-from-the-kla-ska~Depa-rtment-o-f-Revenue-'-s--.------.-.-..
PETREV model except for two variables:world oil price and
Cook Inlet gas price.Three forecasts of petroleum revenue
have been prepared,each associated with a different world
oil price forecast and its companion gas price forecast.
The three oil price cases include forecasts made by Sherman
H.Clark Associates (SHCA)and Wharton Econometrics,as well
as a Composite cas.e representing the average forecast of
----several--ptibl--ic agencies and private forecasting
organizations.This discussion focuses on the SHCA and
Composi te cases.All three oil price forecasts are shown on
Table B.5.4.l and in Figure B.5.4.l.A detailed discussion
.]
j
._j~.~
I
1
851104 B-5-46
of the forecasts appears in Exhibit D,Appendix D1.
Other input to the APR model for the SHCA and composite
cases are shown on Table B.5.4.2.Of the factors listed on
Table B.5.4.2,North Slope petrolemn production has the
largest potential impact on state petrolemn revenues.
Projected North Slope petrolemn prod~ction is the smn of
projected production from several fields:Prudhoe
Bay-Sadlerochit,Kuparuk,Milne Point,Endicott,Lisburne,
West Sak Sands,Seal Island,and unspecified onshore fields.
Currently only Prudhoe Bay-Sadlerochit and Kuparuk are
producing fields.The other fields are projected to begin
production between 1986 and 1997.The currently producing
fields are projected to remain the main producers,
accounting for 72 percent of total North Slope production in
2000 and 79 percent in 2010.
While production rates during the next eight to ten years
can be fOl:1ecasted with some degree of certainty,production
rates after this period will depend on the rate of
exploration and development of oil fields.Exploration
rates will depend largely on the level of world petrolemn
prices and the demand for petrolemn,but development of oil
fields will depend on oil discoveries and production costs
as well as petrolemn prices and demand.
(b)MAP Model (*)
Table B.5.4.3 lists ten categories of exogenous or basic
employment,one measure of tourism,five categories of
II )1·petrolemn revenues,and four national economic parameters
that are used as input to the MAP model.These factors are
the principal input variables and parameters to the MAP
Model.
For the current studies,the values of all the variables
listed in Table B.5.4.3 other than petrolemn production tax
and royalty revenues were left unchanged during each of the
MAP model executions.Sensitivity tests indicated that
varying the value of several of these factors produced
demonstrable effects on economic projections.Based on
results of sensitivity tests,the key input factors to the
MAP model other than petrolemn revenues are:state mining
employment,which includes petrolemn production;state
active duty military employment;tourists visiting Alaska;
U.S.real wage growth rate;and price level growth rate.
Employment relating to construction of the Susitna
Hydroelectric Project was not included in the analysis.
Construction employment for electric power generating
stations that would be required in the absence of the
851104 B-5-47
project is included in the larger category of construction
employment.
Table B.5.4.4 summarizes the basis for selecting the values
for the variables listed in Table B.5.4.3.The values for
many of the variables listed have been developed from the
MAP model Data Base (Goldsmith et al.1985),a volume of
economic and demographic data compiled and maintained by the
Institute of Social and Economic Research.These data are
derived from information collected by various state and
federal governmental agencies,published reports,and other
sources.The data are organized,adjusted,and in the case
of some variables,projected to the year 2010 to meet the
input requirements of the MAP model.
(c)RED Model (*)
Table'B.5.4.5 lists the main variables that are used in
each module of the RED model.In the Uncertainty module,
the fuel price forecasts,the housing demand coefficients,
the saturation of residential appliances,and the price
adj ustmerit~coefficiei::l.tsarethemaiIfvatiables.
Tables B.5.4.6 and B.5.4.7 show the projected customer real
prices of heating fuel oil,natural gas,and electricity for
the SHCA and Composite cases,respectively.The heating
fuel oil price forecast was derived from the 1983 actual
price,escalated at the same growth rate as the world oil
---~--~-~p-rt-ce~i:ll-~fat:h---ca;-se-FThe--tta~turCa-l-ga~s~pri-:'c'e~~foreca-st·for the-
Anchorage-Cook Inlet area was derived from average price
(old and new contracts)of natural gas.The new contract
prices were estimated as a function of the world oil price.
In the Fairbanks-Tanana Valley area,a continuation of the
present practice of using propane for heating was assumed.
The price escalates with world oil prices.Retail
electricity prices were calculated as a function of the
.1evelized_production ...cost.sforeach_~ca.se._.~.Theproduction_~
___~costs were estimated by-earlier OGP resultslQL~he_l!am~
cases.All fuel prices shown in Tables B.5.4.6 and
B.5.4.7 are expressed in 1980 dollars,the base year used in
the RED model.
Table B.5.4.8 presents the housing demand coefficients which
were used in the housing demand equations for single family,
-'-~"-'-murHfami1Y,-arid mobile~J:iom~S.TableB.5~4~9 gives ari
~:lC.anlPl~••1:)ftna:t:'kel:•.sa tt1l:'~l:~Ql!~()~=appl~.9.l!c~l;:il!..•s ing!efam i~y
homes for the Anchorage-Cook Inlet area,and Table B.5.4.10
presents the parameter values of the price adjustment
mechanism.
'1
'~'.''"1
,j
851104 B-5-48
,J
851104
(d)
For the Housing module,the two main variables are the
regional household forecast,and the state households by age
group.These variables are directly obtained from the MAP
output file.
The main variables in the Residential module include
households by dwelling type and various appliance
characteristics.Tables B.5.4.ll,B.5.4.l2,and B.5.4.l3
provide detailed information on the percent of appliances
using electricity,the annual consumption and growth rate of
residential appliances,as well as the survival rate of the
existing and new appliances.
The main variables of the Business Consumption module are
regional employment,which is an output of the MAP model,
and the floors pace consumption parameters listed on Table
B.5.4.l4.Vacant housing,second homes and street lighting,
and their expected annual consumptian are the variables of
the Miscellaneous module.The ann~l load factor for the
two load centers are the main variables of the Peak Demand
module.
Of the many variables included in the RED model,several can
be identified as key variables.Because the RED model is an
end-use model,the appliance saturation rate based on the
existing stock of appliances is important.Also,the energy
usage per appliance has a major effect on electricity
demand.Further,the growth rate of consumption per
appliance type has a significant impact on residential
electricity consumption in future years.In the business
sector,the projections of the demand for floorspace and the
consumption per unit of floorspace are key variables.Own-
and cross-price elasticities of demand have a significant
impact on electricity consumption by influencing consumption
behavior in both the short and long term.The own-price
elasticity values that are assumed in the model determine
the extent and time path of electricity price impacts on
residential and commercial consumption.The cross-price
elasticities show the impact on electricity consumption due
to changes in the price of substitute energy resources for
electricity.The own-and cross-price elasticities of
demand are used to adjust electricity consumption for
price-induced conservation of electrical energy.The last
key factor is the regional peak load factor,which is
applied to the energy demand forecast to forecast peak
loads.
OGP Model (0)
Table B.5.4.15 presents the main variables of the OGP model.
The variables are:fuel costs and escalation rates,
B-5-49
thermal and hydro plant construction costs,and the discount
rate.A detailed presentation of these variables -is given
in Exhibit D and Exhibit D,Appendix D1.
5.4.2 -Load Forecasts (**)
A total of three load forecasts were made.Two are discussed
here,while the third --a low bound sensitivity case --is
presented in Section 5.4.3.The two cases presented here are
associated with the two petroleum price forecasts discussed
earlier,Le.,the SHCA and composite cases.
As described in Section 5.4.1,the petroleum prices served as the
basis for the state petroleum revenue forecasts,which in turn
comprised one of the inputs to the MAP model.The MAP model
produced economic projections which were then used by the RED
model to forecast electric energy demands.
Tables B.5.4.16 and B.5.4.17 summarize the data for the SHCA and
Composite cases,showing the oil price scenarios and a
corresponding set of input and output prices of other forms of
energy,revenues,population,and employment.Table B.5.4.16
shows that in the SHCA case,Railbelt population will grow
approximately 33 percent between 1985 and 2010,reaching 506,384
by the year 2010.During this same period the Railbelt's
electric energy demand is forecasted to rise from 3,323 to 4,929
gigawatt-hours,a 48 percent increase.Peak demand is projected
to rise from 632 to 938 megawatts,a 48 percent increase during
the--25-;1-ear_period~-and....-an~-a:v:erage-annual--grow~th~rateoLl.6
percent.Similarly,Table B.5.4.17 indicates that under
Composite case assumptions,Railbelt population would be expected
to grow by 32 percent by the year 2010.During the same period,
the Railbelt's electric energy demand would rise to 4888
gigawatt~hours,a 47 percent increase.Peak demand is projected
to rise to 930 megawatts.
The following sections summarize the SHCA and Composite case...----.-,.,-"".,---------"'--fo'r'ec-~i's-ts--'-o·r'--s-Ea'-te-·-·pe-tr'oI-e"um-""·--reveiiue-s·-~···--"·f-is-c-a-l·-'·-'and--e-c·c)"ti()TQlc·
con at-t-ions,anaelectric energy aemand-.-Decailed--illput-ana-
output values for both cases appear in Tables B.5.4.18 through
B.5.4.43.
(a)State Petroleum Revenues (**)
--c_.Table B.5.4-.18 presents SHCAcase-projections of state
petroleum revenues from each of the prima-ry revenue
sources through the year 2010~The first two columns ()f
this table contain projected royalties and severance,or
production,taxes,respectively.These projections are in
nominal dollars,reflecting an annual change in the
J
J
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851104 B-5-50
consumer price index of 5.5 percent.The projections of
royalties and severance taxes through the year 2010 were
produced by the Department of Revenue's APR petroleum
revenue forecasting model.The same revenue information for
the Composite case appears on Table B.5.4.19.
Tables B.5.4.18 and B.5.4.19 also present projections of
state petroleum revenues derived from corporate income
taxes,property taxes,lease bonuses,and federal shared
royalties.Forecasts of future revenues from these sources
were used,along with the projections of royalties and
severance taxes,as input to the MAP economic model.
In nominal terms,as indicated on Tables B.5.4.18 and
B.5.4.19,petroleum revenue is expected to rise-and fall in
cycles over the forecast period.In real terms,however,
petroleum revenue is expected to fall continuously after
1987.In the SHCA case,real petroleum revenue is forecast
to decline by 71 percent between 1987 and 2010,while
contributions to the general fund (net of permanent fund
contributions)fall by 73 percent during the same period.
In the Composite case,total petroleum revenue and
contributions to the general fund are forecast to fall by 74
percent and 76 _.percent,respectively.
(b)Fiscal and Economic Conditions (**)
State petroleum revenues constitute a major,but declining,
portion of the.total funds available to the State of
Alaska for expenditure on operations and capital investment,
which in turn affects the general level of economic activity
in the state.The impact on economic activity,however,is
not directly proportional to the decline in petroleum
revenue.Basic sector economic activity is expected to
continue to expand as it has in the past.This growth will
include--in varying degrees--all of Alaska's resources but
would continue to be dominated by petroleum and mining.
Federal civilian and tourism employment will grow;although
mi Ii tary employment will continue its secular decl ine.
Manufacturing employment will be minimal.
This continuing,but gradual,expansion of basic activities
will be the growth trend underlying several indentifiable
phases in the economy in future decades.Four periods can
be characterized as pause,renewed growth,structural
realignment,and the post-Prudhoe economy.
The economy is expected to enter a flat period in the
immediate future as the economy adjusts to lower petroleum
prices as well as the excess capacity produced during the
851104 B-5-51
rapid growth years of the early 1980s.The primary forces
driving the economy-construction,state and local
government,petroleum employment--will stop growing or
contract,causing the economy to pause.This pause in new
job creation will result in net out~igration which will
slow,but not eliminate growth in population and
households.
Toward the end of the decade,economic growth is expected to
resume as oil prices begin to rise and petroleum and mining
activity increase.Activity in the state and local
government sectors will be augmented by new revenue
measures,including reimposition of the income tax and
transfer of Alaska Permanent Fund earnings to the General
Fund for annual appropriations.These measures maintain the
existing employment level in government but are not
sufficient for expansion of government employment.
Toward the end of the century,the decline in petroleum
revenues resultin;g;;;.from the depletion of the Prudhoe Bay
field will become more pronounced,leading to a marked
contraction in state-and local-government-activity,which
will continue through 2010.This is initially a period of
slow growth,marked by a structural realignment of the
economy as the public sector contracts absolutely as well as
in p~rcentage terms.
As this realignment continues,the economy eventually will
---~-enter what--mightbe-character-ized-as-the~post"""l'.rudhoe.-Bay
era.State and local governments are less dominant forces
in the economy,and growth will be more closely related to
private sector basic activities.
During this period,growth in population and the number of
households will be primarily the result of natural increase.
The annual addition of new jobs to the economy will be the
growth in the labor supply resulting in net out-migration in...._..._.---..·--maiiy-ye-~irs-:-B-e-causethe-averag-e--househoTd-sIzewIII----
...·_-·---conEinue its-downwara.treiia-;-tfie growtnin tnenumoero-f-~
households will exceed that of population.The labor force
participation rate will remain high so that the proportion
of the population at work will stay relatively constant.
Table B.5.4.20 presents projections of several important
components·of the state's fiscal structure for the SHCA
case,while TableB.5.4.21 presents the same information for
theCoiiipositecase.These c6iiiponentsincl'ude unrestricted
general fund expenditures,the balance in the general fund,
permanent fund dividends,state personal income tax
revenues,level of outlays for subsidies,and the percentage
851104 B-5-52
of Permanent Fund earnings that are added to the general
fund.Table B.5.4.20 shows that,based on the fis·cal rules
summarized in Section 5.3 above,dividends from the
Permanent Fund continue to be disbursed through the year
1990 in the SHCA case,at which time the program is halted.
A state personal income tax is reinstituted in the year
1992 in order to augment revenues.State subsidy programs
are terminated after the year 1990,and reinvestment of
Permanent Fund dividends ends after 1992.Table B.S.4.21
indicates that in the Composite case,maintenance of general
fund expenditures requires the same actions,in the same
years,as in the SHCA case.
However,while these fiscal measures are assumed to be
implemented,petroleum revenues are projected to continue to
provide a large share of state expenditures,accounting in
the year 2010 for approximately 42 percent of total
unrestricted general fund expenditures (those expenditures
not funded by revenues dedicated to specific functions)in
the SHCA case.Petroleum revenues constitute ap~roximately
39 percent of unrestricted general fund expenditures in 2010
in the Composite case.
l\
851104
(i)
(ii)
Population (***)
Table B.5.4.22 pr~sents SHCA case population
projections for the state,Rai lbelt"Anchorage-Cook
Inlet area,and Fairbanks-Tanana Valley area.The
state population is forecast to increase by 30
percent.Railbelt population is projected to grow by
approximately 33 percent between 1985,from 381,264
to 506,384.In the Railbelt,the Anchorage area is
projected to grow by 34 percent,compared to the
projected growth in Fairbanks of 27 percent.Table
B.5.4.23 indicates that in the Composite case,growth
rates would be 32,34,and 26 percent in the
Railbelt,Anchorage,and Fairbanks,respectively.
Employment (***)
The growth of employment in the SHCA case is shown on
Table B.5.4.24.While statewide non-agriculture
wage and salary employment is projected to grow by 33
percent during the next 25 years,total state
employment is forecast to increase by only 29
percent.Again the Railbelt is projected to
experience a higher employment increase,rising by 34
percent,with the Anchorage area growing by 35
percent compared to 29 percent growth in the
Fairbanks area.
B-5-53
Table B.5.4.25.Total state employment is forecast
to grow by 29 percent,while Railbelt growth is 33
percent over the same 25 year period.The Anchorage
and Fairbanks areas are forecast to grow by 34 and 29
percent,respectively.-
(iii)Households (***)
Table B.5.4.26 presents household projections for the
SHCA case according to state total,the Railbelt,
the Anchorage area,Fairbanks area,and statewide by
age of head of household.Households are projected
to increase faster than population.Statewide
households are projected to increase by 37 percent by
the year ·.2010,compared to a 39 percent increase in
the Railbelt,a 40 percent rise in the Anchorage
area,and a 34 percent increase in the Fairbanks
area.Household growth in the Composite case is
slightly lower than in the SHCA case,showing 36
percent growth in the state,38 perQent in the
Railbelt,40 percent in the Anchorage area,and 33
percent in the Fairbanks area.The figures are shown
on Table B.5.4.27.
(c)Electric Power Demand (**)
(i)Households Served and Vacant £ouseholds (***)
The-regional households -proJections-obtained from
the MAP model are used in the RED housing module to
derive the number of households served by electric
utilities and the number of vacant households.
Tables B.5.4.28 and B.5.4.29 present the number of
households served in the SHCA and Composite cases,
respectively.Tables B.5.4.30 and B.5.4.31 present
the number of vacant households by case.The
residential module then computes the annualco-nsumptTonper--typeoI ---househoI d·-bas-edon-the ·market·_·
...···saturationof-appriances andt'fi"eannua-l--consumpTion-
per appliance.
(ii)Residential Electricity Use Per Household (***)
Table B.5.4.32 summarizes the average consumption per
..--·householdbefore and-after-conservation adjustment
anCl.-fuel substitution int:heSHCA case.In the
Anclior~rge-area;-the average-consumption per household
is expected to decrease from about 11,700 kWh in 1985
to 10,100 kWh in 2000,mainly due to the real
increase of electricity price which will continue to
I 1
I j
·1
851104 B-5-54
j
851104
cause so~e conversion from electric space heating to
substitute fuels.After 2000,the consumption is
expected to slowly increase to about 10,300 kWh in
2010,at an average annual growth rate of less than
one percent.In the Fairbanks area,the average
household consumption is expected to increase from
12,400 kWh in 1985 to 14,500 kWh in 2010,at an
average annual growth rate of about one percent.
This increase is due to the stabilization of
electricity prices,while the prices of substitute
fuels are increasing.The projected consumption per
household in year 2000 is similar to the 1975 average
consumption.
Table B.5.4.33 summarizes the average consumption per
household in the Composite case.The use per
household is essentially the same as for the SHCA
case.
(iii)Business Use Per Employee (***)
The employment forecasts obtained from MAP are used
in the RED Business Consumption module to derive
the electric demand in the business
(commercial-government-small industrial)sector.
Table B.5.4.34 summarizes the business use ~per
employee projections for the SHCA case.The
consumption projections were obtained from a forecast
of predicted floorspace per employee,and an
econometrically derived electricity consumption per
square foot,which is then adjusted for price
effects.The floorspace per employee is expected to
increase at the Anchorage historical rate until 2010,
bringing square footage per employee close to the
1979 U.s.national average.As a result,in the
Anchorage area,the average consumption per employee
is expected to increase from about 8,700 kWh in 1980
to about 10,000 kWh in 2010,at an average annual
rate of less than one percent.In the Fairbanks
area,the consumption per employee is expected to
increase from about 8,100 kWh in 1980 to 12,000 kWh
in 2010,corresponding to an average annual growth
rate of 1.3 percent.
As indicated in Table B.5.4.35,business electricity
use per employee in the Composite case is expected to
be similar.
Table B.5.4.36 provides a year by year projection of
price-induced conservation and fuel switching for the
B-5-55
851104
two load centers in the SHCA case,while Table
B.5.4.37 provides the same information for ·the
Composite case.Tables B.5.4.38 and B.5.4.39 give a
year by year breakdown of energy consumption
projections for the residential,business
(commercial-government-small industrial),
miscellaneous,and large industrial sectors for the
two load centers for the SHCA case.Tables B.5.4.40
and B.5.4.41 present the composite case.The
industrial sector includes projections of large
industrial and military loads.Industrial loads were
derived from estimates of industrial growth in the
Kenai Peninsula.Military loads were derived from
discussions with representatives at each military
installation.
Finally,Tables B.5.4.42 and B.5.4.43 sunmarize the
annual peak and energy demand projections for each
load center and for the total system for the SHCA and
Composite cases,respectively.In the SHCA case,the
averge annual growth rate of electricity demand is
expected to slowly decrease from about ·1.5 percent
during the period 1985-1990 to 0.6 percent during
the period 1995-2000.After 2000,the demand is
expected to increase at an average annual rate of 1.5
percent.until 2005,and 2.7 percent for the period
2005-2010.In the ComposIte case,the rates of
change are essentially the same.
5.4.3 -Forecast Comparison (***)
In addition to the SHCA and Composite cases,the Wharton case was
carried through the MAP and RED models.The results are
presented on Table B.5.4.44.Projections of population,
households,energy demand,and peak demand are displayed in
Figures B.5.4.2 through B.5.4.5 for all three cases.
As Shawn 'iii ..Figiire"':B ~.5~4:'2~-the"Rairoertpopu ration-is expected
---~to-ill"c-rea-s"e-from-381-;300-in-t98S-to-Lf99-';-200-in····tn.e-Wnartonca s e
and 506,400 in the SHCA case,for the year 2010.The
corresponding number of households,shown in Figure B.5.4.3,
would increase from·134,300 in 1985 to 184,000 or 187,000.
Railbelt employment is expected to increase from 181,900 in 1985
to 240,300 under the Wharton case,and 243,200 in the SHCA case.
As shown onFigureB.5.4.4,the 2010 energy consumption would be
between 4,900 and 5 ;100 GWh in aU-'cases ."The corresponding
average annual growth rate over the period 1985-2010 would be
appJ;oximately 1.7 percent.The peak demand shown in Figure
B-5-56
1
,)
!
}
"1
\)
B.5.4.5,is expected to increase from 630 MW in 1985 to
approximately 950 MW in 2010 in all three cases.
5.4.4 -Sensitivity Analysis (**)
Sensitivity analyses for a number of variables were conducted
using the MAP,RED,and OGP models in order to determine the
extent to which forecasts are affected by varying the values of
selected input variables and parameters.
(a)MAP Model Sensitivity Tests (**)
The Susitna License Application as accepted by FERC in July
1983 (APA 1983)contained a summary of several MAP model
sensitivity tests •.At that time,input variables subjected
to sensitivity testing included ten industrial development
factors,tourism in Alaska,and four national economic
variables,as well as a number of other parameters not
reported in the License Application.The results indicated
that of the variables tested,projections of households are
most sensitive to mining employment,which includes
petroleum production;military employment;tourism;growth
in real wages;and growth in the consumer price index.
An additional set of tests was made during the autumn of
1984.The results of these tests are shown on Table
B.5.4.45.The first three tests (TEST 0,1,2)investigated
the effect of adding new and revised data such as updated
population and wage and salary figures to the data base.
Three tests (TESTS 3,3S,4)were undertaken to assess the
sensitivity o~model simulations to the econometric methods
used to estimate the stochastic equation coefficients,and
one test (TEST 5)redefined the form of the relationship
between support industry gross product and income.Three
tests (TEST 6,6R,6T)compared the effects of various
petroleum corporate income tax levels,while one test (TEST
7)holds royalty,severance tax,and petroleum corporate
income taxes constant.One test (TEST 8)assumes very high
levels of petroleum revenues and petroleum employment.One
test (TEST 9)determines the gross effect of Susitna
construction on the state economy (without netting out the
displaced economic activity associated with meeting Railbelt
power demands by some other means).
Additionally,three tests (CTST lOA,lOB,laD)gauged
simulation sensitivity to varying certain state government
policies,such as increasing the return on the Permanent
Fund balance from 3 to 4 percent,combining no
reintroduction of the income tax with perpetuation of the
851104 B-5-57
permanent fund dividend,and permanent elimination of the
income tax alone.
One test (CTST 11)examined the combined effects on
households of a decline in the labor force participation
rate and a related change in average household size.
Finally,four tests (TEST 9.82, 9.81,9.80,9.79)were made
to determine how sensitive the support sector equations are
to the extension of data series to termination points in
1982, 1981,1980,and 1979.
The results indicate that the forecast of households is most
sensitive to 1)high exogenous estimates of
petroleum-related employment,and 2)a declining labor force
participation rate accompanied by a declining average
household size.The latter effect is large because changes
in labor force participation are usually correlated with
changes in household ~ize,creating more households in a
given population.
(b)RED Model Sensitivity Tests (**)
Sensitivity analyses were conducted for key variables,using
the data files from the Uncertainty Module.These
variables include (1)appliance saturations,(2)business
consumption and the trend in.square feet of business
floorspace per employee,(3)own price eiasticity,(4)cross
price elasticity,(5)the lagged adjustment factor,and (6)
10a~L factors.J'he ..senslt:ivity analyses were~.!:lx:r_l~d.Qut f.Qr
the SHCA Case.The results are shown on Tables B.5.4.45
through B.5.4.49.Although these sensitivity tests were
based on earlie~RED Model runs using prices that are
slightly different,the results are similar to the current
cases.
Table B.5.4.45 summarizes the results obtained when
appliance saturations were allowed to vary.Table B.5.4.9
............._......fffeSrerits-'a"typica le-xanfpIe·'ofmafket'-sfaturat-ioff ·rangeswnich
......--..·-·~----cwere-us·e·d-as--input-·-into-the-Uncertai:ntrModu-l-e-;'."'The-'-
saturations were allowed to vary over their entire range (in
some instances,+10 percent)•.As shown on Table
B.5.4.45,the results on the overall energy demand are
within 1 percent of the test case values •.
.The sensitivity analysis.o.ftheBusinessSector was done by
allowing the consumption rate parameter to vary within a
range 'approximately-corresponding--to 'a95'percent confidence
interval.This resulted ina range of values within +20
percent of tl:lemean value for the Anchorage-Cook Inlet area.
As shown on Table B.5.4.46,the effects on the overall
.1
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.(I,
j
851104 B-5-58
energy demand are within 20 percent of the test case values.
Because of the lack of detailed historical data for the
Fairbanks area,the range of the consumption parameter value
was set by assumption and the results of the Monte Carlo
test reflect this assumption.
Tables B.5.4.47 and B.5.4.48 present the results of the
own-price and cross-price elasticities variations.The
values of the parameters were allowed to vary within an
assumed range of minus 16 percent to plus 40 percent for own
price elasticity,plus or minus 100 percent for oil price
elasticity,and plus or minus 40 percent for gas price
elasticity.This roughly corresponds to a 95 percent
confidence interval.The effects on the overall energy
demand are within plus 5 percent to minus 2Q percent of the
test case values.
Finally,a sensitivity analysis was done for the peak
demand,using the range of the annual load factors of the
two load centers for the period 1970-1982.The results are
presented in Table B.5.4.49.For the year 2010,the peak
residential plus commercial demand would vary between 925
and 1187 MW,with a test case value of 1030 MW.No range
has been specified for industrial demand;however,the total
2010 ftemand levels that would be forecast with 75 percent
and 25 percent confidence are 1032 MW and 1212 MW,
respectively,compared to the reference value of 1085.
I)
(c)OGP Model Sensitivity Tests (**)
Sensitivity tests were also conducted for the OGP Model.
The key variables other than petroleum price which were
tested are base fuel price,discount rate,Watana
construction cost,real coal price escalation and natural
gas availability.The sensitivity analyses are described ~n
Exhibit D.
5.4.5 -Comparison with Previous Forecasts (**)
Previous power demand forecasts have been used in earlier stages
of the Susitna Hydroelectric Project studies.In 1980,the
Institute for Social and Economic Research (ISER)prepared
economic and accompanying end-use electric energy demand
projections for the Railbelt.These forecasts were used in
several portions of the feasibility study,including the
development selection study.The forecast is shown on Table
B.5.4.50.
In 1981 and 1982,Battelle Pacific Northwest Laboratories
produced a series of load forecasts for the Railbelt.These
forecasts were developed as,a part of the Railbelt Alternatives
851104 B-5-59
Study completed by Bat telle under contract to the State of
Alaska.Battelle's forecasts were based on updated economic
projections prepared by ISER and some revised end-use models
developed by Battelle which took into account price sensitivity
and several other factors not included in the 1980 projections.
The December 1981 Battelle forecast used in the optimization
studies for the Watana and Devil Canyon developments is shown on
Table B.5.4.50.
Another series of load forecasts was made to support the Susitna
License Application as accepted by FERC in 1983 (APA 1983).The
reference case forecast is shown on Table B.5.4.50.The
reference case and other forecasts were made following the same
procedures described in Section 5.3.They reflect an ongoing
process of model refinement,pI us the ..updating of underlying
ecqnomic assumptions.
In addition to the forecasts made for the purpose of.planning the
Susitna Hydroelectric Project,the Railbelt utilities annually
produce fo.reca-sts for their own respective markets.The sum of
the current Railbelt utility forecasts is shown on Table
B.S-.4.50.
Table B.5.4.50 provides a summary comparison of these previous
power market forecasts.While these forecasts are not precisely
consistent in the definitions of the market area or in the
assumptions relating to the current reference c·ase,the
comparison does provide an insight into the change in·perception
.·o·f-...futut'eg-rowthra-t es.dur-ing.-the-"timec.."that--the~vaI'ious--sets of
forecasts were developed.
5.4.6 -Impact of·Oil Prices on Forecasts (**)
The world price of oil is a significant factor in the Alaskan
economy.As a consequence,world oil prices influence the
demand for electric energy and other forms of energy.Although
oil prices are important,there are many other economic,social,'anci""polItTcaT'factors'whIchaffecE·"·fuEur-eAT"iskari'economicErends·.
-and-energy req uirement"5':~-----...--'.--------.-.----.--------..---..----..--..--..--------
Among the factors which mitigate the impact of declining oil
prices on the level of economic activity in Alaska are the
following:
o'.Other basic industries-,--unre-latedctopetroleum,exist
independent of the oil industry in'Alaska and will continue
to d6 56.
o The presence of the petroleum industry in Alaska has
already transformed the Alaska economy,creating an
851104 B-5-60
,I
)
./
J
l.1
infrastructure and a degree of economic maturity that would
not be undone if the oil industry declines in importance.
o The current level of petroleum producing activity in the
state is relatively insensitive to oil price changes within
a wide range,because continued operation of existing
fields requires only sufficient revenue to cover low field
operating costs.(Lower petroleum prices do,however,have
a more dramatic impact on exploration and development of
new fields).
o Diversion of a portion of past petroleum revenue into the
State's Permanent Fund,plus reinvestment of Permanent Fund
interest,has provided the state with a cushion against
falling petroleum revenues in the future.Interest on the
Permanent Fund could be channeled into the General Fund (as
is assumed in the MAP model)to help maintain the level of
operating and capital expenditures.
The impact of world oil prices on future.eco,nomic conditions and
electric energy and peak demands can therefore best be understood
by reviewing the load forecasting procedure.First,a number of
world oil price scenarios were used in the APR Model to generate
various petroleum revenue projections.Because royalties and
severance taxes are sens.itive to changes in world oil prices,
different petroleum 'revenue projections were obtained.Next,the
projected petroleum revenues along with specified economic
development assumptions and other variables were employed in the
MAP Model to project economic factors such as households,state
government expenditures,and employment.These economic factors
were influenced by the various oil price growth rate assumptions,
but were also influenced by other economic factors which tend to
mitigate the impact of petroleum revenues alone.Finally,
electric demand forecasts were produced using the RED Model.The
RED Model employed the output of the MAP Model as well as other
assumptions and input data.The fuel price data used in the RED
Model for electricity,natural gas,and heating oil are affected
by the growth rates assumed for world oil prices.An electric
demand forecast was made for each world oil price scenario.This
procedure resulted in the production of electric demand forecasts
which incorporated all direct and indirect effects of a given
timepath of world oil prices on electric demand in the Railbelt
in a comprehensive and consistent manner.The ·range of electric
demand forecasts reflects the overall impact of world oil prices
as well as other key variables included in the separate models.
851104 B-5-61
i II.
6 -FUTURE SUSITNA BASIN DEVELOPMENT (*)
Development of the proposed Susitna Hydroelectric Project would
preclude further major hydroelectric development in the Susitna
basin,with the exception of major storage projects in the Susitna
basin headwaters.Although these types of plans have been considered
in the past,they are neither active nor anticipated to be so in the
foreseeable future.
851104 B-6-1
1
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-_.__-------.----_.__.__._---.,-.___.._--_..------__..-_..----_.._._--------___--,-.._---_---_.._---.---------.-----_._-----_-.-.-_.___--_._-..-
J
7 -REFERENCES
Acres American Inc.1981.Susitna Hydroelectric Project,Development
Selection Report.Prepared for the Alaska Power Authority.
•1982a.Susitna Hydroelectric Project,Feasibility Report (7---Volumes).Prepared for the Alaska Power Authority.
•1982b.Susitna Hydroelectric Project,1982 Supplement to the---1980-81 Geotechnical Report.Prepared for the Alaska Power
Authority.
•1982c.Susitna Hydroelectric Project,Subtask 8.02.Closeout---Report.Electrical System Studies.March 1982.
Acres American Inc.and Terrestrial Environmental Specialists Inc.
1982.Transmission Line Selected Rout~.Prepared for the Alaska
Power Authori ty.
Alaska Department of Fish and Game.1978a.Alaska's Fisheries Atlas
(Volumes I and II).Anchorage,Alaska.
•1978b.Habitat Essential for Fish and Wildlife on State Lands.---Anchorage,Alaska.
Alaska Department of Revenue.1985.Petroleum Productio~Revenue
Forecast.Petroleum Revenue Division.
Alaska Economics Inc.1983.Alaska's Economic Potential:Background.
March,1983.
Alaska Power Administration.1984.Alaska Electric Power Statistics
(1960-1983).Ninth Edition.U.S.Department of Energy.Sept.
Alaska Power Authority.1983.Susitna Hydroelectric Project FERC
License Application,Project No.7114-000.
•1985.Susitna Utility Meeting -Results of Sensitivity Analy~is.---June 19,1985.
Battelle Pacific Northwest Laboratories.1981.End Use Survey.
Unpublished report.
•1982.Railbelt Electric Power Alternatives Study (17 Volumes).---Prepared for the Office of the Governor,State of Alaska.
December,1982.
•1983.RED Model (1983 Version)Documentation Report.---
Brown,A.C.1985.The Policeless State of OPEC.Fortune.112(2):52.
851104 B-7-1
Burns and McDonald.1983.Report on Power Requirements Study for
Chugach Electrical Association.
CIRl/Holmes and Narver.1980.Susitna Hydroelectric Project,Subtask
2.04.Land status maps.Prepared for Acres American Inc.
Chow,V.T.1964.Handbook of Applied Hydrology.McGraw-Hill.
Clarke,T.S.1985.Glacier Runoff Balance and Dynamics in the Upper
Susitna River Basin,Alaska.A thesis presented to the University
of Alaska,Fairbanks in partial fulfillment of the requirements
for the degree of Master of Science.
Commonwealth Associates Inc.1980.Anchorage-Fairbanks Transmission
Intertie-Transmission System Data.Prepared for the Alaska Power
Authority.
Data Resources Inc.1983.U.S.Long-Term Review.
Energy Probe.1980.An Evaluation of the ISER Electricity Demand
Forecast.
ExxonCorp.-T984.MiddleEast Oil arid Gas.Public:Affairs Department.
New York,New York.40 pp.
French ,M.1985.Long Term Outlook for Petroleum Prices.Wharton
Econometric Forecasting Associates,Philadelphia,PA.
Friese,N.V.1975.Pre-Authorization Assessment of Anadromous Fish
-.-----POI:lUlaEIons-of-tne-Upper-S-iis-itha·RiverWat:er-snealtfthe-Vicinrty
of the Proposed Devil Canyon Hydroelectric Project.Alaska
Department of Fish and Game ,Divisionof Commercial Fisheries.
General Electric Co.1983.OGP6 User's Manual.March~1983.
Goldsmith,S.and L.Husky.1980.Electric Power Consumption for the
Railbelt - A Projection of Requirements.Prepared for State of
··Alaska,Ho us ePower-Al-terna.tives Study--Committ ee__andAlas ka Power ....
-.-..-------.Author-it¥-.J_une_,__L9SO-.__._.....__
Goldsmith,S.,T.Hull and S.Colt.1985.Monitoring the Performance of
the Alaska Economy:The 1985 ISER MAP Economic Database.Institute
of Social and Economic Research,University of Alaska.April,
1985.
Harrison,W.D.1985.Susitna HydroelectricProject,Glacier Mass
Balance and RunoffStuqy ..JJJ:liyer'si.t:y Qf.A,laI31ta,Fairbanks,
Geophysical Institute.Prepared for Harza-Ebasco Sus tna·Joint
Venture.
i .j
1
·1
.J
851104 B-7-2
lJ
Harza-Ebasco Susitna Joint Venture.1984.Evaluation of Alternative
Flow Requirements.Final Report.Prepared for Alaska Power
Authority,Anchorage,Alaska.55 pp.
Institute of Electrical and Electronics Engineers.1977.symposium on
Reliability Criteria for System Dynamic Performance.IEEE Power
Engineering Society 1977 Winter Meeting.pp.15,34,36.
•1982.Power System Reliability Evaluation.IEEE Tutorial Course.
pp.54,56.
Institute of Social and Economic Research.1980.Electric Power
Consumption for the Rail be 1 t:A Projection of Requirements,
Technical Appendices.Prepared jointly for State of Alaska House
Power Alternatives Study Committee and Alaska Power Authority.
•1981.Alaska Economic Projections for Estimating Requirements for
the Rai1be1t.Prepared for Battelle Pacific Northwest
Laboratories.October,1981.
•1983.MAP'~ode1 Technical Documentation Report.June,1983.
•1985.MAP Modeling System Documentation.Compiled by O.S.
Goldsmith,University of Alaska.
Manne,A.S.and L.Schrattenho1zer.1985.International Energy
Workshop:A Progress Report.
Morrow,J.E.1980.the Freshwater Fishes of Alaska.Alaska Northwest
PubliShing Co.,Anchorage,Alaska.
R &M Consultants Inc.1981a.Terrain Analysis of the North and South
Intertie Power Transmission corridors.Prepared for Acres American
Inc.
•1981b.Susitna Hydroelectric Project,Regional Flood Studies.
Prepared for Acres American Inc.
•1981c.Susitna Hydroelectric Project,Glacier Studies.Prepared
----for Acres American Inc.
•1982a.Susitna Hydroelectric Project,1982 Susitna Basin Glacier
----Studies.Prepared for Acres American Inc.
•1982b.Susitna Hydroelectric Project,Tributary Stability
----Analysis.Prepared for Acres American Inc.
851104 B-7-3
Scott,M.,M.J.King and R.J.Moe.1985.Review and challges to the
Railbelt Electricity Demand Model.Pacific Northwest
Laboratories.
Sebasta,D.1978.Lowering Reliability Offers Little Benefit.
Electrical World.190(7):pp.70-71.
Sherman H.Clark Associates.1983a.Evaluation of World Energy
Developments and Their Economic Significance,Volume II.Prepared
for Harza-Ebasco.
___•1983b.Long-Term Outlook for Crude Oil and Fuel Oil Prices.
Prepared for Harza~Ebasco.
Sherman H.Clark and Associates.1985.Oil Price Outlook.Prepared for
Harza-Ebasco Susitna Joint Venture,Anchorage,Alaska.
Stahr,T.R.1983.Personal communication.General Manager,Municipal
Light and power.Letter to D.Glascock,Harza-Ebasco Susitna Joint
Venture,June 22,1983.
Trihey,E.W.1981.Susitna Hydroelectric Project,Instream Flow
Assessment :Issuefdent:rUcat:ion and Bas-eHne 1jat:aArialysis,1981
Study Plan.Prepared for Acres American Inc.
u.S.Department of Agriculture,Soil Conservation Service.1979.
Exploratory Soil Survey of Alaska.Washington,D.C.
u.S.Army Corps of Engineers.1975.Program Description and User Manual
--fo-rStreamf16wSYntnesis and-I1eservoir Regura:tion CS-SA1nn:U~S-.
Army Corps of Engineers,North Pacific Division.Portland,
Oregon.
Woodward-Clyde Consultants.1980.Forecasting Peak Electrical Demand
for Alaska's Railbelt.Prepared for Acres American Inc.December,
1980.
--.-1982.--Final Report·on-Seismic·--Studies-forSusitnaHydroelectric-------_______Pro.J_ect..Prepared_fOIAc:ies -American.Inc -Eebr_uar.y_,_1.982-.-~-.
-1
]
J
851104 B-7-4
TABLES
l
J
J
1
j
1
j
1
TABLE B.1.3.1:POTENTIAL HYDROELECfRIC DEVELOPMENT
Capital Average Economicl/
Dam Cost Installed Annual Cost of Source
Proposed Hel.gh t Ups tream $million Capacity Energy Energy of
Site Type Ft.Regulation (1980)(MW)GWh $/1000 kWh (1980)Data
Gold Creeld Fill 190 Yes 900 260 1,140 37 USBR 1953
0180n11
(Susitna Up Concrete 160 Yes 600 200 915 31 USBR 1953
KAISER 1974
COE 1975
Devil canyo~Concrete 675 No 830 250 1,420 27 This Study
Yes 1,000 600 2,980 17 "
High Devil t.nyon "(Susitna I)Fill 855 No 1,500 800 3,540 21 "
Devil Creek I Fill Approx No
850
Wa tana I Fill 880 No 1,860 800 3,250 28 "
Sus itna III Fill 670 No 1,390 350 1,580 41 "
Vee I Fill 610 No 1,060 400 1,370 37 "
Maclaren Fill 185 No 530~/55 180 124 "
Denali Fill 230 No 480.1:1 60 245 81 "
Butte Cree I Fill Approx No -40 1303 -USBR 1953
150
Tyonell Fill Approx No -6 22 3 -USBR 1953
60
1/Include AFDC,Insurance,Amortization,and Operation and Maintenance Costs.2/No deta led engineering or energy studies undertaken as part of this study.3/These a e approximate estimates and serve only to represent the potential of these two damsites in perspective.~/Include estimated costs of power generation facility.
TABLE B.1.3.2:mST COMPARISONS
A C RES 1980
Capital
DAM
Site
Gold Creek
Olson
(Susitna II)
Type
Fill
Concrete
Installed
Capacity -MW
i Capital Cost
$mi llion
Cost EstimateV
Ins talled
Capacity -MW
2601/
1901/
(1980 $)
OTHERS
Capi tal Cos t
$million
890
550
Source and
Da te of Data
USRB 1968
mE 1975
Devil Canyon Fill
:Concrete
Arch
:Concrete
Gravity
High Devil Canyon Fill
(Susitna I)
600
800
1,000
1,500
776
776
700
630
910
1,480
mE 1975
mE 1978
COE 1975
Devil Creek
Watana
SusitnaIII
Vee
Maclaren
Denali
Fill
Fill
Fill
Fill
Fill
Fill
800
350
400
55
60
1,860
1,390
1,060
530
480
792
445
None
1,630
770
500
COE 1978
KAISER 1974
COE 1975
COE 1975
1/Dependable Capaciity
1/Excluding Anchorage/Fairbanksit~ansmissioninter~ie,but including local access and transmission.
~~<------.-
TABLE B.1.3.3:DAM CREST AND FULL SUPPLY LEVELS
Staged Full Dam Average Dam --
Dam Supply Crest Tailwater Heigh tl/
Site Construction Level -Ft.Level -Ft.Level -ft.ft.
Gold Creek No 870 880 680 290
Olson No 1,020 1,030 810 310
Portage Creek No 1,020 1,030 870 250
-Devil Canyon -
intermediate
heigh t No 1,250 1,270 890 465
Devil Ca nyon -
full height No 1,450 1,470 890 675
High Devil Canyon No 1,610 1,630 1,030 710
No 1,750 1,775 1,030 855
Watana Yes 2,000 2,060 1,465 680
Stage 2 2,200 2,225 1,465 880
Susitna III No 2,340 2,360 1,810 670
Vee No 2,330 2,350 1,925 610
Maclaren No 2,3'95 2,405 2,300 185
Denali No 2,540 2,555 2,405 230
1/To foundation level
TABLE 'IB.i .4.1:CAPITAL COST ESTIMATE SUMMl\RIESSUSITNA BASIN DAM SCHEMES
(CO$T IN $MIllION 19BO)
Devil Ca~yori High Devil Canyo~Watana Susitna III Vee Maclaren Denali
I :
1470 ft ~rest 1775 ft Crest 2225 ft Crest 2360 ft Crest 2350 ft Crest 2405 ft Crest 2250 ft Crest
Item 600 MW 800 MW BOO MW 330MW 400 MW No power No power
1)lands,Damages &Reservoirs 26 ,11 46 13 22 25 38
2)Diversion Works 50 4B 71 88 37 lIB 112
3)Main Dam 166 432 536 39B 183 106 100
4)Auxiliary Dam 0 0 0 0 40 0 0
5)Power System 195 232 244 140 175 0 0
6)Spillway Syst.em 130 141 165 121 74 0 0
7)Roads and Bridges 45 6B 96 70 80 57 14
8)Transmission line 10 10 26 40 49 0 0
9)Camp facilities and Support 97 140 160 130 100 53 50
10)Miscellaneousl!8 8 8 8 8 5 5
11)Mobilization and Preparation 30 47 57 45 35 15 14
Subtotal 757 1137 1409 1053 803 379 333
Contingency (20%)152 227 282 211 161 76 67
Engineering and Owner's
Administration (12%)91 136 169 126 96 45 40
TOTAL 1000 ,1500 1860 1390 1060 500 440
!
1-1 ;,
Includes recreational facilities,buil~ings and grounds and pe:rmanent operating equipment.
~-------'
'-~---'--~~'-~-"-------~-----_..-'-'..--~-----------
TABLE B.1.4.2:RESULTS OF SCREENING MDEL
To al Demand Optimal Solution First Suboptimal Solution second Suboptimal Soultion
M9x.lust.Total M9x.lust.Total M9x.Inst.Total
Cap Energy Site Water Cap.Cost Site Water Cap.Cost Site Water Cap.Cost
Run }M GWh Names Level }M $million Names Level }M $million Names Level }M $million
1 400 1750 HiW:t 1580 400 885 Devil 1450 400 970 Watana 1950 400 980
Devil Canyon
Canyon
2 800 3500 HiW:t 1750 800 1500 Watana 1900 450 1130 Watana 2200 800 1860
.Devil
Canyon
I
I
I Devil
Canyon 1250 350 710
I
I 'IOIAL 800 1840
3 120C 5250 Watana 2110 700 1690 HiW:t .1750 800 1500 HiW:t 1750 820 1.500
Devil Devil
Canyon .Canyon
Devil 1350 500 800 Vee.2350 400 1060 Susitna 2Dl 380 1260
Canyon III
'IOIAL 1200 2490 'IOIAL 1200 2560 'IOIAL 1200 2760
4 14(X 6150 Watana 2150 740 1770
NO SOLUTION NO SOLUTION
Devil 1450 660 1000
Canyon
'IOIAL 1400 2770
i
!
J
TABLE B.1.4.3:INFORMATION ON THE DEVIL CANYON DAM AND TUNNE,4 SQHEMES J
1 1
1I·Devil Canyon •Tunnel Scheme
Item j Dam j 1 j 2 I 3 ~4
I 1 1 j I
1IIII•Reservoir Area I I ••I
(Acres)I 7,500 I 320 I 0 1 3,900 j 0
1 ,•••)River Miles 1 I I
I I
Flooded I 31.6 I 2.0 1 0 I 15.8 I 0
I I I I I
JTunnelLengthIj•1 i
(Miles)I 0 I 27 I 29 I 13.5 j 29
•I ••I ITunnelVolumeIIIjj
(1000 Yd 3 )1 0 1 11,976 j 12,863 1 3,732 1 5,131
j 1 j I j
Compensating Flow 1 j j I j
-1Release(cfs)I 0 I 1,000 j 1,000 j 1,000 j 1,000
1 I I I 1
I I I I i
1ReservoirVolumeI1iIj
(1000 Acre-feet)I 1,100 I 9.5 I J 350 I
1 j 1 I I
jDamHeightII I I j
(feet)I 625 i 75 ,I 245 "I
,I.I
I I I lTypicalDailyIjI
J I I
Range of Discharge I 6,000 j 4,000 j 4,000 8,300 3,900
!from Devil Canyon I to I to I to to to
Powerhouse (cfs)I 13,000 j 14,000 j 14,000 8,900 4,200
I j I
IApproximatejII
maximiirii'aaify j
Reservoir (feet)
1
I
]
1
..j
1
TABLE B.1.4.4:DEVIL CANYON TUNNEL SCHEMES COSTS,POWER OUTPUT AND AVERAGE ANNUAL ENERGY
Installed Devil Canyon Increasel!in Tunne 1 Scheme Cost21 of
Capacity (MW)Increasel!in Average Annual Average Total Project Additional
Watana Devil Canyon Installed Capacity Energy Annual Energy Costs Energyl
Stage Tunnel (MW)(GWh)(GWh)$Million (mills/kWh)
STAGE 1:
Watana D m 800
.§.IlillL2:
Tunnel:
-Scheme 1 BOO 550 550 2,050 2,050 19BO 42.6
-Scheme 2 70 1,150 420 4,750 1,900 2320 52.9
-Scheme J2/B50 330 3BO 2,240 2,lBO 1220 24.9
-Scheme 4 BOO 365 365 2,490 890 1490 73.6
1-1 Inc~ease over single Watana,BOO MW development 3250 GWh/yr
2-1 Includes power and energy produced at re-regulation dam
3-1 Energy cost is based on an economic analysis (i.e.using 3 percent interest rate)
CAPITAL COST .ESTIMATE SUMMARIES TUNNEL SCHEMES
COSTS IN $MILLION 1980
Item
TABLE B.1.4•5:
Two 30 ft
dia tunnels
One 40 ft
dia tunnel
J
j
}
Land and damages,reservoir clearing
Diversion works
Re-regulation dam
Power system
(a)Main tunnels
(b)Intake,powerhouse,tailrace
and switchyard
Secondary power station
Spillway system
Roads and bridges
Transmission lines
Camp facilities and support
Miscellaneous
Mobilization and preparation
TOTAL CONSTRUCTION COST
Contingencies (20%)
Engineering,and Owner's Administration
TOTAL PROJECT COST
14
35
102
68'0
557
123
21
42
42
15
131
8
47
1,137
227
136
1,500
....
1
1
I
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1
(i
TABLE B.l.4.6:SUSIrNA DEVELOPMENT PLANS (Page 1 of 3)
Cumulative
Stage/Incremental Data System Data
Annual
Maximum Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$Millions On-line Full Supply Draw-Firm Avg.Factor
Plan)Stage Construction (1980 values)Datel/Level -ft.down-ft GWh GWh %
1.1 I 1 Watana 2225 ft 800MW 1860 1993 2200 150 2670 3250 46
2 Devil Canyon 1470 ft
600 MW 1000 1996 1450 100 5500 6230 51
TOTAL SYSTEM 1400 MW 2860
1.2 I 1 Watana 2060 ft 400 MW 1570 1992 2000 100 1710 2110 60
2 Watanaraise to
2225 ft 360 1995 2200 150 2670 2990 85
3 Watana add 400 MW
capacity 130.£/1995 2200 150 2670 3250 46
4 Devil Canyon 1470 ft
600 MW 1000 1996 1450 100 5500 6230 51
TOTAL SYSTEM 1400 MW 3060
1.3 I 1 Watana 2225 ft 400 MW 1740 1993 2200 150 2670 2990 85
2 Watana add 400 MW
capacity 150 1993 2200 150 2670 3250 46
3 Devil Canyon 1470 ft
600 MW 1000 1996 1450 100 5500 6230 51
TOTAL SYSTEM 1400 MW 2890
TABLE B.l.4.6 (Page 2 of 3)
ptage/lncremental Data
Cumulative
System Data
Plan Stage Construction
Capital Cost
$Millions
(1980 values)
Earliest Reservoir
On-line Full Supply
Datel/Level -ft.
Maximum
Seasonal
Draw'-
down-ft.
Annual
Energy
Production
Firm Avg.
GWh GWh
Plant
Factor
%
MW
2.1
2.2
2.3
3.1
1
2
1
2
3
1
2
3
1
2
Highi Devil Canyon
1775 ft 800 MW
Vee 2350 ft 400 MW
TOTAL SYSTEM 1200 MW
High'~~Yil Canyon
163(>,ft 400 MW.
HighJDevil Canyon
addi400 MW capacity
raise dam to 1775 f
Vee 2350 ft 400 MW
TOTAL:SYSTEM 1200 MWI
High i Devil Canyon
1775:ft 400 MW
High i D~vil Canyon
addi400 i MW capacity
Vee 2350 ft 400 MW
TOTAL SYSTEM 1200 MW
!
i
I
Watana2225 ft 800 ~
Watana add 50 MW .
tunnel 330 MW
TOTAL SYSTEM 1180
i
1500
1060
2560
1140
500
1060
2700
1390
140
1060
2590
1860
1500
3360
1994~l!
1997
1993J/
1996
1997
19941/
1994
1997
1993
1995
1750
2330
1610
1750
2330
1750
1750
2330
2200
1475
~-~".
150
150
100
150
150
150
150
150
150
4
.~
2460 3400
3870 4910
1770 2020
2460 3400
3870 4910
2400 2760
2460 3400
3870 4910
2670 3250
4890 5430
49
47
58
49
47
79
49
47
46
53
~
TABLE BI.1.4.6 (Page 3 of 3)
Plan Stage Construction
3.2 1 Watana 2225 ft 400 MW
2 Watana add 400 MW
capacity
3 Tunnel 330 MW add
50 MW to Watana
Cumulative
Stage/Incremental Data System Data
Annual
Maximum Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$Millions On-line Full Supply Draw-Firm Avg.Factor
(1980 values)Datel/Level -ft.down-ft.GWh GWh %
1740 1993 2200 150 2670 2990 85
150 1994 2200 150 2670 3250 46
1500 1995"1475 4 4890 5430 53
3390
4.1 I 1 Watana
2225 ft 400 MW 1740 19951/2200 150 2670 2990 85
2 Watana add 400 MW
capacity 150 1996 2200 150 2670 3250 46
3 High Devil Canyon
1470 ft 400 MW 860 1998 1450 100 4520 5280 50
4 Portage Creek
1030 ft·150 MW 650 2000 1020 50 5110 6000 51
TOTAL SYSTEM 1350 MW 3400
1 /A lowing for a 3 year overlap construction period between major dams.
2_/P an 1.2 Stage 3 is less expensive than Plan 1.3 Stage 2 due to lower mobilization costs.
3_/A~sumes FERC license can be filed by June 1984,ie.2 years later than for the Watana/Devil Canyon Plan 1.
TABLE B.l.5.~:SUSITNA ENVIRONMENTAL DEVELOPMENT PLANS (Page 1 of 3)
Cumulative
System Data
Plan Stage Construction
Capital Cost
$Millions
(I980 va 1 ue s)
Stage/Incremental Data
Earliest Reservoir
On-line Full Supply
Date!/Level -'ft.
Maximum
Seasonal
Draw-
down-ft
Annual
Energy
Production
Firm Avg.
GWh GWh
plant
Factor
%
El.I
El.2
E1.3
1
2
1
2
3
4
1
2
3
Wata na,2225 ft 800~
,I
and Re-Regu1atioq
Dam
Devil Canyon 1470 ft
49 0M W I
'IOTAL SYSTEM 1200MW
i
Watana 2060 ft 400MW
Watana.rai se to
2225 ft
Watana add 400MW
~ap~City and
Re-Regulation Daml
Devil Canyon 1470 it '
400MW Ii
'IO'I1AL,SYSTEM 1200MW!
Watiana2225 ft 400~
Watanaadd 400MWc~p~city and I
R~-Regu1ation Dami
Dev~l Canyon 1470 f~
4pp MW
'IOTAL SYSTEM 1200MW
1960 1993 2200 150 2670 3250 46
900 1996 1450 100 5520 6070 58
2860
1570 1992 2000 100 1710 2110 60
360 1995 2200 150 2670 2990 85
2301/995 2200 150 2670 3250 46
900 1996 1450 100 5520 6070 58
3060
1740 1993 2200 150 2670 2990 85
250 1993 2200 150 2670 3250 46
900 1996 1450 100 5520 6070 58
2890
~--''---''---'l!f/·..
'------''~
TABLE B.Il.5.1 (Page 2 of 3)
---~.-
Cumulative
Stage/Incremental Data System Data
Annual
Maximmn Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$Millions On-line Full Supply Draw-Finn Avg.Factor
Plan tage Cons truction (1980 values)Datel/Level -ft.down-ft.GWh <Mh %
E1.4 1 Watana 2225 ft 400MW 1740 1993 2200 150 2670 2990 85
2 Devil Canyon 1470 ft
400MW 900 1996 1450 100 5190 5670 81
TOTAL SYSTEM 800MW 2640
E2.1 11 Hi gh Devil Ca nyon
1775 ft 800MW and
Re-Regulation Dam 1600 19941/1750 150 2460 3400 49
2 Vee 2350ft 400MW 1060 1997 2330 150 3870 4910 47
TOTAL SYSTEM 1200MW 2660
E2.~11 High Devil Canyon
1993.111630f t 400MW 1140 1610 100 1770 2020 58
2 High Devil Canyon
raise dam to 1775 ft
add 400MW and
Re-Regulation Dam 600 1996 1750 150 2460 3400 49
3 Vee 2350 ft 400 MW 1060 1997 2330 150 3870 4910 47
TOTAL SYSTEM 1200MW 2800
E2.3 I 1 High Devil Canyon
1775 ft 400MW 1390 19941/1750 150 2400 2760 79
2 High Devil Canyon
add 400MW capacity
and Re-Regulation
Dam 240 1995 1750 150 2460 3400 49
3 Vee 2350 ft 400MW 1060 1997 2330 150 3870 4910 47
TOTAL SYSTEM 1200 2690
TABLE B.l.5.1 (Page 3 of 3)
Stage/Incremental Data
Cumulative
System Data
I
Plan Stage Co~struction
Capital Cost
$Mill ions
(1980 values)
Earl iest Re servoir
On-1 iqe Fun Supply
Datell Level -ft.
Maximtnn
Seasonal
Draw-
down-ft.
Annual
Energy
Production
Firm Avg.
GWh GWh
Plant
Factor
%
E2.4 1
2
3
E3.2 1
2
3
E4.l 1
2
3
4
Hi~h 'Devil Canyon
1755 ft 400MW
High Devil Canyon :
add400MW capacit~
and Portage Creek i
Dam 150 ft '
VeJ,2350 ft
400MW:
TOTAL SYSTEM
i
Watana i
2225 ft 400MW
Watanai add
400 .MW ca pac i ty
anq Re-Regulation
Dam.
Wat±ana'add 50MW
Tumtei Scheme 330MW
TOTAL SYSTEM 1180~
Watana
2225 ft 400MW
Watana
add 400MW capacity!
and Re-Regulation I
Dam i
High Devil Canyon
1470 f t 400MW
Portage Creek
1030 ft 150MW .
'IDTAL SYSTEM 1350 Mw
1390
790
1060
nziIT
1740
250
1500
1Zi"9rr
1740
250
860
650
'15UU
19941/
1995
1997
1993
1994
1995
19951/
1996
1998
2000
1750
1750'
2330
2200
2200
1475
2200
2200
1450
1020
150
150
150
150
150
4
150
150
100
50
2400 2760
3170 4080
4430 5540
2670 2990
2670 3250
4890 5430
2670 2990
2670 3250
4520 5280
5110 6000
79
49
47
85
46
53-
85
46
50
51
1 /
2=/
3_/
Allowing for ,a 3 year overlap Fons truction.periiod between major dams.
Plan 1.2 Stage 3 is less exp~nsive than plan 1.3 Stage 2 due to lower mobilization costs.
Assumes FERC license can be Ifiled by June 1984,!ie.2 years later than for the Watana/Devil Canyon Plan 1.
'---<~~'---'.--:....,.~
TABLE B.1.5.2:RESULTS Of ECONOMIC ANALYSES Of SUSITNA PLANS -MEDIUM LOAD fORECAST
Susitna Development Plan Inc.Installed Capacity (MW)by Total System Total System
On-line Dates .Category in 2010 Installed Present Remarks Pertaining to
Plan Sta es OGP5 Run Thermal Hydro Capacity In Worth Cost the Susitna Basin
No.1 2 3 4 Id.No.Coal Gas Oil Other Susitna 20l0-MW $Millionl/Development Plan
ELI 2000 ----LXE7 300 426 0 144 1200 2070 5850
E1.2 1995 1997 2002 L5Y9 200 501 0 144 1200 2045 6030
El.3 1996 2000 --L8J9 300 426 0 144 1200 2070 5850
1996 ----L7W7 500 651 0 144 800 2095 6960 Stage 3,Devil Canyon Dam
not constructed
19J8 2001 2005 --LAD7 400 276·30 144 1200 2050 6070 Delayed implementation
schedule
E1.4 19J3 2000 ---LCK5 200 726 50 144 800 1920 5890 Total development limited
to 800 MW
Modified 1
E2.1 19 4 2000 -- --
LB25 400 651 60 144 .800 2055 6620 High Devil Canyon limited
to 400 MW
E2.yl!t 1996 2000 -L601 300 651 20 ~44 1200 2315 6370
19 3 1996 ----LE07 500 651 30 144 800 2125 6720 Stage 3,Vee Dam,not
constructedModified
E2.3 19 3 1996 2000 LEB3 300 726 220 144 1300 2690 6210 Vee Dam replaced by
Chakachamna Dam
3.1 19~3 .1996 2000 --L607 200 651 30 144 1180 2205 6530
Special
19933.1 1996 2000 --L615 200 651 30 144 1180 2205 6230 Capital cost of tunnel
reduced by 50 percent
E4.1 1996 1998 --LTZ5 200 576 30 144 1200 2150 6050 Stage 4 not constructed
1-1 Adju ted to incorporate cost of re-regulation dam
C",
TABLE B.1.5.3:RE~ULfS Of ECONOMIC ANALYSES Of SUSITNA PLANS -LOW AND HIGH LOAD fORECAST
I ':,
Susitna Development Plan Inc.Installed Capaci~y (MW)by Total System Total System
On-line Dates Category ini2010 Installed Present Remarks Pertaining to
Plan Stages OGP5 Runi Thermal Hydro Capacity In Worth Cost the Susitna Basin
No.1 2 3 4 Id.No.:Coal Gas Oil Other Susitna 20l0-MW $Million Development Plan
VERY LOW fORECASTl
n.4 1997 2005 ----L7B7 0 651 50 144 800 1645 3650
LOW LOAD fORECAST
n.3 1993 1996 2000 -------- -- --------Low energy demand does not
warrant plan capacities
n.4 1993 2002 ----LC07 0 351 40 144 800 1335 4350
1993 ------LBK7 200 501 80 144 400 1325 4940 Stage 2,Devil Canyon Dam,
not constructed
E2.1 1993 2002 ----LG09 100 426 30 144 800 1500 4560 High Devil Canyon limited
to 400 MW
1993 ------LBUl 400 501 0 144 400 1445 4850 Stage 2,Vee Dam,not
constructed.
E2.3 1993 1996 2000 ------------------Low energy demand does not
warrant plan capacities
Special
3.1 1993 1996 2000 --L613 0 576 20 144 780 1520 4730 Capital cost of tunnel
reduced by 50 percent
3~2 1993 2002 ----L609 0 576 20 144 780 1520 5000 Stage 2,400 MW addition
to.Watana,not constructed
HIGH LOAD fORECAST
E1.3 1993 1996 2000 --LA73 1000 951 0 144 1200 3295 10680
Modified
E1.3 1993 1996 2000 2005 LBV7 800 651 60 144 1700 3355 10050 Chakachamna hydroelectric
generating station (480 MW)
brought on line as a fourth
stage
E2.3 -1993 1996 2000 --LBV3 1300 951 90 144 1200 3685 11720
Modified
E2.3 1993 1996 2000,2003 LBY!1000 876 10 144 1700 3730 11040 Chakachamna hydroelectric
generating station (480 MW)
i brought on line as a fourth
i stage
I
Note:Incorporating load ~anagement and conservation
I
--'--''-'--'
TABLE B.l.5.4:ANNUAL FIXED CARRYING CHARGES
Economic Parameters
Economic Cost of
Life Money Amortization Insurance
Project Type -Years %%%
Thermal -Gas Turbine
(Oi 1 Fired)20 3.00 3.72 0.25
Dies~l,Gas Turbine
(Gas Fired)and
Large Steam
Turbine 30 3.00 2.10 0.25
-Small Steam Turbine 35 3.00 1.65 0.25
Hydropower 50 3.00 0.89 0.10
FUEL COSTS AND ESCALATION RATES
IJ
Natural Gas .Coal Distillate
I )
I
Base Period (January 1980)
Prices ($/million Btu)
Market Prices
Shadow (Opportunity)Values
$1.05
2.00
$1.15
1.15
$4.00
4.00
Real Escalation Rates (Percentage)
Change Compounded (Annually)
1980 -~985
1986 -1990
1991 -1995
Composite (average)1980-1995
1996 -2005
2006 -2010
1.79%
6.20
3.99
3.98
3.98
o
9.56%
2.39
-2.87
2.93
2.93
o
3.38%
3.09
4.27
3.58·
3.58
o
TABLE B.l.5.5:SUMMARY OF THERMAL GENERATING RESOURCE PLANT PARAMETERS
PLANT TYPE
COAL-FIRED STEAM COMBINED GAS
Parameter CYCLE TURBINE DIESEL
500 MW 250 MW 100 MW 250 MW 75 MW 10 MW
Heat Rate (Btu/kWh)10,500 10,500 10,500 8,500 12,000 11,500
O&M Costs
Fixed O&M ($/yr/kW)0.50 1.05 ·1.30 2.75 2.75 0.50
Variable O&M ($/MWh)1.40 1.80 2.20 0.30 0.30 5.00
Outages
P.lanned Outages (%)11 11 11 14 11 1
Forced Outages (%)5 5 5 6 3.8 5
Construction Period (yrs)6 6 5 3 2 1
Start-up Time (yrs)6 6 6 4 4 1
Total Capital Cost
($million)
Railbelt:175 26 7.7
B~~1!gll:..'__'_J,J30 630 .~.2JL
Unit Capital Cost ($/kW)l/
RaBbel t:728 250 778
Beluga:2,473 2;744 3,102
1/Including AFDC at 0 percent escalation and 3 percent interest.
I 1
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TABLE B.l.5.6:ECONOMIC BACKUP DATA FOR EVALUATION OF PLANS
Total Present Worth Cost for 1981 -2040
Period $Million (%Total)
Parameter
Generation Plan
With High Devil
Canyon -Vee
Generation Plan Generation Plan
With Watana -With Watana -
Devil Canyon Dam Tunnel
All Thermal
Generation Plans
Capital Investment
Fue
Operation and Maintenance
TOT~:
2800 (44)
3220 (50)
350 (6)
6370 (100)
2740 (47)
2780 (47)
330 (6)
5850 (100)
3170 (49)
3020 (46)
340 (5)
6530 (l00)
2520 (31)
5240 (64)
370 (5)
8130 (l00)
TABLE B.1.5.7:
!
I I
II I .
ECONOMIC EVALUATION Of DEVIL CANYON DAM ANID TUNNEL SCHEMES AND WATANA/DEVIL CANYON AND HIGH DEVIL CANYON/VEE PLANSii'
Present Worth of Net Benefit ($million)of Total Generation
System Costs for the:
Devil Canyon Dam over Watana/Devil Canyon Dams over
I
the Tunnel Scheme the High Devil Canyon/Vee Dams Remarks
ECONOMIC EVALUATION:
-Base Case
SENSITIVITY ANALYSES:
-Load Growth
-Capital Cost Estimate
-Period of Economic
Analysis
-Discount Rate
Low
High
Period shorten~d to
(1980 -2010)i
5 '"IAII
8%(interpolat~d)
9%!
680
650
N.A.
Higher uncertain~y assoc-
iated with tunnel scheme.,.I
230
520
210
1040
Higher uncertainty associated with
H.D.C./Vee plan.
160
Economic ranking:Devil Canyon
Dam scheme is superior to tunnel
scheme.Watans/Devil Canyon Dam
plan is superior to the High
Devil Canyon Dam/Vee Dam plan.
The net benefit of the
Watana/Devil Canyon plan remains
positive for the range of load
forecasts considered.No change
in ranking.
Higher cost uncertainties associ-
ated with higher cost
schemes/plans.Cost uncertainty
therefore does not affect
economic ranking.
Shorter period of evaluation
decreases economic differences.
Ranking remains unchanged.
-fuel Cost
-fuel Cost Escalation
-Economic Thermal Plant
life
80%basic fuel Icost
i,
0%fuel escala~ioh
0%coal escalatton
50%extension
0%extension
As both the capi~al and fuel costs associated with the tunnel
scheme and H.D.C.I/Vee Plan are higher than for Watans/Devil
Canyon plan any qhanges to these parameters cannot reduce the
Devil Canyon or ~atana/Devil Canyon net benefit to below zero.
Ranking remains unchanged.
~~.-..J '--~---'
TABLE 8.1.5.8:ENVIRONMENTAL EVALUATION Of DEVIL CANYON DAM AND TUNNEL SCHEME (Paga 1 of 2)
Environmenta
Attribute
Ecological:
-Downetreamlfisheries
and Wildlife
Concerna
Effects resulting
from changea in
water quantity and
quality.
Appraiaal
(Differencea in impact
of two achemee)
No aignificant differ-
ence betwesn achemes
regsrding effecta down-
stream of Devil Can~on.
Identification
of difference Appraisal Judgment
Not a factor in evaluation of
scheme.
Scheme judgsd to have
ths leaat potential impsct
Tunnel DC
Reaident fisperies:
Wildlife:
Loss of resident
fisheries habitet.
Loas of wildlife
hebitat.
Difference in reach
between Devil Canyon
dam and tunnel re-
regulation dam.
Minimal differences
betwssn schsmea.
Minimal differsncee
between schemes.
With the tunnel schema
controlled flowa between
regulation dam and down-
stream powerhouse offers
potential for anadromoua
fisheries enhancement in
thia 11 mile reach of the
river.
Devil Canyon Dam would
inundate 27 miles of ths
Susitns River and approx.
2 milss of Dsvil Cresk.
The tunnel acheme would
inundate 16 milea of the
Susitna River.
The most eensitive wild-
life habitst in this reach
is upstream of ths tunnel
re-rsgulstion dsm where
there is no significant
difference between the
echeme.The Devil Canyon
Dam schems in addition
inundatss ths river vslley
between the two damsites
resulting in s mode rete
increase in impacts to
wildlife •.
If fieheriea enhancement
opportunity can be realized
the tunnel echeme offere e
positive mitigetion measuree
not aveilable with the Devil
Canyon Dam schsme.This
opportunity is'considered
moderate and,favore the tunnel
scheme.However,there are no
current plens for such enhance-
ment and feasibility is uncertain.
Potential value is therefore
not significant relative to
additional coat of tunnel.
Loaa of,habitat with dam schema ia
leas than 5~of total for Susitna
mainatem.This resch of river ia
thsrefore not considered to bs
highly significsnt for rssident
fisheries and thus the difference
betwsen the schemes is minor and
favors the tunnel scheme.
Moderate wildlife populatione of
moose,black besr,weasel,fox,
wo]verine,'othsr small msmmals
and songbirds and aoms riparian
cliff hsbitat for ravsns and
raptora,in 11 miles of river,
would be loat with the dam schems.
Thus,the difference in loss of
wildlife habitat ia considerad
moderate and favora the tunnel
scheme.
x
x
x
·TABLE 0.1.5.0:(Page 2 0(2)
Environmental
Attribute Concerna
Appraisal
(Differences in impact
of two achemea)
Identi fication
of diffe.renca Appraiaal Judgment
Schema udged to have
the leaat potential impact
Tunnel DC
Cultural:
Land Uae:
Inundation of
archeological sites.
IInundstion of Devil
Canyon.
~otential differences
between schemes.
!
.
S'igni ficant di fference
O'etwelln schemea.
Due to the larger area
inundated the probability
of inundatingarche~logi
cal eites ia increased.
The Devil Canyon ie'con-
sidered a unique resource,
,80 percent of which would
be inundated by the Devil
Canyon Dam scheme.This
would reault in a loea of
both ao aeathatic value
plua the optential for
white water recreation.
Significant archeological
aites,if identified,can proba-
bly be excavated.Additional
coats could range from several
hundred a to hundreds of thouaands
of dollara,but are atill consider-
ably less than the additions1 cost
of the tunnel scheme.This concern
is not considered a factor in scheme
evalustion •
The aesthetic and to some extent
the recreational losses associ-
ated with the development of the
Devil Canyon Dam iethe main
aspect favoring the ,tunnel scheme.
However,current recreational uses
of Devil Canyon are low due to
limited sccess.future possibilities
include major recrational develop-
ment with conatruction of restsu-.
ranta,msrinaa,etc.Under such
conditions,neither scheme would be
more favorable.
x
OVERALL EVALUATION:
'---~
The tunnel ,scheme haa overalll a
!
-..---'
i,'Ilowerimpactontheenvironment.
.-.....,--../~----'~.~
TABLE B.I.5.9:SOCIAL EVALUATION OF SUSITNA BASIN DEVELOPMENT SCHEMES/PLANS
Remarks
Devil Canyon Dam scheme
potential higher than
tunnel scheme.Watana/
Devil Canyon plan higher
than High Devil Canyon/
Vee plan.
socia~Tunnel Devil Canyon High Devil Canyon/Watana/Devil
Aspec Parameter Scheme Dam Scheme Vee Plan Canyon Plan
poteor Million tons 80 110 170 210
non-r newable Beluga coal
resou ce over 50 years
displ cement
Impac
statejeconomy
Impac on
local economy
All projects would have similar impacts on the state and
local economy.
All projects would have similar impacts on the state and
local economy.
seismtc
expos re
Risk of major
structural
failure
All projects designed to similar levels of safety.Essentially no difference
between plans/schemes.
Potential
impact of
failure on
human life.
Any dam failures would effect the same downstream
population.
--
Overa~l
Evalu~tion
1.Devil Canyon Dam superior to tunnel.
2.Watana/Devil Canyon superior to High Devil Canyon/Vee plan.
TABLE B.I.5.10:ENERGY CONTRIBUTION EVALUATION OF THE DEVIL
CANYON DAM AND TUNNEL SCHEMES
Parameter
Total Energy Production
Capability
Annual Average Energy GWh
Firm Annual Energy GWh
%Basin Potential
Developed.1/
Energy Potential Not
Developed GWh
Dam
2850
2590
43
60
Tunnel
2240
2050
32
380
Remarks
Devil Canyon dam annually
develops 610 GWh and 540
GWh more average and firm
energy respectively than
the tunnel scheme.
Devil Canyon scheme
develops more of the
basin potentia 1.
As currently envisaged,
the Devil Canyon Dam does
not develop 15 ft gross
head between the Watana
site and the Devil Canyon
reservoir.The tunnel
scheme incorporates addi-
tional friction losses in
Euiinels-~-Arso-thecompeii:";;
sation flow released from
re-regulation dam is not
used in conjunction with
head between re-regulation
dam and Devil Canyon.
[
)
)
)
I
lLBased-on-annual average .energy.--Ful-l--potent-ialbasedonUSBR-four--
\)
'I
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TABLE B.I.5.11:OVERALL EVALUATION OF TUNNEL
SCHEME AND DEVIL CANYON DAM SCHEME
ATTRIBUTE SUPERIOR PLAN
Economic Devil Canyon Dam
Energy
Contribution Devil Canyon Dam
Environmental Tunnel
Social Devil Canyon Dam (Marginal)
Overall
Evaluation Devil Canyon Dam scheme is superior
Tradeoffs made:
Economic advantage of dam scheme
is judged to outweigh the reduced
environmental impac.t associated
with the tunnel scheme.
TABLE B.1.5.12:ENVIRONMENTAL EVALUATIbN bf WATANA/DEVIL CANYON AND HIGH DEVIL CANYON/VEE DEVELOPMENT PLANSt•,(Page 1 (If 2)
Environmental
'Attribute PlaQ Comparison _~pp~ai~~!_~udgment
Plan jUdged to have the
least potential impactHocrv·~···W70C
Ecological:
1)fisher ies No significant differenceiin effects on downstream
anadromous fisheries.ii'
Hoc/v would inundate a~prbximatelY 95 miles ofithe
Susitna River and 28 m~le~of tributary stream~,in-
cluding the Tyone River.i
i
W/DC would inundate apRro*imately 84 miles of ~he
Susitna River and 24 miles of tributary streams,
including Watana CreekJ
Due to the avoidance of the
Tyone River,lesser inundation
of resident fisheries habitat and
no significant difference in the
effects on anadromous fisheries,
the W/DC plan is judged to have
less impact.
x
xriverDuetothelowerpotentialfor
direct impact on moose populations
within the Susitna,the W/DC plan
is judged superior.
I
HDC/v would inundate li3 miles of critical winter
bottom habitat.i '
IW/DC would inundate 108 miles of this river bottom
hsbitat.'.
Hoc/v would inundate a IIS~ge area upstream of vee
ut~lized by three sub-p,opulations of moose that range
in the northeast secti~n of the basin.
2)Wildlife
a)Moose
b)Caribou
c)furbearers
d)Birds &Bears
W/DC would inundate the Watana Creek area utilized by
moose.The condition 6,f ~his sub-population o~moose
and the quality of the ra~itat they are using ~ppears
to be decreasing •!''
The increased length o~river flooded,especia]ly up-
stream from the Vee damsite,would result in the
HoD/Vplan creating a g~eater potential divisi~n of
the'Nelchina herd I s range.j In addition,an inc,tease
in ,r~nge would be direcrly:inundated by the Ve~res-
ervo~r.I '
The area flooded by thel Ve:e reservoir is consid:ered
important to some key f~rb~arers,particularly ~ed fox.
This area is judged to be more important than the
Watana Creek area that Wou[d be inundated by the W/DC
plan.!'
i !
forest habitat,important ,for birds and black bears,
exist along the valley ~lopes.The loss of this habi-
tat'would be greater wi~h ~he W/DC plan.
!
Due to the potential for a greater
impact on the Nelchina caribou
herd,the HDC/v scheme is
considered inferior.
Due to the lesser potential for
impact on furbearers the W/DC is
judged to be superior.
The HDc/V plan is judged superior.
x
x
x
Cultural:There is a high potenti~l for discovery of arch~ologi
cali sites in the easterly region of the upper Susitna
basin.The HDc/v plan ~asl a greater potential pf
affecting these sites.Ifor other reaches of the river
the difference between plans is considered minimal •
The W/DC plan is judged to have a
lower potential effect on
archeological sites.
x
._.__i'
~~.--~
TABLE B.l.~.12 (Page 2 of 2)
EnvironmentJal
Attribute Plan Comparison Appraisal Judoment
Plan~uaged to have the
least potential impact
HDC/V -WTDC
Aestheticl
Land Use
With either scheme,the aesthetic quality of both
Devil Canyon and Vee Canyon would be impaired.The
HDC/v plan would also inundate Tsusena Falls.
Due to construction at Vee damsite and the size of
the Vee reservoir,the HDC/v plan would inherently
create access to more wilderness area than would the
W/DC plan.
Both plans impact the valley
aesthetics.The difference
is considered minimal.
As it is easier to extend access
than to limit it,inherent access
requirements were considered
detrimental and the W/DC plan is
judged superior".The ecological
sensitivity of the area opened by the
HDC/V plan reinforces this judqment.
x
OVERALL EVALUATION:The W/DC plan is judged to be superior to the HDe/V plan.
(The lower impact on birds and bears associated with HDC/v
plan is considered to be outweighed by all the other impacts
which favor the WiDe plan.)
Notes:WIWatana Dam
DC =Devil Canyon Dam
HD =High Devil Canyon Dam
V Vee Dam
TABLE B.l.5.l3:ENERGY CONTRIBUTION EVALUATION OF THE
WATANA/DEVIL CANYON AND
HIGH DEVIL CANYON/VEE PLANS
I
Parameter
Total Energy Production
Capability
Annual Average Energy GWh
Firm Annual Energy GWh
%Basin Potential
Developedl..l
Energy Potentia~Not
Developed GWh '1:.7
Watana/
Devil Canyon
6070
5520
91
60
High'Devil
Canyon/Vee
4910
3870
81
650
Remarks
Watana/Devil Canyon
plan annually devel-
ops 1160 GWh and
1650 GWh more average
and firm energy,re-
pectively,than the
High Devil Canyon/Vee
Plan.
Watana/Devil Canyon
plan develops lIlOte of
the basin potential
As currently con-
ceived,the Watana/-
Devil Canyon plan
does-not--devel"op t 5
ft of gross head
between the Watana
site and the Devil
Canyon reservoir.
The High Devil
Canyon/Vee Plan does
not develop 175 it
gro.ss __hea.d_b.etwee.n_
site and
}
I
Notes:
1/Based on annual average energy..F1illp6~~nt:~aT basecl0nUSBR'fpur .
dam schemes.
'1:./Includes losses due to unutilized head.
J
I
J
TABLE B.I.5.14:
ATTRIBUTE
Economic
Energy
Contribution
Environmental
Social
Overall
Evaluation
OVERALL EVALUATION OF THE HIGH DEVIL
CANYON/VEE AND WATANA/DEVIL CANYON·
DAM PLANS
SUPERIOR PLAN
Watana/Devil Canyon
Watana/Devil Canyon
Watana/Devil Canyon
Watana/Devil Canyon (Marginal)
Plan with Watana/Devil Canyon is
superior
Tradeoffs made:None
-I
TABLE B.2.2.1:COMBINED WA'l'ANA AND DEYfCCANYON OPERATION
Watana Dam
Crest Elevation
(ft MSL)
j
----------------------------------A-v-e-r-a-g-e-A-n-n-u-a-l--J
Wat anal/Devil Canyonl/Total Energy (GWh)
Cost Cost Cost Watanak /Watana/Devil
($x 10 6 )($x 10 6 )($x 10 6 )Alone Canyon
2240 (2215
reservoir elevation)
2190 (2165
reservoir elevation)
4,076
3,785
1,711
1,711
5,787
5,496
3,542
3,322
6,809
6,586
.)
I
2140 (2115
reservoir elevation)3,516 1,711 5,227 3,071 6,264
II Estimated costs in January 1982 dollars,based on preliminary conceptual
designs,including relicfcnaiinel drainage blanket and 20 percent
contingencies.
kl Prior to year 2002
,1
I
i J
)
TABLE B.2.2 .2:
Watana Dam
Crest Elevation
(ft MSL)
2240 (reservoir
elevation 2215)
2190 (reservoir
elevation 2165)
2140 (reservoir
elevat ion 2115)
PRESENT WORTH OF PRODUCTION COSTS
Pre sent Wo rth
of Production Costs1/
($x 10 6 )
7,123
7,052
7,084
1/.LTPW in January 1982 dollars
TABLE B.2.2.3:DESIGN PARAMETERS FOR DEPENDABLE CAPACITY AND ENERGY PRODUCTION
Watana
Minimum stream flow!/(monthly average,cfs)570 (March 1950)
Mean streamflow!/7,990
Devil Canyon
664 (March 1964)
9,080
Maximum streamflow!/42',840 (June 1964)47,816 (June 1964)1
J
Evaporation Approximately cancels precipitation
and is neglected.
Leakage Negligible Negligible
Critical streamflow for dependable
capacity curve (Watana and Devil Canyon
combined)
Area capacity curve
Hydraulic Capacity
Flow (cfs)1/2
full
'best
Efficiency 1/2
fu-l-l-
best
Generator output (kW)1/2
full
best
Tailwater rating curves
5,450 GWh annual potential recurrence
frequency 1 in 32 years
Figure B.3.2.1 Figure B.3.2.1
1,775 1,895
3,550 3,790
2,900 3,100
87 87
94 94
91,000 82,000
183,000 164,000
156,000 139,000
Figure B.4.2.3 Figure B.4.2.3
)
J
I,I
,1
TABLE B.2.2.4:WATANA -MAXIMUM CAPACITY REQUIRED (MW)
OPTION 1 -THERMAL AS BASE .
CAPACITY (MW)
Hydrological Year 1995 2000 2010***
1 743 762 838*
2 550 569 680
3 760 779 836*
4 749 I 768 836*
5 744 763 868*
6 763 782 832*
7 737 756 838*
8 771 790 836**
9 799**818**825*
10 563 582 683*
11 769 788 832*
12 784*803 829*.
13 773 792 832*
14 771 790 838*
15 745
,
764 844*
16 550 569 840*
17 745 764 836*
18 554 573 684*
19 771 790 832*
20 550 569 685*
21 550 569 678
22 550 569 672
23 784*803 834*
24 747 766 838*
25 550 569 684
26 ·550 569 678
27 728 747 839*
28 550 569 675
29 785*804 833*
30 550 569 678
31 787*806 837*
32 754 773 839*
*Restricted by peak demand
**Maximum value
***Including Devil Canyon
TABLE B.2.2.5:WATANA -MAXIMUM CAPACITY REQUIRED (MW)
OPTION 2 -THERMAL AS PEAK
CAPACITY (MW)
Hydrological Year 1995 2000 2010*
1 575 575 838
2 382 382 389
3 592 592 839
4 581 581 836
5 576 576 868
6 595 595 832
7 569 569 838
8 603 603 836
9 631 631 825
10 395 365 391
11 601 601 832
12 616 616 829
13 605 605 832
14 603 603 838
15 577 577 844
16 382 382 840
17 577
I
577 836
18 386 386
j
392
19 603 603 832
20 382 382 393
21 382 382 386
22 382 382 380
23.616 626 834
-."""5.79 ~38
25 382 382 392
26 382 382 386
27 560 560 839
.28 382 382 383
29 617 617 833
30 382 382 387
31 619 619 837
32 586 586 839
""""-
J
l
1
(
i
j
.1
J
i
,\
TABLE B.2.2.6:SUMMARY COMPARISON OF POWERHOUSES AT WATANA
S U R F ACE U N D ERG R 0 U N D
($000)($000)($000)
Item 4 x 210 MW 4 x 210 MW 6 x 140 MW
Civil Works:
Intakes 54,000 54,000 70,400
Penstocks 72,000 22,700 28,600
Powerhouse/Draft Tube 29,600 26,300 28,100
Surge Chamber NA 4,300 4,800
Transformer Gallery NA 2,700 3,400
Tailrace Tunnel NA 11,000 11,000
Tailrace Portal NA 1,600 1,600
Main Access Tunnels NA 8,100 8,100
Secondary Acc.ess Tunnels NA 300 300
Main Access Shaft NA 4,200 4,200
Access Tunnel Portal NA 100 100
Cable Shaft NA 1,500 1,500
Bus Tunnel/Shafts NA 1,000 1,200
Fire Protection Head Tank NA 400 400
Mechanical -For Above Items 54,600 55,500 57,200
Electrical -For Above Items 37,400 37,600 41,200
Switchyard -All Work 14,900 14,900 14,900
TOTAL 262,500 246,200 277 ,000
TABLE B.2.3.1:DESIGN DATA AND:DESIGN CRITERIA
FOR FINAL REVIEW OF LAYOUTS
.River Flows
Average flow (over 30 years of record):
Probable maximum flood (routed):
Maximum inflow with return period of 1:10,000 years:
Maximum 1:10,000-year routed discharge:
Maximum flood with return period of 1:500 years:
Maximum flood with return period of 1:50 years:
Reservoir normal maximum operating level:
Reservoir minimum operating level:
Dam
Type:
Crest elevation at point of maximum super elevation:
Height:
Cutoff and foundation treatment:
Upstream slope:
Downstream slope:
Crest width:
Diversion
Cofferdam type:
__~~Cut9 ft=and founda t ion :~~~~_~__~~~~~_
Upstream cofferdam crest elevation:
Downstream cofferdam crest elevation:
Maximum pool level during construction:
Tunnels:
Final closure:
Releases during impounding:
(Page 1 of 2)
7,860 cfs
326,000 cfs
156,000 cfs
115,000 cfs
116,000 cfs
,87,000 cfs
2215 ft
2030 ft
Rockfill
2240 ft
890 ftabove foundation
Core foundedon'rock;
grout curtain and down-
stream drains
.2.4H:IV
2H:lV
50 ft
Rockfill
..Slurry_tre!1~J!.~~().Q~drC?~c~
1585'ft
1475 ft
1580 ft
Concrete-lined,
Mass concrete plugs
6,000 cfs maximum via
bypass to outlet
structure
J
..l
Design floods:
Main spillway -Capacity:
-Control structure:
Emergency spillway -Capacity:
-Type:
Passes PMF,preserving
integrity of dam with
no loss of life
Passes routed 1:l0,000-year
flood with no damage to
structures
Routed1:10,000-year flood
wi th 5 ft surcharge "/Gated agee crests !
PMF minus 1:10,000 year flood
Fuse plug -I
TABLE B.2.3.1 (Page 2 of 2)
Power Intake
]
Type:
Number of intakes:
Draw-off requireme~ts:
Drawdown:
Penstocks
Type:
Number of penstocks:
Powerhouse
Type:
Transformer area:
Control room and administration:
Access -Vehicle:
-Personnel:
Power Plant
Type of turbines:
Number and rating:
Rated net head:
Design flow:
Normal maximum gross head:
Type of generator:
Rated output:
Power factor:
Frequency:
Transformers:
Tailrace
Water passages:
Surge:
Average tailwater elevation (full generation):
Reinforced concrete
6
Multi-level corresponding
to temperature strata
185 feet
Concrete-lined tunnels with
downstream steel liners
6
Underground
Separate gallery
Surface
Rock tunnel
Elevator from surface
Francis
6 x 170 MW
690 ft
3,500 cfs per unit
745 ft
Vertical synchronous
190 MVA
0.9
60 HZ
13.8-345 kV,3-phase
2 concrete-lined tunnels
Separate surge chambers
1458 ft
Note:Certain design data and criteria have been revised since date of layout
review.For current project parameters refer to Exhibit F,Preliminary
Design Report.
PRELIMINARY REVIEW
Technical feasibility
Compatibility of layout
with known geological
and topographical site
features
Ease of construction
Physical dimensions
of component structures
in certain locations
TABLE B.2.3.2:EVALUATION CRITIERA
INTERMEDIATE REVIEW
Technical feasibility
Compatibility of layout
with known geological and
topographical site features
Ease of construction
FINAL REVIEW
Technical feasibility
Compatibility of layout
with known geological and
topographical site features
Ease of construction
,~
Obvious cost differences
of comparable structures
Environmental accept-
ability
Overall cost
Environmental accept-
ability
Overall cost
Environmental impact
'J
,I
j
TABLE B.2.3.3:SUMMARY OF COMPARATIVE COST ESTIMATES
INTERMEDIATE REVIEW OF ALTERNATIVE ARRANGEMENTS
(January '1982 $x 10 6 )
WP1 WP2 WP3 WP4--
Diversion 101.4 112.6 101.4 103.1
Service Spillway 128.2 208.3 122.4 267.2
Emergency Spillway -46.9 46.9
Tailrace Tunnel 13 .1 13.1 13 .1 8.0
Credit for Use of Rock in Dam (ll.])(31.2)(18.8)(72.4)
Total Non-Common Items 231.0 349.7 265.0 305.9
Common Items 1643.0 1643.0 1643.0 1643.0
Subtotal 1874.0 1992.7 1908.0 1948.9
Camp &Support Costs (16%)299.8 318.8 305.3 311.8--
Subtotal 2173.8 2311.5 2213 .3 2260.7
Contingency (20%)434.8 462.3 442.7 452.1
Subtotal 2608.6 2773.8 2656.0 2712.8
Engineering and
Administration (12.5%)326.1 .346.7 332.0 339.1
TOTAL 2934.7 3120.5 2988.0 3051.9
____..~~__~_..__._.--=-=-==--==~--l ........=====~=----------
**Maximum Value
TABLE B.2.4.1:DEVIL CANYON -MAXIMUM CAPACITY REQUIRED (MW)
<:1
Hydrological Year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
25
26
27
28
29
30
31
Capacity (MW)
2010 (Option 1 and 2)
544**
353
546
546
514
548
544
546
557
351
548
551
548
544
538
542
546
350
550
349
355
361
544
349
355
543
359
549
355
545
1
"J
j
J
I
J
l
(
-J
I
I
1
I
i
1
.1
)
j
J
TABLE B.2.5.1:DESIGN DAT~AND DESIGN CRITERIA FOR
REVIEW OF ALTERNATIVE LAYOUTS
River Flows
(Page.1 of 2)
Average flow (over 30 years of record):
Probable maximum flood:
Max.flood with return period of 1:10,000 years:
Maximum flood wi th return period of 1:500 years:
Maximum flood with return period of 1:50 years:
Reservoir
Normal maximtml operating level:
Reservoir minimum operating level:
Area of reservoir at maximum operating level:
Reservoir live storage:
Reservoir full storage:
Dam
Type:
Crest elevation:
Crest length:
Maximum height above foundati<Jn:
Crest width:
Diversion
Cofferdam types:
Upstream cofferdam crest elevation:
Downstream cofferdam crest elevation:
Maximum pool level during construction:
Tunnels:
Outlet structures:
Final closure:
Releases during impounding:
8,960 cfs
346,000 cfs
165,000 cfs (after routing
through Watana)
42,000 cfs (after routing
through Watana)
1455 feet
1430 feet
21,000 acres
180,000 acre-feet
1,100,000 acre-feet
Concrete arch
1455 feet
635 feet
20 feet
Rockfill
960 feet
900 feet
955 feet
Concrete-lined
Low-level structure with
slide closure gate
Mass concrete plugs ~n
line with dam grout curtain
2,000 cfs min.via fixed-cone
val ves
TABLE B.2.5.1 (Page 2 of 2)
Spillway
Design floods:
Service spillway -capacity:
-control structure:
energy dissipation:
Secondary spillway -capaci ty:
-control structure:
-energy dissipation:
Emergency spillway -capacity:
1:10 ,OOO-year
-type:
Power -Intake
Type:
Transformer area:
Access:
Type of.turbines:
Number and rating:
Rated ne t head:
_M~~LimJ.Im g:J;Q~!iLb_ead:._
____Iype of generator:__.._._
Rated output:
Power factor:
Passes PMF,preserving
integrity of dam with no
loss of life
Passes routed
l:10 ,OOO-year
flood wi th no damage to
structures
45,000 cfs
Fixed-cone valves
Five 108-inchdiameter
fixed-cone valves
90,000 cfs
Gated,ogee crests
Still ing basin
prof mi nus routed
flood
Fuse plug
Underground
Separate gallery
Rock Tunnel
Francis
4 x 140 MW
550 feet
565f.ee.tapprox._
_____Vertica1~ynchronous
155 MVA
0.9
..~
Note:Certain design data and criteria have been revised since date of layout
review.For current projectparB.III.eters refer to Exhibit F,Preliminary
Desi~l1Report.]
TABLE B.2.5.2:SUMMARY OF COMPARATIVE COST ESTIMATES
PRELIMINARY REVIEW OF ALTERNATIVE ARRANGEMENTS
(January 1982 $X 10 6 )
Item DC1 DC2 DC3 DC4
Land Acquisition 22.1 22.1 22.1 22.1
Reservoir 10.5 10.5 10.5 10.5
Main Dam 468.7 468.7 468.7 468.7
Emergency Spillway 25.2 25.2 25.2 25.2
Power Facilities 211.7 211.7 211.7 211.7
Switchyard 7.1 7.1 7.1 7.1
Miscellaneous Structures 9.5 9.5 9.5 9.5
Access Roads &Site Facilities 28.4 28.4 28.4 28.4
Common Items -Subtotal 783.2 783.2 783.2 783.2
Diversion 32.1 32.1 32.1 34.9
Service Spillway 46.8 53.3 50.1 85.2
Saddle Dam 19.9 18.6 18.6 19.9
Non-Common/Items Subtotal 98.8 104.0 100.8 140.0
Total 882.0 887.2 884.0 923.2
Camp &Support Costs (16%)141.1 141.9 141.4 147.7
Subtotal 1023.1 1029.1 1025.4 1070.9
Contingency (20%)204.6 205.8 205.1 214.2
Subtotal 1227.7 1234.9 1230.5 1285.1
Engineering &Administration
(12.5%)153.5 154.3 153.8 160.6
Total 1381.2 1389.2 1384.3 1445.7
TABLE B.2.7.1:POWER TRANSFER REQUIREMENTS (MW)
1
J
\
J
l
i
j
l
l
)
1
!
I
I
j
j
\
52
198
276
327
601
1245
TRANSFER EXPECTED
Sus tina to Susitna to
Anchorage Fairbanks
170
320
405
578
1088
1377
360
960
1620
600
600
360
360
1020
DEPENDABLE CAPABILITY TRANSFER CAPABILITY
Devil Total Susitna to Susitna to
Watana Canyon Susitna Anchorage Fairbanks
1999
2005
2012
Year
TABLE B.2.7.2:SUMMARY OF LIFE CYCLE COSTS (1985 $Mi1lion)ll
TRANSMISSION ALTERNATIVE
1 2 3 4 5
Transmi sion Lines
Capital $220.12 $231.37 $188.18 $205.28 $223.72
Land Ac uisition 26.70 29.64 25.76 28.70 26.59
Capi tal zed Annual Charges 181-.56 191.25 153.17 166.57 180.95
Capital zed Line and Losses 75.66 77.70 91.97 93.85 61.05
Total T ansmission Line Cost $504.04 $529.96 $459.08 $494.40 $492.31
Swi tchi g Stations
caPital!$168.62 $155.35 $190.43 $177 .16 $224.79
Capital zed Annual Charges 181.06 167.53 204.19 190.66 242.85
Total S itching Station Cost $349.69 322.88 394.19 367.82 467.64
TOT~$853.72 $852.84 $853.70.$862.22 $959.95
II Thit estimate is based on an Acres (1982).Subsequently,switching equipment for Devil Canyon was shifted
to reate Gold Creek switchyard.However,selection of alternative 2 did not change.
il
J
Type
1.Technical
-Primary
-Secondary
2.Econanical
-Primary
-Secondary
3.Envirornental
-Primary
-Secondary
Criteria
General Location
Elevation
Relief
Access
River Crossings
Elevation
Access
River Crossings
Timbered Areas
~tlands
reveloprent
.Erlsting-Tranmsslori
Right-of-Way
Land Status
Topogra];hy
Vegetation
Selection
o>nnect with Intertie near Gold Creek,WillCM,
and Healy.Connect Healy to Fairbanks.0>0-
nect WillCM to Anchorage.
Avoid IDOWltainous areas.
Select gentle relief.
IDcate in praximi~to existing transP2rtation
corridors to facill.tate maintenance arid repairs.
Minimize wide crossings.
Avoid IIlJUntainous areas.
IDca~e in proximity to existiJ?g tranSportation
corrldors to reduce constroctlon costs.
Minimize wide crossings.
Minimize such areas to reduce clearing costs.
Minimize crossings which require special designs.
Avoid existing or proposed developed areas.
ParalleI:
Avoid private lands,wildlife refuges,parks.
Select gentle relief.
Avoid heavily timbered areas.
,I
I ~l
I
j
i
TABlE B.2.7.4:fNI/!IlIPl!·£'·lT.,\L INVENTORY -SOUTHERN STUDY AREA
(WIllOW TO ANCHORAGE/POINT MACKENZIE:)
(Page I of 2)
length (miles)
AB
38
Be
35
Corridor Segment
ADf
26
AEf
27
fC
12
Number of Road
Crossings
Number of River
Creek Croasing
Topogrsphy
Soilsl!
lsnd ownerShiP/it
Stetus
Existing/Proposed
Developments
Existing Rights~of
Way
Scenic Quality/
Recrestion
Cultural Resourc~sll
2 hwy (Rt.3,Glenn),6 light
duty roads,1 unimproved road,
2 trails,1 railroad
1 river,17 creeks
Willow (100'),croases Willow
Ck.,follows
Deception Ck.(1000')along
ridge of Talkeetns Hte.,s.e.
into Palmer (200')
Willow to near Palmer-S04,
Palmer-EO!
A to e.of Willow Ck.Rd.
crosaing-mostly P,with aome
BAP and some SP,•••to due n.
of Wasilla-mainly SPTA,•••to
B-mostly P,with aome BAP and
SP
Ag.usea n.&w.of Palmer,
ag/res.use near l.Susitna,
proposed capital aite,mixed
res.area at Willow Ck.,
Willow air atrip,cabin near
A
follows no known right-of-way
for appreciable distance
Gooding l.-bird-watching,
rec.traila a.of Willow-
hunting,hiking,x-c skiing,
dog sledding,snowmobiling,
snowshoeing,rec.trsil by
Decep.Ck.-anowmobiling,
dog eledding,fishing
DATA VOID
4 hwy (Glenn,4x),3+light
duty roads,7 unimproved roads,
1 trail,several railroads
4 rivers,II creeks
Palmer (200'),crosses Knik
River to base st Chugsch Hta.
(500'),along Knik Arm (200'-
300'),to Anchorsge (200')
Palmer-EO!,Knik Arm-En,S.
of Eklutna to n.of Anchorage-
505,Anchorege -504
B to Knik R.-P,...to
Birchwood-mainly VS with eome
SPTA,P and BAP,Birchwood
eres-P,s.w.of Birchwood to
nesr C'-U.S.Army Military
tid!.,C'-DATA VOID
Urban uses in Anch.,pssses
through/near eeverel
communitiesl Eegle R,
Birchwood,Eklutna,Chugisk,
Peters Ck.
Parallela trans.line Knik R.
to Anch.,parallels Glenn Hwy.
from Knik R.to Birchwood,
parallels RR-Esgle to C'
Pssses near 2 camping grounda,
parellela Iditarod racing
trail (x-c ekiing,aledding,
snowmobiling),birdwatching
at Eklutna flata and Hatunusks
River
DATA VOID
1 hwy (Rt.3),3 tractor
traile
1 river,6 creeks
Willow (100'),e.along
SuaitnsRiver plaina (flat,
wet area,with drier,raised
leveea,200'-400'),to f at
150'
Willow-504,S.of Willow to
f-SOI
Near A-P,route fairly even
mix of BAP and SPTA,some P
near fieh Ck,area aurrounding
l Suaitna R -Susitna flate
Gsme Reguse,near f-SPTA
Red Shirt lake-mixed
residential use;near
residential &recr.areas s.w.
of Willow,Suaitna flats State
Gsme Refuge
Generally parallela a tractor
treil
X-c eki &snowmobile traile;
recreation area s.w.of
Willow
DATA VOID
1 hwy (Parka),1 tractor
trail
1 river,6 creeks
Willow (100'),s.slong flat
wet area (200'-400'),to f at
about 150'
Near l.Susitns River -505,
Remainder-S04
A,s.to Rainbow l.-mostly P,
small parcels BAP;State
selected fed.parcel w.of
Willow l.,e.to l.Susitna R.
-Nsncy lake State Rec.Area,
to f -mix of SPTA and BAP
Mixed res.areas;lakes used
to land float plsnes
No known
Mixed rec.sreas,Nancy lake
State Rec.area,traila and
multiple uses;msy cross Gooss
Bay st.Gsme Re fuge
DATA VOID
2 trsctor trails
2 creeks
f et 150'along flste to C
nesr ses level
Nesr f -504,Nesr C -501
f to I mi.s.-SPTA,...s.to
Horseehoe l.-Pt.MacKenzie
Agr.Ssle;•••s.to C-mainly
SPT A,some BAP
Scsttered residentisl/cabins on
Horsehoe lake,proposed ago uses
in area
Generally follows a trsctor trail
Hsy cross Susitna flats State
Wildlife Refuge
DATA VOID
TABlE B.2.7.4 (Paga 2 of 2)
AB
dorridor Sagment
!AOfBC AEf FC
VegetationAl
fish Reaourcea21
Birda.61
furbearera.61
Bi!il Game.61
Upland,mixad deciduoue-
conifer forests (birch-spruce)
-open and closed mostly.Tsll
shrub (s~der);,somawoodland
black spruce;bogs along
Deceptlo'l Ck.
Willow Ck.,-chinook ealmon,
graylingJ burbot I longnoee
eucker,~ound wh tefish,
Dollsr V~rdan,ialimy aculpin;
lake trout!&rainbow trout in
lakea;l~Susitna R.-king
salmon;qecep.'Ck.-king,
pink salnion
DATA VOlq
DATA VOID
Except near Palmer-black bear
aummer rsnge.mooee winter/
summer ranga,migrating
corridora and calving araa;
near A alao brown bear summar
ranga and faeding area
,!
~aci~uoua forest (balsam
~opl~r)along rivar,probsbly
~irc~/apruce foreets on
uplands in most of aras.DATA
VOID
I
S'ockJya,chinook,pink,ahum,c~hoisalmon in Isrge rivera;
grayling burbot,longnose
s~cker,round whitefish,Dolly
V~r~n,slimy eculpin,lake
and rainbow trout in lakes &:
stream;ealmonof,perticular
sIgnificsnce in the Hstanuska
ard ~nik Rivers
Waterfowl and shore bird
n~eting areae around Knik Arm
ard ~agle River Flata
I ,
DATA VOID
I IiTA\VOID
•
Higher grounds:Spruce-birch-
poplar forests.Wet sedge
grase boga and black spruce
forest a prevalent in lower
half
Willow Ck.-chinook aalmon,
lake and rainbow trout
possible in some lakes;also,
in etreams are grayling,bur
bot,long nose sucker,round
w~itefish,Dolly Vardsn,
slimy.sculpin;Red Skirt l.-
lake trout,sockeye sslmon
Waterfowl snd shore bird
nesting in Willow Creek/
Delta Islanda
VOID
Brown and black bear'feeding
moose winter/summer range and
calving area
Upper half;mostly upland
birch,spruce &:aapen.lower
halfl wet sedge-grasa bogs snd
black apruce;eome birch,
spruce;aspen on higher
ground
lekes msy contain rainbow snd
lake trout;possibly grsyling
in the region
Ssme aa ADf
Same as AUF
Ssme aa ADf
Spruce foresta,spruce-birch
foreata,sedge-grsss bogs snd
black spruce boga
lake may contain rainbow snd
Iske trout;posaibly grayling
in the region
Waterfowl snd shore bird
migration route,feeding and
neating area
Furbearer snd small mammal
summer/winter rsngs
Black bear summer rsnge and
fseding area;moose winter/
summer range,feeding snd
calving area
:l !.)
Tall shrub=slder;low ShrUb=dw•....ar.f'.birch'and/or WillO['~pen spruce=black (wet)covrr,mixed forest=spruce-birch.
,I
little data svailable.Sour~e of information in this tablel Alaeka Department of Fieh and Geme 1978a.
!I
little dste available.Source of information in this tsble:Alaeka Department of Fish and Game 1978b.
1..1
2..../
3J
4J
5..../
6..1
Source I
Source I
Coaatal
i I •.•.I,Unites Statea Department ,of Agriculture,Soi~Conservation Service 1979.See Table B.43 for explanation of soil units.
I ,!
CIRI/Holmes and Na~v~r.~980.P=Private,SPTf+s,ate Patented or Tentatively Approved,SP=State P~tented,BAP=Borough Approved
area probably haa many eites,available liter~ture not yet reviewed.!
or Patented.
!_~-~-_!~.'-----------
TABLE B.2.7.5:ENVIRONMENTAL INVENTORY -CENTRAL STUDY AREA (DAMSITES TO INTERTIE)(Page 1 of 6)
Approx. Approx.IJ Al?Prox.IJCorridorLen~th Road Rlver/Creek a Land b
Segment (Mi es)Crossings Crossings Topography Soils Ownership/st at us
AB 7 0 5 creeks Moderate sloping s.rim of S015 VSSusitnaR.V811ey;crosses
deep ravine at Fog Ck.at
about 2000'contour
II:18 0 8 creeks 2000'contour along s.rim B,westwiird-S015;VSofSusitnaRiver;crosses near C -SOlO3st.eep gorges
CD 15 1+1 river Moderately sloping terraini OSlO C to 1 1/2 mi.e.4 creeks crosses 5usit.na R.near Go d of Susitna R.-Creek (800')VSi Susitra R.t.o
1 12 mi.e.-
SPTA;...to D-P
BEC 23 0 8 creeks Crosses moderate slopes 8,westward -OS15;VS except wherearoundStephaniLake;w.,then ret ween B &C corridor skirts
n.to avoid dee~ravine at IU3;near C -SOlO Cheechako Ck.
Cheechako Ck.,hen follows s.ravine,..which isrimofSusitnaatabout2000'classi ied 5S
Suspended
AJ 18 0 11 creeks A (about.2000')t.o 3500';A,westward -OS15;SS ex ceRt at JcrossesdeepravineatDevilremainder,exce~t and at.westward
Ck.(2000');goes by several J -OS16;near J -
across Tsusena
ponds SOlO Ck.,which are VS
JC 8 0 1 creek J (2000'),s.w.throu~OSlO SS excegt.at JgentlyslopingHighL e and C w ich are
area,to C at Devl1 VSCanyon(2000')
CF 15 0 2 creeks Devil Cannon «2000'f west SOlO C to 1 1/2 mi.e.across 60 'deep Por age of Miami L.Creek gorge;w.across mainly VS with
rentle terrain to F small parcel of
1200')S5;...to F-P
AG 65 0 1 river A (2000'~6 n.along Deadman Near A and along A-VS;n.of A35creeksCk.to 3 0';crosses Denali Hwy.-to s.w.of Big L.
Brushkana drainage (at OS15;throu!tl -SS,•••to s.
3200')'dr~s to Nenana uts.-5016 •of Deadman L.-
River (240 ,)and fairly SPTA ...to
flat.t.errain to G (2200 )Denali Hwy -Fed.
D-l Land;data
void for 8 mi.'
around G -Smail
Fed.Parcel
a.Source:United States Department of Agriculture,Soil Conservation Service 1979.See Table B.42forexplanationofsoilunits.
b.Source:CIRI/Holmes and Narver.1980.P=Private,SPTA=State Patented or Tentatively Approved,
SS=St.ate Selection,VS=Village Selection.
TABLE B.2.7.,5 (flage 2 of 6)
Approx.Approx./1
Corridor Length Road
Segment (Mila:!)Crossings
Appro,./IRI~er Creek
Crossings Topography
a
Soils
Land b
Ownership/Status
Ali 22 0
HI
HJ
21 0
23 0
91 creeks
151 creeks
0,creeks
I
A (2000')1,along Tsusena Ck.
past Tsusena Buft e;through,
fit.pass lat 3600'';I
H (3400')1 through mts.;along
Jack R.drainage and Caribou
Pass;to II at 2400'
H (3400')1 through mts.along
Portage Ck.draInage,through
pass at 3600'into Devil
Creek dra~nage;;to J at 2000'
I '
i
Near A -5015Lmt.base -SOlb;
mts.-RMl
Mts.-RMl;
along hwy -S015
Near J -5016
mid elevations-
S017;mts.-
RMI
A -V5;•••to n.
of Tsusena Butte
55;dat a void
l:eyond here
If -VS;data void
to east
J-VS;Devil Ck
drainage -SS;
data void beyond
here
a.
b.
!lSource:,United States Department
for explanation of aoil unit~.I
Source:CIRI/Holmes and Nar~eri.
I
of Agricult ure,Sop Conservation Service,1979.See Table B.42
p
1980.P=Private,iSPTA=State Patented or Tentatively Approved,
I
i
'---''--~~----;'---'
TABLE B.2.7.5 (Page 3 of 6)
Corridor
Segment
AB
II:
ro
E£C
AJ
JC
CF
a
Fish Resources
F llJ Lakes -Dolly Varden,sculpin;
Stephan Lake contains laKe and
rainbow trout~sockeye &coho
salmon,whit~rish,longnose
sucker,gray~ng;Durbof
Several small tributaries crossed,
perhaps used by grayling
Same as II:
Several small tributaries crossed,
perhaps used by grayling,burbot
Dolly Verden;grayling in Tsusena
Creel<
Burbot;no data for High Lake
Portage Creek has king,chinook,
chum and pink salmon,grayling,
~rb~
Birds
Potential raptor
nesting habitat in
Fog Creek area
Potential raptor
nesting habitat
along Devil Canyon
Potential raftornestinghabiat
along Devil Canyon
Potential raftornestinghabiat along
Devil Canyon and along
drainages upstream;
Stephan Lake area
important to waterfowl
and migrating swans
Data void
Potential raptor hab.
by Devil Can~on;golden
eagle nest along Devil
Ck.s.of confluence of
ck.from High Lake
Potential raptor
habitat along lower
Portage Ck.and from
Portage Ck.mouth
through Devil Canyon
Fur bearers
Excellent fox and
marten habitat;
Fog Lakes support
numerous beavers and
muskrat;otters
common
Excellent fox and
nart en ha bit at
Area around Devil
Canyon has
excellent fox and
marten habitat
Excellent fox and
marten habitat,
particu larly
around Stephan
Lake
Red fox denning
sites,numerous
beaver,muskrat and
mink,esp.ecially
around High Lake
Same as AJ
Area bet ween P ar ks
Hwy~nd Devil Canyon
supports numerous
!:eaver,muskrat,and mili<
Big Game
Supports large pop.
of moose;wolves,wolverine and bear,
(especially brown)
common;caribou
regularly use area
Area around Stephan
Lake &Prairie Ck.
supports large pcp.
of moose;wolves,
wolverines,and some
bear (especially
brown)common;
caribou regular users
Moose,caribou,and
bear nabitat
Same as AB
Mout h of Tsusena Ck.
important moose
habitat;heavily
used by black
and brown bear
Important moose and
!:ear habitat;data
void
Probably imp~rtant
moose w~nter~ng area
area and black bear
habitat t at leastonewolrpack
a.Little data available.Sources of information in this table:Alaska Department of Fish and
Game 1978a,Friese 1975,and Morrow 1980.
TABLE B.2.7.5 (Page 4 of 6)
Corridor
Segment
AG
AH
HI
HJ
a
Fish Resources
,'
Dollr-Vardeni lakes -I lake trout,
grayling,whlte-fish;tributaries
foNenana River and Brushkana
Creekn.of Deadman Mt.,:and
Jack R.near Denali H~considered
fish habitat I I
I
Dolly Varden;grayling
!
Lake trout,Cari bou Phssi area;
Jack River s.of Caribou:Pass
considered important fish
habitat;data void !ipb~tage Creek -king,Ich~nook,
chum,and pink salmon~grayling,
bur bot 'i
Birds
Waterfowl numerous at
Deadman Lake;impor-
tant baHl eagle habitat
by Denali Hwy and
Nenana R~just w.of
Monahan Flat;unchecked
bald eagle nest along
Deadman Ck.,s.e.of
Tsusena ~utte
Known acti ve bald
eagle nest s.e.of
Tsusena ~utte
Data voi(J
I
I
I
Data voi~
Fur bearers
P~ulation
relati vely low,
although beaver,
mink,fox present;
Deadman Mt.to
Denali Hwy -
moderate pop.redfox
Population along
Tsusena Ck.prooably
relatively low;with
beaver 1 ffilnk,and fox
probab y present
Data void
Numerous beaver,
muskrat.~and mink
around Ni!tl Lake
Big Game
Probably important
area for caribou,
expecially in the
north
Data void
Data void
Data void
'------'-''-"---
a.Little data available.Sour6eslof information
Game 197Ba,Friese 1975,andl Moii-row 1980.
I
in this table:
I
Alaska Department of Fish and
'10.,
~-'-~'-'--'
TABLE B.2.7.5 (Page 5 of 6)
Corridor
Segment
AB
II:
ID
BEC
Existing/Proposed
Development s
Cabins on FW Lakes;
planes use lakes
Cabins and lodge on
Stephan Lake
Follows proposed
Susitna railroad
extension;scattered
cabins in Canyon/Gold
Creek area
Cabins and lodge on
Stephan lake
Exist ing
Right s -of -Way
No known
No known
Old Corps trail,
Gold Ck.to
Devil Canyon
No known
Scenic
Quality/Recreation
Fog Lakes -high
aest hetic qual1t y;
fishing in Fog
Lakes
Stefhan Lake -hiQh
aes hetic quality
Scenic area;
possible fishing
st efhan Lake -hiQh
aes hetic qualH y;
major recreation
area for fishing/
boat i ng/planes
Cult ural Resources
Arch.sHes
identi fied near
Wat ana Dam site
and w.shore of
Stephan Lake;
potential for more
sites around F9Q
Lakes and Stephan
Lake
Arch.sites near
Stephan Lake
Hist.sit es near
Gold Ck.;data
void
See AB
a
Vegetation
Most ly wood land
black spruce (wet);
some low shrub
Open and woodland
spruce forests,low
shrub,open ana
closea ffi1xed forest
in about equal
amounts
Mostly closed mixed
forests
Woodland sp'ruce and
bogs arouna Stephan
Lakei low shrub,
mat ~cushion and
sedge-grass tundra
at upper end of
Cheechako Ck.drain-
age;tall shrub
(alder)and mixed
forest along
Cheechako Cl<.and
towards Devil
Canyon
a.Tall shrub:alder;low shrub:dwarf birch}and/or willow;open spruce:black (wet)or white spruce,25%-60%cover;
woodland spruce:white or black spruce,0%-25%cover,mixed forest :spruce-birch.
TABLE B.2.7.5 (Page 6 of 6)
Corridor Existing/Proposed
Segment Developments
Exist ing
Rights-of -Way
ScenicQ~lity/Recreation Cult ural Resources
a
Vegetation
Mostly low shrub,
mat &:cushion,
sedge-grass tundra
some ta II shrub
(alder)
Tall shrub (alder)
shrub and open low
mixed forest
Mostly low shrub in
southern end;
northern end -data
void
Open &:closed mixed
forest,tall shrub,
low shrub
Mat &:cushion
sedge-grass tundra,
tall shrub and open
mixed forest in
southern end
Low shrub,tall
shrub,woodland
spruce
Data void
Arch.sites at
Portage Ck.and
Susitna R.con-
fluence and near
11atana Dam site
No Known arch.
sites
Arch.sites at
Portage Ck.;
hist.si t es near
Canyon
Arch.sites
along Deadman Ck.
Arch.site n.of
Tsusena But t e
along T susena Ck.;
data void
Data void
Data void
Boating in Susitna;
hunt ing,fishing,
hiking
High Lake and other
laKeS -high aesthe-
tic quality·fishing/hun~ing in
H~ght lake area
S~me as AJ
Scenic drainage;
S?eep hunting in n.
I .Remote flat areas -
high visibility;..
Deadman L.and Me.•
Alaska Range -hig~
aesthetic quality;
fishing,qoat
p~anes;major rae.
aJ,'eas oy Bfushkana
afrl Nenana R.,
Dresher L.
Tsusena Butte -
aesthetic quality;
major sheep hunting
area
IM~j or sheep hunting
stea;,bird watching
at Summit L.
I
No Known
No known
No known
No known
No known
Parallels'Denali
Hwy beyond
Brushkana Ck.
drainage to G
iNo known
Cabins near Tsusena
Butte
Cabins near Summit
Follows pr op osed
Sasitna access road
along Devil Creek
approx,.3 mi.1
cabins along uevil
Creek drainage
follows proposed
Susit ns access road
from Watana to just
s ~,of Deadman Mt.;
occasional cabins;
landing strip along,
Denali Hwy;airporf
near G
AH
HJ
AG
Cf
AJ follows proposed
Susitna access road
from Tsusena Creek
to Hi{fl Lake;
lodge at High Lake
JC Generally follows
proposed Susitna
access rd.;lodge
at 'High Lake
Mining claims,cabins
i':l'Portage Creek
area
HI
a.Tall shru,b,:a1"der;,low shrub:dwatf birch l and/or willdw;open spruce:black (wet)or white spruce ,25%-60%cover;
woodland,spruce:white or bla~k ~pruce,0%-25%cover~mixed forest:spruce-birch.
j.-
~-------~
TABLE 8.2.7.6:ENVIRONMENTAL INVENTORY -NORTHERN STUDY AREA
(HEA~Y TO FAIRBANKS)i
(Page 1 of 2)
Length (millis)
Number of Roed
Croesings
Number of River/
Creek Croesings
Topography
SoilsY
Land Ownerahip/lI
Status
Existing/Propoaed
Developmenta
Existing Rights-of
Way
Scenic Quality/
Recreation
Cultural Resourcea
AB
40
2 hwy (Park).3 traila
(1 winter>.2 unim-
proved rds ••I rail-
rosd
3 rivers.15 creeks
Follows Nensna River
north at 1000'to
Browne-crossea River;
n.w.to Clear MEWS
at 500'
IRIO
A to e.of Dry Ck.-
small Fed.Parcel;•••
to s.of Clear MEWS
and at B-mostly SPTA.
small parcels of p.
small Fed.Nat.Allot.
along Nenana R.;Clear
MEWS area-parcel CIRI
Selection.and U.S.
Army Wdl.land
Scat tared residential
and other usee along
Parke Hwy;cabin near
Browne;air atrip at
Healy
Generally parallele
Parke Hwy.RR and
trans.line-Healy
to Browne
Parka Hwy-acenic area;
rafting.kayaking on
Nenana R.
Dry Ck.arch.eite near
Healy;good possibility
for other sites;DATA
VOID
f£
50
Parks Highway,
1 winter trail
1 river.25 creeks
Clear MEWS (500')
north across plain
(400'),n.e.across
Tanana River Valley
to Ester (600')
Near B-IRIO;flats a.
of Tanana River-IQ2;
Tanana River-IQ3;
Tanana R.to Ester-
IRI4
B to 1-1/2 mi n.-
SPTA;•••to s.to
Tansna R.-SS;•••to
Tanana R.-P;•••to
crossing l.Goldstream·
Ck.-mostly SPTA;•••to
Bonanza Ck.Crossing -
SS;•••to nesr C-SP;
remainder-DATA VOID
Scattered residential
and other uses along
Parks Hwy;cabin at
Tanana R.crossing
Followa w/in aeveral
mi.Parke Hwy.RR,and
trans.line;more
closely follows Parka
Hwy.and trans.Une
and aled rd.n.of
of Tanana R.
Parks Hwy-eceni~area;
hunting,fishing
Good poasibility for
arch.aites;DATA VOID
Corridor Segment
roc
46
1 winter trail
2 rivera.29 creeka
Clear MEWS (500'),
n.e.across plain to
a point about 24 mi.
due a.of Eeter;n.
acrosa plain to
Tanana R.(400')and
n.to Ester
Near B-IRIO.Remainder
-IQ2
B area -SPTA;Fish Ck.
to Tanana R.-data void
remainder-SPTA,8I\P
with P at C and just n.
of Tanana R.
Ft.Wainwright Hil.
Reservation
No known
Wide open flat-high
visibility;enow-
mobiling in flata e.
of Fairbanks
Good possibility fDr
arch.sitea;DATA VOID
AE
65
I hwy.(Parks),
1 trail
I river 50 creeka l
Up Healy Ck.to pass st
4500';down WDDd R.
drainsge tD Japan Hilla
(1100');ateep mta.;
valleya
Near A-IRIO;rot.baae-
IQ25;mt.area-RHl;
near E-IRI
A tD Nenana R.-small
Fed.Parcel;•••to e.
Df GDld Run-SPTA •••
remainder-DATA VOID
Air at rips-Healy and
Cripple/Healy Cka.
cDnfluence;cabins-
CDdy Ck/WoDd R.,
SnDW Ht.Gulch
Parallels small rd.-
near Healy tD CDal
Ck.;amall RR-Healy to
Suntrana;trail at
pass between Healy and
Cody Cks.
Scenic quality data
vDid;Healy Ck.-rafting
area
Dry Ck.arch.site near
Healy;few arch.sites
in mDuntains;maybe
near Japan Hills;DATA
VOID
EOC
50
7 trails
2 rivers,22 creeks
Japan Hilla (1100')
n.w.Dn plain alDng
WDod R.;thrDugh
Wood R.Buttes area,
n.acrDSS Tanana R.;
n.to Ester
Near E-IRI;between
E and Dpen flats-
IRIO;open flata
IQ2;Tanana R.-IQ3;
Eater-IRl4
Same aa BOC nDrth Df
the Tanana River
Ft.Wainwright Hil.
Res.;WDDd R.Butte
VABH
ND knDwn
Wide Dpen flats-high
viaibility;anow-
mobiling in flata a.
of Fairbanks
High pDssibility fDr
arch.sites;DATA VOID
EF
40
Several roads in Fairbanka
depending upDn exact
route;3 trails
2 rivera,10 creeks,
Salchaket SIDugh
Japan Hilla (1100')n.
acroas plain to Tanana
R.(500');n.tD Fairbanks
Near E-IRl;a.section
of flats-IRIO;flats-IQ2;
Fairbanks-IQ3
DATA VOIO
Ft.Wainwright Hil.
Rea.;cabin-WDod R.
crDssing a.Df Clear Butte
Parallels Bonnifield Trail
-Clear Ck.Butte to
Fairbanks;trsns.line
juet s.Df Fairbanks
Wide open flats-high
visibility
Arch.sites have been
identified fDr the Ft.
Wainwright and Blair
Lakes areas
'~l
TABLE B.2.7.6 (Page 2 of 2)
Vegetation!!
fish Resourcee21
Bird~
furbearers.61
Big Game.61
AB
Southern end-da~a
void NortherneOd-low
shrub,eedge-grase
tundra
Grayling.burbot i••long-
nose.sucker.Do~ly
Varden.round.white-
fish.slimyrsculpin
Importsnt ~)d~n eagle
habitat na'!r A
Prime habitat-15 mi.
from Nenana to B
from Nenans R.to B-
prime moose and impor-
tant black bear
habitat;fr,om A ~orth
wsrd about 10 mi~-prime
moose habit~t .
oc
S.of Tsrana River-wet
old river floodplain,
low shrup a~d sedge-
gress bogs;ITanans R.
crossingrwi~low and
alder ahrubltypea,
white sPfuc~,balaam
poplar forests slong
river;nL o~Tanana R.
-open a~cloaed de-
ciduous ~bl~ch and
aspen)forsats on
alopes,~/woodlsnd
spruce spd bogs,low
shrub,and ~st sedge-
grsss onlVa~ley bottoms
Grayling~~rbot.long-
nose suc~er~Dolly
Varden.round white-
fish.slimy iaculpin.
sslOlon (~oho king.
chum).s~se~Ish;lske
chub possibleI!
I .
Prime pe~egr~ne.hsbitst
st Tsna~R.I;prime
waterfowl habitat slang
Tanana RJ s.1 of
corridor I
I
I !Prime haDitat-from
Clear ME~S ac.ross the
Tanana I !
Clear MEWS to across
Tanana RJ-prtme mooss
and imporl'tan~blsck
bear hsbJ!,tat;n~of
Bonanza Ck.Exp.
foreat-p~ime!blsck
bear habirat!
Corridor Segment
IDC
Probably wet,low
shrub,andlisedga-grass.
alder shrub,lowland
spruce;n.lof Tansna-
uplsnd deciduous
forests !
Ssme as OC
Near Totatlanika Ck.
to Tanena ft.-prime
waterfowl habitat;
near Wood n.-important
rapt or hab~tat;be
tween O&C ~y Tanana R.
-prime per~grine
habitat !
Prime habitiat from B
to across ~anana Rive
I
B to across,Tanana R.
-prime moo~e.important
black bea~hsbitat;
Wood R.to Uust s.of
the Tanana R.-prime
black bear·habitat
i
AE
DATA VOID
Same aa AB
Important golden eagle
habitat at A &along
Healy !Ck.s.of
Usibelli Pk,prime
peregrine habitat on
Keevy Pk.
Prime habitat from E
to the s.about 15 mi.
Usibelli to Japan
Hills-prime moose &
caribOu habitat,
between A.&Mystic
Mt .-prime sheep
habitat;E to the s.-
import••black bear
habitat
mc
Probably similar to IDC
Same as AB.lske chub
possible
from Wood R.Buttes to
n.of Tansns R.-prime
waterfowl hsbitat;
between D&C along the
Tanans R.-prime
peregrina habitat
Prime hllbitat from E
to just n.of Tsnana
River
E to just n.of Tansna
R.-prime moose.impor-
tant black besr
hsbitat;Wood R.to
just s.of Tsnana R.~
prime,black besr
Ef
Probably similar 'to EDC;
wet
Same as Be with the excep-
tion of coho sslmon.which
is not recordsd
N.of Blsir Lake Air force
Renge to the Tanana R.-
prime wsterfowl habitat;
s.of fairbanks along
Tanana R.-prime bald eagle
habitat
Prime habitst from E
to Tsnana River
E to tanana R.-prime mooae
and important black bear
habitat;Clear MEWS to
Tanans R.-prime black bear
habitat
J!Assumes corridor is located on r.side of Healy Ck.fori most .of its length.n.sidelof Cody Ck ••and n.~.aida of Wood R.
11 So~rcsl United Ststes Dept.ofl~griculture.Soil conss~vs~ion Service 1979 ..See T~ble B.42 for explanation of soil units.
I !.11 Source I CIRI/Holmes and Narver.1900.P=Private.5PT~=S~ete Patented or Tentatively Approved;sp=state Patented;SS=State Selection.BAP=Borough Approved or Patented.
!I Tall shrub=alder;low shrub=dwarf birch,end/or wtllOW;!open spruce=blsck (wet)or ~ite spruce,25~60~cover;woodland spruce=white or black spruce,10~-25~ccover;mixed
foreat=spruce-birch.'..I
Source I VanBallenberghe personal communication.Primelhabitat=minimum amount of land neceesary to provide sustained yield for that species;based upon knowledge of that
species'nesds from experience of AOf&G personnel.Importsnt habitat=land which the AOf&G considera not aa critical to a species aa is Prime habitat but is valuable.
21 Little data available.
~
,'
Sources.of information in thia tab~el Alsska Dept.of fishlan~Game 1970a and Morrow 1900.
•...ib!!.:..-.'---'.k-.,~--'._-,;;.;....:
TABLE B.2.7.7:SOIL ASSOCIATIONS WITHIN THE PROPOSED TRANSMISSION
CORRIDORS -GENERAL DESCRIPTION,OFFROAD
TRAFFICABILITY LIMITATIONS (ORTL),AND
COMMON CROP SUITABILITY (CCS)a
EFI -Typic Gyofluvents -Typic Cryaquepts,loamy,nearly level
(Page 1 of 3)
-Dominant soils of this association consist of well-drained,stratified,
waterlaid sediment of variable thickness over a substratum of gravel,
sand,and cobblestones.Water table is high in other soils,including
the scattered muskegs.ORTL:Slight -Severe (wet;subject to flood-
ing);CCS:Good -Poor (low soil temperature throughout growing season).
E01 -Typic Cryorthents,loamy,nearly level to rolling
-This association occupies broad terraces and moraines;most of the bed-
rock is under thick deposits of very gravelly and sandy glacial drift,
capped with loess blown from barren areas of nearby floodplains.Well-
drained,these soils are the most highly developed agricultural lands in
Alaska.ORTL:Slight;CCS:Good -Poor.
IQ2 -Histic Pergelic Cryaquepts -loamy,nearly level to rolling
The dominant soils in this association are poorly drained,developed in
silty material of variable thickness over very gravelly glacial drift.
Most soils have a shallow permafrost table,but in some of the very
gravelly,well-drained soils,permafrost is deep or absent.ORTL:
Severe -Wet;CCS:Poor
IQ3 -Histic Pergelic Cryaquepts -Typic Cryofluvents,loamy,nearly level
-Soils of this association located in low areas and meander scars of
floodplains are poorly drained silt loam or sandy loam;these are usually
saturated above a shallow permafrost table.Soils on the natural levees
along existing and former channels are well-drained,stratified silt loam
and fine sand;permafrost may occur.ORTL:Severe (wet);CCS:Unsuit-
able (low temperature during growing season;wet)-Good (but subject to
flooding).
IQ25 -Pergelic Cryaquepts -Pergelic Cryochrepts,very gravelly,hilly to steep
-Soils of this association occupying broad ridgetops,hillsides,and
valley bottoms at high elevation are poorly drained,consisting of a few
inches of organic matter,a thin layer of silt loam,under which is very
gravelly silt loam;permafrost table is at a depth greater than 2 feet.
In locations of hills and ridges above tree line these soils are well-
drained.ORTL:Severe (wet,steep slopes);CCS:Unsuitable (wet;low
soil temperature;short,frost-free period).
a.Source:U.S.Department of Agriculture,Soil Conservation Service 1979.
See Table B~43 for definitions for Offroad Trafficability Limitations and
Common Crop Suitability.
!
TABLE B.2.7.7 (Page 2 of 3)
IRI -Typic eryochrepts,loamy,nearly level to rolling r
)
, 1
-On terraces and outwash plains,these soils are well-urained,having a
thin mat of course organic matter over gray silt loam.In slight depres-
sions and former drainage ways,these are moderately well-drained soils,
having a thin organic mat over silt loam,with a sand or gravelly sub-
stratum.ORTL:Slight-Moderate;ees:Good.r
TRIO -Typic eryochrepts,very gravelly,nearly level to rolling -Aeric erya-
quepts,loamy,nearly level to rolling
-Generally well-to moderately well-drained soils of terraces,outwash
plains,and low moraines.Typically,these soils have a silt loam upper ·1
lay~r over gravelly soils.Pockets of poorly drained soils with a shal-
low permafrost table occupy irregular depressions.ORTL:Moderate-
Severe (we.t);ees:Good -Poor (wet;low soil temperature throughout
growing season;short,frost-free period).
IR14 -Alfie eryochrepts,loamy,hilly to steep -Histic Pergelic eryaquepts,
loamy,nearly level to rolling
On mid-slopes,these soils are well drained,of micaceous loess ranging
to-many feet thick over shattered bedrock of mica schist.Bottomland I
areas are poorly drained with a relatively thick surface of peatmoss.In .]
~Qi I!;,perntafrost r~l1g~s fJ:()m 5..30 inches in depth.ORTL:
Moderate -Severe (steep slope;wet);CeS:Poor (steep slopes;highly
susceptible to erosion).
IU3 Perge1ic eryumbrepts,very gravelly,hilly to steep -rough mountainous
land
On high alpine slopes and ridges close to mountain peaks,these soils
have a thin surface mat of organic material beneath which is an 8 to 12-
---..~~."_.__._..._--_.__."---'-'-~i-nc1:f;;;;t1fi-clt-;--'~da-rk'--b-r'own~--'h-o'ri~z'on--f·onne·d--'···-i-n·-very·---g'·rave-1-1y---or·_·,s -tony loam .
.---..--------·--·--~~·---·---·--Th±s--a·s·s·o·c-i·a~t·i_o-n---a-l-s·o-i-nc-l-ude·s-·-a-r:e-a·s·---o·f--ba-:re-~r.oc·k-an<i-s.t-o.nJ7---I.u.b.b_Le o_n _
mountain peaks.ORTL:Severe (short,frost-free period)-Very Severe
(steep slope);ees:Unsuitable (short,frost-free period;shallow
bedrock)•
RMI -Rough Mountainous Land
SOl -Typic eryorthods,loamy,nearly level to rolling -Sphagnic Borofibrists,
nearly level .1
-Low hills,terraces,and outwash plains have well-drained soils formed in
silty loess or ash,over gravelly glacial till.Depressions have poorly
drained,fibrous organic soils.ORTL:Slight -Very Severe;ees:Good
(on well-drained soils)-Unsuitable (wet organic soiO.
TABLE B.2.7.7 (Page 3 of 3)
S04 -Typic Cryorthods~very gravelly,nearly level to rolling -Sphagnic
Borofibrists,nearly level
-Soils of nearly level to undulating outwash plains are well-drained to
excessively well-drained,formed in a mantel of silty loess over very
gravelly glacial till.Soils of the association located in depressions
are very poorly drained,organic soils.ORTL:Slight -Very Severe;
ees:Good -Unsuitable (wet,organic).
S05 -Typic eryorthods,very gravelly,hilly to steep -Sphagnic Borofibrists,
nearly level
-On the hills and plains,these soils,formed in a thin metal of silty
loess over very gravelly and stony glacial drift,are well drained and
strongly acid.In muskegs,most of these soils consist of fibrous peat.
ORTL:Severe (steep slope);ecs:Unsuit~ble (steep slopes;stones and
boulders;short,frost-free season).
SOLO -Humic Cryorthods,very gravelly,hilly to steep
-Generally,these are well-drained soils of foothills and deep mountain
valleys,formed.in very gravelly drift with a thin mantel of silty loess
or mixture of loess and volcanic ash.These soils are characteristically
free of permafrost except in the highest elevation.ORTL:Severe (steep
slope);ees:Poor -Unsuitable (low soil temperature throughout growing
season;steep slopes).
S015 -Pergelic eryorthods -Histic Pergelic eryaquepts,very gravelly,nearly
level to rolling
-On low moraine hills,these soils are well drained,formed in 10 to 20
inches of loamy material over very gravelly glacial drifts.On foot
slopes and valleys,these soils tend to be poorly drained,with shallow
permafrost table.ORTL:Slight -Severe (wet);ecs:Unsuitable (short,
frost-free period;wet;stones and boulders).
S016 -Pergelic Cryorthods very gravelly,hilly to steep -Histic
Pergelic Cryaquepts,loamy,nearly level
-On hilly moraines these soils are well-drained;beneath a thin surface of
partially decomposed organic matter,the soils have spodic horizons
developed in shallow silt loam over very gravelly or sandy loam.In
valleys and long foot slopes,these are poorly drained soils,with a
thick,peaty layer over a frost-churned loam or silt loam.Here,depth
of permafrost is usually less than 20 inches below surface mat.ORTL:
Severe (steep slope;wet);ees:Unsuitable (short,frost-free period)-
Poor (wet;low soil temperature).
TABLE B.2.7.8:DEFINITIONS FOR OFFROAD TRAFFICABILITY
LIMITATIONS AND COMMON CROP SUITABILITY
OF SOIL ASSOCIATIONSa OFF ROAD
TRAFFICABILITY LIMITATIONS (ORTL)
(Page 1 of 3)
,J
.•..'J
-I.,
Offroad Trafficability refers to cross-country movement of conventional
wheeled and tracked vehicles,including construction equipment.Soil
limitations for Offroad Trafficability (based on features of undisturbed
soils)were rated Slight,Moderate,Severe,and Very Severe on the
following bases:
-Slight
Soil limitations,if any,do not restrict the movement of cross-country
vehicles.
-Moderate
Soil limitations need to be recognized but can generally be overcome with
careful route planning.Some ,special equipment may be required.
-Severe
Soil limitations are difficult to overcome,and special equipment and
careful route planning are required.These soils should be avoided if
possible.
-Very Severe
Soil limitations are generally too difficult to overcome.Generally,
these soils are unsuitable for conventional offroad vehicles.
COMMON CROpb
SUITABILITY (CCS)
Soils were rated as Unsuitable,Good,Fair,and Poor for the production of
common crops ·ou-the-following-bases:-------
-Unsuitable
Soil or climate limitations are generally too severe to be overcome.
None of the common crops can be grown successfully in most years,or
there is danger of excessive damage to soils by erosion if cultivation is
attempted.
a.Source:U.S.Department of Agriculture,Soil Conservation Service
1979.
b.The principal crops grown in Alaska--barley,oats,grasses for hay and
silage,and potatoes--were considered in preparing ratings.Although
only these crops were used,it is assumed that the ratings are also
valid for vegetables and other crops suited to Alaskan soils.
I,'J,
]
'(
,j
'j
TABLE B.2.7.8
-Good
(Page 2 of 3)
i
!
I I
Soil or climate limitations,if any,are easily overcome,and all of the
common Alaskan crops can be grown under ordinary management practices.
On soils of this group --
(a)Loamy texture extends to a depth of at least 18 inches (45 cm).
(b)Crop growth is not impeded by excessive soil moisture during the
grow~ng seasons.
(c)Damage by flooding occurs no more frequently than 1 year in 10.
{d)Slopes are dominantly less than 7 percent.
(e)Periods of soil moisture deficiency are rare,or.irrigation is
economically feasible.
(f)Damage to crops as a result of early frost can be expected no more
frequently than 2 years in 10.
(g)The hazard of wind erosion is estimated to be slight.
-Fair
Soils or climate
Common crops can
may be required.
limitations need to be recognized but can be
be grown,but careful management and special
On soils of this group
overcome.
practices
(a)Loamy texture extends to a depth of at least 10 inches (25 cm).
(b)Periods of excessive soil moisture,which can impede crop growth
during the growing season,do not exceed a total of 2 weeks.
(c)Damage by flooding occurs no more frequently than 2 years in 10.
(d)Slopes are dominantly less than 12 percent.
(e)Periods of soil moisture deficiency are infrequent.
(f)Damage to crops as a result of early frost can be expected no more
frequently than 3 years in 10.
(g)There is no more than a moderate hazard of wind erosion.
TABLE B.2.7.8
-Poor
(Page 3 of 3)I, I
Soils or climate limitations are difficult to overcome and are severe
enough to )
make the use questionable.The choice of crops
treatment or management practices are required.
overcoming the limitations may not be feasible.
is narrow,and special
In some places,
On soils of this group
(a)Loamy texture extends to a depth of at least 5 inches (12 cm).
(b)Periods of excessive soil moisture duringc>the growing season do not
exceed a total of 3 weeks.
(c)Damage by flooding occurs no more frequently than 3 years in 10.
(d)Slopes are dominantly less than 20 percent.
(e)Periods of soil moisture deficiency are frequent enough to severely
damage crops.
(f)Climatic conditions permit at least one of the common crops,usually
grasses,to be grown successfully in most years.
}
,)
i.
TABLE B.2.7.9:ECONOMICAL AND TECHNICAL SCREENING SOUTHERN STUDY
AREA (WILLOW TO ANCHORAGE/POINT MACKENZIE)
-Length (miles)
-Max.Elev.(ft)
-Clearing (miles)=
Medium &Light
None
-Access (miles)=
New Roads
4-Wheel
-Tower Construction*
-Rating:
Economical
Technical
A =recommended corridor
C =acceptable but not preferred
F =unacceptable
(1)
ABC'
73
1400
61
12
20
53
329
C
C
(2)
ADFC
38
400
20
18
o
38
180
A
A
(3)
AEFC
39
400
15
24
12
27
176
C
A
*Approximate number of towers required for this corridor,
assuming single-circuit line.
rABlE B.2.7.10:ECONOMICAL AND TECHNICAL SCREENING
CENTRAL!STUDY AREA (DAM SITES TO INTERTIE)
I
(1 )(2)!(3)(4)(5),(6)(7)(8) (9)(10)(11)(12)(13)(14)*(15)
ABCD ABECD AJCf ABCJHI ABECJH[CBAHI CEBAHI CBAG CEBAG CJAG CJAHI JACJHI ABCf AJCD ABECf
!,
-Length 40 45 41 77 82 68 75 90 95 91 69 70 41 41 45
I
-Max.Elevation,ft.2500 3600 3500 4300 430P 4300 3500 3300 3600 3500 3800 3900 2500 3500 3600
-Clearing
Medium &Light 38 30 26 18 30 20 27 45 37 40 55 17 39 26 35
None 2 1~15 59 50 48 46 45 60 51 14 53 2 15 10
-Access
New Roads 28 31 12 58 49 44 53 44 49 13 27 44 41 5 45
4-Wheel 12 12 29 8 8 3 3 46 46
78 23 26 0 36 0
-Tower Construction*180 20~185 347 369 306 338 405 428 410 311 315 185 185 203
-Rating:
Economical C Ci C f fl C f f f f C
f C A C
Technical A Ci C f f!F C C C
C C C C A C
I
A =recommended
C =acceptable but not preferred
F =unacceptable
*Approximate number of towers requ.ire,d for this'corridor,
assuming single-circuit line.!
__i_~----
TABLE B.2.7.11 ECONOMICAL AND TECHNICAL SCREENING
NORTHERN STUDY AREA (HEALY TO FAIRBANKS)
(1)(2)(3).(4)
ABC ABDC AEDC AEF
-Length 90 86 115 105
-Max.Elevation 1600 1600 4500 4500
-Clearing
Medium &Light 48 50 40 50
None 42 36 75 55
Access
New Roads 0 0 54 42
4-Wheel 90 43 42 16
-Tower Construction*405 387 518 473
-Rating:
Economical A A C C
Technical A C F F
A =recommended
C =acceptable but not preferred
F =unacceptable
*Approximate number of towers required for this corridor,
assuming single-circuit line.
TABLE B.2.7.l2:SUMMARY OF SCREENING RESULTS
RAT I N G S
Corridor Env.Econ.Tech.Summary
-Southern Study Area
(1)ABC'C C C C
(2)ADFC A A A A
(3)AEFC F C A F
-Cental Study Area
(1)ABCD C C A c
(2)ABECD F C C F
(3)AJCF C C C C
(4)ABCJHI F F F F
(5)ABECJHI F F F F
(6)CBAHI F C F F
(7)CEBAHI F F C F
(8)CBAG F F C F
(9)CEBAG F F C F
(10)CJAG F F C F
(11)CJAHI F C C F
(12)JACJHI F F C F
(13)ABCF C C C C
(14)AJCD A A A A
(-15-)ABECF F C C
-Northern Study Area
(1)ABC A A A A
(2)ABDC C A C C
(3)AEDC F C F F
(4)AEF F C F F
A =recommended
C =acceptable but not preferred
F =unacceptable
I
I
~I
,l
,1
'(
1
)
I
)
I
I
I
!
!
)
I
1
I
)
j
TABLE B.217.13:ENVIRONMENTAL CONSTRAINTS -SOUTHERN STUDY AREA (WILLOW TO ANCHORAGE/POINT MACKENZIE)
1 (ABC')
Corridor Segment
2 (ADFC)3 (AEFC)
Length (miles)
Topograph /Soils
Land Use
Aesthetic
Cultural ~esourcesl/
Vegetatio
Fish ResoUrces
Wildlife
73
Some soils with severe limita-
tions to off road travel;some
good agricultural soils
No existing ROW in AB;resi-
dential uses near Palmer;
proposed capital site;much
U.S.Military Wdl.,Private,
and Village Selection Land
Iditarod Trail;trail paral-
leling Deception Ck.:Gooding
L.birdwatching area;5
crossings of Glenn Hwy,1
crossing of Parks Hwy
Archeologicsites -DATA VOID
Wetlands along Deception Ck.
and at Matanuska River
crossing;extensive clearing
in upland,forested areas
needed
5 river and 28 creek cross-
ings;valuable spawning sites,
especially salmon:Knik area,
Matanuska area,DATA VOID
Passes through or near water-
fowl and shorebird nesting and
feeding areas,and areas used
by brown bear
38
Most of route potentially wet,
with severe limitations to
off road travel;'some good
agricultural soils
Trail is only existing ROW;
residential and recreational
areas;susitna Flats Game
Refuge;agricultural land
sale
susitna Flats Game Refuge;
Iditarod Trail;1 crossing of
Parks Hwy
Archeologic sites -DATA VOID
Extensive wetlands;clearing
needed in forested areas
1 river and 8 creek crossings;
valuable spawning sites,
especially salmon:L.susitna
R.,DATA VOID
Passes through or near water-
fowl and shorebird nesting,
feeding,and migration areas,
and areas used by fur bearers
and brown bear
39
Same as Corridor 2
No known existing ROW;recrea-
tional use areas,including
Nancy Lakes;lakes used by float
planes;agricultural land sale
Lake area south of Willow;
lditarod Trail;1 crossing of
Parks Hwy
Archeologic sites -DATA VOID
Extensive wetlands;clearing
needed in forested areas
1 river'and 8 creek crossings;
valuable spawning sites,
especially salmon:L.susitna
R.,DATA VOID
Same as Corridor 2
Environmental Ratingl!C A F
1-1 Coastjal area probably has many sites;available literature not yet reviewed.
2-1 A =Jecommended;C =acceptable but not recommended;F =unacceptable
I~ABlE 8.2.7.14:ENVIRONHENTALICONSTRAINTS CENTRAL STUDY AREA (DAM SITES TO INTERTIE)(Page 1 of J)
1 (ABeD)!2 (AI£CO)
Corridor Segment
J (AJCF)4 (AIlCJHI)5 .(AI£CJHI)
Environmental Retingl!C
Length (miles)
Topography/Soila
Land Use
Aaathetica
Cultural Raaourcea
Vegetation
Fieh Reaources
Wildlife Reaourcea
40
Cr08!JaaaBveral daep ravinea;1
about 1000'change in ~leva-I
tion;!aome wet aoUa !
Little exieting ROW except
Corpa Rd.;mostly Village
Sel~ction:and Private Lands
Fog lakesI Stephan Lake
,
Archeolog~c aitea near watanal
dam .aHe,Stsphan lake and fog
lakaa;DATA VOID from Gold Ck~
to Devil Canyon;hiatoric I
aitesnea~the communities of
Gold Creek and Canyon !
Wetlanda fneastern third of i
corrIdor;'extensive forest-i
clearing needed I
1 river and 17 creek cross-
inga;valusble spswning areas,
especially;grayling:DATA VOI~
i
unide.ntified rapt or nest Ii
located on trib.to Susitns;
passeathrough,habitat for:II
raptors;furbaarera,wolves,
wolverine,:brown bear,cariboti
I
45
Crosaea aeveral deep raviJea;
about 2000'chenge in ele~a
tion;some.steep slopes;~ome
wet eoils
little exieting ROW exceptl
Corpa Rd.and at 0;rec.and
reaid.areaa;float plane:
areaa;moatly Village Selec-
tion and Private lsnda I
1 '.·1,fog lakes,Stephan lake;pro-
:poaed railroad extenaion,high
Icountry (Prairie &Chulitna
:Ck.drainages)and viewshed of
!Alaaka Range
ISame ss Corridor 1
!Wstlsnda in eastern half of
~orridor;extenaive foraat~
:clearing needed
~river and 17 creek cross~
~ngs;vslusble spawning areaa,
,eapecially grayling:DATA ~OIO
1
Paaaaa through habitat forI
~aptora,waterfowl.migrsting
,owans,furbearere,:cariboui
wolves,wolverina,brown '
J
f
41
Crosaes several,deep ravinea;
sbout 2000'change in eleva-
tion;some ateep alopea;aome
aome wet aolls
No existing ROW except at f;
rec.areae;float plane areae;
mostly Village Selection and
Private Land;reaid.&rec.
devalopment in area of Otter
l.and old aled road
Viawahed:of Alaaka Range &
'High lake;propoaed acceae
road
Archeologic aites by.Hatana
dam site,&near Port'liga Ck.l
Susitna R.confluenca,poasi-
ble aites elongSuaitna R.;
hiatoric aitea near communi-
tiea of Gold Ck.and Canyon
foreat-clearing.needed in
weatern half
14 creek croeaing,valuable
spawning areas,especially
grayling and salmon I Indian
River,Portage Creek,DATA
VOID
Golden eagle nest along Devil
Ck.near High l.,active raven
neat on Devil Ck.;passea
through habitat ,forI raptora,
furbearera,wolvee,brownbaar
C
n
Crosses several deep ravinea;
>2000'change in elevation;
routing above 4000';eteep
alopea;aome wet soils;
shallow bedrock in mta.
No existing ROW,rec.areaa
ieolated cabine;lakee ueed
by float planes;much Village
Selaction land
foglakee;Stephan·lake;pro-
poeed acceee road;viewahed of
Alsska Range
Archeologic eitee near WataOB
dam aite,Stephan L.and fog
lakea;poeeible aitea along
paae between drainagee,DATA
VOID betwean H and "I
Small wetland Brese in JA
area;exteneive foreet-
clearing needed;DATA VOID
1 river and 42 creek croee-
inge;valuable epawning areae,
eepecially grayling
Golden eagle neet along Devil
Ck.near High L.;caribou
movement area;psaaee through
habitat for I reptora,watar-
fowl,furbearere,wolves,
wolverine,brown bear
f
82
Croasea several deep ravinea;
chan gee in elevation >2000';
routing above 4000';steep
slopes;eome wet eoilei ehallow
bedrock in mts.
Same aa corridor 4
fog lakee;Stephan Lske;High
Lake;propoeed accees rosd;
viewshed of Alaska Ranga
Same as Corridor 4
WBtlands in JA and Stephan Lake
areas;exteneive foreat-clearing
neaded
42 creek crosainga;valuable
spawning areaa,especially
grayling and salmon:DATA VOID
Same as Corridor 4 with impor-
tant waterfowl and migrating
ewan habitat at Stephan laka
f
}j ,IA=recommended,C =acceptabl~but not recommended,f =unacceptablej·i
---"
,~----
TABlE 8.2.7.114 (Page 2 of 3)
Cor ridor Segment
6 (CIlAHI)7 (CEIlAHI)8 (CBAG)~(l::E81!1!)10 (CJAG)
length (mile
Topography/Sbila
land Uae
Aeathatica
cultural Raauurcea
Vegatation
Fiah Reaourcea
Wildlife ReaGurcea
Environmanta!Rating
68
Croases aeveral dsep ravinsa;
changea in elevation of about
1600';routing above 4000';
steep alopea;BomB wet aoils;
shallow bedrock in mta.
No known exiating ROW;rec.
areas and iaolated cabina;
float plana area;Suaitna area
and near I are Village Selec-
tion lands
Fog lakes and Staphan lake;
Tsusena Butte;viewshed of
Alaska Range
Archeologic aitas naar Watana
dam aite,Fog lakes &Stephan
lake;DATA VOID between H and
I
Extenaive wetlands from 8 to
near Tausena 8utte;extensive
forest-clearing needed
32 creek crosainga;valuable
apawning areas,espacially
grayling:DATA VOID
8ald eagle nest a.e.of
Teuaena Butte;erea of caribou
movament;paasea thrOUgh
habitat forI raptora,water-
fowl,furbearera,wolvea,
wolvarine,brown bear
F
73
Croases saveral deep ravinea;
change in elevation of about
1600';routing abova 3000';
steep alopaa;aoma wet soila;
shallow bedrock In mta.
Same aa Corridor 6
For Fog lakes and Stephan
lake;high country (Prairie-
Chunlina Cka.);Tauaana Butte;
viewahed of Ala aka Range
Sama aa Corridor 6
Extensive wetlands in Stephsn
l.,Fog lskea Tsusena Butte
sress;extensivs foreat-
clesring needed
45 creek crossings;vsluable
spswning areas,eapecially
grayling:DATA VOID
Same aa Corridor 6,with
important waterfowl and
migrating awan habitat at
Stephan lake
F
90
Crosaes aeveral deep ravinea;
change in elevation of about
1600';routing above 3000';
ateep alopes;some wat Boils;
ahallow bedrock in mta.
No exiating ROW;rec.areas
and isolated cabina;float
plane areas;air atrip and
airport;much Village Selec-
tion and Federal land
Fog lakea;Stephan lake;
•access road;scenic area of
Deadman Ck.;viewahed of
Alaaka Range
Archeologic aites by near
Watana dam aite,Fog lakea,
Stephan Lake end along
Deadman Ck.
Wetlanda between 8 and moun-
tains;extenaive forest-
clearing needed
1 riv,er and 43 creek croas-
inga;valuable spawning areaa,
espacially grayling:DATA VOID
Important bald eagle habitat
by Denali Hwy.&Deadman L.;
unchecked bald eagle neat near
Tsusena Butte;passes through
habitat forI raptors,fur-
bearera,wolvea,wolverine,
brown baar
F
h"
95
Crosses several deep ravines;
changaa in alevation of about
1600';routing above 3000';
steep alopes;aome wet aoila;
shallow bedrock in mta.
Same aa Corridor 8
Fog lakes;Stephan lake;pro-
posed acceas road;high
country (Prairie and Chunilna
Cks.);Deadmsn Ck.;viewshed
of Alaska Range
Same as Corridor 8
Wetlands in Stephan L./Fog
"Lakes areaa;extenaive
foreat-clearing needed
1 river and 48 creek cross-
ings;valuable spawning areas,
especially grayling:DATA VOID
Sama aa Corridor 8,with
important waterfowl and
migrating swan habitat at
Stepahn Lake
F
91
Same as Corridor 8
No exiating ROW;rec.areas and
isolated cabina;float plane
areas;air strip and airport;
mostly Village Selection and
Fadaral land
High Lakes area;proposed accesa
rosd;Deadman Ck.drainage;view-
shed at Alaska Range
Archeologic sites naar Watana
dam aite and along Deadman Ck.
Small wetlands in JA area;
extans~ve forest-clearing needed
1 river and 47 creek cross-
ings;vslusble spswning sreas,
especislly grayling:DATA VOID
Golden esgel neat sIong Devil
Ck.near High lake;unchecked
bald esgel nest near Tsusena
Butte;area of caribou movement;
passes through habitst for:
raptors,waterfowl,furbearers,
brown besr
F
TABlE 8.2.7.14 (Page J of J)
::¢orridor Segment
11 {!:JAHI)12 (JA-CJf!I)IJ (ABCF)~(A.lCQL __12 (AgCr)
length (miles)69 jo 41 41 145
Topography/Soila
land Use
Aesthetice
Culturel Resources
Crossee 'eeveral deep ravines;
changes 1n elevation of about
1000';r~uting:above JOOO';
steep elopea;aome wet aoila;
shallow bedrock in mta.
No exiating ROW;rec.areas &
iaolated cabins;float plane
areas;mostly ,Village Selec-
tion and Private land
High lake~araa;propoaed
acceaa road;viewahed of
Alaaka Rrnga ;
i
Archeologic aitea near Watana
dam site!'
Same BB Corridor 11!'
:INoexiating ROW;rec.areaa
~d !iaolated cabina;float
plane area;mostly Villaga
Salection and Private land
i
High lakea area;propoaed
Bcce~a road,Tsuaena Butte;
yie~ahedofAlaskaRange
~rch~0109ic site,near Wahoo
~m ~ite;possible eite~
~ass:between drainages
!'
Crossea several deep ravinea;
about 1000'change in eleva-
tion;some wet soile
No known exieting ROW;except
at f;rec.areea;float plane
areas;reaid.and rec.use
near OHer l.and old aled
rd.;iaolated cabins;moatly
Village Selection land;aoma
Pri vate land
fog lakea,Stephan l.
Archeologic aitea n~ar Watana
dam eite,Portage Ck./Suaitna
R.confluence;Stephan l.'and
fog lakea;historicieitee
near communitiea of Canyon
and Gold Ck.
Croaaes deep ravine at Devil
Ck.;about 2000'change in
elevation;routing above
3000';some steep alopea;
some wet soila
little exieting ROW except
Old Corpa Rd.and at 0;rec.
areaa;iaolated cabins;much
Village Selection land;some
Private land
Viewehed of Alaska Range and
High lake;propoaed acceea
road
Archeologic eitea by Watana
dam aite,poesible aitee along
Sueitoo R.;historic sltsa
near communitiea of Canyon
and Gold Ck.
Croases several deep ravines;
sbout 2000'change in elevation;
some wet soils
No known existing ROW except
at F;rec.areas;float plane
areas;resid.and rec.use
near Otter l.&old sled rd.;
isolatsd cabins;mostly
Village Selection land with
some Private land
fog lakes;Stephan lake;high
country (Prairie andChulina Cka.
drainages);viawahed of Alaska
Range
Same as Corridor 13
f f
Wetlande in eaetern half of
corridor;extensive forest-
clearing needed
15 creek croseings;valuable
spawning areas,expecially
grayling and salmon:Indian
River,Portage Ck.,DATA VOID
Important waterfowl and
migrating swan hsbitat at
Stephan l.;pasaes through
habitat for:raptors,water-
fowl,furbesrers,wolves,
wolverine"brown bear,caribou
Golden eagel neet in Devil
Ck./High lake area;active
raven nest on Devil Ck.;
pasaea through habitet for:
reptors,furbearers,wolves,
brown bear,caribou
A
1 river and 16 creek cross-
ings;veluable spawning areas,
eapacially grsyling:DATA VOID
forest-clearing needed in
weet ern half
Wetlands in eastern third of
corridor;extensive forest-
clearing needed
15 creek croasings;:valusble
spswning aress,especially
grayling and salmon:Indian
River,Portage Ck.,DAT~VOID
Unidentified ~aptor :nsst on
tributary to ~uaitnB;paases
through habitst for:raptors,
furbearers,wolves,wolverine,
brown bear,csribou
C
Small wetland areaa in JA
areal fairly extensive foreat-
~leaffng needed
40 c~eek croasings;vsluable
qpaw~ing sreas,especislly
gray~ng and salmon:DATA VOID
I '
I !
dOldl,n eagle nest along De.vil
Ok.tJoar,High Lake;pasaea
~hrough habitat for:rapt ora,
~urbearera,wolves,brown
bear!
Ifl
:!,':
Small wetland areas 1n JA
area;aome foreat-clearing
needed I
36 creek croaainga;valuable
spawning araaa',eapecially
grayling and ealmon:DATA VOID
Golden eagle neat along Devil
Ck.near:High lake;beld eagle
neat a.e.of Tausena Butte;
passeathroughihabitat for:'
raptora,!furbearera,brown
bear '
Vegetetion
Wi'ldlife Resources
Environmental Rating
fish Resourcee
TABlE B.2.7.15:ENVIRONMENTAL CONSTRAINTS NORTHERN STUDY AREA (HEALY TO fAIRBANKS)
length (mHes)
1 (AOC)
90
2 (AIn:)
86
Corridor Segment
J (AEOC)
115
4 (AEf)
105
TopographyJsoils
land Use
Aesthetics
Cultural Resources
Vegetation
fish Resoutces
Wildlife Resourcesl!
Some wet soils with severe limita-
tions to off-road traffic
Air strip;residential aresa and
isolated cabina;some U.S.Military
Withdrawal and Native land
J crossinga of Parks Hwy;Nsnana
R.-scenic area
Archeologic sites probable since
there is a known eite nearby;DATA
WID
Extensive wetlande;forest-clearing
needed msinly north of the Tanana
River
4 river and 40 creek crossings;
valuable spawning sites:Tanana
River,DATA VOID
Paases through or near prime hsbitat
for:peregrinea,waterfowl,fur-
bearera,moose;passes through or
near important habitat for:pere-
grinee,golden eagles
Severe limitations to off-road
traffic in wet soils of the flats
No exiating ROW n.of Browne;
scattered reeidential and isolated
cabins;airstrip;fort Wainwright
Military Reservation
J crossinge of Parks Hwy;high
visibility in open flats
Dry Creek archeologic eite near
Healy;possible sites elong river
crosaings;DATA VOID
Probsbly extensive wet lends between
Wood and Tanana Rivers;extensive
foreat-clearing needed n.of Tanana
River
5 river and 44 creek croesings;
valuable spawning sites:Wood River,
DATA VOID
Passes through or near prime hsbitat
for:peregrinee,waterfowl,fur-
bearers;paeses through or near
important habitat for:golden
eagles,other raptors
Chsnge in elevation of ebout 2500';
steep elopes;shallow bedrock in
mts.;ssvere limitations to off-
rosd traffic in the flats
No existing ROW beyond Healy/Cody
Ck.confluence;isolated cabins;
airstripa;fort Wsinwright Military
Reservation
1 crosaing of Parks Hwy.;high
visibility in open flata
Dry Creek archeologic aite near
Hesly;possible sites near Japsn
Hills and in the mta.;DATA VOID
Probably extensive wstlands between
Wood and Tansna Rivers;extensive
foreat-clearing neelkld n.of Tanana
River;data lacking for southern part
J river and 72 cresk croasings;
valuable spawning sitea:Wood River,
DATA VOID
Passes through or near prime habitat
for:peregrines,waterfowl,fur-
burers,caribou,aheep;passss
thrOUgh or near important-habitat
for:golden eagles,brown besr
Same aa Corridor J
Airatrips;isolated cabins;
fort Wsinwright Military
Reservation
High visibility in open flats
Archeologic sites near Dry Creek
and fort Wainwright;possible
sites nesr Tanans River;DATA
VOID
Probsbly extensive wetlands
between Wood and Tansns Rivers
J river snd 60 creek crossings;
valusble spawning sites:Wood
River,DATA VOID
Passes through or near prime
hsbitat for:peregrines,bald
eagles,waterfowl,furbeerers,
caribou,sheep;passea thrOUgh
or near important habitat for:
golden eagles,brown bear
Environmental Ratingl!A C f f
l-/sourCl:VsnBallenberghe persons1 communication.Prime habitat =minimum amount of land necesaary to prOVide a sustained yield for a species;based upon knowledge
of tha species'needs from eeperience of ADf&G personnel.Important habitat =land which ADf&G considers not as critical to a species as ia Prime habitat,
but ia valuable.
2-1 A =r commended,B =acceptable but not preferred,C =unaccepta~le
TABLE B.2.7 .16:TEffiNI CAL,EOONOMIC AND ENVIRONMENTAL
CRITERIA USED IN OORRIOOR SCREENING
Technical
Primary
J
)
I
j
Topography
Climate and
Soils
Length
Elevat ion
Secondary
Economic
Primary
Secondary
Envi ronme nta 1
Primary
Vegetation and Clearing
Highway and River Crossings
Length
PresenC!3 of Right:-of-Way
Presence of Access Roads
Topo~raphy
Stream Crossings
liighW~y~C'i'['l,4RailrQC'icl CroE.si.rrg§_
Aesthetic and Visual
Land Use
Presence of Existing Right-of-Way
Existing and Proposed Development
Length
Topography
Soils
Cultural Reservoir
Vegetation
Fishery Resources
Wildli fe Resources
}
1
../
1
Table B.3.1.1:PERTINENT DATA FOR GAGING STATIONS
USGS Gage Susitna Drainage p,eriods of Record
Station Name Number River Mile Area (mi 2 )Streamflow (Continuous)17 Water QualityV Agency
Susitna River nr.DenalI 15291000 290.8 950 5/57-9/66,11/68-Present 1957-66,1968-69,1974-Present USGS
(6/30/82)
Cantwell 15291500 223.1 4,140 5/61-9/72,5/80-Present 1962-72,1980-Present (7/27/82)USGS
Cantwell -223.1 4,140 -1980-81 R&M
Consult.
Susitna River nr.Watana Damsite -182.i1/5,180 8/80-Present 10/80-12/81 R&M
Consult.
Susitna Rliver at Gold Creek 15292000 136.6 6,160 6/49-Present 1949-58,1962,1967-68,1974-Present USGS
(9/16/82)
Susitna Rliver at Gold Creek -136.6 6,160 -1980-Present (10/14/82)R&M
Susitna Rliver at Sunshine 15292780 83.9 11,100 5/81-present 1971,1975, 1977,1981-Present
(10/13/82)
Susitna Rliver at Susitna Station 15294350 25.8 19,400 10/74-Present 1955,1970,1975-Present (10/5/82)USGS
Maclaren IRiver nr.Paxson 15291200 259.aM 280 6/58-Present 1958-61,1967-68,1975 USGS
Chulitna IRiver nr.Talkeetna 15292400 98.o!V'2,570 2/58-9/72,5/80-Present 1958-59,1967-72,1980-Present USGS
(6/3/82)
Ta1keetnal River nr.Talkeetna 15291500 97.o!V'2,006 6!.64-Present 1954,1966-Present (10/14/82)USGS
Skwentna IRiver nr.Skwentna 15294300 28.021 2,250 1O/59-Present 1959,1961,1967-68,1974-75,USGS
1980-81
Yentna Riwer nr.Susitna Station 15294345 28.o!V'6,180 10/80-Present 1981-Present (8/11/82)USGS
t recent data available.
a continuous water quality monitor was installed at river mile 183.0.
mile at tributary's confluence with Susitna R~ver.
mile at Yentna-Susitna confluence.
1~All ~treamf1ow gage stations are currently active,however,flow data included in this document is through September 1981.
2-1 "Pre6ent"in periods of record indicates station is active as of January 1983.A date after "Present"indicates the
3-1
4-1
5-1
Source:IUSGS and R&M
----~--~-,-~--_.._----~_.._--"
-~---------,~_._--..--'"----.~~-------~._._~.-------
TABLE B.3.1.3:WATANA NATURAL MONTHLY FLOWS (CFS)
YEAR OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP ANNUAL
1951 3299 1107 906 808 673 620 1302 11650 18518 19787 16478 17206 7734
1952 4593 2170 1501 1275 841 735 804 4217 25773 22111 17356 11571 7777
1953 6286 2757 1281 819 612 671 1382 15037 21470 17355 16682 11514 8035
1954 4219 1600 1184 lO88 803 638 943 11697 19477 16984 20421 9166 7401
1955 3859 2051 1550 1388 1051 886 941 6718 24881 23788 23537 13448 8719
1956 4102 1588 1039 817 755 694 718 12953 27172 25831 19153 13194 9051
1957 4208 2277 1707 1373 1189 935 945 10176 25275 19949 17318 14841 8381
1958 6035 2936 2259 1481 1042 974 1265 9958 22098 19753 18843 5979 7770
1959 3668 1730 1115 1081 949 694 886 10141 18330 20493 23940 12467 8011
1960 5166 2214 1672 1400 1139 961 1070 13044 13233 19506 19323 16086 7954
1961 6049 2328 1973 1780 1305 1331 1965 13638 22784 19840 19480 10146 8603!1962 4638 2263 1760 1609 1257 1177 1457 11334 36017 23444 19887 12746 9833,1963 5560 2509 1709 1309 1185 884 777 15299 20663 28767 21011 10800 9278
I 1964 5187 1789 1195 852 782 575 609 3579 42842 20083 14048 7524 8263
1965 4759 2368 1070 863 773 807 1232 10966 21213 23236 17394 16226 8451
1966 5221 1565 1204 1060 985 985 1338 7094 25940 16154 17391 9214 7374,
1967 3270 1202 1122 1102 1031 890 850 12556 24712 21987 26105 13673 9096
I 1968 4019 1934 1704 1618 1560 1560 1577 12827 25704 22083 14148 7164 8032
1969 3135 1355 754 619 608 686 1262 9314 13962 14844 7772 4260 4912
1970 2403 1021 709 636 602 624 986 9536 14399 18410 16264 7224 6115
1971 3768 2496 1687 1097 777 717 814 2857 27613 21126 27447 12189 8589
1972 4979 2587 1957 1671 1491 1366 1305 15973 27429 19820 17510 10956 8963
1973 4301 1978 1247 1032 1000 874 914 7287 23859 16351 18017 8100 7112
1974 3057 1355 932 786 690 627 872 12889 14781 15972 13524 9786 6314
1975 3089 1474 1277 1216 1110 1041 1211 11672 26689 23430 15127 13075 8403
1976 5679 1601 876 758 743 691 1060 8939 19994 17015 18394 5712 6835
1977 2974 1927 1688 1349 1203 1111 1203 8569 31353 19707 16807 10613 8233
1978 5794 2645 1980 1578 1268 1257 1408 11232 17277 18385 13412 7133 6992
1979 3774 1945 1313 1137 1055 1101 1318 12369 22906 24912 16671 9097 8184
1980 6150 3525 2032 1470 1233 1177 1404 10140 23400 26740 18000 11000 8908
1981 6632 3044 1790 1858 1592 1262 1641 .14416 16739 27601 30542 11669 9985
1982 5700 2650 1863 1700 1234 898 1196 10879 21444 20445 13206 13890 7968
1983 5154 2132 1893 1797 1610 1427 1565 11672 20401 18761 20862 11192 8253
MAX 6632 3525 2259 1858 1610 1560 1965 15973 42842 28767 30542 17206 9985
MIN 2403 1021 709 619 602 575 609 2857 13233 14843 7772 4260 4912
MEAN 4567 2064 1453 1225 1035 936 1158 10625 22980 20747 18366 10875 8046
B.3.1.4:DEVIL,CANYON NATURAL MONTHLY FLOWS (CFS)
YEAR OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP ANNUAL
1950 5,758 2~405 1,343 951 736 670 802 10,491 18,469 21,383 18,821 7,951 7,482
1951 3,652 1,231 1,031 906 768 697 1,505 13,219 19,979 2,157 18,530 19,799 8,574
1952 5,222 2,539 1,758 1 484 943 828 ,879 7,990 30,014 24,862 19,647 13,441 8,884
1953 7,518 3,233 1,550 1 000 746 767 1,532 17,758 25,231 19,184 19,207 13,928 9,305
1954 5,109 1,~21 1,387 1 224 930 729 1,131 15.;'286 23,188 19,154 24,072 11,579 8,809
1955 4,830 2,507 1,868 1 649 1,275 1,024 1,1O~8,390 28,082 26,213 24,960 13,989 9,658
1956 4,648 1,189 1,207 922 ,893 852 867 15,979 31,137 29,212 22,610 16,496 10,551
1957 5,235 2,774 1,987 1 583 1,389 1,105 1,190 12,474 28,415 22,110 19,389 18,029 9,633
1958 7,435 3,590 2,905 1 792 1,212 1,086 1,437 11,849 24,414 2,163 21,220 8,689 8,808
1959 4,403 2,000 1,371 1317 1,179 878 1,120 13,901 21,538 23,390 28,594 15,330 9,585
1960 6,061 2,623 2,012 1 686 1,340 1,113 :1.,218 14,803 14,710 21,739 22,066 18,930 9,025
1961 7,171 2,760 2,437 2 212 1,594 1,639 2,405 15,031 27,069 22,881 21,164 12,219 9,965
1962 5,459 2,~44 1,979 1 796 1,413 1,320 1,613 12,141 49,680 24,991 22,242 14,767 10,912
1963 6,308 2,696 1,896 1 496 1,387 958 811 17,698 24,094 32,388 22,721 11,777 10,353
1964 5,998 2,085 1,387 978 900 664 697 4,047 47,816 21,926 15,586 8,840 9,244
1965 5,744 2.;645 1,161 925 829 867 1,314 12,267 24,110 26,196 19,789 18,234 9,507
1966 6,497 1,908 1,478 1 279 1,187 1,187 1,619 8,734 30,446 18,536 20,245 10,844 8,663
1967 3,844 1,458 1,365 1 358 1~268 1,089 1,054 14,436 27,796 25,081 30,293 15,728 10,398
1968 4,585 2,204 1,930 1 851 1,779 1,779 1,791 14,982 29,462 24,871 16,091 8,226 9,129
1969 3,577 1,532 836 687 682 770 1,421 10,430 14,951 15,651 8,484 4,796 5,318
1970 2,867 1,146 810 757 709 772 1,047 10,722 17,119 21,142 18,653 8,444 7,012
1971 4,745 3,082 2,075 1 319 944 867 986 3,428 31,,031 22,942 30,316 13,636 9,614
1972 5,537 2~912 2,313 2 036 1,836 1,660 1,566 19,777 31,930 21,717 18,654 11,884 10,152
1973 4,639 2,155 1,387 1 140 1,129 955 987 7,896 26,393 17,572 19,478 8,726 7,705
1974 3,491 1,463 997 843 746 690 949 15,005 16,767 17,790 15,257 11,370 7,114
1975 3,507 1,619 1,487 1 490 1,342 1,272 1,457 14,037 30,303 26,188 17,032 15,155 9,567
1976 7,003 1,853 1,008 897 876 825 1,261 11,305 22,814 18,253 19,298 6,463 7,655
1977 3,552 2,392 2,148 1 657 1,470 1,361 1,510 11,212 35,607 21,741 18,371 11,916 9,411
1978 6,936 3,211 2,371 1 868 1,525 1,481 1,597 11,693 18,417 20,079 15,327 8,080 7,715
1979 4,502 2,324 1,579 1 304 1,204 1,165 1,403 13,334 24,052 27,463 19,107 10,172 8,965
1980 6,900 3,955 2,279 1 649 1,383 1,321 1,575 11,377 26,,255 30,002 20,196 12,342 9,936
1981 7,335 3,382 1,841 1 958 1,839 1,470 1,898 15,789 18,387 31,680 35,256 13,033 11,156
1982 6,384 3,270 2,207 2 086 1,559 1,094 1,574 12,490 ~4,439 22,877 14,536 16,427 9,079
1983 6,272 2,454 2,192 2 098 1,858 1,596 1,781 13,777 22,789 20,295 23,203 12,731 9,254
MAX 7,518 3,955 2,905 2 212 1,858 1,779 2,405 19,777 47,816 32,388 35,256 19,799 11,156
MIN 2,867 1,146 810 687 682 664 697 3,428 14,710 15,651 8,484 4,796 5,318
MEAN 5,374 ·2,402 1,693 1 415 1,202 1,074 1,324 12,404 25,821 23,025 20,600 12,420 9,063
~--~'---:
B.3.1.5:GOLD CREEK NATURAL MONTHLY FLOWS (CFS)
OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP ANNUAL
950 6335 2583 1439 1027 788 726 870 11510 19600 22600 19880 8301 8032
951 3848 1300 1100 960 820 740 1617 14090 20790 22570 19670 21240 9106
952 5571 2744 1900 1600 1000 880 920 5419 32370 26390 20920 14480 9552
953 8202 3497 1700 1100 820 820 1615 19270 27320 20200 20610 15270 10090
954 5604 2100 1500 1300 1000 780 1235 17280 25250 20360 26100 12920 9682
955 5370 2760 2045 1794 1400 1100 1200 9319 29860 27560 25750 14290 10256
956 4951 1900 1300 980 970 940 950 17660 33340 31090 24530 18330 11473
957 5806 3050 2142 1700 1500 1200 1200 13750 30160 23310 20540 19800 10384
958 8212 3954 3264 1965 1307 1148 1533 12900 25700 22880 22540 7550 9476
959 4811 2150 1513 1448 1307 980 1250 15990 23320 25000 31180 16920 10560
960 6558 2850 2200 1845 1452 1197 1300 15780 15530 22980 23590 20510 9712
961 7794 3000 2694 2452 1754 1810 2650 17360 29450 24570 22100 13370 10809
962 5916 2700 2100 1900 1500 1400 1700 12590 43270 25850 23550 15890 11565
963 6723 2800 2000 1600 1500 1000 830 19030 26000 34400 23670 12320 11073
964 6449 2250 1494 1048 966 713 745 4307 50580 22950 16440 9571 9800
965 6291 2799 1211 960 860 900 1360 12990 25720 27840 21120 19350 10169
966 7205 2098 1631 1400 1300 1300 1775 9645 32950 19860 21830 11750 9432
967 4163 1600 1500 1500 1400 1200 1167 15480 29510 26800 32620 16870 11219
968 4900 2353 2055 1981 1900 1900 1910 16180 31550 26420 17170 8816 9811
969 3822 1630 882 724 723 816 1510 11050 15500 16100 8879 5093 5596
970 3124 1215 866 824 768 776 1080 11380 18630 22660 19980 9121 7591
971 5288 3407 2290 1442 1036 950 1082 3745 32930 23950 31910 14440 10251
972 5847 3093 2510 2239 2028 1823 1710 21890 34430 22770 19290 12400 10886
973 4826 2253 1465 1200 1200 1000 1027 8235 27800 18250 20290 9074 8086
974 3733 1523 1034 874 777 724 992 16180 17870 18800 16220 12250 7631
975 3739 1700 1603 1516 1471 1400 1593 15350 32310 27720 18090 16310 10275
976 7739 1993 1081 974 950 900 1373 12620 24380 18940 19800 6881 8189
977 3874 2650 2403 1829 1618 1500 1680 12680 37970 22870 19240 12640 10109
978 7571 3525 2589 2029 1668 1605 1702 11950 19050 21020 16390 8607 8195
979 4907 2535 1681 1397 1286 1200 1450 13870 24g90 28880 20460 10770 9489
980 7311 4192 2416 1748 1466 1400 1670 12060 29080 32660 20960 13280 10748
981 7725 3569 1915 2013 1975 1585 2040 16440 19300 33940 37870 13790 11961
982 7463 3613 2397 2300 1739 1203 1783 13380 26100 24120 15270 17780 9800
983 6892 2633 2358 2265 1996 1690 1900 14950 24510 21150 24500 13590 9926
8212 4192 3264 2452 2028 1900 2650 21890 50580 34400 37870 21240 11961
IN 3124 1215 866 724 723 713 745 3745 15500 16100 8879 5093 5596
EAN 5840 2589 1832 1527 1301 1156 1424 13425 27554 24337 21852 13340 9733
II I
TABLE B.3•1.6:WEEKL~STREAMFiLOW AT WATANA (CES)l/(Page 1 of 5)
I
II
j
~EAR I
I 656 628
1950 802 774 7~9 869 876 791 559,512 576 558 523
550 557 6q3 717 1,711 6,115 10,442'10,845 13,591 14,369 13,924 21,992 16;255
15,817 17,953 19,6~1 21,345 21,448 19,853 18,160 14,972 11,275 8,096 9,178 6,205 6,282
4,54 1 4,029 3,518 2,007 .1,248 1,176 1,103 1,042 994 903 903 903 903
1951 828 812 812 812 ,757 667 667i 667 641 618 618 6,189 618I5427001,OJ 1 1,861 4,923 14,338 15,945 7,915 13,828 26,695 19,247 12,238 17,232
18,4Q4 21,682 20,7 °19,074 17,891 14,413 15,312 14,985 21,048 24,531 15,237 15,738 15,226
I 2,690 1,928 1,489 1,4897,559 5,055 3,6~4 2,855 2,793 1,908 1,761 1,489 1,489
1952 1,349 1,299 1,2~9 1,299 1,069 819 819 819 784 730 730 730 730
796 796 7~6 696 ,909 1,132 1,549 3,357 16,784 19,892 28,174 30,555 27,039
23,526 16,714 21,31F 23,150 30,727 19,888 15,618 11,855 13,935 15,561 10,522 9,086 12,430
8,559 7,982 5,5~6 4,049 2,938 3,377 2,164 2,542 1,913 1,250 1,250 1,250 1,250
1953 880 820 820 820 722 598 498 598 606 678 678 678 678I
4~6 486 7~5 1,308 1,007 13,666 12,435,21,448 6,652 2].,821 21,482 17,488 20,466
17,377 15,695 17,0~0 17,745 20,931 17,859 14,312 14,731 17,519 14,058 12,806 10,679 9,299
6,126 50,809 3,748 2,971 1,821 1,738 1,608 1,497 1,361 1,174 1,174 1,174 1,174
1954 1,120 1,099 1,0~9 1,099 1,099 984 794 794 794 716 630 630 630
506 506 8~0 930 4,308 8,521 13,802 15,823 14,807 19,799 19,022 18,245 22,178
19,307 15,396 14,9~1 14,981 24,614 20,049 20,049 20,049 18,930 11,256 9,676 9,025 6,621
4,746 4,461 3,3~9 3,359 2,716 2,159 2,032 1,796 1,756 1,657 1,624 1,431 1,431
1955 1,546 1,561 1,338 1,249 1,179 1,052 1,052 949 979 879 879 879 879
I82882884 8 828 2,519 3,321 3,882 11 ,626 12,771 17 ,007 27,727 30,081 28,168
29,660 24,776 19,124 22,869 20,805 19,270 19,771 24~039 34,146 17,921 13,691 11,128 10,015
I6,059 4,461 3,6~3 3,129 2,062 1,721 1,581 1,393 1,306 1,027 1,027 1,027 1,027
1956 848 310 810 810 809 750 750 750 739 689 689 689 689
641 641 641 641 1,798 8,483 12,106 24,085 15,966 27,294 35,522 26,081 22,994I24,335 26,536 26,7~9 26,153 24,666 ,446 29,285 16,173 ·13,792 11,446 16,046 15,637 11,446
5,279 5,279 3,5~3 3,300 2,789 2,342 2,247 2,123 '2,035 1,908 1,852 1,509 1,509
1957 1,399 1,378 1,3~8 1,378 1,310 1,193 1,193 1,193 1,079 920 920 920 920
837 837 8~7 837 2,452 4,269 4,269 15,611 23,050 31,747 28,053 24,892'17,043
19,864 18,252 20,4~3 22,198 17,659 17,664 17,568 16,III 17,894 14,143 15,435 15,008 16,474
7,628 6,544 5,3V 5,503 3,997 3,287 2,815 2,314 2,837 2,991 2,551 1,902 1,544
'------..~
I",,-------,:
B.3.1.6 (Page 2 of 5)
19518 1.939 1.514 1,408 1.332 1,101 1,152 1.038 959 959 1,024 1,000 939 939
950 1.063 1,153 1,398 3.001 5,917 8,267 15,742 16,842 24,642 24,642 21,247 19.363
18,442 18,442 18.442 18.082 32,829 23,946 17,783 14,415 9.969 6,695 6,695 5.128 5.862
4.604 5,050 3,865 2,689 2.392 2,068 1.760 1,352 1,215 797 879 1,375 1.375
19519 1.150 1.190 1.056 1,035 1,051 1,027 984 879 797 683 683 683 683
666 666 952 999 1,891 2.951 12,694 17,856 14,298 20,496 15,311 18.247 20,418
21.688 20,819 22,556 17,816 18,373 14.392 18,474 34.121 33,290 20,953 10.824 8.131 8,765
8.534 5.896 3,243 4.051 2,692 2,292 2.194 2,064 1.962 1,656 1.656 1,656 1,656
1.541 1.523 1,360 1,295 1.227 1,175 1.152 1,096 1,062 1,041 996 882 882
694 694 910 945 4.703 6.668 12.886 20,055 29.716 11,838 12,275 12,710 13.971
19,936 14,780 17,003 23,312 26.486 20.467 18,086 17,477 16,811 14,281 22,570 15,996 13,691
9,778 7,102 5,050 3.678 2,753 2.516 2.319 2.958 2.118
2,126 2.985 1.833 1.833
1.776 1,773 1,825 1.846 1.601 1.317 1,297 1,246 1,181 1.097 1,222 1.535 1.535
1,617 1.617 1,783 1,811 5,580 10,306 17,835 16,989 15.795 14.578 23.810 29.749 24.996
18,341 19,253 19.937 29.655 22,581 23.083 19,710 18,708 13.842 9,309 10.560 10,059 11.578
8.304 3,663 3.663 3.663 2.910 2.187 2.187 2,187 2.967 1,742 1.742 1,742 1,742
1,645 1.626 1,626 1.626 1.462 1.237 1.237 1.237 1.207 1~174 1,174 1,174 1.174
1.336 1.335 1.335 1.335 3.165 3,896 10.571 15,580 25.042 25,502 49,464 42,296 29.941
24.659 24.067
20.979 24,659 22,051 19,487 19.487 19.487 19,844 18,961 11.972 9.699 11.158
7.677 5.856 5.094
4,603 3,273 2,427 2.427 2,427 2.243 1,684 1,684 1.684 1.684
1,346 1.303 1,303 1,303 1,284 1.203 1.203 1,203 1.015 870 870 870 870
680 680 680 2.138 2,871 16,185 26,173 29,395 20,039 20,039 20,039 20,039 20,039
25,591 30.081 31,343 26.765 24,772 22.882 19,853 20,996 17,689 13,134
11,736 8.384 9.514
7.204 6,067 4,963 3,760 2,277 2,937 1,803 1,489 1.454 1,358 1,.311 1,038 1,038
913 888 830
807 815 818 802 760 696 612 588 524 524
588 588 637 646 524 521 699 1.548 17 ,791 66,753 45.845 38,257 27.669
22.261 22.938 21.646 14,854 16.893 15,984 12.889 13,741 11.603 8.901 7.255 7.294 7,139
5.814 6,596 4.258 3,387 2,593 2.408 2,383 2.656 1.708 1.175 1.047 952 952
880 866 866 866 821 764 764 764 785 809 809 809 809
1.050 1.050 1.324 1,370 1.702 4.582 7,973 14,365 28,598 18,020 19.249 18.396 27.076
25,264 25,478 23,730 20,581 18,313 16,343 25,247 16.925 9.394 14,093 17,314 15.844 20,946
10,948 6.087 2.852 2,359 2,043 1.676 1.481 1.412 1.361 1,265 1.223 1.174 1.129
1.075 1.062
1,062 1,062 1.026 980 980
980 983 985 985 985 985
1,091 1.091 1,432 1.490 2.210 2,873 5,322 10.202 16,017 37,660 26,954 22,768 19,214
15,178 14.458 15,132 17,122 22,511 18,320 15.064 18.252 14,605 10,023 9,733 9,623 8.022
5,525 3.605 2,802 1,896 1,290 1.192 1,192 1,192 1,173 1,119 1,119 1,119 1,119
~;
~--'
TABLE B.3.1.6 (Page 3 of 5)
YEAR I
I
1967 1,105 1,106 1,106 1,106 1,077 Ii.037 1,037 1,037 965 882 882 882 882
771 771 790 910 1,409 41,044 14,066 19,680 23,533 22,187 29,069 24,227 23,703
17,634 16,574 24,423 28,466 21,665 2°1,177 44,290 24,653 16,555 23,511 13,875 10,087 8,761
5,636 4,692 3,669 2,797 2,340 11,987 1,881 1,812 1,780 1,740 1,740 1,669 1,657
1968 1,633 1,634 1,634 1,611 1,552 11,561 1,561 1,561 1,561 1,560 1,560 1,560 1,560
1,544 14,885 1,556 1,552 1,787 21,353 10,464 27,061 21,911 21,507 29,938 20,356 22,099
24,724 22,504 21,723 2(},991 18,327 161,541 13,759 12,436 11 ,024 9,099 9,115 5,821 5,903
4,162 3,593 2,768 2,457 2,109 11,631 1,241 1,084 901 809 767 724 687
1969 658 640 ,598 1,598 598 i 587 599 630 630 655 673 709 732
779 919 1,196 1,696 2,867 5!,116 9,727 17,064 10,290 11,525 14,689 15,092 14,614
13,051 16,518 16,974 1~,188 11,668 12~201 6,318 5,126 4,792 5,256 4,595 3,939 3,781
3,018 2,841 2,489 1,680 1,~32 .11,202 950 842 784 735 699 694 694
1970 656 656 628 617 618 1628 589 589 589 605 616 645 645
769 846 969 1,176 1,634 31,900 13,817 12,474 15,221 12,989 12,531 11,864 19,977
22,089 16,855 18,059 17,267 21,606 18~880 14,586 16,486 11,350 9,396 7,477 7,616 4,850
4,991 4,166 3,393 2,885 2,923 2~796 2,543 2,249 2,013 1,886 1,761 1,614 1,446
1971 1,328 1,188 1,080 9,50 880 1821 746 746 730 716 716 716 716
717 744 808 I 904 1,098 1\,415 2,987 3,683 6,558 19,251 39,740 24,136 33,340
21,395 21,771 25,092 16,325 20,943 38~945 34,819 21,362 16,880 19,170 12,233 9,251 9,174
6,619 5,931 4,501 3,711 3,005 21,717 2,574 2,430 2,311 2,015 2,015 1,860 1,860
1972 1,790 1,642 1,642 1,642 1,643 1~528 1,465 1,464 1,403 1,416 1,351 1,351 1,329
1,241 1,241 1,189 ~,241 2,386 13',753 13,553 18,894 31,966 20,142 35,772 31,327 21,178
22,096 22,084 19,683 16,050 18,343 19~674 18,045 18,653 12,473 11,598 15,857 11,686 6,032
4,296 3,976 5,515 ~,090 2,727 2~210 1,887 1,738 1,519 1,356 1,210 1,186 1,186
1973 1,051 1,026 1,026 +,026 1,035 1~008 .1,008 1,008 ,929 868 868 ,868 868
879 879 879 929 1,227 2~355 8,066 11,190 13,811 17,385 28,985 31,344 20,593
18,980 18,143 13,728 14,810 15,752 18\,754 14,942 19,441 20,593 11,210 7,823 6,605 6,133
4,607 3,710 2,558 1,938 1,693 1~459 1,344 1,230 1,129 1,028 926 881 854
1974 816 ,811 778 . I 765 745 1707 694 662 663 648 636
605 605
594 620 747 l,189 2,059 5~341 9,964 22,246 25,280 16,013 13,675 12,785 13,651
14,383 17 865 16,395 1~,766 14,730 15~504 13,265 10,498 14,244 13,395 7,511 6,590 11,410
4,537 4 590 2,402 1,602 1,468 1 1,478 1,478 1,478 1,461 1,264 1,264 1,264 1,264
1975 1,270 1 203 1,203 1,203 1,200 1~123 1,123 1,081 1,051 1,040 1,040 1,040 1,040
1,036 1 047 1,142 ~,354 2,133 5~138 11,291 17,252 23,081 30,459 22,880 28,749 25,700
23,413 25 455 24,131 22,076 20,265 16~199 15,474 13,658 11,.762 9,359 15,849 14,847 14,301
7,559 6 664 6,139 3,621 2,720 1~937 1,475 1,173 1,011 925 80 855 809
i
of 5)
778 778 750 739 741 746 746 746 726 687 687 687 687
644 675 839 1,402 3,440 9,778 9,397 9,828 11,375 23,100 24,887 17,525 16,928
16,991 16,954 15,164 15,476 20,226 26,317 19,534 15,004 10,554 6,302 5,160 5,190 6,320
3,729 3,045 2,903 2,576 2,139 1,963 1,839 1,736 2,097 1,902 1,722 1,583 1,462
1,442 1,400 1,326 1,294 1,257 1,219 1,197 1,197 1,156 1,106 1,106 1,106 1,106
1,149 1,149 1,211 1,272 1,314 2,267 8,205 12,588 19,531 29,414 38,954 .31,928 28,489
18,502 20,572 21,740 18,089 19,531 18,939 17,328 17,519 11,066 8,643 12,235 11,736 11,288
8,782 6,882 6,046 4,510 3,355 2,862 2,578 2,392 2,223 2,108 2,015 1,955 1,808
1,741 1,641 1,557 1,496 1,403 1,285 1,247 1,247 1,212 1,258 1,258 1,258 1,275
1,251 1,251 1,251 1,322 3,355 11,862 16,195 10,959 11,660 13,979 19,417 16,614 20,703
19,608 18,215 18,416 18,064 16,600 15,674 14,572 12,160 8,756 9,287 8,372 6,293 5,367
4,195 4,701 3,796 2,849 2,736 2,368 1,774 1,558 1,502 1,483 1,349 1,214 1,170
1,185 1,138 1,138 1,138 1,059 1,067 1,067 1,067 ,989 1,113 1,113 1,113 1,113
1,064 1,113 1,228 1,545 2,451 4,633 10,811 17,246 28,470 25,470 21,379 19,302 23,880
22,832 22,584 27,495 28,100 21,732 20,356 15,431 13,993 12,415 7,911 7,704 11,339 10,260
6,672 8,469 5,948 4,395 4,084 3,698 4,120 2,949 2,811 2,297 2,069 1,890 1,711
1,607 1,535 1,451 1~379 1,345 1,285 i,224 1,176 1,175 1,177 1,177 1,177 1,177
1,122 1,122 1,179 1,604 3,462 8,212 11,764 10,518 16,714 25,823 20,349 26,351 22,988
26,281 26,663 38,137 25,275 28,150 19,051 18,006 16,331 11,948 8,723 9,329 15,679 11,706
8,532 7,605 6,326 5,214 3,950 3,534 2,637 2,685 2,707 2,175 1,678 1,578 1,516
1,448 1,584 1,961 2,118 2,142 1,911 1,594 1,265 1,190 1,194 1,274 1,297 1,314
1,238 1,291 1,373 1,779 4,737 17,566 17,640 11,625 19,077 15,465 14,949 16,085 18,788
14,090 33,261 32,516 29,007 31,168 30,077 38,871 30,803 20,047 15',158 12,220 10,197 9,485
5,901 5,560 5,713 6,627 3,364 2,845 2,782 2,339 2,057 1,971 1,860 1,794 1,794
1,697 1,695 1,695 1,695 1,729 1,662 1,212 ,881 ,767 ,826 ,826 ,874 1,123
,956 ,956 1,057 1,403 2,641 6,274 11,618 15,603 17 ,916 21,638 18,090 23,883 23,173
16,689 20,637 2,979 23,533 20,306 13,970 12,157 10,610 11,835
10,670 13,360 21,010 13,236
7,782 6,119 4,982 2,921 2,384 2,252 2,137 1,997 1,944 1,850 1,850
1,850 1,965
2,201 1,906 1,590 15,588 1,553 15,335 1,540 1,685 1,583 1,534 1,437 1,389 1,280
1,185 1,208 1,411 ,197 3,484 8,419 14,537 12,909 18,671 23,758 17,019 29,754 ,20,568
22,463 19,352 16,152 17,431 17,935 22,829 21,149 18,683 22,728 15,528 9,607 8,465 11,118
9,429 7,833 6,641 4,560 4,967 2,833 2,462 2,258 2,113 2,947 1,961 1,887 1,826
TABLE B.3.1.6 (Page 5 of 5)
MAX
MIN
MEAN
2,201
1,517
.29,660
10,948
656
486
13,051
3,018
1,274
906
20,412
6,392
1,906
1 617
33 261
8 469
640
486
14.458
2,841
1,235
925
20 804
5 356
1,971
1,783
32,516
6,641
598
603
13,728
2,402
1,204
1,043
20,963
4,235
i2,118
1,907
2i9,007
;6,627
598
641
1;4,188
i1,602
i1 ,190
i1,232
2:0,393
13,403
2,142
10,007
32,829
4,984
598
524
11,668
12,248
1,137
2,792
21,250
2~650
1,911
Q,566
38,945
3,698
587
521
1 ,201
,176
1,060
6,260
1~,718
2,264
1,650
17,834
44,209
4,120
559
699
6,318
950
1,019
19,667
18,857
2,027
1,685
27,061
34,121
2,949
512
1,548
5,126
842
987
14,705
17,190
1,868
1,583
31,966
34,145
2,811
576
6,558
4,792
787
,944
18,439
15,445
1,748
1,560
66,753
24,531
2,911
558
11,525
5,256
735
,920
22,802
12,573
1,556
1,560
49,464
22,570
2,551
,523
12,275
5,495
699
,918
24,502
11,279
1,482
1,560
42,296
21,010
1,955
,524
11,864
3,939
694
923
23,194
10,324
1,405
1,560
33,340
20,946
1,965
524
13,651
3,781
687
930
21,895
9,788
1,370
1/Flows are presented in stdnd~rd weekly periods of seven days,beginning with week number one (Dec.31 -
Jan.6)and continuing ac~oss at thirteen weeks per line.The 39th week is an eight day period (standard
water week 52 [Sept.23 -ISept.30])and the flow for this period is the total eight day flow divided by
seven as used in the rese~voir operation p~ogram.This flow in week 39 is the average flow multiplied by
1.143.I
-L-'-----'
(Page 1 of 5)WEEKLY STREAMFLOW AT DEVIL CANYON (CFS)l/
937 903 910 1,015 1,017 905 639 586 662 658 618 666 741
645 653 707 841 2,073 7,412 12,653 13,142 16,482 16,076 15,579 24,604 18,186
18,806 20,005 21,876 23,788 23,852 22,094 20,211 16,662 12,546 8,782 9,955 6,732 6,814
5,002 4,460 3,893 2,221 1,390 1,308 1,227 1,159 1,105 1,029 1,029 1,029 1,029
928 911 911 911 849 763 763 763 732 693 ,693 ,693 693
632 812 1,247 2,166 5,578 16,270 18,094 8,982 15,694 28,723 20,708 13,168 18,542
20,078 23,579 22,556 29,742 20,059 16,216 17,229 16,860 23,677 28,254 17,550 18,128 17,537
8,578 5,735 4,169 3,240 3,275 3,051 2,256 2,2?1 2,060 1,744 1,744 1,744 1,744
1,547 1,512 1,512 1,512 1,242 913 913 913 876 823 ,823 ,823 823
865 865 865 865 1,070 1,348 1,844 3,994 19,808 23,151 32,788 35,561 31,470
26,455 18,796 24,021 26,032 34,530 22,572 17,722 13,454 15,784 18,093 12,236 10,567 14,453
10,249 9,557 6,653 4,848 4,640 3,958 2,537 3,109 2,241 1,518 1,518 1,518 1,518
1,076 1,001 1,001 1,001 882 728 728 728 737 770 ,770 ,770 770
515 515 833 1,384 11,682 16,151 14,696 25,346 19,715 32,683 25,237 20,543 24,040
19,114 17,262 18,775 19,518 24,005 20,574 16,487 16,972 20,191 17,049 15,531 12,951 11,276
7,420 6,152 4,514 3,597 2,199 2,085 1,928 1,796 1,633 1,374 1,374 1,374 1,374
19154 1,260 1,236 1,236 1,236 1,105 923 923 923 834 718 1,718 ,718 718
585 585 1,006 1,067 5,588 11,134 18,035 20,674 19,401 23,4;45 22,525 21,603 26,262
21,613 17 ,237 16,771 16,771 29,010 23,623 23,623 23,623 22,350 14,288 12,282 11,456 8,406
5,953 5,593 4,211 4,211 3,316 2,637 2,487 2,197 2,140 1,995 1,956 1,723 1,723
1QI55 1,838 1,855 1,589 1,483 1,401 1,280 1,280 1,280 1,153 1,010 1,010 1,010 1,010
962 962 962 962 3,137 4,150 4,849 14,520 15,954 19,123 31,175 33,822 31,673
32,794 27,394 21,145 25,282 22,103 20,433 20,965 25,488 36,191 18,609 14,219 11,555 10,400
6,868 5,055 4,117 3,547 2,325 1,938 1,781 1,570 1,470 1,197 1,197 1,197 1,197
958 913 913 913 914 892 892 892 879
849 ,849 ,849 849
770 770 770 770 2,220 10,455 14,922 29,687 19,760 31,174 40,573 29,790 26,263
27,406 29,885 30,181 29,454 29,030 26,510 23,956 19,099 16,306 14,339 20,101 19,588 14,339
6,577 6,577 4,462 4,110 3,399 3,855 2,740 2,587 2,471 2,213 2,147 1,751 1,751
1,614 1,588 1,588 1,588 1,590 1,396 1,396 1,396 1,263 1,088 1,088 1,088 1,088
974 974 974 974 2,998 5,240 8,557 19,170 28,186 35,489 31,349 27,825 .19,052
21,995 20,209 22,658 24,581 19,970 19,771 19,663 18,031 19,953 17,237 18,813 18,292 20,076
9,403 8,067 5,479 6,784 4,885 4,021 3,443 3,831 3,221 3,868 3,300 2,460 1,998
TABLE B.3.1.7 (Page 2 of 5)
YEAR
1958 2,228 1,,953 1,703 :1,611 1,331 ~,333 1,201 1,190 '1,111 1,138 1,110 1,042 1,042
1,071 1~198 1,299 11,575 3,551 1,050 9,849 18,752 20,003 2,116 27,116 23,381 21,304
20,248 20,248 20,248 19,851 36,827 26,,997 20,0,48 16,251 11,239 7,737 7,737 6,008 6,865
5,540 4,873 4,662 3,236 2,770 2,388 2,035 1,563 1,405 985 1,086 1,699 1,699
1959 1,403 1~351 12,288 1,262 1,275 I 1,226 1,096 997 865 865 865 865~,278
831 ,831 1,187 11,246 2,471 41,043 17,266 24,455 19,652 23,860 17,822 21,239 23,769
24,645 23,659 25,632 2P,,245 21,943 111,188 22,064 40,7i§6 39,763 24,835 13,349 10,026 10,810
10,007 6,913 3,803 ~,751 3,192 2,716 2,599 2,444 2,322 1,995 1,995 1,995 1,995
1960 1,857 1,835 1,637 '1,559 1,474 11,378 1,351 1,286 1,247 1,205 1,152 1,019 1,019
790 ,.'790 1,035 il,077 5,345 71,566 14,617 22,750 23,52{f.13,128 13,610 14,093 15,491
22,156 16,426 18,898 25,911 30,054 23,,404 20,681 19,984 19,226 16,823 26,586 18,844 16,128
11,591 8,418 5,986 ~,360 3,269 2;,981 2,749 2,439 2,508 2,534 2,583 2,271 2,271
1961 2,211 2~203 2,268 ~,294 1,988 11,604 1,578 1,516 1,556 1,352 1,505 1,891 1,891
1,996 1,996 2,201 ~,235 6,581 121,101 20,940 19,947 18,628 17,325 28,298 35,357 29,708
21,299 22,357 23,150 2~,984 24,592 I 21,399 30,310 15,053 1,162 12,778 12,169 14,00725;,061
9,801 4,324 4,324 {.,324 3,274 2!,458 2,458 2,458 2,321 1,960 1,960 1,960 1,960
1962 1,837 1,815 1,815 '1,815 1,634 1\,392 1,392 1,392 1,359 1,316 1,316 1,316 1,316
1,486 1~486 1,486 1,486 3,391 41,173 11,325 16,690 26,822 28,876 56,010 47,891 33,902
26,163 25,543 22,258 2~,163 24,614 211,799 21,799 21,799 22,290 22,008 13,899 11,257 12,951
8,737 6~653 5,797 5,238 3,522 21,607 2,607 2,607 2,410 1,872 1,872 1,872 1,872
1963 1,540 I 1,490 1,490 1,490 1,465 11,414 1,414 1,414 1,188 933 933
933 933
693 !693 693
,693 2,460 3:,320 18,714 30,261 34,055 23,383 23,383 23,383 23,383
28,908 37,368 35,407 30,234 26,472 24:,729 21,455 22,691 19,122 14,318 12,804 10,239 10,381
8,327 7 ~011 5,636 {f,347 2,658 21,374 2,100 1,736 1,690 1,576 1,523 1,205 1,205
1964 1,047 1~020 954 926 934 :'942 922 866 802 707 679 606 606
674 674 730 i 740 590 1604 809 1,790 20,029 74,483 51,153 42,687 30,872,
24,270 25,009 23,601 Ip,194 18~729 17 1,736 14,300 15,247 12,880 10,489 8,548 8,595 8,413
7,044 7,883 5,159 {f,104 2,914 2:,687 2,659 2,963 1,906 1,271 1,133 1,030 1,030
1965 943 928 928 928 880 820 820 820 841 870 870 870 870
1,115 1,115 1,406 1,454 1,899 51,130 8,925 16,084 31,961 20,514 21,916 29,042 30,826
28,458 28;698 26,730 23,181 20,872 181,586 28,711 19,247 10,693 15,833 19,452 17,801 '23,533,'1,804 1,442 1,38813,634 7,579 3,550 2,937 2,500 21,042 1,721 1,656 1,554 1,503
1966 1,298 1,281 1,281 1,281 1,238 11,180 1,180 1,180 1,184 1,187 1,187 1,187 1,187
1,317 1,317 1,731 1,800 2,714 31,540 6,557 12,569 19,703 4,411 15,369 26,668 22,505
17,390 16,564 17 ,337 19,615 16,089 211,345 17,552 21,266 17 ,016 11,802 11,462 11,331 9,448
6,487 4,350 3,288 ~,227 1,568 11,446 1,446 1,446 1,422 1,361 1,361 1,361 1,361
",---'"---~_.---'~-~.'--~'-------..-
TA LE B.3.1.7 (Page 3 of 5)
YE R
19 7 1362 1363 1363
1363 1325 1275 1275 1275 1188 1078 1078 1078 1078
963 963 989 1138 1624 4649 16169 22624 207061 24918 32648 27290 26620
20076 19995 27805 32408 25176 23505 51282 28599 19229 27035 15955 11597 10072
6430 5353 4187 3191 2670 2265 2145 2064 2026 1969 1969 1888 1875
19~8 1868 1869 1869 1842 1776 1779 1779 1779 1779 1779 1779 1779 1779
1750 1684 1764 1883 2087 2748 12217 31597 25614 24621 34274 34753 25300
27823 25325 24447 23623 20824 18816 15653 14145 12539 10453 10471 6687 5851
4751 4102 3160 2805 2386 1844 1404 1229 1017 896 849 801 761
191&9 731 711 663 663 663 660 673 607 707 735 755 796 822
878 1036 1348 1912 3208 5726 10892 19104 11446 12312 15692 17191 15610
13725 17372 17848 14921 12703 13327 6903 5598 5234 5924 5179 4441 4262
3613 3401 2979 2011 ·1615 1349 1065 943 883 840 799 793 793
1910 780 781 748 735 735 739 693 693
693 698 711 745 745
811 893 1021 1240 1833 4383 15525 14018 17146 15505 14957 14162 23845
23076 19362 20745 19835 24759 21655 16732 18910 13021 10994 8748 8910 5677
6293 5253 4279 3638 3621 3449 3138 2776 2486 2321 2166 1986 1779
19f1 1597 1429 1298 1140 1059 999 908 908 889 865 865 865 865
870 903 980 1096 1312 1700 2506 4424 7861 21610 44612 27094 37428
~3189 23596 27197 17694 23161 43006 38447 23577 18657 21459 13693 10354 10269
7354 6590 5002 4124 3386 3056 2896 27-35 2602 2389 2389 2205 2205
19V2 2182 2001 2001 2001
2000 1885 1807 1807 1730 1718 1639 1639 1613
1483 1483 1422 1483 2946 17070 16823 234$2 39387 23332 41437 36288 24532
24274 24261 21623 17632 19568 20953 19219 19865 13290 12589 17212 12685 6546
4631 4286 5945 4490 2970 2408 2056 1894 1654 1511 1349 1321 1321
1162 1134 1134 1134
1142 1142 1142 1142 1059 945 945 945 945
949 959 959 1003 1329 2552 8737 12035 14974 19248 32089 34700 22798
20385 19488 14744 15905 17030 20275 16155 21018 22260 12074 8425 7115 6604
5275 4249 2930 2220 1835 1574 1450 1328 1218 1099 989 941 913
876 870 835 822 798 765 751 717 718 714 700 666 666
639 665 802 1279 2387 6225 11611 25921 29383 18190 15463 14457 15436
16001 19887 18241 17539 16605 17493 14966 11844 16072 15586 8738 8830 13278
5158 5126 2732 1822 1618 1622 1622 1622 1607 1479 1479 1479 1479
1473 1394 1394 1394 1393 1365 1365 1313 1274 1272 1272 1272 1272
1248 1260 1375 1630 2559 6184 13592 20770 27708 34462 25886 32526 29079
TABLE B.3.1.7 (Page 4 of 5)
YEAR-
26,155!28,436 26,9571 24,660 22,789 1~,242 17,426 15,380 13,252 10,858
18,386 17,223 16,589
9,346:8,243 7,593
1
\4,478 3,159 2,241 1,707 1,356 1,167 1,063 1,023 983 930
1976 920 921 888 875 875 880 880 880 856 822 822 822 822I7567929831.1,643 4,311 12,374 11,892 12,436 14,396 26,245 28,274 19,909 19,234
18,276'18,235 17,3851 17,831 21,250 2~,600 20,486 15,736 11,079 7,164 5,867 5,902 7,183
4,442 3,626 3,458 1 \3,068 2,652 2,438 2,285 2,156 2,600 2,429 2,200 2,020 1,867
1977 1,772i 1,720 1,6291 '1,590 1,543 [,487 1,461 1,461 1,415 1,355 1,355 1,355 1,355
1,438 1,438 1,516 1 .1,692 1,712 2,974 10,765 16,516 25,448 33,191 43,962 36,028 32,148
20,430 22,716 24,005!19,973 21,372 2p,695 18,935 19,143 12,iOl '9,714 13,751 13,190 12,685
8,112 8,229 7,232!i 5,395 4,079 l3,474 3,131 2,904 2,692 2,523 2,412 2,340 2,163
1978 2,060 1,942 1,8431 il,770 1,663 1,548 1,503 1,503 1,460 1,478 1,478 1,478 1,498
1,441 1,441 1,441',1,522 3,504 12,344 16,853 11,404 12,150 14,917 20,720 17,729 22,092
21,324:19,810 20,028 1 19,646 18,935 lil,917 16,659 13,901 10,010 10,516 9,480 7,126 6,077
5,005 5,607 4,5281 i 3,398 3,267 e,830 2,121 i,862 1,792 1,748 1,591 1,433 1,381
1979 1,359 1,306 1,3061 '1,306 1,212 [,218 1,218 1,218 1,126 1,169 1,169 1,169 1,169
1,131 1,184 1,305!1,640 2,638 4,998 11,662 18,604 30,663 26,683 22,397 20,220 25,018
25,082'24,811 30,2051 ~0,868 24,867 2~,326 18,838 16,043 14,232 8,834 8,606 12,663 11,459
7,486 9,501 6,6731 4,930 4,588 ~,148 4,621 3,309 3,151 2,576 2,321 2,119 1,918
1980 1,801 1,722 1,628!\1,547 1,507 1,440 1,372 1,119 1,320 1,321 1,321 1,321 1,321
1,260 1,260 1,3241 :1,800 3,875 9,212 13,196 11,801 18,768 28,973 22,831 29,565 25,792
29,501 29,933 31,585 1 28,372 31,440 2~,402 20,230 18,346 13,413 9,786 10,465 17,592 13,134
9,434 8,409 6,9941 !5,465 4,389 13,929 2,932 2,985 2,99~2,216 1,710 1,608 1,546
1981 1,525 1,775 2,066 1 :2,232 2,262 2,240 1,868 1,484 1,391 1,391 1,484 1,510 1,529
1,449 1,510 1,608!i2,083 5,196 19,239 19,321 12,733 20,884 18,091 16,425 17 ,674 20,644
16,157 38,138 37,2831 ~3,258 36,067 3~,704 44,852 35,541 23,832 16,893 13,620 11,366 10,573
6,569 6,190 6,361 1 :7,376 4,141 B,513 3,436 2,889 2,534 2,328 2,193 2,115 2,115
1982 2,084 2,083 2,083!!2,083 2,106 2,III 1,542 1,119 982 1,001 1,001 1,060 1,363
1,286 1,286 1,420!'1,886 3,035 il,207 13,345 17,920 20,543 24,650 20,690 27,290 26,402
18,710 23,136 23,5211 26,386 22,303 15,386 13,388 11,684 13,035 12,548 15,713 24,712 15,566
9,491 7,464 6,077!13,562 2,760 e,590 2,458 2,297 2,235 2,142 2,142 2,142 2,274
1983 2,569 2,225 1,974 1 1 1 ,854 1,813 1,769 1,902 1,942 1,821 1,710 1,602 1,548 1,427
1,341 1,366 1,5961 '2,158 4,096 9,947 17,176 15,253 21,996 26,445 18,942 23,102 22,894
24,232 20,875 17 ,4231 18,801 19~944 '2p,388 23,520 20,778 25,284 17,691 19,046 9,644 12,669
10,643 8,842 7,49 51 :5,148 4,558 3,173 2,758 2,532 2,362 2,262 2,167 2,087 2,019
.,
I I
'---,"--~
---'-_.-~.__.-'-_._~_.."~-
2,569 2,225 2,268 2,294 2,262 2,240 1,902 1,942 1,821 1,779 1,779 1,891 1,891
1,996 1,996 2,201 2,235 11,682 19,239 20,940 31,597 39,387 74,483 56,010 47,891 37,428
32,794 38,138 37,283 33,258 36,826 43,006 51,282 40,756 39,763 28,254 26,586 24,712 23,533
13,634 9,557 7,593 7,376 4,885 4,148 4,621 3,309 3,221 3,868 3,300 2,460 2,274
MIN ,731 ,711 ,663 ,663 ,663 ,66O ,639 ,586 ,662 ,658 ,617 ,606 ,606
,515 ,515 ,693 ,693 ,59O ,604 ,809 1,790 7,861 12,312 13,610 13,168 15,436
13,725 16,426 14,744 14,921 12,703 13,327 6,903 5,598 5,234 5,924 5,179 4,441 4,262
3,613 3,401 2,732 1,822 1,390 1,308 1,065 ,943 ,883 ,840 ,799 ,793 ,761
MEAN 1,489 1,442 1,404 1,388 1,324 1,248 1,199 1,160 1,190 1,066 1,064 1,070 1,079
1,047 1,069 1,205 1,422 3,265 7,330 12,498 17,336 21,612 25,764 27,707 26,246 24,768
22,653 23,106 23,303 22,673 23,875 22,124 21,222 19,348 -17,375 14,496 13,016 11,929 11,304
7,506 6,284 4,957 3,983 3,082 2,631 2,355 2,169 2,030 1,822 1,736 1,644 1,602
1J~Flows are presented in standard weekly periods of seven days,beginning with week number one (Dec.31 -
Jan.6)and continuing across at thirteen weeks per line.The 39th week is an eight day period (standard
water week 52 [Sept.23 -Sept.30])and the flow for this period is the total eight day flow divided by
seven as used in the reservoir operation program.This flow in week 39 is the average flow multiplied by
1.143.
TABLE B.3.1.~:WEEKLY STREAMFLGW AT OOLD CREEK (CFS)ll (Page 1 of 5)
YEAR--
1950 1,014 979 986 i1,1100 1,100 971 689 629 710 711 666 720 801
774 783 849 11,1009 2,314 8,007 13,671 14,200 17,914 17,100 16,571 26,171 19,343
19,957 21,229 23,214 ~5 ,1243 25,100 23,129 21,157 17,443 13,171 9,263 10,500 7,100 7,186
5,257 4,686 4,091 1 2 ,j334 1,471 1,~86 1,300 1,229 1,171 1,100 1,100 1,100 1,100
1951 980 960 960 1960 900 820 820 820 786 740 740 740 740
774 997 1,529 'i 2,)65 7 6,157 17,~29 19,271 9,567 16,671 29,543 21,300 13,543 19,071
20,729 24,343 23,286 +1,1414 21,429 17 ,614 18,714 18,314 25,600 30,057 18,671 19,286 18,657
9,229 6,171·4,486 !3,1486 3,500 3,~04 2,369 2,343 2,186 1,900 1,900 1,900 1,900
1952 1,643 1,600 1,600 i1,[600 1,343 1,QOO 1,000 1,000 ,949 880 880 880 880
920 920 920 '920 1,191 1,514 2,071 4,486 21,929 24,814 35,143 38,114 33,729
27,629 19,629 25,086 27,i186 37,243 25,Q71 19,686 14,943 17,329 18,886 12,771 11 ,029'15,086
11,143 10,390 7,233 i5 1271 5,000 4,257 2,729 3,343 2,429 1,700 1,700 1,700 1,700
11 :1100
,
1953 1,186 '1,100 1,100 980 820 820 820 ,820 820 820 820 820
930 930 1,504 12 ,1 500 14,129 ~i:~~j 15,300 26,386 20.,743 35,114 27,114 22,071 25,829
20,229 18,271 19,871 ~O ,1657 25,643 17,514 18,029 21,500 18,786 17,114 14,271 12,426
8,119 6,733 4,940 13,937 3,401 2,271 2,100 1,957 1,786 1,500 1,500 1,500 1,500
1954 1,329 1,300 1,300 iI,pOO 1,171 1,pOO 1,000 1,000 ,906 780 780 780 780
870 870 1,496 i1,600 6,743 12,~86 19,900 22,814 21,571 25,457 24,457 23,456 28,514
24,486 19,529 19,000 JJ9 ,000 .31,143 24,QOO 24,000 24,000 23,000 1,586 14,000 13,057 9,581
6,500 :6 ,109 4,500 14,:500 3,686 I 2,829 2,500 2,414 2,200 2,157 1,900 1,9003,0,00
1955 1,986 :2,000 1,714 i,1,!600 1,514 1,lJIOO 1,400 1,400 1,271 1,100 1,100 1,100 1,100
1,200 1,200 1,200 !1,200 3,557 4,5~00 5,247 15,743 17,429 20,329 33,143 35,957 33,671
34,186 28,557 22,043 ~6,357 22,614 20,9100 21,443 26,071 37,243 19,671 15,029 12,214 10,993
7,236 5,327 4,339 !3,(737 2,486 I 1,929 1,700 1,586 1,300 1,300 1,300 1,3002,lPO
1956 1,026 980 980 .,980 976 9,70 970 970 957 940 940 940 940
950 950 950 950 2,514 11 ,400 16,271 32,371 21,686 33,457 43,543 31,971 28,186
~1,229 I29,057 31,686 32,000 31,429 28,7i71 26,000 20,729 17,714 16,000 22,429 21,857 16,000
7,200 7,200 4,886 14 ,POO 3,757 3,2pO 3,071 2,900 2,757 2,400 2,329 1,900 1,900
1957 1,729 1,700 1,700 11 ,flOO 1,614 1,5QO 1,500 1,500 1,371 1,200 1,200 1,200 1,200
1,200 1,200 1,200 !1,200 3,414 5,7~7 9,400 21,057 30,914 37,443 33,086 29,357 20',100
23,214 21,329 23,914 ~5,943 20,957 20,9~3 20,829 19,100 21,143 19,814 29,643 20,071 20,029
10,333 8,864 7,230 17 ,~54 5,429 4,5~1 3,870 3,181 3,586 4,314 3,680 2,744 2,229
i.I
'---------'__"I .-:...-.-...-'----~
L ,
TABL B.3.1.8 (Page 2 of 5)
YEAR
1958 2,429 2,129 1,857 1,757 1,457 1,443 1,300 1,200 1,200 1,200 1,171 1,100 1,100
1,200 1,343 1,457 1,766 3,990 7,883 11 ,014 20,971 22,056 28,000 28,000 24,143 22,000
22,000 22,000 22,000 21,571 38,686 27,529 20,443 16,571 11,557 8,500 8,500 6,600 7,543
3,991 5,271 5,043 3,500 2,986 2,600 2,214 1,700 1,529 1,100 1,214 1,900 1,900
19591 1,557 1,500 1,429 1,400 1,400 1,400 1,343 1,200 1,106 980 980 980 980
1,000 1,000 1,429 1,500 2,857 4,543 19,400 27,486 22,329 26,029 19,443 23,171 25,929
26,400 25,343 27,457 21,686 23,886 18,629 23,914 44,171 43,171 28,700 14,829 11 ,137 12,007
10,714 7,400 4,071 5,086 3,486 3,000 2,871 2,700 2,557 2,200 2,200 2,200 2,200
19601 2,029 2,000 1,786 1,700 1,614 1,500 1,471 1,400 1,357 1,300 1,243 1,100 1,100
1,100 1,100 1,443 1,500 5,857 7,600 14,686 22,857 24,286 14,357 14,886 15,415 16,943
22,929 17 ,000 19,557 26,814 32,043 25,429 22,471 21,714 20 i 857 18,314 28,943 20,514 17 ,557
12,529 9,100 6,471 4,714 3,586 3,300 3,043 2,700 2,757 2,900 2,843 2,500 2,500
1961 1 2,414 2,400 2,471 2,500 2,200 1,800 1,771 1,700 1,614 1,500 1,571 2,100 2,100
2,500 2,500 2,657 2,800 7,229 12,714 22,000 20,957 19,814 18,971 30,986 38,714 32,529
23,000 24,143 25,000 25,900 25,643 26,000 22,200 21,071 15,657 12,429 14,100 13,429 15,457
10,429 4,600 4,600 4,600 3,514 2,700 2,700 2,700 2,529 2,100 2,100 2,100 2,100
1962 1 1,929 1,900 1,900 1,900 1,729 1,500 1,500 1,500 1,456 1,400 1,400 1,400 1,400
1,700 1,700 1,700 1,700 3,700 4,500 12,214 1,800 28,471'30,286 58,743 50,229 35,557
27,186 26,543 23,129 27,186 26,057 23,000 23,000 23,000 23,429 23,571 14,886 12,057 13 ,871
9,150 6,976 6,071 5,486 3,700 2,800 2,800 2,800 2,571 2,000 2,000 2,000 2,000
19631 1,657 1,600 1,600 1,600 1,557 1,500 1,500 1,500 1,286 1,000 1,000 1,000 1,000
830 ,830 ,830 ,830 2,666 3,400 19,171 31,000 35,686 26,000 26,000 26,000 26,000
31,143 40,257 38,143 32,571 27,800 25,143 21,814 23,071 19,543 15,143 13,543 10,829 10,979
8,897 7,491 6,129 5,643 2,886 2,600 2,300 2,900 1,843 1,700 1,643 1,300 1,300
19641 1,129 1,100 1,029 1,000 1,000 1,000 ,980 ,930 ,861 ,770 ,739 ,660 ,660
710 ,710 ,770 ,780 ,866 1,043 1,400 3,099 28,990 75,029 51,529 43,000 31,100
25,371 26,143 24,671 19,629 19,757 18,729 15,100 16,100 13,600 11,354 9,253 9,304 9,106
7,677 8,591 5,623 4,473 3,080 2,836 3,807 3,129 2,033 1,370 1,221 1,110 1,110
19651 981 ,960 ,960 ,960 ,917 ,860 ,860 ,860 ,877 ,900 ,900 ,900 ,900
1,180 1,180 1,489 1,540 2,011 5,386 9,371 16,886 33,643 21,971 23,471 22,429 33,014
30,357 30,614 28,514 24,729 22,229 19,671 30,386 20,371 11,343 15,849 20,700 18,943 25,043
15,086 8,387 3,929 3,250 2,764 2,264 2,000 1,907 1,829 1,714 1,557 1,590 1,530
19661 1,419 1,400 1,400 1,400 1,357 1,300 1,300 1,300 1,300 1,300 1,300 1,300 1,300
1,500 1,500 1,971 2,050 3,014 3,886 7,200 13 ,800 21,657 47,686 34,129 28,829 24,329
18,643 17 ,757 18,586 21,029 28,014 22,914 18,843 22,829 18,300 12,886 12,614 12,371 10,314
6,990 4,687 3,544 2,400 1,729 1,600 1,600 1,600 1,571 1,500 1,500 1,500 1,500
TABLE B.3.1.8 Page 3 of 5)
YEAR :,
1967 1,500 1,500 1,500 ~,~OO 1,457 1,4(1)0 1,400 1 400 1,314 1,200 1,200 1,200 1,200
1,100 1:,100 1,129 ~,300 1,743 4,9 t 9 17,143 23 986 28,829 26,571 34,814 29,014 28,386
21,557 21'471 29,857 3~,~00 27,100 25,043 54,871 30 600 20,614 29,071 17,157 12,471 10 ,831
",
6,851 5,70:3 4,460 ~,400 2,857 2,4i9 2,300 2,214 2,171 2,100 2,100 2,014 2,000
1968 2,000 2,000 2,000 l,971 1,900 1,9(1)0 1,900 1,900 1,900 1,900 1,900 1,900 1,900
1,871 1',800 1,886 ?,Q14 2,243 2,943 13 ,086 33.843 27,543 26,457 36,829 37,343 27,186
29,429 26,786 25,857 24-,~86 22,214 20,143 16,757 15,143 13,429 11 ,271 11 ,291 7,210 6,309
5,061 4,370 3,366 2,987 2,543 l,gzl 1,500 1,314 1,086 950 900 850 807
1969 771 750 700 I ~OO 700 700 714 :750 750 779 800 843 871
957 1:,129 1,471 ~,O86 3,400 6,013 11 ,434 20,1057 12,069 12,800 16,314 17,871 16,229
13,929 17,629 18,114 1~,1143 13,386 14,286 7,399 6,001 5,593 5,303 5,511 4,72,6 4,536
3,940 3,709 3,249 :2 1193 1,714 1,429 1,129 1,000 936 900 857 850 850
850 ":8001970850814,aOO 800 750 :750 750 750 764 800 800
850 1936 1,071 i,300 1,943 4,6]4 15,343 14,1757 18,129 16,971 19,671 15,500 26,100
25,029 21,000 22,500 2',~14 26,429 22,8~1 17,671 19 ;971 13,786 11,897 9,466 9,643 6,143
7,017 5,857 '4,771 4,0;57 4,000 3,8QO 3,457 3,057 2,743 2,571 2,400 2,200 1,971
1971 1,743 1 ~557 1,414 ~,243 1,157 1,100 1,000 1,r000 979 950 950 950 950
964 hOOO 1,086 1,2!l4 1,457 1,9QO 2,800 4,943 8,714 22,857 47,186 28,6571 39,586
24,900
I ,
24,471 28,700 1~,q71 24,357 44,743 40,000 24,:529 19,471 22,857 14,586 11,029 10,939
7,744 6,939 5,267 4,3.43 3,600 3,2~7 3,086 2,914 2,771 2,600 2,600 2,400 2,400
1972 2,400 2,200 2,200 2,~oo 2,200 2,0~6 2,000 2,:000 1,914 1,886 1,800 1,800 1,771
1,700 1,too 1,629 ~,700 3,386 19,571 19,286 26,886 44',243 24,471 43,457 38,057 25,729
35,371 25,357 22,600 1~,429 20,243 21,7~9 19,929 20,1600 13,786 13,186 18,029 13,286 8,657
4,786 4,429 6,143 4 5157 3,114 2,5~3 2,171 2,000 1,743 1,600 1,429 1,400 1,400,,
1973 1,229 1,200 1,200 J!2'00 1,200 1,ZQO 1,200 1,200 1,114 1,000 1,000 1,000 1,000,,
1,000 HOOO 1,000 ]Oi57 1,400 2;6~6 9,200 12,'671 15,714 20,214 33,700 36,443 23,943I',
21,057 20,129 15,229 q ,41 29 17,545 21,029 15,757 21,1800 23,171 12,814 8,942 7,551 7,010
.5,636 4,539 3,130 2,3:71 1,914 1,643 1,514 1,:386 1,271 1,143 1,029 979 950
1974 907 900 864 I 8150 829 8do 786 750 750 750 736 700 700
700 729 879 JJ 400 2,571 6,5~6 12,286 27,'429 31,357 19,557 16,700 15,614 16,671i'!
16,943 21,057 19,314 18,5[71 17,714 18,6~6 15,986 12,1651 17,130 16,614 9,314 9,413 14,154
5,503 5,469 2,914 ~,943 1,700 1,70;0 1,700 1,700 1,686 1,600 1,600 1,600 1,600
1975 1,586 1,500 1,500 11,5PO 1,500 1,500 1,500 1,443 1,400 1,400 1,400 1,400 1,400
1,400 1 414 1,543 ~,8~9 2,843 6,8~7 15,071 23,029 30,500 36,400 27,343 34,357 30,714
27,500 29 900 28,343 25,,9!29 24,200 19,486 18,614 15,429 14,157 11 ,743 19,886 18,629 17,943
10,286 9 071 8,357 ~,9'29 3,429 2,457 1,871 1,486 1,271 1,143 1,100 1,057 1,000
~
,.;.
'------'
TABLE B.3.1.8 (Page 4 of 5)
YEAR
1976 1,000 1,000 964 950 950 950 950 950 929 900 900 900 900
900 943 1,171 1,957 4,957 13 ,943 13,400 14,014 16,129 27,700 29,843 21,014 20,300
19,329 19,286 18,386 18,857 21,714 27,714 20,571 15,800 11,183 7,729 6,330 6,367 7,750
4,831 3,943 3,760 3,337 2,943 2,714 2,543 2,400 2,886 2,715 2,457 2,257 2,086
1977 I 1,957 1,900 1,800 1,757 1,700 1,629 1,600 1,600 1,557 1,500 1,500 1,500 1,500
1,600 1,600 1,686 1,771 1,971 3,457 12,514 19,200 29,200 24,956 46,300 37,943 33,857
21,714 24,143 25,514 21,229 22,286 21,329 19,514 19,729 12,514 10,363 14,671 14,071 13,534
8,829 8,957 7,871 5,871 4,486 3,829 2,450 3,200 2,964 2,757 2,636 2,557 2,364
1978 I 2,236 2,107 2,000 1,921 1,807 1,700 1,650 1,650 1,600 1,600 1,600 1,600 1,621
1,650 1,650 1,650 1,743 3,643 12,557 17,143 11,600 12,371 15,386 21,371 18,286 22,786
22,314 20,729 20,957 20,557 20,214 19,114 17 ,771 14,829 10,686 11,214 10,109 7,599 6,481
5,416 6,069 4,901 3,679 3,577 3,126 2,343 2,057 1,971 1,900 1,729 1,557 1,500
1979 I 1,457 1,400 1,400 1,400 1,300 1,300 1,300 1,300 1,200 1,200 1,200 1,200 1,200
1,200 1,257 1,386 1,743 2,743 5,143 12,000 19,143 31,671 27,486 23,071 20,829 25,771
26,371 26,086 31,757 32,457 26,514 24,800 20,029 17 ,057 15,171 9,447 9,203 13,543 12,254
7,890 10 ,014 7,034 5,197 4,871 4,424 4,929 3,529 3,357 2,743 2,471 2,257 2,043
1980 I 1,914 1,829 1,729 1,643 1,600 1,529 1,457 1,400 1,400 1,400 1,400 1,400 1,400
1,400 1,400 1,471 2,000 4,143 9,714 13,914 12,443 19,843 32,143 25,329 32,800 28,614
31,343 31,800 33,557 30,143 33,014 23,200 21,929 19,886 14,457 10,570 11,304 19,000 14,186
9,849 8,779 7,303 6,019 4,657 4,211 3,143 3,200 3,200 2,314 1,786 1,679 1,614
1981 I 1,571 1,829 2,129 2,300 2,329 2,414 2,014 1,600 1,500 1,500 1,600 1,629 1,650
1,700 1,771 1,886 2,443 5,623 20,400 20,486 13 ,500 21,943 18,629 15,914 18,200 21,257
17 ,829 42,086 41,143 36,700 38,600 31,657 46,729 37,029 24;971 17 ,986 14,500 12,100 11,256
7,641 7,200 7,399 8,581 4,512 3,943 3,857 3,243 2,828 2,529 2,385 2,300 2,300
1982 I 2,300 2,300 2,300 2,300 2,314 2,357 1,721 1,250 1,100 1,100 1,100 1,164 1,497
1,500 1,500 1,657 2,200 3,386 8,100 15,000 20,143 22,714 26,143 21,857 28,857 28,000
19,500 24,114 24,514 27,500 23,657 16,629 14,471 12,629 14,014 13,486 16,886 26,557 28,000
10,429 8,201 6,677 3,914 2,971 2,786 2,643 2,471 2,400 2,301 2,300 2,300 2,443
1983 I 2,771 2,400 2,129 2,000 1,957 1,900 2,043 2,086 1,957 1,814 1,700 1,643.1,514
1,500 1,529 1,786 2,414 4,586 11 ,086 19,143 17,000 24,143 27,343 19,586 23,886 23,671
25,371 21 ,857 18,243 19,686 21,014 26,586 24,629 21 ,757 26,529 18,957 11,729 10,334 13,574
11,283 9,373 7,945 5,457 4,843 3,386 2,943 2,700 2,414 2,386 2,286 2,200 2,129
TABLE B.3.1.8 (p age 5 0 f 5)
YEAR
MAX
MIN
MEAN
2,271
2,500
34,186
15,086
771
700
13,929
3,940
1,607
1,216
23,987
8,102
2 400
2 500
42 08'6
10 390
750
710
17 000
3 709
1 554
1 240
24 4911
6 782
2,471
2,757
41,143
8,357
700
770
15,229
2,914
1,412
1,408
24,708
5,348
2,500
I !t,~Oo
36,~OOI ,
~,~81
~OO
1180
1~,~43
1,9.43!j
1,lJj94
L~67
24,Q31
4,~03
2,329
14,129
38,686
5,429
700
866
13,386
1,471
1,427
3,654
25,294
3,332
I
I
2,4l4
20,400
44,743
I .
4,529
!
700
1,043
I
14,286
I
1,3~6
1,3~4
7,9]]4
23,320
2,861
I
2,043
22;000
54,871
4,929
686
1,400
7,399
1,129
1;300
13,466
22,387
2,562
2 086
33 843
44 171
3 529
629
3,1099
6,001
1,000
1 258
18 715
20 411
2 358
1,957
44,243
43,171
3,586
710
8,714
5,593
,936
1,204
23,556
18,377
2,204
1,900
65,029
30,057
4,314
711
12,800
6,303
,900
1,151
27,284
15,621
1,978
1,900
58,743
28,943
3,680
666
14,886
5,511
,857
1,149
29,369
14,039
1,886
2,100
50,229
26,557
2,744
660
13 ,543
4,726
,850
1,157
27,860
112,871
1,785
2,100
39,586
25,043
2,500
660
16,229
4,536
,807
1,167
26,313
12,129
1,739
1.143.
1/
I
Flows are presented in stand4rq weekly periods of seven days,beginning with week number one (Dec.31 -
Jan.6)and coni:'inuing acros~a.t thirteen weeks Iper line.the 39 th week is an eight day period (standard
water week 52;(Sept.23 -Sept.'30)and the flow for th is period is the total eight day flow divided by
seven as used in the reservoir ioperation progra~.Th is flow in week 39 is the average flow mu1 tip1 ied by,
I TABLE B.3.1.9:SUMMARY OF ESTIMATED STREAMFLOW (cfs)i
I Devil Gold
~t,ation Denali Cantwell Watana Canyon CreekJ.!SunshineY Susitna Maclaren Chulitna Ta1keet na Skwentna
-I
,t Max 2,165 5,472 6,632 7,518 8,212 20,837 58,640 734 8,062 4,891 7,254
Min 528 1,638 2,403 2,867 3,124 8,176 13,476 249 2,380 1,451 1,929
Mean 1,165 3,149 4,567 5,363 5,825 13,799 32,777 418 4,850 2,683 4,329
iv Max 878 2,487 3,525 3,955 4,192 8,795 31,590 370 3,213 1,721 4,195
Min 192 780 1,021 1,146 1,215 4,020 8,251 95 1,480 765 678
Mean 500 1,460 2,064 2,402 2,578 6,185 15,063 182 2,155 1,223 1,867
LJc Max 575 1,658 2,259 2,905 3,264 6,547 14,690 246 2,100 1,203 2,871
Min 146 543 709 810 866 2,675 5,753 49 1,000 556 624
I Mean 315 951 1,453 1,703 1,828 4,426 9,267 117 1,564 871 1,295
.,.In Max 651 1,694 1,858 2,212 2,452 5,216 10,120 162 1,681 940 2,829
Min 85 437 619 687 724 2,228 6,365 44 974 459 600
I
Mean 248 850 1,125 1,429 1,524 3,674 8,112 99 1,330 693 1,068
Feb Max 422 1,200 1,610 1,858 2,028 4,664 9,413 140 1,414 777 1,821
Min 64 426 602 682 723 2,095 5,614 42 820 392 490
Mean 206 706 1,035 1,216 1,309 3,115 .-7,383 81 1,115 548 911
Mar Max 290 1,273 1,560 1,779 1,900 3,920 8,906 121 1,354 743 1,352
Min 42 408 575 644 713 1,972 5,271 36 770 285 522
Mean 192 659 936 1,085 1,173 2,786 6,412 74 1,017 485 826
Apr Max 415 1,702 1,965 2,405 2,650 5,228 13,029 145 1,883 1,075 2,138
Min 43 465 609 697 745 2,233 4,613 50 700 385 607
Mean 231 835 1,158 1,340 1,441 3,585 7,684 86 1,264 605 1,088
May Max 4,259 13,751 15,973 19,777 21,890 43,121 88,470 2,131 21,902 8,840 22,370
I )Min 629 1,915 2,857 3,428 3,745 10,799 28,713 208 2,355 2,140 1,635
,J Mean 2,306 7,473.10,625 12,462 13,483 27,674 56,770 832 8,862 4,294 8,555
June Max 12,210 34,630 42,842 47,814 50,580 116,152 165,900 4,297 40,330 19,040 40,356
Min 4,647 9,909 13,233 14,710 15,500 40,702 73,838 1,751 15,297 5,207 10,650
Mean 7,532 17,567 22,980 26,043 27,795 63,268 112,256 2,888 22,173 11,085 18,462
July Max 12,110 22,790 28,767 32,388 34,400 85,600 181,400 4,649 35,570 17,079 28,620
Min 6,~56 12,220 14,843 15,651 16,100 45,226 92,511 2,441 20,781 7,080 11 ,670
Mean 9,688 16,873 20,747 23,075 24,390 64,143 126,590 3,241 26,875 10,748 16,997
A\Jg Max 12,010 22,760 30,542 35,256 37,870 84,940 159,600 4,122 33,670 16,770 20,590
[
Min 3,919 6,597 7,772 8,484 8,879
25,092 80,891 974 11 ,300 3,787 7,471
Mean 8,431 14,614 18,366 20,654 21,911 56,148 109,084 2,644 22,896 9,596 13,335
,C"ep Max 6,955 12,910 17,206 19,799 21,240 54,110 107,700 2,439 22,260 10,610 13,371
! \Min 1,194 3,376 4,260 4,796 5,093 14,320 37,592 470 6,704 2,070 3,783
!I'
Mean 3,334 7,969 10,878 12,555 13,493 32,867 67,721 1,167 12,391 5,779 8,371
"nn Max 3,651 7,962 9,985 11,254 11,961 28,262 63,159 1,276 11,419 5,400 10,024
I I Min 2,127 4,159 4,912
5,352 5,596 14,431 38,030 693 6,110 2,249 4,939
'I ..J Mean 2,885 6,184 8,046 9,159 9,781 23,607 46,891 998 8,931 4,073 6,622
'i.l Data for Gold Creek based on 34 years of recorded data (1950-1983).Missi ng Dat a for all other locat ions
!have been filled,in as described in Harza-Ebasco's report (HE 1984b).
2-1 SUllshine discharge for "IN 1980 ancl-9et Apr WY19Bl w~m~m Gold Creek,Talkeetna,and Chulitna
discharges for the same period.
TABLE B.3.1.10:INSTANTANEOUS PEAK FLOWS OF RECORD .
Maclaren Denali Cantwell Go1d··Creek
Flows Flows Flows Flows
Date (cfs)Date (cfs)Date (cfs)Date (cfs)
8/11/71 9,260 8/10/71 38,200 8/10/71 55,0002 6/7/64 90,700
9/13/60 8,920 8/14-15/67 28,200 6/8/64 51,200 8/10/71 87,400
8/14/67 7,460 7/28/80 24,300 6/15/62 3 46,800 6/17/72 82,600
7/18/63 7,300 8/4/76 22,100 6/17/72 44,700 6/15/62 80,600
6/16/72 7,070 8/9/81 23,200 8/14/67 38,800 8/15/67 80,200
8/10/81 6,650 7/12/7~21,700 7/18/63 32,0004 7/12/81 64,900
6/14/62 6,540 7/27/68 19,000 8/14/81 30,900 6/6/66 63,600
8/5/61 6,540 8/25/59 62,300
Notes:1 Maximum daily flow from preliminary USGS data.
2 Estimated maximum daily·flow based on d~~~ar~~_r~cords at Denali and GoldC-iFeek-:-------------_.--------_.-
3 Approximate date.
4 Maximum.daily flow.
Source:USGS
-\
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,
----~-------~-----
--_.---------~--"-".._-''-.._..,---,,,-,--_..---,--_.-
TABLE B.3 .1.11 :ESTIMATED EVAPORATION LOSSES -WATANA AND DEVIL CANYON RESERVOIRS
WATANA STAGE III D E V I L CAN YON Average Monthly Air Temper ture (DC)
Pan Reservoir Pan .Reservoir
Evaporation Evaporation Evaporation Evaporation
Watana11 Devil Canyon2.1 Talkeetna.11Moth(inches)(inches)(inches) (inches)
Jan 0.0 0.0 0.0 0.0 -2.5 -4.5 -13.0
Feb 0.0 0.0 0.0 0.0 -7.3 -5.0 -9.3
Mar 0.0 0.0 0.0 0.0 -1.8 -4.3 -6.7
Apr 0.0 0.0 0.0 0.0 -1.8 -2.5 0.7
May 3.6 2.5 3.9 2.7 8.7 6.1 7.0
Jun 3.4 2.4 3.8 2.7 10.0 9.2 12.6
Jul 3.3 2.3 3.7 2.6 13.7 11.9 14.4
Aug 2.5 1.8 2.-7 1.9 12.5 N/A 12.7
Sept 1.5 1.0 1.7 1.2 N/A 4.8 7.8
Oct 0.0 0.0 0.0 0.0 0.2 -1.8 0.2
Nov 0.0 0.0 0.0 0.0 -5.1 -7.2 -7.8
Dec 0.0 0.0 0.0 0.0 -17 .9 -21.1 -12.7------
Annu 1 14.3 10.0 15.8 ll.l
II ased on data -April 1980-June 1981
2..1 ased on data -July 1980-June 1981
.11 ased on data -January 1941-December 1980
'J
J
TABLE B.3.1.12 :WATER APPROPRIATIONS WITHIN ONE MILE OF THE ·SUSITNA RIVER
ADL SOURCE .-\LOCATIONl/NUMBER TYPE (DEPTH)AMOUNT DAYS OF USE
CERTIFICATE '\
T19N R5W 45156 Single-family dwelling well (?)650 gpd 365
general crops same source 0.5 ac-ft/yr 91 }
T25N R5W 43981 Single-family dwelling well (90 ft)500 gpd 365
T26N R5W 78895 Single-family dwelling well (20 ft)500 gpd 365 ,)
200540 Grade school well (27 ft)910 gpd 334
209233 Fire station well (34 ft)500 gpd 365
IT27NR5W200180Single-family dwelling unnamed stream 200 gpd 365
Lawn &garden irrigation same source 100 gpd 153
200515 Single-family dwelling unnamed lake .~5.00 gpd 365 : 1206633Single-family dwelling unnamed lake 75 gpd 365 I
206930 Single-family dwelling unnamed ..lake 250 gpd 365
206931 Single-family dwelling unnamed lake 250 gpd 365
PERMIT
206929 General crops unnamed creek 1 ac-ft/yr
T30N R3W 206735 Single-family dwelling unnamed stream 250 gpd
PENDING
209866 Single-family dw:elling Sherman Creek 75 gpd
Lawn &garden •..irrigation same source 50 gpd
l/All locations are referenced to·the Seward Meridian.
153
365
365
183
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J
1
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I
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J
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TABLE B.3•2.1:RESERVOIR OPERATION LEVEL CONSTRAINTS
Normal Normal
Minimum Maximum Maximum
Water Water Flood
Surface Surface Surcharge
Reservoir Elevation Elevation Elevation
Watana Stage I 1,850 2,000 2,014
Devil Canyon Stage II 1,405 1,455 1,456
Watana Stage III 2,065 2,185 2,193
J
J
TABLE B.3.2.2:STANDARD WATER WEEKS FOR ANY WATER YEAR N
FROM TO FROM TO 1
WEEK WEEK
NUMBER day month year day month year NUMBER day month year day month year I
1 1 Oct n-l 7 Oct n-l 27 1 Apr n 7 Apr n
2 8 Oct n-l 14 Oct n-l 28 8 Apr n 14 Apr n 'j315Octn-l 21 Oct n-l 29 15 Apr n 21 Apr n
4 22 Oct n-l 28 Oct n-l 30 22 Apr n 28 Apr n
5 29 Oct n-l 4 Nov n-l 31 29 Apr n 5 May n
)6 5 Nov n-l 11 Nov n-l 32 6 May n 12 May n
7 12 Nov n-l 18 Nov n-l 33 13 May n 19 May n
8 19 Nov n-l 25 Nov n-l 34 20 May n 26 May n
')
9 26 Nov n-l 2 Dec n-l 35 27 May n 2 Jun n ;~)
10 3 Dec n-l 9 Dec n-l 36 3 Jun n 9 Jun n
11 10 Dec n-l 16 Dec n-l 37 10 Jun n 16 Jun n
12 17 Dec n-l 23 Dec n-l 38 17 Jun n 23 Jun n
;,13 24 Dec n-l 30 Dec n-l 39 24 Jun n 30 Jun n
14 31 Dec n-l 6 Jan n 40 1 Jul n 7 Jul n
15 7 Jan n 13 Jan n 41 8 Jul n 14 Jul n ,I1614Jann20Jann4215Juln21Juln
17 21 Jan n 27 Jan n 43 22 Jul n 28 Jul n )
18 28 Jan n 3 Feb n 44 29 Jul n 4 Aug n
19 4 Feb n 10 Feb n 45 5 Aug n 11 Aug'n '(
20 11 Feb n 17 Feb n 46 12 Aug n 18 Aug n
...U,..,18 Feb Il 24 F.~Q 19.Aug..n 25 Aug n
22 25 Feb n 3 Mar n 48 26 Aug n 1
Sep n
1234Marn10Marn492Sepn 8 Sep n
24 11 Mar n 17 Mar n 5.0 9 Sep n 15 Sep n
25 18 Mar'n 24 Mar n 51 16 Sep n 22 Sep n
12625Marn31Marn5223Sepn30Sepn
)
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TABLE B.3.2.3:SHCA LOAD FORECAST
Net Generation at Plant 1/
I
i
Year
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Peak
(MW)
702
713
724
735
746
757
769
782
795
808
821
826
831
836
840
845
858
871
885
898
912
937
962
988
1,015
1,042
1,064
1,087
1,110
1,133
1,157
1,182
1,207
1,232
1,258
1,285
1,312
1,340
1,369
1,398
1 427
Energy
Requirement
(GWh)
3,691
3,747
3,803
3,861
3,919
3,978
4,043
4,110
4,178
4,247
4,317
4,341
4,366
4,392
4,417
4,442
4,510
4,579
4,650
4,7Zl
4,793
4,923
5,056
5,193
5,333
5,478
5,594
5,712
5,833
5,957
6,083
6,212
6,343
6,478
6,615
6,755
6,898
7,044
7,193
·7,345
7 501
1/Losses of 10 percent for transmission and distribution
included.Net generation =Sa1es/(1-.10)
TABLE B.3.2.4:DISTRIBUTION OF RAILBELT MONTHLY ENERGY
REQUIREMENT SHCA FORECAST
Energy Energy
Percent Load Year Load Year
Month of Annualll 2004 2025
(GWh)(GWh)
Jan .107 505 803
Feb .089 420 667
Mar .089 420 667
Apr .079 373 593
May .072 340 540
Jun .066 312 495
Jul .068 321 510
Aug .070 330 525
Sep .073 345 548
Oct .089 420 667
Nov .095 449 713
Dec .103 486 773
Total s 100.0 4721 7501
1
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i,'~,'jI'~
\.
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I,
':..}
II Source:Based on Method of Indirect Averaging analysis
of Railbelthourly load data for 19~82and L983 •.
TABLE B.3.2.5:EXISTING AND PLANNED RAILBELT
HYDROELECTRIC GENERATION
Average Energy (GWh)
Existing P1antsll
Proposed
Plant
Cooper Sub-Brad1ey~./
Month Ek1utna Lake Total Lake Total
Jan 14 4 18 41 59
Feb 12 3 15 39 54
Mar 12 3 15 31 46
Apr 10 3 13 26 39
May 12 3 15 20 35
Jun 12 3 15 13 28
Ju1 13 4 17 17 34
Aug 14 4 18 27 45
Sep 13 3 16 39 55
Oct 14 4 18 34 52
Nov 14 4 18 39 57
Dec 14 4 18 41 59
Total 154 42 196 367 563
Firm Energy (GWh)
P1antsl1
Proposed
Existing Plant
Cooper Sub-Brad1ey11
Month Ek1utna Lake Total Lake Total
Jan 13 4 17 41 58
Feb 12 3 15 39 54
Mar 9 3 12 31 43
I Apr 10 3 13 26 39
j May 11 3 14 20 34
Jun 8 2 10 13 23
J
Ju1 9 3 12 13 25
Aug 8 2 10 13 23
Sep 9 -3 12 14 26
Oct 9 3 12 29 41
1
Nov 8 2 10 39 .49
Dec 12 3 15 41 56
Total 118 34 152 319 471
II Source:Acres 1982)
!I 11 Scheduled on-line in 1990
TABL E B.3•3•1:WEEKLY MINIMUM MEAN FLOWS AT GOLD CREEK
FOR FLOW CASE E-VI
Minimum Minimum
Water Gold Creek Water Gold Creek
Week Flow Week Flow
(cf s)(cfs)
14 5,000 40 6,000
15 5,000 41 6,000
16 5,000 42 6,000
17 5,000 43 6,400(2)
18 5,000 44 11 ,100(3)
19 5,000 45 12,000
20 5,000 46 12,000
21 5,000 47 12,000
22 5,000 48 12,000
23 5,000 49 12,000
24 5,000 50 11,900(4)
25 5,000 51 7,400(5)
26 5,000 52 6,000(6)
27 5,000 1 5,000
28 5,000 2 5,000
29 5,000 3 5,000
30 5,000 4 5,000
31 5,700(1)5 5,000
32 6,000 6 5,000
.6~OOO·7 5~-00O
34 6,000 8 5,000
35 6,000 9 5,000
36 6,000 .10 5,000
37 6,000,11 5,000
38 6,000 12 -5,000
39 6,000 13 5,000
(1)2 days at 5,000 cfs then 5 days at 6,000 cfs
(2)5 days at 6,000,1 day at 7,000,1 day at 3,000 cfs
(3)1 day each at 9,000,10,000 and 11,000 and 4 days at
12,000 cfs
(4)6 days at 12,000 cfs,1 day at 11,000 cfs
(5)1 day each at 10,000,9,000,8,000 and 7,000 cfs and
days at 6~000 cfs
(6)8da.ysat 6,000 cfs
1
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TABLE B.3.3.2:EmOOMIC ANALYSIS OF ENVIRONMENTAL FLOW CASES
SHeA FORECAST
Cumulative
Cumulative Present Cumulative Present Worth Of Present Worth
orth of System Cos t sl!Differential Mitigation Costsl1 of Ne t Sy s tern Co s t s
(1996-2054)(1996-2054)(1996-2054)
Case I (million 1985 $)(million 1985 $)(million 1985 $)
P-l I 4,811 25 4,836
A I 4,813 25 4,838
E-VI I 4,823 0 4,823
E-IV I 4,830 ·0 4,830
C I 5,120 11 5,131
E-V I 5,490 -4 5,486
E-I I 6,570 -7 6,563
Total Railbel t
Ins taIled
Capacity in
Year 2025 (MW)
2,105
2,105
2,192
2,192
2,279
2,543
2,855
I_I cds ts incl ude production costs and cos ts for mi tigat ion measures for E-VI flow requirements.
2_1 Cdsts represent differential costs to mitigate beyond E-VI flow requirements.
II Based on an estimated 14%overload capability over rated,assuming a 75%
daily load factor.
11 Based on thermal capability of conductor bundle.
Parameter
Highest Line Loading
as %of Rating
Highest P.U.Voltage
Lowest P.U.Voltage
On 345 kV
On 115 or 138 kV
Max.Differential
Phase Angle
TABLE B.4.1.1:TRANSMISSION SYSTEM PERFORMANCE
UNDER DOUBLE CONTINGENCY
Acceptable System Configuration
Performance
Criteria 1999 2005 2025
11411 27'1:/58'1:/48'1:/
1.10 1.05 1.05 1.05
0.90 1.006 0.988 0.998
0.90 0.986 0.963 0.964
55°16.5°30.5°30.2°
J
~'l
1
1
TABLE B.4.2.1:GENERATING UNIT OPERATING CHARACTERISTICS
Devil
Watana Canyon Watana
Stage I Stage II Stage III
eservoir Elevation-ft
Normal Maximum 2000 1455 2185
Average Operating 1955 1452 2145
December-January Operating 1915 1405 2110
Minimum Operating 1850 1405 2065
nit Characteristics
Number of Units 4 4 4/21/
Net Head-ft
Design 590 590 590/680
Maximum Operating 537 600 719/719
Average Operating 490 597 680/680
December-January Operating 450 545 645/645
Minimum Operating 384 545 600/600
enerator Unit Output-MW
Maximum Operating Head 125 175 200/200
Average Operating llO 170 185/185
December-January Operating Head 90 150 170/170
Minimum Operating Head 65 150 150/150
ependable Plant Capability-MW
(December-January Operating Head)360 600 1020
ominal Plant Capability-MW
(Average Operating Head)440 680 1110
/Stage I Units/Stage III Units
TABLE I B!4.2.2:ENERGY PRODUCTION AND DEPENDABLE CAPACITY
Average Energy (GWh)
Finn Energy (Glh)
Dependable Capacity (MW)
Watana I and Watana III and
Watana Stage!I Devil Canyon II Devil Canyon II Not Limited
1999 2004 2005 2011 2012 2025 by Load
2,390 4,200 4,750 5,130 6,690 6,900
1,990 4,200 4,500 5,130 5,720 5,720
300 790 805 1,500 1,520 1,620
\--:--::~:....:..---:...:'------,,---'
TABLE B.5.2.1:INSTALLED CAPACITY OF
ANCHORAGE-roOK INLET AREA
(DECEMBER 1984)
Natural Gas
Combustion Steam
Hydro Diesel Turbine Turbine Total
Util itiesl/
Alas ka Power
Administration 30.0 0 0 0 30.0
Anchorage Municipal
Ligh t and Power 0 0 329.9 0 329.9
Chugach Electric
A$sociaton 17.4 0 490.4 0 507.8
Homer Electric
Association 0 2.1 0 0 2.1
Matanuska Electric
Association 0 0 0 0 0
Seward Electric
Association 0 5.5 0 0 5.5
Total 47.4 7.6 820.3 0 875.3
Military Installations.f.!
Elmendor f AFB 0 2.1 0 31..5 33.6
Fort Richardson 0 7.2 0 18.0 25.2
Subtotal 0 9.3 0 49.5 58.8
Industrial Installations].!
Industry 0 9.6 16.0 0 25.6
TOTAL 47.4 26.5 836.3 49.5 959.7
1/Data based on Applicant's evaluation of information provided
by the Rai1belt Utilities.
2:./Source:Departments of Anny and Air Force,January 1985.
1/Source:Battelle (1982)and Alaska Power Administration
(1983);updated by Harza-Ebasco Susitna Joint
Venture,1983.Figures are for 1981,latest year
that data was available.
TABLE B.S.2.2:INSTALLED CAPACITY OF THE
FAIRBANKS.,.TANANA VALLEY AREA
(DECEMBER 1984)
Diesel Hydro
Utilitiesl/
Faribanks Municipal
Utility System 8.4 0
Golden Valley Electric
Association 17.3 0
University of
Ala.ska 0 0
Sub tot al 25 '.7 0
Military Installations1/
Oil
Combustion
Turbine
32.2
157.8
o
190.0
Coal
Steam
Turbine
28.6
25.0
13.0
66.6
Total
69.2
200.1
13.0
202.3
I
(
I
Eiel son AFB
Fort Greeley
Fort Wainwright
o
5.5
o
o
o
o
o
o
o
15.0
o
22.0
15.0
5.5
22.0
Industry 2.8 0 0 0 2.8
TOTAL 34.0 0 190.0 103.6 327.6 (
I
Data based on Applicant's evaluation_oi_infQrrnatio-.npx9JlLded_·~~~.
~~~----_._.~the -Ra il bef t-ir til ftT~-;'-----
1/Source:Departments of Army and Air Force,January 1985.
1/Source:Battelle (1982)and Alaska Power Administration
(1983);updated by Harza-Ebasco Susitna Joint
V¢J:lture,198J .Figure~a1;'e fo.l:.198.L,.lates t ..year_
that data was available.
)
I
TABLE B.5.2.3:EXISTING GENERATING PLANTS (Page 1 of 4)
IN THE RAIL BELT REGION
(DECEMBER 1984)
Heat Rate
Instal-Retire-Generating @ Gen.
Prime Fuel lation ment Capacity Capacity
Plant/Unit Mover Type Date Date @ 30°F (MW)(Btu/kWh)
Alaska Power Administration
Ek1ut nal/H 1955 2051 30.0
Anchorage Municipal Light-and Power
Station 1f:11/(b)
Unit 1f:1 SCCT NG/O 1962 1990 16.2 15,329
Uni t 1/:2 SCCT NG/O 1964 1990 16.2 15,329
Unit 1/:3 SCCT NG/O 1968 1991 19.9 14,089
Unit 1/:4 SCCT NG/O 1972 1992 33.8 13,901
S ta tion 1/:2
Unit 1/:561/CCCT NG/O 1979 1999 47.5 10,·570
Uni t 1f:7 61/CCCT NG/O 1979 1999 109.3 9,365
Uni t 1f:8 SCCT NG/O 1984 2009 87.0 12,000
Chugach Electric Association
Beluga
Unit 1f:!SCCT NG 1968 1994 16.1 16,100
)Unit 1/:2 SCCT NG 1968 1994 16.1 16,100
Unit 1/:3 SCCT NG 1972 1999 49.5 12,800
Unit 1/:4 SCCT NG 1976 1996 10.0 17,500
Unit 1f:5 SCCT NG 1975 1999 67.3 12,400
Unit 1f:68!±/CCCT NG 1976 2007 100.6 9,600
Unit 1f:78!±/CCCT NG 1976 2007 100.6 9,600
Cooper Lake2./
Unit 1f:!,2 H 1960 2051 17.4
International
Uni t 1f:!SCCT NG 1965 1996 14.3 18,000
Unit 1f:2 SCCT NG 1968 1996 14.3 18,000
Uni t 1/:3 SCCT NG 1970 1996 19.9 14,500
Bernice Lake
Uni t 1f:!SCCT NG 1963 1988 8.9 17,300
Unit 1f:2 SCCT NG 1971 1997 18.4 14,500
Unit 1/:3 SCCT NG 1978 2004 27.2 13,700
Unit 1f4 seCT NG 1981 2004 27.2 13,700
Seldovia
Unit 1/:1 D 0 1952 1990 0.3 14,998·
Unit 1/:2 D 0 1964 1994 0.6 12,006
Unit 1/:3 D 0 1970 2000 0.6 12,006
Unit 1/:4 D 0 1982 2012 0.6 12,006
Seward Electric System
SES
unit i/:1 D 0 1965 1990 1.5 15,000
Unit 1/:2 D 0 1965 1990 1.5 15,000
Unit 1/:3 D 0 1965 1995 2.5 15,000
Military Installations -Anchorage Area
iJ
9,500
9,500
11,210
10,500
20,000
10;500
12,000
Heat Rate
@ Gen.
Capacity
(Btu/kWh)
2.6
7.2
18.0
31.5
60.9
60.9
Generating
Capacity
@ 30°F (MW)
1997
2006
2007
Retire-
ment
Date
1967
1976
1977
1952
1952
Instal-
lation
Date
Golden Valley Electric Association
Homer Electric Association
~(}-~--T95Z
NG 1952
Fuel
Type
o
NG
SCCT 0
seCT 0
D~
ST
D 0
Prime
Mover
(Page 2 of 4)
North Pole
Uni t 1/:1
Unit 1/:2
Fort Richardson
Total Diesel D
Total Steam ST
Elmendorf AFB
Tota~I Diesel
Total ST
Healy Diesel
Plant/Unit
.TABLE B.5.2.3
TABLE B.S.2.3 (Page 4 of 4)
Legend H
D
SCCT
ST
CCCT
NG
o
Notes
Hydro
Diesel
Simple cycle combustion turbine
Steam turbine
Combined cycle combustion turbine
Natural gas
Distillate.fuel oil I
11 Average annual energy production for Eklutna is lS4 GWh.
11 All AMLP SCCTs are equipped to burn natural gas or oil.!n normal
operation they are supplied with natural gas.All units have reserve
oil storage for operation in the event gas is not available.
11 uni ts :I/:S,6,and 7 are designed to operate as a combined-cycle plant.
When simulat.e.d.Jn.t:Jti;;_m()cl~,t'hfayare mod 131edas two separate units with
the characteristics shown.Thus,UnitsffiS and 7 are retired from "gas
turbine operation"and added to "combined-cycle operation".
!I Beluga Units #6,7,and 8 operate as a combined-cycle plant.When
simulated in this mode,they are modeled as two separate units with the
characteristics shown.Thus,Units :I/:6 and 7 are retired from "gas
~__t.ur_b_iJJ.g Qper.!!~i.o!!:".a.ll<3.added to "combined-cycle operation".-.,.....---_._..•_..,...__..._~-_..__...--_.._--_._._-_.._-~_.._-_.._..._.__.__..-_._~~_.._-_._-_......•'._--_...................................•._----
11 Average annual energy production for Cooper Lake is 42 GWh.
.i ,
TABL E B.5•2 .4:MONTHLY DI STRIBUTION (Page 1 of·2)
OF PEAK POWER DEMAND
Anchorage -Cook Inlet Area
Average Average
1976-1982 1982 1983 1982-1983
(%)(%)(%)(%)
January 88.5 100.0 100.0 100.0
February 87.4 92.5 88.0 90.2
March 78.4 82.1 80.5 81.3
April 69.4 76.5 72 .8 74.6
May 60.9 63.5 65.3 64.4
June 58.5 60.5 62.5 61.5
July 58.5 61.4 62.1 61.8
August 59.2 62.9 64.4 63.6
September 66.8 72.9 72 .6 72.8
October 80.1 90.6 81.0 85.8
November 88.0 95.8 84.7 90.2
December 99.2 93.7 93.6 93.6
Fairbanks -Tanana Valley Area
Average Average
1976-1982 1982 1983 1982-1983
(%)(%)(%)(%)
January 92.7 100.0 100.0 100.0
February 91.8 97.2 86.6 91.9
March 79.1 84.5 79.7 85.6
April 68.0 76.3 67.9 72 .1
)j May 60.2 69.4 67.1 68.2
June 56.9 68.4 62.9 65~6
July 57.1 64.6 63.4 64.0
August 58.6 66.0 67.6 66.8
September 64.1 69.5 71.3
70.4
October 75.4 84.6 79.8 82.2
November 84.2 99.4 82.6 91.0
December 95.0 -94.9 97.2 96.0
Total Rai 1 bel t Area
Average Average
1976-1982 1982 1983 1982-1983
(%)(%)(%)(%)
January 89.8 100.0 100.0 100.0
February 87.7 92.8 87.6 90.2
March 78.9 83.0 80.6 81.8
April 69.2 77.3 72 .2 74.8
May 60.9 65.1 65.1 65.1
June 58.3 61.2 62.1 61.6
July 57.9 62.4 62.1 62.2
August 59.8 63.0 64.4 63.7
September 66.4 72.7 72.0 72.4
October 79.5 89.8 81.0 85.4
November 87.7 96.3 84.3 90.3
December 98.9 94.6 93.5 94.0
TABLE B.5.2.4 (Page 2 of 2)
Source:Data for 1976~1982 are taken from Alaska Electric Power
Statistics 1960-1983,Alaska Power Administration (1984).Data
for 1982 and 1983 are based on Applicant's evaluation of hourly
load data provided by the Railbelt Utilities.
(%)(%)(%)
Anchorage -Cook Inlet Area
Average
1982 1983 1982-1983
1
1
I
J
1
l
!
\
i
I
.1
1
J
(
J
(
1
10.8
9.0
9.0
7.6
7.2
6.6
6.8
7.0
7.4
8.6
9.2
10.4
10.6
8.8
8.9
7.8
7.2
6.6
6.8
7.0
7.4
8.8
9.4
10.3
10.6
8.9
8.9
7.8
7.2
6.6
6.8
7.0
7.4
8.8
9.4
10.3
Average
1982-1983
10.7
8.8
9.0
7.5
7.2
6.7
6.8
7.2
7 ~7
8.5
9.1
10.6
10.4
8.7
8.9
7.8
7.3
6.7
6.9
7.2
7.6
8.7
9.3
10.4
(%)(%)
Tanana Valley Area
Average
1983 1982-1983
11.0
9.2
8.9
7.8
7.3
6.6
6.8
6.9
7.2
8.8
9.4
10.2
10.7
9.0
8.9
7.9
7.1
6.5
6.8
6.9
7.2
9.0
9.6
10.2
t%)nuuu ..u.....(%-)·u
10.7 10.5
9.0 8.8
8.9 8.9
7.9 7.8
7.2 7.2
6.5 6.7
6.8 6.9
6.9 7.2
7.2 7.6
9.0 8.7
9.6 9.2
10.2 10.4
1982 1983
Total Railbelt Area
(%)(%)
10.8
9.7
9.2
7.7
6.9
6.3
6.6
7.1
8.5
9.4
11.3
10.2
9.1
9.0
7.8
7.1
6.5
6.7
6.8
7.2
8.7
9.7
11.2
t%}
(%)
10.0
8.9
8.9
7.8
7.2
6.6
6.7
6.9
7.2
8.7
9.8
11.2
Fairbanks -
Average
1976-1982 1982
Average
1976-1982
Average
1976-1982
January
February
March
April
May
June
January
February
March
April
May
June
July
August
September
October
November
December
January
February
March
April
May
June
July
August
September
October
November
December
August
.September
October
November
December
TABLE B.5.2.5:PROJECTED MONTHLY DISTRIBUTION
OF PEAK AND ENERGY DEMAND
PERCENTAGE OF ANNUAL DEMANDll
Total Railbelt Area
Peak Energy
(%)(%)
January
February
March
April
May
June
July
August
September
October
November
December
100.0
88.5
81.8
74.7
65.1
61.6
62.2
63.6
72 .3
85.4
91.1
94.9
10.7
8.9
8.9
7.9
7.2
6.6
6.8
7.0
7.3
8.9
9.5
10.3
II Source:Based on Applicant's Method of Indirect Averaging
analysis of Railbelt hourly load data for·J:982 and
1983 provided by the Railbelt Utilities.
TABLE B.S.2 .6:TYPICAL 24-HOUR LOAD DURATION RELATIONS
TYP I CAL WEEKD AY TYPICAL WEEKEND DAY
RANK APRIL AUGUST DECEMBER APRIL AUGUST DE CEMBER
1 1.000 1.000 1.000 .945 .967 .943
2 .922 .957 .928 .916 .934 .925
3 .899 .947 .898 .899 .931 .914
4 .896 .938 .890 '.877 .908 .912
5 .896 .933 .883 .864 .899 .899
6 .880 .916 .870 .858 .884 .889
7 .869 .912 .860 .857 .858 .884
8 .866 .910 .852 .856 .851 .857
9 .839 .902 .850 .853 .835 .856
10 .829 .871 .843 .841 .832 .846
11 .818 .867 .838 .833 .824 .835
12 .809 .841 .813 .822 .822 .831
13 '.805 .823 .805 .807 .805 .826
14 .796 .810 .793 .803 .798 .802
15 .794 .767 .772 .801 .785 .783
16 .792 .744 .757 .747 .737 .730
17 .717 .723 .704 •735 .715 .721
18 .694 .709 .674-.697 .649 .714
19 .649 .613 .655 .657 --;-626 .674
20 .632 .609 .611 .638 .626 .663
2L -.627-.584 ..-.610 ---.630.-.585-.---.661
22 .613 .579 .610 .621 .584 .627
23 .606·.577 .566 .612 .582 '.602
24 .601 .575 .548 .586 .565 .571
Source:Based on Applicant's Method of Indirect Averaging analysis of
Rai 1be1 t hourly load dat.!l.~or 1 ?~2 and 1983pl:'()'V'ided1:ly.tl:1~Ra~!.~_~l~.__fiEiIitTes:---
1
I
I
(
I
!
\
1
'\
1
I
I
J
l
I
I
1
J
)
(-
TABLE B.S.2.7:LOAD DIVERSITY IN THE RAILBELT
Railbelt Loads (MW)-January 6,1982
Non-
Coincident
UTILITY 2PM 3PM 4PM 5PM 6PM 7PM 8PM Peak
CEA 301.4 309.6 327.8 337.7 352.2 346.2 341.1 352.2
AMLP 109.0 107.0 117.0 114.5 116.0 112.0 107.0 117.0
GVEA 59.8 61.3 61.3 67.6 63.7 65.8 65.7 67.6
FMUS 26.0 26.2 26.1 25.6 24.0 23.5 22.5 26.2
TOTAL 496.2 506.1 532.2 545.4 555.9 547.5 536.3 563.0
Div.ersity =Coincident Peak =555.9 =.987
Non-coincident Peak 563.0
Rail belt Loads (MW)-January 10,1983
Non-
Coinciclent
UTILITY 2PM 3PM 4PM 5PM 6PM 7PM 8PM Peak
CEA 335.2 331.7 354.8 370.0 372.3 370.1 360.5 372.3
\I AMLP 117.0 117.0 121.0 119.0 115.0 114.0 112.0 121.0
LJ GVEA 65.3 67.9 72.2 71.8 70.7 70.2 70.1 72.2
FMUS 27.7 28.0 28.2 26.9 26.0 25.0 24.5 26.9
TOTAL 545.2 544.6 576.2 587.7 584.0 579.3 567.1 592.4
Diversity =Coincident Peak =587.7 =.992
Non-coincident Peak 592.4
Source:Applicants evaluation of 1982 and 1983 hourly load data provided by
Railbelt Utilities.
TA8LE 8.5.2.8:RESIDENTIAL AND,COMMERCIAL
ELECTRIC RATES.l/
ANCHORAGE-COOK INLET AREA
JUNE 1985
utility Energy Used
Residential Rates
(monthly )
(Page 1 of 2)
Electric Rate
Rate With Cost
of Power
Fixed Rate Adjustment
.1
Anchorage Municipal
Light &Power
Chugach Electric
Association,Inc.
Commercial Rates
(monthly )
Customer Charge $4.50
All kWh 5.15 cents/kWh 5.99 cents/kWh
Customer Charge $5.49
First 1500 kWh 6.00 cents/kWh 6.44 cents/kWh
Over 1500 kWh 4.50 cents/kWh 4.94 cents/kWh
Anchorage Municipal
Light &Power
Small General Service
25 kW or less
Large General Service
Over 25 kW
Customer Charge
All kWh
Customer Charge
Demand Charge
All kWh
$8.24
6.24 cents/kWh
$65.00
$7.22/kW
2.90 cents/kWh
7.08 cents/kWh
8.06 /kW
3.74 cents/kWh
.\
Exper.Time of Day
Chugach Electric
Association,Inc.
Small General Service
10 kW or Less
Customer Charge $18.00
7AM to 7PM 5.86 cents/kWh 6.70 cents/kWh
c~7P-M~to.JPM.~~.C .•C
To Amt.used
7PM to 7PM 2.41 cents/kWh 3.25 cents/kWh
Excess of Amt.
7PM to 7PM 1.64 cents/kWh 2.48 cents/kWh
Customer Charge $10.07
All kWh 5.69 cents/kWh 6.13 cents/kWh j
..···-·..--··-Over·-lO-kW-·..·-·..----..Customer-Charge....$-·30-;-51-cents..·....··_;;-"..·····..··-·.._-··
Demand Charge $7.93/kW
All 3.32 cents/kWh 3.76 cents/kWh
Sale for Resale Customer Charge
All kWh
Demand Charge
MEA
HEA
SES
$132.86
1.06 cents/kWh
$14.73 /kW
$14.23 /kW
$12.10 /kW
-1.41 cents/kWh
l/Source:Alaska Public Utility Commission,Rates for Regulated Utilities as of
June 14,1985.
TABLE B.5.2.8 (Page 2 of 2)
Electric Rate
utility
Residential Rates
(monthly )
Energy Used
Rate With Cost
of Power
Fixed Rate Adjustment
Homer Electric Assn.,
Inc.
Matanuska Electric
Assn.,Inc.
Seward Electric21
Systan
Commercial Rates
(monthly )
Homer Electric
Assn.,Inc.
Customer Charge
First 1000 kWh
Over 1000 kWh
Facility Charge
First 1300 kWh
Over 1300 kWh
Customer Charge
All kWh
$14.74
6.44 cents/kWh
5.21 cents/kWh
$10.00
7.51 cents/kWh
5.81 cents/kWh
$20.08/22.28
8.08 cents/kWh
7.57 cents/kWh
6.34 cents/kWh
8.52 cents/kWh
Non-Demand Metered
Demand Metered
Interruptible
Matanuska Electric
Assn.,Inc.
Seward Electric Systan
Small General Service
50 kW or Less
Large General Service
Over 50 kW
Customer Charge $29.48
All kWh 6.44 cents/kWh 7.57 cents/kWh
Customer Charge $176.90
Danand Charge
$4.30 /kW(over 25 kW)
All kWh 5.02 cents/kWh 6.15 cents/kWh
Customer Charge $176.90
Danand Charge
3.07 /kW(over 25 kW)$
All kWh 5.02 cents/kWh 6.15 cents/kWh
Facility Charge $25.00
Demand Charge $3.61 /kW
All kWh 4.48 cents/kWh
Customer Charge $36.25/45.49
All kWh 9.80 cents/kWh 10.24 cents/kWh
Customer Charge $36.25 cents/45.49
Demand Charge $28.31 /kW
All kWh 2.59 cents/kWh 3.03 cents/kWh
1/Source:Alaska Public Utility Commission,Rates for Regulated Utilities as of
June 14,1985.
11 Source:City of Seward Resolution 85-55,May 15,1985.
TABLE B.5.2.9:RESIDENTIAL AND COMMERCIAL ELECTRIC RATES1/
FAIRBANKS-TANANA VALLEY AREA JUNE 1985
Utility
Residential Rates
Fairbanks Municipal
Utilities System
Energy Used
Customer Charge
0-100 kWh
100-500 kWh
Over 500 kWh
Electric Rate
Rate With Cost
of Power
Fixed Rate Adjustment
$8.00
6.00 cents/kWh
8.00 cents/kWh
7.00 cents/kWh ,J
Golden Valley
Electric Assn.Cus tomer Cha rge
First 500 kWh
Over 500 kWh
$10 .00
11.25 cents/kWh
9.50 cents/kWh
$10.00 J
12.11 cents/kWh ~\
10.36 cents/kWh
Alaska Public Utility Commission,Rates for Regulated Utilities as of
June 14,1985.
Commercial Rates
Golden Valley
Electric Assn.
cents/kWh
cents/kWh
cents/kWh
cents/kWh
\
1
'\
j
15.86 cents/kWh '!
11.96 cents/kWh
10.36 cents/kWh
I
I
l
j
12.22
10.76
10.20
8.44
cents/kWh
cents/kWh
cents/kWh
$15.00
$13.00/kW
10.00 cents/kWh
9.00 cents/kwh
6.00 cents/kwh
$20.00
15.00
11.10
9.50
.····-··$4-0~-OO
$--6--;-25-t-kW .-------.-..-...
11.36 cents/kWh
9.90 cents/kWh
9.34 cents/kWh
7.58 cents/kWh
Customer Charge
0-4500 kWh
4500-5000 kWh
Over 5000 kWh
Customer Charge
Demand Charge
(Over 30kW)
First 500 kWh
500-1500 kWh
Over 15,000 kWh
-CUeft:omer "Cnarge-
.·Deman-d--Char·ge--·
0-4500 kWh
4500-10000 kWh
10000-15000 kWh
Over-15000 kWh
Source:
General Service
50 kW or Less
Fairbanks Municipal
Utilities System
1/
·-··GeneraTServi ce-
.-------···-Over-5-0--kW----·--
\
·l
j
TA BLE B•5•2•1°:ANCHORAGE MUNICI PAL LIGHT AND POWER CUMULATI VE
ENERGY CONSERVATION PROJECTIONS
Energy Conservation in MWh/yr
Program 1981 1982 1983 1984 1985 1986 1987
Weatherization 586 762 938 1,114 1,290 1,466 1,641
State Programs 879 1,759 2,199 2,683 3,078 3,518 3,737
Water Flow 200 464 464 464 464 464 464
Restrictions
Water Heat 3,922 3,922 3,922 3,922 3,922 3,922 3,922
Injection
Hot Water NA NA 249 249 249 249 249
Heater Wrap
Street Light °555 1,859 3,307 4,788 6,306 7,861
Conversion
Transmission ° °
4,119 8,732 9,256 9,811 10,399
Conversion
Boiler Pump 7,148 7,148 7,148 7,148 7,148 7,148 7,148
Conversion
TOTAL 12,735 14,609 20,896 27,619 30,195 32,614 35,421
Increase NA 14.7 43.0 32.2 9.3 9.8 8.6
From Previous
Year %
Source:AMLP,1983
!,
i i
l i
T~B:ciE B.S.2.11 :HISTQRICAL ECONOMIC AND ELECTRIC POWER DATA
YEAR
ITEM Unit!1960 1965 1970 1975 1980 1982 1984
i I
State oil and Gas ($million)
Revenues to
Genera 1 Fund 4.2 16.4 938.6 88.3 2,261.0 3,580.2 2,866.1
State General Fund
Expenditures n.a~157.7 249.6 661.4 1,375.7 3,848.0 3,346.0i
State Population 226,000 265,000 305,000 390,000 402,000 437,000 523,000
S tate Employment 94,OqO 110,000 133,000 198,000 211 ,000 232,000 264,000
Railbelt
Employment I n.a.74,000 89,000 130,000 132,000 154,000 n.a.,
Railbelt Population!140,000 n.a.200,000 n.a.276,000 307,000 371 ,000
Railbelt Households 37,OqO n.a.54,000 n.a.94,000 107,000 n.a.
Railbelt Electric
Energy Generation GNh
Anchorage 1/n.a 367 700 1,353 2,105 2,446 2,667
Fairbanks 1../n.a 120 222 452 443 491 541
Total n.a 487 922 1,805 2,548 2,937 3,208
'---'---'---~-----!J LJ!L..
\-.-_.
TABLE B.D.2.11 (Page 2 of 2)
YEAR
ITEM Unit 1960 1965 1970 1975 1980 1982 1984
It Peak 1/
nd MW
It Generation
city MW
n.a.
n.a.
107
n.a.
210
n.a.
420
n.a.
577
1,143
598
1,272
609
1,287
1/AML&r'CEA,Alaska Power AdministrationU~~~M
1/Alas a Electric Power Statistics 1960-1983,USDOE APAD.1984 values taken from utility annual reports.
Sources MAP Model Data Base;Federal Energy Regulatory Commission,Power System Statement;Alaska Power
Administration,Unpublished Printouts,1983.
11 Applicant's evaluation of 1983 Railbe1t utility hourly load data.
11 Includes total net generation byCEA,AMLPand APAD and sales to other
utilities.(This equals total Rai1be1t area except MEA purchase from APAD -
5 MW by contract).Source:Alaska Power Administration,unpublished printouts,
1983.
489
19831/
472
472 489
440 430
392 394
365 356
...304 319
291 306
291 304
299--315-
-34-g-·~35-5-.
429 396
445 414
451 458
1982
202 265 266
188 220 222
187 216 225
170 192 200
154 177 184
148 159 171
156 167 176
157 169 182
164 175 193
197 ·221 221
218 234 236
234 250 265
445
352
377
325
307
272
273
280
276·
:310·
350
401
445
1981
2,175 2,445 2,541
444
221
182
186
157
146
137
141
144
152
177
202
259
399
337
322
267
248
234
224
··241
259
311
350
444
2,104
19801979
209
210
185
162
146
132
136
138
142
168
179
238
395
2,045
358
395
340
268
233
231
217
.-220
245
287
316
391
1978
197
168
173
150
141
130
132
132
139
169
191
209
383
341
329
297
270
240
229
227
-237·-
--25-3·
312
353
383
NET ENERGY (GWh)
1,931
375
288
270
283
262
225
209
203
216····
253-
293
344
375
163
144
165
143
131
118
118
123
128
159
194
217
1977
1,803
1976
TABLE BO.5.2.12:MONTHLY LOAD DATA FROM ELECfRIC UTILITIES
OF '!HE ANCHORAGE-mOK INLET AREA
1976-198311
311
293
284
254
220
199
186
194
.198··
21-g-
278
276
311
January 161
Februa ry 151
March 147
April 127
May 117
June 103
July 108
August III
September 121
October 145
November 154
December 172
ANNUAL
ANNUAL 1,617
January
February
March
April
May
June
July
aug-ust
---S·eptember
October
November
December
TABLE B.5•2•13 :MONTHLY LOAD DATA FOR THE FAIRBANKS-T-!\NANA
VALLEY AREA 1976-198311
1976 1977 1978 1979 1980 1981 1982 198311
NET ENERGY (GWh)
January 56 48 52 49 50 42 54 55
February 53 41 45 51 38 41 45 46
March 44 47 45 42 38 38 43 47
April 34 38 36 35 33 35 39 39
May 30 32 32 30 31 32 35 27
June 27 29 30 28 28 30 32 34
July 28 29 30 30 30 30 34 35
August 29 31 31 29 30 30 34 37
September 31 31 33 32 32 34 36 40
October 40 41 40 36 36 39 43 44
November 43 54 44 37 41 42 46 47
December 53 61 48 48 56 49 50 55
ANNUAL 468 482 466 447 443 442 491 516
PEAK DEMAND (MW)
January.101 88 96 89 95 80 94 100
February 100 87 95 101 75 88 92 87
II March 82 86 82 81 70 68 82 80
April 65 73 71 66 60 65 73 68
May 55 60 58 56 56 65 67 67
June 50 56 58 54 54 60 63 63
July 54 54 55 56 56 59
61 64
August 53 56 55 57 59 61 71 68
September 60 65 63 60 61 66 70 72
October 82 79 72 67 71 72 82 80
November 84 102 86 72 76 78 89 83
December 97 118 84 88 95 93 89 98
ANNUAL 101 118 96 101 95 93 94 100
11 Data for FMUS and GVEA including purchases.Source:Alaska Power
Administration,unpublished printout,1983.
11 Applicant's evaluation of 1983 Railbelt utility hourly load da ta.
[
TA~LE B.5.2.14:
I
NET G.ENERATION BY RAILBELT UfILITIES
1976-11984
(GWh )!
Utility 197611
Anchorage
Municipal 444.9
L igh t &Power
Chugach
Electric Assn.1,054.5
Alaska Power
Administration 118.0
Anchorage Cook
Inlet Subtotal 1,617.4
Fairbanks
Municipal 123.3
Utility System
Golden Valley
Electric 344.7
As socia tion
Fairbanks Area
Sub-total 468.0
Rai1be1t Total 2l085.4
1977fJ/I
420.3,
1,179.7!
203 .~
1,803.~
128.~
353.5
481.~
2,285.3
[
197811
443.1
1,308.6
180.1
1,931.8
124.7
341.5
466.2
2,398.0
11 97911
'473.1
1
1,:401.0
171 .1
2,[045.2
'124.7
2.9
447.6
2,:492.8
[
198011
486.6
1,434.1
184.3
2,105.0
125.6
317.7
443.3
2,548.3
198111
485.3
1,467.2
223.2
2,175.7
126.1
316.9
443.0
2,618.7
198211
579.5
1,718.4
147.9
2,445.8
140.7
350.3
491.1
2,936.9
1983-6.1 1984
598.7 654.0
1,775.3 1873.7
149.5 139.2
2,523.5 2666.9
139.1 140.2
364.4 401.4
503.5 541.4
3,027.0 3208.3
Note:Subtotals and total shown m~y ;differ from co1uII\n totals due t.o rounding.
11
II
Source:Alaska Power
Alaska Electric Power
!
Admin stration,Unpublis~ed Printouts,1983.
!
Stati ti'cs 1960-1983,A11Ska Power Administration,Sept.1984.
..
~-~----
TABLE B.5.3.1:COMPARISON OF RECENT FY 1985
PETROLEUM PRODUCTION
REVENUE FORECASTS FROM PETREV
(IN MILLIONS OF DOLLARS)
TABLE B.5.3.2:MAP MODEL VALIDATION
SIMULATION OF HISTORICAL
ECONOMIC CoNDITIONS
Observed Estimated Percent
Factor Year Value Value Difference Difference
Non-Agricultural 1965 70,529 68,377 -2,152 -3.0
Wage and Salary 1970 92,465 90,949 -1,516 -1.6
Employment 1975 161,315 155,908 -5,407 -3.4
1980 170,807 165,323 -5,484 -3.2
1982 199,545 195,990 -3,555 -1.8
Wages and Salaries 1965 721 729 .8 1.1
In Alaska 1970 1,203 1,121 -82 -6.8
(million nominal $)1975 3,413 3,253 -160 -4.7
1980 4,280 4,390 110 2.6
1_982 5,938 5,963 25 0.4
Personc:ilIncome 1965 .827 814 --13 -1.6
In Alaska 1970 1,388 1,276 -112 -8.1
(million nominal $)1975 3,455 3,212 -243 -7.0
1980 5,152 .5,393 241 4.7
1982 7,384 7,437 53 0.7
SotiYce~ISER ·(1985)~.
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TABLE B.5.3.3:COMPARISON OF ACTUAL (Page 1 of 2)
AND PREDICTED ELECTRICITY
CONSUMPTION OF 1980-1983 (GWh)
RED SHCA Red Utility.J.!
Case Outputl/Adjustedl/Reported
Anchorage -Cook Inlet Area
1980
1
I,I Residential 980 939 936
Business 903 903 915
Others 109 109 109
Total 1,992 1,951 1,960
1981
Residential 1,034 1,030 916
Business 994 1,006 913
Others 117 117 139
Total 2,145 2,153 1,968
1982
Residential 1,088 1,096 1,033
Business 1,084 1,101 1,009
Others 126 126 160
Total 2,298 2,323 2,202
1983
Residential 1,142 1,069 1,059
Business 1,175 1,128 1,158
Others 135 135 97
Total 2,452 2,332 2,314
Fairbanks -Tanana Valley Area
1980
Residential 175 168 168
Business 234 234 239
Others 7 7 5
Total 417 408 412
1981
Residential 193 186 159
!I Others 7 7 4
Total 455 453 421
1/Two adjustments were made.First,residential space heat and
··au·tomooiTeana·EruCR·engine oTo-ckl:ieaterconsumptioii·was··scaTea~·bytfle
actual number of heating degree-days compared to the normal heating
degree days represented in the model.Second,the total use in both
load centers was scaled for price effects using actual retail prices
for electricity and estimated gas and oil prices for 1980-1983.Price
effects were individually calculated for each year because the RED
model contains data only for five year increments (i.e.1980,1985)
and not for each intervening year.The scaling mechanism for price
............effectsisfuU.y..documentedin··Scott.,Kingand.Moe···1985.·
Data from Alaska Power Administration,Alaska Electric Power
Statistics,u.S.Department of Energy,Juneau,Alaska.
o Sixth Edition,1960-1980,August 1981.
o Seventh Edition,1960-1981,August 1982.
o Eighth Edition,1960-1982,August 1983.
o Ninth Edition,1960-1983,September 1984.
Industrial consumption was estimatecr as Homer Electric Association
Largec:ommEarcial c,g,tegory,reported.in:Burns ,g,ncil1c:I>onnell,1983,
p.D.19.-I
TABL E B.S.4.1:FORECASTS OF WORLD
OIL PRICE APR M:>DEL
(1985 $/bbl)
Year Wharton Composite SHCA
1985 27.10 27.10 28.10
1990 24.80 26.50 27.70
1995 27.60 31.80 32.80
2000 31.30 38.10 41.00
2005 35.10 44.00 50.20
2010 40.70 51.00 61.50
Source:Exhibit D,Appendix D1
MAJOR VARIABLES AND ASSUMPTIONS
APR MODEL
1985 1.69
2010 0.15
1985 9.10
2010 4.27
1985 0.86
2010 0.65
1985 12.5
2010 12.6
1985 15.0
2010 15.0
1985 0.03
2010 0.18
1985 1.42
2010
TABLE B.5 .4.2:
Name
North Slope Oil Variables1/
Production (mmbbl/day)
Trans.&Quality Dif-
ferential (1985 $/bbl)
Prudhoe Bay Economic
Limi t Factor
Average State Royalty
Rate (%)
Average Nominal Sever-
ance Tax Rate (%)
North Slope Gas Variables1/
Production (bcf/day)
Price (1985 $/mcf)
Year Value
Same Value in All Cases
1/Alaska Department of Revenue,APR Data Disk,1985,except as noted
1/See Exhibit D
0.05
0.00
0.54
0.58
Values Vary :B~tY1~~I1Cc':lI3~§
site SHCA
"---"-"-------"-------""------"-""------
Cook Inlet Oil Variables1/
Production (mmbbl/day)
Cook Inlet Gas Variables1/
Production (bcf/day)
Cook Inlet Gas Variablesl/
Price (1985 $/mcf)
1985
2010
1985
2010
2010 4.97 6.43
.j
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i·
TABLE B.5.4.3:VARIABLES AND ASSUMPTIONS
MAP MODEL
Symbol Name Year Value
Same Value in
All Cases
EMAGRI
EMP9
EMCNX1
EMCNX2
EMT9X
EMMXl
EMMX2
EMFISH
EMQ:1
EMGC
TOURIST
GGRWEVS
UUS
GRDIRPU
GRUSCPI
RPBS
RPPS
RTCSPX
RPTS
RPRY
State Agricultural Employment
(Employees)
State Mining Employment
(Employees)
State High Wage Exog.Const.
Emp •.(Employees)
State Regular Wage Exog.
Const.Emp.(Employees)
State Exog.Transportation
Emp.(Employees)
State High Wage Manuf.Emp.
(Employees)
State Regular Wage Manuf.
Emp.(Employees)
State Fish Harvesting Emp.
(Employees)
State Active Duty Military
Emp.(Employees)
State Civilian Federal Emp.
(Employees)
Tourists Visiting Alaska
(Visitor.s )
U.S.Real Wage Growth/Year
U.S.Unemployment Rate
U.S.Real Per Capita Income
Growth/Year
Price Level Growth/Year
State Bonus Payment &Federal
Shared Royalties Revenue
(Million Nominal $)
State Petroleum Property Tax
Revenue (Million Nominal $)
State Petroleum Corporate Tax
(Million Nominal $)
State Petroleum Production Tax
Revenue (Million Nominal $)
State Petroleum Royalty
Revenue (Million Nominal $)
1985
2010
1985
2010
1985
2010
1985
2010
1985
2010
1985
2010
1985
2010
1985
2010
1985
2010
1985
2010
1985
2010
1985
2010
1985
2010
1985
2010
1985
2010
1985
2010
400
1,223
10,391
16,243
2,891
.336
218
o
1,116
2,335
o
o
11,129
12,104
7,608
8;233
21,818
19,570.
17,907
20,285
810,000
1,560,000
.01
.06
.015
.055
50.6
82.0
107.4
451.9
190.0
44.9
Values Vary
Composi te
1372.0
969.6
1372.0
1784.7
Between Cases
SHCA
1372.0
1191.3
1372.0
2207.3
TABLE B.5.4.4:SUMMARY OF MAP MODEL
PROJECTION ASSUMPTIONS
(SHCA AND COMPOSITE CASES)
(Page 1 of 5)',j
1
ASSUMPTIONS COMMON
TO BOTH CASES
NATIONAL VARIABLES ASSUMPTIONS
U.S.Inflation Rate
Real Average Weekly Earnings
Real Per Capita Income
Unemployment Rate
INDUSTRY ASSUMPTIONS
Trans-Alaska Pipeline
North Slope Petroleum
P.roduction_
DESCRIPTIONll
Consumer prices rise at 5.5 percent annually
after 1985 [GRUSCPI].
Growth in real average weekly earnings
averages 1 percent annually [GRRWEUS].
Growth in real per capita income averages 1.5
percent annually after 1984 [GRDIRPU]•
Long-run rate of 6 percent [UUS].
Operating employment remains constant at 990
through 2010 (~AP.F84).
Petroleum employment increases through the
e~J;'lyJiiQJL.~Q.jLpe aK..Qf.~!-~_.tl!Qtl ElCl!1cf ..and
subsequently tapers off gradually.
Construction employment is eliminated by the
late 1990s.This case presumes no
significant change in current oil price
trends (NSO.84B)•
,\
.}
1
Upper Cook Inlet Petroleum Employment in exploration and development of
oil and gas in the Upper Cook Inlet area
declines·grt,fdual-ly--be·ginning-in-198-3--by······
_..··---·approxi-mate·ly-2.5-percen·t-pe·r-yea·r-(-UPG..F84-)-.-..
OCS Development Exploration and development activity grows
through the mid-1990s and direct employment
continues through the following decade at a
slightly reduced level of approximately 7,000
(OCS.CM3 (-3))•
)
(.
TABLE B.5.4.4 (Page 2 of 5)
ASSUMPTIONS COMMON
TO BOTH CASES
Oil Industry Headquarters
Beluga Chuitna Coal Production
Healy Coal Mining
U.S.Borax
Greens Creek Mine
Red Dog Mine
Other Mining Activity
Agriculture
Logging and Sawmills
Pulp Mills
Commercial Fishing -
Nonbottomfish
DESCRIPTION1/
Oil company headquarters employment in
Anchorage rises by 1,150 between 1983 and
1986 to remain at around 4,600 through 2010
~OHQ.F84).
Development of 4.4 million ton/year mine for
export beginning in 1990 provides total
employment of 524 (BCL.04T(-4)).
Export of approximately 1 million tons of
coal annually will add 25 new workers to
current base of 100 by 1986 (HCL.84X).
The U.S.Borax mine near Ketchikan is brought
into production with operating employment of
790 beginning in 1989 and eventually
increasing to 1,020 (BXM.F84).
Production from the Greens Creek Mine on
Admiralty Island results in employment of 150
people from 1988 through 2003 (GCM.F84).
The Red Dog Mine in the Western Brooks Range
reaches full production with operating
employment of 428 by 1993 (RED.F84).
Mining employment not included in special
projects increases from current level at 1
percent annually (OMN.F84).
Moderate state support results in expansion
of employment in agriculture by 4 percent per
year (AGR.F83).
Employment expands to over 3,200 by 1990
before beginning to decline gradually to
about 2,800 after 2000 (FLL.F84).
Employment declines at a rate of 1 percent
per year after 1991 (FPU.F84).
Employment levels in traditional fisheries
harvest remain constant at 7,500 through 2010
(TCF.F84).
TABLE B.5.4.4 (Page 3 of 5)
ASSUMPTIONS COMMON
TO BOTH CASES
Commercial Fish Processing -
Nonbottomfish
Commercial Fishing -Bottomfish
Federal Military Employment
Light Army Division Deployment
Federal Civilian Employment
Tourism
DESCRIPTION1I
Employment in processing traditional
fisheries harvests remains at the level of
the average figure for the period 1978-1982,
or around 7,300 (TFP.F84).
The total U.S.bottomfish catch expands at a
constant rate to allowable catch in 2000,
with Alaska resident harvesting employment
rising to 733.Onshore processing capacity
expands in the Aleutians and Kodiak census
divisions to provide total resident
employment of 971 by 2000 (BCF.F83).
Emplo~ment declines at 1 percent per year,
consistent with the long-term trend since
1960 (GFM.F84).
A portion of a new Army division is deployed
to Fairbanks and Anchorage beginning in 1986,
augmenting active-duty personnel by 2,600
(GFM.JPR)•
Rises at 0.5 percent annual rate consistent
with the long-term trend since 1960
(GFC.F84)•
Number of visitors to Alaska increases by
30,000 per year to over 1.3 million by 2010
(TRS .XXX)•
1
1
..-..-.-.-.-.--.~--'."-'-'--~"---"'--'~-'-.----_...,._--_..-.._..._.._--_.•........._--,-....
State Hydroelectric Projects Construction employment Alaska
--Authori typro.fects~peaks af over 700in-T99-0 .
for construction of several projects in
Southcentral and Southeast Alaska (SHP.F83).
STATE PETROLEUM REVENUE ASSUMPTIONS
Bonuses
Property Taxes
Nominal average of past values net of major
sales (SHC.B85).
Aggregation of property taxes from specific
petroleum activities based upon March 1985
Alaska Department of Revenue estimates
(SHC.B85)and ISER estimates for OCS-related
activities (OCS.CM3(-3)).
L!
TABLE B.5.4.4 (Page 4 of 5)
ASSUMPTIONS COMMON
TO BOTH CASES
Petroleum Corporate Income
Tax
Rents
State Sharing of Federal
Petroleum Revenues
STATE FISCAL BEHAVIOR ASSUMPTIONS
State Appropriations
Capital/Operations Split
General Obligation Bonds
Municipal Capital Grants
Permanent Fund/Other Appro-
priations in Excess of
Spending Limit
Permanent Fund Principal
State Loan Programs
Permanent Fund Dividend
Use of Permanent Fund Earnings
Personal Income Tax
DESCRIPTION1/
No change from current method of calculating
tax base.Based upon March 1985 Alaska
Department of Revenue estimates (SHC.B85).
Approximately constant at real current level
[RPEN]•
Increasing $1 million annually in nominal
dollars with two steps of $10 million each in
the mid-199Gs [RSFDNPX].
If funds available,ceiling established by
Constitutional Spending Limit;otherwise
appropriations equal revenues [APGF].
Two-thirds operations if Spending Limit in
effect;three-fourths operations otherwise
[EXSPLITX]•
Bonding occurs up to point where debt service
is 5 percent of state revenues.
Funding terminated in FY 1987 [RLTMCAP].
None
Continuous accumulation.
New capitalization terminated in FY 1991
[EXSUBSX].
Dividend terminated after FY 1990
distribution [EXPFDIST].
Beginning in FY 1991,half of earnings
transferred to General Fund;beginning in
1993,all earnings transferred to General
Fund [EXPFTOGF].
Personal income tax reinstated in CY 1992.
TABLE B.5.4.4 (Page 5 of 5)
ASSUMPTIONS SPECIFIC
TO EACH CASE
COMPOSITE CAs~1
State Petroleum Revenue
Assumptions
Severance Taxes
Royalties
SHERMAN CLARK cAsElI
State Petroleum Revenue
Assumptions
DESCRIPTION11
Based on 1985 "APA Average"world oil price
projection used to drive Alaska Department
Revenue APR petroleum revenue model
(AOF.B85).
Based on 1985 "APA Average"world oil price
projection used to drive Alaska Department
Revenue APR petroleum revenue model
(AOF.B85).
'j
.!
!
of
]
of
1
Severance Taxes
Royalties
Based on 1985 Sherman Clark world oil price
projection used to drive Alaska Department of.Reve'nueAPR petroleum revenuemocfel .,
(SHC.B85).
Based on 1985 Sherman Clark world oil price
projection used to drive Alaska Department of
Revenue APR petroleum revenue model
(SHC.B85)•
._......_--_...__...._.,---------------------------------------------
11 Codes in brackets are model variables.Codes in parentheses indicate ISER
names for MAP Model SCEN case files.Industry and state petroleum revenue
assumptions are incorporated into the scenario generator.
2.1 Case HE53.3 with scenario S85.SUA3.j
:J..I Case HE53.1 with scenario S85.SUA3.
Symbol Name
TABLE B.5.4.5:VARIABLES AND ASSUMPTIONS
RED MODEL
SHCA and
Composite
Case Values
.(Page 1 of 3)
Source
Uncertainty Module
Fuel Price Forecast Table B.5.4.6
and B.5.4.7
1983 Actual Data
Combined with
Escalation Rates
b,c,d
SAT
ESR,
CEOSR,
CEGSR
Housing Demand Coefficients
Saturation of Residential
Appliances
Price Adjustment
Coefficients
,Table B.5.4.8 .Battelle (1983)
Table B.5.4.9 Battelle Northwest
End Use Survey;
Battelle (1983)
Table B.5.4.l0 Scott,King,and
Moe (1985)
Housing Module
I, I
J
THH
HH
Regional Household Forecast
State Households by Age
Group
Table
B.5.4.26
and
B.5.4.27
Table
B.5.4.26
and
B.5.4.27
MAP Output
MAP Outpu t
Residential Module
HI
AC
Households by Type of
Dwellings
Average Consumption of
Appliances
Table
B.5.4.28
and
B-5.4.29
Table B.5.4.1l
Housing Module Output
Battelle Northwest
End Use Survey;
Battelle (1983)
TABLE B.5.4.5 (Page 2 of 3)
Symbol Name
FMS Fuel Mode Split (Percentage
of Appliances Using
Electicity)
AS Initial Stock of
Appliances
I
.1
SHCA and
Composite
Case Values Source
Table B.5.4.11 Battelle (1983)
Table B.5.4.9 Battelle (1983)
and B.5 .4.11
c Growth in Electricity Use
of Applicances
Table B.5.4.12 Battelle (1983)j
Scott,King and Moe (1985
d Vintage Specific Survival
Rate
Business Consumption Module
TEMP Total Regional Employment
Table B.5.4.13
Table B.5.4.24
and B.5.4.25
Battelle (1983)
MAP Out put
"1
j
a,b Floors per Employee Table B.5.4.14 Scott ng and Moe 1985
BETA,
BBETA
Business Consumptions Table B.5.4.14 Scott,King and Moe 1985
Program-Induced Conservation Module
Not used
.....Misce.llaneo.u.s-Mo.duLe_.....~....
VACHG
vh
Vacant Housing
Consumption per Vacant
Housing
Table
B.5.4.30
B.5.4.31
300 kWh
Battelle (1983)
Battelle (1983)
\I
)J
TABLE B.5.4.5 (Page 3 of 3)
SHCA and
Composite
Symbol Name Case Values Source
S1 Street Lighting Consumption 1.0 percent Battelle (1983)
sh Proportion of Households 2.5 percent Battelle (1983)
Having a Second Home
shkWh Per Unit Second Home 500 kWh Battelle (1983)
Consumpt ion
Peak Demand Module
LF Annual Load Factor Exhibit D
Fairbanks 60.0 percent
Anchorage 60.0 percent
TABL E B.S.4 •6:FUEL PRI CE FORE CASTS USED BY RED -SHCA CASE
(1980 DOLLARS)
Anchorage -Cook Inlet Area Fal.rbanks -Tanana Valley Area
Year Residential Bus iness Re sident ial Bus iness
Heating Fuel Oil ($/MMBtu)
1980 7.75 7.20 7.83 7.50
1985 6.45 5.87 6.51 6.18
1990 6.36 5.79 6.42 6.10
1995 7.53 6.85 7.60 7.22
2000 9.41 8.56 9.49 9.02
2005 11.52 10.49 11.63 11.05
2010 14.11 12.84 14.24 13.53
Natural Gas ($/MMBtu)
1980 1.73 1.50 12.74 11.29
1985 2.11 1.74 10.60 9.12
1990 2.44 2.06 10.45 8.98
1995 4.23 2.97 12.37 10.64
2000 5.13 3.86 15.46 13.29
2005 6~10 4.84 18.94 16.29
2010 7.37 6.11 23.19 19.95
Electricity ($/kWh)
1980 .037 .034 .095 .090
1985 .057 .047 .082 .072
1990 .065 .053 .075 .066
--T99S ;076-;0-62 .
2000 .101 .082 .104 .091
2005 .105 .086 .107 .094
2010 .107 .088 .111 .096
1
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TABLE B.5.4.7:FUEL PRICE FORECASTS USED BY RED-COMPOSITE CASE
(1980 DOLLARS)
Anchorage -Cook Inlet Area Fairbanks -Tanana Valley Area
Year Residential Business Residential Business
Heating Fuel Oil ($/MMBtu)
1980 7.75 7.20 7.83 7.50
1985 6.45 5.87 6.51 6.18
1990 6.31 5.74 6.37 6.05
1995 7.55 6.88 7.63 7.25
2000 9.07 8.25 9.15 8.69
2005 10 .51 9.56 10.61 10 .08
2010 12.18 11 .09 12.30 11.68
Natural Gas ($/MMBtu)
1980 1.73 1.50 12.74 11.29
1985 2.11 1.74 10 .60 9.12
1990 2.43 2.05 10.37 8.92
1995 4.11 2.85 12.43 10.69
2000 4.80 3.54 14.90 12.81
2005 5.46 4.20 17.27 14.86
2010 6.23 4.97 20.02 17.22
Electricity ($/kWh)
I
J 1980 .037 .034 .•095 .090
1985 .057 .047 .082 .072
1990 .065 .053 .075 .066
1995 .071 .058 .077 .068
.2000 .091 .074 .094 .082
2005 .105 .086 .107 .094
2010 .105 .086 .107 .095
Source:Battelle (1983).
Note:These coefficients were used in the housing demand equations.A
detailed explanation of these equations is presented in Battelle (1983).
BAl -0.303 CAl 0.225 DAl 0.068
BA2 -0.175 CA2 0.086 DA2 0.039
BA4 0.080 CA4 -0.090 DA4 0.014
B2S 0.182 C2S -0.203 D2S 0.008
B3S 0.317 C3S -0.280 D3S -0.020
B4S 0.380 C4S -3.352 D4s -0.016
1
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Mobile Homes
Variable Value
Mu lti Fami ly
Variable Value
TABLE B.5.4.8:HOUSING DEMAND COEFFICIENTS
Single Family
Variable Value
TABLE B.5 .4 •9:EXAMPLE OF MARKET SATURATIONS OF APPLIANCES
IN SINGLE-FAMILY HOMES FOR ANCHORAGE-COOK
INLET AREA (PERCENT)
Refrigera tors Freezers Dishwashers Clothes Washers
Year Default Range Default Range Default Range Default Range
1980 99.0 88.3 78.2 91.7
1985 99.0 98-100 90.0 85-95 85.0 80-90 92.0 90-94
1990 99.0 98-100 90.0 85-95 90.0 85-95 92.5 90-95
1995 99.0 98-100 90.0 85-95 90.0 85-95 93.7 91-96
2000 99.0 98-100 90.0 85-95 90.0 85-95 95.0 92-98
2005 99.0 98-100 90.0 85-95 90.0 85'-95 95.0 92-98
2010 99.0 98-100 90.0 85-95 90.0 85-95 95.0 92-98
TABLE B.5.4.l0:PARAMETER VALUES IN RED MODEL PRICE
ADJUSTMENT MECHANISM
Source:Scott,King,and Moe (1985).
Short-Run Elasticities
Own-Price
Cross-Price
Natural Gas
Oil
Long-Run Elasticities
Own-Price
Cross-Price
'Natural Gas
Oil
La.'gged Adju stment
Residential
Sector
-O~12
0.0225
0.01
-0.40
0.075
0.033
0.700
Business
Sector
-0.15
0.0082
0.01
-0.50
0.027
0.033
0.700
1
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TABLE B.5.4.11:PERCENT OF APPLIANCES USING ELECTRICITY AND AVERAGE ANNUAL
ELECTRICITY CONSUMPTION,RAILBELT LOAD CENTERS,1980
Anchorage Fairbanks
Percentage US1ng Electr1c1ty Annual kWh Percentage US1ng EDectr1c1ty Annual kWh
Appliance SF MH DP MF Consumption SF MH DP MF Consumption
Space HeJt (Existing Stock)
Single Family 16.0 NA NA NA 32,850 9.7 NA NA NA 43,380
Mobile Home NA 0.7 NA NA 24,570 NA .0.0 NA NA 33,210
Duplex NA NA 22.8 NA 21,780 NA NA 11.7 NA 28,710
Multi-amily NA NA NA 44.4 15,390 NA NA NA 14.8 19,080
Space HeJt (New Stock)
32,850SingleFamily10.9 NA NA NA 9.7 NA NA NA 43,380
Mobile Home NA 0.7 NA NA 24,570 NA 0.0 NA NA 33,210
Duplex NA NA 15.0 NA 21,780 NA NA 11.7 NA 28,710
Multi-amily NA NA NA 25.0 15,390 NA NA NA 14.8 19,080
Water ~eaters (Existing)36.5 50.4 44.0 60.9 3,300 33.1 42.8 43.1 26.2 3,300
Water eaters (New)10.0 0.7 15.0 25.0 3,300 33.1 42.8 43.1 26.2 3,300
Dryers 84.3 88.1 81.3 86.6 1,032 96.2 94.6 94.4 100.0 1,032
Ranges 75.8 23.2 85.2 88.2 850 79.0 48.2 95.0 97.1 850
Sauna-Jacuzzis 93.5 100.0 93.7 81.8 2,000 61.8 100.0 60.8 100.0 2,000
Refrigtrators 100.0 100.0 100.0 100.0 1,800 100.0 100.0 100.0 100.0 1,800
Freeze s 100.0 100.0 100.0 100.0 1,342 100.0 100.0 100.0 100.0 1,342
Dishwashers 100.0 100.0 100.0 100.0 250 100.0 100.0 100.0 100.0 250
Additi~nal
Wate Heating (Existing)36.5 50.4 44.0 60.9 799 33.1 42.8 43.1 26.2 799
Wate Heating (New)10.0 0.7 15.0 25.0 799 33.1 42.8 43.1 26.2 799
Clothel Washers 100.0 100.0 100.0 100.0 90 100.0 100.0 100.0 100.0 90
Additi nal
Wate Heating (Existing)36.5 50.4 44.0 60.9 1,202 33~1 42.8 43.1 26.2 1,202
Wate Heating (New)10.0 0.7 15.0 25.0 1,202 33.1 42.8 43.1 26.2 1,202
Miscellaneous 100.0 100.0 100.0 100.0 2,110 100.0 100.0 100.0 100.0 2,466
Source:IBattelle (1983).
Source:Battelle (1983);Scott,King,and Moe (198S).
.......~}..·Tncrementd·growth·of·80-·kWhpercustomerrn·-Anchorage·S-yearperi·od·;--····_··
100 kWh in Fairbanks.
TABLE B.S.4.12:GROWTH RATES IN ELECTRIC
APPLIANCE CAPACITY AND INITIAL ANNUAL AVERAGE
CONSUMPTION FOR NEW APPLIANCES
Appliance
Space Heat
single Family
Mobile Home
Duplex
Multi-Family
Water Heaters
Clothes Dryers
Cooking Ranges
Sauna-Jacuzzis
Refrigerators
.Freezers
Dishwashers
Additional Water Heating
Clothes Washers
Additional Water Heating
Miscellaneous Appliances
Average Annual
kWh Consumption for
New Appliances (198S)
Anchorage Fairbanks
40,000 43,380
30,000 33,210
26,600 28,710
18,800 19,080
3,475 3,47S
1,032 1,032
1,2S0 1,2S0
1,7S0 1,7S0
1,S60 1,S60
1,SSO 1,SSO
230 230
740 740
70 70
1,OSO 1,OSO
2,160 2,S36
Growth Rate in
Electrical Capacity
Post 1985 (annual)
O.OOS
O.OOS
O.OOS
O.OOS
0.000
0.01
0.01
0.01
0.01
0.01
O.OOS
0.0
O.OOS
1/
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TABLE B.5.4.14:RED BUSINESS SECTOR ELECTRICITY
CONSUMPTION PARAMETERS
Variable Anchorage -Cook Inlet Fairbanks -Tanana Valley
1
1
Default
Value Range
Default
Value Range
Business Square Feet
of Floorspace Per Employeell
a i 383.023 317.5622
b 5.811 5.8112
Business Consump.tion
of ElectricityZ7
BETA 1 -2.2118 -.7980
BBETA i 1.224 1.003-1.416 .1.0 .826-1.081
11 Equation is STOCK it=(ai *b *t)*TEMP it
where:··.
STOCK it =Square feet of business floorspace,load center i,
year t
a i =intercept (1972 value)square footage per employee in
each load center i,year t
b=growth rate parameter
TEMP it =Total employment,load center l,year t
ZI Equation is PRECON ik =exp [BETA i +BBETA i x In (STOCK ik)]
PRECON ik =Nonprice-adjusted business consumption (MWh),load center 1
forecast period K
BETA i =patametet equal to regression equation intercept,load center 1
BBETA i =percentage change in business consumption for a 1%change
in stock (floorspace elasticity),load center i
STOCK ik square feet of business floorspace,load center l,forecast period k.
1
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TABLE B.5.4.15:VARIABLES AND ASSUMPTIONS --OGP MODEL
ECONOMIC PARAMETERS
1.All Costs in January 1985 Dollars
2.Base Year for Present Worth Analysis:1985
3.Analysis Periods:
System Expansion:1996-2025
Annual Cost Extension:2026-2054
4.Electrical Load Forecast:1985 to 2025
5.Discount Rate:3.5 percent
6.Inflation Rate:0 percent
7 ..Economic Life of projects:
(Page 1 of 3)
Combustion Turbines:
Combined Cycle Turbines:
Steam Turbines
Hydroelectric Projects
Transmission
8.Annual Fixed Carrying Charges
25 years
30 years
35 years
50 years
50 years
Cost of Money
Amortization
Insurance
Total
25-year
Life
3.50
2.57
0.25
6.32
30-year 35-year 50-year
Life Life Life
3.50 3.50
3.50
1.94 1.50 0.70
0.25 0.25 0.10
5.69 5.25 4.36
I I
9.Susitna Project Construction Cost,$mill ion
Watana Stage I 2682
Devil Canyon Stage II 1394
Watana Stage III 1319
Total 5395
10.Susitna Annual Operation and Maintenance Cost,$million
1999-2004
2005-2011
2012-2017
2018-2025
11.50
12.75
12.75
11.45
TABLE B.5.4.15 (Page 2 of 3)
Coal
200 MWl/Parameters
THERMAL GENE RATI NG PLANT
Combined
Cycle
229 MW
PARAMETERS (1985 $)
Combustion
Turbine
87 MW6./
......--ll--Gross···out-pu-t·at··30.9--F--is237-.-3MW··and-inc1udes--correctioo···
.-----..---'------..--for--water--in:iection for--NOx.contI'o-1·,net-out-puG-o-f-.-·2-30--MW--·
includes correction for station auxiliary loads.
~/Values reflect assembly of three units,gross output at
30°F is 268.8 MW and includes correction for water injec-
tion for NOx control,net output of 262 MW (87.3 MW each)
includes correction for station auxiliary loads.
J,./Includes AFDC at.3.5 percent interest assuming an S""sha.ped
expenditure curve.
Heat Rate (Btu/kWh)
Earliest Availability
O&M Costs
Fixed O&M ($/kW/yr)
Variable O&M ($/MWh)
Outages
Planned Outages (%)
Forced Outages (%)
Construction Period (yrs)
Startup Time (yrs)
Unit Capital Cost ($/kW)
Beluga/Railbelt
Nenana
Unit Capital Cost ($/kW):J/
Beluga/Railbelt
Nenana
10,300
1992
61.42
4.30
8
5.7
6
3
2,593
2 702
2,877
2,998
9,200
1988
13.26
0.66
7
8
2
2
650
673
12,000
1988
8 •.76
0.58
3.2
8
1
1
386
393
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TABLE :8.5.4.15 (Page 3 of 3)
FUEL PRICES (1985)
SHCA Forecast Composite Forecast Forecas tl/
Coal Price Coal Price
Nenana Beluga Nenana Beluga
Year I Delivered Minemouth Oil Ga s 'I/Del ivered Minemouth Oil .Gas 'I/Oil Gasl/
($/MMBtu)($/MMBtu)($/bbl)($/MMBtu)$/MMBtu $/MMBtu ($/bbl)($/MMBtu)($/bbl)($/MMBtu)
1985 I 1.84 1.32 28.10 2.13 1.84 1.42 2710 1.98 27.10 1.97
1990 I 1.99 1.45 27.70 2.08 1.99 1.5'4 26.50 1.90 24.80 1.66
1995 I 2.14 1.60 32.80 2.80 2.14 1.65 31.80 2.65 27.60 2.05
2000 I 2.31 1.78 41.00 3.95 2.31 1.78 38.10 3.53 31.30 2.57
2010 I 2.69 2.13 61.50 6.83 2.69 2.19 51.00 5.37 40.70 3.89
2020 I 3.13 2.55 85.00 10.15 3.13 2.57 68.90 7.85 54.60 5.83
2030 3.64 3.30 96.00 11.70 3.64 3.08 75.00 8.70 73.40 8.84
2040 4.24 4.10 106.00 13.12 4.24 3.22 75.00 8.70 75.00 8.70
2050 4.94 5.12 117.00 14.67 .4.94 3.74 75.00 8.70 75.00 8.70
1_/Cdmposite forecast coal prices assumed for Wharton forecast.
2_/Includes 0.40 $/MMBtu charge for delivery.
TABLE B.5.4.16:SHCA CASE FORECAST SUMMARY
OF INPUT AND OUTPUT DATA
Item Description 1985 1990 1995 2000 2005 2010
World Oil Price (1985$/bbl)28.10 27.70 32.80 41.00 50.20 61.50
Energy Price Used by RED (1980$)
Heating Fuel Oil-Anchorage
($/MMBtu)6.45 6.36 7.53 9.41 11.52 14.11
Natural Gas -Anchorage
($/MMBtu)2.11 2.44 4.23 5.13 6.10 7.37
State Petroleum RevenueslJ
(Million Nominal $)
Production Taxes 1,372 1,299 1,286 994 903 1191
Royalty Fees 1,372 1,826 2,031 1,983 1,912 2,207
State General Fund Expenditures
(Million Nominal $)3,665 3,773 5,692 5,831 6,387 7,762
State Population 536,525 563,923 597,969 632,655 657,639 699,607
State Employment 269,087 281,962 304,522 319,827 325,447 348,304
Railbelt Population 381,264 399,873 422,238 440,956 468,823 506,384
Railbelt Employment 181,885 189,109 201,168 210,611 222,663 243,163
Railbelt Total Number of
Households 134,300 142,574 152,499 161,248 172,218 186,823
Railbelt Electricity Consumptionb /
(GWh)
Anchor.age 2,Zl5..2,284 2,.983 .3,079 ..3,336...3.,848
Fairbanks 608 797 902 919 978 1,081
Total 3,323 3,581 3,885 3,998 4,314 .4,929
Railbelt Peak Demand (MW)632 681 739 761 821 938
1/Petroleum revenues also include corporate income taxes,oil and gas property
taxes,lease bonuses,rents,and federal shared royalties.
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TABLE B.5.4.17:COMPOSITE CASE FORECAST SUMMARY
OF INPUT AND OUTPUT DATA
Item Description 1985 1990 1995
2000 2005 2010
World Oil Price (1985$/bbl)27.10 26.50 31.80 38.10 44.20 51.00
Energy Price Used by RED (1980$)
Heating Fuel Oil-Anchorage
($/MMBtu)6.45 6.31 7.56 9.07 10.51 12.18
Natural Gas -Anchorage
($/MMBtu)2.11 2.43 4.11 4.80 5.46 6.23
State Petroleum Revenuesl /
(Million Nominal $)
Production Taxes 1,372 1,224 1,238 913 783 970
Royalty Fees 1,372 1,717 1,953 1;819 1,650 1,785
State General Fund Expenditures
(Million Nominal $)3,665 3,610 5,280 5,586 6,009 7,131
State Population 536,525 562,317 595,023 '6Q8,969 653,542 695,215
State Employment 269,087 280,177.302,226 318,010 323,335 346,249
Railbelt Population 381,264 398,969 419,236 438,363 465,911 503,372
Railbelt Employment 181,885 187,967 199,116 209,340 221,172 241,761
Railbelt Total Number of
Households 134,300 142,243 151,445 160,294 171,129 185,668
Railbelt Electricity Consumptionl/.
(GWh)
Anchorage 2,715 2,770 3,003 3,160 3,344 3,815
Fairbanks 608 793 907 943 981 1,073
i I Total 3,323 3,563 3,910 4,103 4,325 4,888
I !Railbelt Peak Demand (MW)632 678 744 781 823 930~J
1/Petroleum revenues also include corporate income taxes,oil and gas property
taxes,lease bonuses,rents,and federal shared royalties.
1/At customer level
I.
TABLE B.5.4.18:SHCA CASE STATE PETROLEUM REVENUES (Million Nominal $)
Total Total to
Including General
Bonuses,Fund (Net
Rents,of
and Permanent
Corporate Federal Fund
Severance Income Property Shared Contri-
Year Royalties Taxes Taxes Taxes Royalties bution)
1983 1437.900 1493.000 236.000 152.600 3420.600 3035.849
1984 1396.700 1392.400.265.100 131.000 3237.300 2875.100
1985 1372.000 1372 .000 190.000 107.400 3092.000 2736.350
1986 1695.265 1627.469 24.2.100 102.900 3701.734 3269.417
1987 1828.607 1735.756 264.200 107.000 3970.563 3504.661
1988 1848.434 1453.355 274.100 116.523 3728.412 3257.303
1989 1863.817 1411.140 294.200 137.637 3743.794 3268.590
1990 ...1826.438 ....1299.429 304.000 144.649 3612.515 3146.406
1991 1894.220 1316.453 303.700 147.376 3701.749 3169.838
1992 1971.221 1337.337 29L 700 140.725 3781.982 3228.621
1993 2054.794 1379.784 297.800 156.315 3912.693 3283.655
1994 2050.586 1355.180 268.100 165.402 3882.268 3254.192
1995 2030.882 1285.693 251.100 161.875 3783.550 3158.085
1996 2023.862 1247.807 235.200 206.137 3779.006 3152.047
1997 2046.940 1215.856 222.600 230.911 3783.307 3149.124
1998 2046.433 1167.739 200.700 270.521 3753.394 3119.063
1999 2008.302 1070.878 179.300 306.096 3633.576 3010.385
2000 1983.280 993.533 158.400 379.048 3584.261 2968.277
2001 1843.249 842.240 138.000 449.979 3345.468 2770.893
2002 1780.510 792.668 121.800 486.557 3254.535 2698.482
..------_..--._----,--,.······-··-200T --18T4'~T69"····-814:537 ..--TOT~500 485~099-"'329S~304 ···---27Z8-~853'
-~-"---_._---··-----2004-·..--t8-5-4--.-22-1~"-851--;.-4-50'-.."9'4--;900-4-83-;-2,0-"--3358;-8-4-]:----·-2780-;-0,-4-..
2005 1911.559 902.923 83.800 480.773 3455.055 2858.787
2006 1955.380 951.888 74.000 477 .435 3536.702 2926.688
2007 2031.676 1025.718 65.300 473.079 3674.773 3041.570
2008 2035.953 1062.136 57.600 467.558 3703.246 3068.460
2009 2118.701 1112.038 50.900 460.572 3823.211 3163.300
2010 2207.310 1191.319 44.900 451.948 3977.478 3290.684
Source:MAP Model Output.Files RE53.1 and HER53.1.Variables:RPRY,RPTS,
RTCSPX,RPPS,RP9S,and RP9SGF.
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TABLE B.5.4.19:.COMPOSITE CASE STATE PETROLEUM REVENUES (Million Nominal $)
Total Total to
Including General
Bonuses,Fund (Net
Rents,of
and Permanent
Corporate Federal Fund
Severance Income Property Shared Contri-
Year Royalties Taxes Taxes Taxes Royalties bution)
1983 1437.900 1493.000 236 ..000 152.600 3420.600 3034.849
1984 1396.700 1392.400 265.100 131.000 3237.300 2875.100
1985 1372.000 1372.000 190.000 107.400 3092.000 2736.350
1986 1605.383 1544.257 242.100 102.900 3528.640 3118.794
1987 1729.298 1644.928 264.200 107.000 3780.426 3339.351
1988 1746.100 1375.635 274.100 116.523 3548.358 3102.833
1989 1757.513 1333.247 294.200 137.637 3559.597 3110.969
1990 1717.382 1224.391 304.000 .144.649 3428.422 2989.576
1991 1790.046 1246.316 303.700 147.376 3527.438 3024.175
1992 1871.650 1271.800 291.700 140.725 3616.875 3090.896
1993 1960.157 1318.919 279.800 156.315 3756.291 3155.644
1994 1963.875 1299.419 268.100 165.402 3739.796 3137.733
1995 1953.026 1237.628 251.100 161.875 3657.629 3055.521
1996 1927.142 1189.558 235.200 206.137 3624~037 3026.994
II 1997 1930.842 1148.461 222.600 230.911 3599.814 3000.461
1998 1912.060 1092.759 200.700 270.521 3544.041 2950.022
LJ 1999 1858.931 993.055 179.300 306.096 3406.382 2828.002
2000 1818.815 912.904 158.400 379.048 3339.167 2772.522
2001 1669.401 764.645 138.000 449.979 3094.025 2571.604
2002 1593.035 711.232 121.800 486.557 2985.623 2485.812
2003 1603.990 722.449 107.500 485.099 2993.038 2489.641
2004 1620.013 746.507 94.900 483.270 3019.690 2511.186
2005 1650.406 782.548 83.800 480.773 3073.528 2555.605
2006 1667.140 815.027 74.000 477 .435 3111.602 2588.060
2007 1710.077 867.402 65.300 473.079 3194.857 2658.134
2008 1690.615 886.851 57.600 467.558 3182.624 2651.439
2009 1736.014 916.641 50.900 460.572 3245.126 2700.022
2010 1784.688 969.571 44.900 451.948 3333.107 2773.100
Source:MAP Model Output Files HE53.3 and HERS3.3.Variables:RPRY,R?TS,
RTCSPX,RPPS,RP9S,and RP9SGF.
TABLE B.5.4.20:SHCA CASE STATE GOVERNEMENT FISCAL CONDITIONS
(Million Nominal $)
Unre-Percent of
stricted Permanent
General Fund Earn-
Fund General Permanent State State ings to
Expendi-Fund Fund Personal Subsidy General
Year tures Balance Dividends Income Tax Programs Fund
1983 3499.489 2315.700 176.000 0.000 274.700 23.0
1984 3518.373 2041.822 193.917 0.000 250.000 0.0
1985 3664.836 1497.312 190.524 0.000 250.000 0.0
1986 3410.682 1712.316 238.049 0.000 250,.000 0.0
1987 3736.196 1865.815 269.060 0.000 250.000 0.0
1988 3915.580 "'1611.859 291.666 0.000 250.000 0.0
1989 4150.453 1125.223 314.778 'O.000 200.000 0.0
1990 3772.734 873.367 350.895 0.000 100.000 0.0
1991 4012.436 868.398 0.000 0.000 0.000 50.0
1992 4295.910 935.254 0.000 244.207 0.000 50.0
1993 4922.473 1304.047 0.000 494.410 0.000 100.0
1994 5736.023 993.992 0.000 557.415 0.000 100.0
1995 5692.410 739.742 0.000 609.495 0.000 100.0
.__._._.~---.-~.._--~~._-_._-_._-
1996 5663.820 604.469 0.000 651.376 0.000 100.0
1997 5611.551 623.102 0.000 691.34.9 0.000 100.0
1998 5708.297 640.164 0.000 745.909 0.000 100.0
1999 5750.297 646.602 0.000 804.565 0.000 100.0
2000 5831.277 666.785 0.000 865.454 0.000 100.0
2001 5802.555 659.980 0.000 925.312 0.000 100.a
2002 5833.957 668.094 0.000 974 •.152 0.000 100.0
-------200:3-----591-0·.-074-------695~-758--····-----0;-000 ·---1029;-248----0-;,-000 -100-;0--'--'---
·-··-----2-004--····--6-g4-.-2-70----7-3~.9.Q_6---0.000---1096-.:306---0-;-000-----100-;-0------.
2005 6386.668 778.551 0.000 1174.044 0.000 100.0
2006 6634.203 818.473 0.000 1261.026 0.000 100.0
2007 6927.227 862.113 0.000 1350.871 0.000 100.0
2008 7150.926 899.289 0.000 1446.110 0.000 100.0
2009 7421.859 964.199 0.000 1551.661 0.000 100.0
2010 7762.457 1039.770 0.000 1669.305 0.000 100.0
Source:MAP Model Output Files HE53.1 and HERS3.1.
Variables:EXGFBM,BALGF9,EXTRNS,RTIS,EXSUBS,and EXPFTOGF.
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TABLE B.5.4.21:COMPOSITE CASE STATE GOVERNMENT FISCAL CONDITIONS
(Million Nominal $)
Unre-Percent of
stricted Permanent
General Fund Earn-
Fund General Permanent State State ings to
Expendi-Fund Fund Personal Subsidy General
Year tures Balance Dividends Income Tax Programs Fund
1983 3499.489 2315.700 176.000 0.000 274.700 23.0
1984 3518.373 2041.822 193.917 0.000 250.000 0.0
1985 3664.836 1497.312 190.524 0.000 250.000 0.0
1986 3497.226 1475.323 237.954 0.000 250.000 0.0
1987 3519.947 1662.631 268,.661 0.000 250.000 0.0
1988 3907.627 1246.773 290.727 0.000 250.000 0.0
1989 4133.516 591.129 313.038 0.000 200.000 0.0
1990 3610.305 303.882 348.073 0.000 '100.000 0.0
1991 3810.986 303.789 0.000 0.000 0.000 50.0
1992 4104.195 370.859 0.000 242.797 0.000 50.0
1993 4943.199 526.613 0.000 493.807 0.000 100.0
1994 5215.172 538.273 0.000 555.853 0.000 100.0
1995 5279.566 529.848 0.000 604.697 0.000 100.0
1996 5344.398 537.188 0.000 645.287 0.000 100.0
tJ
1997 5422.613 553.246 0.000 685.799 0.000 100.0
1998 5498.207 566.367 0.000 741.467 0.000 100.0
1999 5522.371 569.859 0.000 800.179 0.000 100.0
2000 5585.840 586.949 0.000 860.942 0.000 100.0
2001 5547.316 578.715 0.000 920.752 0.000 100.0
2002 5562.297 583.645 0.000 969.491 0.000 100.0
2003 5669.082 605.258 0.000 1024.249 0.000 100.0
2004 5818.734 635.445 0.000 1090.747 0.000 100.0
2005 6009.129 671.547 0.000 1167.367 0.000 100.0
2006 6207.797 706.578 0.000 1252.621 0.000 100.0
2007 6446.035 745.398 0.000 1341.272 0.000 100.0
2008 6627.434 777.578 0.000 1436.832 0.000 100.0
2009 6850.598 830.434 0.000 1543.331 0.000 100.0
2010 7130.594 889.020 0.000 1660.639 0.000 100.0
Source:MAP Model Output Files HE53.3 and HER53.3.
Variables:EXGFBM,BALGF9,EXTRNS,RTIS,EXSUBS,and EXPFTOGF.
~ABLE B.5.4.22:SHCA CASE POPULATION (thousands)
Greater Greater
Year State Railbelt Anchorage Fairbanks
1983 510.484
1984 527.453 374.240 301.002 73.238
1985 536.525 381.264 307.278 73.987
1986 549.371 391.208 311.344 79.864
1987 551.850 390.471 310.969 79.503
1988 553.178 391.972 312.366 79.607
1989 560.657 397.279 317.269'80.011
1990 563.923 399.873 ·320.000 79.874
1991 567.837 402.244 321.868 80.376
1992 569.795 401.942 321.495 80.447
1993 576.465 406.349 '324.935 81.414
1994 589.708 417.667 334.396 '83.272
1995 597.969 422.238 338'.649 83.590
1996 603.645 419.442 336.577 82.865
1997 607.509 423.985 340.597 83.388
1998 616.940 422.667 339.905 82.763
1999 623.645 432.981 348.769 84.213
2000 632.655 440.956 355.751 .206
2001 638.154 450.147 363.651 86.496
2002 641.315 452.291 365.571 86.721
2003 645.454 457.491 370.066 87.425
2004 651.059 462.966 374.809 88.157
2005 657.639 468.823 379.953 88.870
2006 665.142 475.693 385.946 89.747
---.-.__......_.•.__..,--"'.-..-.-".---.---..._--_.-._.-._.._..-.-.---_._---------.2007-...._.......612.362 _······_·.··0·------482.381 .391.752 ...........90.•630
- -.-_.._~_._--~----~-_.__..__.._---_._•.._._._-~.._._-----...2.0_0_a_._...._6_8_0___2_2_6___...~2..:i~_.__J97 .903 ..91.452 _...._-----
2009 689.099 497.095 404.682 92.414
2010 699.607 506.384 412.734 93.651
Source:MAP Model Output Files HE53.1 and HER53.1.
Variables:POP,P.IR,P.AG,and P.FG.
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TABLE B.5.4.23:COMPOSITE CASE POPULATION (thousands)
Greater Greater
Year State Railbelt Anchorage Fairbanks
1983 510.484
1984 527.453 374.240 301.002 73.238
1985 536.525 381.264 307.278 73.987
1986 550.839 391.606 311.573 80.033
1987 551.434 389.888 310.504 79.385
1988 552.191 390.945 311.520 79.426
1989 559.888 396.563 316.673 79.891
1990 562.317 398.969 319.317 79.653
1991 565.875 401.077 320.956 80.122
1992 567.640 400.610 320.444 80.166
1993 576d55 405.522 324.154 81.369
1994 587.631 415.703 332.791 82.913
1995 595.023 419.236 336.150 83.086
1996 599.708 416.280 334.018 82.262
1997 603.835 421.303 338.419 82.884
1998 613.332 420.115 337.833 82.282
1999 619.991 430.404 346.681 83.723
2000 628.969 438.363 353.654 84.709
II 2001 634.505 447.581 361.579 86.003
2002 637.662 449.725 363.500 86.226
,...-.)641.739 454.889 367.968 86.9222003
2004 647.234 460.295 372.658 87.638
2005 653.542 465.911 377.608 88.303
2006 660.673 472.421 383.303 89.118
2007 667.716 478.976 388.991 89.986
2008 675.723 486.141 395.288 90.854
2009 684.784 494.124 402.265 91.859
2010 695.215 503.372 410.295 93.077
Source:MAP Model Output Files HE53.3 and HER53.3.
Variables:POP,P.IR,P.AG,and P.FG.
TABLE B.5.4.24:SHCA CASE EMPLOYMENT
(thousands)
State
Non-Ag Greater Greater
Wage and State Railbelt Anchorage Fairbanks
Year Salary Total Total Total Total
1983 213.243 254.642
1984 222.290 264.038 179.069 142.623 36.446
1985 227.237 269.087 181.885 145.242 36.643
1986 230.977 275.622 186.029 146.478 39.551
1987 230.747 275.175 184.430 145.319 39.112
1988 231.062 275.298 185.665 146.309 39.356
1989 237.587 282.046 189.091 149.379 39.712
1990 237.706 281.962 189.109 149.717 39.392
1991 239.485 283.649 190.640 150.843 39.797
1992 239.117 283.060 190.715 150.751 39.964
1993 244.731 288.840 192.612 152.380 40.232
1994 256.670 301.365 198.950 157.805 41.145
1995 259.797 304.522 201.168 159.816 41.352
1996 260.901 305.539 201.285 159.853 41.433
199Z ....2.60 ....~.~__.~4..a4.2 201.Z2A ..16Q.~,3Jl6 ..A1.378
1998 267.445 312.240 203.778 162.172 41.606
1999 269.222 314.032 206.967 164 ..989 41.978
2000 274.802 319.827 210.611 168.225 42.386
2001 275.004 319.843 213.426 170.652 42.773
2002 273.982 318.556 214.858 171.710 43.148
2003 274.888 319.326 216.952 173.465 43.487
2004 277.481 321.894 219.582 175.696 43.886
-200S-...280;;995 .·----325-;'447···-222:-663-··------178;;-343 ------44;320-
--~~-~--"-~~~._-_.._-------~~-~._----~-~--~------_.-----_._---..~~_._..__._._._-
2006 285.102 329.634 226.402 181.529 44.873
2007 288.438 333.002 230.098 184.620 45.479
2008 292.451 337.094 233.656 187.694 45.961
2009 297.192 341.965 237.800 191.240 46.561
2010 303.306 348.304 243.163 195.767 47.396
Source:MAP Model Output Files HE53.1 and HER53.1.
Variables:EM97,EM99,M.IR,M.AG,and M.FG.
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TABLE B.5.4.25:COMPOSITE CASE EMPLOYMENT (thousan~s)
State
Non-Ag Greater Greater
Wage and State Railbelt Anchorage Fairbanks
Year Salary Total Total Total Total
1983 213.243 254.642
1984 222.290 264.038 179.069 142.623 36.446
1985 227.237 269.087 181.885 145.242 36.643
1986 232.708 277.462 187.016 147.205 39.812
1987 229.835 274.206 183.619 144.679 38.940
1988 229.786 273.942 184.560 145.424 39.136
1989 236.797 281.206 188.419 148.836 39.583
1990 236.028 280.177 187.967 148.837 39.130
1991 237.719 281.771 189.426 149.896 39.530
1992 237.420 281.254 189.540 149.833 39.707
1993 245.445 289.600 192.846 152.501 40.345
1994 254.997 299.584 197.462 156.611 40.851
1995 257.641 302.226 199.116 158.141 40.975
1996 258.035 302.488 198.978 158.013 40.965
1997 258.304 302.631 200.169 159.111 41.059
IJ 1998 265.601 310.276 202.399 161.068 41.330
1999 267.451 312.145 205.644 163.933 41.712
2000 273.096 318.010 209.340 167.212 42.128
2001 273.398 318.132 212.230 169.700 42.530
2002 272.404 316.875 213.684 170.776 42.908
2003 273.268 317.600 215.750 172.510 43.240
2004 275.770 320.071 218.317 174.692 43.625
2005 279.013 323.335 221.172 177.159 44.013
2006 282.796 327.176 224.621 180.110 44.511
2007 286.091 330.500 228.281 183.167 45.115
2008 290.405 334.912 232.107 186.452 45.655
2009 295.394 340.048 236.489 190.190 46.299
2010 301.379 346.249 241.761 194.650 47.111
Source:MAP Model Output Files HE53.3 and HER53.3.
Variables:EM97,EM99,M.IR,M.AG,and M.FG.
Source:MAP Model Output Files HE53.1 and HER53.1.
Variables:HH,HH.IR,HH.AG,and HH.FG.
174.930 142.268 32.662
177.555 144.530 33.026
-T8"0".-Z89-.-"-"-""T4-6:913"--".-".··:rf:36'6--"----
....."--.1"8'3-:-;289-"""-"-···"-r-lf9-;-533-"--------33--;75·6~_:_----.
186.823 152.580 34.243
131.373 106.128 25.246
134.300 108.704 25.596
137.863 110.118 27.745
138.002 110.306 27.696
138.830 Ill.035 27.795
141.253 113.204 28.050
142.574 114.496 28.079
143.725 115.402 28.322
143.962 115.544 28.418
146.003 117.144 28.859
150.409 120.808 29.601
152.499 122.694 29.805
152.187 122.509 29.678
154.032 124.123 29.909
154.385 124.544 29.841
158.106 127.737 30.369
161.248 130.468 30.780
164.568 133.316 31.252
165.607 134.220 31.388
167.646 135.968 31.677
169.862 137.871 31.991
172.218 139.921 32.298
SHCA CASE HOUSEHOLDS (thousands)
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(Page 1 of 2)
Greater
Fairbanks
Greater
AnchorageRailbelt
TABLE B.5.4.26:
Year State
1983 171.664
1984 178.150
1985 181.869
1986 186.311
1987 '187.702
1988 188.676
1989 191.754
1990 193.379
1991 195.217
1992 196.374
1993 199.139
1994 204.155
1995 207.471
1996 209.895
1997 211.690
1998 215.375
1999 218.129
2000 221.663
2001 223.997
2002 225.523
2003 227.368
2004 229.700
2005 232.357
2006 235.322
2007 238.186
····1UO-8------":r4T:T64-
"-'-'''''-----""2009--------2-lflj;';;"o79"---""
2010 248.645
TABLE B.5.4.26 (Page 2 of 2)
Head
Younger Head Head Head Older
Year Total Than 25 25-29 30-54 Than 54
1983 171.664 21.132 29.622 96.310 24.600
1984 178.150 21.394 30.205 100.802 25.749
1985 181.869 21.155 30.102 103.790 26.822
1986 186.311 21.134 30.299 106.954 27.923
1987 187.702 20.623 29.714 108.371 28.994
1988 188.676 20.138 29.106 109.340 30.092
1989 191.754 20.099 29.134 111.210 31.311
1990 193.379 19.837 28.828 112.204 32.510
1991 195.217 19.661 28.641 113.167 33.748
1992 196.374 19.406 28.331.113.652 34.985 '':'.
1993 199.139 19.459 28.500 114.876 36.303
1994 204.155 19.879 29.282 117.269 37.725
1995 207.471 19.973 29.599 118.806 39.093
1996 209.895 19.919 29.690 119.851 40.435
1997 211.690 19.781 29.639 '.120.513 41.757
1998 215.375 19.969 30.117 122.137 43.152
1999 218.129 19.992 30.346 123.285 44.506
2000 221.663 20.139 30.792 124.848 45.885
L]2001 223.997 20.086 30.918 125.785 47.206
2002 225.523 19.923 30.850 126.266 48.484
2003 227.368 19.835 30.897 126.878 49.758
2004 229.700 19.833 31.097 127.738 51.032
2005 232.357 19.879 31.394 128.784 ,52.299
2006 235.322 19.964 31.776 130.024 53.557
2007 238.186 20.021 32.128 131.246 54.791
2008 241.264 20.102 32.533 132.616 56.014
2009 244.679 20.221 33.019 134.208.57.231
2010 248.645 20.403 33.638 136.149 58.454
Source:MAP Model Output Files HE53.1 and HER53.1.
Variables:HH,HH24 ,HH25.29,HH30.54,and HH55.
TABLE B.5.4.27:COMPOSITE CASE HOUSEHOLDS (Page 1 of 2)
(thousands)
Greater Greater
Year State Railbelt Anchorage Fairbanks
1983 171.664
1984 178.150 131.373 106.128 25.246
1985 181.869 134.300 108.704 25.596
1986 186.818 138.028 110.217 27.811
1987 187.561 137.805 110.150 27.655
1988 188.337 138.473 110.742 27.732
1989 191.489 141.002 112.995 28.007
1990 192.825 142.243 114.246 27.997
1991 194.538 143.298 115.070 28.228
1992 195.626 143.476 115.162 28.314
1993 199.021 145.716 116.871 28.845
1994 203.432 149.716 120.244 29.473
1995 206.446 151.445 121.819 29.626
1996 208.526 151.059 121.599 29.460
1997 210.404 153.061 123.337 29.724
1998 214.106 153.453 123.790 29.663
1999 216.838 157.162 126.975 30.187
2000 220.355 160.294 129.699 30.595
20_01 ..2_22_•.6_9_6 1.63.6_12 1.3_2.•.5..5.2_31.Q6Z
2002 224.215 164.654 133.452 31.202
2003 226.033 166.675 135.188 31.487
2004 228.321 168.862 137.068 31.794
2005 230.879 171.129 139.047 32.083
2006 233.710 173.712 141.287 32.425
2007 236.506 176.284 143.502 32.782
2008 239.624 179.076 145.939 33.138
..·2009·-----..·---243~-096 ....·---T8Z~154--·-----T48-;;613-·--·----·33:S4Z--·---
..---··---·_·-20·10---------24-7-;:029--.....--1·8-5-;:668--··--·+51.64-8--··------:34-;:02·1--
Source:MAP Model Output F les HE53.3 and HER53.3.
Variables:HH,HH IR,HH.AG,and HH.FG.
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TABLE B.5.4.27 (Page 2 of 2)
Head
Younger Head Head Head Older
Year Total Than 25 25-29 30-54 Than 54
1983 171.664 21.132 29.622 96.310 24.600
1984 178.150 21.394 30.205 100.802 25.749
1985 181.869 21.155 30.102 103.790 26.822
1986 186.818 21.222 30.431 107.222 27.943
1987 187.561 20.589 29.668 108.315 28.989
1988 188.337 20.075 29.012 109.170 30.080
1989 191.489 20.056 29.066 111.065 31.302
1990 192.825 19.751 28.689 111.896 32.489
1991 194.538 19.563 28.480 112.774 33.721
1992 195.626 19.307 28.164 113.204 34.952
1993 199.021 19.473 28.509 114.748·36.292
1994 203.432 19.787 29.133 116.826 37.686
1995 206.446 19.839 29.380 118.190 39.037
[1996 208.526 19.741 29.395 119.030 40.360
1997 210.404 19.632 29.385 119.709 41.678
1998 214.106 19.833 29.882 121.325 43.065
I 1999 216.838 19.860 30.119 122.450 44.409
2000 220.355 20.010 30.573 123.996 45.775
IJ 2001 222.696 19.964 30.712 124.934 47.086
2002 224.215 19.804 30.650 125.410 48.351
2003 226.033 19.714 30.698 126.010 49.611
2004 228.321 19.709 30.892 126.850 50.870
2005 230.879 19.744 31.170 127.846 52.119
2006 233.710 19.813 31.523 129.015 53.358
2007 236.506 19.867 31.866 130.199 54.575
2008 239.624 19.960 32.290 131.590 55.784
2009 243.096 20.092 32.799 133.217 56.988
2010 247.029 20.272 33.414 135.148 58.195
Source:MAP Model Output Files HE53.3 and HER53.3.
Variables:HH,HH24,HH25.29, HH30.54,and HH55.
TABLE B.5.4.28:SHCA CASE FORECAST
NUMBER OF HOUSEHOLDS SERVED
Year Single Family Mul tifamily Mobile Homes Duplexes Total
Anchorage-Cook Inlet Area
1980 35,473 20,314 8,230 7,486 71,503
1985 57,487 26,204 13,233 8,567 105,492
1990 61,250 27,558 14,017 8,460 111,284
1995 65,723 36,308 15,119 8,333 119,483
2000 69,849 33,196 16,193 8,019 127,256
2005 74,870 35,738 17,493,8,607 136,708
2010 81,469 39,268 19,227 9,403 149,367
Fairbanks-Tanana Valley Area
1980 7,220 5,287 1,189 1,617 15,313
1985 ....10 ,646 6,348 .2,130 ),881 ~1,004
1990 11,521 7,960 2,209 2,375 26,064
1995 13,619 7,841 3,001 2,339 26,800
2000 14,470 7,703 3,302 2,298 27,773
2005 15,791 7,549 3,695 2,252 29,287
2010 16,962 8,049 4,019 2,202 31,231
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TABLE B.5.4.29:COMPOSITE CASE FORECAST
NUMBER OF HOUSEHOLDS SERVED
Year .Single Family Mul tifamily Mobil e Homes Duplexes Total
Anchorage-Cook Inlet Area
1980 35,473 20,314 8,230 7,486 71,503
1985 57,487 26,204 13,233 8,567 105,492
1990 61,123 27,468 13,984 8,460 111,035
1995 65,254 30,012 15,007 8,333 118,606
2000 69,431 32,990 16,095 7,970 126,486
2005 74,397 35,505 17,381 8,552 135,835
2010 80,963 39,022 19,107 9,345 148,437
Fairbanks-Tanana Valley Area
1980 7,220 5,287 1,189 1,617 15,313
1985 10,646 6,348 2,130 1,881 21,004
1990 11,458 7,960 2,193 2,375 23,986
1995 13,700 7,841 2,742 2,339 26,621
2000 14,413 7,703 3,172 2,298 27,587
2005 15,630 7,549 3,640 2,252 29,071
2010 16,841 7,975 3,991 2,202 31,008
TABLE B.5.4.30:SHCA CASE FORECAST
NUMBER OF VACANT HOUSEHOLDS
Year Single Family Multifamily Mobile Homes Duplexes Total
Anchorage-Cook Inlet Area
1980 5,089 7,666 1,991 1,463 16,209
1985 632 1,496 146 292 2,566
1990 674 1,488 154 289 2,605
1995 723 1,637 166 284 2,810
2000 768 1,793 178 448 3,187
2005 824 1,930 192 284 3,230
2010 896 2,121 212 310 3,539
Fairbanks-Tanana Valley Area
1980 3,653 3,320 986 895 8,854
1985 118 2,173 24 606 2,921
1990 127 454 24 81 686
1995 150 448 33 80 710
2000 159 440 36 78 714
2005 174 431 41 77 722
2010 187 435 44 75 740
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TABLE B.5.4.31:COMPOSITE CASE FORECAST
NUMBER OF VACANT HOUSEHOLDS
Year Single Family Mul tifami ly Mobile Homes Duplexes Total
Anchorage-Cook Inlet Area
)
I 1980 5,089 .7,666 1,991 1,463 16,209II19856321,496 146 292 2,566
1990 672 1,483 154 289 2,598
1995 718 1,621 165 284 2,788
2000 764 1,782 177 497 3,219
2005 818 1,917 191 282 3,209
2010 891 2,107 210 .308 3,516
Fairbanks-Tanana Valley Area
1980 3,653 3,320 986 895 8,854
1985 118 2,173 24 606 2,921
1990 126 454 24 81 686
1995 151 448 30 80 708
2000 159 440 35 78 712
2005 172 431 40 77 720
2010 185 431 44 75 735
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TABLE B.5.4.32:SHCA CASE FORECAST
RESIDENTIAL ELECTRICITY USE PER HOUSEHOLD
(kWh)
Before Conservation Adjustment and Fuel Substitution
Small Appliances Large Appliances Space Heat Total
Fairbanks-Tanana Valley Area
Anchorage-Cook Inlet Area
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11,689
10,7~4
10,551
10,083
10,021
10,298
After
Adjustment
Total
12,410
12,385
13,995
13,857
1.1:.,051
14,465
11,519
12,118
12,667
13,143
13,657
H,lQli:
14,466
13,699
12,923
12,912
13,033
13,291
13,593
13,908
3,314
3,372
3,471
3,514
3,626
3,~!1
3,791
5,089
4,636
4,569
4,505
4,443
4,407
4,431
5,740
6,180
6,529
6,863
7,165
7,427
1~608
6,501
6,098
6,073
6,178
6,418
6,676
6,887
2,466
2,566
2,666
2,766
2,866
2,966
3~(r66-'
2,110
2,190
2,270
2,350
2,430
2,510
2,590
1980
1985
1990
1995
2000
2005
2010
Year
1980
.1985
1990
1995
2000
2005
:foTd
TABLE B.5.4.33:COMPOSITE CASE FORECAST
RESIDENTIAL ELECTRICITY USE PER HOUSEHOLD
(kWh)
Year
Before Conservation Adjustment and Fuel Substitution
Small Appliances Large Appliances Space Heat Total
After
Adjustment
Total
Anchorage-Cook Inlet Area
1980
1985
1990
1995
2000
2005
2010
2,110
2,190
2,270
2,350
2,430
2,510
2,590
6,501
6,098
6,073
6,176
6,419
6,675
6,886
5,089
4,636
4,569
4,504
4,444
4,407
4,431
13,699
12,923
12,911
13,030
13,293
13,592
13,907
11,689
10,790
10,710
10,390
10,079
10,220
Fairbanks-Tanana Valley Area
1980
1985
1990
1995
2000
2005
2010
2,466
2,566
2,666
2,766
2,866
2,966
3,066
5,740
6,180
6,528
6.,860
7,165
7,426
7,609
3,314
3,372
3,471
3,552
3,640
3,714
3,791
11,519
12,118
12,665
13,178
13,671
14,105
14,466
12,410
13,405
14,207
14,279
14,148
14,439
TABLE B.5.4.34:SHCA CASE FORECAST
BUSINESS ELECTRICITY USE PER"EMPLOYEE
(kWh)
8,672 8,086 8,672 8,086
10,123 8,73~9,153 9,278
10,988 9,377 9,104 10,561
11,968 10,022 9,288 11,322
12,945 10,667 9,077 11 ,204
13,975 11,313 9,310 11,427
15,157 11,958 9,997 12,003
Year
1980
1985
1990
1995
2000
2005
2010
Before Conservation Adjustment
and Fuel Substitution
Anchorage-Cook Fairbanks-Tanana
Inlet Area Valley Area
After Adjustments
Anchorage-Cook Fairbanks-Tanana
Inlet Area Valley Area
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TABLE B.5.4.35:C()MPOSIr~CASE FORECAST
BUSINESS ELECTRICITY USE PER EMPLOYEE
(kWh)
Year
Before Conservation Adjustment
and Fuel Substitution
Anchorage-Cook Fairbanks-Tanana
Inlet Area Valley Area
After Adjustments
Anchorage-Cook Fairbanks-Tanana
Inlet Area Valley Area
1980
1985
1990
1995
2000
2005
2010
8,672 8,086 8,672 8,086
10,123 8,731 9,153 9,278
10,973 9,377 9,089 10,557
11,940 10,022 9,450 11,473
12,927 10,667 8,833 11 ,632
13,954 11 ,313 9,417 11,587
15,138 11,958 9,996 11,989
TABLE B.5.4.36:SHCA CASE FORECAST
SUMMARY OF PRICE EFFECTS
(GWh)
Anchorage-Cook Inlet Area Fairbanks-Tanana Valley Area
Residehtial Sector I IBusiness Sector I Residential Sector Business SectorI,
Own-Price Cross-Price 9wri-Price Cross-Price Own-Price Cross-Price Own-Price Cross-Price
Year Reduction Reduction Reduction Reduction,Reduction Reduction Reduction Reduction
I
i
·1985 137.6 -7.4 138.4 2.5 9.2 -3.0 22.4 -2.4
1990 257.1 -21.4 :282.0 0.0 23.7 -5.8 51.0 -4.4
1995 376.2 -79.7 i 449.2 -20.8 26.3 -3.5 56.5 -2.7
2000 556.9 -148.6 i 707.0 -56.4 1.6 4.0 20.6 2.2
2005 708.4 -220.2 933.9 -101.9 21.5 -20.0 -3.5 8.8
2010 854.0 -314.8 11176.9 -166.6 0.6 -0.6 -12.0 14.1
'-----L'---.~
TABLE B.5.4.37:COMPOSITE CASE FORECAST
SUMMARY OF PRICE EFFECTS
(GWh)
Year
Anchorage-Cook Inlet Area
Resiaentia 1 Sector -BusIness Sector
Own-Price Cross-Price Own-Price Cross-Price
Reduction Reduction Reduction Reduction
Fairbanks-Tanana
Resicren:tIal Sector
Own-Price Cross-Price
Reduction Reduction
Valley Area
Business Sector
Own-Price Cross-Price
Reduction Reduction
19851 137.6 -7.4 138.4 2.5 9.2 -3.0 22.4 -2.4
19901 256.4 -20.9 279.9 0.5 23.6 -5.9 50.6 -4.4
19951 351.6 -76.5 412.9 -19.1 30.8 -3.4 62.2 -2.7
20001 505.2 -138.0 634.6 -50.0 13.7 3.1 39.1 1.5
20051 671.5 -194.4 889.6 -85.8 -7.6 8.8 5.5 6.6
20101 811.0 -263.5 1,135.6 -135.0 0.4 0.4 -9.3 10.8
TA BLE B.5 .4.38 :SHCA CASE FORECAST
BREAKDOWN OF ELECTRICITY REQUIREMENTS
ANCHORAGE-COOK INLET AREA
(GWh)
Residential Business Mi see 11aneou s Indust./Military Total
Year Requirements Requirements Requirements Requirements Requirements
1985 1,233 1,329 28 124 2,715
1990 1,201 1,363 28 192 2,784
1995 1,261 1,484 30 208 2,983
2000 1,283 1,527 31 238 3,079
2005 1,370 1,660 33 273 3,336
2010 1,538 1,957 38 315 3,848 :I
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TABLE B.5.4.39:SHCA CASE FORECAST
BREAKDOWN OF ELECTRICITY REQUIREMENTS
FAIRBANKS-TANANA VALLEY AREA
(GWh)
Residential Business Miscellaneous Indust./Military Total
Year Requirements Requirements Requirements Requirements Requirements
I 1985 261 340 7 0 608,J
1990 323 416 8 50 797
1995 375 468 9 50 902
2000 385 475 9 50 919
2005 412 506 10 50 978
2010 452 569 11 50 1,081
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TABLE B.5.4.40:COMPOSITE CASE FORECAST
BREAKDOWN OF ELECTRICITY REQUIREMENTS
ANCHORAGE-COOK INLET AREA
(GWh)
Year
Residential
Requirements
Business
Requirements
Miscellaneous
Requirements
Indust./Mi1itary Total
Requirements Requirements
t
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)
1985 °1 ,233 1,329 28 124 2,715
1990 1,198 1,353 28 192 2,770
1995 1,270 1,494 30 208 3,003
2000 1,314 1,577 31 238 3,160
2005 1,369 1,668 33 273 3,344
2010 1,517 1,946 38 315 3,815
I
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TABLE B.5.4.41:COMPOSITE CASE FORECAST
BREAKDOWN OF ELECTRICITY REQUIREMENTS
FAIRBANKS-TANANA VALLEY AREA
(GWh)
Residential Business Mi see llaneou s Indust./Military Total
Year Requirements Requ irement s Requirements Requirements Requirements
1985 261 340 7 0 608
1990 322 413 8 50 793
1995 378 470 9 50 907
2000 394 490 10 50 943
2005 411 510 10 50 981
2010 448 565 11 50 1,073
TABLE B.5.4.42:SHCA CASE END USE FORECAST
PROJECTED PEAK AND ENERGY DEMAND
Anchorage-Cook Fairbanks-Tanana
Inlet Area Valley Area Total System Area
Energy Peak Energy Peak Energy Peak at 60%Load
Year (GWh)(MW)(GWh)(MW)(GWh)Factor (MW)
1985 2,715 517 608 116 3,322 632
1990 2,784 530 797 152 3,580 681
1995 2,983 568 902 172 3,885 739
2000 3,079 586 919 175 3,998 761
2005 3,336 635 978 186 4,314 821
2010 3,848 732 1,081 206 4,930 938
1
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\)
TABLE B.5.4.43:COMPOSITE CASE END USE FORECAST
PROJECTED PEAK AND ENERGY DEMAND
Anchorage-Cook Fairbanks-Tanana
Inlet Area Valley Area Total System Area
Energy Peak Energy Peak Energy Peak at 60%Load
Year (GWh)(MW)(GWh)(MW)(GWh)Factor (MW)
1985 2,715 517 608 116 3,322 632
1990 2,770 527 793 151 3,563 678
1995 3,003 571 907 173 3,910 744
2000 3,160 601 943 179 4,104 781
2005 3,344 636 981 187 4,325 823
2010 3,815 726 1,073 204 4,889 930
TABLE B.5.4 .44:~ARTON CASE FDRE'CAST SUMMARY OF INPUT AND OUTPUT DATA
Item Description
World Oil Price (1985$/qbl~
Energy Price Used by RED,(i1980$)
Heating Fuel Oil-Anchdrage
($/MMBtu)!i
Natural Gas -Anchorage
($/MMBtu)r
State Petroleum Revenues~/
(Million Nominal $)
Production Taxes
Royalty Fees
State General Fund Expe~ditures
(Mill ion Nominal $)i'
State Population
State Employment
Railbe1t Population
Railbelt Employment
Rail bel t Total Number ofl
Households !
RailbeltElectricity Co~sumption
(GWh)!
Anchor,age
Fairbanks
Total
I
Rail bel t Peak Demand (MWI)
I
I
1985
27.10
6.45
2.10
1,372
1,372
3,665
536,525
269,087
381,264
181,885
134,300
2,714
608
3,322
632
1990
24.80
5.90
2.35
1,113
1,556
3,806
559,621
278,012
394,631
185,257
140,751
2,721
786
3,507
667
1995
27.60
6.58
3.65
1,033
1,622
4,701
583,589
293,298
410,458
192,530
148,302
2,946
893
3,838
730
2000
31.30
7.45
4.05
720
1,423
4,944
618,952
313,683
431,301
206,302
157,679
3,260
971
4,231
805
2005
35.10
8.35
4.46
601
1,253
5,335
645,298
320,030
460,071
218,848
168,895
3,576
1,047
4,623
880
2010
40.70
9.68
5.08
751
1,364
6,379
688,969
'344,017
499,187
240,312
183,964
3,964
1,117
5,081
967
i/Petroleum revenue s alIso include corporaite income taxes,oil and gas property taxes,
lease bonuses,rentsl,~nd federal share:d royal ties.
I
,--_..~_._-<:
TABLE B.5.4.45:RESULTS OF RED MODEL SENSITIVITY
TEST ON APPLIANCE SATURATIONS
Total Electricity Requirements Without Large Industrial
1990 2000 2010
(GWh)(GWh)(GWh)
Anchorage-Cook Inlet Area
Maxim tnnl/
25%GE
Mean
50%GE
75%GE
Minimtnn
Std Dev
Test Case
Fairbanks-Tanana Valley Area
Maximtnnl/
25%GE
Mean
50%GE
75%GE
Minimtnn
Std Dev
Test Case
2,681
2,673
2,670
2,669
2,667
2,663
4.82
2,673
721
720
719
719
718
717
1.0
719
3,186
3,179
3,173
3,173
3,167
3,164
6.8
3,174
897
896
894
896
894
892
1.4
895
3,918
3,910
3,904
3,905
3,900
3,890
7.4
3,901
1,117
1,116
1,114
1,114
1,113
1,.1 10
2.0
1,113
1/Maximtnn =maximtnn simulation value.
25%GE =25 percent of simulation values were greater than or equal
to table value.
Mean =mean value of all simulations.
50%GE =50 percent of simulation values were greater than or equal
to table val ue.
75%GE =75 percent of simulation values were equal to or greater
than table value.
Minimtnn =minimtnn simulation value.
TABLE B.5.4.46:RESULTS OF RED MODEL SENSITIVITY TEST ON
BUSINESS SECTOR CONSUMPTION INTENSITYll
Total Electricity Requirements Without Large Industrial
1990 2000 2010
(GWh )(GWh )(GWh )
.\
]
775 965 1,203
729 907 1,129
712 886 1,102
712 8.87 1,103
696 867 1,078
§"§l 823 ...._1,02!L-"------._._.
32.0 40.0 51.4
719 895 1,113
3,180 3,804 4,717
2,826 3,364 4,147
2,653 3,149 3,870
2,545 3,016 3,697
2,119 2,488 3,019
2,663 3,164 3,890
276.32 342.7 442.2
2,673 ;-,3,174 3,901TestCase
Anchorage-Cook Inlet Area
Maximuml.l
25%GE
Mean
50%GE
75%GE
Minimum
Std Dev
Test Case
Fairbanks-Tanana Valley Area
Maximumll
25%GE
Mean
50%GE
75%GE
"Minimum
Std Dev
II Coefficient of demand per square foot.
......2"./··MaxinftIlll=·tnaximumsitnuL!rtion·va·luEf;·_··········-
...--·-25-%-@E-=--25--per-cen·t-of--simul·a·tion-va-l-ues-were-·grea·ter-than-or-eq·ua-l-·.
to table val ue.
Mean =mean value of all simulations.
50%GE =50 percent of simulation values were greater than or equal
to table value.
75%GE =75 percent of simulation values were equal to or greater
than table value.
Minimum =minimum simulation value.
1
i
1
J
.J
J
TABLE B.5.4.47:RESULTS OF RED MODEL SENSITIVITY
TEST ON OWN PRICE ELASTICITIES
Total Electricity Requirements Without Large Industrial
1990 2000 2010
(GWh)(GWh)(GWh)
Anchorage-Cook Inlet Area
Max im t.m11/2,720 3,283 4,093
25%GE 2,641 3,138 3,843
Mean 2,621 3,077 3,745
50%GE 2,635 3,072 3,726
75%GE 2,591 3,021 3,659
Minimt.m1 2,528 2,903 3,453
Std Dev 50.82 96.2 160.6
Test Case 2,673 3,174 3,901
Fairbanks-Tanana Valley Area
Max im t.m11/736 911 1,137
25%GE 729 905 1,128
Mean 724 900 1,117
50%GE 724 902 1,119
75%GE 720 894 1,108
Minimt.m1 713 887 1,091
i Std Dev 6.0 7.1 13.3L
Test Case 719 895 1,113
1/Maximt.m1 =maximt.m1 simulation value.
25%GE =25 percent of simulation values were greater than or equal
to table value.
Mean =mean value of all simulations.
50%GE =50 percent of simulation values were greater than or equal
to table val ue.
75%GE =75 percent of simulation values were equal to or greater
than table value.
Minimt.m1 =minimt.m1 simu1a tion value.
TABLE B.5.4.48:RESULTS OF RED MODEL SENSITIVITY TEST ON CROSS
PRICE ELASTICITIES TOTAL ELECTRICITY REQUIREMENTS
WITHOUT LARGE INDUSTRIAL (Page 1 of 2)
2,690 3,183 3,965
2,676 3,178 3,931
2,672 3,175 3,907
2,672 3,175 3,911
2,666 3,172 3,893
2,656 3,165 3,838
9.5 5.1 36.0
2,673 3,174 3,901
B.Gas Cross-Price Elasticities
_..----Z,-699--~--------3~-279----------~--~_;TOT
2,684 3,219 3,981
2,675 3,180 3,911
2,676 3,184 3,914
2,670 3,162 3,870
2,638 3,024 3,649
15.8 64.7 120.6
723 898 1,132
720 896 1,122
718 895 1,115
719 896 1,116
711 895 -l",cU-L~-
714 892 1,095
2.5 1.5 10 .4
719 895 1,113
A.0.1 Cross-Price Elasticities
Anchorage-Cook Inlet Area
Maximuml/
25%GE
Mean
50%GE
75%GE
Minimum
Std Dev
Test Case
Fairbanks-Tanana Valley Area
Maximum1 /
25%GE
Mean
50%GE
'Z5_%__GE~-
Minimum
Std Dev
Test Case
Anchorage-Cook Inlet Area
------------Maximuml:l ------
25%GE
Mean
50%GE
75%GE
Minimum
Std Dev
Test Case
1990
(GWh)
2,673
2000
(GWh)
3,174
2010
(GWh)
3,901
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TABLE B.5.4.48 (Page 2 of 2)
1990 2000 2010
(GWh)(GWh)(GWh)
Fairbanks-Tanana Valley Area
Maximuml/726 896 1,134
25%GE 720 896 1,122
Mean 719 895 1.,114
50%GE 719 895 1,115
75%GE 717 895 1,110
Minimum 713 891 1,086
Std Dev 3.4 1.6 12.7
Test Case 719 895 1,113
TABLE B.5.4.49:RESULTS OF RED MODEL SENSITIVITY TEST ON ANNUAL LOAD FACTOR
TOTAL ELECTRICITY REQUIREMENTS WITHOUT LARGE INDUSTRIAL
1990
(MW)
2000
(MW)
2010
(MW)
Anchorage-Cook Inlet Area
Maximuml l
25%GE
Mean
50%GE
75%GE
Minimum
Std Dev
Test Case
Fairbanks-Tanana Valley Area
Maximumll
25%GE
Mean
50%GE
75%GE
Minimum
Std Dev
Test Case
620 733 890
604 695 843
560 646 790
556 648 795
531 604 754
489 573 708
40.4 50.2 49.5
548 650 799
196 241 297
184 223 279
171 207 254
177 210 253
156 195 234
146 174 217
16.1 19.1 24.5
149 186 231
}
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II Maximum =maximum simulation value.
25%GE =25 percent of simulation values were greater than or equal
to table value.
Mean =mean value of all simulations.
50%GE =50 percent of simulation values~t=J:c:gJ:_E!Cl.t§J:'~I:1Ci_t1_()["c:gIJCl.Lto-tabTevaTue:----
-----------.-.------.----~-~.-.----------~------------7-5"%~GE~=--75 per~cent "-o-f----s~imu-rat "foii .val-u es-were---equ a Y---EQ_···or-----grea t ei----------··--"-_.
than table value.
Minimum =minimum simulation value.I
j
1
1
Ii
TABLE B.5.4.50:LIST OF PREVIOUS RAIL BELT PEAK AND ENERGY DEMAND FORECASTS
(MEDIUM SCENARIO)
ISER Battelle Reference Case Utility
1980 Forecastl/1981 Forecas d./Forecastl/1985 Forecast!!./
Peak Energy Peak Energy Peak Energy Peak Energy
Demand Demand Demand Demand Demand Demand Demand Demand
Year (MW)(GWh)(MW)(GWh)(MW)(GWh)(MW)(GWh)
1985 685 3,610
1990 735 4,030 892 4,456 777 3,737 869 4,584
1995 934 5,170 983 4,922 868 4,171 971 5,135
2000 1,175 6,430 1,084 5,469 945 4,542 1,085 5,7252./
2005 1,380 7,530 1,270 6,428 1,059 5,093 NA NA
2010 1,635 8,940 1,537 7,791 1,217 5,858 NA NA
1/Acres American 1982,Volume 1,Table 5.6.Includes 30 percent of military
loads,and excludes industrial self-supplied electricity.
2J Acres American 1982,Volume 1,Table 5.7.Excludes military and industrial
self-supplied electricity.
3J APA 1983,Table B.117.Excludes 30 percent of military loads,and excludes
industrial self-supplied electricity.
±/APA 1985,Table 1.
i/Energy and peak demand in the year 2000 were computed by
extrapolation,based on the annual growth rate in the last
year of each utility's forecast period.
Note:The ISER,Battelle,and Reference Case forecasts are for end-use demand,
and should be increased for transmission and distribution losses.Net
generation =sales/(l-l).
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LEGEND
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20
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I
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TYONEI ttl DAMSITE
.'
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SCALE IN MILES
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COMPUTER MODELS
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LEAST COST DAM
COMBINATIONS
DATA ON DIFFERENT
THERMAL GENERATING
SOURCES ,
---II COMPUTER MODELS I
TO EVALUATE
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ENERGY YIELDS
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ECONOMICS
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LAYOUT AND I ,
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SCREEN
PREWOUS
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RECO
ADDITIONAL SITES
PORTAGE CREEK
DIS'HIGH DEVIL CANYON
DIS WATANA
GOLD CREEK
DEVI L CANYON
HIGH DEVIL CAN'rON
DEVIL CREEK
WATANA
SUSITNA m
VEE
MACLAREN
DENALI
BUTTE CREEK
TYONE
CRITERIA DEVIL CANYON OBJECTIVE WATANA I DEVIL
ECONOMICS HIGH DEVIL ECONOMIC CANYON
ENVIRONMENTAL CANYO~HIGH DEVIL
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SITES SUSITNA]I[HIGH DEVIL
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CONTRIBUTION MACLAREN
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ECONOMIC
ENVIRONMENTAL
SOCIAL
ENERGY
CONTRIBUTION
WATANA I DEVIL'
CANYON
PLUS THERMAL
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FIGURE 8.1.2.1
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SUSITNA m '1I111111'(f?I~III~t~il
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•DAM IN COLUMN IS MUTUALLY EXCLUSIVE IF FULLrl11'''''''''"'II SUPPLY LEVEL OF DAM IN ROW EXCEEDS THIS VALUE-FT.·\;··j;~;~l:~:;'I~;~·::\··j:\·VALUE IN BRACKET REFERS TO APPROXIMATE DAM HEIGHT.
MACLAREN 111111
DENALI Ili1'llIilltilt1~I(t
BUTIE CREEK f~~lfif1~~~;~~~
TYONE
MUTUALLY EXCLUSIVE DEVELOPMENT ALTERNATIVES
FIGURE B.I.3.2
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!lon
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D 100 lIDO PUT
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----
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t?f'L!fftC.r-.a&ft I \'~.......-:;.7 £/J \~..._•............'-,_,
-------,.....----~tl=l·•.,~rt:'CRm 111..1118
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•.IWl.ILIMO ~~n',I,~~'"C ....IIl ••U.Ii .aoo ~IOOO],us ~(Jj:J fu.-cr _"/
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.,.1--~-..r-..)..,..-L---'---,
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I T 1
llT.nOHItJl IN 'EET
sJLWAJ PROFILE
!.C~"WATANA
2000lOIXl
"---to,
111111(
1IlOO
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lCALI:.
IlOO IDOO
ITATIOIOlIll 1M FUT
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nool :;;;;;/....,:PlLRR L}I ~tIYIUWI \~fll I€8 ..........._ r .._a_'.\...........(
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HIGH DEVIL CANYON HYDRO DEV~LOPMENT FIGURE 8.1.3.6
FIGURE B.1.3.7
lIOn:
~:~,:::;I~W=~CT L.MOU1'
~POI co ......1aotf OP
ALTI....n".&1'1 OCYILOf'II!PTa "LY
SECllON THRU DAM
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SPILLWAY PROFILE
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1400[===-----:::::t:::----;nw:~~~===_--------~;;.;;;;;;;-;;;;::;;;;-===----------II~U'ITIIIO _IIlIlfilQl
1;;1100 .~--1'---
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SUSITNA m HYDRO'DEVELOPMENT
-----_...--....
LO'
'-.I
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VEE HYDRO DEVELOPMENT FIGURE 8.1.3.8
.pi>
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-------""
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I.
TUNNEL
SCHEME
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DEVIL CANYON
550 MW
DAM
2 TUNNELS
800.MW
-....-2 MILES
__--1475 FT.
2200 FT.WATANA
38 FT.DIAMETER
800 MW_70MW
2 TUNNELS 1150 MW
2.
38 FT.DIAMETER
1475 FT.
800 MW -850 MW
15.8 MILES-I
--RE -REGULATION DAM
30 MW
'----=.-..:..:==~_...;:::o".300 MW
3.
30 FT.DIAMETER
800 MW
2 TUNNELS 365 MW
4.
24 FT.DIAMETER
SCHEMATIC REPRESENTATION
OF CONCEPTUAL TUNNEL SCHEMES
FIGURE 8.1.4.1
~
---_...._-....-~
~-~,~-!~,\------------1
'SCHEME 3 PLAN
ICAU:a ,f III.U
Q'
NOTI:
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-----'",---","---<~-.~'--'~':.-.,-)...,---..-~.'--.J.-.---,,./'.-
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SECTiON A TYPICAL TlHlNEl SECTIONS
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DETAIL .,
PREFERRED TUNNEL SCHEME :3 SECTIONS FIGURE 8,1.4.3
3
3:
:E 2
ooo
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()
~I
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'}
",'1
1
J
1
l
01.---1..------------------------------:--......
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I.t
I
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~
J
j
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2010
DEVI L CANYON
(400 MW)
WATANA-L(400 MIN)
2000
EXISTING a COMMITTED
1990
D 'HYDROELECTRIC
ItWW1d COAL FIRED THERMAL
~GAS FIRED THERMAL
.--Oll-FIRED-'l'HERMA\;'(NO"r,SHOWN-ON-ENERGY DIAGRAM}
NOTE:RESULTS OBTAINED FROM
OGP5 RUN L8J9 '
1980
10
2
8
::I:
3:6(!)
ooo
TIME
GENERATION SCENARIO WITH SUSITNA ,PLAN E 1.3
-MEDIUM LOAD FORECAST-
FIGURE B.1.5.1
l
1
\
i
3
3:
::1E 2
ooo
>-r-
u
~I
<t
U 715
1980
1972
PEAK
LOAD
1990
2230
2211 ...
10 LEGEND:
VEE(400 MW)
HIGH DEVIL CA.~YON-2 (400 MW)
HIGH DEVIL CANYON -1(400MW)
EXISTING AND COMMITTED
NOTE:RESULTS OBTAINED FROM
OGP5 RUN LSOI
o HYDROELECTRIC
fttt~~1 COAL FIRED THERMAL
EZl GAS FIRED THERMAL
18 OIL FIRED THERMAL(NOT SHOWN ON ENERGY DIAGRAM)
TOTAL DISPATCHED
ENERGY~
2
8
:I:
3:S(,!)
oo
Q
O'--...;.a..------------------.J
1980 1990 2000 2010
GENERATION SCENARIO WITH SUSITNA PLAN E 2.3
-MEDIUM LOAD FORECAST-
FIGURE B.1.5.2
3
I
J
I
)
oJ
J
t
'.I
J
2010
WATANA-2 (400MW)
TUNNEL(380MW)·-~
WATANA.-I(400 Mw)
2000
EXISTING a COMMITTED
TIME
1990
o HYDROELECTRIC
It~tt~~~1 COAL FIRED THERMAL
(:Z]GAS FIRED THERMAL
•6iLFiRED THERMAL.(N()T SHOWN ON ENERGY DIAGRAM)
NOTE :RESULTS OBTAINED FROM
OGP5 RUN L607 .
PEAK
LOAD
LEGEND'
GENERATION.SCENARIO WITH SUSITNA PLAN E3.1
-MEDIUM LOAD FORECAST-.
FIGURE 8.1.5.3
1980
715
3=
:E 2ooo
o J.!I~03~;;~~4;.....~tl=:=I.~4Wb=dL .:2:0°::Jk!.;~~]~~"""'1~1~]~~~tm.1~1~~1~1
1980 1990 2000 2010
0 ......--1....:.....------------------------.....1
>-I-
(;)
~I
<[
(;)
10
8
:r:
3=6(!)
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--0::-----~--TOTAC-DISPATCHED--·~4 ENERGY~
7300
I
7200
I
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x
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en 7000I-en
0
(,)
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0
i=
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0
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0
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z
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6600 1------l------l------l------.1f------+------l
226022402220220021802160
6500 '-J.-J.-J.-l-.---L --I
2140
DAM CREST ELEVATION (FT)
WATANA R~~F:RVOIR
DAM CREST ELEVATiON/PRESENT WORTH OF PRODUCTION COSTS
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-
FIGURE B2.2~
45.40
LESS THAN 3
ENTRANCE
SUBMERGED
···30 35
TUNNEL DIAM€TERJFTo'
25
1450 '--L-__......_.L-_~__..L-....--,_......___'
WATANA DIVERSION
HEADWATER ELEVATIONITUNNELDIA"METER
o
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.................•..-1····..···TY.PICAL·..··
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-----------_._~-----_.._.-----
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If
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CAPITAL·COST S
WATANA DIVERSION
UPSTREAM COFFERDAM COSTS FIGUREB.2.2.5
80
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TUNNEL
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TUNNEL DIAMETER (FT.)
WATANA DIVERSION
...
TUNNEL COSTI TUNNEL DIAMETER FIGUREB.2.2.6
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TUNNEL
SECTION
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15 20 25 30 35
TUNNEL DIAMETER (FT.)
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WATANA DIVERSION
TOTAL COST/TUNNEL DIAMETER FIGURE 6.2.2.7
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3.THE LETTER BEFORE EACH STATION NAME IN
THE TABLE IS USED ON THE MAP TO MARK THE
APPROXIMATE LOCATION OF THE STATIONS.
(A)SUSITNA RIVER NEAR DENALI
(B)SUSITNA RIVER NEAR CANTWELL
(VEE CANYON)
(C)SUSITNA RIVER NEAR WATANA DAMSITE
(D)SUSITNA RIVER NEAR DEVIL CANYON
(E)SUSlnlA RIVER AT GOLD CREEK
(F)SUSmiA RIVER NEAR SUNSHINE
(G)SUSITNA RIVER AT SUSITNA STATION
(H)MACLAREN RIVER NEAR PAXSON
(I)CHULITNA RIVER NEAR TALKEETNA
(J)TALKEETNA RIVER NEAR TALKEETNA
(K)SKWENTNA RIVER NEAR SKWENTNA
(L)YENTNA RIVER NEAR SUSITNA STATION
--.........
""\.
\
\
I
H /
J
/
/6'
/
/
I
STATION
o'
---/._-
/
./
./
/'
\
\
\
\
'Jl \
\
\
)\\
Q.\
\
\o J
",.,.---------~/'"."'"/
/
/
/",/-,,/.........__//
O~~~:i:il0ii;;;;;;iiiiiiiiiiiiiiiii~"?MILESSCALEI::,
~£KLUTNA
LAKE
/'"
/
/
/
/
I
/
/
/
/
SUSITNA RIVER ./
DRAINAGE BASIN\"././
,./
,./~,.....
,./
---,..-~..-
/'"
,/
,/
/'
/
I
/
I
/
/
I
/
/
/
/
I
I
/
STREAMFLOW GAGING AND WATER QUALITY MONITORING STATIONS
FIGURE S:3.1.1
------~.--,
)
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j
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]
:j
i
1
]
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:I
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SUSITNA RIVER
DEVIL WATANA
CANYON SITE SITE
~}
,20%.GOLD CREEK
..)
TRIBUTARIES
10%
SUSITNA GAGING STATION
COOK INLET
FLOW DISTRI BUTION
SUSITNA RIVER BASIN
AVERAGE ANNUAL
WITHIN THE
FIGURE 8.3.1.2
:1
1
II
J
J
l
1:-1
'\
'I
i
''1
I
\'j
~_.._--_._~._.__._-
1
I'j
,j
I
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i )
•
88 r-:-.r-1-Ir--IITI---rI-""'I--n11i;""r---r"1-""'-I-'TT11-r-I-r-I-rr-1r""'Ir---r,--rqr--'"T'"I--r1-"'-I"'--I-r--,-r--I-,,-r---rII--r,--r''''''I'''--'-'-""\''""1-""""'II-r--,-r--I"""I""""""1"'I""",--rI-'"'T"I-r--r-11 -""\""",-OY--I"""
--LEGEND:-
80 t---
CANTWELL FLOW
WATANA FLOW
GOLD CREEK FLOW
I--
72+------------------------------+-1------------------------------------------f
-
-
-
-
-
· .·.'·.'
I-~!\641------------------------------j--i4-.J----------------------------------------1f\, I
, I,\
561-----------------------------+-:+--1+--·-------------------------------------~~NI
~I-I ~
-=I '.'w'48 t---------------,...----------------h---;.--It1it--f't--------------------..,-----------------1~e-L';\11\I
u .'.V1
CI)1:\'::'I ~/I
C>40 I------------------------------f/'-..--"::-:-u/~1_\l_---------------------;.-----------------1....V I
::!.",.:,I
c5 __C :'II
-
-
-
I,
AUGUST
I I II
JULY
I I II
JUNE
,
MAY
MONTH
,
APRIL
,
MARCH
I
FEBRUARY
I
I
JANUARY
I-
o
32 t----'------------..:.------------..:.---t1r--·-\:7;-:-'!...-\\-I\-f\l-lfi-t----,~-------------.,'--------..:.-------____I
I \l\\~I~\~
1 ~:\~,jl!\A
24 t----------------------------++--:---~---=;4\__h.q,+-------------~----------------..-..1
,1 \\'\-JFr\A:\,~Ql:'\f.:\
:.',,:,\~
•••••:".":"...."'\A161------------------'------------I~--------'---_';_~~~8_,ftt__f~._a_----------------------------1\\y;...."''\VV ~"V·'"...,,..~:\\/'tJ ......V,.. .\~:'.••••.J\'I
~~\p
•••••••".'"'.....A if"\.
8 I------------;----------------I-+-----------------~..~:."':-\-_-..".,p.~\.\:I.Ooe~__~,-J-j..J\c-h---------------I
',..'v'"""\
'..'--/"......."..",.'-'"--...........\-'......'.J",-
'-::-~-----__--~..~.....
I I I I I II I'I '1",',.···I·"':·.-~r .,.I
NOTE:
TIME SCALE'S IN INCREMENTS OF 10 DAYS.DAILY DISCHARGE HYDROGRAPHS
1964 NATURAL FLOWS
CANTWELL,WATANA AND GOLD CREEK FIGURE 8.3.1.3
I
._---~--
J
J
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]
1
J
I
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1
1
1
-j
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1
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1
88 ..-----r-I-..,...I-....,11r----r--I-..,...-,-..,...I·~:-..,...-,--r--I-"1TIII-r--I-r--j-T'lI"li'-Ir---.....,'r-----r'-rr---r'---r'·--r'"T'---r-r-"T'--r'"T'--rI-I'-lt"--rI-II--r,"-T';-11--r,-r-rJr-T.-.,..,-'Ir--T"I-"'"-""1.-.ow,)
I
.....LEGEND:
•••••.•...CANTWELL FLOW
80,.......-- ---WATANA FLOW
GOLD CREEK FLOW
-
-
721------------~--------------------------------j1t--------------------------~
-
•
-
-
-
-
-
:
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r:~I
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64
I-
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Ci.i I-u.
CJ
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.!:.()
f\( \1\n:..V 'WI:~:\'\\11 i ':\~;\I 'VI:\,:'...':.:~\.1 \,:~.\(\::,:-t.".:".\I:~:~..,,:\ : . \\I :.~/..:..I A 1":":.1 .::" \•••'y •••,1\•••••"'•••\.'I:::::*.'~J :•./~:::~:'.;-.•.~i \:~f ....'./\oJ ...:••••:.".!:....',J;:..\
f "*.... ."'.,..'"I_\
-
I,\~!'.::/~:..''.v:\.\~
.....:\.....'.:'.\.
I:..../"-I;,
1:",
-
-
I I
APRIL MAY JUNI::JULY AUGUST SEPTEMBER OCTOBER NOVEMBER DECEMBER
NOTE:
TIME SCALE IS IN INCREMENTS OF 10 DAYS,DAILY DISCHARGE HYDROGRAPHS
1967 NATURAL FLOWS
CANTWELL,WATANA AND GOLD CREEK FIGURE -8.3.1.4 :
J
J
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1
j
j
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•
88 "'--"--1--r-1-"'I""'I11,--.,--,--r-,-""-r-"'--,-.,.--,-"'"Ilil-.,.--I-.,.--'-TrIII-r--I-Ir----,'i""'TI--,I--,I--,.I-rI---rI-..,.I-..,.I-r'-...1-""'1-'-,,.,--.,-,..,-""""'1I-I
.....LEGEND:
•••••••••••CANTWELL FLOW
----WATANA FLOW80-
-----GOLD FLOW
I I I 1 I 1 I
-
-
721---------------------.:.---------------------------------·-------------------t
-
64~-------------------------------------------------------'-----------------1
-
561-----'---------------------------------:----------------~-------------------t
-
-
-en
LL
'0
ooo.:::.481--------------------------------:c-------------_------------"-.--------------------1
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C)
'0:«
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(,)
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MAY JUNE JULY AUGUST SEPTEMBER OCTORF"R
~:......"....."".',,'....:~y.\.,...:.../'.,"~...:~I'.....:,,"ow --_-
................~
I 'I ,,I I I II I I II I I I I I I .···;···t····I·..···....I..·:::-·:;:··l:::I ..·::::y:::·:-::·~:::-:·i:-=:::-=f'..=.:··t~···=·..=:-:j-...·-=-·-zr~.:;:;
APRIL
.1
10-
24
---
16
i-
8
f-
1 1
0
JANUARY FEBRUARY MARCH
32 1-------------,--------------------------------:-------------'---------------------f
MA ~~A
MONTH
NOTE:'
TIME SCALE IS IN INCREMENTS OF 10 DAYS.DAILY DISCHARGE HYDROGRAPHS
1970 NATURAL FLOWS
CANTWELL,WATANA AND GOLD CREEK ..FIGURE 8.3.1.5
I
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1
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------
~-_...__.~~----::::.~--"~_u .._~_J
-"-
THREE PAF AMETER LOG NORMAL DISTRIBUTION WITH 95 %CONFIDENCE LI MITS
PARAMETE is ESTIMATED BY MAXIMUM LIKELIHOOD
100
90
80
70 ./60 /'.50 //
40
/V
iii 30u./'./(J /§20:::V ~W V /Cl "~a:<::I:~~10 ~~•-ello9
~8 ------~----..--.o 7 ~..~.,----'W
~6 -.-----!Z 5 A A A A
~4
a
U)
Z
3
2
I
1.005 1.05 j,25 2 5 10 20 50 100 200 500
RECURRENCE INTERVAL (YEARS)
LEGE NO:
A a BSERVED DATA
0 E,T1MATED DATA•9'>%CONFIDENCE LIMITS
ANNUAL FLOOD FREQUENCY CURVE
0 MACLAREN RIVER NEAR PAXSON FIGURE B.3.1.6
SOURCE'RaM 1981
500200
~
FIGURE B.3.1.7:
10050
-'--'
20
'--~'
1052:
RECURRENCE INTIERVAL (YEARS)
--;
IANNUAL FLOOD FREQUENCY CURVE
SUSITNA RIi"ER NEAR DENALI
1.25
LEGEND:
A OBSERVED DATA
o ESTIMATED DATA
•95%CONFIDENCE LIMITS
1.005 1.05
60
10
80
70
.i i
THREE PARAMETER LOG NORMAL DISTRIBUTION WITH 95%CONFIDENCE LIMITS
PARAMETERS ESTIMATED BY MAXIMUM L1~EL!HOOD
100
90
RaM 1981
iiiu.o 50
8
S
;40
Cl
II:«:::t
~a 30
~owz·~z
~20enz
A
THREE IP.AR.AMETER LOG NORMAL DISTRIBUTION WITH 95%CONFIDENCE LIMITS
PARAM~TERSESTIMATEDBY MAXIMUM LIKELIHOOD
100•90 r---I-------.---+--._--.-I -.-.--..-.----+-----I +
80
70
_60
(I)u.o
8 50o....
-w
C)40a:
c(
J:o
-(I)
is
CI)30_.::Jow
Z
c(
~-z
c(
Iii 20z
1---+------+-------
-----+-------_._._---_...._..
...-.-----+-------.--...-.--...--..---t-.---.--...-..
-t---
;
LEGJND
6 BSERVED DATA
o STIMATED DATA
•.5%CONFIDENCE LIMITS
101.005 1.05 1.25 2 5
RECURRENCE INTERVAL (YEARS)
ANNUAL FLOOD FREQUENCY CURVE
SUSITNA RIVER NEAR CANTWELL
10 20 50 100 200 500
SOURCE'RaM 1981
FIGURE B.3.1.8
o
,
!
.:!•
i I
~
~~
~~L---0--i ::~
I ,.---.~~-I :...--......~-I
I I -,~
I ~A"--'"~---!i ------=..J-....-c"____r
-----~~~"------A ~.-A-
P-~~i
,-------V
i
005 1.05 1.25 2 i 5 10 20 50 100 200 50
RECURRENCE INTERVAL (YEARS)
20
10
I
'f.!:,.._i
THREE PARAMETER LOG NORMAL DISTRIBUTlqN'WITH 95%CONFIDENCE LIMITS
PARAMETERS ESTIMATED BY MAXIMUM LlKEWIHOOD
000
900
800
700
600
500
400
w
Cl
II:«':I:ollOO(J);ci'90
(J):805170
~:60«,H,50z'.
~'40
lJ)'
~,30
iii'300
u.o
0'8,200
:::
LEGEND:
A OBSERVED DATA
o ESTIMATED DATA
•95 %CONFIDENCE LIMITS
ANNUAL FLOO~FREQUENCY CURVE
SUSITNA RI\tER AT GOLD CREEl<
FIGURE ~.3.1.9
SOURCE:RaM 1981
'----.-'----'-___i~
----~~_._~~~--~._-----
I J
:]
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J
1
,J
1
-]
r
l
]
'/
.j
j
1
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,I
J
I 1
SURFACE AREA (1000 ACRES)
12 10 8 8 ..2 o
VOLUME (ACRE FEET 106 )
RESERVOIR VOLUME AND SURFACE AREA
I
'"./
I>/
V "~DWME"",VSURF.CE AREA
/1\
V \/
!1\
I ..\
\
SURFACE AREA (ACRE x 104 )
6 5 ..3 2
"./V
)v~
•VOLUME
f'Y V ~IsuRFACE REA
/f\
/\
r\
/\
I ,
I
I
a 2 ..6 8 10 12 14
VOLUME (ACRE FEET 105 )
RESERVOIR VOLUME AND SURFACE AREA
900
1400
1500
1500
~
Ww
!:
z
0
~1200~w·oJ'wi
1100
1000
o·
1412108642o
600
SOO
400
00
00
~
1.00ww
!:
z
0 2000~
~>W
900oJ
W
800
I
700
I
II
'600
I
500
400
WATANA DEVIL CANYON
RESERVOIR AREA AND VOLUME VERSUS ELEVATION,
WATANA AND DEVIL CANYON FIGIjRE B.3.2.1
1
I
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1
I
(
,I
,I
'I
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!
(
i
i
1
I
1
1.
,'}.
1459
RESERVOIR IS KEPT FULL
AT ALL TIMES IF POSSIBLE
2178 2185
2163
2150 II2143-
II 2129
1 2113 2114
•2100-I 2081
I 2065 2074
-WATANA STAGE III J
2000
1 1986
1966111966
-11942
11926 1928
1 1905 1900 I-I 1890
-'--WATANA STAGE I
.•... .
I I I I I I I I I I I
1390 -+---f---ir--+---+---t--+---t--~---tr-----+---t----.
1800
1850
2200
MAR APR
MONTHS
DEVIL CANYON RESERVOIR
',.MONTHLY RULE CURVE ELEVATIONS
OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP
MONTHS
WATANA STAGE I AND STAGE III RESERVOIRS
~2150
-Iw>2100w
-I
a::o 2050>a::w
ff3 2000a::
:x::
I-
~1950
~
u.
o 1900ozw
750 ----------------------------~
450
350
FILLING SEASON
SUSITNA GENERATION
DRAWDOWN SEASON
250
650
::2.{§-z 550o
~a:wzw
C)
>-C)
a:wzw
>-...J ..
:::r::
I-zo
2
OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP
MONTHS - WATER YEAR 2000
LEVEllZED THERMAL ENERGY GENERATION
FIGURE 8.3.2.3.
2200 ......----------------------------.
2180
-.-:u..
;;2160
o
I-«
~2140
..Jw
W
U«
~2120
:;:)en
0:-
w
~2100
3:
2060 -I--__._---r----,,....--....---,--_-........--,,....--__-......--_----f,
OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP
WATERYEAR
LEGEND:
--....CURVE FOR IN,CREASING RATE OF POWERHOUSE RELEASE
_ac.-....CURVE FOR DECREASING RATE OF POWERHOUSE RELEASE
WATANA OPERATING GUIDE CURVES
FIGURE 8.3.2.4
12:8:4:12:
PM
PEAK LOAD CURVE
AUGUST 1983
(Peak August Day)
8:4:
L -TOTAL RAILBELT
./"""""'---.....
j;~.,--r\-AN(-...
HORAGE AREA1-"----
r-FA IRBANKS AREA
_1--------------'------
110
550
o
12:
AM
440
~
~
-330oz«
.~
wo
o 220«
'0
..J
12:8:
---_1 _
4:
---
12:
PM
PEAK LOAD CURVE
DECEM8ER 1983
(Peak December Day)
8:
,.-'
."".
4:
--
0'I I I I ,I ,
12:
AM
110 I I I I if I I I I
440 I I f I I I I I ~I
550 iii i Iii •
~
~-330 I =r---""1""I I "........,......"......."1....."I '-Io~
z«
~wo
~220 I I It I I I I I
o
..J
TYPICAL LOAD VARIATION IN
ALASKA RAILBEL T SYSTEM
'FIGURE 8.4.1.1
MONTHLY LOAD VARIATION FOR RAILBEL T AREA
o 0
JAN.FEB.MAR.APR.MAY JUNE JULY AUG.SEP.OCT.NOV.DEC.
1983
FIGURE 804;1-;2
200
300
500
600
400
iOO
\~/
\~/V
1\TOTAL RAILBELT AREA /'"V"/---'""~//.-""""
'"r-.-/-
ANCHORAGE-COOK INLET AREA
1.0::---~,---~-------Ic-----~-------~-1---------
~r--.~IRBANKS.TANANA VALLEY ARE~~
600
400
100
500
3:
:E
c'
Z
<300:Ewc
~<wa..
~
~200
zo
:E
1.028 L8.1°·
26_
2 :+to ESTER
1.4 52
26--
~~7 SVC
183-
12.14.~54.4
345 ,KY i
88~
138 KV"os Lll 0
-190 -380
,,,":r.n r.n (0
(0 ...:en .
N ....co ....,f ~26.1 1'1.5....~1.04:1L9~40't t t t
GOLD ~i
CREEK 326;8 80.2
r.n .......26.6 -r.-53.1
g .....';_190 WATANA....',...--...;..--.;.------1
~t 51 .6 "';-2~:6 345 KV
345 KV
-t-Jp 282
105 L 0 0
345KV
68.8 .'1.009 L -5.9°
~!1::-1026 Lao
.1·15 KV...1:.8 ...-5 ..8
KNIK ARM 41+--+-362\"G
155.3 ---._58.7 58.6 ---.._:158.2 2.30 KV.
<f+-'.......80 80 8 ++-UNIVERSITY
744 .120 1.03 L -3.7 0
'--rn."+~...;;".....;5:_:8;.:,;..7----::::5.:::.:8.~6.....;;;:;:.~..=;...:;:..~,...--
.0$-80 80 8 Olf--+-..e+:S VC.3~~
345 K'l ---;lII>120
-f-Jlo 58
115 K\l
WillOW~.__'0.985 L-4.7 °
322.9 :39.4 """_~~__I~'-,1 t f -t+81
1.006L2.4 ...._~....138 KV
"1 ~
1999 APPROXIMATE PEAK LOAD.DOUBLE CONTINGENCY
LEGEND
-REAL POWER (MW)
-REACTIVE POWER (MVAR)
1.00,t).00 VOLT AGE IN PER UNIT a
ANGLE IN DEGREES
~LOCAL LOAD
@ GENERATOR
,lsvcl STATICVAR COMPENSATOR
t OIM TL TO U/W CABLE
AGE-FAIRBANKS TRANSMISSION
RELIABILITY EVALU
1999 INTERCONNECTED SYSTEM FIGURE 8.4.1.3
lI
I
\
i
j
J
1
j
I
j
]
i
1
lOS Lao
-""""""·-659-
........319
++.-::SVC
172.~
-.210
-t+103
i 138 KV 1.0SL22.70
+-.410 G
........3~A ,
WATANA
345 KV
9J+.~o.,
'345 KV t
9.~ESTER
98_~
345 KV
WILLOW:'.0.961L 0.30
'587;8 2.8 1n t.',{--(:.~t 1"112.80.992L7.8°·l!!!!!f__~IIlIlIllli=~138 KV
I.345KV
-----.----=-....1-.....---1 ----=-.------.----
;A15B ~tQ.l 1.015.~-l__:9_1;5~1-025L12'
'28.+-1.15 KV -~_
,'NIK A M-......·:~.t_..1:io~"G
412.1--""~184'fI ,183:B-iI'247.5 _-230 KV
."+-++-121_.4,]25.7+i-UNIVE:RSITY;052·;7·144 T.O £..-3.2___189 -183.8__-iI'.r-.....--,--.-
-------------------~u--Ell "CL_l21..L -125.7.'!1--_~_4_-
345 KV 345 KV'
204.4
98.8 Hi:98.8 -161 41204.4"-.
.1.042-L20.90 t t,*,t ~t 4t'C.345 KV:".',-,-",.."..-..---,--
GOLD ,~tt,t t t45 ~045L2~390
CREEK qOo.~141.4 194.9 45.8'194.9 .+t-80 G
......----1 DEVIL CANYON
@ GENERATOR
'-lsvclsTATIC VAR'COMPENSATOR
+O/N TL TO U/W CABLE
115 KV
2005 APPROXIMATE PEAK LOAD,DOUBLE CONTINGENCY
LEGEND
-REAL POWER (MW)
-REACTIVE POWER (MVAR)
1.00&>.00 VOLT AGE IN PER UNIT I
ANGLE IN DEGREES
~LOCAL LOAD
ANCHORAGE-FAIRBANKS TRANSMISSION
RELIABILITY EVALUATION
2005 INTERCONNECTED SYSTEM FIGURE 8.4.1.4
J
,(
]
I
i
.........SVC
'234.4
--+273
'1.05L13.1°·1.015L 19;2
136.5 --i"-
3.5-1+-ESTER
:273136.5 --+..-..-
3.5-++.....70.4
345 KV
......132 .
138 KV.l05L30.90
..-1070 G
530.8 (Xl ~71..7
138;1 18.7122.3 g WATANAttttr{22.3 -..345 KV
1.037L26,1:-+1iIliI-.....-.....-........-~345 KV
GOLD.l t ~t t t ~,1.043 L26;5'~
CREEK 622.4 150.Q.·147'229.7 229.7 -4£10 G
622.4 150.6 147 .......285·:
DEVIL CANYON
345 KV
+--412.'
1.05LOO
_851
:yi'lllOW
608 3 0 2
:0.93 L2.3°
608.3 '0~2 "t'.221 ."t--I-~1+t ,. t +1:60.4 -1-0'7
T 138 1(\1"
~f 345 KV
497,8 80.4 1.001L5..6°a.943L-4.60
497.8 80.4 .~.51 f .1-'..1!!'!.57-+-f.......:.2&.1.917L3.1°~SVC492.6.)tl)~·115'KV ·.737.2 810:6 .
:::KNIK ARM -'::;:O::==-H-~~"~";".:::1t~G-,....•.....-·1'i-70~140.2;414.8 -"230 KV ",--_4_9,;;,;2.~6,.._.......__•4..;,.;64;..;,;;.;,.1__--:.;46:.:2::.:;.6:...-.:...-1 UNIVERSITY
...........191.2 214.7..-+-188 ..1.03L-2.7°
___-:;:o;:~-1r4_0._2+-...;,,~4;:.;64:.::.1:-_--...,;4~62:;:;.6::-~"~_"~....---.
4-+-191.2 214.7 -++-r,4:~1"
345 KV 345 KV
.985L12.4°
2025 APPROXIMATE PEAK LOAD,DOUBLE CONTINGENCY
LEGEND
-REAL POWER (MW)
~REACTIVE POWER (MVAR)
1.00&00 VOLT AGE IN PER UNIT &
ANGLE IN DEGREES
-.LOCAL LOAD
@ GENERATOR
Isvcl STATIC VAR COMPENSATOR
+O/N TL TO U/W CABLE
RELIABILITY EVALUATION
2025 INTERCONNECTED SYSTEM,
FIGURE 8.4.1:5
RESERVOIR EL.2000
GENERATOR OUTPUT WITH
TURBINE OPERATING AT BEST
EFFICIENCY GATE -"';"'--:--..
STAGE m
NOMINAL PLANT CAPABILITYIt6V8Eo~A-JGEOPERATING HEAD
185MW
I-------I------+-------..+---+--,ST AGE m'650 _DEPENDABLE PLANT CAPABILITY
I DECEMBER-JANUARY HEAD
(645)
170MW
GENERATOR OUTPUT WITH
TURBINE OPERATING AT FULL
GATE POWER--'I
500 1-------1-----...-t---j~-STAGE 1-----+-------1
_NOMINAL PLANT CAPABILITY
I AVERAGE OPERATING HEAD
(490)
110M'll
750 ,..-----..,-------r-----.,....-----,-----.....,
200MW
..:.R:.::E;:.;;S::.::E;:.:.R.:.;V:..;0=r-I:.:.R~.-=E-=L~...:;2:..:1:.;:8:.;:5+_-,,__~r-.1 MA XIMU M HEAD
(719)
700 I-------I------+-----+--I---~t-+------I
I-w
~600 I-------I------+--~~-_fl_-----I------I
1
w
Z
a:Ia:
~
~550 1-------1------+--,1----#--+-------1------1
c
<Cw
:I:
I-w
Z
STAGE I
........._,,4,,5..0..1--1-----I---1-#-_-.-I-,,~1-+-..~~j5~~~~~~~J~~b~~~~~~~BILlTY_-~.
.90MW
400 1-------1--1--1----+--'----+------+-------1
MIN 1M U M H E;.:A~D__+&-__..:.R.:.:E:.;;S:;.;E:::.;;R.:.V~0r__1R........E...L...._1...8...5..0"'1
(384)I
65MW
250200100150
UNIT OUTPUT -MW
350 .....----.......----.....1-----.....----......-------1
o 50
WATANA UNIT OUTPUT
.....-
FIGURE 8.4.2.1
75MW
OMW
--MAXIMUM HEAD
(600)
MINAL PLANT CAPABILITY
RAGE OPERATING HEAD
0)
E PLANT CAPABILITY
EAD
TOR OUTPUT WITH
OPERATING AT
ATE
180160140
UNIT OUTPUT -MW
120
~1
RESERVOIR EL.1455
GENERATOR1 O~TPUT WITH /
TURBINE OPERATING AT I
/_NOBESTEFFICIENCY-rJ AVE(y
~.L __17
/'.GENERl
/TURBINE
FULL Gi
..~/RESERVOIR EL.1405/DEPENDABL
MINIMUM H
(545)-
150MW-
580
620
560
540
520
100
600
I-wwu.
I
C«w
::J:
I-w
Z
J
FIGURE B.4.2.2
-
."\V~o\l->
~
,V~«:.,
/o¢
bOlO'
~V /'
~
~-
V ATANA ST i\GEm
A ~:D DEVIL C I\NYON
WATAN
STAGE n
~
STAGE!NO
DEVJL CAt'-YON
STAGE III
WATANA
StAGE 1 .
1800
1600
-3=
:E 1400->a:
4:
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Ia:w
In
:E 1000w
0wc
:z...
>800
I--0
4:a..
4:
0 600
w
-'In
4:
C:z 400wa..wc
200
o
1990 1995 2000 2005
YEAR
2010 2015 2020 2025
I
l SUSITNA DEPENDABLE CAPACITY
FIGURE 8.4.2.4
1
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FIGURE 8.5;2.1
FAIRBANKS·TANANA
VALLEY r:'""":,i
RAILBELT AREA OF ALASKA
SHOWING ELECTRICAL LOAD CENTERS
FIGURE 8.5.2.,2
11
LOCATION MAP
LEGEND
\1 PROPOSED
DAM SITES
PROPOSED I~KV I.INE
-EXISTING I.INES
.~
20 0I .
SCAI.E IN MII.ES
::lOCATION MAP SHOWING
TRANSMISSION SYSTEMS
20,60
!
MONTHLY LOAD VARIATION FOR RADLBEL T AREA
600 _-,..----.,~.......,........'_""I"......._,..-...,...-....,...-.......-...._~=;=======r600
o 0
JAN.FEB.MAR.APR.MA-<i,JUNE JULY_A.'J§~.S~.()~I~_r-"-QV!_DEC.
11':10.,
1__~~---:-.:.·::.-:I ·_------------------.--------------l----~"I--·_·I-----.------------,----
lOOp-..............0::-+---1-----1----+--+--1---+---+--+--+---~-J 100
r--..~IRBANKS-TANANAVALLEY AR~..__ol----t-~
)
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----'-,.-
ANCHORAGE-COOK INLET AREA
'",
1\
500 ~/5001\"1\TOTALRAILBELTAREA vVv
400 ~~/--400
;0 1"'\~~~V V
g ~r-~V
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wo
~
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Q,.
~
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o
:l:
'---'
600 iii iii i i
500"'I I I I I I ,
,,·-'----'1 ..-----..J ,-_......I ,,--•.-.,_.,'',......l ',"f ..1'--...."
ANCHORAGE AREA
I
FAIRBANKS AREA
TOTAL RAILBELT
-_,'-.""'-'J r-_r.-~,--.'"
~400'I P..~'I ,A I &I A I • I ,
Q
Z«~300 I ,(\\1 H ",-'~\\1 I.'"J1-''1 N '-,\I H """",w •-(..~
Q
Q«o 200 I I I I ..I I-I ~I I
100 I 1 1 / 1 1 I 1 I
o I ,,,,,,,
SUN MON TUE WED THU FRI SAT
WEEKLY LOAD CURVES -APRIL 1983
FIGURE 8.5.2.4
Page 1 of 3
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,'"...""......I ",........I .."
__.'_...',....,,1 ....".-'..."
0'I I I I I I ,
SUN MON TUE WED THU FRI SAT
WEEKLY LOAD CURVES -DECEMBER·1983
FIGURE 8.5.2.4
Page 3 of 3
/
-
7.7%/y'l
.3.3%/V
3,/V
3'B7
3.6%~
"
I··c I~-·1-···-
HISTORICAL POPULATION GROWTH
400
350
300
-.In 2500
0
0...-
2:
0 200I-«-':>
C-
O
C-150I-
...J
W
a::l
-'«ex:100
50
o
1960 1965 1970 1975 1980 1985
FIGURE 8.5;2.5
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I-
(.)
W
..J
W
...I 1000«
I-
0
l-
I-
...I
W 500a::l
...I.-..«a:
/6,1%17
7.0%1v!
V
/
.14'4%/V/
13,6%;/
,
1960 1965 1970
YEAR
1975 1980 1985
-HISTORICAL GROWTH IN UTILITY NET .GENERATION
FIGURE 8.5.2.6
OPTIMUM
EXPANSION
PLANS·
FIGURE 8.5.3.1
•EXISTING
GENERATION
SYSTEM
•'FUTURE
GENERATION
SYSTEM
•CONSTRUCTION
COSTS
·O&MCOSTS
•RELIABILITY AND
AVAILABILITY
CRITERIA
ELECTRICITY
PRICES
•RESIDENTIAU .
BUSINESS
END USE DATA
•PRICE
ELASTICITIES
•INDUSTRIAL
LOAD FORECAST
•NATIONAL ECONOMIC
PARAMETERS
•INIDUSTRIAL ACTIVITY
•STRUCTURAL
F?ARAMETERS
•STATE FISCAL RULE
RELATIONSHIP OF PLANNING MODELS
AND I~PUT DATA
I !
APR STATE
1 MAP POPULATION_REDPETROLEUM-ENERGY.OGP
PETROLEUM ECONOMIC HOUSEHOLDS_ELEctRIC GENERATION
REVENUE REVENUE GROWTH.-LOAD PEAK PLAN
FORECAST -.FORECAST EMPLOYMENT.FORECAST LOAD
I
•.ROYALTY RATE
•SEVERANCE
TAX RATE!.
IRESIDENTIAL&qOfl(lMERCIAL HEATING OIL &GAS PRICES
ALASKA
GAS AND
OIL PRICE
FORECAST
WORLD
OIL
PRICE
FORECAST
ALASKA
OIL AND
GAS
PRODUCTION
FORECAST
---.J '------''-----"..----.J ..:...---~.__"
r 'I
I I,,
1 I
INPUT VARIABLES:
•PRODUCTION VARIABLES
•PRICE VARIABLES
"
REVENUE
FORECAST
MODULE
•North Slope Oil Revenue
•North Slope Gas Revenue
•Cook Inlet Oil Revenue
•Cook Inlet Gas Revenue
PETROLEUM
REVENUE
FORECAST
•Severance Taxes
•Royalties
INPUT PARAMETERS:
o INFLATION RATE
•TAX AND ROYALTY RATES
8 ECONOMIC LIMIT FACTOR
ALASKA PETROLEUM REVENUE
SENSITIVITY (APR)MODEL STRUCTURE
FIGURE B.5.3.2
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FIGURE B.5.3.3
NONSTOCHASTIC
PARAMETERS
INPUT VARIABLES:
•INDUSTRIAL CASE
FILES
•PETROLEUM
REVENUE
FORECASTS
INPUT VARIABLES:
•U.S.INFLATION RATE
G U.S.UNEMPLOYMENT
RATE
•otHERS
PARAMETERS:
•STATE FISCAL POLICY
PARAMETERS
•STOCHASTIC
PARAMETERS
ccc...NGNSTGGHASrlG ...
PARAMETERS
MAP MODEL SYSTEM
STATE
ECONOMIC
PROJECTION
REGIONAL
ECONOMIC
PROJECTION
REGIONALIZATION
MODEL
STATEWIDE
ECONOMIC MODEL
•ECONOMIC MODULE
•FISCAL MODULE
•DEMOGRAPHIC MODULE 1lIIIlIIIIIIi...----t
I CONSTRUCTION I
FISCAL MODULE.r,-sr-;;;-I-L PETROLEUM,..-.----.,....-----I~.GOVT.I"ACTIVITY1__ _ __......r---r--...I
LOCAL _
GOVT.
Ir
BASIC SECTORS
FORESTRY
FISHERIES
FEDERAL GOVT.
AGRICULTURE
MANUF.FOR EXPORT
MINING
TOURISM
~,
INDUSTRIAL'PRODUCTION
SUPPORT SECTORS
TRADE
FINANCE
SERVICES
TRANSPORTATION
COMMUNICATIONS
MANUFACTURING
PUBLIC UTILITIES
EMPLOYMENT
DEMOGRAPHIC MODULE ----....1 I
FIGURE 8.5.3.4
MAP ECONOMIC SUB-MODEL STRUCTURE
------------------~
,Ir
WAGES.AND..
SALARIES
J,
.PERSONAL...INCOME
...
DISPOSABLE
PERSONAL
INCOME
•REAL
Il1o.
DISPOSABLE.
PERSONAL -INCOME
PERSONAL ~At--~
TAXES '
CONSUMER
PRICES
NON-WAGE
INCOME
WAGE RATES 1-----DJooI
-
LABOR
FORCE
ALASKA
HOUSEHOLDS
-
ALASKA
POPULATION
I NATURAL )
I INCREASE
r-------------.1----,
.'F--'-I
1
NET L.I
MIGRATION J
I
I(
~f
LIIII
I
TOTAL
EMPLOYMENT
IN
OTHER REGIONS
POPULATION *
TOTAL EMPLOYMENT *
BY PLACE OF WORK
~,...-------,
EMPLOYMENT BY PLACE
OF RESIDENCE
BASIC AND GOVT.SUPPORT
EMPLOYMENT EMPLOYMENT
SCENARIO GENERATOR
AND
STATE MODEL
P0PlJlAr10N-..
BY 1980 CENSUS AREAS
*CONSISTENCY ADJUSTMENT APPLIED
TO CONFORM WITH STATE MODEL
SIMULATION RESULT.
HOUSEHOLDS *
MAP REGIONALIZATION SUB-MODEL STRUCTURE
FIGURE 8.5.3.5
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FORECAST
~HOUSING --STOCK
I III,,,
..-RESIDENTIAL -
UNCERTAINTY
MODULE
".....BUSINESS -
I]"---
Ir
-PROGRAM INDUCED--...CONSERVATION-,
LARGE MISCELLANEOUS
INDUSTRIAL
,It
--ANNUAL SALES --
I I t' I\J -PEAK DEMAND --
RED INFORMATION FLOWS
..
FIGURE 8.5.3.6
SELECT PARAMETERS
TO BE
GENERATED
RANDOMLY
SELECT NUMBER OF
VALUES TO BE
GENERATED
..COMPUTER.
GENERATES N·
RANDOM NUMBERS
TRANSFORM
RANDOM NUMBERS
TO PARAMETER VALUES
OUTPUT
PARAMETER
VALUES
RED UNCERTAINTY MODULE
NO
FIGURE 8.5.3.7
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CONSTRUCTION
OF TYPE TY
FILL VACANCIES
TY WITH
COMPLEMENTARY
DEMAND
•AGE DISTRIBUTION
OF HOUSEHOLD
HEADS
•SIZE DISTRIBUTION
OF HOUSEHOLDS
IS
DEMAND TY
)STOCK TY
?
CALCULATE
DEMAND FOR
HOUSING UNITS
BY TYPE TY
STRATIFY
HOUSEHOLDS BY
AGE OF HEAD
SIZE OF HOUSEHOLD
FORECASTS OF OCCUPIED
&UNOCCUPIED HOUSING
BY TYPE
DIIlIlI ·1!llIlIII1I
REINITIALIZE
HOUSING
STOCKS
INITIAL HOUSING
STOCK TY
RED HOUSING MODULE
FIGURE 8.5.3.8
RED RESIDENTIAL CONSUMPTION MODULE
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SATURATIONS
BY HOUSING TYPE
(UNCERTAINTY MODULE)
-PRICE-ADJ~PARAMETERS -
RESIDENTIAL SECTOR
(UNCERTAINTY MODULE)
--PRICE-AND-
CROSS·PRICE
ADJUSTMENTS
..RESIDENTIAL
CONSUMPTION
PRIOR TO
PROGRAM·INDUCED
CONSERVATION
SUM PRELIMINARY
CONSUMPTION
FOR ALL
APPLIANCES
FIGURE 8.5.3.9
CALCULATE INITIAL
SHARE OF EACH
APPLIANCE USING
ELECTRICITY
SUM PRELIMINARY
CONSUMPTION FOR
APPLIANCE USE
BY APPLIANCE
FORECAST OF
OCCUPIED HOUSING
STOCK BY TYPE
(HOUSING MODULE)
CALCULATE AVERAGE
ELECTRICAL USE IN
LARGE APPLIANCES
BY APPLIANCE
CALCULATE STOCK OF
LARGE APPLIANCES
BY END USE
DWELLING TYPE
EMPLOYMENT
FORECAST
CALCULATE
BUSINESS
GOVERNMENT
LIGHT INDUSTRIAL
FLOOR SPACE
CALCULATE
PRELIMINARY
BUSINESS
ELECTRICAL
CONSUMPTION
PRELIMINARY
BUSINESS USE
COEFFICIENTS
(UNCERTAINTY
MODULE)
PRICE
ADJ PARAMETERS
BUSINESS SECTOR
(UNCERTAINTY
MODULE)
PRICE AND
CROSS PRICE
ADJUSTMENTS
PRICE
FORECASTS
(EXOGENOUS)
BUSINESS
CONSUMPTION PRIOR
TO
PROGRAM-INDUCED
CONSERVATION
RED BUSINESS CONSUMPTION MODULE
FIGURE 8.5.3.10
RED MISCELLANEOUS CONSUMPTION MODULE
ElGJ,l8i::.....B.5..3.lL~
IJ
1
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1
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1
1-
CALCULATE
VACANT HOUSING
CONSUMPTION
CALCULATE
STREET LIGHTING
REQUIREMENTS
SUM FOR
MISCELLANEOUS
-CONS(JMPTION~-.
CALCULATE
SECOND
HOME
CONSUMPTION
II
II
LOAD
FACTORS
(FROM UNCERTAINTY
MODULE)
ANNUAL ELECTRICITY
REQUIREMENTS
•RESIDENTIAL
•BUSINESS
•MISCELLANEOUS
CALCULATE
PRELIMINARY
PEAK DEMAND
CALCULATE
REVISED
PEAK DEMAND
CALCULATE
PEAK
SAVINGS
•ANNUAL SAVINGS
DUE TO SUBSIDY
•PEAK CORRECTION
FACTOR
(FROM C9NSERVATION
MODULE)
RED PEAK DEMAND MODULE
FIGURE 8.5.3.12
II
JFIGURE8.5.3.13
.,11
!;1
FUTURE ECONOMICS &'j
OPERATING GUIDELINES
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EXISTING UNITS &
ALLOWABLE
TECHNOLOGIES
OPTIMIZED GENERATION PLANNING (OGP)PROGRAM
INFORMATION FLOWS
HOURLY BASED
PEAKS &ENERGIES
OPTIMIZED GENERATION
PLANNING (OGP)
.J,..EVALUATE RELIABILITY .......,
+
EVALUATE SELECT UNIT .....
ALL CHOICES SIZES &TYPES
STUDY
.·WITH"L.OOK~AHEAD"I··..
~ALL YEARS
~~CALCULATE OPERATING &
INVESTMENT COSTS 4~
USING "LOOK-AHEAD"
~....I........._-~.-....
CHOOSE LOWEST
COST ADDITIONS &
CALCULATE CURRENT
YEAR'S COSTS
I ........
,..
..........J3.ESU.LIAI'YTQeI1MUM ..~._...•I····
EXPANSION PATTERN ·?-==-==··==--=t1-0IJTPtJT--1-_._---_._._._------_._--_.--_..__..~-_.._.._-----------_._-_._---_._._-._------_........._-_.
&DOCUMENTATION OF
NEAR-OPTIMUM PLANS
20l6
WEEKEND DAY
12a4
PI =MINIMUM RATING (MW)
24 .
INITIAL
LOAD
.a 20128
WEEKDAY
MODIFIED
LOAD
4a
II
r I
II
II
rI
II
HOUR HOUR
OPTIMIZED GENERA TION PLANNING
EXAMPLE OF CONVENTIONAL HYDRO OPERA TJONS
FIGURE 8.5.3.14
o
20
30
40
50
60
10
70
80
20101990199520002005
!
I IALTER~A1iIVE Oil PRICE P~OJECTIONS -$/bbl (1985 $)
,
i ,
N01'E:PERCENTAGES IAR~
I 'AVERAGE ANNUAL GRpw;TH
RATES FOR S-YEAR PERIODS
FOR COUPOSITI!CASI ONL Y
/
SHCA CASEI '
I v/COMPOSITE CASE
I
1 k ,/,}.O%
I .~WHARTON CASE
i ~/"'~~i i .--::;::;!,--
~~
-.4%-
I,.
i
1
50
o
1985
10
30
40
20
60
70
:0
~
10m...
-I
o
LLo
Woa:
0-
C
-Ia:
~
FIGURE 8.5.4.1
'-----''-'---""~__,,~L-...L---...;\.----...i >..---i.....:L.i L.--.-...-----..J ~~t:-------i
i~--·
700.I ••II I i I •Ii'
600 I I I I U I I I I
NOTE:PERCENTAGES ARE
AVERAGE ANNUAL GROWTH
RATES FOR S-YEAR PERIODS
FOR COMPOSITE CASE
AND HISTORICAL DATA ONLY
-1----3 .6 %
v,3.6%
WHARTON CASE-
COMPOSITE CASE
PROJECTIONS SHCA CASE
I
I
400 I
I I
:,:I •
0.9%1.0%0.9%1.2% 1.6%
300 t-t----+----t----jf-----+--;e---+----I-------l------1---+----I-
/""
3.3%
HISTORICAL ."lV
~3.3%
zo-I-
<C
..J
::J
Q.o
Q.
I-
..J
W
OJ 200..J.-<C
a:
.....,
"""'o
o
o 500..
100 I I I I I I I I I I I I
2005 20102000199519901980197519701985
.YEARS
ALTERNATIVE RAILBEL T POPULA TION FORECASTS
O'I ••,I I ,•I •,
1960 1965
FIGURE 8.5.4.2
!
AL TERN'~TIVE RAIL BEL THOUSEHOLDS FORECASTS
!!I
201020051995200019901985197~1975 .19801965
,
1 !W l"IARTON CASE
CO,~POSITE CASE
!f'!SHA CASE -..,I,
PROJE CTIONS ~~
~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
1.2%1.3%1.1%1.3%1.7%
/
HISTO RICAl /
/
!
V V
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YEARS
NOTE:PERCE'NTAGES ARE AiN AVERAGE ANNUAL GROWTH RATES
FOR 5-YEAR PERIOID~FOR COMPOSIT~CASE AND HISTORICAL DATA ONLY.FIGURE B.5.4.3
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W 10100
AL TERN A TIVE ELECTRIC ENERGY DEMAND FORECASTS
AT POINT OF USE
CO~~POSITE CASE
SHCA CASE
~W HARTON CASE -;:J
PROJEC TIONS ~~
...?-
I
I
W p-I I I
I I I
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7.8Y
/
7
V ';'
o
1960 1965 1970 1975 1980 1985 1990
YEARS
1995 2000 2005 2010
NOTE:PERCENTAGES ARE AVERAGE ANNUAL GROWTH RATES
FOR 5-YEAR PERIODS FOR COMPOSITE CASE AND HISTORICAL DATA ONLY.FIGURE B.5.4.4
201020052000199519901985198P197519701965
,
i W HARTON CA~P
l-
I
PROJE PTIONS ~~I
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I
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ALTERN'ftJTIVE Ef ,':;T,RIC PEAI<DEMAND FORECASTS
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o •
1960
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z«
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NOTE:PERCENTAGES ARE AVERAGE,ANNUAL,'GROWTH RATES
FORS";YEAR PERIO'D~FOR COMPOSITE CASE AND HISTORICAL DATA ONLY.
YEARS
FIGURE 8.S.4.S
~;~L..-..-.J~<-----J--~'.~'-........--l'-----''---.:~------.;'------'---;