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BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
APPLICATION FOR LICENSE FOR MAJOR PROJECT
SUSITNA HYDROELECTRIC PROJECT
DRAFT LICENSE APPLICATION
VOLUME 5
EXHIBIT C
PROPOSED CONSTRUCTION SCHEDULE
EXHIBIT D
PROJECT COSTS AND FINANCING
APPENDIX Dl
FUELS PRICING
L:I'J!\,IfFl ':)IT'!
ABeTle El-.JVIRONM ......"..,.."..'·-:
AND DATA csase.,...'"
707 A STREET
ANCHOAAGI.W.wlOl,
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November 1985
ARLIS
Alaska Resources
Library &Information Services
Anchor3ie ,Alaska
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l't!V'i',tt~nl·\~:>;,(il )i{~'l'~'l'l _,t\1.!1:L'1:tj ..1
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NOTICE
ARLIS
Alaska Resources
Library &Informatinn Services
Anchor~e.~aska
I'
A NOTATIONAL SYSTEM HAS BEEN USED
TO DENOTE DIFFERENCES BETWEEN THIS AMENDED LICENSE APPLICATION
A~
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 1n the
July 29,1983 License Application
VOLUME COMPARISON
DESCRIPTIONCHAPTER
VOLUME NUMBER COMPARISON
LICENSE APPLICATION AMENDMENT VS.JULY 29,1983 LICENSE APPLICATION
JULY 29,1983
AMENDMENT APPLICATION
VOLUME NO.VOLUME NO.EXHIBIT
A Entire Project Description 1 1
B Entire Project Operation and Resource
Utilization
2 2 &2A
App.Bl MAP Model Documentation Report 3 2B
App.B2
App.B3
RED Model Documentation Report
RED Model Update
4
4
2C
C Entire Proposed Construction
Schedule
5 1
D Entire
App.Dl
Project Costs and Financing
Fuels Pricing
5
5
1
1
E 1
2
General Description of Locale 6
Water Use and Quality 6
5A
5A
Tables
Figures
7 5A
5B
Figures 5B
3 Fish,Wildlife and Botanical 9
Resources (Sect.1 and 2)
6A
6B
Fish,Wildlife and Botanical
Resources (Sect.3)
10 6A
6B
Fish,Wildlife and Botanical
Resources (Sect.4,5,6,&7)
11 6A
6B
7
7
7
8
8
8
13
13
13
Aesthetic Resources
Recreational Resources
Socioeconomic Impacts
Historic &Archaeological Resources 12
12
12GeologicalandSoilResources
Land Use
4
5
6
7
8
9
~
I
10
11
Alternative Locations,
and Energy Sources
Agency Consultation
Designs 14
14
9
lOA
lOB
F
F
Entire
Entire
Project Design Plates
Supporting Design Report
"15
16
3
G Entire Project Limits and Land Ownership
Plates
17 4
SUMMARY TABLE OF CONTENTS
SUSITNA HYDROELECTRIC PROJECT
LICENSE APPLICATION
SUMMARY TABLE OF CONTENTS
EXHIBIT A
PROJECT DESCRIPTION
Title Page No.
1 -PROJECT STRUCTURES -WATANA STAGE I (**)•· ....A-1-2
1.1 -General Arrangement (**)· · · ··· · · ·
·1.2 -Dam Embankment (**)··· · ·
·1.3 -Diversion (**)· · ·· · · · · ·
·1.4 -Emergency Release Faci li ties (**)
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 (**)·· · · · ·· ·
·loll -Tailrace (**)··· · · · · · ·
· ·· · ·1.12 -Main Access Plan (**)· ··· ·
··· ·1.13 -Site Facilities (**)•· ······ · ·1.14 -Relict Channel (***)·· · ·
2 -RESERVOIR DATA -WATANA STAGE I (**)••· ·
• • • •
A-1-2
A..,.1-4
A-1-6
A-1-9
A-I-I0
A-l-13
A-1-15
A-1-15
A-1-18
A-1-19
A-1-22
A-1-23
A-1-25
A-1-29
A-2-1
3 -TURBINES AND GENERATORS -WATANA STAGE I (**)· ....A-3-1
3.1 -Unit Capacity (**)•••.
3.2 -Turbines (***)•.••
3.3 -Generators (**)
3.4 -Governor System (0)••••
·. ..
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)(***)
5 -TRANSMISSION FACILITIES FOR WATANA STAGE I (0)
a>
M
Na>co.q
ooo
10
10
I'"
M
M
5.1 -Transmission Requirements (0)
5.2 -Description of Facilities (0)
5.3 -Construction Staging (0)•••·. .
• •·..
·..
A-4-1
A-4-5
A-4-12
A-5-1
A-5-1
A-5-1
A-5-11
851014 1
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT A
PROJECT DESCRIPTION
Title Page No.
6 -PROJECT STRUCTURES -DEVIL CANYON STAGE II (**)· ...A-6-1
6.1 -General Arrangement (**)A-6-1
6.2 -Arch Dam (**)A-6-2
6.3 -Saddle Dam (**)· · ·
··· ·
·A-6-4
6.4 -Diversion (**)··· ·
··· · ·
··A-6-6
6.5 -Outlet Facilities (**)··•··A-6-8
6.6 -Spillway (**)·.· ··· ··· ·
A-6-10
6.7 -Emergency Spillway · · ·········A-6-12
(This section deleted)
6.8 -Power Facilities (*)····· · ····A-6-12
6.9 -Penstocks (**)·.· ·
··•·· ·
·A-6-13
6.10 -Powerhouse and Related Structures (**)···A-6-14
6.11 -Tailrace Tunnel (*)·· · · ·
·· ·
···A-6-17
6.12 -Access Plan (**)A-6-17
6.13 -Site Facilities (*)·· · ·· ·· ·
A-6-18
7 -DEVIL CANYON RESERVOIR STAGE II (*)-•·•• •·• • ••A-7-1
8 -TURBINES AND GENERATORS -DEVIL CANYON STAGE II (**)• •
A-8-1
8.1 -Unit Capacity (**)
8.2 -Turbines (**)
8.3 -Generators (0)••
8.4 -Governor System (0)
· . ....·. . .. .. . ...· . . .. .. . . . . ..
A-8-1
A-8-1
A-8-1
A-8-2
9 -APPURTENANT EQUIPMENT -DEVIL CANYON STAGE II (0).•• •
A-9-1
9.1 -Miscellaneous Mechanical Equipment (0)••
9.2 -Accessory Electrical Equipment (0)••••••
9.3 -Switchyard Structures and Equipment (0)•••
A-9-1
A-9-3
A-9-6
10 -TRANSMISSION LINES -DEVIL CANYON STAGE II (**)••••A-1O-1
11 -PROJECT STRUCTURES -WATANA STAGE III (***)• • • •
A-11-1
11.1 -General Arrangement (***)····· ···A-11-1
11.2 -Dam Embankment (***)··.· · · · ·
· ···A-11-3
11.3 -Diversion (***)· ···.· · ···A-11-5
11.4 -Emergency Release Facilities (***)· · ···A-11-6
851014 ii
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT A
PROJECT DESCRIPTION
Title Page No.
11.S -Outlet Facilities (***)A-1l-6
11.6 -Spillway (***).· · · · · ·· ·
·A-11-7
11.7 -Power Intake (***)· · · · · · · · ·· · ·
A-1l-8
11.8 -Power Tunnel and Penstocks (***)· · · ··.A-ll-ll
11.9 -Powerhouse (***)····A-ll-ll
11.10 -Trailrace (***)· · · · · ·
· ·
A-ll-13
11.11 -Access Plan (***)· · ·
A-1l-l3
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 (***)••••••••••••••
14.1 -Miscellaneous Mechanical Equipment (***)•
14.2 -Accessory Electrical Equipment (***)••••
·.
••
A-13-1
A-13-1
A-13-1
A-13-1
A-13-1
A-14-1
A-14-1
A-14-1
15 -TRANSMISSION FACILITIES -WATANA STAGE III (***). ..A-lS"'1
IS.1
IS.2
Transmission Requirements (***)•
switching and Substations (***)•
A-lS-l
A-lS-1
16 -LANDS OF THE UNITED STATES (**)..... . . . ...A-16-1
17 -REFERENCES
8S1014
.. . ...................
iii
A-17-1
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT B
PROJECT OPERATION AND RESOURCE UTILIZATION
Title
. 1 -DAMSITE SELECTION (***)... .. ....•••
Page No •
B-1-1
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 (***)
B-1-1
B-1-4
B-1-5
B-1-12
B-1-17
2 -ALTERNATIVE FACILITY DESIGN,PROCESSES AND
OPERATIONS (***)•••••••••••••• ••• ••B-2-1
2.6 -
2.7 -
2.8
2.1 -Susitna Hydroelectric Development (***)•••••
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
Arrangement (***)• • • • • • • • • • • •
Selection of Access Road Corridor (***)
Selection of Transmission Facilities (***).
Selection of Project Operation (***).•••••
B-2-1
B-2-1
B-2-22
B-2-48
B-2-60
B-2-67
B-2-83
B-2-131
3 -DESCRIPTION OF PROJECT OPERATION (***)• • • • • •e-•B-3-1
3.1 -Hydrology (***)•••••••••
3.2 -Reservoir Operation Modeling (***)••••
3.3 -Operational Flow Regime Selection (***)
B-3-1
B-3-6
B-3-20
4 -POWER AND ENERGY PRODUCTION (***)• • ••••• • • • •
B-4-1
4.1 -Plant and System Operation Requirements (***)
4.2 -Power and Energy Production (***).••
5 -STATEMENT OF POWER NEEDS AND UTILIZATION (***)..
B-4-1
B-4-10
B-5-1
5.1 -Introduction (***)•••••••••••••..•
5.2 -Description of the Railbelt Electric Systems (***)
5.3 -Forecasting Methodology (***)••
5.4 -Forecast of Electric Power Demand (***)
B-5-1
B-5-1
B-5-17
B-5-47
6 -FUTURE SUSITNA BASIN DEVELOPMENT (***)·.... ...B-6-1
7 -REFERENCES
851014
. . ......... . ..........
iv
B-7-1
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT B -APPENDIX HI
MAN-IN-THE-ARCTIC PROGRAM (MAP)
TECHNICAL DOCUMENTATION REPORT
STAGE MODEL (VERSION A85.1)
REGIONALIZATION MODEL (VERSION A84.CD)
SCENARIO GENERATOR
Title
Stage Model
1.Introduction ...· · · · · · · · · ·2.Economic Module Description · · · · ·3.Fiscal Module Description ·· · ·
I
4.Demographic Module Description · ·· ·
·5.Input Variables .· · · · · · ·
·6.Variable and Parameter Name Conventions
7.Parameter Values,Definitions and Sources · ·
··8.Model Validation and Properties ··9.Input Data Sources ···· ·
· · · · ·· ·
·10.Programs for Model Use ··· · ·
·· · ·
·11.Model Adjustments for Simulation ·· · ·
·12.Key'to Regressions ··· ·
· ·· · ·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
Printing Library Files •
4.Model Output • • • • • • • • • • •
1
1
8
14
22
851014 v
EXHIBIT B -APPENDIX B2
RAILBELT ELECTRICITY DEMAND (RED)MODEL
TECHNICAL DOCUMENTATION REPORT (1983 VERSION)
SUMMARY TABLE OF CONTENTS (cant'd)
Title
1 -INTRODUCTION • •
)
1
!
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I
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1
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I
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1.1
2.1
3.1
5.1
7.1
10.1
11.1
6.1
12.1
4.1
13.1
8.1
9.1
Page No.
...
. .
. . .
....
...
. . .
...
. ..
. ..
... .
. .. . . .
·.
· ..
·. .. .. ... ...
5 -THE RESIDENTIAL CONSUMPTION MODULE •
2 -OVERVIEW • •
3 -UNCERTAINTY MODULE •
10 -LARGE INDUSTRIAL DEMAND • •
11 -THE PEAK DEMAND MODULE
12 -MODEL VALIDATION
7 -PRICE ELASTICITY • • • • • • • • •
13 -MISCELLANEOUS TABLES
4 -THE HOUSING MODULE •
8 -THE PROGRAM-INDUCED CONSERVATION MODULE
6 -THE BUSINESS CONSUMPTION MODULE
9 -THE MISCELLANEOUS MODULE
851014 vi
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT B -APPENDIX B3
RAILBELT ELECTRICITY DEMAND (RED)MODEL
CHANGES MADE JULY 1983 TO AUGUST 1985
6 -EFFECT OF THE MODEL CHANGES ON THE FORECASTS •
2 -RED MODEL PRICE ADJUSTMENT REVISIONS
3 -RESIDENTIAL CONSUMPTION MODULE
Title
1 -INTRODUCTION
4 -BUSINESS SECTOR
5 -PEAK DEMAND
851014
. ..
vii
...
. . .. . . .
. .. .
Page No.
l.1
2.1
3.1
4.1
5.1
6.1
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT C
PROPOSED CONSTRUCTION SCHEDULE
Title Page No.
1 -WATANA STAGE I SCHEDULE (**)·..........C-1-1
C-1-2
C-1-2
C-1-2
C-1-2
C-1-3
C-1-3
C-1-3
C-1-3
C-1-3
· . .
· ..1.1 -Access (*)•••••••
1.2 -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 (**)••••• •·...C-2-1
2.1 -Access (**).· ·
·.·· · ·
·······2.2 -Site Facilities (**)···· · ··· ·· ·
·2.3 -Diversion (*)··· · ·
·2.4 -Arch Dam (**)··· ·
· · ···2.5 -Spillway and Intake (*)·· ···· ···2.6 -Powerhouse and Other Underground Works (0)
2.7 -Transmission Lines/Switchyards (*)·· ·
·2.8 -General (*).· ·
·· ··
3 -WATANA STAGE III SCHEDULE (***)• •·•• •• •·• • •
C-2-1
C-2-1
C-2-1
C-2-1
C-2-2
C-2-2
C-2-2
C-2-2
C-3-1
3.1 -Access (***)· ·· ·
··3.2 -Site Facilities (***)·· ····3.3 -Dam Embankment (***)·· · · ···3.4 -Spillway and Intakes (***)·· ···3.5 -Powerhouse and Other Underground Works (**)···3.6 -Relict Channel (***)··· ·· ·
·· ·
···3.7 -Transmission Lines/Switchyards (***)·· ··3.8 -General (***)·· ·
.··· ·· · · ··
4 -EXISTING TRANSMISSION SYSTEM (***)
851014 viii
·..·..••·..
C-3-1
C-3-1
C-3-1
C-3';'2
C-3-2
C-3-2
C-3-2
C-3-2
C-4-1 I
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SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT D
PROJECT COSTS AND FINANCING
Title
1 -ESTIMATES OF COST (**)............ . ...
Page No.
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-l-ll
D-1-12
D-1-12
D-l-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
1.996 (***)•.••••••••••
2.9 Selection of Expansion Plans (***)••••
2.10 -Economic Development (***)•
2.11 -Sen.si ti vi ty Analysis (***)
2.12 -Conclusions (***)••••••••
D-2-1
D-2-1
D-2-10
D-2-l0
D-2-l9
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'd)
EXHIBIT D
PROJECT COSTS AND FINANCING
Title
4.4 -Market Value of Power (***).
4.5 -Rate Stabilization (***)
4.6 -Sensitivity of Analyses (***)•
Page No.
D-4-4
D-4-4
D-4-4
5 -REFERENCES (***)
851014
• • • • • • • • • • • 0 • • • • • • •
x
D-5-1
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT D -APPENDIX Dl
FUELS PRICING
Title Page No.
• ••1 -INTRODUCTION (***)
2 -WORLD OIL PRICE (***)•. ..••......
Dl-1-1
DI-2-1
2.1 -The Sherman H.Clark Associates Forecast (***)
2.2 -The Composite Oil Price Forecast (***)
2.3 -The Wharton Forecast (***)
3 -NATURAL GAS (***).. . . . ....• ••..
DI-2-1
DI-2-2
DI-2-5
DI-3-1
3.1 -Cook Inlet Gas Prices (***)• .••.•.••
3.2 -Regulatory Constraints on the Availability of
Natural Gas (***)• • • • • • . • • • . • • •
3.3 -Physical Constraints on the Availability of
Cook Inlet Natural Gas Supply (***)• • . • • • •
3.4 -North Slope Natural Gas (***)•••••
Dl-3-1
Dl-3-10
Dl-3-12
Dl-3-20
4 -COAL (***)....... ...............Dl-4-l
4.1 -Resources and Reserves (***)•••
4.2 -Demand and Supply (***). . .. . • . •
4.3 -Present and Potential Alaska Coal Prices (***)
4.4 Alaska Coal Prices Summarized (***)..••
Dl-4-1
Dl-4-3
Dl-4-4
Dl-4-10
5 -DISTILLATE OIL (***)........ .........Dl-5-1
5.1 -Availability (***)•.•••••
5.2 -Distillate Price (***).•••
Dl-5-1
Dl-5-1
6 -REFERENCES
851014
. . . ..............
xi
Dl-6-1
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 1
GENERAL DESCRIPTION OF THE LOCALE
1.1 -General Setting (**)••••
1.2 -Susitna Basin (*)••••••••••. . . ...
Title
1 -GENERAL DESCRIPTION (*)• • •.. .......
...
• •
Page No.
E-1-1-1
E-1-1-1
E-1-1-2
2 -REFERENCES ............ ........E-1-2-1
3 -GLOSSARY
851014
.. . ....................
xii
E-1-3-1
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 2
WATER USE AND QUALITY
... .1 -INTRODUCTION (**)• • • • •
·......
E-2-1-1
Page No.
E-2-2-1
• •
........
......••
Title
2 -BASELINE DESCRIPTION (**)
E-2-2-3
E-2-2-12
E-2-2-19
E-2-2-46
E-2-2-49
E-2-2-50
E-2-2-63
E-2-2-64
E-2-3-1....
· ..
· .....
•••
2.1 -Susitna River Morphology (**)••••.
2.2 -Susitna River Water Quantity (**)
2.3 -Susitna River Water Quality (**).
2.4 -Baseline Ground Water Conditions (**)
2.5 -Existing Lakes,Reservoirs,and Stream~(**)
2.6 -ExistingOlnstream Flow Uses (0)•
2.7 -Access Plan (**).••••.•••
2.8 -Transmission Corridor (**).
3 -.OPERATIONAL FLOW REGIME SELECTION (***)•
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-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
4 -PROJECT IMPACT ON WATER QUALITY AND QUANTITY (**)•••E-2-4-1
4.1 -Watana Develo~ent (**)••••••
4.2 -Devil Canyon Development (**)•••
4.3 -Watana Stage III Development (***).
4.4 -Access Plan (**)••••••
· .
E-2-4-7
E-2-4-110
E";'2-4-160
E-2-4-211
5 -AGENCY CONCERNS AND RECOMMENDATIONS (**)·..... .
E-2-5-1
6 -MITIGATION,ENHANCEMENT,AND PROTECTIVE MEASURES (**)•E-2-6-1
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-2-6-5
851014 xiii
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 2
WATER USE AND QUALITY
Title
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 -Watana Stage III -
Impoundment/Construction (***)
6.10 -Mitigation -Stage III Operation (***)••
6.11 -Access Road and Transmission Lines (***)•
Page No.
E-2-6-7
E-2-6-13
E-2-6-13
E-2-6-13
E-2-6-15
E-2-6-16
E-2-6-16
E-2-6-18
7 -REFERENCES
8 -GLOSSARY
851014
•• •••••• • • ••• •• • •• ••••
• • • • • • • • • • • • • • • • • • • 0 • • •
xiv
E-2-7-1
E-2-8-1
SUMMARY TABLE OF CONTENTS (cont'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 (**)•E-3-2-1
2.1 -Overview of the Resources (**)••••.
2.2 -Species Biology and Habitat Utilization
in the Susitna River Drainage (*)•••..•••
2.3 -Anticipated Impacts To Aquatic Habitat (**)
2.4 -Mitigation Issues and Mitigating Measures (**)
2.5 -Aquatic Studies Program (*)• ••••••
2.6 -Monitoring Studies (**)•••.•••••
2.7 -Cost of Mitigation (***)••••••••
2.8 -Agency Consultation on Fisheries Mitigation
Measures (**)• • • • • . • •
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 (**)•••••••
.. ... . . .
E-3-3-1
E-3-3-6
E-3-3-34
E-3-3-63
. .. . .. . . .
.. . . . . .
.,.. . . . .4.1 -Introduction (*)
4.2 -Baseline Description (**)
4.3 -Impacts (*)••
4.4 -Mitigation Plan (**)
E-3-4-1
E-3-5-1
E-3-4-1
E-3-4-3
E-3-4-110
E-3-4-248
• ••••
.......
...• •
....• •
• • •• •• •
(**)••••
5 -AIR QUALITY/METEOROLOGY (***)
4 -WILDLIFE
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 (cont'd)
EXHIBIT E -CHAPTER 3
FISH,WILDLIFE,AND BOTANICAL RESOURCES
Title
5.5 -Regulatory Agency Consultations (***)•
Page No.
E-3-5-3
6 -REFERENCE •. ......... ............E-3-6-1
7 -GLOSSARY
APPENDICES
E1.3
E2.3
... ............. .......
FISH AND WILDLIFE MITIGATION POLICY
ENVIRONMENTAL GUIDELINES MEMORANDUM
(THIS APPENDIX HAS BEEN DELETED)
E-3-7-1
E3.3
E4.3
E5.3
E6.3
E7.3
E8.3
E9.3
ElO.3
E1L3
851014,'
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
INFORMATION INCORPORATED INTO APPENDIX E3.3.)
STATUS,HABITAT USE AND RELATIVE ABUNDANCE OF BIRD
SPECIES IN THE MIDDLE SUSITNA BASIN
STATUS AND RELATIVE ABUNDANCE OF BIRD SPECIES
OBSERVED ON THE LOWER SUSITNA BASIN DURING GROUND
SURVEYS CONDUCTED JUNE 10 THE JUNE 20,1982
SCIENTIFIC NAMES OF MAMMAL SPECIES FOUND IN THE
PROJECT AREA
METHODS USED TO DETERMINE MOOSE BROWSE UTILIZATION
AND CARRYING CAPACITY WITHIN THE MIDDLE SUSITNA BASIN
EXPLANATION AND JUSTIFICATION OF ARTIFICIAL NEST
MITIGATION (THIS SECTION HAS BEEN DELETED)
PERSONAL COMMUNICATIONS (THIS SECTION HAS BEEN
DELETED)
EXISTING AIR QUALITY AND METEOROLOGICAL CONDITIONS
XV1
I
I
I
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 4
HISTORIC AND ARCHEOLOGICAL RESOURCES
Title
1 -INTRODUCTION AND SUMMARY (**)• •.... . ..••..
Page No.
E-4-1-1
1.1 -Program Objectives (**)••.•••
1.2 -Program Specifics (**)••••
2 -BASELINE DESCRIPTION (**)• •. .......•••• •
E-4-1-4
E-4-1-4
E-4-2-1
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 (**)•••••••
E-4-2-l
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 (**)••••••• • •••• •
E-4-3-1
3.1 -Evaluation of Selected Sites Found:
Prehistory and History of the Middle
Susitna Region (**). • • • . • • • • • • • •••E-4-3-1
3.2 -Impact on Historic and Archeological Sites (**).E-4-3-4
4 -MITIGATION OF IMPACT ON HISTORIC AND
ARCHEOLOGICAL SITES(**)• • • • • • •• •
.......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-4-5-1
6 -REFERENCES ......................E-4-6-1
7 -GLOSSARY
851014
.......................
xvii
E-4-7-1
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 5
SOCIOECONOMIC IMPACTS
Title
1 -INTRODUCTION (**)• • • • •
....• •••
E-5-1-1
Page No.
E-S-2-1••••
.....• ••....••
BASELINE DESCRIPTION (**)•2
2.1 -Identification of Socioeconomic
Impact Areas (**)• • • • • . • • • • • • • • • •E-5-2-l
2.2 -Description of Employment,Population,Personal
Income and Other Trends in the Impact Areas (**)E-S-2-1
3 -EVALUATION OF THE IMPACT OF THE PROJECT (**).....E-S-3-1
3.1 -Impact of In-migration of People on Governmental
Facilities 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 (***)•••.
3.S -Displacement and Influences on Residences and
Businesses (**)• • • • • • . • • • • • •
3.6 -Fiscal Impact Analysis:Evaluation of
Incremental Local Government Expenditures
and Revenues (**)• • • • • • •
3.7 -Local and Regional Impacts on
Resource User Groups (**)•
E-S-3-2
E-S-3-32
E-S-3-3S
E-S-3-39
E-S-3-49
E-S-3-59
E-S-3-6S
E-S-4-2
E-S-4-1
E-"S-4-1
E-S-4-1
E-S-4-2
• • • •
. .
• •••••
..
••• •e·•••
4.1 -Introduction (**)
4.2 -Background and Approach (**)•••••
4.3 -Attitudes Toward Changes
(This section deleted)
4.4 -Mitigation Objectives and Measures (**)
4 -MITIGATION (**)• •
8S1014 xviii
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 5
SOCIOECONOMIC IMPACTS
Title
5 -MITIGATION MEASURES RECOMMENDED BY AGENCIES(**). . ..
Page No.
E-5-5-1
5.1 -Alaska Department of Natural Resources (DNR)(**)
5.2 -Alaska Department of Fish and Game (ADF&G)(*)
5.3 -u.s.Fish and Wildlife Service (FWS)(*).•..
5.4 -Summary of Agencies'Suggestions for Further
Studies that Relate to Mitigation (**)
E-5-5-l
E-5-5-1
E-5-5-2
E-5-5-2
6 -REFERENCES
851014
.............. . .......
xix
E-6-6-1
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 6
GEOLOGICAL AND SOIL RESOURCES
Title
1 -INTRODUCTION (**)
Page No.
E-6-1-1
2 -BASELINE DESCRIPTION (*)·.· .
·.....·.••o •E-6-2-1
2.1 -Regional Geology (*)
2.2 -Quarternary Geology (*)•..
2.3 -Mineral Resources (0)•
2.4 -Seismic Geology (*)••.•••
2.5 -Watana Damsite (**)••••••
2.6 -Devil Canyon Damsite (0)••••
2.7 -Reservoir Geology (*)...•
· ..
· . . ..· . .· ..
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
3 -IMPACTS (*)• •......••• •••• • • • ••••E-6-3-1
· ..3.1 -Reservoir-Induced Seismicity (RIS)(*)
3.2 -Seepage (*)•••••••..•••
3.3 -Reservoir Slope Failures (**)••
3.4 -Permafrost Thaw (*)...•.••
3.5 -Seismically-Induced Failure (*)••
3.6 -Reservoir Freeboard for Wind Waves (**)•••
3.7 -Development of Borrow Sites and Quarries (**)
E-6-3-1
E-6-3-4
E-6-3-4
E-6-3-11
E-6-3-11
E-6-3-11
E-6-3-12
4 -MITIGATION (**)•·.....•••••• • •·.·..E-6-4-1
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 -Reservoir Slope Failures (**)··· ····E-6-4-2
4.5 -Permafrost 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
5 -REFERENCES
6 -GLOSSARY
851014
• ••
••• •
••••
•• ••
·....
••• • •
xx
·.........
•• • ••• ••• •
E-6-5-1
E-6-6-1
I
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SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 7
RECREATIONAL RESOURCES
Title
1 -INTRODUCTION (**)• •...• ••..... ....·.
Page No.
E-7-1-1
1.1 -Purpose (**)•••••
1.2 -Relationships to Other Reports (*)
1.3 -Study Approach and Methodology (**)
1.4 -Project Descri ption (**)••••••
2 -DESCRIPTION OF EXISTING AND FUTURE RECREATION
WITHOUT THE SUSITNA PROJECT (**)•••••••
2.1 -Statewide and Regional Setting (**)
2.2 -Susitna River Basin (**)••••••
..·.
E-7-I-1
E-7-1-1
E-7-I-1
E-7-1-3
E-7-2-1
E-7-2-I
E-7-2-8
3 -PROJECT IMPACTS ON EXISTING RECREATION (**)•• • • • •
E-7-3-1
3.1 -Direct Impacts of Project Features (**)
3.2 -Project Recreational Demand Assessment •••
(Moved to Appendix E4.7)
E-7-3-1
E-7-3-I2
4 -FACTORS INFLUENCING THE RECREATION PLAN (**)•••••E-7-4-I
4.1 -Characteristics of the Project Design and
Operation (***)• • • • • • • • • • • • • .
4.2 -Characteristics of the Study Area (***)••.••
4.3 -Recreation Use Patterns and Demand (***)•••.
4.4 -Agency,Lando~ner 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 (**)•• • •••• ••• •••••• •
E-7-5-1
5.1 -Recreation Plan Management Concept (***)>••
5.2 -Recreation Plan Guidelines (***)
5.3 -Recreational Opportunity Evaluation •••••
(Moved to Appendix E3.7.3)
5.4 -The Recreation Plan (**)
E-7-5-1
E-7-5-2
E-7-5-4
E-7-5-4
6 -PLAN IMPLEMENTATION (**)
851014
..... . ... ......
xxi
E-7-6-1
SUMMARY TABLE OF CONTENTS (cont'd)
7 -COSTS FOR CONSTRUCTION AND OPERATION OF THE PROPOSED
RECREATION FACILITIES (**)• • • • • • • • • •
PROJECT RECREATIONAL DEMAND ASSESSMENT
Title
!
r
I
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[
I
I
I
l
I
I
I
I
I
I
I
I
I
Page No.
E-7-7-1
E-7-6-1
E-7-6-1
E-7-6-2
E-7-6-3
E-7-8-1
E-7-9-1
E-7-10-1
E-7-8-1
E-7-8-1
E-7-8-1
E-7-8~2
E-7-7-1
E-7-7-1
E-7-7-2
• •
. . . .
• • • • •••• • •• ••••
..................
••• •• • •• • • •• ••••• •••• •
RECREATION SITE INVENTORY AND OPPORTUNITY EVALUATION
ATTRACTIVE FEATURES -INVENTORY DATA
DATA ON REGIONAL RECREATION FACILITIES
PHOTOGRAPHS OF SITES WITHIN THE PROJECT RECREATION
STUDY AREA
EXAMPLES OF TYPICAL RECREATION FACILITY DESIGN
STANDARDS FOR THE SUSITNA PROJECT
....
EXHIBIT E -CHAPTER 7
RECREATIONAL RESOURCES
6.1 -Phasing (**)..••••..••
6.2 -Detailed Recreation Design (***)
6.3 -Operation and Maintenance (***)
6.4 -Monitoring (**)•••••.•••
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 -Consultation Meetings (***).•.•••
8 -AGENCY COORDINATION (**)
9 -REFERENCES
E2.7
El.7
10 -GLOSSARY •
E6.7
APPENDICES
E5.7
E3.7
E4.7
851014 xxii
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 8
AESTHETIC RESOURCES
......... .......
Title
1 -INTRODUCTION (**)•
1.1 -Purpose (*).•••••••.
1.2 -Relationship to Other Analyses (*)
1.3 -Environmental Setting (**)••••
. .. .
·. .
Page No.
E-8-1-1
E-8-1-1
E-8-1-1
E-8-1-1
...... ......... .
.................
4 -PROJECT FACILITIES (*)
2 -PROCEDURE (*)• • • •
3 -STUDY OBJECTIVES (*)
• ••• •
...••..•• • ••E-8-2-1
E-8-3-1
E-8-4-1
·. . ..4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
-Watana Project Area (*)• • •
-Devil Canyon Project Area (*)•••
-Watana Stage III Project Area (***)• .
-Denali Highway to Watana Dam Access Road (*)
-Watana Dam to Devil Canyon Dam Access Road (*)
-Transmission Lines (*)
Intertie . . . . • . . . . . . . • .
(This section deleted)
-Recreation Facilities and Features (*)
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
......................
.. ..
6 -VIEWS (**)
6.1 -Viewers (***)
6.2 -Visibility (***)
7 -AESTHETIC EVALUATION RATINGS (**)•• ••..·....
E-8-6-1
E-8-6-1
E-8-6-1
E-8-7-1
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
8 -AESTHETIC IMPACTS (**)••• • • • • • • • • • 0 • • •
Page No.
E-8-8-1
8.1 -Mitigation Planning of Incompatible
Aesthetic Impacts (Now addressed in Section 9)
8.2 -Watana Stage I (***)••••
8.3 -Devil Canyon Stage II (***)•••.••••
8.4 •Watana Stage III (***)•••..••••.
8.5 -Access Routes (***)• •••••••
8.6 -Transmission Facilities (***)•••~••
E-8-8-1
E-8-8-2
E-8-8-3
E-8-8-4
E-8-8-5
E-8-8-6
·............9 -MITIGATION (**)• • • • • • •
9.1 -Mitigation Feasibility (**)
9.2 -Mitigation Plan (***)••••
9.3 -Mitigation Costs (**)••••
9.4 -Mitigation Monitoring (***)
.... . ... .
....
E-8-9-1
E-8-9-1
E-8-9-2
E-8-9-11
E-8-9-12
•••• •
10 -AESTHETIC IMPACT EVALUATION OF THE INTERTIE
(This Section Delected)
11 -AGENCY COORDINATION (**)•..............
E-8-10-1
E-8:"'1l-1
11.1 -Agencies and Persons Consulted (**).
11.2 -Agency Comments (**)• •••••
E-8-11-1
E-8-11-1
12 -REFERENCES •• ••• ••• • • •••...•• • •• •
E-8-12-.1
13 -GLOSSARY
APPENDICES
• •• •• ••• • •
• 0 • • • • • • • • •• •
E-8-13-1
El.8
E2.8
E3.8
E4.8
851014
EXCEPTIONAL NATURAL FEATURES
SITE PHOTOS WITH SIMULATIONS OF PROJECT FACILITIES
PHOTOS OF PROPOSED PROJECT FACILITIES SITES
EXAMPLES OF EXISTING AESTHETIC IMPACTS
xxiv
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 8
AESTHETIC RESOURCES
Title
APPENDICES (cont'd)
Page No.
E5.S
E6.S
E7.S
ES.S
E9.S
851014
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 PROJECT
LANDSCAPE CHARACTER TYPES OF THE PROJECT AREA
AESTHETIC VALUE AND ABSORPTION CAPABILITY RATINGS
xxv
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 9
LAND USE
Title
1 -INTRODUCTION (***)• • • • • • • • • • •
2 -HISTORICAL AND PRESENT LAND USE (***)
2.1 -Historical Land Use (***)
2.2 -Present Land Use (***)
.......
.. .
Page No.
E-9-1-1
E-9-2-1
E-9-2-1
E-9-2-1
3 -LAND MANAGEMENT PLANNING IN THE PROJECT
AREA (***)• • • • • • • •.'.• • • • •••••• • •
E-9-3-1
4 -IMPACTS ON LAND USE WITH AND WITHOUT THE
PROJECT (***)••••••••••••••••••..E-9-4-1
5 -MITIGATION (***)•••••••• ••• ••• • ••
6 -REFERENCES
851014
. ...••••••• ••
xxvi
...• 0 • •••
E-9-5-1
E-9-6-1
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 10
ALTERNATIVE LOCATIONS,DESIGNS,AND ENERGY SOURCES
Title
1 -ALTERNATIVE HYDROELECTRIC SITES (*)• • • • • • • •
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 (***)••
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-I0-3-1
Page No.
E-I0-1-32
E-10-1-1
E-I0-1-2
E-10-2-1
E-10-1-17
E-I0-l-l
E-I0-3-1
E-I0-3-2
E-I0-2-1
E-I0-2-3
E-I0-2-4
E-I0-2-24
E-I0-2-53
E-I0-4-1
E-10-3-6
E-I0-3-17
E-I0-3-38
E-1O-3-43
E-I0-3-53
E-lO-4-1
E-lO-4-27
E-lO-4-39
E-lO-4-41
E-lO-4-42
E-10-4-42
..
(0)• •
••
. . .
.....
...
•• ••••• • • ••
-Non-Susitna Hydroelectric Alternatives (*)
Assessment of Selected Alternative
Hydroelectric Sites (***)• • • • • • • • • •
-Middle Susitna Basin Hydroelectric
Alternatives (0)••••••••
Overall Comparison of Non-Susitna
Hydroelectric Alternatives to the
Proposed Susitna Project (***)
1.3
1.1
1.2
1.4
2.1 -Watana Facility Design Alternatives (*)•
2.2 -Devil Canyon Facility Design Alternatives
2.3 -Access Alternatives (0)•••••••••
2.4 -Transmission Alternatives (0)••
2.5 -Borrow Site Alternatives (**)
3 -OPERATIONAL FLOW REGIME SELECTION (***)•
2 -ALTERNATIVE FACILITY DESIGNS (*)
4 -ALTERNATIVE ELECTRICAL ENERGY SOURCES (***)•
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851014 xxvii
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 10
ALTERNATIVE LOCATIONS,DESIGNS,AND ENERGY SOURCES
Title Page No.
4.7 -Wind Conversion Alternatives (***)
4.8 -Solar Energy Alternatives (***)•0
4.9 -Conservation Alternatives (***)••
5 -ENVIRONMENTAL CONSEQUENCES OF LICENSE DENIAL (***)..
E-lO-4-43
E-IO-4-44
E-lO-4-44
E-lO-5-l
6 -REFERENCES . . ........... .........E-lO-6-1
7 -GLOSSARY
851014
.....................
xxviii
E-lO-7-l
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT E -CHAPTER 11
AGENCY CONSULTATION
2.1 -Technical Workshops (***)••
2.2 -Ongoing Consultation (***)•••••
2.3 -Further Comments and Consultation (***)
. ........
Title
1 -ACTIVITIES PRIOR TO FILING THE INITIAL
APPLICATION (1980-February 1983)(***)
Page No.
E-ll-l-1
E-1l-2-1
E-1l-2-1
E-1l-2-1
E-1l-2-2
..••. .....2 -ADDITIONAL FORMAL AGENCY AND PUBLIC
CONSULTATION (***)• • • • • • • • •
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851014 xx~x
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT F
SUPPORTING DESIGN REPORT (PRELIMINARY)
2.-PROJECT DESIGN DATA (**)..... ..........
Title
1 -PROJECT DATA (***)......• •·...·.·....
Page No.
F-1-1
F-2-1
2.1 -Topographical Data (0)·.•· ·
•····.F-2-1
2.2 -Hydrological Data (**)F-2-1
2.3 -Meteorological Data (*)·····F-2-1
2.4 Reservoir Data (0)· · ·· ···F-2-1
2.5 -Tailwater Elevations (0)·.F-2-1
2.6 -Design Floods (**)···.····F-2-2
3 -CIVIL DESIGN DATA (*)....·.·.·...·..·.F-3-1
·..........4 -GEOTECHNICAL DESIGN DATA (**)
3.1 -Governing Codes and
3.2 -Design Loads (**)•
3.3 -Stabi li ty (*)• • •
3.4 -Material Properties
Standards (0)
· .
(0)•
·..
· . .
F-3-1
F-3-1
F-3-6
F-3-9
F-4-1
4.1 -Watana (**)••••
4.2 Devil Canyon (**)
5 -HYDRAULIC DESIGN DATA (**)
· .. .
..............
F-4-1
F-4-10
F-5-1
5.1 -River Flows (**)••••••••
S.2 -Design Flows (**)•••••••••••
5.3 -Reservoir Levels (**)••••••••••••
5.4 -Reservoir Operating Rule (**)• • • •••
5.5 -Reservoir Data (**)•••••••••••••
5.6 -Wind Effect (**)•••
5.7 -Criteria (***)
F-5-l
F-5-1
F-5-l
F~5-2
F-5-2
F-5-3
F-5-3
6 -EQUIPMENT DESIGN CODES AND STANDARDS (**)•·..• • •
F-6-1
6.1 -Design Codes and Standards (*)
6.2 -General Criteria (*)•.•.•
·.. . . ....·. .
F-6-1
F-6-2
851014 xxx
SUMMARY TABLE OF CONTENTS (cont'd)
EXHIBIT F
SUPPORTING DESIGN REPORT (PRELIMINARY)
Title
6.3 -Diversion Structures and Emergency Release
Facilities (*)•.••
6.4 -Spillway (**)••
6.5 -Outlet Facilities (*).
6.6 -Power Intake (*)
6.7 -Powerhouse (**)•
6.8 -Tailrace Tunnels (**)••••••••
Page No.
F-6-4
F-6-6
F-6-6
F-6-8
F-6-9
F-6-12
7 -REFERENCES
APPENDICES
............. . ... . ..F-7-1
F1
F2
F3
851014
THIS APPENDIX DELETED
WATANA AND DEVIL CANYON EMBANKMENT STABILITY ANALYSES
SUMMARY AND PMF AND SPILLWAY DESIGN FLOOD ANALYSES
xxxi
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C -PROPOSED CONSTRUCTION SCHEDULE
D -PROJECT COSTS AND FINANCING
AND
D1 -FUELS PRICING
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C -PROPOSED CONSTRUCTION
SCHEDULE
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TABLE OF CONTENTS
SUSITNA HYDROELECTRIC PROJECT
LICENSE APPLICATION
EXHIBIT C
PROPOSED CONSTRUCTION SCHEDULE
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Title
1 -WATANA STAGE I SCHEDULE (**)
1.1 -Access (*)...
1.2 -Site Facilities (**)
1.3 -Diversion (**)
1.4 -Dam Embankment (**)
..... . ... .
Page No.
C-l-l
C-1-2
C-1-2
C-1-2
C-1-2
1.5 -Spillway and Intakes (**)
1.6 -Powerhouse and Other Underground Works (**)
C-1-3
C-1-3
1.7 -Relict Channel (**)..••....
1.8 -Transmission Lines/Switchyards (*)
1.9 -General (**)
2 -DEVIL CANYON STAGE II SCHEDULE (**)•
2.1 -Access (**)..
2.2 -Site Facilities (**)
2.3 -Diversion (*)
2.4 -Arch Dam (**)
2.5 -Spillway and Intake (*)
. . .
C-1-3
C-1-3
C-1-3
C-2-1
C-2-1
C-2-1
C-2-1
C-2-l
C-2-2
2.6 -Powerhouse and Other Underground Works (0)
2.7 -Transmission Lines/Switchyards (*)
2.8 -General (*).
C-2-2
C-2-2
C-2-2
851014 i
TABLE OF CONTENTS (cont'd)
3.5 -Powerhouse and Other Underground Works (**)
EXHIBIT C
PROPOSED CONSTRUCTION SCHEDULE
3.7 -Transmission Lines/Switchyards (***)
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C-3-1
C-3-1
C-3-l
C-3-1
C-3-2
C-3-2
C-3-2
C-3-2
C-3-2
C-4-1
Page No.
. ..
.. ......
..
3.1 -Access (***)
3.4 -Spillway and Intakes (***)
3.2 -Site Facilities (***)
3.3 -Dam Embankment (***)
3.6 -Relict Channel (***)
Title
3 -WATANA STAGE III SCHEDULE (***)•
3.8 -General (***).
4 -EXISTING TRANSMISSION SYSTEM (***)
851014 ii
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Number
C.1
C.2
C.3
851014
EXHIBIT C
PROPOSED CONSTRUCTION SCHEDULE
LIST OF FIGURES
Title
WATANA STAGE I CONSTRUCTION SCHEDULE
DEVIL CANYON STAGE II CONSTRUCTION SCHEDULE
WATANA STAGE III CONSTRUCTION SCHEDULE
1.1.1.
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EXHIBIT C
PROPOSED CONSTRUCTION SCHEDULE
This section describes the construction schedules prepared for Watana
Stages I and III and Devil Canyon Stage II to meet the on-line power
requirements of 1999,2005 and 2012,respectively.Schedules for the
development of both Watana and Devil Canyon are shown on Figures C.l,
C.2,and C.3.The main elements of the project have been shown on
these schedules,as well as some key interrelationships.For purposes
of planning,it has been assumed that the FERC license will be awarded
by January 1,1990.
For all stages the period for construction of the dams and their
appurtenances is critical.A study of the front end requirements for
Watana Stage I concluded that initial construction access work would
have to commence as soon as possible and be completed in the shortest
possible time to permit accomplishment of support facilities to meet
field exploration requirements for design.
1 -WATANA STAGE I SCHEDULE (**)
Commencement of construction:
o Main access road
o Main site facilities
o Diversion
Completion of construction:
o Four units ready
-March 1990
-April 1990
-May 1994
-July 1999
Commencement of commercial operations:
o Four units -July 1999
The Watana Stage I schedule was developed to meet two overall project
constraints:
o FERC license would be issued by January 1,1990;and
o Four units would be on-line by July 1,1999.
The critical path of activities to meet the overall constraints was
determined to be through site access,site facilities,geotechnical
programs,diversion and main dam construction.In general,construc-
tion activities leading up to diversion in 1994 are on a normal
schedule whereas the remaining activities are on an accelerated
schedule.
851014 C-l-l
1.1 -Access (*)
Initial road access to the site is required by October 1987.Certain
equipment will be transported overland during the preceding winter
months so that an airfield can be constructed during the summer of
1990.This effort to complete initial access is required to mobilize
labor,equipment,and materials for the field explorations and the
orderly construction of site facilities and diversion works.
1.2 -Site Facilities (**)
Site facilities must be developed in a very short time to support the
main construction activities.A camp to house approximately 750
workers must be constructed during the first twelve months.Site
construction roads and contractors'work areas have to be started.An
aggregate processing plant and concrete batching plant must be
operational to start diversion tunnel concrete work by October 1993.
Construction transmission lines must be completed by 1991 to supply
power for camp and construction activities.
1.3 -Diversion (**)
Construction of diversion facilities,the first major activity,should
start in the spring of 1992 after completion of access roads to the
portal areas.Excavation of the portals and tunnels requires a
concentrated effort to allow completion of the tunnels for river
diversion by May 1994.The upstream diversion dike must be placed to
divert river flows in May 1994.The cofferdams are scheduled for
completion before December 1994 to avoid overtopping during the
following spring.
1.4 -Dam Embankment (**)
The progress of work on the dam is critical throughout the period 1995
through 1998.Mobilization of equipment and start of site work must
begin in 1994.Excavation of the right abutment as well as river
alluvium under the dam core begins after diversion and installation of
the cofferdams in 1994.During 1995 and 1996,dewatering,excavation
and foundation treatment must be completed in the riverbed area and a
substantial start made on placing fill.The construction schedule is
based on the following program:
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Year
1994
1995
1996
1997
1998
851014
Fill
Elevation
October 15
(feet)
1,506
1,725
1,835
2,025
C-I-2
Reservoir
Elevation
(feet)
1,920
The program for fill placing has been based on an average six-month
season.It has been developed based on high utilization of
construction equipment which is required to handle and process the
necessary fill materials.
1.5 -Spillway and Intakes (**)
These structures have been scheduled for completion in consonance with
embankment construction to meet the requirement to handle flows.In
general,excavation for the spillway is on the critical path and must
begin so that excavated rock can be placed in the dam embankment as
soon as it is excavated.
1.6 -Powerhouse and Other Underground Works (**)
The four units are scheduled to be on line by 1999.Excavation for the
access tunnel into the powerhouse complex has been scheduled to start
in late 1994.Concrete begins late in 1996 with start of installation
of major mechanical and electrical work in 1997.In general,the
underground works have been scheduled to level resource demands as much
as possible.
1.7 -Relict Channel (**)
Construction of underground seepage remedial measures (downstream adit
toe drain)will be installed during 1998 and 1999 if impoundment
reservoir level effects indicate the need.
1.8 -Transmission Lines/Switchyards (*)
Construction of the main transmission lines and switchyards has been
scheduled to begin in 1995 and to be completed before commissioning of
the first unit.
1.9 -General (**)
The Watana schedule for Stage I requires that extensive planning and
commitments for exploration programs be made during 1986 to permit this
type work to progress on schedule during 1987 and 1988.
851014 C-1-3
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2 -DEVIL CANYON STAGE II SCHEDULE (**)
Commencement of construction:
o Main Access -April 1995
o Site Facilities -June 1996
o River Diversion -May 1999
Completion of construction:
o Four units -October 2005
Commencement of commercial operations:
o Four units -October 2005
The Devil Canyon schedule was developed to meet the on-line power re-
quirement of all four units in 2005.The critical path of activities
was determined to follow through site facilities,diversion and main
dam construction.
2.1 -Access (**)
It has been assumed that site access built to Watana will exist at the
start of construction.A road will be constructed connecting the Devil
Canyon site to the Watana access road including a high level bridge
over the Susitna River downstream of the Devil Canyon Dam.At the same
time,a railroad spur will be constructed to permit railroad access to
the south bank of the Susitna near Devil Canyon.These activities will
be completed by mid-1997.
2.2 -Site Facilities (**)
Camp facilities should be started in 1996.Site roads and power
transmission work could also be started at this time.
2.3 -Diversion (*)
Excavation and concreting of the single diversion tunnel should begin
in 1994.River diversion and cofferdam construction will take place to
permit start of dam construction in 1999.
2.4 -Arch Dam (**)
The construction of the arch dam will be the most critical construction
activity from start of excavation in 1999 until topping out in 2004.
The concrete program has been based on an average eight-month placing
season for 4-1/2 years.The work has been scheduled so that a fairly
constant work effort may be maintained during this period to make best
use of equipment and manpower.
851014 C-2-l
2.5 -Spillway and Intake (*)
The spillway and intake are scheduled for completion by the end of 2003
to permit reservoir filling the next year.
2.6 -Powerhouse and Other Underground Works (0)
Excavation of access into the powerhouse cavern is scheduled to begin
in 2000.Concrete begins in 2001 with start of installation of major
mechanical and electrical work in 2003.
2.7 -Transmission Lines/Switchyards (*)
The additional transmission facilities needed for Devil Canyon have
been scheduled for completion by the time the first unit.is ready for
commissioning in 2004.
2.a -General (*)
The development of site facilities at Devil Canyon begins gradually in
1996 with a rapid acceleration in 1997 through 1999.Within a short
period of time,construction will begin on the major structures.This
rapid development is dependent on the provision of support site
facilities which should be completed in advance of the main
construction work.
851014 C-2-2
3 -WATANA STAGE III SCHEDULE (***)
Commencement of construction:
o Access road
o Site facilities
o Dam construction
Completion of construction:
o Two units
-Provided in Stage I
-Provided in Stage I
-June 2006
-October 2012
Commencement of commercial operations:
o Six units
3.1 -Access (***)
-October 2012
Access during Stage III construction will be provided by facilities
constructed and utilized during Stages I and II.
3.2 -Site Facilities (***)
Site facilities developed to support the main construction activities
for Stage I will be utilized during Stage III.
3.3 -Dam Embankment (***)
The progress of work on the dam is critical throughout the period 2006
through 2011.Mobilization of equipment and start of site work must
begin early in 2006.
ISl (
I Year
2007
2008
2009
2010
2011
2012
Fill
Elevation
October 15
(feet)
1,550
1,850
2,000
2,100
2,210
Reservoir
Elevation
(feet)
2,065
The program for fill placement has been based on an average six-month
season.It has been based on high utilization of construction
equipment which is required to handle and process the necessary fill
materials.
851014 C-3-l
3.4 -Spillway and Intakes (***)
These Stage III structures have been scheduled to begin construction 1n
2008 and continue in consonance with embankment construction to meet
the requirement to handle flows.Construction of the spillway ogee
concrete work will be accomplished during the years 2010 and 2011.The
gates will be reinstalled in the latter part of year 2011 and early
2012.
3.5 -Powerhouse and Other Underground Works (***)
All six units are scheduled to be on line by 2012.Concrete placement
begins in the spring of 2008 with start of installation of major
mechanical and electrical work in 2009.
3.6 -Relict Channel (***)
Construction of underground seepage remedial measures (cutoff wall)
will be installed during 2011 and 2012 if impoundment reservoir level
effects indicate the need.
3.7 -Transmission Lines/Switchyards (***)
Construction of the transmission lines and switchyards for use in Stage
III will begin in 2009 and be complete in 2011.
3.8 -General (***)
The Watana schedule requires that extensive engineering investigations
be made during 2003 to permit this geotechnical work to progress on
schedule from 2004 through 2005.
851014 C-3-2
FIGURES
---.._-----~
DESCRIPTION 1997 1998 1999
01 01
02 INITIAL ACCESS (1987)02
03 03
04 MAIN ACCESS 04
05 05
06 MAIN SITE FACILITIES 06
07 07
08 DIVERSION TUNNELS 08
09 09
10 COFFERDAMS 10
11 :~25 18.1 5 2~25 11
12 DAM EMBANKMENT ,.J ....,""""~:-."""",'12
13 13
14 RELICT CHANNEL 11111111111111111111111 111111111111111 14
15 15
16 SPILLWAY EXCAV.11111111 1111111111111111111111111111111 111111111111111111111111111111111 16
17 17
18 SPILLWAY CONCRETE 18
19 19
20 OUTLET FACILITIES ',1111111 '111111111111111 .,.,.,20
21 21.
22 POWER INTAKE 11111111 .,,.,.,.22
23 23
24 POWER TUNNELS ;111111111111 •••.,.,24
25 25
26 POWERHOUSE 26
27 27
28 TRANSFORMER GALLARY/CABLE SHAFTS 1111111111111 11111111111111 28,
29 29
30 TAILRACE/SURGE CHAMBER 30
31 31
32 TURBINE/GENERATORS .,.,.,.,."'.'.'.'.'M'.'.'.32
33 33
34 MECH.lELECT.SYSTEMS .,.,.,.,.,.......,.,.,.,.,.,34
35 35
36 SWITCHYARD/CONTROL BLDG..,.,.,.,.,.,..,.,.,.,.,.,.36
37 37
38 TRANSMISSION LINES .,..,.,.,.,.,.,..,.,.,.,.,.,.38
39 "'....*''''c.."'.....c..vvv 39
40 IMPOUNDMENT --_.....----40
41 UNITS l li,oN LIN E 41
42 TEST AND COMMISSION ;,•...-.,•••,••111 42
43 43
44
LEGEND
r",,~ACCESS/FACILITIES
11111111'"111111 EXCAVA TION/FOUNDA TION TREATMENT
.""",FILL-CONCRETE.,.,.,.,MECHANICAL/ELECTRICAL---IMPOUNDMENT
FIGURE C.1
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DESCRIPTION 1995 I 2004 2005 2006
01 01
02 MAIN ACCESS ~~......................~""02
03 03
04 SITE FACILITIES 04
05
PLUG 05
06 DIVERSION TUNNELS ,
I 06
07 :07
08 COFFERDAMS :08
09 :09
10 MAIN DAM -10
11 :11
12 SADDLE DAM I"~:12
13 I 13
14 OUTLET FACILITIES 14
15 15
I
1616SPILLWAYIll'."I
17 I 17
18 :18
19 I 19
20 POWER INTAKE '11'11'.20
21 21
22 POWER TUNNELS 11 22
23 I 23
24 POWERHOUSE 24
25 :25
26 TRANSFORMER GALLERY/CABLE SHAFTS :11'11'11'11'11 26
27 I 27
28 TAILRACE/SURGE CHAMBER i-28
29 29
30 TURBINES/GENERATORS '111111'.1I111'1I'1I'1I'1I1.~.I.J '.II1I.I.~30
31 :I 31
32 MECH.lELECT.SYSTEMS 18'.'..'.'''.'11'.'.'.'.'1 ,.,11,.,.,1 32
33
STRUCTURES/E QUIPMENT 33
34 SWITCHY ARD/CONTROL BLDG.-I~'.'.'.'.'~I 34
I
3535
I
36 TRANSMISSION LINES -1':".'11'.'.'I 36
37 1 EL.1455 37
38 IMPOUNDMENT 1.____11----11--38
39 UNITS .1-.1 ,,2 ,3 ...4 ON-LINE 39
40 TEST &COMMISSION "'8'.,.,.T.,.,II,.,.1 40
41 41
42 '42
43 43
44 44
LEGENDr._ACCESS/FACILITIES
11111111111111111 EXCAVATION/FOUNDATION TREATMENT
................,..........,FILL
CONCRETE...,.,..MECHANICAL/ELECTRICAL---IMPOUNDMENT
FIGURE·C.2
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DESCRIPTION 2012 2013 2014
01 MOBILIZATION 01
02 02
03 SITE ROADS 03
04 04
05 05
I
06 SITE FACILITIES 06
07 07
08 DOWNSTREAM COFFERDAM 08
09 09
10 DAM EMBANKMENT FOUNDATION )10-11 \J 11\J
12 DAM EMBANKMENT r 12
13 13
14 RELICT CHANNEL HIIIIIIII II 1II111 II II 11111111 1111I 1'1 14
15 15
16 SPILLWAY 16,-17 17
18 GATES (REMOVAL)!18
19 I 19
20 GATES (INSTALLATION):'~51 •••••••20
21 I 21
22 POWER INTAKE I 22
23 ~.23
24 POWER TUNNELS 24
25 25
26 POWERHOUSE 26
27 27
28 TRANSFORMER GALLARY/CABLE SHAFTS 28
29 29
30 TAILRACE/SURGE CHAMBER 30
31 31
32 TURBINE/GENERATORS 32
33 33
34 MECH.lELECT.SYSTEMS 34
35 35
36 36
37 37
38 TRANSMISSION LINES 38
39 c ...·roo 39
40 IMPOUNDMENT --__.;T___
40
<
41 UNITS 1.~ON LINE 41
42 TEST AND COMMISSION ,I_~.~J,42
43 43
44 44
LEGEND...._.ACCESS/FACILITIES
11I1I1I1I1I1II1II EXCAVA TION/FOUNDATION TREATMENT
.""",FILL-CONCRETE
.1 •.•.•.MECHANICALIELECTRICA L---IMPOUNDMENT
I
FIGURE C.3
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D -PROJECT COSTS AND FINANCING
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SUSITNA HYDROELECTRIC PROJECT
LICENSE APPLICATION
EXHIBIT D
PROJECT COSTS AND FINANCING
TABLE OF CONTENTS
)i
Title
1 -ESTIMATES OF COST (**)
1.1 -Construction Costs (**)
. . ..
Page No.
D-1-1
0-1-1
1.1.1 -Code of Accounts (**)
1.1.2 -Approach to Cost Estimating (0)
1.1.3 -Cost Oata (*).
1.1.4 -Seasonal Influences on Productivity (**).
1.1.5 -Construction Methods (*).
1.1.6 -Quantity Takeoffs (**).
1.1.7 -Indirect Construction Costs (*).
1.2 -Mitigation Costs (**)....
1.3 -Engineering and Administration Costs (*)
0-1-1
0-1-3
0-1-3
D-1-4
0-1-5
0-1-5
0-1-5
0-1-6
0-1-7
1.3.1 -Engineering and Project
Costs (*). . . . . . .
1.3.2 -Construction Management
1.3.3 -Procurement Costs (*)
1.3.4 -Owner's Costs (*)...
Management
Costs (*)
0-1-8
0-1-9
0-1-9
0-1-10
1.4 -Operation,Maintenance and Replacement Costs (**)
1.5 -Allowance for Funds Used During
Construction (AFOC)(**)
1.5.1 -AFDC for Economic Analysis (*)
1.5.2 -AFDC for Financial Analysis (***)
1.6 -Escalation (**)
1.7 -Cash Flow (**)
1.8 -Contingency (*)
1.9 -Previously Constructe~Project Facilities (*)
0-1-10
0-1-11
0-1-11
0-1-12
0-1-12
0-1-12
0-1-13
0-1-13
851102 i
EXHIBIT D
PROJECT COSTS AND FINANCING
TABLE OF CONTENTS (cont'd)
Title
2 -EVALUATION OF ALTERNATIVE EXPANSION PLANS (***)•
2.1 -General (***)
2.2 -Hydroelectric Alternatives (***)
Page No.
D-2-1
D-2-1
D-2-1
2.2.1 -
2.2.2 -
Susitna Basin Hydroelectric
Developments (***).
(a)Selection Process (***)
(b)Selected Sites (***). . . . . . . .
(c)Three-Stage Susitna Development
Plan (***). . . . . . . . . . . . .
Non-Susitna Basin Hydroelectric
Developments (***)
D-2-2
D-2-2
D-2-2
D-2-3
D-2-3
2.3 -Thermal Alternatives (***)
2.4 -Natural Gas-Fired Options (***)
2.4.1 -Natural Gas Availability and Price (***).
2.4.2 -Simple Cycle Combustion Turbine
Power Plant (***). . . . . .
(a)Plant Description (***)
(b)Combustion Turbine and
Auxiliaries (***)..•......
(c)Plant Auxiliary Loads (***)
(d)Plant Operating Parameters (***). .
(e)Environmental Assessment (***).
(f)Capital Costs (***).
(g)Operation and Maintenance Costs (***)
(h)Heat Rate (***).
(i)Fuel Costs (***).
2.4.3 -Combined Cycle Combustion Turbine
Power Plant (***). . . .
(a)Plant Description (***)•......
(b)Combustion Turbine (***).~.
(c)Heat Recovery Steam Generator (***).
(d)Steam Turbine Generator (***)
(e)Plant Auxiliary Load (***).....
(f)Plant Operating Parameters (***)..
D-2-4
D-2-5
D-2-5
D-2-6
D-2-6
D-2-6
D-2-7
D-2-7
D-2-8
D-2-8
D-2-8
D-2-9
D-2-9
D-2-10
D-2-10
D-2-10
D-2-11
D-2-11
D-2-11
D-2-l2
851102 1.1.
EXHIBIT D
PROJECT COSTS AND FINANCING
TABLE OF CONTENTS (cont'd)
Title
(g)Environmental Assessment (***). . .
(h)Capital Costs (***).
(i)Operation and Maintenance Costs (***)
(j)Heat Rates (***).
(k)Fuel Costs (***)
2.5 -Coal-Fired Options (***)
2.5.1 -Coal Availability and Price (***)
2.5.2 -Coal-Fired Powerplants (***).
(a)Plant Description (***).
(b)Steam Generator (***).
(c)Turbine-Generator Operating
Parameters (***). . . . . . . .
(d)Plant Auxiliary Loads (***)
(e)Plant Operating Parameters (***)
(f)Environmental Assessment (***).
(g)Capit~l Costs (***).•....
(h)Operation and Maintenance Costs (***)
(i)Heat Rate (***)
(j)Fuel Costs (***).
2.6 -The Existing Railbelt System (***)
2.6.1 -System Description (***).
(a)Anchorage-Cook Inlet Area (***)
(b)Fairbanks-Tanana Valley Area (***).
2.6.2 -Total Present System (***)
2.7 -Generation Expansion Before 1996 (***)
2.8 -Formulation of Expansion Plans Beginning in
1996 (***)..... . . .
Page No.
D-2-12
D-2-12
D-2-13
D-2-13
D-2-14
D-2-14
D-2-14
D-2-15
D-2-15
D-2-16
D-2-16
0-2-16
0-2-17
0-2-17
D-2-17
0-2-18
D-2-19
0-2-19
0-2-19
0-2-19
D-2-20
0-2-21
D-2-21
0-2-22
D-2-23
851102
2.8.1
2.8.2
2.8.3
2.8.4
2.8.5
2.8.6
2.8.7
2.8.8
-Methodology (***)....
-Load Forecast (***). . . . . .
-Reliability Evaluation (***)
-Hydro Scheduling (***)....
-Thermal Unit Commitment (***)
-OGP Optimization Procedure (***)
-Generation Expansion (***)
-Transmission System Expansion (***)
111
...
0-2-23
0-2-24
0-2-24
0-2-25
0-2-26
D-2-26
0-2-26
D-2-27
EXHIBIT D
PROJECT COSTS AND FINANCING
TABLE OF CONTENTS (cont'd)
Title Page No.
2.9 Selection of Expansion Plans (***)
2.9.1 -With-Susitna Expansion Plan (***)
2.9.2 -Without-Susitna Expansion Plan (***)
(a)System Expanison Plans (***). .
(b)Transmission System Expansion (***).
2.9.3 -Comparison of Expansion Plans (***).
D-2-27
D-2-28
D-2-29
D-2-29
D-2-30
0-2-32
2.11.1
2.11.2
2.11.3
2.10 -Economic Feasibility (***)..
2.10.1 -Economic Principals and Parameters (***)
(a)Economic Principles (***)
(b)Real Discount Rate (***). . .
2.10.2 -Analysis of Net Economic Benefits (***).
2.11 -Sensitivity Analysis (***)...
-World Oil Price Forecast (***)
-Discount Rate (***)
Construction Cost for Watana
Stage I (***).
2.11.4 -Real Escalation of Coal Price (***)
2.11.5 -Natural Gas Availability for Baseload
Generation (***). . . . . . . .
2.11.6 -Combined Sensitivity Case (***)
0-2-33
D-2-33
D-2-33
0-2-34
D-2-37
0-2-38
0-2-38
D-2-39
D-2-39
0-2-39
0-2-39
D-2-40
2.12 -Conclusions (***)
3 -CONSEQUENCES OF LICENSE DENIAL (***)
3.1 -Statement and Evaluation of the
Consequences of License Denial (***)
3.2 -Future Use of the Damsites if
the License is Denied (***)
.. .. ..
0-2-40
0-3-1
D-3-1
D-3-l
4 -FINANCING (***)•... ..D-4-1
4.1 -General Approach and Procedures (***)
4.2 -Financing Plan (***).
4.2.1 -Tax-exempt Revenue Bonds (***)
4.2.2 -Direct Billing (***).....
D-4-l
D-4-1
D-4-1
D-4-2
851102 iv
EXHIBIT D
PROJECT COSTS AND FINANCING
TABLE OF CONTENTS (cont'd)
Title
4.2.3 -Legislative Status of Alaska
Power Authority and Susitna
Project (***)....
Page No.
D-4-2
4.3 -Annual Costs (***)
4.4 -Market'Va1ue of Power (***)
4.5 -Rate Stabilization (***)
4.6 -Sensitivity Analyses (***)
....
D-4-3
D-4-4
D-4-4
D-4-4
5 -REFERENCES (***)
851102
.. .. .... .
v
D-5-1
Number
0.1.1.1
0.1.1.2
0.1.1.3
0.1.1.4
0.1.2.1
0.1.4.1
0.1.7.1
0.2.2.1
0.2.3.1
0.2.4.1
0.2.4.2
0.2.4.3
0.2.4.4
0.2.4.5
0.2.4.6
0.2.4.7
851102
EXHIBIT 0
PROJECT COSTS AND FINANCING
LIST OF TABLES
Title
SUMMARY OF SUSITNA COST ESTIMATE
COST ESTIMATE SUMMARY -WATANA STAGE I
COST ESTIMATE SUMMARY -WATANA STAGE III
COST ESTIMATE SUMMARY -DEVIL CANYON STAGE II
SUMMARY OF MITIGATION COSTS INCORPORATED IN
CONSTRUCTION COST ESTIMATES
SUSITNA HYDROELECTRIC PROJECT -ANNUAL OPERATION,
MAINTENANCE AND REPLACEMENT COSTS
CUMULATIVE AND ANNUAL CASH FLOW -SUSITNA STAGES I,
II,AND III
SUSITNA POWER AND ENERGY PRODUCTION
SUSITNA HYDROELECTRIC PROJECT THERMAL ALTERNATIVES
DATA SUMMARY
NATURAL GAS FUEL PRICES (1985$)
CAPITAL COST ESTIMATE SIMPLE CYCLE COMBUSTION TURBINE,
INITIAL UNIT (thousand 1985 $)
CAPITAL COST ESTIMATE SIMPLE CYCLE COMBUSTION TURBINE,
EXTENSION UNIT (thousand 1985 $)
CAPITAL COST SUMMARY,SIMPLE CYCLE COMBUSTION TURBINE
POWER PLANT THREE UNITS (thousand 1985 $)
SUMMARY OF'O&M COSTS,262 MW SIMPLE CYCLE COMBUSTION
TURBINE POWER PLANT (1985 $)
CAPITAL COST ESTIMATE,COMBINED CYCLE POWER PLANT
(thousand 1985 $)
CAPITAL COST SUMMARY,COMBINED CYCLE POWER PLANT
(thousand 1985 $)
Vl
Number
D.2.4.8
D.2.5.1
0.2.5.2
D.2.5.3
D.2.5.4
D.2.5.5
D.2.5.6
D.2.5.7
D.2.5.8
D.2.6.1
D.2.6.2
D.2.6.3
D.2.6.4
D.2.6.5
D.2.6.6
851102
EXHIBIT D
PROJECT COSTS-AND FINANCING
LIST OF TABLES (cont'd)
Title
SUMMARY OF O&M COSTS 230 MW COMBINED CYCLE POWER
PLANT (1985 $)
NENANA AND BELUGA COAL FUEL PRICES (1985 $)
CAPITAL COST ESTIMATE,BELUGA 200 MW COAL-FIRED PLANT,
INITIAL UNIT (thousand 1985 $)
CAPITAL COST ESTIMATE,BELUGA 200 MW COAL-FIRED POWER
PLANT,EXTENSION UNIT (thousand 1985 $)
CAPITAL COST SUMMARY,BELUGA COAL-FIRED POWER PLANT,
TWO UNITS (thousand 1985 $)
CAPITAL COST ESTIMATE,NENANA 200 MW COAL-FIRED POWER
PLANT,INITIAL UNIT (thousand 1985 $)
CAPITAL COST ESTIMATE,NENANA 200 MW COAL-FIRED POWER
PLANT,EXTENSION UNIT (thousand 1985 $)
CAPITAL COST SUMMARY,NENANA COAL-FIRED POWER PLANT,
TWO UNITS (thousand 1985 $)
COAL-FIRED POWER PLANT,SUMMARY OF O&M COSTS (1985 $)
INSTALLED CAPACITY OF ANCHORAGE-COOK INLET AREA -DEC.
1984 (in megawatts)
INSTALLED CAPACITY OF THE FAIRBANKS-TANANA VALLEY AREA
-DEC.1984 (in megawatts)
EXISTING AND PLANNED RAILBELT HYDROELECTRIC
GENERATION
ANCHORAGE -COOK INLET AREA EXISTING PLANT DATA -DEC.
1984
FAIRBANKS -TANANA VALLEY AREA EXISTING PLANT DATA -
DEC.1984
RAILBELT EXISTING EQUIPMENT RETIREMENT SCHEDULE
V11
Number
0.2.7.1
0.2.7.2
0.2.8.1
0.2.8.2
0.2.8.3
0.2.9.1
0.2.9.2
0.2.9.3
0.2.9.4
D.2.9.5
0.2.10.1
D.2.10.2
D.2.10.3
D.2.10.4
D.2.1l.1
D.2.1l.2
D.2.1l.3
D.2.11.4
D.2.1l.5
851102
EXHIBIT 0
PROJECT COSTS AND FINANCING
LIST OF TABLES (cont'd)
Title
RAILBELT SYSTEM ADDITIONS AND RETIREMENTS 1984-1995
RAILBELT SYSTEM ADDITIONS 1984-1995 t PLANT DATA
SHCA LOAD FORECAST
COMPOSITE LOAD FORECAST
SUMMARY OF THERMAL GENERATING PLANT PARAMETERS
(1985$)
WITH-SUSITNA EXPANSION PLAN YEARLY MW ADDITIONS
SUSITNA DEPENDABLE CAPACITY AND ENERGY
WITHOUT-SUSITNA EXPANSION PLAN YEARLY MW ADDITIONS
TRANSMISSION SYSTEM EXPANSION t WITHOUT-SUSITNA
ALTERNATIVE t SHCA FORECAST
TRANSMISSION SYSTEM EXPANSION t WITHOUT-SUSITNA
ALTERNATIVE t COMPOSITE FORECAST
PRINCIPAL ECONOMIC PARAMETERS
EXAMPLE OF REAL INTEREST RATE CALCULATION
EX-POST REAL INTEREST RATES ON SELECTED TREASURY
ISSUES (1945-1984)
ECONOMIC ANALYSIS OF SUSITNA PROJECT
FORECASTS OF ELECTRIC 'POWER DEMAND NET AT PLfu~T
WHARTON FORECAST SENSITIVITY ANALYSIS
DISCOUNT RATE SENSITIVITY ANALYSIS
WATANA CAPITAL COST SENSITIVITY ANALYSIS
REAL ESCALATION OF COAL PRICE SENSITIVITY ANALYSIS
viii
I
I
I
i
I
I
I
Number
0.2.11.6
0.2.11.7
0.4.1.1
0.4.2.1
0.4.2.2
0.4.3.1
0.4.4.1
0.4.5.1
851102
EXHIBIT 0
PROJECT COSTS AND FINANCING
LIST OF TABLES (cont'd)
Title
NATURAL GAS AVAILABILITY FOR BASELOAD GENERATION
COMBINED SENSITIVITY CASE
FINANCIAL PARAMETERS
CONSTRUCTION CASH FLOW SUSITNA HYDROELECTRIC PROJECT
(Millions of Dollars)
BOND ISSUE SUMMARY SUSITNA HYDROELECTRIC PROJECT
(Millions of Dollars)
SUSITNA HYDROELECTRIC PROJECT ANNUAL COSTS (Millions
of Dollars)
VALUE OF POWER (Millions of Dollars)
RATE STABILIZATION SUMMARY (Millions of Dollars)
1X
Number
0.2.2.1
0.2.2.2
0.2.9.1
0.2.9.2
0.2.9.3
0.2.9.4
0.2.9.5
0.2.9.6
0.4.5.1
851102
EXHIBIT D
PROJECT COSTS AND FINANCING
LIST OF FIGURES
Title
FORMULATION OF PLANS INCORPORATING NON-SUSITNA HYDRO
GENERATION
ALTERNATIVE HYDROELECTRIC PROJECTS LOCATION PLAN
WITHOUT-SUSITNA TRANSMISSION SYSTEM
WITHOUT-SUSITNA TRANSMISSION RELIABILITY STUDIES
WITH-SUSITNA ALTERNATIVE GENERATION SCENARIO,SHCA
LOAD FORECAST
WITHOUT-SUSITNA ALTERNATIVE GENERATION SCENARIO,SHCA
LOAD FORECAST
WITH-SUSITNA ALTERNATIVE GENERATION SCENARIO,
COMPOSITE LOAD FORECAST
WITHOUT-SUSITNA ALTERNATIVE GENERATION SCENARIO,
COMPOSITE LOAD FORECAST
COMPARISON OF NOMINAL COST OF ENERGY
x
!
I
!
I
!
I
1
I '
(
EXHIBIT D
PROJECT COSTS AND FINANCING
This exhibit presents the estimated project cost for the Susitna
Hydroelectric Project,development of alternative system generation
expansion plans and their evaluation to assess the economic feasibility
of the Susitna Project,and a financing plan for the project.
Alternative sources of power which were studied are also presented.
1 -ESTIMATES OF COST (**)
This section presents estimates of capital and operating costs for the
Susitna Hydroelectric Project,comprising the Watana Stages I and III
and Devil Canyon Stage II developments and associated transmission and
acce.ss facilities.The costs of design features and facilities
incorporated into the project to mitigate environmental impacts during
construction and operation are identified.Cash flow schedules,
outlining capital requirements during planning,construction,and start
up are presented.The approach to the derivation of the capital and
operating costs estimates is described.
The total cost of the Susitna project is summarized in Table D.l.l.l.
A more detailed breakdown of cost for each development is presented in
Tables D.l.l.2,D.l.l.3 and D.l.l.4.
1.1 -Construction Costs (**)
This section describes the process used for derivation of construction
costs and discusses the Code of Accounts established,the basis for the
estimates and the various assumptions made in arriving at the
estimates.For general consistency with planning studies,all
construction costs were developed for the project in January 1982
dollars and later adjusted to January 1985.
1.1.1 -Code of Accounts (**)
Estimates of construction costs were developed using the FERC
format as outlined in the Code of Federal Regulations,Title 18
(18 CFR).
The estimates have been subdivided into the following main cost
groupings:
Group
Production Plant
851102 D-l-l
Description
Costs for structures,
equipment,and facilities
necessary to produce power.
Transmission Plant
General Plant
Indirect Costs
Overhead Construction Costs
Costs for structures,
eq ui pment,and fac i Ii tie s
necessary to transmit power
from the sites to load
centers.
Costs for equipment and
facilities required for the
operation and maintenance of
the production and
transmission plant.
Costs that are common to a
number of construction
activities,such as camps,
catering and off-site
transportation of workers.
The estimate for camps
includes electric power costs.
Other indirect costs have been
included in the costs under
production,transmission,and
general plant costs.
Costs for engineering and
administration.
Further subdivision within these groupings was made on the basis
of the various types of work involved,as typically shown in the
following example:
0 Group:
0 Account 332:
0 Main Structure 332.3:
0 Element 332.31:
0 Work Item 332.311:
0 Type of Work:
Production Plant
Reservoir,Dam,and Waterways
Main Dam
Main Dam Structure
Excava tion
Rock
851102 D-1-2
1.1.2 -Approach to Cost Estimating (0)
The estimating process used generally included the following
steps:
o Collection and assembly of detailed cost data for labor,
material,and equipment as well as information on
productivity,climatic conditions,and other related
items;
o Review of engineering drawings and technical information
with regard to construction methodology and feasibility;
o Production of detailed quantity takeoffs from drawings in
accordance with the previously developed Code of Accounts
and item listing;
o Determination of direct unit costs for each major type of
work by development of labor,material,and equipment
requirements;development of other costs by use of
estimating guides,quotations from vendors,and other
information as appropriate;
o Development of construction indirect costs by review of
labor,material,equipment,supporting facilities,and
overheads;and
o Development of construction camp size and support
requirements from the labor demand generated by the
construction direct and indirect costs.
1.1.3 -Cost Data (*)
Cost information was obtained from standard estimating sources,
from sources in Alaska,from quotes by major equipment
suppliers and vendors,and from representative recent
hydroelectric projects.Labor and equipment costs were developed
from an analysis of costs for recent projects performed in the
Alaska environment.
It has been assumed that most contractors will work an average of
two 10-hour shifts per day,six days per week.During periods of
severe compression of construction activities,it has been
assumed that work will be on two 12-hour shifts,seven days per
week.
The 10-hour work shift assumption provides for high utilization
of construction equipment and reasonable levels of overtime
earnings to attract workers.The two-shift basis generally
851102 D-1-3
achieves the most economical balance between labor and camp
costs.Underground work has been assumed on a three-shift
operation.
Construction equipment costs were obtained from vendors on an FOB
Anchorage basis with an appropriate allowance included for
transportation to site.A representative list of construction
equipment required for the project was assembled as a basis for
the estimate.It has been assumed that most equipment would be
fully depreciated over the life of the project.Equipment
operating costs were estimated from industry source data,with
appropriate modifications for the remote nature and extreme
climatic environment of the site and duration of the project.
Alaskan labor rates were used for equipment maintenance and
repair.Fuel and oil prices have been based upon FOB site
prices.
Information for permanent mechanical and electrical equipment was
obtained from vendors and manufacturers who provided guideline
costs on major power plant equipment.
The costs of materials required for site construction were
estimated on the basis of suppliers'quotations with allowances
for shipping to site.
1.1.4 -Seasonal Influences on Productivity (**)
A review of climatic conditions together with an analysis of
experience in Alaska and in northern Canada on large
construction projects was undertaken to determine the average
duration for various key activities.It has been projected that
most above-ground activities will either stop or be curtailed
during December and January,because of the extreme cold weather
and the associated lower productivity.For the main dam
construction activities,the following seasons have been used:
o Watana earth and rockfill dam -6-month season
o Devil Canyon arch dam -8-month season.
Other above-ground activities are assumed to extend up to 11
months depending on the type of work and the criticality of the
schedule.Underground activities are generally not affected by
climate and should continue throughout the year.
Studies by others (Roberts 1976)have indicated a 60 percent or
greater decrease in efficiency in construction operations under
adverse winter conditions.Therefore,it is expected that most
contractors would attempt to schedule outside work over a period
of between six to ten months.
851102 D-1-4
Studies performed as part of this work program indicate that the
general construction activity at the Susitna damsite during the
months of April through September would be comparable with that
in the northern sections of the western United States.Rainfall
in the general region of the site is moderate between mid-April
and mid-October,ranging from a low of 0.75 inches precipitation
in April to a high of 5.33 inches in August.Temperatures in
this period range from 33°F to 66°F for a twenty-year average.
In the five-month period from November through March,the
temperature ranges from gOF to 20°F,with snowfall of 10 inches
per month.
1.1.5 -Construction Methods (*)
The construction methods assumed for development of the estimate
and construction schedule are generally considered normal to
the industry,in line with the available level of technical
information.A conservative approach has been taken in those
areas where more detailed information will be developed during
subsequent investigation and engineering programs.For example,
normal drilling,blasting,and mucking methods have been assumed
for all underground excavation.Conventional equipment has also
been considered for major fill and concrete work.
1.1.6 -Quantity Takeoffs (**)
Detailed quantity takeoffs were produced from the engineering
drawings using methods normal to the industry.
1.1.7 -Indirect Construction Costs (*)
Indirect construction costs were estimated in detail for the
civil construction activities.A more general evaluation was
used for the mechanical and electrical work.
Indirect costs included the following:
o Mobilization;
o Technical and supervisory personnel above the level of
trades foremen;
o All vehicle costs for supervisory personnel;
o Fixed offices,mobile offices,workshops,storage
facilities,and laydown areas,including all services;
o General transportation for workmen on site;
o Yard cranes and floats;
851102 D-1-5
o Utilities including electrical power,heat,water,and
compressed air;
o Small tools;
o Safety program and equipment;
o Contractor financing;
o Bonds and securities;
o Insurance;
o Taxes;
o Permits;
o Head office overhead;and
o Profit.
In developing contractor's indirect costs,the following
assumptions have been made:
o Mobilization costs have generally been spread over
construction items.
o No escalation allowances have been made,and therefore any
risks associated with escalation are not included.These
have been addressed in both the economic and financial
studies.
o Project all-risk insurance has been estimated as a
contractor's indirect cost for this estimate,but it 1S
expected that this insurance would be carried by the
owner.
o Contract packaging would provide for the supply of major
materials to contractors at site at cost.These include
fuel,electric power,cement,and reinforcing steel.
1.2 -Mitigation Costs (**)
The project arrangement includes a number of features designed to
mitigate potential impacts on the natural environment and on
residents and communities in the vicinity of the project.In addition,
a number of measures"are planned during the construction of the project
to reduce similar impacts caused by construction activities.These
measures and facilities represent additional costs to the project than
would otherwise be required for safe and efficient operation of a
851102 D-I-6
hydroelectric development.These m1t1gation costs have been estimated
at $303.5 million and have been summarized in Table D.1.2.1.These
costs include direct and indirect costs,engineering,administration,
and contingencies.
A number of mitigation costs are associated with facilities,
improvements or other programs not directly related to the project or
located outside the project boundaries.These would include the
following items:
o Raptor nesting platforms;
o Salt licks;
o Habitat management for moose;and
o Slough enhancement.
A detailed discussion of the mitigation programs required for the
project is included in Exhibit E along with tables listing detailed
costs.The costs of these programs including contingency have been
estimated as follows and listed under project indirects in the
capital cost estimate.
Stage I Watana
Stage II Devil Canyon
Stage III Watana
$187.8
35.4
80.3
million (approximately)
million (approximately)
million (approximately)
A number of studies and programs will be required to monitor the
impacts of the project on the environment and to develop and record
various data during project construction and operation.These
include:
o Archeological studies;
o Fisheries and wildlife studies;
o Right-of-way studies;and
o Socioeconomic planning studies.
The costs for the above work have been included under project overheads
and have been estimated at approximately $20 million.
1.3 -Engineering and Administration Costs (*)
Engineering has been subdivided into the following accounts for the
purposes of the cost estimates:
o Account 71
•Engineering and Project Management
851102 D-1-7
•Construction Management
•Procurement
o Account 76
Owner's Costs
The total cost of engineering and administrative activities has been
estimated at 12.5 percent of the total construction costs,including
contingencies.A detailed breakdown of these costs is dependent on the
organizational structure established to undertake design and management
of the project,as well as more definitive data relating to the scope
and nature of the various project components.However,the main
elements of cost included are discussed in the following sections.
1.3.1 -Engineering and Project Management Costs (*)
These costs include allowances for:
o Feasibility studies,including preliminary designs,site
surveys,investigations and logistics support;
o Preparation of the license application to the FERC;
o Technical and administrative input for other federal,state
and local permit and license applications;
o Overall coordination and administration of engineering,
construction management,and procurement activities;
o Overall planning,coordination,and monitoring activities
related to cost and schedule of the project;
o Coordination with and reporting to the Applicant regarding
all aspects of the project;
o Preliminary and detailed design;
o Plans and specifications for construction;
o Technical input to procurement of construction services,
support services,and equipment;
o Monitoring of construction to ensure conformance to design
req uirements;
o Preparation of start up and acceptance test procedures;
and
o Preparation of project operating and maintenance manuals.)-
,851102 D-I-8
1.3.2 -Construction Management Costs (*)
Construction management costs have been assumed to include:
o Establishment of project procedures and organization;
o Coordination of on-site contractors and construction
management activities;
o Administration of on-site contractors to ensure harmony of
trades,compliance with applicable regulations,and
maintenance of adequate site security and safety
requirements;
o Coordination and monitoring of construction schedules;
o Construction cost control;
o Material,equipment and drawing control;
o Inspection of construction and survey control;
o Measurement for payment;
o Start up and acceptance tests for equipment and systems;
o Compilation of as-constructed records;and
o Final acceptance.
1.3.3 -Procurement Costs (*)
Procurement costs have been assumed to include:
o Establishment of project procurement procedures;
o Preparation of non-technical procurement documents;
o Solicitation and review of bids for construction services,
support services,permanent equipment,and other items
required to complete the project;
o Cost administration and control for procurement contracts;
and
o Quality assurance services during fabrication or
manufacture of equipment and other purchased items.
851102 D-1-9
1.3.4 ~Owner's Costs (*)
Owner's costs have been assumed to include the following:
o Administration and coordination of construction management
and engineering organizations;
o Coordination with other state,local,and federal agencies
and groups having jurisdiction or interest in the project;
o Coordination with interested public groups and
individuals;
o Reporting to legislature and the public on the progress of
the project;and
o Legal costs.
1.4 -Operation,Maintenance and Replacement Costs (**)
The estimated operation,maintenance,and replacement costs,at
January 1985 price level,account for the personnel,materials,and
facilities required to operate and maintain the dam and reservoir along
with the generating plant and associated transmission facilities.Also
included are costs to maintain structures and equipment in changing
project conditions to insure dam safety at all times.A detailed
breakdown of the operation,maintenance and replacement cost estimate
and staffing requirements is shown in Table D.1.4.l.The following
cost estimates cover the various periods of the project life:
o Watana Stage I,$11.5 million/year;
o Devil Canyon Stage II,$12.8 million/year;
o Watana Stage III,$12.8 million/year;and
o Mature project operation and maintenance cost,$11.5
million/year.
The operating plan provides powerhouse operators on duty at all times
at Watana Stage I for the initial period of trials and operation.This
level of attention provides adequate monitoring and supervision until
all aspects of the power facility operation are proven reliable.A
similar schedule would apply to the early years of operation at Devil
Canyon Stage II and Watana Stage III.The operation transition from
manual to computer control would be gradual and would depend upon the
satisfactory functioning of the communication system,computers at each
power plant,and training of the resident staff as emergency operators,
should communications be interrupted.In a similar fashion,the
maintenance needs in the new power plants will be greater initially to
correct malfunctions as they are discovered.
851102 D-1-10
Also included in the personnel shown in Table D.1.4.1 are staff
required for two visitor centers,one located at each damsite.A
resource management staff would be responsible for regulating use of
the project's public facilities and use of lands managed by the
project.This management of resources would include monitoring and
enforcement of regulations but also include providing information and
guidance for users.
An O&M staff would provide all necessary services for the operation and
maintenance of the dam.Also included are personnel to operate town
facilities and provide for essential health and safety needs of town
residents.The staff would also provide warehouse and SOme maintenance
personnel.
In addition to the personnel and equipment required to implement normal
operation and maintenance,there are specific allowances for a sinking
fund to provide for equipment machinery replacement,helicopter
operations,and for snow clearing and maintenance of the dam,reservoir
and access roads.Allowances have also been made for environmental
mitigation services as well as a contingency for unforeseen costs.
1.5 -Allowance for Funds Used During Construction (AFDC)(**)
AFDC can be a significant element of project cost given the lengthy
construction periods required for construction of the three stages of
the project.Provisions for AFDC at appropriate rates of interest are
made in the economic and financial analyses included in this Exhibit.
1.5.1 -AFDC for Economic Analysis (*)
Interest and escalation were calculated as a percent of the total
capital costs of the project at the start of construction.The
method used for calculating the effects of interest and
escalation during construction is documented in "A Method for
Estimating Escalation and Interest During Construction"(Phung
1978).
An S-shaped symmetric cash flow was adopted where:
851102
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1 -
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211"
B In
2
(l +J
1 +f =
where
1 +f co =Total cost upon commercial service expressed as a
multiplier of construction cost.
1 +Y
1 +x
x =effective interest rate
y =escalation rate
B =construction period
The value of the variables used in the AFDC computations are as
follows:
o the effective interest rate is equal to the discount rate,3.5
percent,and
o the escalation rate is zero percent.
The Watana Stage I,Devil Canyon Stage II,and Watana Stage III
construction periods were taken from Exhibit C as 8 years,9
years,and 6 years,respectively.
The resultant total project cost was then calculated for use in
the OGP-6 economic studies.
1.5.2 -AFDC for Financial Analysis (***)
For the financial analysis,interest and escalation were
calculated as a percent of annual capital expenditure.Details
of the calculation procedure are presented in Section 4 of this
Exhibit.
1.6 -Escalation (**)
All construction costs presented in this Exhibit are at January 1985
levels and consequently include no allowance for future cost
escalation.Thus,these costs would not be representative of actual
construction and procurement bid prices.This is because provision
must be made in such bids for continuing escalation of costs,and the
extent and variation of escalation which might take place over the
lengthy construction periods involved.Economic and financial
evaluations take full account of such escalation at appropriate rates
as discussed in Section 1.5.1 for the economic analyses and Section
1.5.2 for the financial analyses.
1.7 -Cash Flow (**)
The cash flow requirements for construction of the Susitna Hydroelectic
Project are an essential input to financial planning studies.The
basis for the cash flows are the construction cost estimates in January
1985 dollars and the construction schedules presented in Exhibit C.
851102 D-1-12
The cash flow estimates were computed on an annual basis and do not
include adjustments for advanced payments for mobilization or for
holdbacks on construction contracts.The results are presented in
Table D.l.7.1.
1.8 -Contingency (*)
Following prevailing norms such as those used by the CaE (1980),an
overall contingency allowance of approximately 15 percent of
construction costs has been included in the cost estimates.
Contingencies have been assessed for each account and range from 10 to
20 percent.The contingency is estimated to include cost increases
which may occur in the detailed engineering phase of the project after
more comprehensive site investigations and final designs have been
completed and after the requirements of various concerned agencies have
been satisfied.The contingency estimate also includes allowances for
inherent uncertainties in costs of labor,equipment and materials,and
for unforeseen conditions which may be encountered during construction.
Escalation in costs due to inflation is not included.No allowance has
been included for costs associated with significant delays in project
implementation.
1.9 -Previously Constructed Project Facilities (*)
An electrical inter tie between the major load centers of Fairbanks and
Anchorage has been constructed by the Applicant.The line connects
transmission systems at Willow in the south and Healy in the north.
The intertie has been built to the same standards as those proposed for
the Susitna Hydroelectric Project transmission lines.The line will be
energized initially at 138 kV and will operate at 345 kV after the
Watana Stage I is complete.
The cost for the completed intertie was $122 million.This cost 1S not
inc!uded in the Sus i tna proj ec t cos t es t ima tes •
851102 D-1-13
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2 -EVALUATION OF ALTERNATIVE EXPANSION PLANS (***)
2.1 -General (***)
The Applicant's studies indicate that electric demand growth over the
next 25 years coupled with the retirement of a considerable portion
of the existing generation system will require the addition of new
generating capacity.The Susitna hydroelectric project constitutes a
major potential contributor to that additional capacity.This Section
describes the development of system generation expansion plans and
their evaluation in order to assess the economic feasibility of the
Susitna Project.
The system expansion studies are performed using the Optimized
Generation Planning (OGP)computer program and result in system
expansion plans With and Without the Susitna Hydroelectric Project.
The costs of these two expansion plans are then compared to determine
the economic viability of the With~Susitna plan.
During the pre-license phase of Susitna project planning,two studies
proceeded in parallel which addressed alternatives to generating power
in the Alaska Railbelt.These studies are the Susitna Hydroelectric
Project Feasibility Study (Acres 1982),and the Railbelt Electric Power
Alternatives Study (Battelle 1982).Information from these earlier
studies was used to support analyses in this Exhibit.
In this Section,information required for generation planning 1S
presented for the hydroelectric (i.e.Susitna and Non-Susitna
hydroelectric)and thermal generation options.The analysis relies on
fuel prices for thermal alternatives,developed in Exhibit D,
Appendix Dl and forecasts of electrical demand generated from the
APR/MAP/RED model sequence discussed in Exhibit B,Chapter 5,
Section 4.
2.2 -Hydroelectric Alternatives (***)
Numerous studies of hydroelectric potential in Alaska have been
undertaken.These date back to 1947 and were performed by various
agencies including the then Federal Power Commission,the Corps of
Engineers,the U.S.Bureau of Reclamation,the U.S.Geological Survey,
and the State of Alaska.Significant identified hydroelectric
potential is located in the Railbelt region,including several sites in
the Susitna River Basin.
Drawing from the above studies,Acres American developed and evaluated
Susitna and Non-Susitna basin hydroelectric alternatives.This series
of studies was based on cost data and load forecasts prepared and
updated over the period 1979 through 1982.During this period several
study interactions were made to eliminate candidate hydroelectric
851102 D-2-l
alternatives and the resulting development plans are the most
attractive alternatives.
2.2.1 -Susitna Basin Hydroelectric Developments (***)
The analysis of alternative sites for Susitna basin hydroelectric
development is discussed in Exhibit B,Chapter 1.The plan
formulation and selection methodology outlined in Exhibit B,
Chapter 1 is summarized below.
(a)Selection Process (***)
Step I in the plan formulation and selection process was to
define the overall objective of selecting the optimum
expansion plan incorporating Susitna basin hydroelectric
developments.In Step 2 of the process,all feasible sites
were identified for inclusion in the subsequent screening
process.The screening process (Step 3)eliminated those
sites that did not meet the screening criteria and yielded
candidates which could be refined and included in the
formulation of Railbelt generation plans (Step 4).
(b)Selected Sites (***)
The results of the site screening process indicated that
further Susitna basin development planning should
incorporate a combination of several major dams and
powerhouses located at one or more of the following sites on
the Susitna River:
o Devil Canyon;
o High Devil Canyon;
o Watana;
o Susitna III;and
o Vee Canyon.
One-on-one comparisons of combinations of the above sites
identified plans with Watana/Devil Canyon and High Devil
Canyon/Vee as most economic.Further refinements to the
project layouts and costs of these plans and systemwide
generation expansion analyses resulted in selection of the
Watana/Devil Canyon plan.Subsequent studies by the
Applicant described in Exhibit B,Chapter 2,concluded that
there would be advantages derived from modifying the
Watana/Devil Canyon plan to provide for construction in
three stages.
851102 D-2-2
(c)Three-Stage Susitna Development Plan (***)
The three stage Susitna plan is as follows:first,construc-
tion and operation of a facility at the Watana site with a
dam crest at elevation 2025 feet;second,completion and
operation of the Devil Canyon facility with a darn crest
at elevation of 1463 feet;and third,further elevation of
the darn at the Watana facility to an elevation of 2205
feet.
The capital and operation,maintenance and replacement costs
for the three-stage Susitna Hydroelectric Project are
discussed in Section 1 -Estimates of Costs.Capital costs
are shown in Tables D.I.I.I through D.l.I.4.Operation,
maintenance,and replacement costs are shown in Table
D .1.4.1.
The operation of the three staged Susitna project is
designed to meet system energy demand requirements along
with minimum instream flow requirements.Project operation
details are provided in Exhibit B,Section 3,and a summary
follows.
Monthly estimates of project power and energy production are
based on monthly reservoir simulation performed with a
multiple reservoir operation model.The estimated energy
generated is first compared to the system energy demand and
if the energy produced is greater than that which the system
can absorb the energy production is reduced by decreasing
the discharge through the powerhouse.The resulting
powerhouse discharge is compared to the minimum monthly flow
requirements at Gold Creek to ensure that the project
releases adequate flows for environmental purposes (Flow
Regime E-VI).
The Watana -Stage I development initially operates on base
load to maintain nearly uniform discharge from the
powerplant.When Devil Canyon begins operation,Watana
operates on load-following while Devil Canyon operates on
base load.Watana-Stage III operation is essentially
identical to Watana-Stage I and Devil Canyon Stage II
operation.Table D.2.2.1 provides the power and energy
production of the three stage project based on this
operation plan.
2.2.2 -Non-Susitna Basin Hydroelectric Developments (***)
Selection of non-Susitna Basin hydroelectric plans involved a
step-wise application of progressively more stringent criteria
851102 D-2-3
that eliminated candidate sites based on unfavorable economic and
environmental characteristics.The details of this process are
presented in the Susitna Development Selection Report (Acres
1981).A flow diagram of this process is shown in Figure
D.2.2.l.Through this process,10 of an original 91 sites were
selected for detailed development and cost estimates.Of these,
three sites -Chakachamna,Snow and Keetna -were proposed by the
Applicant as the primary sites to be examined in alternative
scenarios,and compared to the optimum development on the Susitna
River.·In the Draft Environmental Impact Statement (DEIS)
prepared on the original License Application (FERC 1984),the
FERC Staff identified a combination of five specific
hydroelectric sites -Johnson site (210 MW)on the Tanana River,
Browne site (100 MW)on the Nenana River,Keetna site (100 MW)on
the Talkeetna River,Snow site (100 MW)near Kenai Lake,and the
Chakachamna site (300 MW)on Chakachamna Lake -to partially
fulfill the energy needs of the Railbelt.The five sites are
shown on Figure D.2.2.2.
For the purposes of this application,the five recommended sites
were re-examined in greater detail by the Applicant from
engineering,economic,and environmental perspectives.Results
of the evaluation are presented in Exhibit E,Chapter la,and in
"Alaska Power Authority Comments on the Federal Energy Regulatory
Commission Draft Environmental Impact Statement of May 1984",
Volume 4,Appendix II -Evaluation of Non-Susitna Hydroelectric
Al terna t i ve s (APA 1984).
The overall conclusion of the re-examination,is that,based on
the engineering,economic,and environmental characteristics of
the non-Susitna hydro alternatives,they are not viable options
and are unfavorable when compared to the proposed project.
2.3 -Thermal Alternatives (***)
A majority of the generating capability in the Railbelt is currently
thermal,principally natural gas-fired combustion turbines with some
coal-fired steam,oil-fired combustion turbine and diesel
installations.Several alternative technologies exist that could be
used to generate electricity for the Railbelt,either as substitutes
for,or as complements to the Susitna Project.In Sections 2.4 and
2.5,the results of the analyses undertaken to define the most
appropriate Without-Susitna generation plan for comparison with the
With-Susitna generation plan are presented.
The overall objective established was the selection of an optimum
Without-Susitna generation plan.Primary consideration was given to
gas and coal electric generating sources which are the most readily
developable alternatives in the Railbelt from the standpoint of
technical and economic feasibility.
851102 D-2-4
The broader perspectives of other alternative resources such as peat,
refuse,geothermal,wind and solar and the relevant environmental,
social,and other issues involved were addressed in the Railbelt
Alternatives Study (Battelle 1982).As a result of this study,these
unconventional resources were concluded to be infeasible for reasons of
reliability,economy,insufficient capacity,or technical inadequacy.
Using coal and gas as fuels,three types of units were selected for
evaluation by the OGP computer program.These units are the natural
gas fired options of simple cycle combustion turbines (SCCT)and
combined cycle combustion turbines (CCCT)and the coal-fired option of
a conventional steam-electric generating station (HE 1985).
Table 0.2.3.1 summarizes the capacity,generation,capital cost,
operation and maintenance cost,and heat rate data of the three
available alternatives.These are the data that are input to OGP.
Following is a description of each of the options.
2.4 -Natural Gas-Fired Options (***)
2.4.1 -Natural Gas Availablility and Price (***)
Both the availability and pricing of natural gas as fuel for
electric generation are addressed in detail in Appendix 01,
Chapter 3.A summary follows.
Estimates of Cook Inlet natural gas quant1t1es include 4.5
trillion cubic feet (TCF)of proven reserves and 3.4 TCF of
estimated undiscovered resources.Therefore,8 TCF of natural
gas are assumed available for all future uses of Cook Inlet
natural gas.Additionally,the North Slope contains at least 36
TCF of reserves.In the case of Cook Inlet natural gas,
infrastructure exists to move the gas to the Railbelt market,
however,no such infrastructure (e.g.,a pipeline)is in
place for North Slope gas.Consequently only Cook Inlet gas is
considered available for the purposes of this analysis.
Because only Cook Inlet gas can be planned on,there
are uncertainties regarding its long-term availability to fuel
baseload power generation.The Applicant's analyses of competing
demands throughout the planning period demonstrate a need for
more natural gas than exists in the field.For long-tern
planning purposeS it has been assumed that Cook Inlet gas
supplies will not be allowed to support baseload generation
expansion after 1999.Therefore,in the system analyses
gas-fired system additions after 1999 will be limited to 1,500
hours of operation.
The natural gas fuel prices developed in Appendix 01 are a
function of world oil price and the technique for price estima-
851102 D-2-5
tion isnetback methodology.Natural gas prices for the SHCA and
Composite oil price forecasts which also include utility delivery
charges are shown in Table D.2.4.l.
2.4.2 -Simple Cycle Combustion Turbine Power Plant (***)
In support of the Without-Susitna plan,a complete simple cycle
plant conceptual design and the appropriate engineering,
environmental,capital cost,and operating parameters were
developed.
(a)Plant Description (***)
The Simple Cycle Combustion Turbine (SCCT)plant will
consist of three large-frame,industrial-type gas-fired
combustion turbine generators rated by the manufacturer at a
nominal Isol/rating of 80 MW each.The gross plant
output will be 269 MW reflecting 3 units operating with
ambient temperatures corrected to 30°F and with water
injection (which increases output).The plant will have a
net operating range from 26 MW (30 percent load for a single
unit)to 262 MW (full load net at 30°F)which includes
correction for plant auxiliary loads.The plant will
require approximately a five-acre site.For purposes of
this Application,it was assumed that any such plants will
be located at existing,partially-developed sites.
The plant's major and auxiliary systems include the natural
gas fuel system,water injection system,lubrication system,
starting and cool down system,inlet and exhaust system,
waste control system,and fire protection system.
(b)Combustion Turbine and Auxiliaries (***)
Each combustion turbine is an axial flow,multistaged
compressor and power turbine on a common shaft directly
coupled to the electric generator.The unit can be started,
synchronized,and loaded in about one-half hour under normal
conditions.The fuel system will be capable of utilizing
natural gas,mixed gas,or liquid petroleum distillate for
fuel.
Each gas turbine generator is a packaged unit and as such
includes all auxiliary equipment.The package will include
1/ISO -International Standards Organization,standard conditions
of 59°F and atmospheric pressure at sea level.
851102 D-2-6
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I
(c)
the turbine and generator with exciter,complete controls,
turbine auxiliary equipment,switchgear,transformers and
motor control centers.
Plant Auxiliary Loads (***)
The SCCT plant ratings are net values assuming an overall
plant auxiliary load of 2.5 percent.The plant auxiliary
loads consist of the combustion turbine auxiliary
requirements and the plant loads.The combustion turbine
loads are approximately one percent of the gross SCCT output
and include the lube oil heaters and pumps,the cooling
fans,water injection pumps,enclosure heaters,and cooling
water pumps.The fixed plant load,estimated at 4,000 kW,
includes lighting,service water pumps,HVAC equipment,
water treatment pumps,and maintenance equipment.
The net output from the plant consisting of three SCCT
units,varies from 308 MW at -23°F to 227 MW at 71°F.The
plant has a design heat rate of 10,900 Btu/kWh based on the
plant design operating condition at an ambient temperature
of 30°F and the Lower Heating Value (LHV)of the natural
gas.This corresponds to a heat rate of 12,000 Btu/kWh
based on the Higher Heating Value (HHV)of the fuel.
(d)Plant Operating Parameters (***)
The performance of the 240 MW ISO rated SCCT plant is
affected by plant elevation and ambient air temperature.
Gas turbines are volumetric mass flow devices and cold,
dense air increases the mass flow through the machines,
which,with increased firing,increases the plant output and
reduces the heat rate.The SCCT operating parameters are
shown below.
SCCT PLANT OPERATING PARAMETERS
Fuel Consumption (Full Load)
Gross Generating Capacity (at 30°F)
Station Auxiliary Loads
Net Generation (Nominal Capacity)
Gross Station Heat Rate (Full Load)
Net Station Heat Rate (Full Load)
Net Station Heat Rate (30%Load)
3,135 X 10 6 Btu/hr
268,800 kW
6,700 kW
262,000 kW
11,700 Btu/kWh
12,000 Btu/kWh
18,000 Btu/kWh
851102
The plant operating parameters are based on the average
expected conditions of 30°F and approximately sea level
atmospheric pressure.The temperature variation together
with water injection increase output and account for the
plant capacity and efficiency variance from ISO rating.
D-2-7
(e)Environmental Assessment (***)
Construction and operation of natural gas fired combustion
turbines creates environmental concern in four areas.
These are Air Quality,Water Quality,Noise Pollution,and
Land Use Impacts.There concerns are addressed in detail in
Exhibit E,Chapter 10,Section 4.
(f)Capital Costs (***)
The capital cost for the complete,3 unit,SCCT plant is
based on two separate estimates for single SCCT units.
One estimate is for a new unit at an existing but not fully
developed site and the second estimate is for a new unit
add-on at a fully developed,existing site.The three unit
plant estimate consists of one unit corresponding to the
first estimate and two add-on units.
This plant configuration was selected as providing a
feasible base-load alternative to the 200 MW coal plant for
selection by OGP and for its flexibility in allowing the
addition of single SCCT units for satifying intermittent or
peak load requirements.
The estimates are based on a scope that includes facilities
and systems required for self sustaining units.The
estimates were prepared in 1983 dollars and escalated to
1985 dollars using Ebasco's Composite Index of Direct Cost
for Electric Generating Plants (escalation factor 1.0394).
The Composite Index is based on historical data and reflects
annual changes in cost of materials,equipment,and labor
rates.
Tables D.2.4.2 and D.2.4.3 present a summary of the detailed
estimates for the SCCT initial unit and extension unit.
Table D.2.4.4 presents the capital cost summary for the SCCT
plant consisting of three units including other related
plant costs.All costs are presented in 1985 dollars.
(g)Operation and Maintenance Costs (***)
Operation and Maintenance (O&M)costs were developed from
three sources:
1)Railbelt Utility Data;
2)Lower 48 States Utility Data;and
3)Independent Data.
851102 D-2-8
1-
Through utility contacts,data was accumulated for similar
operations and modified for the specific plant and site.
The independent data was developed from vendor equipment
information,operational parameters,data files,and
engineering judgment.
The O&M costs were segregated into two components,fixed,
and variable categories.The fixed costs are those which
are independent of the level of plant operation,provided
the plant is maintained in operational condition.Fixed
costs are measured in dollars per kilowatt ($/kW)based on
net plant capacity.Variable costs are those which occur
only if the plant generates electricity.They vary directly
with the amount of electricity produced and are measured in
dollars per megawatt-hour ($/MWh)based on annual plant
generation.A summary of the O&M costs are presented in
Table D.2.4.5.These costs include fixed costs and variable
costs and exclude fuel costs.
The O&M costs were developed in 1982 dollars and were
escalated to 1985 dollars using the GNP Implicit Price
Deflator (escalation factor 1.1046).All costs in Table
D.2.4.5 are in 1985 dollars.
(h)Heat Rate (***)
The net output at the three unit SCCT station is 262,100 kW
(262 MW nominal capacity)at full load.The corresponding
heat rate is 12,000 Btu/kWh,HHV.This is a direct meassure
of the amount of heat energy input to the combustor as
natural gas that is required to produce one kilowatt-hour of
electricity.The resulting net thermal efficiency is 28.5
percent.
As the operating load decreases,the SCCT efficiency
decreases and net station heat rate increases.At the low
load end of approximately 30 percent load a SCCT of the type
and size considered here will have a heat rate of approxi-
mately 18,000 Btu/kWh and an operating efficiency of
approximately 19 percent.
(i)Fuel Costs (***)
Estimated fuel costs for the combustion turbine are
calculated by the OGP program based on the delivered fuel
price,the annual energy generated and the station heat
rate.Fuel prices are addressed in Appendix Dl.
851102 D-2-9
2.4.3 -Combined Cycle Combustion Turbine Power Plant (***)
The second gas-fired thermal alternative conceptual design
developed for this analysis is a complete combined cycle plant.
Development included the necessary engineering,environmental,
capital cost,and operating parameters.
(a)Plant Description (***)
The Combined Cycle Combustion Turbine (CCCT)power plant
incorporates two large-frame industrial-type natural gas
fired simple cycle combustion turbine generator sets each
exhausting into a waste Heat Recovery Steam Generator (HRSG)
to generate high pressure steam for the steam turbine
generator set.The plant's major equipment consists of the
following:
o Two combustion turbine generators rated at 80 MW,ISO;
o Two heat recovery steam generators;
o One steam turbine generator rated at 59 MW;
o Air-cooled condenser;and
o Feedwater system.
The plant will have a gross output of approximately 237 MW.
The capacity in excess of the ISO based capacity of 219 MW
is due to increased efficiency of operation at the design
generating temperature of 30°F and to increased efficiency
realized due to injection of water into the two SCCT
combustors.The net station capacity after deducting
auxiliary loads is approximately 230 MW at full load and 69
MW at the minimum recommended load of approximately 30
percent.Alternatively,a single SCCT can be operated
independently down to 26 MW at 30 percent load.
The plant will require a five-acre site and will be located
at an existing,partially-developed site.
(b)Combustion Turbine (***)
The two natural gas-fired combustion turbines with attendant
equipment will be identical to those described for the SCCT
plant.The combustion turbine performance is slightly
dertated due to the increase in exhaust pressure associated
with the HRSG.
851102 0-2-10
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(c)Heat Recovery Steam Generator (***)
The heat recovery steam generators are considered part of
the steam plant but would be housed with the gas fired
combustion turbines in a common building.
Each heat recovery steam generator package will include the
following:
o Ductwork from combustion turbine to the steam
generator;
o Bypass damper and bypass stack;and
o Steam generator exhaust stack.
Each HRSG will generate 258,000 pounds of steam per hour at
900 psig and 955°F when supplied with 250°F feedwater and
2,417.000 pounds per hour of exhaust gas at 973°F.
The HRSGs are designed for continuous operation and include
an evaporative section,a superheat section,and an
economizer.All steam generator controls will be located in
a common area in the central control room.
(d)Steam Turbine Generator (***)
The steam generated by the HRSGs will be conveyed to a
single steam turbine generator set.The steam turbine
generator will be a tandem compound,multistage condensing
unit,with one extraction for feedwater heating,and will be
mounted on a pedestal with a top exhaust going to the
air-cooled condenser.The steam turbine generator set will
be furnished complete with lubricatlng oil and
electrohydraulic control system,gland seal system,and
cooling and sealing equipment.Other associated equipment
includes feedwater pumps,condensate pumps,vacuum pumps,
deaerator,instrument and service air compressors,motor
control centers,and control room.
(e)Plant Auxiliary Load (***)
TheCCCT plant has an assumed overall pla'nt auxiliary load
of approximately three percent of the plant rating.The
auxiliary loads fall into three categories:
o Combustion turbine auxiliary power and control;
o Steam cycle loads;and
o Plant loads.
851102 D-2-11
The combustion turbine auxiliary loads are approximately one
percent of the CCCT plant output.The steam cycle auxiliary
loads are estimated at four percent of the steam turbine
generator output and consist of boiler feed pumps,
condensate pumps,cooling tower fans,and water treatment
equipment.The balance of plant load is estimated at 3,300
kW including plant lighting,heating and cooling,air
compressors,and maintenance equipment.
(f)Plant Operating Parameters (***)
The CCCT plant performance is affected by site conditions
similar to the SCCT plant.At ambient temperatures below
design conditions,the CCCT plant output increases.Lower
ambient temperatures improve performance of the air-cooled
condenser,and increase mass flow through the combustion
turbines which in turn increases steam generation in the
HRSG,resulting in increased electric generation.The CCCT
plant operating parameters are given below.
Fuel Consumption (Full Load)
Gross Generating Capacity (at 30°F)
Station Auxiliary Loads
Net Generation (Nominal Capacity)
Gross Station Heat Rate (Full Load)
Net Station Heat Rate (Full Load)
Net Station Heat Rate (30%Load)
The plant operating parameters are based on average expected
site conditions of 30°F and approximately sea level
atmospheric pressure.
(g)Environmental Assessment (***)
Construction and operation of the combined cycle plant will
create four areas of environmental concern.There are Air
Quality,Water Quality,Noise Pollution,and Land Use
Impacts.There concerns are addressed in Exhibit E,Chapter
10,Section.4.
(h)Capital Costs (***)
The capital costs for the CCCT plant were based on a single
estimate for a three-unit combined cycle natural gas-fired
plant.
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851102 D-2-12
(0
The estimate was based on a scope that includes facilities
and systems required for a self-sustaining plant.The
estimate was prepared in 1983 dollars and escalated to 1985
dollars using Ebasco's Composite Index of Direct Cost for
Electric Generating Plants (Escalation factor of 1.0394).
The Composite Index is based on historical data and reflects
annual changes in cost of materials,equipment,and labor
rates.
Table 0.2.4.6 presents a summary of the detailed estimate
for the combined cycle power plant.Table 0.2.4.7 presents
the capital cost summary for the combined cycle power plant
including other related plant costs.All costs are in 1985
dollars.
operation and Maintenance Costs (***)
Operation and Maintenance (O&M)costs were developed from
three sources:
o Rainbelt Utility Data;
o Lower 48 States Utility Data;and
o Independent Data.
Through utility contacts,data was accumulated for similar
operations and modified for the specific plant and site.
The independent data was developed from vendor equipment
information,operational parameters,data files,and
engineering judgment.
The O&M costs were segregated into two components,fixed
costs and variable costs.A summary of the O&M costs are
presented in Table 0.2.4.8.These costs include variable
costs,and exclude fuel costs.
The O&M costs were developed in 1982 dollars and were
escalated to 1985 dollars using the GNP Implicit Price
Deflator (escalation factor 1.1046).All costs in Table
0.2.4.8 are in 1985 dollars.
(j)Heat Rates (***)
The combined cycle plant when operating at full load has a
net output of 229,700 kW (230 MW nominal capacity)and a
net station heat rate at 9,200 Btu/kWh.The resulting net
thermal efficiency is 37 percent.
851102 0-2-13
Like the SCCT,the combined cycle plant also decreases in
efficiency as load decreases,but not to as great an extent.
At minimum load of approximately 30 percent,with only one
SCCT fired and the steam turbine at part load,the net
station heat rate increases to 12,600 Btu/kWh and the net
efficiency drops to approximately 27 percent.
(k)Fuel Costs (***)
Estimated fuel costs are determined by the OGP program based
on the fuel price,energy generated and the station heat
rate.Fuel prices are addressed in Appendix 01.
2.5 -Coal-Fired Options (***)
2.5.1 -Coal Availability and Price (***)
Alaskan coal availability and pricing for electric generation in
the Railbelt is addressed in Appendix 01,Chapter 4.A summary
follows.
Two major coal fields are available for fuel supply to the
coal-fired thermal alternative.These are the Nenana field,
which is currently mined for fuel and export,and the Beluga
field which is currently in the permitting stage of development
for export and potential power generation.Both fields are large
enough to meet all foreseeable export and domestic requirements
for the planning period.
The estimated recoverable reserves in the Nenana field are 457
million tons.The present mining capacity is about 2 million
tons per year.The addition of a coal-fired plant (400 MW)in
the Nenana area would require mining capacity expansion to
approximately 4 million tons per year.
The recoverable reserves at Beluga are estimated in the billions
of tons.The combination of export market needs and potential
domestic use for electric generation would result in production
of about 8 to 12 million tons per year per mine.
The prices of Alaskan coals are a function of primary market
served,method of coal transport,and pricing methodology.The
Nenana field coal is primarily assumed t~serve domestic markets.
However,the coal must be shipped to the town of Nenana if the
coal is to be burned in an environmentally acceptable plant •.
Costs of Nenana coal have been calculated on a production basis.
The main potential for the Beluga field is to serve the export
market.Domestically the field operation can serve mine mouth
coal-fired power plants.The Beluga pricing methodology 1S
netback pricing based on a supply/demand analysis of the Pacific
851102 0-2-14
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Rim market under both the SHCA and Composit oil price forecasts.
Estimated prices of Nenana and Beluga coal are shown in Table
D.2.5.l.
2.5.2 -Coal-Fired Power Plants (***)
For the coal-fired alterntive a conventional steam electric
central generating station conceptual design was developed.
The design includes the engineering,capital cost,environmental,
and operating parameters necessary to develop the plant.
(a)Plant Description (***)
The basic building block for the Coal Fired Power Plant
al ternative is a single 200 MW (net)coal fired
steam-electric generating unit.A complete plant will
consist of two 200 MW generating units.The plant may be
sited in either the Beluga or Nenana areas of Alaska.The
major difference between the two plant conceptual designs is
coal at Beluga will be received by truck and coal at Nenana
will be received by rail.The area of either plant site is
approximately 110 acres.The generating station will be
centrally located on the site and will consist of the
following major structures:
o Boiler house;
o Turbine buildi~g;and
o AQCS and stack.
Other buildings and facilities include:
o Administration building;
o Maintenance building;
0 Warehouse;
0 Parking area;
0 Switchyard;
0 Transmission line connection;
o Cooling tower;
o Coal receiving,processing,storage,and retrieval
area;and
o Wastewater treatment facility.
851102 D-2-l5
(b)Steam Generator (***)
The steam generator will produce 1.46 x 10 6 lbs/hr of steam
at 2,520 psig and 1,005°F when combusting 135 tons/hr of
coal.Coal is metered by gravimetric feeders to five (5)
pulverizers,any four (4)of which can distribute coal to
the burners to maintain Maximum Continuous Rating (MCR)of
the boiler.The coals to be burned at a Beluga or Nenana
site are similar:both are a low sulfur subbituminous Type C
coal with relatively high ash and moisture content.
The calculated efficiency of the boiler for these plants
using a coal analysis representative of either plant is
about 84 percent.This is slightly lower than for many
coal-fired plants,but it reflects the relatively low
heating value and high moisture and ash content of the fuels
being burned.
(c)Turbine-Generator Operating Parameters (***)
At a full load of 1.46 x 10 6 lb/hr of main steam to the
turbine,the generator output is 217,640 kW.The turbine
is a tandem compound flow design with two intermediate
pressure extraction points,four low pressure extraction
points and an extraction between the intermediate and low
pressure turbine piping in the crossover.The generator's
power factor is 0.85 operating with a 45 psig hydrogen
cooling system and two inches Hg absolute back pressure.
The generator rating is 260,000 kW.
(d)Plant Auxiliary Loads (***)
The power plant will consume approximately 8 percent of the
electricity generated when operating at full load.The
components of the total estimated auxiliary load are listed
below:
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851102
Load Description
Steam Generator including ID and FD Fans
Turbine Generator
Coal Handling System
Ash Handling System
Boiler Feed Pumps
Miscellaneous Pumps
Makeup Demineralizer
Condensate Polishing
Wastewater Treatment System
D-2-16
kW
4,000
420
2,500
800
3,100
3,000
200
200
275
The performance of the station is not significantly affected
by elevation or ambient air temperature.The station
operating parameters are as follows:
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(e)
Load Description
Cranes &Lifting Equipment
Turbine &Boiler Bldg.HVAC
Total Plant Auxiliary Loads
Plant Operating Parameters (***)
kW
275
2,600
17,370 kW
STEAM PLANT OPERATING PARAMETERS
Fuel Consumption (Full Load)135 tons/hr
Combustion Air Flow 1.6 x 10 6 ACFM at 350°F
Steam Generated/Pressure/1,460,000 lbs/hr
Temperature 2,520 psia/1005°F
Reheat Steam Flow 1,270,996 lbs /hr
Flue Gas Volume 1.6 x 10 6 ACFM
Lime Consumption 1900 lbs/hr
Particulate Collection Efficiency 99.95%
Turbine Throttle Steam Flow 1,456,128 lbs /hr
Turbine Exhaust 1,395 x 10 6 lbs/hr
Waste Heat Rejected 1 x 10 9 Btu/hr
Circulating Water Flow,at 90°F 87,900 GPM
Gross Generating Capacity 217,600 kW
Station Auxiliary Loads 17,400 kW
Net Generation (Nominal Capacity)200,000 kW
Gross Turbine Heat Rate (Full Load)7,890 Btu/kWh
Net Station Heat Rate (Full Load)10,300 Btu/kWh
Net Station Heat Rate (40%Load)11 ,800 Btu/kWh
(f)Environmental Assessment (***)
Construction and Operation of the coal-fired power plants
will result in potential environmental impact in five
areas.These are Air Quality,Water Quality,Solid Waste
Disposal,Noise Pollution,and Land Use Impact.These
impacts are addressed in Exhibit E,Chapter 10,Section 4.
(g)Capital Costs (***)
The capital costs for the coal-fired power plant alternative
were based on four separate es·timates for 200 MW power
plants at the Beluga and Nenana sites as follows:
o Beluga Initial Unit;
o Beluga Extension Unit;
851102 D-2-17
o Nenana Initial Unit;and
o Nenana Extension Unit.
The estimates were prepared in 1983 dollars and escalated to
1985 dollars using Ebasco's composite Index of Direct Costs
for Electric Generating Plants (escalation factor of
1.0394).The Composite Index is based on historical data
and reflects annual changes in cost of materials,equipment
and labor rates.
Tables D.2.5.2 and D.2.5.3 present a summary of the detailed
estimates for the Beluga 200 MW initial unit and the Beluga
200 MW extension unit.Table D.2.5.4 presents the Capital
Cost Summary for the Beluga coal-fired power plant including
other related plant costs.
Tables D.2.5.5 and D.2.5.6 present a summary of the detailed
estimates for the Nenana 200 MW initial unit and the Nenana
200 MW extension unit.Table D.2.5.7 presents the capital
cost summary for the Nenana coal-fired power plant including
other related plant costs.
All costs are in 1985 dollars.
(h)Operation and Maintenance Costs (***)
Operation and maintenance (0 &M)costs were developed from
two sources:
o RailbeltUtility Data;and
o Independent Data.
Through utility contacts,data was accumulated for similar
operations and modified for the specific plants and sites.
The independent data was developed from vendor equipment
information,operational parameters,data files,and
engineering judgment.
The operation and maintenance costs were segregated into two
components,fixed costs and variable costs.The fixed costs
are those which are independent of the level of plant
operation,provided the plant is maintained in operational
condition.Fixed costs are measured in dollars per kilowatt
($/kW)based on net plant capacity.Variable costs are
those which occur only if the plant generates electricity
and vary directly with the electricity produced.Variable
costs are measured in dollars per megawatt hour ($/MWh)
based on assumed annual plant generation.
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851102 D-2-18
851102
L
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A summary of the O&M costs are presented in Table
0.2.5.8.These costs include fixed costs and variable
costs,and exclude fuel costs.
The O&M costs were developed in 1982 dollars and were
escalated to 1985 dollars using the GNP Implicit Price
Deflator (escalation factor of 1.1046).All costs in Table
0.2.5.8 are in 1985 dollars.
(i)Heat Rate (***)
The net output of the station will be 200,270 kW at full
load after allowing for auxiliary loads.The turbine will
have a gross heat rate of 7,890 Btu/kWh at full load.This
is a direct measure of the amount of heat energy as stearn
required to produce a kilowatt hour at the generator bus.
The net station heat rate is calculated based on the turbine
heat rate and boiler efficiency after subtraction of the
auxiliary load to obtain the net output of the unit at full
load.The net station heat rate is 10,300 Btu/kWh for both
a Nenana plant and a Beluga plant.The resulting net thermal
efficiency is 33 percent.
(j)Fuel Costs (***)
Estimated annual fuel costs for the coal plants are
terrnined by the OGP program based on the delivered fuel
price,the energy generated,and the station heat rate.
Fuel prices are addressed in Appendix 01.
2.6 -The Existing Railbelt System (***)
2.6.1 -System Description (***)
The two major load centers of the Railbelt region are 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.
The existing transmission system of the Anchorage-Cook Inlet area
extends north to Willow and consists of a network of 115-kV,
138-kV,and 230-kV lines with interconnection to Palmer.The
Fairbanks-Tanana Valley system extends south to Cantwell over a
138-kV line.The Anchorage-Fairbanks Intertie,completed by the
Applicant in 1985,connects willow and Healy and operates at
138-kV.However,it is designed for 345-kV operation.
0-2-19
851102
(a)Anchorage-Cook Inlet Area (***)
The Anchorage-Cook Inlet area has the following major
electric utilities and power producers:
o Municipal Utilities;
-Municipality of Anchorage-Municipal Light &Power
Department (AMLP)
-Seward Electric System (SES)
o Rural Electrification Administration
Cooperative (REA);
-Chugach Electric Association,Inc.(CEA)
-Romer Electric Association,Inc.(REA)
-Matanuska Electric Association,Inc.(MEA)
o Federal Power Marketing Agency;and
-Alaska Power Administration (APAd)
o Military Installations.
-Elmendorf Air Force Base
-Fort Richardson
AMLP and CEA are the two principal utilities serving the
Anchorage-Cook Inlet area.AMLP and CEA are intertied and
have established rate schedules which contain capacity
charges and flat energy changes for certain commitments.
All of these organizations,with the exception of MEA,have
electrical generating facilities.MEA buys its power from
CEA.REA and SES have relatively small generating
facilities that are used for standby operation.They also
purchase from CEA.The rate structures and tariffs for
wholesale and retail electric power contracts are discussed
in detail in Exhibit B,Chapter 5,Section 2.
The Anchorage-Cook Inlet area is almost entirely dependent
on natural gas to generate electricity.About 92 percent of
the total capacity is provided by gas-fired units.The
remainder is provided"by hydroelectric units and oil-fired
diesel units.TableD.2.6.1 presents the total generating
D-2-20
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(b)
capacity of the Anchorage-Cook Inlet utilities and military
installations.
Fairbanks-Tanana Valley Area (***)
The Fairbanks-Tanana Valley area is currently served by the
following utilities and power producers:
o Municipal Utility;
-Fairbanks Municipal Utilities System (FMUS)
o Rural Electrification Administration;
Cooperative (REA)
-Golden Valley Electric Association,Inc.(GVEA)
o Military Installations;and
-Eielson Air Force Base
-Fort Greeley
-Fort Wainwright
o University of Alaska,Fairbanks.
GVEA and FMUS own and operate generation,transmission,and
distribution facilities.The University and military bases
maintain their own generation and distribution facilities.
GVEA and FMUS are interconnected and exchange economy
energy.In addition,Fort Wainwright is interconnected with
GVEA and FMUS and provides both utilities with economy
energy.Rate structures and tariffs for retail electric
power sales from GVEA and FMUS are discussed in Exhibit B,
Chapter 5,Section 2.
A large portion of the total installed capacity consists of
oil-fired combustion turbines (58 percent)and coal-fired
steam turbines (31 percent).The remaining capacity is
provided by diesel units.Table 0.2.6.2 presents the total
generating capacity of the Fairbanks-Tanana Valley area
utilities,military installations and the University.
2.6.2 -Total Present System (***)
The total Railbelt installed capacity is 1145 MW,excluding
installations not available for public service at the
University and military bases.The 1145 MW consist of 1098 MW of
thermal generation fired by oil,gas,or coal,plus 47 MW from
851102 0-2-21
the Eklutna and Cooper Lake hydroelectric plants.Average and
firm monthly energy estimates for the Eklutna and Cooper Lake
hydroelectric projects are shown in Table D.2.6.3.
Tables D.2.6.4 and D.2.6.5 summarize equipment operation periods,
generating capacity and operation characteristics including heat
rates,operation and maintenance costs and outage rates.These
data are based upon the Applicant's evaluation of information
provided by the Railbelt utilities.
The unit capacities and heat rates were developed uS1ng power
output versus inlet temperature curves,equipment heat rate
curves,and fuel consumption vers us power output curves.
The operation and maintenance costs are the result of review of
historical plant accounting records.The utility records were
assembled and analyzed based on a consistent breakdown of fixed
and variable cost items.The planned and forced outage rates
reflect established maintenance schedules and experienced outage
da ta.
Retirement policy for the existing generating units was provided
by the Railbelt utilities and reflects present age of the
equipment,projected maintenance programs,anticipated hours of
operation,and industry standards.The retirement schedule of
existing Railbelt generating equipment is shown in Table D.2.6.6.
For purposes of the economic evaluation,the Applicant has
assumed the following lifetimes for new generation equipment:
[
L
Equipment
Coal-Fired Steam Turbines:
Gas-Fired Combustion Turbines:
Oil-Fired Diesel Units:
Gas-Fired Combined-Cycle Turbines:
Hydroelectric Projects:
2.7 -Generation Expansion Before 1996 (***)
Life
in Years
35
25
20
30
50
The short-term generation plan is based on expansion studies with the
Applicant's load forecast and evaluation of utility information for
generation planned in the period 1985 through 1995.Table D.2.7.1
presents the year-by-year capacity additions and planned retirements.
Table D.2.7.2 summaries on-line dates,operation costs,and
characteristics of each unit.
Railbelt utility additions include 132 MW of gas-fired generation,and
7.5 MW of diesel standby generation.HEA and MEA are cooperating on
the addition of a 45 MW combustion turbine which will be online in the
851102 D-2-22
fall of 1985.Both CEA and AMLP are planning the addition of 87 MW
combustion turbines.-However,based on the Applicant's load forecast
only one combustion turbine is required in the period 1985 through
1995.Therefore an 87 MW combustion turbine has been scheduled on-line
in 1992.SES plans include the addition of 2.5 MW of diesel standy
capacity in 1985 and 1986 and an additional 2.5 MW in 1990.
The Applicant confirmed the economic feasibility of the Bradley Lake
project and submitted an application for license to the FERC in March
1984.The Applicant and Railbelt utilities are currently negotiating
power sales contracts for Bradley Lake power and energy.
The Project is located near Kachemak Bay at the southern end of the
Kenai Peninsula.Project features include a l25-foot concrete-faced
rock fill dam,and a 19,000-foot-long power tunnel which will divert
water from Bradley Lake to an above-ground powerhouse at tidewater.
The project will have 90 megawatts of installed capacity and average
annual energy generation will be about 367 GWh.The estimated average
and firm monthly energy generation for the Bradley Lake project are
shown in Table D.2.6.3.A 20-mile,lIS-kilovolt transmission line will
connect the project to the existing Kenai Peninsula system.
2.8 -Formulation of Expansion Plans Beginning in 1996 (***)
2.8.1 -Methodology (***)
Capacity expansion studies undertaken for the Susitna Project
serve three major functions:(1)reliability (or reserve)
evaluation;(2)electricity production simulation;and,(3)
capacity expansion optimization.Expansion optimization analyses
provide a systematic means of evaluating the timing,type,and
system costs of new power facilities,thus permitting analysis of
the relative costs of different but equivalent means of meeting
projected electrical demand.
The Optimized Generation Plan (OGP)model was used to develop
expansion plans for the Railbelt.The details of the OGP program
and its relationship with other computer models used in the power
market forecast are described in Exhibit B,Chapter 5,Section 3.
Section 5.3 discusses the variables used in all the models to
assure that they are consistent throughout the planning process.
In developing an optimal capacity expansion plan,the program
considers the load forecast and system operation criteria to
determine the need for additional future capacity within the
specified degree of reliability.Then the program considers the
existing and committed units (planned and under construction)
available to the system and the operating characteristics of
these units.The program optimizes the amount and installation
date of needed additional capacity as .load increases over time.
851102 D-2-23
In addition to a number of sensitivity cases described in Section
2.11 of this Exhibit,two companion cases were developed for the
present analysis that rely on alternative oil price forecasts.
The Sherman H.Clark Associates (SHCA)forecast and the Composite
forecast,both of which are described in Appendix Dl,Chapter 2.
Generation expansion plans and related costs are presented for
each case in the following discussion.
The next five sections briefly review Railbelt load forecasts and
the elements of the OGP program,then the expansion planning
analysis period is described.
2.8.2 -Load Forecast (***)
The electric demand forecasts from Exhibit B,Chapter 5,Section
4 are shown in Tables D.2.8.1 and D.2.8.2,respectively.
The RED Model forecasts of peak power demand and energy
requirements are computed at the customer or point-of-use level.
The generation required to supply the customer loads at the point
of generation exceeds the load by bulk transmission,
distribution,and unaccounted losses.
Estimates of bulk transmission capacity and energy losses between.
utility sub-stations were prepared using load flow over the high
voltage transmission line configuration presented in this
Application.The estimates of distribution system capacity
losses were based on available cable sizes,line lengths,and
line voltages for the distribution system in the Anchorage area.
The energy losses at the distribution system level were estimated
by comparing utility net generation and sales figures included
in Alaska Electric Power Statistics,prepared by the Alaska Power
Administration.
In addition,the load forecasts were extended from 2010 to 2025
using the average annual growth for the period 2000 to 2010 for
use in the OGP model studies.
2.8.3 ~Reliability Evaluation (***)
The Loss of Load Probability (LOLP)method is used in the OGP
program to determine when additional capacity is needed.The
LOLP approach recognizes that forced outages of generating units
would cause a deficiency in the capacity available to meet the
system load unless adequate capacity had been installed.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.
Evaluation of expansion plans resulting from different LOLP
levels indicated that the expansion plans and associated system
•
851102 D-2-24
L
costs of the With-and Without-Susitna plans are not
significantly affected across the range investigated.For these
studies,the Applicant has selected a LOLP of one day in ten
years.System reliability criteria are further discussed in
Exhibit B,Chapter 4,Section 1.
Spinning thermal reserve equal to the largest unit on line is
included within the reserve margin for all alternative expansion
plans.Spinning reserve is available capacity which can quickly
be brought into full production to off-set any forced shut-down
of operating units.The costs associated with this spinning
reserve are included in all plans.
2.8.4 -Hydro Scheduling (***)
In the OGP simulation,the power and energy potential and timing
of hydroelectric units are provided as input around which
thermal units are added.The estimates of average monthly energy
generation,which are limited by system demand,are input to OGP
and are also used to define Susitna capacity as input to OGP.
When the Watana Stage I development comes on-line,environmental
constraints limit plant operation to base load maintaining nearly
uniform discharge from the powerhouse.This effectively limits
the Watana project dispatch to a constant 24-hour capacity level.
The power capability input into OGP is then computed as the
estimated average monthly energy generated,divided by the number
of hours in the month.
When Devil Canyon Stage II comes on-line,the Watana Stage I
project will follow load,regulate frequency and voltage,provide
spinning reserve,and react to system needs under all normal and
emergency conditions.This operation will result in powerhouse
discharge fluctuations which will be regulated by the Devil
Canyon reservoir.The load-following power output from Watana
can equal the capability of the turbines,which is a function of
Watana reservoir elevation.The monthly capability of the Watana
Stage I turbines is input to OGP.The Devil Canyon Stage II
power output used in OGP is computed as described above for
Watana Stage I operating as a base load plant.Devil Canyon is
operated as a base load plant maintaining nearly uniform
discharge from the powerhouse.
The power and energy estimates of both facilities are increased
when Watana Stage III comes on-line to reflect increased
operating head and greater river regulation.The OGP inputs are
revised based on the approach outlined for Stage II.Table
D.2.2.l provides estimates of power and energy production as
input to OGP.
851102 D-2-25
2.8.5 -Thermal Unit Commitment (***)
After deducting hydroelectric plant output,including Eklutna,
Cooper and Bradley Lake,and thermal unit maintenance,the
remaining loads are served by the existing thermal units
available to the system.The units are added to the system to
minimize operating costs,which consist of fuel costs.and
variable operating and maintenance (O&M)costs for each unit.
Fixed O&M costs do not affect the order in which existing units
are committed.The unit operation logic determines how many
units-will be on-line each hour and which units are selected,
with the least expensive increment being added first.
2.8.6 -OGP Optimization Procedure (***)
For each year under study,OGP evaluates system reliability to
determine the need for installing additional generating
capacity.If the capacity is sufficient to maintain the desired
LOLP of one day in ten years,the program calculates the annual
production and investment costs and proceeds to the next year.
If additional capacity is needed,OGP adds units from the list of
suitable additions until the given reliability level is met.
Among the issues considered in determining suitability is the
size of a potential unit relative to the size of system load and
cost.For a combination of units the program calculates annual
costs for a 25-year look-ahead period and selects the most
economical installation.The capital and O&M costs and operating
characteristics of the thermal units available for addition to
the system are summarized on Table D.2.8.3.Summaries of fuel
prices are shown in Tables D.2.4.1 and D.2.5.1.
2.8.7 -Generation Expansion (***)
The objective of the expansion planning study was to determine if
the proposed Susitna Hydroelectric Project will produce energy
at lower total cost than its competing alternative.The period
of analysis for the evaluation consists of two periods.The
first period covers the years of expansion of the system and ends
in the year 2025.This period defines the alternative system
developments to be compared.The annual costs are further
extended for a second period which extends until the
hydroelectric project has reached its service life.
The economic analysis of hydroelectric developments may be based
on a period of 100 years.Dam and reservoir facilities normally
have lives of at least 100 years,however,power facilities
including the powerhouse and generating equipment will have
shorter lives.If a period of analysis is used that exceeds the
life of power faci lities,interim replacement costs must be
L
851102 D-2-26
computed to provide for the cost of replacing units of property
having a shorter life than the period of analysis.For the
expansion planning analysis the Applicant has selected a period
of analysis of 50 years for the Susitna Project.This 50-year
period is assumed to end in 2054 or 50 years after the operation
of the Devil Canyon project which is the middle stage of the
three-stage development.The Applicant's estimate of operation
and maintenance costs provides for overhaul of turbines and
generators after 30 years of service.
Using the Optimized Generation Planning (OGP)program,
alternative expansion plans were developed for the period from
January 1996 to Dec~mber 2025 to establish the least-cost system
for that period with and without the Susitna Project.In the
With-Susitna case,it was assumed that Watana-Stage I would start
operation in 1999,Devil Canyon Stage II would be on line in 2005
and Watana-Stage III would be completed in 2012.In the
Without-Susitna alternative plan,coal-fired and gas-fired
thermal generation are added to the existing units.
The costs for each expansion plan include the annualized capital
costs of any plants and transmission facilities added during the
period and fuel and O&M costs of the generating units.Costs
common to all the alternatives,such as investment costs of
facilities in service prior to 1996,and administrative and
customer service costs of the utilities,are excluded.
The long-term system costs (2026-2054)are estimated by extending
the 2025 annual costs,with no load growth and fuel prices
adjusted for real fuel price escalation,for the 29-year period.
All costs are then converted to a 1985 present worth and the
With-Susitna and Without-Susitna expansion plans are compared on
the basis of the 1985 present worth of costs from the 1996 to
2054 time frame.
2.8.8 -Transmission System Expansion (***)
Transmission system expansion costs for the With-Susitna
expansion have been estimated and included as part of the
Project,as discussed in Exhibit B,Chapter 2,Section 7.
Transmission system expansion needs associated with
Without-Susitna expansion plans are added as a separate items to
the alternatives and are discussed in Section 2.9.2 of this
Exhibit.
2.9 -Selection of Expansion Plans (***)
Two forecasts are analyzed in OGP to demonstrate their effects on
future generation expansion plans and the economic attractiveness of
851102 D-2-27
851102
the Susitna Hydroelectric Project.In the analysis it is assumed that
all Railbelt utilities will be interconnected and will share reserves
as of 1996.A discussion of the selected plans and their capacity
additions follows.
2.9.1 -With-Susitna Expansion Plan (***)
Table D.2.9.1 shows the yearly additions for the With-Susitna
expansion plan based on the SHCA forecast.As shown in Table
D.2.9.l,two combustion turbines (174 MW)are required to meet
system reserve criteria during the period between Watana-Stage I
and Devil Canyon-Stage II.In addition,one combustion turbine
(87 MW)is required between Devil Canyon-Stage II and
Watana-Stage III.
Following Watana-Stage III operation,about 350 MW of additional
combustion turbines will be required to replace retired units and
to meet the load demand and reserve criteria through 2025.
Two adjustments to the power and energy capabilities of the
Susitna Project are implemented in 2009 and 2019.The
adjustments reflect increased project power and energy as a
result of system load growth.
Table D.2.9.1 also shows the yearly additions for the
With-Susitna expansion plan based on the Composite forecast.
Inspection of Table D.2.9.l indicates that the alternative
electric demand forecast has had very little impact on the system
additions.This is due primarily to the similarity in the
forecasted demands of the SHCA and Composite forecasts.
Table D.2.9.2 summarizes OGP output for the SHCA and Composite
forecasts based on the With-Susitna alternatives related to
Susitna dependable capacity and usable energy.The dependable
capacity is defined as the Susitna project's capacity which is
dispatched to carry system load at the time of peak,taking into
account unit operating characteristics,hydrologic conditions,
and resulting estimates of unit capability.Usable energy is the
energy dispatched in the system when compared to the energy made
available for dispatch in the OGP input data.
As can be seen from Table D.2.9.2 (Page 1 of 2),with the SHCA
forecast the base-load capacity of the Watana Stage I development
has been absorbed in the system.About 94 percent of energy
available is usable in 1999,increasing to 97 percent in 2004.
With the addition of Devil Canyon Stage II in 2005 the capacity
and energy available for dispatch increases.In addition,the
project's capability is adjusted to reflect growth in demand in
2009.The dependable capacity and energy absorbed increases as
D-2-28
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system growth in peak load and energy requirements occurs.This
increase also reflects the upward capability adjustments.
Dependable capacity increases from 775 MW to 805 MW,which is
the total capacity available.The usable energy increases from
4,230 GWh to 4,740 GWh 1n 2011.
In 2012 the Watana dam is raised and corresponding increments in
capacity and energy are available due to increased head,addition
of two units in the Watana powerhouse,and better regulation of
Susitna River flows.Also,project capability is adjusted upward
in 2019 due to growth in demand.During the period 2012 to 2025,
dependable capacity increases 28 percent and usable energy
increases 30 percent.The 2025 dependable capacity of about
1,220 MW is about 310 MW less than the available capacity,
therefore,this level of capacity could be considered avai r'able
for spinning reserve.The three-stage Susitna hydroelectric
project's maximum average annual energy generation which
corresponds to unlimited system demand is 6,900 GWh.It is
projected that this level of energy generation would be absorbed
in about 2027.
Review of Table D.2.9.2 (page 2 of 2),which summarizes the
dependable capacity and usable energy for the Composite forecast,
shows nearly identical utilization of the Susitna project's power
and energy for the period 1999 through 2025 as with the SHCA
forecast.
2.9.2 -Without-Susitna Expansion Plan (***)
(a)System Expansion Plans (***)
Table D.2.9.3 shows the Without-Susitna alternative plans
for the SHCA and Composite forecasts.These plans were
developed by the OGP process of comparing the economic
advantages of various generation mixes including combined
cycle,combustion turbine and coal-fired alternatives.
Gas-fired system additions after 1999 are limited to 1500
hours of operation because projected gas supply and demand
projections exceed resource estimates.
As the SHCA forecast OGP analysis is initiated,the existing
Railbelt capacity is sufficient to meet the projected load
growth and maintain reliability criteria through the middle
to late 1990's.In 1999,coal-fired plants are added near
the Beluga coal field.Additional coal-fired plants are
added in 2004 and 2006 in the Nenana area of the northern
Railbelt.Subsequent coal-fired power plants are sited near
the Beluga field.Combustion turbines are brought on-line
for peaking service,reliability requirements,and to
replace combustion turbines added in earlier years.
851102 D-2-29
851102
Table 0.2.9.3 also shows the yearly additions for the
Without-Susitna expansion plan based on the Composite
forecast.Capacity additions in the early years of this
plan are essentially identical to the SHCA expansion pl~n.
The coal-fired plant locations follow the same pattern as
discussed in the SHCA plan.However,the Composite forecast
expansion plan has one less coal-fired powerplant than the
SHeA plan.The combustion turbines added in later years
perform peaking service,meet reliability requirements and
replace combustion turbines added in earlier years.
After allowance for the retirement of existing units and
additions of new capacity in the period 1996 through 2025
the generation system mix (MW)as of 2025 for the SHCA and
Composite forecasts can be summarized as follows:
SHCA Composite
Forecast Forecast
Coal-Fired Steam 1,400 1,200
Gas-Fired Combustion Turbine 544 611
Gas-Fired Combined Cycle
Hydroelectric 137 137
Total 2,061 1,948
(b)Transmission System Expansion (***)
Electric system studies were carried out to establish
transmission requirements associated with the
Without-Susitna expansion plan.The object was to develop a
system configuration which would be consistent with the
Susitna transmission planning criteria.The guidelines
concerning power transfer capability,stability,system
performance limits,and thermal overloads for the Susitna
Project are outlind in Exhibit B,Section 2.7.
Studies were made for both the SHCA and Composite forecasts
and corresponding expansion plans.A system one line
diagram,showing the transmission line configurations is
shown on Figure 0.2.9.1.The ultimate development shown
applies to the Without-Susitna alternative for both
forecasts,although there are variations in timing of
transmission system additions between the two alternatives.
The system consists of 230-kV lines north of Nenana and
south of Willow.Between Nenana and Willow,the 2l8-mile
long section would be operated at 345 kV.The 345-kV
section would consist of the existing Intertie operated at
345-kV and a new 345-kV circuit constructed parallel to the
Intertie in 1999.
0-2-30
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I
8S1102
The system takes full advantage of the existing 138-kV and
230-kV submarine cables crossing Knik Arm.An additional
230-kV cable crossing was planned.
Load flow calculations were performed for selected stages of
development.Figure D.2.9.2 shows a load flow diagram for
approximate peak load conditions in the year 202S.
The load flow calculation verified acceptable voltage ranges
and line loadings and established the ratings for
transformers,reactors,and dynamic var compensators.
230-kV submarine cables have compensating shunt reactors at
both ends.
Line energization studies using load flow calculations
indicated that,during energization of the largest line
section,namely,the 218-mile Willow to Nenana line,the
volatage would not exceed 1.1 per unit at the open end.
In general,the load flows demonstrated that the
transmission system would be capable of handling the full
range of steady state conditions.
A cost estimate was prepared for the SHCA and Composite
transmission line plans.The estimates are presented in
Tables D.2.9.4 and D.2.9.S.The estimates cover the major
transmission system developments expected to occur to the
year 202S.For the coal-fired capacity additions at Beluga
and Nenana,the cost of the powerplant substation and
connections to the major transmission system are included
with the powerplant estimate.For these costs,see Tables
D.2.5.2 through D.2.S.7
Table D.2.S.2 shows the breakdown of transmission line and
substation costs for the initial Beluga unit and the
extension unit of the first 2-unit plant to be built at a
Beluga site.It was determined that installing a
transmission line with the initial unit which would be
capable of handling the output of two units is not
economically justified.Each 200-MW unit would,therefore,
include a 230-kV transmission line installed along a common
right-af-way.The second two-unit Beluga plant assumes
costs identical to the first two-unit plant._That is,a new
right-of-way,or expansion of the existing right-of-way,
will be necessary for the additional transmission lines.
Each 230 kV transmission line would be approximately 48
miles long.
TablesD.2.S.S and D.2.5.6 present the total capital costs
of plant,substations and transmission lines for the two
D-2-3l
Nenana units.Two 230-kV transmission circuits would be
required.Each circuit would be approximately 10 miles
long.
For the simple-cycle and combined-cycle gas-fired additions,
the siting criteria and transmission system costs are based
on the following three assumptions:(1)Maximum of one plant
with three combustion turbines or two combustion turbines
and one steam turbine generator.Existing generating sites
would be used,(2)At least two transmission lines are
required from the generating site to an existing substation,
and (3)High voltage transmission connections would be 115
or 138 kV.
The costs for the transmission lines in Tables D.2.9.4 and
D.2.9.5 are based on the following unit costs:
Material and Labor
Voltage Conductor Size $per Mile
345 kV 2 x 954 kcmil $415,350
230 kV I x 1272 kcmil $340,800
138 kV 556.6 kcmil $181,050
115 kV 556.5 kcmil $106,500
These cost estimates are at 1985 price levels,and include
material and labor.The estimates include right-of-way
cost,engineering,construction management and Owner's
overhead.A contingency allowance of 15 percent is included
for material and labor.Tables D.2.9.4 and D.2.9.5 include
additional information about line additions and
reinforcements such as:line terminal name,voltage level,
length in miles,conductor size,and line termination
station costs.Line compensation such as shunt reactors,
and static var compensation,is included with the line
termination and substation costs.
The cost estimates also include the cost of a Rai1belt
energy management system which is included in the
transmission system for the With-Susitna expansion plan.
2.9.3 -Comparison of Expansion Plans (***)
Figures D.2.9.3 through D.2.9.6 compare the contribution of
energy production between the With-Susitna plan and
Without-Susitna plan for each forecast.As shown by these
exhibits,the Railbelt system generation will continue to be
dominated by gas-and oil-fired generation over the next 10 to 15
years.By 1999 a very large share of the gas-and oil-fired
generation can be replaced with Susitnain operation.Otherwise,
851102 D-2-32
L
coal-fired generation becomes more significant in the SHCA and
Composite expansion plans,respectively.
2.10 -Economic Feasibility (***)
This section provides a discussion of the key economic parameters used
in the study and develops the net economic benefits and benefit-cost
ratio of the Susitna Hydroelectric Project.
First,economic principles and parameters relevant to the economic
analysis are discussed.Then the annual and cumulative pres~nt worth
of system costs of expansion plans resulting from the SHCA and
Composite forecasts are developed for the With-and Without-Susitna
expansion plans.Next,the net economic benefits and benefit-cost
ratio of the Susitna Project are determined.Finally,sensitivity
analyses were performed.
2.10.1 -Economic Principles and Parameters (***)
(a)Economic Principles (***)
The economic analysis compares the costs of alternatives
during the planning period 1996-2054.Throughout the
analysis,all costs and prices are expressed in real terms
using January 1985 dollars.
The With-Susitna and Without-Susitna alternative expansion
plans,discussed in detail in Section 2.9 above,are
utilized here to assess the economic benefits of the Susitna
Project.Net benefits are based on the difference between
the costs of the Without-Susitna alternative and the
With-Susitna alternative.For the Susitna Proj~ct to be
considered economically feasible,net benefits must be
positive and the benefit/cost ratio must be greater than
one.The benefit/cost (B/C)ratio is determined using the
following formula:
Total Present Worth of System Expansion
B / C =Plan Without-Susitna
Total Present Worth of System Expansion
Plan With-Susitna
Costs for each expansion alternative include three main
items:capital,fuel,and operation and maintenance (O&M)
costs.Capital costs include construction costs and
interest on funds used during construction assuming 100
percent debt financing for all facilities.The method used
for estimating interest on funds during construction is
discussed in Section 1.5 of this Exhibit.Fuel costs for
the coal or gas consumed annually in the thermal plants are
851102 D-2-33
adjusted to account for real fuel pr1ce escalation,O&M
costs also are expended each year.
To determine the benefit/cost ratio and net benefits,all
costs (or benefits)must be adjusted to a comparable present
worth.Costs are adjusted to their present worth by
discounting,which gives costs in earlier years more weight
than costs in later years.The total present worth of each
expansion plan was obtained by calculating the present
worth of each future annual cost.
Table D.2.l0.l summarizes the principal economic parameters
that were used in the economic analysis.The economic life
of each generating plant type used in the economic analysis
is based on 25 years for combustion turbines,30 years for
combined cycle,35 years for steam turbines,and 50 years
for hydroelectric plants.
The annual fixed carrying charge on the investment in
generating facilities varies with estimated service life of
the facilities.The three major elements included in this
analysis are cost of money,amortization,and insurance
payments.Taxes are not applicable since the applicant is a
public agency.Interim replacement are included in
operation and maintenance costs.
The fixed charge rates are expressed on a levelized basis
over the economic life of the equipment.When applied to
the plant investment costs they yield annual revenue
requirements for capital recovery,which includes interest
and principal,and insurance preminums to protect against
losses and damage to facilities.The cost of money which is
equated with the discount rate is discussed in the next
section.
(b)Real Discount Rate (***)
The selection of a real discount rate for the Susitna
economic analysis has been based on the anticipated real
cost of project financing in accordance with regulations
adopted by the Applicant.l /A major survey (Corey 1982)
conducted in 1977 established that,in electricity and gas
industries 94 percent of all investor-owned utilities,100
percent of all cooperatives,and 71 percent of all
government agencies used discount rates as determined by the
1/AAC 94.055(c)(5)and 3 AAC 94.060(c)(5)require the adoption of a
discount rate for project evaluation that represents "the estimated
long-term real cost of money."
L
851102 D-2-34
j
\--
851102
cost of finance methodology with only minor technical
variations.The same methodology has long been advanced by
the Electric Power Research Institute (EPRI 1982).In
concept,the efficiency of a power system is enhanced if
projects are undertaken that produce net economic benefit
when evaluated with a discount rate determined in this
manner.An expectation of benefit so derived is equivalent
to a demonstration that a project's expected rate of return
exceeds the cost of project financing.
As discussed in Section 4.0 of this Exhibit,it is intended
that the full cost of project construction be financed
through the issuance of tax-exempt revenue bonds.
Consequently,determination of the real discount rate has
been based on the real interest rate anticipated for such
bonds issued during the course of project construction.
The real interest rate is equal to the inflation-adjusted
rate of return over the life of the bond.For example,to
estimate the real interest rate for 20-year bonds to be
issued five years from now,it is necessary to forecast the
nominal interest rate for bonds to be issued at that time
and to forecast the inflation rate for the 20-year period
following the date of issuance.To support estimation of a
real interest rate for Susitna financing,forecasts of
nominal interest rates and inflation rates produced by Data
Resources,Inc.,Wharton Econometrics Forecasting
Associates,and Chase Econometrics were obtained during the
spring of 1985.
It was necessary to adjust these forecasts in two ways in
order to generate appropriate estimates of real interest
rates:
1)The forecasts cover the 10-year period from 1985 to
1994.Since inflation forecasts are required over a
longer term in order to make the necessary
calculations,they were extended for an additional 20
years based on the average of the last 5 years of each
forecast.
2)The nominal interest rate forecasts that were obtained
are for long-term U.S.Treasury bonds.Analysis of
long-t~rm Treasury bond yields and Grade A tax-exempt
yields between 1945 and 1984 indicates that the former
has exceeded the latter by an average factor of 1.12
over the last 40 years.This factor was,therefore,
applied to the Treasury bond interest rate forecasts
in order to arrive at consistent forecasts of Grade A
tax-exempt nominal interest rates.
D-2-35
Given this conversion of Treasury bond rates to
tax-exempt rates,the averages of the three 10-year
forecasts are shown below:
Year
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
Inflation
Rate Forecast*
3.7
4.3
4.7
5.3
4.9
5.2
5.0
4.9
5.2
5.3
Nominal Interest
Rate Forecast **
10.1
9.8
10.1
10.3
9.8
9.4
8.7
8.2
8.1
8.0
L
*Percent change in u.s.Consumer Price Index.
**Long-term Grade A tax-exempt securities.
The real interest rates of long-term grade A tax-exempt securites
implied by these forecasts are as follows:
Year
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
Real Interest
Rate Forecast
5.0
4.6
4.8
4.9
4.4
4.1
3.4
2.9
2.8
2.8
851102
An example of the manner in which the real interest rates
are calculated is presented in Table 0.2.10.2.
In addition to these forecasts,the historical pattern of
real interest rates was examined to provide a more complete
context for discount rate determination.Again,the
analysis focused on U.S.Treasury issues over the last 40
years.In order to construct a series of real interest
rates that extends to the present,it is necessary to
0-2-36
examine a range of maturities.Real rates on l5-year
maturities can be computed only for bonds issued prior to
1971,since bonds issued at a later date have not yet
matured and,therefore,the actual rate of inflation
throughout the term of the issue is not yet known.Real
rates on 10-year maturities were therefore examined for the
years 1971 through 1975,3-to 5-year maturities for 1976
through 1981,and 3-month maturities thereafter.The
results of the analyses are presented in Table D.2.l0.3.
Though these are essentially risk-free securities (in
contrast to Grade A municipals),it is striking that real
interest rates on these issues have been low or negative
until the beginning of the 1980s.
Conclusions from the foregoing analysis can be summarized as
follows:
o Real interest rates currently appear to be in the
vicinity of 5 percent;
o During most of the last 40 years,real interest rates
have been well below 3 percent;and
o The average forecast described herein anticipates that
real rates on Grade A tax-exempt securities will fall
back below 3 percent by the early 1990s;i.e.,prior
to the time during which Susitna financing would take
place.
No attempt has been made to formulate a precise forecast of
real interest rates for long-term debt issued during the
years of Susitna construction.However,based on the
analysis above,it is reasonable to conclude that such rates
will most likely be well below the levels apparent today,
and that a 3.5 percent real rate represents a conservative
judgment of the extent to which they will decline.A real
discount rate of 3.5 percent has therefore been adopted,
which is consistent in magnitude with the selected financial
parameters of a 5.5 percent inflation rate and a 9 percent
nominal interest rate.
2.10.2-Analysis of Net Economic Benefits (***)
The comparison of the With and Without-Susitna plans is based on
an assessment of the annual system costs and present worth of
costs for the period 1996 to 2054,using the load forecast,fuel
prices,fuel price escalation rates,and capital costs associated
with the SHCA and Composite forecasts.
851102 D-2-37
Table 0.2.10.4 shows the computation of the total present worth
of the With-and Without-Susitna expansion plans.During the
1996 to 2025 study period,the 1985 present worth costs for the
Susitna plans are $3.5 and $3.4 billion for the SHCA and
Composite forecasts,respectively.The annual production costs
in 2025 are $423.3 and $315.8 million.The present worth of these
costs,which reflect real fuel cost escalation for a period
extending to the end of the planning period are $2.0 and $1.4
billion.The resulting total present worth in 1985 dollars of
the With-Susitna plans are $5~5 and $4.8 billion for the SHCA and
Composite forecasts,respectively.
The Without-Susitna expansion plans for the SHCA and Composite
forecasts have 1985 costs of $4.6 and $4.5 billion for the 1996
to 2025 period,with 2025 annual costs of $604.0 and $553.4
million.The total long-term costs (2026-2054)have a present
worth of $3.1 and 2.7 billion for the SHCA and Composite
forecasts.The resulting total present worth in 1985 dollars of
the Without-Susitna plans are $7.7 and $7.2 billion for the SHCA
and Composite forecasts,respectively.
The Susitna Project has net benefits of $2.2 and 2.3 billion and
benefit/cost ratios of 1.40 and 1.48 for the SHCA and Composite
forecasts,respectively.Therefore,the Susitna Project is
economically justified under both forecasts.
2.11 -Sensitivity Analysis (***)
Sensitivity analyses were carried out to identify the impact of a
change in assumptions on the resulting net benefits and benefit-cost
ratios of the Susitna Project.The analyses were directed at the
following variables:
o Oil Price Forecast;
o Discount Rate;
o Construction Cost for Watana Stage I;
o Real Escalation of Coal Price;
o Natural Gas Availability for Baseload Generation;and
o Combined Sensitivity Case.
2.11.1 -World Oil Price Forecast (***)
World oil price forecasts influence the load forecast,natural
gas prices,and economics of the With-and Without-Susitna
alternative;therefore,a third oil price forecast was analyzed.
851102 0-2-38
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This forecast is the Wharton forecast which is discussed in
Appendix 01.The Wharton forecast exhibits oil prices lower than
either the SHCA or Composite forecasts.
Table 0.2.11.1 summarizes the load forecasts based on the three
(SHCA,Composite,and Wharton)oil price forecasts.The natural
gas prices used in the analysis are presented in Appendix 01.
Table 0.2.11.2 shows the calculation of the net benefits and
benefit-cost ratio of the Susitna project.Net benefits of $1.7
billion and a benefit-cost ratio of 1.34 demonstrate that the
project is economically attractive under the Wharton forecast.
2.11.2 -Discount Rate (***)
The the Susitna Project's margin of feasibility was tested by
computing the change in net benefits and benefit-cost ratio at
a discount rate of 4.5 percent.Table 0.2.11.3 summarizes the
results of the analysis which show the Susitna Project remains
attractive under the higher discount rate.
2.11.3 -Construction Cost for Watana Stage I (***)
The estimated construction cost of Watana-Stage I is $2.68
billion (January 1985 prices).If the construction cost of
Watana-Stage I were to increase by 15 percent or to $3.08
billion,the net benefits of the Susitna project would be about
$2.0 billion and the benefit-cost ratios would be 1.32 and 1.39
respectively for the SHCA and Composite forecasts,as shown in
Table 0.2.11.4.
2.11.4 -Real Escalation of Coal Price (***)
The sensitivity of the analysis to coal price escalation was
tested using January 1985 coal prices of $1.30 and $1.42/MMBtu
for Beluga coal at mine-mouth for the SHCA and Composite
forecasts,respectively,and $1.84/MMBtu for Nenana coal
delivered.A scenario of zero real escalation on the price of
coal for the entire period from 1985 through 2054 was analyzed,
and the results are presented in Table 0.2.11.5.For the Sherman
Clark and Composite forecasts,net benefit of the Susitna project
would be $0.9 billion and $1.3 billion respectively,with
benefit-cost ratio of 1.16 and 1.28.
2.11.5 -Natural Gas Availability for Baseload Generation (***)
The Applicant's analysis of natural gas supply and demand
projections over the course of the planning period demonstrate
that the demand for Cook Inlet gas exceeds the total estimated
resource.For planning purposes the Applicant assumed that gas
supplies would not be allowed to support baseload generation
851102 0-2-39
expansion after 1999.Therefore,in the system expansion
planning analyses,gas-fired generation additions were designated
as peaking facilities and limited to 1500 hours of operation
after 1999.The sensitivity of the gas-fired generation was
tested by allowing unlimited gas-fired operation for SHCA and
Composite forecasts.
The unlimited gas expansion plans exhibited similar mixes of
coal-and gas-fired plants when compared to the limited gas
plans.This demonstrates that the economically preferred fuel
for baseload generation is coal and that based on price
considerations natural gas is the appropriate choice for peaking
facilities.Table 0.2.11.6 shows the calculation of the net
benefits and benefit-cost ratios of the Susitna Project for the
unlimited gas analy~is.For the SHCA and Composite forecasts,
net benefits would be $2.2 billion and $2.3 billion,
respectively,with benefit-cost ratio of 1.41 and 1.48.
2.11.6 -Combined Sensitivity Case (***)
In Sections 2.11.1,2.11.4 and 2.11.5 above,the influences of
world oil price,real coal price escalation,and gas
availability for baseload generation on Susitna project economics
were tested.In the combined sensitivity case the Wharton oil
price forecast,real coal price escalation and gas availability
influences were reanalyzed together with natural gas prices based
on the Enstar gas pricing methodology.
The Enstar methodlogy establishes the well head price of Cook
Inlet gas in relation to the world oil price,as described in
Appendix 01.Table 0.2.11.7 summarizes the results of the
combined effects of the variables and shows that the Susitna
Project remains attractive with net benefits of $0.8 billion and
a benefit-cost ratio of 1.15.
2.12 -Conclusions (***)
Although stated in various terms throughout this Exhibit,the conclu-
sion of the OGP analysis of Railbelt expansion plans is that the
Susitna Project would have a benefit/cost ratio (greater than 1.0 over
the planning period of 1996-2054.Therefore,the Applicant concludes
that the three-stage Susitna Hydroelectric Project is the economically
preferred alternative for meeting the Railbelt electric demand.
l
851102 0-2-40
r-
3 -CONSEQUENCES OF LICENSE DENIAL (***)
3.1 -Statement and Evaluation of the Consequences of License
Denial (***)
The enabling legislation for the Alaska Power Authority establishes
that "it is declared to be the policy of the state,in the interest
of promoting the general welfare of the people of the state and public
purposes,to reduce consumer power costs and otherwise encourage the
long-term economic growth of the state,including the development of
its natural resources through the establishment of power projects."
On the basis of extensive study,diligently pursued over a period of
years,the Alaska Power Authority has found the Susitna Hydroelectric
Project to be the least-cost means of meeting the power needs of the
Railbelt for well into the 21st Century.The costs of Susitna power
will be substantially fixed;these costs will be lower than those from
alternative hydro projects and also alternative thermal projects under
any credible scenario for the future cost of fuels.If the Commission
denies the License to build Susitna,it will foreclose for the citizens
of the Railbelt the least-cost opportunity of meeting their electricity
needs.
The assured energy supply which Susitna represents will foster
long-term economic growth in the state.If the Commission disapproves
Susitna,electric utilities in the Railbelt area will have to
participate in a series of shorter horizon measures for power
generation;the reduced certainty of energy supply and the reduced
certainty of the cost thereof,will be less condusive to long-term
economic growth than a Susitna-based generation system.
In economic terms,the effect of the Commission's denying the License
would be to cause the Railbelt power consumers to forego the net
benefits of Susitna compared to the cost of the next-most attractive
alternative.The present value of these net benefits will amount to
approximately $2.3 billion in 1985 dollars with either of the two
principal oil price forecasts presented herein.The environmental
costs of denying the License are also substantial in view of the
environmental impacts associated with the alternatives.These impacts
are described in more detail in Exhibit E,Chapter 10,Section 4 of
this Application.
3.2 -Future Use of the Dam Sites if the License ~s Denied (***)
The dam sites have no present economic purpose.It is expected that,
in the absence of construction of the dams,the present situation would
continue.
851102 D-3-l
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4 -FINANCING (***)
4.1 -General Approach and Procedures (***)
The financial analysis of the Susitna project utilizes the economic
analysis described in Section 2.10 of this Exhibit and recasts it in
nominal terms using the parameters set forth in Table D.4.1.1.
Estimated bond requirements are derived based on assumed cash flows.
Based on the bond requirements,annual debt service is obtained,which,
along with other operating costs,determines the total annual revenues
req uired.
Rate stabilization will be used to reduce retail costs during the
initial years of operation of the With-Susitna plan to a level equal to
the cost of the Without-Susitna alternative.Rate stabilization funds
are assumed to be provided by State contributions.Once Susitna energy
costs become less than the energy cost of the Without-Susitna
alternative,the difference between the costs of the two plans becomes
a regional benefit due to the lower and more stable cost of energy from
the With-Susitna plan.The levelizing of front-end costs associated
with the Susitna project through the device of rate stabilization
payments enhances market confidence in the ability of the Railbelt
customer rate base to support the debt servicing requirements of the
project's financing.
4.2 -Financing Plan (***)
4.2.1 -Tax-exempt Revenue Bonds (***)
The construction costs of Susitna are anticipated to be funded
through the issuance of tax-exempt revenue bonds.The bonds will
be secured by revenues from the sale of Susitna power.
Bond requirements are estimated using a bond issuance computer
program using the cash flow shown in Table D.4.2.1 and the
financial parameters set forth earlier.It is anticipated that
cost incurred prior to the issuance of the FERC license will be
funded through continuing State appropriations.Such costs
incurred after June 30,1985 are assumed to be reimbursed to the
State from bond proceeds.Interest is capitalized through the
entire construction period.
Annual revenue bond requirements in nominal dollars,and their
application,are shown in Table D.4.2.2.Constant dollar bond
requirements are also shown.Thus in real terms (1985 dollars),
the annual bonding requirements average about $415 million
although the amounts shown would shift from year to year
depending on interest rate conditions.The Applicant anticipates
securing tax-exempt status for Susitna financing through
implementation of direct billing,which is discussed in the
following section.
851102 D-4-1
4.2.2 -Direct Billing (***)
Alaska Senate Bill 290 and House Bill 389 introduced in the last
session of the Legislature will amend the Alaska Power
Authority's enabling statute to permit the Applicant to charge
direct service charges for the purchase of power generated by
means of facilities owned or financed by the Applicant,to retain
power customers.The proposed legislation also provides that the
Applicant may enter into one or more agency agreements with a
distributor of power relating to the billing and collection of
these service charges.
This proposed legislation is advanced to provide a possible means
of tax-exempt financing of the Susitna Project.Section 103(b)
of the Internal Revenue Code restricts the use of tax-exempt
bonds for financing power projects which are secured by payments
to be made under Power Sales Agreements with non-governmental
entities,which include rural electric associations,such as
Chugach Electric Association (CEA).The restriction applies when
the project is located within more than two political
subdivisions and more than 25 percent of output is sold under a
power sales agreement to an entity like CEA.Unless other means
are found,these restrictions would seem to preclude tax-exempt
status if the poWer output of the Susitna Project were to be sold
to Railbelt utilities pursuant to conventional power sales
agreements.The direct billing procedure under agency agreements
envisioned by the aforementioned legislation is designed to
provide such an alternative means,although confirmation from the
Internal Revenue Service will perhaps be necessary before
financing of the project on this basis could proceed.
The Applicant has met with the Railbelt utilities on an ongoing
basis for the past year to negotiate agency agreements.
Representatives of the utilities have expressed an interest in
considering a plan that,would permit the Applicant to bill the
consumer directly with the utilities acting as the "agent"in the
billing process in order to achieve tax-exempt status for the
project.Negotiations for these agency agreements are expected
to be concluded in early 1986.
4.2.3 -Legislative Status of Alaska Power Authority and Susitna
Project (***)
The Alaska Power Authority is a public corporation of the State
in the Department of Commerce and Economic Development but with
separate and independent legal existence.
The Authority was created with all general power necessary to
finance,construct,and operate power production and transmission
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851102 D-4-2
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facilities throughout the State.The Authority is not regulated
by the Alaska Public Utilities Commission,but is subject to the
Executive Budget Act of the State and must identify projects for
development in accordance with the project selection process
outlined within Alaska Statutes.The Authority must receive
legislative authorization prior to proceeding with the issuance
of bonds for the financing of construction of any project which
involves the appropriation of State funds or a project which
exceeds 1.5 megawatts of installed capacity.
The Alaska legislature has specifically addressed the Susitna
project in legislation (Statute 44.83.300 Susitna River
Hydroelectric Project).The legislation state.that the purpose
of the project is to generate,transmit and distribute electric
power in a manner which will:
o Minimize market area electric power costs;
o Minimize adverse environmental and social impacts while
enhancing environmental values to the extent possible;
and
o Safeguard both life and property.
Section 44.83.36 Project Financing states that "the Susitna River
Hydroelectric Project shall be financed by general fund
appropriations,general obligation bonds,revenue bonds,or other
plans of finance as approved by the legisla ture."
Two pieces of legislation are required for the current finance
plan.First,further legislative action is required to assure
adequate funding of rate stabilization payment obligations to be
undertaken by the state.Second,as previously discussed,
legislation will be required to provide for direct billing for
the project so as to secure tax-exempt status for project
financing.Appropriate legislation to accomplish both objectives
was introduced into the 1985 legislative session and held over
for consideration in the 1986 session.It is anticipated that
this legislation will be acted upon during the next session.
4.3 -Annual Costs (***)
As stated previously,construction of Susitna is anticipated to be
funded through the issuance of tax-exempt revenue bonds.The average
annual cost of energy from the Susitna Project itself has been
estimated for the years 1999 through 2024 and is set forth in Table
D.4.3.1.Costs include debt amortization and other operating costs and
take into account the anticipated on-line date of each phase.Annual
costs per unit of Susitna Project energy are shown in both nominal and
rea 1 do llars •
851102 D-4-3
4.4 -Market Value of Power (***)
The Susitna project is schedule to begin generating power for the
Railbelt in 1999.At that time,the project will meet growing
electric demand,replace retiring units,and displace capacity having
more expensive operating costs.
The market value of Susitna power is based on an assessment of the cost
of power to the Railbelt system had Susitna not been built.The
least-cost Without-Susitna expansion plan is based on a combination of
coal and gas-fired units,and the capital and operating costs of the
alternative system have been established in a manner similar to that of
Susitna.
Table 0.4.4.1 shows that without rate stabilization the costs of the
With-Susitna plan in the early years are higher than those incurred
under the alternative Without-Susitna expansion plan.In order to
facilitate the maximum use of Susitna and reduce the use of natural gas
for electrical generation,Susitna power is anticipated to be priced
such that the Susitna system is no higher in cost than the alternative
system.Therefore,rate stabilization will be used in the early years.
The actual amount will vary depending on the outcome of contract
negotiations with the utilities.
4.5 -Rate Stabilization (***)
Oue to the capital intensiveness of Susitna,the cost of energy from
the With-Susitna system is higher in the short term than the least-cost
Without-Susitna System (See Figure 0.4.5.1).In order to eliminate the
higher initial costs of Susitna,rate stabilization has been included
in the finance plan.
The rate stabilization fund will be provided through State
contributions and sized such that with interest earnings the fund will
be sufficient to offset annual costs in the early years of operation to
a level that would have been experienced with the least-cost thermal
alternative.Interest earnings are anticipated to commence accruing to
the fund in fiscal year 1987.Table 0.4.5.1 depicts the required State
contribution for rate stabilization,interest earnings,and annual
payments from the fund given the bond requirements developed above and
other system costs With-and Without-Susitna.With interest earnings,
the required State contribution for rate stabilization is about $220
million for the SHCA and Composite forecasts.
4.6 -S~nsitivity Analyses (***)
The Applicant recognizes that the actual level of fuel prices,power
requirements and other parameters may differ from that assumed.An
important variable is the world oil price forecast.
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851102 0-4-4
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Oil price effects on fuel prices are discussed in Exhibit D,Appendix
Dl.The impact of oil prices on power requirements is discussed in
Exhibit B,Section 5.4.Should oil prices follow the Wharton forecast
which exhibits oil prices lower than either the SHCA and Composite
forecasts,the required state contribution would be about $710
million.
In the combined sens~t~v~ty case (Section 2.11.6)the Wharton oil price
forecast was further analyzed.In this analysis real coal price
escalation and gas availability assumptions were relaxed and natural
gas prices were based on Enstar gas pricing methodology.Under these
assumptions the required state contribution would be $850 million.
851102 D-4-5
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5 -REFERENCES
Acres American,Inc.December 1981.Susitna Hydroelectric Project
Development Selection Report.Prepared for the Alaska Power
Authority.
Acres American,Inc.1982.Susitna Hydroelectric Project,Feasibility
Report.Design Development Studies.Final Draft.Prepared for the
Alaska Power Authority.
Alaska Power Administration.1984.Alaska Electric power Statistics
(1960-1983).Ninth Edition.U.S.Department of Energy.Sept.
Alaska Power Authority.1984.Comments on the Federal Regulatory
Commission Draft Environmental Impact Statement of May 1984.Vol.
4,Appendix II -Evaluation of Non-Susitna Hydroelectric
Alternatives.Susitna Hydroelectric Project,FERC Project No.
7114.
Battelle Pacific Northwest Laboratories.1982.Railbelt Electric Power
Alternatives Study.Vol.VI:Existing Generating Facilities and
Planned Additions for the Railbelt Region of Alaska.
Caterpillar Tractor Co.1981.Caterpillar Performance Handbook.
Peoria,Illinois.October,1981.
Code of Federal Regulations.1982.Title 18,Conservation of Power and
Water Resources,Parts 1 and 2.Government Printing Office,
Washington,D.C.
Corey,G.D.1982.Plant Decision Making in the Electrical Power
Industry.In:Lind et al.(eds.),Discounting for Time and Risk ~n
Energy Policy.Washington,D.C.
Department of the Air Force.1985.Letter from H.Bargar,Chief Energy
Engineer,Department of the Air Force,to W.Dyok,Harza/Ebasco
Susitna Joint Venture,January 1985.
Department of the Army.1985.Letter from H.Froehle,Director of
Engineering and Housing,Corps of Engineers to W.Larson,
Harza/Ebasco Susitna Joint Venture,January 31,1985.
Electric Power Research Institute.1982.Technical Assessment Guide.
Special Report.Technical Evaluation Group,EPRI Planning and
Evaluation Division.P-24l0-SR.Palo Alto,California.
Federal Energy Regulatory Commission.1984.Susitna Hydroelectric
Project draft Environment Impact Statement.FERC No.7114.Volume
6:Appendices Land M.
851102 D-5-1
Harza-Ebasco Susitna Joint Venture.1985.Definition and Costs of
Thermal Power Alternatives to Susitna.Final Report.Prepared for
Alaska Power Authority,Anchorage,Alaska.
Phung,D.L.1978.A Method for Estimating Escalation and Interest
During Construction.Institute for Energy Analysis,Oak Ridge L
Associated Universities.April,1978.
Roberts,W.S.1976.Regionalized Feasibility Study of Cold Weather
Earthwork.Cold Regions Research and Engineering Laboratory,
Special Report 76-2.July,1976.
State of Alaska.1982.Alaska Agreements of Wages and Benefits for
Construction Trades.In effect January 1982.
U.S.Army Corps of Engineers.1980.Cost Estimates -Planning and
Design.Engineering Manual 1110-2-1301.July 31,1980.
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851102 D-5-2
TABLES
TABL ED.1 .1.1:SUMMARY OF SUSITNA COST ESTIMATE
JANUARY 1985 DOLLARS $X 10 6
r I CATEGORY WATANA (SI)DEVIL CANYON (SIl)WATANA (SIl 1)TOTAL
Production Plant $1,422 $990 $852 $3,264
I Transmission Plant 460 64 135 659
I General Pla nt 5 6 1 12
Indirect 349 180 184 713
i Total Construction $2,236 $1,240 $1,172 $4,648
f
Overhead
Construction 446 154 147 747
10TAL PROJECT
CONSTRUCTION COST $2,682 $1,394 $1,319 $5,395
Economic Analysis (0 percent inflation,3.5 percent interest)
Escalation
AFDC 399 236 146 781
1-
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10 TAL PROJECT mST $3,081 $1,630 $1,465 $6,176
Financial Analysis (5.5 percent inflation,9.0 percent interest)
Es calation 1,863 1,935 3,544 7,342
AFDC 1,879 1,576 1,351 4,806
10 TAL PROJECT COST $6,424 $4,905 $6,214 $17,543
TABLE D.l.l.2:mST ESTIMATE SUMMARY -WATANA STAGE I (Page 1 of 5)f
I
JANUARY 1985 PRI CE LEVEL
Line Amount Totals
Number Description ( x 10 6 )( x 10 6 )Remarks
PRODUCTION PLANT
330 Land &Land Rights $34
331 Powerplant Structures &
Improvements 78
332 Reservoir,Dams &Waterways 857
333 Waterwheels,Turbines &
Generato rs 47
334 Accessory Electrical
Equipment 15
335 Miscellaneous Powerplant
Equipment (Mechanical)12
336 Roads &Railroads 197
Subtotal $1,240
Co nt ingency 182
'IDTAL PRODUCTION PLANT $1,422
TABLE D.1.1.2:(Page 2 of 5)
Line Amount Totals
Number Description ( x 10 6 )( x 10 6 )
TOTAL BROUGHT FORWARD $1,422
TRANSMISSION PLANT
350 Land &Land Rights $6.6
352 Substation &Switching Sta.
Structures &Improveme nt s 4.8
353 Substation &Switching Sta.
Equipment 98.5
354 Steel Towers &Fixtures 171.0
356 Overhead Conductors &
Devices 126.1
359 Roads &Trai 1s 6.0
Subtotal $413.0
Contingency 47.0
TOTAL TRANSMISSION PLANT $460.0
Remarks
l
Page Total $1,882.0
TABL ED.1 .1 .2 :(Page 3 of 5)I
l
Line Amount Totals
Number Description ( x 10 6 )( x 10 6 )Rema rks
TOTAL BROUGHT FORWARD $1,882
GENERAL PLANT
389 Land &Land Righ ts $Included Under 330
390 Structures &Improvements Incl uded under 331
391 Office Furniture/Equipment Incl uded under 399
392 Transportation Equipment Included under 399
393 Stores Equipment Included under 399
394 Tools Shop &Garage Equip.Incl uded under 399
395 Laboratory Equipment Incl uded under 399
396 Power-Operated Equipment Incl uded under 399
397 Connnunications Equipment Included under 399
398 Miscellaneous Equi pment Included under 399 I~,
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399 Other Tangible Property 4 Incl uded under 399
$
{
Subtotal 4 L
Contingency 1
TOTAL GENERAL PLANT $5
Page Total $1,887
TABLE 0.1.1.2:(Page 4 of 5)
Line Amount Totals
Number Description ( x 10 6 )( x 10 6 )Remarks
!-I TOTAL BROUGHT FORWARD $1,887
INDIRECT COSTS
61 Temporary Construction
Facili ties $See Note
62 Construction Equipment See Note
63 Camp &Commissary 274
64 Labor Expense See Note
65 Superintendence See Note
66 Insurance See Note
68 Mitigation 30
69 Fees See Note
Subtotal $304
hj Contingency 45
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L TOTAL INDIRECT COSTS $349
Page Total $2,236
Note:Cos ts under Accounts 61,62,64,65,66 and 69 are included in the
appropriate di rec t cos ts listed above.
TABLE D.l.l.2:(Page 5 of 5)
Line
Number Description
Amount
( x 10 6 )
Totals
( x 10 6 )Remarks
TOTAL BROUGHT FORWARD $2,236
OVERHEAD CONSTRUCTION COSTS (PROJECT INDIRECTS)
71
72
75
76
77
80
Engineering/Adminis-
tration and Environmental
Monitoring
Legal Expenses
Taxes
Administrative and
General Expenses
Interest
Earnings/Expenses during
Construction
TOTAL OVERHEAD
$446
$446
Included in 71
Not Applicable
Incl uded in 71
Not Included
Not Included
TOTAL PROJECT COSTS -
January 1985 Price Level
$2,682
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TABLE 0.1.1.3:mST ESTIMATE SUMMARY -WATANA Stage III
JANUARY 1985 PRICE LEVEL
-1-
(Page 1 of 5)
Line
Ntnnber
330
331
332
333
334
335
336
Descript ion
PRODUCTION PLANT
Land &Land Rights
Powerpland Structures &
Improvements
Reservoir,Dams &
Waterways
Waterwheels,Turbines &
Generators
Accessory Electrical Equip.
Missce11aneous Powerp1ant
Equipment (Mechanical)
Roads &Railroads
Subtotal
Contingency
TOTAL PRODUCTION PLANT
Amount Totals
( X 10 6 ) ( X 10 6 )
$20
22
615
23
5
5
53
$743
109
--
$852
Remarks
TABLE D.l.l.3 (Page 2 of 5)
Line Amount Totals
Number Description ( X 10 6 )( X 10 6 )Remarks
TOTAL BROUGHT FORWARD $852
TRANSMISSION PLANT
350 Land &Land Right $1.1
352 Substation &switching
Station Structures &
Improvements 3.2
353 Substation &switching Sta.
Equipment 33.8
354 Steel Towers &Fixtures 38.7
356 Overhead Conductors &
Devices 42.8
359 Roads &Trails 1.5
Subtotal $121.1
Contingency 13.9
TOTAL TRANSMISSION PLANT $135.0
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Page Total $987.0
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TABLE D.l.l.3 (Page 3 of 5)
Line Amounts Totals
Number Description ( X 10 6 ) ( X 10 6 )Remarks
TOTAL BROUGHT FORWARD $987
GENERAL PLANT
389 Land &Land Right ---Included under 330
390 Structures &Improvements ---Included under 331
391 Office Furniture/Equipment ---Included under 399
392 Transportation Equipment ---Included under 399
393 Stores Equipment ---Included under 399
394 Tools,Shop,&Garage Equip.---Included under 399
395 Laboratory Equipment ---Included under 399
396 Power-Operated Equipment ---Included under 399
397 Communications Equipment ---Included under 399
398 Miscellaneous Equipment ---Included under 399
399 Other Tangible Property 1 Included under 399
Subtotal 1
Contingency 0
TOTAL GENERAL PLANT $1
-
Page Total $988
TABLE D.l.l.3 (Page 4 of 5)
Line Amounts Totals
Number Description ( X 10 6 )( X 10 6 )Remarks
TOTAL BROUGHT FORWARD $988
INDIRECT COSTS
61 Temporary Construction
Faci lities $---See Note
62 Construction Equipment ---See Note
63 Camp &Commissary 156
64 Labor Expense ---See Note
65 Superintendence ---See Note
66 Insurance ---See Note
68 Mitigation 4
69 Fees ---See Note
Note:Costs under Accounts 61, 62,64,65,
66 and 69 are included in the appropriate
direct costs listed above.
Subtotal
Contingency
$160
24
TOTAL INDIRECT COSTS ••-•••••••••••••••••
Page Total
$184
$1,172
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TABLES D.I.I.3 (Page 5 of 5)
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Line
Number Description
TOTAL BROUGHT FORWARD
Amounts
( X 10 6 )
Totals
( X 10 6 )
$1,172
Remarks
OVERHEAD CONSTRUCTION COSTS (PROJECT INDIRECTS)
71
72
75
76
77
80
Engineering/Administration
and Environmental
Monitoring
Legal Expenses
Taxes
Administrative &General
Expenses
Interest
Earnings/Expenses during
Construction
Total Overhead
TOTAL PROJECT COSTS -
January 1985 Price Level
$147
$147
$1,319
Included in 71
Not Applicable
Incl uded in 71
Not Incl uded
Not Included
TABLE D.1.1.4:mST ESTIMATE SUMMARY -DEVIL CANYON STAGE II (Page 1 of 5)
JANUARY 1985 PRICE LEVEL
LINE Amount Totals
Number Description (X 10 6 )( X 10 6 )Remarks
--
PRODUCTION PLANT
330 Land &Land Rights $23
331 Powerplant Structures &
Improvement s 75
332 Reservoir,Dams &Waterways 572
333 Waterwheels,Turbines &
Generators 42
334 Accessory Electrical Equip.17
335 Miscellaneous Powerplant
Equipment (Mechanical)12
336 Roads &Railroads 122-
Subtotal $863
Contingency 127
TOTAL PRODUCTION PLANT $990
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TABLE 0.1.1.4 (Page 2 of 5)
I ~I-
Line
Number De sc ription
Amount
( X 10 6 )
Totals
( X 10 6 )Remarks
350
352
353
354
356
359
TOTAL BROUGHT FORWARD--
TRANSMISSION PLANT
Land &Land Rights
Substation &Switching Sta.
Structures &Improvements
Substation &Switching Sta.
Equipment
S.teel Towers &Fixtures
Overhead Conductors &Devices
Roads &Trails
Subtotal
Contingency
lDTAL TRANSMISSION PLANT
$0.2
10.2
37.8
5.2
2.3
$0.4
$56.1
7.9
$
$
990
64.0
Page Total $1,054
TABLE D.l.l.4 (Page 3 of 5)
Line Amount Totals
Number Description ( X 10 6 )( X 10 6 )Remarks
TOTAL BROUGHT FORWARD $1,054-
GENERAL PLANT
389 Land &Land Rights $---Included under 330
390 Structures &Improvements ---Included under 331
391 Office Furniture/Equipment ---Included under 399
392 Transportation Equipment ---Included under 399
393 Stores Equipment ---Included under 399
394 Tools,Shop,&Garage Equip.---Included under 399
395 Laboratory Equipment ---Included under 399
396 Power-Operated Equipment ---Included under 399
397 Communications Equipment ---Included under 399
398 Miscellaneous Equipment ---Included under 399
399 Other Tangible Property 5
Subtotal $5
Contingency 1
TOTAL GENERAL PLANT $6
-
Page Total $1,060
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TABLE D.1.1.4 (Page 4 of 5)
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Line
Number De script ion
TOTAL BROUGHT FORWARD
INDIRECT COSTS--
Amount
( X 10 6 )
Totals
( X 10 6 )
$1,060
Remarks
61
62
63
64
65
66
68
69
Temporary Construction
Facilities
Construction Equipment
Camp &Commissary
La bor Expense
Supe ri ntendence
Insurance
Mitigation
Fees
$---See Note
See Note
153
See Note
See Note
See Note
4
See Note
Note:Costs under accounts 61,62,64,
65,66 and 69 are included in the
appropriate direct costs listed
above.
Subtotal
Cont ingency
'IDTAL INDIRECT COSTS
157
23
$180
Page Total $1,240
TABLE D.1.1.4 (Page 5 of 5)
Line
Number De scription
IDTAL CDNSTRUCTION COSTS
BROUGHT FORWARD
Amount
( X 10 6 )
Totals
( X 10 6 )
$1,240
Remarks
71
72
75
76
77
80
OVERHEAD CONSTRUCTION COSTS (PROJECT INDIRECTS)
Engineering/Administration
and Environmental Monitoring
$154
Legal Expenses
Taxes
Administrative &General
Expenses
Interest
Earnings/Expenses during
Cons true tion
Total Overhead $154
Included in 71
Not Applicable
Incl uded in 71
Not Included
No t Incl uded
IDTAL PROJECT CDSTS -
January 1985 Price Level $1,394
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TAB4 D.1.2 .1 :SUMMARY OF MITIGATION COSTS INCORPORATED (Page 1 of 3)
IN CONSTRUCTION COST ESTIMATES
JANUARY 1985 PRICE LEVEL
STAGE I STAGE II STAGE III
WATANA DEVIL CANYON WATANA
COSTS INCORPORATED IN
CONSTRUCTION ESTIMATES $X 103 $X 10 3 $X 10 3 Remarks
1.Outlet Facilities $59,000 $12,100 $19,000
2.Restoration of Borrow
Area D ----------Included in 5
3.Restoration of Borrow
Area F ----- -----Included in 5
4.Restoration of Camp and
Village 640 640 625
5.Restoration of Construc-
tion Sites 11,500 1,500 10,000
6.Fencing around Camp 300 300 380
7.Fencing around Garbage
Disposal Area ---------------Included in 6
8.Multilevel Intake Struc-
ture 19,100 N.A.18,900
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Page Total $90,540 $14,540 $48,905
TABLE D.l.2.1 (Page 2 of 3)
STAGE I
WATANA
STAGE II
DEVIL CANYON
STAGE III
WATANA
9.
COSTS INCORPORATED IN
CONSTRUCTION ESTIMATES
Total Brought Forward
Worker Amenities
$X 10 3
$90,540
12,300
$X 103
$14,540
8,100
$X 103
$48,905
7,400
Remarks
10.
11.
12.
13.
14.
15.
16.
17.
18.
Restoration of Haul Roads
Slough Modifications
Habitat Management on
Mitigation Lands
Raptor Compensation
Cultural Resource
Mitigation
Long Term Environmental
Monitoring During Stage
I Construction
Development of Permanent
Recreation Facilities
and Visitor Center
Impoundment Modifications
Other Wildlife Monitoring
Page Total
~
1,400
1,370
440
7,500
9,800
610
1,100
1,200
$126,260
800
705
$24,145
2,400
1,800
$60,505
r-
TABLE D.1.2.1 (Page 3 of 3)
STAGE I STAGE II STAGE III
WATANA DEVIL CANYON WATANA
COSTS INCORPORATED IN
CONSTRUCTION ESTIMATES $ X 10 3 $ X 10 3 $ X 10 3 Remarks
Total Brought Forward $126,260 $24,145 $60,505
19.Community Infra-
structure 4,667 2,712 342
20.Worker Transportation 11,000 ------------
21.Aesthetics 500 ------ ------
r-
SUBTOTAL
Contingency
TOTAL CONSTRUCTION
ENGINEERING &
ADMINISTRATION
$142,427
20,913
163,340
24,501
$26,857
3,943
30,800
4,620
$60,847
8,934
69,781
10,467
TOTAL PROJECT •••••••••••$187,841 $35,420 $80,248 $303,509
TABLE 0.1.4.1:SUSITNA HYDROELECTRIC PROJECT ANNUAL OPERATION,MAINTENANCE AND REPLACEMENT COSTS (Page 1 of 2)
COST ESTIMATE
(t housand 1985$)
Period Watana Stage I 1999-2004 Devil Canyon Stage II 2005-2011 Watana -Stage III 2012-2016 Mature Stage 2017-beyond
Mature M:lt ure
Stage I Susitna Stages Susitna
Stage I Immature Stage II Immature Watana Project Stage III Immature I &:II Project
Cost Est imate Labor Material Total Labor Material Total Total Total Labor Material Total Total Total Labor Material Total
Power Transmission,
Plant &:Admin.3480 1050 4530 660 530 1190 3650 4840 660 530 1190 3650 4840 3290 1050 4340
Contracted Services --1200 1200 --510 510 1200 1710 00 510 510 1200 1710 --1200 1200
Townsite Operations 660 880 1540 420 200 620 1180 1800 420 200 620 1180 1800 780 880 1660
Resource Management,
VisH or Cent er 1250 150 1400 ------1400 1400 ------1400 1400 1250 150 1400
Environmental
Mitigation Svcs.--1350 1350 -- ----1350 1350 ------1350 1350 --1350 1350-----
Subtotal 5390 4530 10020 1080 1240 2320 8780 11100 1080 1240 2320 8780 11100 5320 4630 9950
Cont i ngency (,±)800 680 1480 150 190 340 1310 1650 150 190 340 1310 1650 800 700 1500
TOTAL 6190 5310 11500 1230 1430 2660 10090 12750 1230 1430 2660 10090 12750 6120 5330 11450
r-
r----
TABLE D.l.4.1 (Page 2 of 2)
MANPOWER ESTIMATE
Watana Stage I Devil Canyon Stage II Watana -Stage III Mature stage
1999-2004 2005-2011 2012-2016 2017-beyond
Stage I Central Stage II stage I Central Stage III Susitna Cent ral Project Cent ral
Manpower Watana Dispatch Devil Canyon Watana Dispatch Watana Stages I &:II Dispatch Site Dispatch
Power Transmission
Superintendent 1 ---1 --1 -1
Assistant -1 1 1 -1 1 -1
Line Crew -5 --5 --5 -5
Plant
Chief 1 ---1 --1 -1
Shift Operators 20 -7 -13 7 -13 5 13
PIa nt Mai nt enance 25 1 8 17 1 8 17 1 20 1
Resource Management
Manager 1 - -
1 --1 -1
Rangers 2 --2 - -
2 -2
Resource Specialists 10 --10 - -
10 -10
Visitor Center ,
Manager 1 --1 --1 -1
Stage 4 --4 --4 -4
Admi ni st rat i on
Chief 1 - -
-1 --1 1 1
Clerk/t ypi st 3 -2 1 3 2 1 3 2 3
Townsite
Management,Security,Fire
Protection,Warehouse 11 -7 5 -7 5 -13---
Subtotal 80 7 25 42 25 25 42 25 60 25
TOTAL 87 92 92 85
TABLE D.l.7.1 (Page 2 of 2)
Annual Cash Flow Cummulative Cash Flow
Year St I St II St III St I St II St III
L End Watana Devil Watana Combined Watana Devil Watana Combined
Canyon Canyon
2000 149.4 149.4 2,682.0 584.2 3,266.2
2001 243.7 243.7 2,682.0 827.9 3,509.9
2002 211.8 211.8 2,682.0 1,039.7 3,721.7
2003 218.7 218.7 2,682.0 1,258.4 3,940.4
2004 114.0 114.0 2,682.0 1,372.4 4,054.4
2005 21.6 21.6 2,682.0 1,394.0 4,076.0
2006 147.8 147.8 2,682.0 1,394.0 147.8 4,223.8
2007 203.8 203.8 2,682.0 1,394.0 351.6 4,427.6
2008 197.2 197.2 2,682.0 1,394.0 548.8 4,624.8
2009 286.0 286.0 2,682.0 1,394.0 834.8 4,910.8
2010 271.9 271.9 2,682.0 1,394.0 1,106.7 5,182.7
2011 135.3 135.3 2,682.0 1,394.0 1,242.0 5,318.0
2012 77 .0 77 .0 2,682.0 1,394.0 1,319.0 5,395.0
*Estimated costs related to engineering,administration and environmental studies
expected to be incurred prior to issuance of FERC license and prior to beginning
of construction.
TABLE D.2.2.1:SUSITNA POWER AND ENERGY PRODUCTION (Page 1 of 2)
MONTH
STAGE I
WATANA WATANA
STAGE II
DEVIL CANYON
Capa-1/
hi lity-
(MW)
Average
Energy
(GWh)
Firm 2/
Energy-
(GWh)
Capa-Average
b "l"3/1.1.ty-Energy
'(M'W)(GWh )
Firm
2/Energy-
(GWh)
Capa-Average
b "I"1/1.1.ty-Energy
'(M'W)(GWh )
Firm 2/
Energy-
(GWh)
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total
297
193
204
150
267
365
356
358
371
192
235
276
221
130
152
108
199
263
265
266
267
143
169
205
2388
212
124
147
103
199
171
164
179
216
130
101
187
1933
417
379
340
299
298
374
462
496
503
500
483
454
223
170
169
142
113
91
132
159
172
182
203
220
1976
210
161
166
142
113
91
124
159
168
150
183
203
1870
388
349
337
320
315
322
267
242
266
303
338
364
288
234
250
230
234
231
198
180
191
225
243
271
2775
267
219
242
230
234
226
198
180
191
184
216
246
2623
1/Corresponds to monthly plant capacity output that produces the total estimated
monthly energy available.
2/Firm energy is referred to as reliability energy in OGP and is used in reliability
calculations.
3/Corresponds to four unit capability and is based on monthly net head and turbine
efficiency.
-----r -1-'r-
-1-~------~---~r--
TABLE D.2.2.1 (Page 2 of 2)
STAGE III
MONTH WATANA DEVIL CANYON
Capa Average F1.rm Capa Average F1.rm
b"1"1/Energy 2/b"1"3/Ener g)Energy1.1.ty-Energy-1 1ty-
"(MtYJ (GWh)(GWh)(MW)(GWh (GWh)
Jan 1068 377 349 462 344 326
Feb 1032 297 269 411 276 260
Mar 997 309 286 392 292 282
Apr 963 254 167 350 252 171
May 958 222 215 360 268 268
Jun 1010 179 179 381 274 274
Jul 1083 203 203 355 264 264
Aug 1136 220 220 333 248 248
Sep 1159 259 233 308 222 222
Oct 1156 314 200 376 280 157
Nov 1135 336 220 418 301 177
Dec 1105 365 289 442 329 268
TOTAL 3335 2830 3350 2917
1./Corresponds to six unit capability and is based on monthly net head and
turbine efficiency.
1./Firm energy is referred to as reliability energy in OGP and is used 1n
reliability calcuations.
:1/Corresponds to monthly plant capacity output that produces the total
estimated monthly energy available.
Capital Data
Gross Capacity Per Unit
TABLE D.2.3.1:
Coal-Fired
S team-EI ec tric
217 MW
SUSITNA HYDROELECTRIC PROJECT
THERMAL ALTERNATIVES DATA SUMMARY
Gas-Fired
Simple-eyc Ie
Combustion Turbine
80,000 kW at ISO
89,600 kW at 30°F
(Page 1 of 3)
Gas-Fired
Combi ned Cycle
CT 79,600 kWat ISO
ST 59,125 kW at ISO
Two CTs at 89,100 kW
each;One ST at 59,100
kW,all at 30°F
Units Per Plant
Total Gross Capacity
at 30°F
Aux iliary Loads
Net Capacity at 30°F
Nominal Plant Capacity
Two,one initially wi th
second at later date
217 MW -first unit
434 MW -two unit
17 MW per unit
200 MW -one unit
400 MW -two unit
400MW
Three,one initially with
second and third at later
dates.
268,800 kW
Each CT unit =896 kW
Station Loads for Alc,
Lighting,etc =4,000 kW
Total Aux.=6,688
262,112 kW
262 MW
One 3-unit group as
described above.
237,300 kW
Each CT unit =891 kW
Each ST unit =2,365 kW
Station Loads for Alc,
Lighting,etc =3,300
Total Aux.=7,447
229,853 kW
230 MW
-r ~r-
TABLE D.2.3.1 (Page 2 of 3)
Coal-Fired
Steam-Electric
Capital Cost Data (thousand 1985$)
Gas-Fired
Simple-Cycle
Combustion Turbine
r----
Gas-Fired
Combined Cycle
Unit Direct Capital Cost
Initial
First Extension
Second Extension
Total
Other Costs
Town Site
Owner's Cost
Startup,Parts and Tools
Machinery and Equipment
Land
Subtotal
Total Project Cost
Unit Cost $/kW
Nominal Capacity -MW
Beluga
593,640
385,386
N/A
979,026
18,333
24,476
11 ,044
2,209
2,209
58,271
1,037,297
2,593
400
Nenana
639,713 38,672
399,706 30,537
N/A 30,537
1,039,419 99,746
N/A N/A
25,985 997
11 ,044 499
2,209 N/A
2,209 N/A
41,447 1,496
1,080,866 101,242
2,702 386
400 262
146,138
N/A
N/A
N/A
2,192
1,096
N/A
N/A
3,288
149,426
650
230
Operating and Maintenance Cost Data
Net Generation at Capacity
Factor of 0.80
2,804,000 MWh
(400 MW)
2,804,000 MWh
(400 MW)
1,836,000 MWh 1,612,000 MWh
TABLE 0.2.3.1 (Page 3 of 3)
Coal-Fired
S team-El ec t ric
Gas-Fired
Simple-Cycle
Combustion Turbine
Gas-Fired
Combi ned Cycle
operating and Maintenance Cost Data (Cont'd)(thousand 1985 $)
Total Fixed O&M Costs
Total Variable O&M Costsl/
Total Annual O&M Costs
Annual Nonfuel,Unit
Production Costs -$/MWh
Fixed O&M Unit Costs -$/KW/yr
VariableO&M Unit Costs -$/MWh
Heat Rate Data
24,566 (400 MW)
12,044 (400 MW)
36,610 (400 MW)
13.06
61.42
4.30
2,295
1,071
3,366
1.83
8.76
0.58
3,049
1,070
4,119
2.57
13.26
0.66
Fuel Used (HHV)
Nominal Capacity
Net Station Heat Rate
4,109.6 x 10 6 Btu/hr
400 MW
10,300 Btu/kWh
1045.0 x 10 6 Btu/hr/unit
Total =3135 x 10 6 Btu/hr
262 MW
12,000 Btu/kWh
2110.0 x 10 6 Btu/hr
230 MW
9200 Btu/kWh
1/Capit~l costs for repairs and maintenance are included in variable O&M costs on an annual basis.
These costs,as an annual percentage of the complete plant total project costs,are approximately 0.4%
for the Beluga and Nenana coal plants,0.8%for the three-unit simple cycle plant,and 0.5%for the
combined cycle plant.
-r-'.r-
I
i
1
l
!
I
I
1
I
i
I
I
)
[
TABL ED.2 .4 .1 :NATURAL GAS FUEL PRICES
(1985 $)
SHCA Forecas t Composite Forecast
.Year Oil Gasl/oil GaslJ
($/bb1)($/MMB tu)($/bb1)($/MMBtu)
1985 28.10 2.13 27.10 1.98
1990 27.70 2.08 26.50 1.90
1995 33.70 2.80 31.80 2.65
2000 41.00 3.95 38.10 3.53
2010 61.50 6.83 51.30 5.37
2020 85.00 10.15 68.90 7.85
2030 96.00 11.70 75.00 8.70
2040 106.00 13.12 75.00 8.70
2050 117.00 14.67 75.00 8.70
1/Includes 0.40$/MMBtu charge for natural gas
delivery.
TABLE D.2.4.2:CAPITAL COST ESTIMATE SIMPLE CYCLE
COMBUSTION TURBINE,INITIAL UNIT
(thousand 1985 $)
Account LNumberDescriptionMaterialsInstallationTotal
1.Improvements to Site 305 834 1,139
2.Earthwork and pi ling 98 597 695
4.Concrete 238 806 1,044 I
5.Strct stl/1ft Equipment 1,306 782 2,088
6.Buildings 695 1,095 1,790
1-
7.Turbine Generator 12,812 706 13,518
10.Other Meehan Equip 646 359 1,005
12.Piping 271 523 794
13.Insulation 38 96 134
14.Instrumentation 103 62 165
15.Electrical Equipment 1,560 1,276 2,836
16.Painting 47 171 218
17.Off-Site Fad li ties 310 1,714 2,024
71.Indirect Const Cost °4,478 4,478 [!-
72.Professional Services °2,181 2,181
300.Total Cost w/o Cont 18,429 15,680 34,109
100.Contingency 2,211 2,352 4,563
99.Total Project Cost $20,640 $18,032 $38,672
I
TABLE D.2.4.3:CAPITAL COST ESTIMATE SIMPLE CYCLE
COMBUSTION TURBINE,EXTENSION UNIT
(thousand 1985 $)
L Account
Number Description Materials Installation Total
2.Earthwork and Piling 98 597 695
4.Concrete 238 806 1,044
5.Strct st1/lft Equipment 1,306 782 2,088
6.Buildings 695 1,095 1,790
7.Turbine Generator 12,812 706 13,518
10.Other Meehan Equip 646 359 1,005
12.Piping 271 523 794
13.Insulation 38 96 134
14.Instrumentation 103 62 165
15.Electrical Equipment 1,560 624 2,184
16.Painting 47 171 218
71-Indirect Const Cost 0 2,078 2,078
72.Professional Services °1,306 1,306
300.Total Cost wlo Cont 17,814 10,585 27,019
100.Con ti ngency 2,138 1,380 3,518
99.Total Project Cost $19,952 $10,585 $30,537
TABLE D.2.4.4:CAPITAL COST SUMMARY SIMPLE CYCLE
COMBUSTION TURBINE POWER PLANT
THREE UNITS (thousand 1985 $)
Direct Project Costs
Unit 1 Estimate,Table D.2.4.2
Unit 2 Estimate,Table D.2.4.3
Unit 3 Estimate,Table D.2.4.3
Subtotal
Items Not Included in Estimate
Owners Cost (at 1%of Direct Project)
Startup,Spare Parts,and Special Tools
(0.5%of Direct Project)
Maintenance Shop Machinery,Laboratory Equipment,and
Office Furniture (Equipment Already Exists)
Land (Installed at Existing Site)
Subtotal
Project Total Cost
Average Cost per kW -$/kW
For 3 un1t,262 MW plant
38,672
30,537
30,537
99,746
997
499
1,496
100,242
386
L
TABLE D.2.4.5:SUMMARY OF O&M COSTS 262 MW SIMPLE CYCLE COMBUSTION TURBINE
POWER PLANT (1985 $)
L
Fixed Costs
Staff
Variable
Consumable Materials
Water Treatment
Lubrications
Inlet Air Filtration
Turbine Exhaust
Waste Disposal
Overall and Repair
Total Variable Cost
Total Non-fuel Costs
Total Cost
(thousand $)
2,295
45
85
53
50
48
790
1,071
3,366
Unit Cost
$8.76/kW/yrl/
$0.58/MWhl/
$12.85/kW/yrl/
$1.83/MWh.V
1/Based on net plant unit capacity of 262,000 kW.
l/Based on annual plant generation of 1,836,000 MWh at the assumed
design capacity factor of 80 percent.
L
I
TABLE D.2.4.7:CAPITAL COST SUMMARY COMBINED CYCLE
POWER PLANT (thousand 1985 $)
Direct Project Costs
Table D.2.4.6
Items Not Included in Estimate
Owners Cost (at 1-1/2%of Direct Project)
Startup,Spare Parts,and Special Tools
(at 0.75%of Direct Project)
Maintenance Shop Machinery,Laboratory Equipment,and
Office Furniture (Equipment Already Exists)
Land (Installed at Existing Site)
Subtotal
Project Total Cost
Average Cost per kW -$/kW
For 230 MW Plant
146,138
2,192
1,096
o
o
3,288
149,426
650
TABLE D.2.4.8:SUMMARY OF O&M COST 230 MW COMBINED CYCLE POWER
PLANT (1985 $)
Fixed Costs
Staff
Variable Costs
Consumable Materials
Lime
Water Treatment
Vehicles
Lubricants
Waste Dis posa1
Overhaul and Repair
Total Variable Costs
Total Non-fuel Costs
Total Cost
(thou sand $)
3,049
45
68
35
33
85
804
1,070
4,119
Unit Cost
$l3.26/kw/yr1 /
$0.66/MWhl/
$17.91/kw/yr1
$2.56/MWhl/
l
I
r
[
I
1/Based net plant capacity of 230,000 kw.
1/Based on plant annual generation of 1,612,000 MWh at assumed
capacity factor of 80 percent.I-
I
TABLE D.2.5.1:NENANA AND BELUGA COAL
FUEL PRICES (1985 $)
Beluga Minemouth
Year:Nenana SHeA Composite
L Delivered Forecast Forecast
($/MMBtu)($/MMBtu)($/MMBtu)
I 1985 1.84 1.32 1.42
I
1990 1.99 1.45 1.54
1995 2.14 1.60 1.65
I 2000 2.31 1.78 1.78
2010 2.69 2.13 2.19
r 2020 3.13 2.55 2.57
[
2030 3.64 3.30 3.08
2040 4.24 4.10 3.22
[2050 4.94 5.12 3.74
I
[
[
I
[
I
I
TABLE D.2.5.4:CAPITAL COST SUMMARY BELUGA COAL-FIRED
POWER PLANT TWO UNITS (thousand 1985 $)
Direct Project Costs
Unit 1 Estimate,Table D.2.5.2
Unit 2 Estimate,Table D.2.5.3
Subtotal
Items Not Included in Estimate
Town Si te Co st
Owners Cost (at 2-1/2%of Direct Project)
Startup,Spare parts,and Special Tools
Maintenance Shop Machinery,Laboratory Equipment,
and Office Furniture
Land (200 acres at $10,920 per acre)
Subtotal
Project Total Cost
Average Cost per kW -$/kW
593,640
385,386
979,026
18,333
24,476
11,044
2,209
2,209
58,271
1,037,297
2,593
L
1-
TABLE D.2.5.5:CAPITAL COST ESTIMATE NENANA 200 MW COAL-FIRED
POWER PLANT INITIAL UNIT (thousand 1985 $)
TABLE D.2.5.7:CAPITAL COST SUMMARY NENANA COAL-FIRED
POWER PLANT TWO UNITS (thousand 1985 $)
L
Direct Project Costs
Unit 1 Estimate,Table D.2.5.5
Unit 2 Estimate,Table D.2.5.6
Subtotal
Items Not Included 1n Estimate
Owners Cost (at 2-1/2%of Direct Project)
Startup,Spare parts,and Special Tools
Maintenance Shop Machinery,Laboratory Equipment,
and Office Furniture
Land (200 acres at $10,920 per acre)
Subtotal
Project Total Cost
Average Cost per kW -$/kW
639,713
399,706
1,039,419
25,985
11,044
2,209
2,209
41,447
1,080,866
2,702
GOAL-FIRED POWER PLANT SUMMARY OF O&M
COSTS (1985 $)
TABLE D.2.5.8:
Fixed Costs
Staff
Variab Ie Co st s
200 MW
Plant Cost
(thousand $)
12,283
400 MW
Plant Cost
(thousand $)
24,566
Unit Cost
$61.42/kw/yr
I'I\
f
L
Consumable Materials
Lime c
Water Treatment
Vehicles
Lubricants
Waste Disposal
Overhaul and Repair
Total Variable Costs
Total Non-fuel Costs
1,260 2,520
743 1,486
102 204
55 110
1,814 /3,628
2,05al 4,116
6,032 12,064
18,315 36,630
$4.30/MWh.U
$9l.58/kw/yr
$13.06/MWh1/
1/Capital replacement costs for repairs and maintenance are included
in this figure.There costs,on an annual basis,are approximately
0.4%of the complete Plant total Project costs.
1/Based on 200 MW plant annual generation of 1,402,000 MWh at the
design capacity factor of 80 percent.
r
TABLE D.2.6.l:INSTALLED CAPACITY OF ANCHORAGE-COOK
INLET AREA-DEC.1984 (in megawatts)
HYDRO OIL NATURAL GAS
Hydro
Utili ti esl1
Diesel
Combustion
Turbine
Steam
Turbine Total
Alaska Power
Administration
Anchorage Municipal
Light and Power
Chugach Electric
Associaton
Homer Electric
Association
Matanuska Electric
Association
Seward Electric
Association
Total
30.0
o
17.4
o
o
o
47.4
o
o
o
2.1
o
5.5
7.6
o
329.9
490.4
o
o
o
820.3
o
o
o
o
o
o
o
30.0
329.9
507.8
2.1
o
5.5
875.3
fI i
(
I '
Military Installation~1
Elmendorf AFB
Fort Richardson
Subtotal
Industrial Installations11
Industry
o
o
o
o
2.1
7.2
9.3
9.6
o
o
o
16.0
31.5
18.0
49.5
o
33.6
25.2
58.8
25.6
TOTAL 47.4 26.5 836.3 49.5 959.7
II
1/
11
Data based on Applicant's evaluation of information provided by
the Railbelt Utilities.
Source:Departments of Army and Air Force,January 1985.
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 D.2.6.2:INSTALLED CAPACITY OF THE FAIRBANKS-TANANA
VALLEY AREA-DEC.1984 (in megawatts)
HYDRO OIL COAL
Hydro
Uti li tiesll
Diesel
Combustion
Turbine
Steam
Turbine Total L
Fairbanks Municipal
Utility System
Golden Valley Electric
Association
University of
Alaska
Subtotal
Military Installation~1
Eielson AFB
Fort Greeley
Fort Wainwright
Subtotal
Industrial InstallationsJl
o
o
o
o
o
o
o
o
8.4
17.3
o
25.7
o
5.5
o
5.5
32.2
157.8
o
190.0
o
o
o
o
28.6
25.0
13.0
66.6
15.0
o
22.0
37.0
69.2
200.1
13.0
282.3
15.0
5.5
22.0
42.5
Industry 0 2.8 o o 2.8
TOTAL o 34.0 190.0 103.6 327.6
II Data based on Applicant's evaluation of information provided by
the Railbelt Utilities.
11 Source:Departments of Army and Air Force,January 1985.
~I 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 D.2.6.3:EXISTING AND PLANNED RAILBELT HYDROELEcrRIC GENERATION
Average Energy (GWh)Firm Energy (GWh)
Existing plants Proposed Existing Plants Proposed
Plant Plant
Cooper Sub-Brad ley.Cooper Sub-Bradley.
Month Ekl utnal/Lakell Total Lakel1 Total Ekl utna Lake Total Lakell Total
Jan 14 4 18 41 59 13 4 17 41 58
Feb 12 3 15 39 54 12 3 15 39 54
Mar 12 3 15 31 46 9 3 12 31 43
Apr 10 3 13 26 39 10 3 13 26 39
May 12 3 15 20 35 11 3 14 20 34
Jun 12 3 15 13 28 8 2 10 13 23
Jul 13 4 17 17 34 9 3 12 13 25
Aug 14 4 18 27 45 8 2 10 13 23
Sep 13 3 16 39 55 9 3 12 14 26
Oct 14 4 18 34 52 9 3 12 29 41
Nov 14 4 18 39 57 8 2 10 39 49
Dec 14 4 18 41 59 12 3 15 41 56
Total 154 42 196 367 563 118 34 152 319 471
I_I Source:Acres (1982).
2_1 Scheduled on-line in 1990.
-,
TABLE D.2.6.4:ANCHORAGE-mOK INLET AREA EXISTING PLANT DATA,DEC.1984 (Page 1 0 f 3)
.Operation Period Generat ing Heat Rate Outage Rates
Unit Online Retire capacity @ Gen.O&M Costs (1985 $)Planned Forced
Name Date Date 30°F Capacity Fixed Variable Outage Outage
(MW)(Btu/kWh)($/kW/yr)($/MWh)(%time)(%time)
Alaska Power Administration
Eklutna 1955 2055 30.0 - -19.0
Anchorage Municipal Light and Power
AMLPCTfFl 1962 1990 16.2 15,329 10.12 5.67 12.0 5.0
AMLPCTfn 1964 1990 16.2 15,329 10.12 5.67 9.7 5.0
AMLPCTf~3 1968 1991 19.9 14,089 10.12 5.67 12.3 5.0
AMLPCTf~4 1972 1992 33.8 13,901 10.12 5.67 13 .5 5.0
AM CCf~56 1979 1999 47.5 10,570 12.79 0.92 11.0 5.0
AM CCfF76 1979 1999 109.3 9,365 12.79 0.92 11.0 5.0
AMLPCTf~8 1984 2009 87.0 12,000 12.79 0.92 14.8 5.0
Total AMLP Capacity 329.9
I~
TABLE D.2.6.4 (Page 2 of 3)
Operation Period Generating Heat Rate Outage Rates
Unit On11ne Ret1re Capacity @ Gen.O&M Costs (1985 $)Planned Forced
Name Date Date 30°F Capaci ty F1xed Vanable Outage Outage
(MW)(Btu/kWh )($/kW/yr)($/MWh)(%time)(%time)
Chugach Electric Association
BEL CT4F1 1968 1994 16.1 16,100 11.21 1.40 10.3 5.0
BEL CT1F2 1968 1994 16.1 16,100 11.21 1.40 9.0 5.0
BEL CT1ft3 1972 1999 49.5 12,800 11.21 1.40 12.8 5.0
BEL CT1ft4 1976 1996 10.0 17,500 11.21 1.40 11.5 5.0
BEL CT1ft5 1975 1999 67.3 12,400 11.21 1.40 12.8 5.0
BEL CC1ft68 1976 2007 100.6 9,600 11 .21 1.40 11.5 6.0
BEL CC1F78 1976 2007 100.6 9,600 11.21 1.40 11 .5 6.0
BERNCT1F1 1963 1988 8.9 17,300 10.03 2.19 9.0 5.0
BERNCT1F2 1971 1997 18.4 14,500 10.03 2.19 9.0 5.0
BERNCTtft3 1978 2004 27.2 13,700 10.03 2.19 10.3 5.0
BERNCT1ft4 1981 2004 27.2 13,700 10.03 2.19 12.8 5.0
1NT CT1F1 1965 1996 14.3 18,000 19.39 13.47 7.7 5.0
1NT CTtF2 1968 1996 14.3 18,000 19.39 13.47 7.7 5.0
1NT CTtft3 1970 1996 19.9 14,500 19.39 13.47 15.4 5.0
mOPER 1960 2055 17.4 - -7.4
Total CEA Capacity 507.8
TABLE D.2.6.4 (Page 3 of 3)
Operation Period Generating Heat Rate Outage Rates
Unit Onl1.ne Ret1.re Capacity @ Gen.O&M Costs (1985 $)Planned Forced
Name Date Date @ 30°F Capaci ty F1.xed Vanable Outage Outage
(MW)(Btu/kWh)($/kW/yr)($/MWh)(%time)(%time)
Homer Electric Association
SELDlCf,b1 1952 1990 0.3 14,998 2.81 38.80 4.0 5.0
SELDlCfF2 1964 1994 0.6 12,006 2.81 38 80 4.0 5.0
SELDlCf,b3 1970 2000 0.6 12,006 2.81 38.80 4.0 5.0
SELDlCf,b4 ·1982 2012 0.6 12,006 2.81 38.80 4.0 5.0
Total HEA Capacity 2.1
Seward Electric System
SES lCfFl 1965 1990 1.5 15,000 0.59 5.72 1.0 5.0
SES lCfF2 1965 1990 1.5 15,000 0.59 5.72 1.0 5.0
SES lCf,b3 1965 1995 2.5 15,000 0.59 5.72 1.0 5.0
Total SES Capacity 5.5
-I--
TABL ED.2.6.5 :FAIRBANKS-TANANA VALLEY AREA EXISTING PLANT DATA,DE C.1984
Operation Period Generating Heat Rate Outage Rates
Unit Onllne Retire Capacity @ Gen.O&M Costs (1985 $)planned Forced
Name Date Date @ 30°F Capacity F1xed Vanable Outage Outage
(MW)(Btu/kWh)($/kW/yr)($/MWh)(%time)(%time)
Fairbanks Municipal Utility System
CHENSTfFl 1954 2000 5.1 15,968 51.12 1.22 6.0 6.0
CHENSTf12 1952 2000 2.0 18,049 51.12 1.22 6.0 6.0
CHENSTfF3 1952 2000 1.5 18,091 51.12 /1.22 /6.0 6.0
CHENSTff4 1963 1985 6.1 12,894 8.761 0.5s!3.0 8.0
CHENSTff5 1970 2005 20.0 14,236 73.57 /0.64 /6.0 6.0
CHENSTff6 1976 2006 26.1 12,733 8.761 0.5s!3.0 8.0
FMUS ICfFl 1967 1992 2.8 12,128 0.87 22.82 2.0 5.0
FMUSI cfn 1968 1992 2.8 12,128 0.87 22.82 2.0 5.0
FMUSICff3 1969 1992 2.8 12,128 0.87 22.82 2.0 5.0--
Total FMUS Capacity 69.2
Golden Valley Electric Association
HEALSTfFl 1967 2002 25.0 12,750 69.96 4.11 7.0 1.8
HEALICff2 1967 1997 2.6 11,210 0.59 5.72 20.0 1.0
NOPOCTfFl 1976 2006 60.9 9,500 7.42 1.43 15.0 1.0
NOPOCTfn 1977 2007 60.9 9,500 7.42 1.43 15.0 1.0
ZEN CTfFl 1971 2001 18.0 14,869 8.79 0.59 15.0 1.0
ZEN CTf12 1972 2002 18.0 14,869 8.79 0.59 15.0 1.0
DSL rcfFl 1961 1991 1.9 11 ,209 0.59 5.72 20.0 5.0
DSL Icfn 1961 1991 1.9 11,209 0.59 5.72 20.0 5.0
DSL ICfF3 1961 1991 1.9 11 ,209 0.59 5.72 20.0 5.0
DSL ICff5 1970 2000 2.6 11,210 0.59 5.72 20.0 5.0
DSL ICff6 1970 2000 2.6 11 ,210 0.59 5.72 20.0 5.0
UAF Icfn 1970 1996 1.9 11 ,209 0.59 5.72 20.0 5.0
UAF rcff8 1970 1996 1.9 11 ,209 0.59 5.72 20.0 5.0
Total GVEA Capacity 200.1
1_/Applicant's estimate of O&M costs used.
TABlE 0.Z.6.6:RAILBELT EXISTING EQUIPMENT RETIREMENT SCHEDULE
AIt..P CEA HEA SES fHUS GVEA TOTAL RAILBELT
Annual Cumulative
Capacity Unit Capacity Unit Capacity Unit Capacity Unit Capacity Unit Capacity Unit Capacity Capacity
Year Retired Namel!Retired Name Retired Name Retired Name Retired Name Retired Name Retired Retired Year
(~)(I·W)(~)(~)(~)(1+1)(1+1)(1+1)
1985 6.1 CHENCT 14 6.1 6.1 1985
1986 6.1 1986
1987 6.1 1987
1988 8.9 BERNCT II 8.9 15.0 1988
1989 15.0 1989
1990 32.4 AHLPCT I1&Z 0.3 SELOIC 11 3.0 SESIC 11&2 35.7 50.7 1990
1991 19.9 AIt..PCT 13 5.7 OSLIC 11,2,&3 25.6 76.3 1991
199Z 33.8 AHLPCT 14 8.4 fHUSIC 11,2,&3 42.2 118.5 1992
1993 118.5 1993
1994 3Z.2 BELCT 11&Z 0.6 SELOIC 12 32.8 151.3 1994
1995 2.5 SESIC 13 2.5 153.8 1995
1996 58.5 BELCT 14,3.8 UAflC 17&8 62.3 216.1 1996
INTCT 11,Z,&3
1997 18.4 BERNeT IZ Z.6 HEALIC 12 21.0 237.1 1997
1998 237.1 1998
1999 156.8 AHCC 156&76 116.8 BELCT 13&5 273.6 510.7 1999
2000 0.6 SELOIC 13 8.6 CHENST 11,Z,&3 5.Z OSLIC 15&6 14.4 525.1 2000
ZOO 1 18.0 ZENCT II 18.0 543.1 ZOOI
2002 43.0 HEALST II 43.0 586.1 2002
ZENCT 12
2003 586.1 2003
2004 54.4 BERNCT 13&4 54.4 640.5 2004
2005 20.0 CHENST 15 ZO.O 660.5 2005
2006 26.1 CHENCT 16 60.9 NQPOCT II 87.0 747.5 2006
2007 201.Z BELCC 168&78 60.9 NOPOCT 12 262.1 1009.6 2007
Z008 1009.6 Z008
2009 87.0 AIt..PCT 18 87.0 1096.6 2009
2010 1096.6 2010
ZOl1 1096.6 2011
2012 ----~SELOIC 14 --~1097.2 2012----
T.otal 329.9 490.4 2.1 5.5 69.Z ZOO.1 1097.2
Not Retired:Eklutna 30.0
Cooper ~
Total Online:1144.6
1-1 Key to plant types:CC:Gas-fired combined cycle
CT:Combuation turbine
H:Hydroelectric
IC:Oil-fired internal combuation (diesel)
ST:Coal-fired steam turbine
-1-
I
I
TA BLE D•2 .7•1:RAILBELT SYSTEM ADDITIONS AND RETIREMENTS 1985-1995
Combustion Total Total Total
Year Coal Turbine Diesel Hydroelectric Additions Re ti reme nt s Capability
1985 45 2.5 47.5 6.1 1186
1986 2.5 2.5 0.0 1188
1987 0.0 1188
1988 8.9 1179
1989 0.0 1179
1990 2.5 90 92.5 35.7 1237
1991 25.6 1210
1992 87 87 42.2 1255
1993 0.0 1255
1994 32.8 1222
1995 2.5 1220
TOTALS 132 7.5 90 229.5 153.8
TABLE D.2.7.2:RAILBELT SYSTEM ADDITIONS 1985-1995,PLANT DATA
Operation Period Generat ing Heat Rate Outage Rates
Unit Onl1ne Ret1re Capacity @ Gen.O&M Costs (1985 $)Planned Forced
Name Company Date Date @ 30°F Capacity F1xed Var1ab Ie Outage Outage
(MW)(B tu/kwfi)($/kW/yr)($/MWh )(%t1me)(%t1me)
GTK CT4H HEA/MEA 1985 2010 45.0 12,785 11.21 1.40 9.0 5.0
SES IC414 SES 1985 2006 2.5 15,000 0.59 5.72 1.0 5.0
SES IC415 SES 1986 2006 2.5 15,000 0.59 5.72 1.0 5.0
SES IC416 SES 1990 2010 2.5 15,000 0.59 5.72 1.0 5.0
BRAD LK APA 1990 2055 90.0
AMLPCT419 AMLP 1992 2016 87.0 12,000 12.79 0.92 14.8 5.0
TABLE 0.2.8.1:SHCA LOAD FORECAST
Year
System Sales
Peak Demand Energy
Net Generationl/
Peak Demand Energy
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
(MW)
632
642
651
661
671
681
692
704
715
727
739
743
748
752
756
761
772
784
796
808
821
843
866
889
913
936
(GWh)
3322
3372
3423
3474
3527
3580
3639
3699
3760
3822
3885
3907
3930
3952
3975
3998
4059
4122
4185
4249
4314
4431
4551
4674
4800
4930
(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
1015
10422:./
1064
1087
1110
1133
1157
1182
1207
1232
1258
1285
1312
1340
1369
1398
"1427
(GWh)
3691
3747
3803
3861
3919
3976
4043
4110
4178
4247
4317
4341
4366
4392
4417
4442
4510
4579
4650
4721
4793
4923
5056
5193
5333
54782:./
5594
5712
5833
5957
6083
6212
6343
6478
6615
6755
6898
7044
7193
7345
7501
1/Includes 10 percent for transmission and distribution losses.
2:./The load forecasts produced by the RED Model were extended from
2010 to 2025 using the average annual growth for the period 2000
to 2010.
I
TA BLE D.2.8.2 :COMPOSITE LOAD FORECAST
System Sales Net Generationl/~Year Peak Demand Energy Peak Demand Energy
(MW)(GWh)(MW)(GWh)L
1985 632 3322 702 3691
1986 641 3369 712 3743
\1987 650 3416 722 3796
1988 659 3465 732 3850
1989 668 3513 743 3904
I199067835637533959
1991 691 3630 767 4033
1992 704 3698 782 4109
1993 717 3767 796 4186 I199473038388114264
1995 744 3910 827 4344
1996 751 3948 835 4387
I199775839868434429
1998 766 4025 851 4473
1999 773 4064 859 4516 ~2000 781 4104 868 4560
2001 789 4147 877 4608
2002 797 4191 886 4657
2003 806 4235 895 4706
(2004 814 4280 905 4755
2005 823 4325 914 4806
2006 843 4432 937 4925
2007 864 4542 960 5047
2008 886 4655 984 5172
2009 908 4771 1008 5301
2010 930 4889 10341./54321/
2011 1052 5528
2012 1070 5626
2013 1089 5725
2014 1108 5826
2015 1128 5929
2016 1148 6034
2017 1168 6140
2018 1189 6249
2019 .1210 6359
2020 1231 6471
2021 1253 6586
2022 1275 6702
2023 1298 6820
2024 1321 6941
2025 1344 7063
1./Includes 10 percent for transmission and distribution losses.
1:./The load forecasts produced by the RED Mode 1 were extended from
2010 to 2025 using the average annual growth for the period 2000 to
2010.
TA BLE D.2•8•3:SUMMARY OF THERMAL GENERATING
PLANT PARAMETERS (1985 $)
Combined Combustion
Coal Cy cle/Turbin?
Parameters 200 MW 230 Mwl.87 MW1
Heat Rate (Btu/kWh)10,300 9,200 12,000
Earliest Availability 1992 1988 1988
O&M Costs
Fixed O&M ($/kW/yr)61.42 13 .26 8.76
Variab Ie O&M ($/MWh)4.30 0.66 0.58
Outages
Planned Outages (%)8 7 3.2
Forced Outages (%)5.7 8 8
Construction Period (yrs)6 2 1
Startup Time (yrs)3 2 1
Unit Construction Cost ($/kW)
Beluga/Rail belt 2,593 650 386
Nenana 2,702
Unit Capital Cost ($/kW)l/
Beluga/Railbelt 2,877 673 393
Nenana 2,998
1/Gross output at 30°F is 237.3 MW.and includes correction
for water injection for NOx control.Net output of 230 MW
includes correction for station auxiliary loads.
1/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.
1/Includes AFDC at 1.5 percent interest assuming an S-shaped
expenditure curve.
TA BLE D.2•9•1:WITH-SDSITNA EXPANSION PLAN YEARLY MW ADDITIONS
SHCA Forecast Composite Forecast-
Peak Combustion
Susitna11
Total1.1 Peak Combustion
Sus itna11
Total1.1
Year Demand Coal Turbine Capability Demand Coal Turbine Capabil ity
(MW)(MW)(MW)(MW)(MW)(MW)(MW)(MW)(MW)(MW)
1996 826 1158 835 1158
1997 831 1137 843 1137
1998 836 1137 851 1137
1999 840 297 1160 859 297 1160
2000 845 1146 868 1146
2001 858 1128 877 1128
2002 871 87 1172 886 87 1172
2003 885 1172 895 1172
2004 898 87 1205 905 87 1205
2005 912 491 1674 914 491 1674
2006 937 1584 937 1584
2007 962 1322 960 1322
2008 988 1322 984 1322
2009 1015 17 1252 1008 17 1252
2010 1042 87 1292 1034 87 1292
2011 1064 1292 1052 1292
2012 1087 698 1989 1070 693 1984
2013 1110 1989 1089 1984
2014 1133 1989 1108 1984
2015 1157 1989 1128 1984
2016 1182 1989 1148 1984
2017 1207 87 1990 1168 87 1985
2018 1232 1990 1189 1985
2019 1258 87 28 2105 1210 87 33 2105
2020 1285 87 2192 1231 2105
2021 1312 2192 1253 2105
2022 1340 2192 1275 2105
2023 1369 87 2279 1298 87 2192
2024 1398 2279 1321 2192
2025 1427 2279 1344 2192
11 The three Susitna stages are Watana-Stage I (1999),Devil Canyon-Stage II (2005),and Watana-Stage III
(2012).
11 Includes existing generation plants less retirements
-r
TABLE D.2.9.2 (Page 2 of 2)I
Composite Forecast lEX1st1ngSusitnaSusitna
Thermal Hydro Susitna Capacity Susitna Energy
Rail bel t Capacity Capacity Capacity as Input Energy as Input IYearPeakatPeakatPeakatPeaktoOGP-6 Absorbed to OGP
(MW) (MW)(MW)(MW)(MW)(GWh)(GWh)I
1996 835 698 137 0 0 0 0
1997 843 706 137 0 0 0 0
I19988517141370 0 0 0
1999 859 430 137 292 297 2264 2388
2000 868 435 137 296 297 2277 2388
2001 877 443 137 297 297 2289 2388 l200288645213729729723012388
2003 895 461 137 297 297 2314 2388
2004 905 471 137 297 297 2327 2388
2005 914 0 137 777 788 4243 4477
I20069371213778878842734477
2007 960 35 137 788 788 4303 4477
2008 984 59 137 788 788 4334 4477
2009 1008 66 137 805 805 4488 4571 ~.2010 1034 92 137 805 805 4619 4571
2011 1052 110 137 805 805 4715 4571
2012 1070 0 137 933 1498 5063 5761
2013 1089 0 137 952 1498 5162 5761 (2014 1108 0 137 971 1498 5263 5761
2015 1128 0 137 991 1498 5365 5761
2016 1148 0 137 1011 1498 5471 5761
2017 1168 0 137 1031 1498 5577 5761
2018 1189 0 137 1052 1498 5683 5761
2019 1210 0 137 1073 1522 5796 6685
2020 1231 0 137 1094 1522 5908 6685
2021 1253 0 137 1116 1522 6023 6685
2022 1275 0 137 1138 1522 6139 6685
2023 1298 0 137 1161 1522 6257 6685
2024 1321 5 137 1179 1522 6341 6685
2025 1344 20 137 1187 1522 6461 6685
f
I
\
)
I
I
~
TABLE D.2.9.3:WITHOUT-SUSITNA EXPANSION PLAN YEARLY MW ADDITIONS
SHCA Forecast Composite Forecast-
Peak Combustion Combined Total-V Peak Combustion Combined Tota1 11
Year Demand coal1.1 Turbine Cycle Capability Demand Coal 11 Turbine Cycle Capabili tyrmvr-rmrr (MW)(MW)(MW)(MW)"'01QT (MW)(MW).(MW)
1996 826 1158 835 1158
1997 831 1137 843 1137
1998 836 1137 851 1137
1999 840 400 B 1263 859 400 B 1263
2000 845 87 1336 868 87 1336
2001 858 1318 877 1318
2002 871 1275 886 1275
2003 885 1275 895 87 1363
2004 898 200 N 1421 905 1308
·2005 912 1398 914 200 N 1486
2006 937 200 N 1509 937 1396
2007 962 200 B 87 1534 960 200 N 174 1509
2008 988 1534 984 1509
2009 1015 174 1622 1008 87 1509
2010 1042 1574 1034 200 B 1661
2011 1064 1574 1052 1661
2012 1087 87 1661 1070 1661
2013 1110 1661 1089 1661
2014 1133 1661 1108 1661
2015 1157 87 1748 1128 1661
2016 1182 1748 1148 1661
2017 1207 87 1748 1168 174 1748
2018 1232 1748 1189 1748
2019 1258 200 B 1948 1210 1748
2020 1285 1948 1231 1748
2021 1312 1948 1253 87 1836
2022 1340 1948 1275 1836
2023 1369 1948 1298 1836
2024 1398 1948 1321 1836
2025 1427 200 B 2061 1344 200 B 1948
1.1 B denotes Beluga coal-fired plant;N denotes Nenana coal-fired plant
11 Includes existing generation plants less retirements
TABLE 0.2.9.4:TRANSMISSION SYSTEM EXPANSION,WITliOUT-SUSITNA ALTERNATIVE,SHCA RlRECAST (page 1 of 5)
Required Transmission/Substation Facility
Year
1996
1996
1996
1996
1996
Generation Capacity
Added
Conductor
Size (kc mil)
Length
Miles
Vol tage
kV
230
230
230
230
230
Description
Use existing line between Lorraine and Teeland.
Termination at 230 kV Lorraine substation.
Use two existing lines between Pt.MacKenzie and
Lorraine.Terminations at 230 kV Lorraine sub-
station.
Use existing line between Fossil Creek and Lorraine.
Terminations at 230 kV Fossil Creek and Lorraine Sub-
stations (includes 2-25 MVAR 230 kV reactors).
Use two existing lines between Fossil Creek and
Station-2.Terminations at 230 kV Fossil Creek and
Station-2 substations.
Use two existing lines between Station-2 and Uni-
versity.Terminations at 230 kV Station-2 and
University substations.
Cost of Facility
(thousand 1985 $)
Transmfssion
Substation Linel/
1,590
3,180
3,590
3,490
5,640
Total
1996
1996
1996
1996
1996
1996
1996
1996
2-954
1-1272
1-1272
1-1272
57
26
60
50
345
230
230
230
345
345
230
230
Healy 345 kV substation to Nenana 230 kV substation
(includes 2-30 MVAR 345 kV reactors).
Willow 230 kV substation to Teeland,with termination
at Willow only.
230 kV Palmer substation power supply to existing 115
kV Palmer substation.
230 kV Fairbanks substation power supply to GVEA system.
Use existing line from Gold Creek to Willow.Termina-
tions at 345 kV Gold Creek and 230 kV Willow sub-
stations (Includes 2-30 MVAR 345 kV reactors).
Use existing line from Gold Creek to Healy.Termina-
tions at Gold Creek and Healy 345 kV substations
(Includes 2-30 MVAR 345 kV reactors).
Nenana 230 kV substation to Fairbanks 230 kV substation
Palmer 230 kV substation to Fossil Creek 230 kV sUb-
station.
6,760
1,590
2,.510
5,640
6,040
5,790
9,540
3,180
26,290
9,630
22,220
18,510
-I
TABLE 0.2.9.4 (Page 2 of 5)SHeA FORECAST
Required Transmission/Substation Facility
Generation Capacity
Year Added
Cond uc t or Len gth
Size (kc mil)Miles
Voltage
kV Description
Cost of Facility
(thousand 1985 $)
Transmission
Substation Line!/Total
1996 230 Willow 230 kV substation to Palmer 230 kV substation
(Includes a 300 MVA 230 kV phase shifting transformer).3,800 13,330
1996
1999
1999
1999
1999
1999
1999
1999
1999
1999
1999
2-200 MW-Bel uga
1-1272
1-1272
2-954
2'-954
1-1272
2-954
1-1272
1-1272
48
7
6
91
79
41
57
60
14
230
230
230
345
345
230
345
230
230
230
Energy Management System.
Subtotal 1996
Cont i ngencyl./
Engineering,Administration
and Owners Overheadl/
Total 1996
y
Station-2 230 kV substation to University 230 kV
substation.
Fossil Creek 230 kV substation to Station-2 230 kV
substation.
Gold Creek 345 kV substation to Healy 345 kV sub-
station (Includes 2-30 MVAR 345 kV reactors).
Gold Creek 345 kV substation to Willow 230 kV sub-
station (Includes 2-30 MVAR 345 kV reactors).
willow 230 kV substation to Lorraine 230 kV sub-
station.
Healy 345 kV substation to Nenana 230 kV substation
(Includes 2-30 MVAR 345 kV reactors).
Nenana 230 kV substation to Fairbanks 230 kV sub-
station.
230 kV Palmer substation second transformer.
Lorraine 230 kV substation to Fossil Creek 230 kV
substation (Includes 4 miles of submarine cable which
has 2~25 MVAR 230 kV reactors).
11 ,540
73,880
11 ,080
12,740
97,700
3,180
2,460
5,790
6,920
2,460
6,920
2,460
2,510
2,870
89,980
13,500
15,520
119,000
2,590
2,220
41,980
36,440
15,180
26,290
22,220
52,400
216,700
TABLE 0.2.9.4:(Page 3 of 5)SHCA FORECAST
Required/Substation TrllnsmiSllion Fa~Jli ty
Generation Capacity
Year Added
1999
1999
Conductor
Size (kc mil)
Length
Miles
Voltage
kV
230
Description
Addition of a phase shifting transformer at 230 kV
Pt.MacKenzie substation.
Energy Management System.
Cost of Facility
(thousand 1985 $)
Transmission
Substation Linel/
2,360
11,540
Total
2000 87 MW 115
Subtotal 1999
Cont ingency.U
Engineering,Administration
and Owners Overheadl/
Total 1999
Connection of unit to existing 115 kV
Station-2 substation.
49,470
7,420
8,530
65,420
810
199,320
29,900
34,380
263,600 329,020
Subtotal 2000 810
Contingency!/120
Engineering,Administration
and Owners OverheadJ/140
2004
2006
200 MW-Nena.na
200 MW-Nenana
10
10
230
230
Total 2000
!!/Two terminations of 230 kV line from Nenana
Powerplant at 230 kV Nenana substation.
Subtotal 2004
Cont ingency!/
Engineering,Administration
and Owners Overheadl/
Total 2004
!!I
--r
1,070
~
1,740
260
300
2,300
1,070
2,300
~
TABLE 0.2.9.4:(Page 4 of 5)
Required Transmission/Substation Facility
Year
2007
2007
Generation Capacity
Added
200 MW-Bel uga
87 MW
Conductor
Size (kc mil)
Length
Hiles
48
Voltage
kV
230
115
Description
!!I
Connection between Station-2 unit to existing
115 kV Station~2 substation.
Cost.of Facility
(thousand 1985 $)
Transmission
Substation Linel/
810
Total
Subtotal 2007 810
Cont ingencyl/120
Engineering,Administration
and Owner s Overheadl/140
2009
2012
2015
2-87 MW
87 MW
87 MW
138
115
Total 2007
Two connections at existing NOrth Pole
li8 kV substation.
Subtotal 2009
Cont ingencyl/
Engineering,Administration
and Owners Overheadl/
Total 2009
Connection to high voltage transmission
and substation to match existing voltage.
Subtotal 2012
Cont ingency1/
Engineering,Administration
and Owners Overheadl/
Total 2012
Connection between Station-2 unit and existing
115 kV Station-2 substation.
1,070
3,180
3,180
480
550
4,210
810
810
210
140
1,070
810
1,070
4,210
1,070
Subtotal 2015 810
Contingencyl/120
Engineering,Administration
and Owners Overheadl/140
Total 2015 1,070 1,070
TABLE 0.2.9.4:(Page 5 of 5)SHCA FORECAST
Required Transmission/Substation Facility
Generation Capacity
Year Added
Conductor
Size (kc mil)
Length
Miles
Vol tage
kV Description
Cost of Facility
(thousand 1985 $)
Tra.nsmlSsion
Substation Linel/Total
2017 87 MW Connection to high voltage transmission
and substation to match existing voltage.810
Subtotal 2017 810
Contingency l/210
Engineering,Administration
and Owners Overheadl/140
2019
2025
200 MW-Beluga
200 MW-Beluga
48
48
230
230
!tI
!i/
Total 2017 1,070 1,070
1_/"All new transmission line cost estimates include the cost of terminations.Existing line cost
estimates as described in the table include the cost of terminations only.
2_/Contingency allowance of 15%
3_/Engineering,Administration and Owners Overhead of 15%.
4_/Transmission costs from the Beluga and Nenana plant site to the high voltage power grid
are included in power plant estimates.
~
TABLE 0.2.9.5:TRANSMISSION SYSTEM EXPANSION,WITHOUT-SUSITNA ALTERNATIVE,OOMPOSITE FORECAST
1--
(Page 1 of 5)
Required/Substation Tr~nsmission Facility
Year
1996
Generation Capacity
Added
Conductor
Size (kc mil)
Length
Miles
Voltage
kV
230
Description
Use existing line between Lorraine and Teeland.
Termination at 230 KV Lorraine substation.
Cost of Facility
(thousand 1985 $)
Transmission
Substation Linel/
1,590
Total
1996
1996
1996
1996
1996
1996
1996
1996
1996
1996
2-954
1-1272
57
26
230
230
230
230
345
230
230
230
345
345
Use two existing lines between Pt.MacKenzie
and Lorraine.Terminations at 230 KV Lorraine substations.
Use existing line between Fossil Creek and Lorraine.
Terminations at 230 kV Fossil Creek and Lorraine substa-
tions (includes 2-25 MVAR 230 kV reactors).
Use two existing lines between Fossil Creek and Station-2.
Tenninations at 230 kV F9ssilCreek andStation-2 sub-
stations •
Use two existing lines between Station-2 and University.
Terminations at 230 kV Station-2 and University substa-
stions.
Healy 345 kV substation to Nenana 230 kV substation
(includes 2-30 MVAR 345 kV reactors).
Willow 230 kV substation to Teeland,with termination
at Wi 11ow onl y.
230 kV Palmer substation power supply to existing
115 kV Palmer substation.
230 kV Fairbanks substation power supply toGVEA system.
Use existing line from Gold Creek to Willow.Termina-
tions at 345 kV Gold Creek and 230 kV Willow substations
(Includes 2-30 MVAR 345 kV reactors).
Use existing line from Gold Creek to Healy.Termina-
tions at Gala Creek and Healy 345 kV substations (Includes
2-30 MVAR 345 kV reactors).
3,180
3,590
3,490
5,640
6,760
1,590
2,510
5,640
6,040
5,790
26,290
9,630
1996
1996
1-1272
1-1272
60
50
230
230
Nenana 230 kV substation to Fairbanks 230 kV substation.9,540
Palmer 230 kV substation to Fossil Creek 230 kV substation.3,180
22,220
18,510
TABLE 0.2.9.5:(Page 2 of 5)COMPOSITE FORECAST
Required TransmissionfSub~~~tionFacil~~
Generation Capacity
Year Added
Conductor Length
Size (kc mil)Miles
Vol tage
kV Description
Cost of Facility
(thousand 1985 $)
Transmission
Substation Line!/Total
1996
1996
1-1272 36 230 Willow 230 kV substation to Palmer 230 kV substation
(Includes a 300 HVA 230 kV phase shifting transformer).
Energy Management System
Subtotal 1996
Cont ingency£/
Engineering,Administration
and Owners Overheadl/
3,800
11,540
73,880
11,080
12,740
13,330
89,980
13,500
15,520
1999 2-200 MW-Bel uga 48 230 Y
Total 1996 97,700 119,000 216,700
1999
1999
1999
1999
1999
1999
1999
1999
1999
1999
1-1272
1-1272
2-954
2-954
1-1272
2-954
1-1272
1-1272
7
6
91
79
41
57
60
14
230 Station-2 230 kV substation to University
230 kV substation.
230 Fossil Creek 230 kV substaion to Station-2
230 kV substation.
345 Gold Creek 345 kV substaion to Healy 345 kV
substation (Includes 2-30 MVAR 345 kV reactors).
345 Gold Creek 345 kV substation to Willow 230 kV
substation (Includes 2-30 MVAR 345 kV reactors).
230 Willow 230 kV Substation to Lorraine 230 kV
substation.
345 Healy 345 kV substation to Nenana 230 kV substation
(Includes 2-30 MVAR 345 kV Reactors).
230 Nenana 230 kV substation to Fairbanks 230 kV substation.
230 230 kV Palmer substation second transformer.
230 Lorraine 230 kV substation to Fossil Creek 230 kV
substaion (lncludes 4 miles of submarine cable
which has 2-25 HVAR 230 kV reactors).
230 Add ition of a phase shi fting transformer at 230 kV
Pt.Mackenzie substation.
-I~
3,180
2,460
5,790
6,920
2,460
6,920
2,460
2,510
2,870
2,360
2,590
2,220
41,980
36,440
15,180
26,290
22,220
52,400
-1--
TABLE D.2.9.5:(Page 3 of 5)COMPOSITE FORECAST
Required Transmission/Substation Facility
Generation Capacity
Year Added
Conductor Length
Size (kc mil)Miles
Voltage
kV Description
Cost of Facility
(thousand 1985 $)
Transmission
Substation Line l /Total
!!/Two terminations of 230 kV line from Nenana
Powerplant at 230 kV Nenana substation.
Subtotal 1999
Cont ingencyl/
Engineering.Administration
and Owners Overheadl/
Subtotal 2000
Contingencyl/
Engineering.Administration
and Owners Overheadl/
Subtotal 2003
Contingencyl/
Engineering.Administration
and Owners Overheadl/
1.070
1.070
329.020
11 .540
49.470 199.320
7.420 29.900
8.530 34.380
65.420 263.600
810
8iO
120
140
1.070
810
-
120
140
1.070
1.740
2000
2003
1999
Total
Total
Total
Connection to high voltage transmission
and substation to match existing Voltage
Connection of unit to existing 115 kV
Station-2 substation.
Energy Management System.
230
115
102005200MW-Nenana
2003 87 MW
2000 87 MW
1999
Subtotal 2005
Cont ingency 1/
Engineering.Administration
and Owners Overheadl/
1.740
260
300
Total 2005 2.300 2,300
TABLE 0.2.9.5:(Page 4 of 5)COMPOSITE FORECAST
Required Transmission/Substation Facility
Year
Generation capacity
Added
Conductor
Size (kc mil)
Length
Miles
Vol tage
kV Description
Cost of Facility
(thousand 1985 $)
Transmission
Substation Linel/Total
2007 200 MW-Nenana
2007 2-87 MW
2009 87 MW
10 230
138
!!.I
Two Connections at existing North Pole 138 kV
substation.
Subtotal 2007
Cont i ngency 1:./
Engineering,Administration
and Owners Overheadl/
Total 2007
Connection to high voltage Transmission
and substation to match existing voltage.
3,180
3,180
480
550
4,210
810
4,210
Subtot~l 2009
Contingencyl/120
Engineering,Administration
and Owners Overheadl/140
2010 200 MW-Beluga 48 230 !±/
Total 2009 1,070 1,070
2012 87 MW 115 Connection between unit and existing 115 kV
Station-2 substation.810
Subtotal 2012 810
Contingency 1/120
Engineering,Administration
and Owners Overheadl/140
1-
Total 2012 1,070
-,--
1,070
-,--,
TABLE D.2.9.5:(Page 5 of 5)COMPOSITE FORECAST
Required Tran!mission/Substa~ionFacility
Generation Capacity
Year Added
2017 87 MW
Conductor
Size (kc mil)
Length
Miles
Voltage
kV Description
Connection to high voltage transmission and
substation to match existing voltage.
Cost of Facil i ty
(thousand 1985 $)
Transmission
Substation Lindl Total
810
2017 87 MW 1-1272 230 Connection of new unit to 230 kV Fairbanks
substation.
Subtotal 2017
Cont ingencyll
Engineering,Administration
and Owners Overheadll
870
1,680
250
290
370
370
60
60
Total 2017 2,220 490 2,710
2021 87 MW 115 connection between unit and existing 115 kV
Station-2 substation.810
Subtotal 2021 810
Cont ingencyll 810
Engineering,Administration
and Owners Overheadll 140
2025 200 MW-Beluga 48 230 tU
Total 2021 1,070 1,070
II All new transmission line cost estimates include costs of terminations.Existing line cost
estimates as described in the table include the cost of terminations only.
1.1 Contingency allowance of 15%.
11 Engineering,Administration,and Owners Overhead of 15%.
!:il Transmission costs from the Beluga and Nenana plant site to the high voltage power grid are
included in the power plant estimates.
TABLE D.2.10.1:PRINCIPAL 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:
~-
Combustion Turbines:
Combined Cycle Turbines:
Steam Turbines
Hydroelectric Projects
Transmission
8.Annual Fixed Carrying Charges
25-year
Life
Cost of Money 3.50
Amortization 2.57
.Insurance 0.25
Total 6.32
25 years
30 years
35 years
50 years
50 years
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
\-
TABLE D.2.10.2:EXAMPLE OF REAL INTEREST RATE CALCULATION1I
Inflation Nominal Real
Year Ra tell Debt Service].!Deb t Servi ce!±1
1991 5.0 107.2 102.1
1992 4.9 107.2 97.4
1993 5.2 107.2 92.5
1994 5.3 107.2 87.9
1995 5.1 107.2 83.6
1996 5.1 107.2 79.5
1997 5.1 107.2 75.7
1998 5.1 107.2 72 .0
1999 5.1 107.2 68.5
2000 5.1 107.2 65.2
2001 5.1 107.2 62.0
2002 5.1 107.2 59.0
2003 5.1 107.2 56.2
2004 5.1 107.2 53.4
2005 5.1 107.2 50.8
2006 5.1 107.2 48.4
2007 5.1 107.2 46.0
2008 5.1 107.2 43.8
2009 5.1 107.2 41.7
2010 5.1 107.2 39.6
Real Interest Rate2 1 3.4%
11 This table presents data necessary to calculate the real interest rate for
a 20-year bond issued in 1981.A $1000 denomination has been selected for
the example,through any denomination will produce the same result.Review
of historical data indicates that the yield on 20-year bonds is nearly the
same as the yield on 35-year bonds,and that therefore the real interest rate
calculated for the former is a close proxy for the latter.The table assumes
that a $1000 bond is issued on Jan.1,1991,and that annual payments begin
on Dec.31,1991.
11 The inflation shown for 1995-2010 is the average of inflation rates
forecast for the years 1990-1994.
11 Level nominal debt service for a 20-year,$1000 bond issued at 8.7 nominal
interest.
!±I Level nominal debt service adjusted for inflation,producing debt serV1ce
expressed in Jan 1,1991 dollars.
21 The real interest rate is the discount rate which,when applied to the
stream of real debt service payments,produces a present value equal to the
initial amount of the bond.In this case,a $1000 sum invested at 3.4%
interest would produce the stream of payments shown as "rea l debt service,II
and would then be exhausted at the end of 20 years.
\
I
TA BLE D.2•10.3 :EX-POST REAL INTEREST RATES ON
SELECTED TREASURY ISSUES !1945-1984
Maturity Range Composi te !Year 3-Month 3-5 Year 10-Year 15-Year +Series
1945 -1.9 -7.1 -1.1 -1.1 -1.1 1-1946 -8.1 -6.3 -2.7 -1.3 -1.3
1947 -13.8 -4.2 -1.9 -0.6 -0.6
1948 -6.8 -2.3 -0.8 -0.6 -0.6
f19492.1 -1.1 -0.2 0.7 0.7
1950 0.2 -1.5 -0.2 0.5 0.5
f1951-6.3 -0.9 0.2 0.7 0.7
1952 -4.3 1.4 1.0 1.3 1.3
1953 1.1 2.0 .1.5 1.6 1.6
I19540.5 0.5
1.0 0.9 0.9
1955 2.2 0.7 1.4 0.7 0.7
1956 1.2 1.0 1.5 0.6 0.6 f-1957 -0.3 1.4 1.9 0.8 0.8
1958 -0.9 1.4 1.6 0.7 0.7
1959 2.6 3.2 2.5 1.2 1.2
I
1960 1.3 2.8 1.8 0.4 0.4
1961 1.4 2.5 1.1 -0.2 -0.2 i19621.7 2.2 0.9 -0.5 -0.5
1963 2.0 1.9 0.7 -0.8 -0.8
1964 2.2 1.9 0.4 -1.1 -1.1
1965 2.3 1.3 -0.5 -1.7 -1.7 I
1966 2.0 1.3 -0.6 -2.0 -2.0
1967 1.4 0.5 -0.7 -2.3 -2.3
1968 1.1 0.6 -0.5 -2.1 -2.1
1969 1.3 2.1 0.1 -1.2 -1.2
1970 0.6 2.4 0.2 -0.6 -0.6
1971 0.0 -0.4 -1.7 -1.7
1972 0.8 -1.6 -2.3 -2.3
1973 0.8 -1.1 -1.9 -1.9
1974 -3.1 -0.3 -0.9 -0.9
1975 -3.3 0.2 0.3 0.3
1976 -0.8 -1.1 -1.1
1977 -1.2 -3.1 -3.1
1978 -0.5 -2.4 -2.4
TABLE D.2 .10.4:ECONOMIC ANALYSIS OF SUSITNA PROJECT
1985 Present Worth of System Costs
Million $
2025
I
1996-Annua I Estimated 1996-
Plan Components 2025 Cost 2026-2054 2054
I ·SHCA Forecast
Without-Susitna 1000 MW Coal-Bel uga
[400 MW Coal-Nenana
611 MW SCCT
0 MW CCCT 4627 604.0 3093 7720
I With-Susitna 1023 MW Watana
508 MW Devil Canyon
[
611 MW SCCT 3512 423.3 2015 5527
Net Benefit
of Susitna Plan-Million $2193
f Benefit/Cost Ratio 1.40
[Composite Forecast
I Without-Susitna 800 MW Coal-Bel uga
400 MW Coal-Nenana
698 MW SCCT
OMW CCCT 4479 553.4 2679 7158
f With-Sus itna 1023 MW Watana
508 MW Devil Canyon
I 524 MW SCCT 3384 315.8 1439 4823·
Net Benefit
of Susitna Plan-Million $2335
Benefit/Cost Ratio 1.48
TA BLE D.2•11 •1:FORECASTS OF ELECTRIC POWER
DEMAND NET AT PLANT
SHCA Composite Wharton
Forecast Forecast Forecast
Year MW GWh MW GWh MW GWh
1990 757 3978 753 3959 741 3897
2000 845 4442 868 4560 894 4701
2010 1042 5478 1034 5432 1074 5646
2020 1285 6755 1231 6471 1290 6780
I
!
[
!
\
I
!
I
r
I
TABLE D.2 .11.2:WHARTON FORECAST SENSITIVITY ANALYSIS
1985 Present Worth of System Costs
Mi Ilion $
1996-2025 Estimated 1996-
Plan 2025 Annual Cost 2026-2054 2054
Wharton Forecast
Without-Susitna 4048 570.6 2786 6884
With-Susitna 3351 380.6 1797 5148
Net Benefit-
Million $1736
Benefit/Cost Ratio 1.34
SHCA Forecast
Without-Susitna 4627 604.0 3093 7720
With-Susitna 3512 423.3 2015 5527
Net Benefit-
Million $2193
Benefit/Cost Ratio 1.40
Composite Forecast
Without-Susitna 4479 553.4 2679 7158
With-Susitna 3384 315.8 1439 4823
Net Benefit-
Million $2335
Benefit/Cost Ratio 1.48
TABLE D.2.11.3:DISCOUNT RATE SENSITIVITY ANALYSIS
1985 Present Worth of System Costs
Million $
Plan
SHCA Forecast
Without-Sus i tna
With-Susitna
Real
Discount Rate
(Percent)
4.5
4.5
1996-
2025
3834
3216
2025
Annual
Cost
646.9
488.2
Estima ted
2026-2054
1978
1395
1996-
2054
5812
4611
I
r
r
Net Benefit -Million $
Benefit/Cost Ratio
Composite Forecast
Without-Susitna 4.5
With-Susitna 4.5
Net Benefit -Million $
Benefit/Cost Ratio
1201
1.26
3609 591.4 1720 5329 I
3120 380.5 1048 4168 r
1161
1.28 [
I
I
!
[
TABLE D.2.11.4:WATANA CAPITAL COST SENSITIVITY ANALYSIS
1985 Present Worth of System Costs
$Million
2025
1996-Annual Estimated 1996-
I
Plan 2025 Cost 2026-2054 2054
SHCA Forecast
I Without-Susitna 4627 604.0 3093 7720
With-Susitna 3734 443.5 2107 5841
[Net Benefit-Million $1879
I
Benefit/Cost Ratio 1.32
Composite Forecast
[Without-Susitna 4479 553.4 2679 7158
With-Susitna 3607 336.0 1530 5137
[Net Benefit-Million $2021
I
Benefit/Cost Ratio 1.39
[
I
I
TABLE D.2.11.5:REAL ESCALATION OF COAL PRICE SENSITIVITY ANALYSIS
TABLE D.2.11.6:NATURAL GAS AVAILABILITY FOR BASELOAD GENERATION
1985 Present Worth of Sy stem Co st s
$Million
2025
1996-Annual Estimated 1996-
Plan 2025 Cost 2026-2054 2054
SHCA Forecast
Without-Sus i tna 4595 589.9 3037 7632
With-Susitna 3488 404.0 1913 5400
I Net Benefit-Million $2232
I Benefit/Cost Ratio 1.41
Composite Forecast
I Without-Susitna 4432 552.0 2673 7105
With-Susitna 3374 315.8 1439 4813
I Net Benefit-Million $2292
[
Benefit/Cost Ratio 1.48
I
[
TABLE D.2.11.7:COMBINED SENSITIVITY CASE
Plan
Wharton Forecast
Without-Susitna
With-Susitna
Net Benefit-Mill ion $
Benefit/Cost Ratio
r
1985 Present Worth of Sys tern Cos ts
$Mill ion
\2025
1996-Annual Estimated 1996-
2025 Cost 2026-2054 2054
I
3548 475.6 2206 5754 !
3339 355.0 1645 4984
770 I
1.15
r
r
I
i
TABLE D.4.1.1:FINANCIAL PARAMETERS
General Inflation 5.5%
Revenue Bond Interest Rate 9.0%
Short-term Reinvestment Rate 8.0%
I'Long-term Reinvestment Rate
Bond Amortization Period
Bond Reserve Funds:
Capital Reserve Fund
Working Capital Fund
10.0%
35 years
One Years Debt Service
Two months operating costs
(including debt service)
TABLE D.4.2.2:BOND ISSUE SUMMARY (Millions of Dollars)
SUSITNA HYDROELECTRIC PROJECT
WATANA I DEVIL CANYON II WATANA III TOTAL
NOMINAL 1985
YEAR DOLLARS DOLLARS1I
NOMINAL 1985
DOLLARS DOLLARS1I
NOMINAL 1985
DOLLARS DOLLARS1I
NOMINAL
DOLLARS
1985
DOLLARS
1991'1:.1
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
1,000
1,000
1,000
1,200
1,104
1,500
800
725
687
618
703 (3)
613(3)
789
299
500
500
500
1,000
1,000
1,000
1,300
293
277
249
448
425
402
496
1,000
1,000
1,500
1,500
1,500
500
300
325
308
438
415
393
124
71
1,000
1,000
1,000
1,700
1,604
1,500
1,100
1,000
1,000
1,000
1,300
1,000
1,000
1,500
1,500
1,500
500
300
725
687
618
996
890
789
548
448
425
402
496
325
308
438
415
393
124
71
7,404 4,434 5,800 2,590 7,300 2,074 20,504 9,098
Average Annual Issue (1991-2012)932 413
11 Based on an assumed average annual inflation rate of 5.5 percent.
II Expenditures incurred prior to 1991 are assumed to be funded through
continuing State appropriations.Those costs incurred after June 30,
1985,are assumed to be reimbursed from bond proceeds.
11 IncLudes issues of $200,000,000 and $104,000,000 for 1995 and 1996,
respectively for 345 kV transmission upgrade.
TABLE D.4.3.1:SUSITNA HYDROELECTRIC PROJECT ANNUAL COSTS
(Millions of Dollars)
Calendar Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Debt Service ••.••..•.••669 702 702 702 702 702 1,224 1,251 1,251 1,251 1,251 1,251 1,251
Interest Earni ngs ••••••(70)(70 )(70)(70)(70)(70)(125)(125) (125)(125 )(125)(125)(125 )
---------
Net Debt Service •••••••599 632 632 632 632 632 1,099 1,126 1,126 1,126 1,126 1,126 1,126
Operating Costs ••••••••
Renewals and
Replacement s 24 26 27 28 30 32 37 39 42 44 46 49 51
Total Annual Cost 623 658 659 660 662 664 1,136 1,165 1,168 1,170 1,172 1,175 1,177
Energy Sales (GWh)2,196 2,207 2,220 2,232 2,245 2,257 4,116 4,145 4,174 4,204 4,353 4,480 4,574
Cost/Unit of Sales
(cents/kWh)
-Nominal 28.3 29.8 29.7 29.6 29 .5 29.4 27.6 28.1 28.0 27.8 26.9 26.2 25.7
-1985 Dollars 13.4 13.3 12.6 11.9 11.2 10.6 9.5 9.1 8.6 8.1 7.4 6.9 6.4
Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
Debt Service(I)•••••••1,888 1,942 1,942 1,942 1,942 1,942 1,942 1,942 1,942 1,942 1,942 1,942 1,942
Interest Earnings •••••(200)(200) (200)(200) (200)(200)(200) (200)(200)(200)(200)(200) (200)
Net Debt Service ••••••1,688 1,742 1,742 1,742 1,742 1,742 1,742 1,742 1,742 1,742 1,742 1,742 1,742
Operating Costs and
Renewals·.and
Replacements 54 57 60 64 67 64 67 71 75 79 83 88 93
Total Annual Cost 1,742 1,799 1,802 1,806 1,809 1,806 1,809 1,813 1,817 1,821 1,825 1,830 1,835
Energy Sales (GWh)4,911 5,007 5,105 5,204 5,307 5,404 5,512 5,622 5,731 5,842 5,955 6,069 6,151
Cost/Unit of Sales
(cents/KWh)
-Nominal 35.5 35.9 35.3 34.7 34.1 33.4 32.8 32.2 31.7 31.2 30.6 30.2 29.8
-1985 Dollars 8.4 8.0 7.5 7.0 6.5 6.0 5.6 5.2 4.9 4.5 4.2 3.9 3.7
--r-
TABLE D.4.4.1:VAL DE OF POWER (Page 1 of 2)
(Millions of Dollars)
SHCA FORECAST
SAVINGS (LOSSES)ACCRUED SAVINGS
SYSTEM SYSTEM wls USIT NA wls USIT NA RATE
COSTS COSTS STABILIZATION
YEAR W/SUSITNAll wlo SUSI TNAll NOMINAL $1985$NOMINAL $1985$REQUIRED
1985 121.4 121.4
1986 124.3 124.3
1987 131 .1 131.1
1988 145.2 145.2
1989 159.3 159.3
1990 167.2 167.2
1991 176.5 176.5
1992 187.3 187.3
1993 200.5 200.5
1994 286.8 286.8
1995 321.2 321.2
1996 339.6 339.6
1997 370.8 370.8
1998 405.7 405.7
1999 853.1 755.9 (97.2)(45.9)(97.2)(45.9 )97.2
2000 908.9 804.2 (104.7)(48.9)(201.9)(92.8)104.6
2001 935.6 841.0 (94.6)(40.2)(296.5)(133.0)94.6
2002 985.0 878.8 (106.2)(42.7)(402.7)(175.7)106.6
2003 1,025.0 924.9 (100.1)(38.2)(502.8 )(213.9)100.1
2004 1,079.6 1,097.9 18.3 6.6 (484.5) (207.3)
I 2005 1,239.4 1,146.3
(93.1)(31.9)(577.6) (239.2)93.1
\2006 1,274.5 1,368.8 94.3 30.6 (483.3) (208.6)
2007 1,374.4 1,619.1 244.7 75.3 (238.6)(133.2)
2008 1,449.4 1,676.3 226.9 66.2 (11.7)(67.0)
2009 1,418.6 1,767.3 348.7 96.5 337.0 29.5
2010 1,508.9 1,835.2 326.3 85.6 663.3 115.0
2011 1,544.8 1,908.9 364.1 90.5 1,027.4 205.5
2012 1,857.5 2,007.6 150.1 35.4 1,177.5 240.9
2013 1,910.6 2,093.3 182.7 40.8 1,360.2 281.7
2014 1,913.5 2,189.3 275.8 58.4 1,636.0 340.1
2015 1,918.9 2,325.3 406.4 81.5 2,042.4 421.6
2016 1,924.6 2,463.6 539.0 102.5 2,581.4 524.1
2017 1,973.0 2,633.0 680.0 119.0 3,241.4 643.1
2018 2,122.8 2,876.8 754.0 128.8 3,995.4 771.9
2019 1,983.3 3,183.2 1,199.8 194.3 5,195.3 966.3
2020 2,012.8 3,344.5 1,331.7 204.4 6,427.0 1,170.7
595.8
II Estimated costs of production only for the Rai1be1t utilities.Costs shown
inc1 ude an es timatedamou nt for exis ti ng ut i1 i ty debt service allocated to
generation and tranmission.
TABLE D.4.4.1 (Page 2 of 2)
COMPOSITE FORECAST
SAVINGS (LOSSES)ACCRUED SAVINGS
SYSTEM SYSTEM W/SUSI TNA W/SUSI TNA RATE
OOSTS OOSTS STABILIZATION
YEAR W/SUSI TNAll w/o SUSI TNAll NOMINAL $1985$NOMINAL $1985$REQUI RED
1985 121.4 121.4
1986 124.3 124.3
1987 131.1 131.1
1988 145.2 145.2
1989 159.3 159.3
1990 167.2 167.2
1991 176.5 176.5
1992 187.3 187.3
1993 200.5 200.5
1994 286.8 286.8
1995 321.2 321.2
1996 336.4 336.4
1997 361.3 361.3
1998 390.3 390.3
1999 846.3 775.4 (90.9)(43.0)(90.9)(43.0)90.9
2000 900.0 801.8 (98.2)(44.0)(189.1)(86.9)98.2
2001 925.9 834.1 (91.8)(39.0)(280.9)(125.9)91.9
2002 968.8 867.9 (100.9)(40.6)(381.8)(166.5)100.9
2003 1 ,000.9 922.5 (78.4)(29.9)(460.2)(196.4)78.4
2004 1,042.9 962.0 (80.9)(29.3)(541.1)(225.7)80.9
2005 1,239.4 1,158.9 (80.5)(27.6)(621.6)(253.3)80.5
2006 1,274.5 1,211.7 (62.8)(20.4)(684.4)(273.7)62.8
2007 1,353.3 1,488.8 135.5 41.7 (548.9)(232.0)
2008 1,415.1 1,554.6 139.5 40.7 (409.4)(191.2)
2009 1,364.1 1,642.0 277 .9 76.9 (131.5)(114.4)
2010 1,431.4 1,899.4 468.0 122.7 336.5 8.4
2011 1,486.8 1,967.0 480.2 119.4 816.7 127.7
2012 1,857.5 2,041.9 184.4 43.4 1,001.1 171.2
2013 1,910.6 2,116.6 206.0 46.0 1,207.1 217.2
2014 1,913.5 2,205.2 291.7 61.7 1,498.8 278.9
2015 1,918.9 2,302.0 383.1 76.9 1,891.9 335.8
2016 1,924.6 2,408.7 484.1 92.1 2,366.0 447.9
2017 1,940.8 2,577.0 636.2 114.7 3,002.2 562.6
2018 1,995.8 2,721.6 725.8 124.0 3,728.0 686.6
2019 1,978.4 2,768.5 790.1 128.0 4,518.1 814.5
2020 1,985.1 3,044.0 1,058.9 162.6 5,577.0 977 .1
684.5
II Estimated costs of production only for the Rai1belt utilities.Costs shown
include an estimated amount for existing utility debt service allocated to
generation and tranmission.
I
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TABLE D.4.5.1:RATE STABILIZATION SUMMARY (Page 1 of 2)
(Millions of Dollars)
SHCA FORECAST
JI I YEAR
SYSTEM
COSTS
WIs US ITNAll
SYSTEM
COSTS
wlo SUSI TNAll
RATE COSTS
STABIL IZATI ON STATE PRE-BO ND
REQUIRED CO NTRIBUTION IS SUA NCEl.I
ACCRUED
STATE
CONTRIBUTIONl!
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
121
124
131
145
159
167
176
187
200
286
321
340
371
406
853
909
936
985
1 ,025
1,080
1,239
1,275
1,374
1,449
1,419
1,509
1,545
1,057
1,911
1,914
1,919
1,925
1,973
2,123
1,983
2,013
121
124
131
145
159
167
176
187
200
286
321
340
371
406
756
804
841
879
925
1,098
1,146
1,369
1,619
1,676
1,767
1,835
1,909
2,008
2,093
2,189
2,325
2,464
2,633
2,877
3,183
3,344
97.0
105.0
95.0
106.0
100.0
93.0
595.8
100.0
118.7
218.7
16.8
28.0
32.6
39.3
85.6
91.0
(171.2)
83.2
181.9
165.9
141.3
86.8
0.0
179.6
197.6
217.4
239.1
263.0
289.3
318.2
350.0
385.1
321.8
254.4
168.6
80.6
88.7
11 Estimated costs of production only for the Railbelt utilities.Costs shown include
an estimated amount for existing utility debt service allocated to generation and
t ra nsmi ss ion
Jj Costs incurred prior to July 1,1985,are not shown as those amounts were funded
from 0 ther sources.Amount shown in 1988 is repayment from bond proceeds and
assumed to be deposited into the Rate Stabil ization Fund.
11 Includes interest earnings on the Rate Stabilization Fund starting July 1,1986.
Interest earnings based on an assumed annual reinvestment rate of 10.0 percent.
TABLE D.4.5.1:(Page 2 of 2)
COMPOSI TE FORECAST
YEAR
SYSTEM
COSTS
wls USITNAll
SYSTEM
COSTS
wlo SUSITNAll
RATE
STABILIZATION STATE
REQUIRED CONTRIBUTION
fiSTS
PRE-BONDISSUANCE~/
ACCRUED .
STATE r ..·1fiNTRIBUTIm
1985 121 121 100.0 16.8 83.2 I1986124124118.7 28.0 181.9
1987 131 131 32.6 165.9
1988 145 145 39.3 141.9 1-1989 159 159 85.6 86.8
1990 167 167 91.0 0.0
1991 176 176 (239~6)251.3
1992 187 187 276.4
I1993200200304.1
1994 286 286 334.5
1995 321 321 367.9
1996 336 336 404.7 I1997361361445.2
1998 390 390 489.7
1999 846 755 91.0 443.3
2000 900 802 98.0 384.8
2001 926 834 92.0 326.8
2002 969 868 101.0 253.5
2003 1,001 923 78.0 197.1
1
2004 1,043 962 81.0 131.8
2005 1,239 1,159 81.0 60.1
2006 1,275 1,212 63.0
2007 1,353 1,489 I20081,415 1,555
2009 1,364 1,642
2010 1,431 1,899
2011 1,487 1,967 !2012 1,857 2,042
2013 1,911 2,117
2014 1,914 2,205
2015 1,919 2,302 (2016 1,925 2,409
2017 1,941 2,577
2018 1,996 2,722
2019 1,978 2,769 (-
2020 1,985 3,044
684.5 218.7
11 Estimated costs of production only for the Rai1be1t utilities.Costs shown
include an estimated amount for existing utility debt service allocated to Fgenerationandtranmission.
11 Cos ts incurred prior to July 1,1985,are not shown as those amounts were funded
from other sources.Amount shown in 1988 is repayment from bond proceeds and
!assumed to be deposited into the Rate Stabilization Fund.
J./Includes interest earnings on the Rate Stabilization Fund starting July 1,1986.
Interest earnings based on an assumed annual reinvestment rate of 10.0 percent.
\
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FIGURES
I--
I
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DATA ON DIFFERENT
THERMAL GENERATING
SOURCES
--------,
PREVIOUS
STUDIES
CRITERIA
ECONOMICS
ENVIRONMENTAL
4 ITERATIONS
ENGINEERING
LAYOUTS AND
COST STUDIES
OBJECTIVE
ECONOMICS
COMPUTER MODELS TO
EVALUATE
-POWER AND
ENERGY YIELDS
-SYSTEM WIDE
ECONOMICS
CRITERIA
ECONOMICS
SNOW (S)
BRUSKASNA (B)
KEETNA (K)
CACHE (CA)
BROWNE (BR)
TALKEETNA·2 (T-2)
HICKS (H)
CHAKACHAMNA (CH)
ALLISON CREEK (AC)
STRANDLINE LAKE (SL)
•CHi K
-CHi K,S
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CH,K.S a THERMAL
LEGEND
--..,j~STEP NUM8t..
IN STANDARD
PROCESS
FORMULATION OF PLANS
INCORPORATING NON-SUSITNA HYDRO GENERATION FIGURE D.2.2.1
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AL TERNA TlVE HYDROELECTRIC PROJECTS
SUStTNA HYDROELECTRIC PROJECTS.
100,
t
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SCALE IN MILES
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UNIVERSITY
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138KV
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EXISTING NEW ~HEALY NEW NENANA NEW FAIRBANKS
345 KV 230 KV •(!)>z ~:ll::
~W 10 NEW
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FIGURE D.2.e.2
..........
RELIABILITY STUDIES
~~N ~~~~~,~--~'"~~22.5 129~
j :
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Z N '"'1i~97.8 194.4
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:E...'"o.988 L=l.:1'"'.....230 KYGoN
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ISTATION2o.985 L.:.!:.1
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IN 2025 IALLCIRCUITSINSERVICE
'1 !~;1 ±~PT.MCKENZlE G Jr\
230 KV ~1 i~~1 i~~1 !~~j f~1 .006 L:.L.!I~
UNIVERSITY
-j l;;j f;;i l;'/230 KY
;1 f:;j f:~j f:0.973 l=id.
~!!;~N
[1.00lt Lh!N ~~...,.,........,..,.rv-...,..,.~
1 17.6 '"~
~~
I12.6 ~..,..,..,......
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~i·
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Lh!,'"'•,..230 KV~..E!!~;j t;~i t;8ELUGA ~•~~SVC I
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N
N
N
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......
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....
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20252020
1668 I'-'-'-..o....a..at
2192 .,...,.,""'""
WATANA
STAGE m
....,.....,..,...1292
STAGE t·STAGE
WATANA DEVIL CAN ON
i:XISTING&COMMITTED HYDROELECTRIC
19901985
o U=ilJ~-.ki:i:i:i:ld...~==~4LQ5 L....:....L _L_L_L__lJ
2000 2010
YEAR
3r------------------------------------~
6t----+-----+----1f-----+-----'-t--~_:;;;P't"§J~----1---,----I
2ffi\\-\\\-\M\~~~r\_\_lr\-IfJtWtW\_WHf-----+-----+---_+-----,-+-----1
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20252020.20102000
YEAR
1990
0 .....----+-----+-----1~---"'t-----+----__t----+-------I
1985
LEGEND:
o
~~$:ii
HYDROELECTRIC
COAL FIRED THERMAL
GAS FIRED THERMAL
OIL FIRED THERMAL
(Not shown on energy diagram)
WITH •SUSITNA
ALTERNATIVE GENERATION SCENARIO
SHCA LOAD FORECAST .FIGUIIE D.I.I.a
3
2025
.:.:...:..•.•..........•........•..•.•...:.:.:.:.:.:.::::::::::::::
:::::::::::::
:::::::::::::.•......•.••.:::::::::::::
.:::::::::::::,',•.•....•..•.••.•..•..•:.:.:.•.•..•.
2020
1337~""'''''I
12001....1••:.:.:.:.:.:.:.
2010
•....•.....•..........•.•.....•.•.....•..••...•....•..•.::::::::::::::
::::::::::::::
::::::::::::::...•.••.•..•....•....••.•..•.••......•..•.
::::::::::::::
....n"M""l",,"1574
1336
1144
2000
YEAR
1948
.................582
a....-tm'l"...445:::::.:.:.:.:.•..•.•.•..••.•::.:.:::::::::
::::::::::::::
1990
o
1985·
!-
202520202010
,.....:.:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::.....:.:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::
.-''<:l.......~••'".:.::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::'--O<~I"l'!':"':.'.:.::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::.-.............:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::••.•....•••..•.•.•..•...••.•..•.•......•.•.•..•........•......•...........•....•...•••••...•.••.•.•.••.•.•..•..•.•.•.•.........•.•....•....•.•.........•....•........•...........•••..•.•........•.....•.....•...•.••...•.•.•...•..••....•..•.............•.•....•...........••..•.............•.•••......•••..•..•.•..••••....•.•....•.•.•......•.........•.•.••..........•.••......
'-.""'....0'•••;:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::
YEAR
2000
EXJSTING &COMMITTED HYDROELECTRIC
6
8
4
o
1985 1990
LEGEND:
2
I
>(,:,
~w
Zw
o HYDROELECTRIC
.:::::.::COAL FIRED THERMAL
GAS FIRED THERMAL
OIL FIRED THERMAL
(Not shown on energy diagram)
WITHOUT -SUSITNA
ALTERNATIVE GENERATION SCENARIO
SHCA LOAD FORECAST FlGUIlI D.I •••4
3 __----------------------------------,
3:
~2105§2..
1668I
>~1292u«
Q.1«942u
2025
2025
2020.
2020
WATANA
STAGE
2010
2010
STAGE I ST AGE
WATANA DEVIL CAN ON
·2000
YEAR
EXISTING &COMMITTED HYDROELECTRIC
19901985
o l.EialM._m=...a.__...J:;z···:::::··:::::··t4!.::5~__...._J.....;.._l..:...L_L__.J___U
2000
YEAR
LEGEND:
2~~~~~~~~~~~lt_\+-+---------+------+------1f__----'--+_---i
O ......----+-----+-----+-----+-----+-----l~---+---~
1985 1990
8-----......-~-...,...---...,..--------.....,.---~r-----..,.-------,
61-----.-,;.+-....:----+-----+-----+----t------:::J~~==---+_-----I
f
I
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HYDROELECTRIC
COAL FIRED THERMAL
GAS FIRED THERMAL
OIL FIRED THERMAL
(Not shown on energy diagram)
WITH -SUSITNA
ALTERNATIVE GENERATION SCENARIO
COMPOSITE LOAD FORECAST 'IGUR.D.2.e.a
3
3:
:::!20
8
1
>1336t:
(J 1144«a.«(J
582
445
0
1985 '1990 2000
YEAR
8
•...........•.•.............:::::::::::::::.::::::::::::.:....:.:.:.:.
::::::::::::::.:........•...•••..•......•..•......•...••••.••..•....•.•..•..•..•..•..•....•.•...•.............
2010
1661
1137
1748
1137
2020
:::::::::::::.:.:.
Iii
2025
~-
\
1-
202520202010
YEAR
2000
EXISTING-,&COMMITED HYDROELE.CTRIC
TOTAL DISPATCHED ENERGY
1990
LEGEND:
oL---.......---t-----;-----t----+-----+----+------I
1985
.......:.:::::::::....":.::::::::::::::::::::::::::::'
6 r-------t--\-----i-------i-------t--~----r---_=::;~~~.~.~.~..~.:~.:.r;:.t;..~.:~.:~.:~.:~.:~.:J.~:.~:.~:.~:.~:.~:.~:.~:.~::~.:~::~::~::.r:.:.~:.....:.:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::.....:.::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::
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'.':':':':':':':':':::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::.::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::
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HYDROELECTRIC
COAL FIRED THERMAL
GAS FIRED THERMAL
OIL FIRED THERMAL
(NC)t shown 01'1 energy diagram)
WITHOUT -SUSITNA
ALTERNATIVE GENERATION SCENARIO
COMPOSITE LOAD FORECAST FIQURI D.2.I.e
-1-
/
/
/
WITHOl(r SUSITNAt-V
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ld
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1995 2000
YEAR
2005 2010 2015 2020
COMPARISON OF NOMINAL COST OF ENERGY
SHCA LOAD FORECAST
"FIGURE D.4.5.1
(PAGE 1 OF 2)
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~
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1985 1990
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COMPARISON OF NOMINAL COST OF ENERGY
COMPOSITE LOAD FORECAST FIGURE D.4.5.1
(PAGE 2 OF 2)
-1--1-
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D 1 -FUELS PRICING
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SUSITNA HYDROELECTRIC PROJECT
LICENSE APPLICATION
APPENDIX Dl
FUELS PRICING
TABLE OF CONTENTS
............. . .....[-
Title
1 -INTRODUCTION
2 -WORLD OIL PRICE • •· ....·.......·....
Page No.
Dl-l-l
D1-2-1
2.1
2.2
2.3
The Sherman H.Clark Associates Forecast
The Composite Oil Price Forecast
The Wharton Forecast
D1-2-1
D1-2-2
01-2-5
3 -RATUIlAL GAS • • •·....·.•• • •·.••·...D1-3-1
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3.1
3.2
3.3
3.4
Cook Inlet Gas Prices • •
Regulatory Constraints on the Availability
of Natural Gas ••••••• • • •••
Physical Constraints on the Availability
of Cook Inlet Natural Gas Supply • • • •
North Slope Natural Gas •
01-3-1
D1-3-11
D1-3-12
D1-3-21
4 -COAL ••.•. .•·.• •·•··• • •
.• • • •··01-4-1
4.1 Resources and Reserves · · · · ·
01-4-1
4.2 Demand and Supply · · · ····01-4-3
4.3 Present and Potential Alaska Coal Prices 01-4-4
4.4 Alaska Coal Prices Summarized · ·· ··DI-4-10
5 -DISTILLATE OIL .·• • •·•·•·••·••·• • •·DI-5-1
6 -REFERENCES
5.1
5.2
851102
Availabili ty
Distillate Price
. ... .. ... ............ .
i
01-5-1
DI-5-1
D1-6-1
Number
D1.3.1
D1.3.2
D1.3.3
D1.3.4
D1.4.1
D1.4.2
851102
APPENDIX DI
FUELS PRICING
LIST OF FIGURES
Title
BASE CASE NATURAL GAS WELLHEAD NETBACK PRICE CALCULATION
ILLUSTRATION
ALTERNATIVE NETBACK CASES WITH COMPOSITE OIL PRICE
COOK INLET NATURAL GAS RESERVES
THE MCKELVEY DIAGRAM
COAL LEASEHOLDERS IN THE NENANA COALFIELD
MAJOR COAL LEASEHOLDERS
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APPENDIX Dl
FUELS PRI CING
1 -INTRODUCTION
The Susitna Project,when constructed,will be the heart of a modern
system generating electricity for an integrated Railbelt electricity
grid.The Susitna Project therefore must be evaluated on a system-wide
basis comparing the costs of the system with Susitna to those of the
system that would evolve if Susitna is not built.
To determine whether the Susitna-based system expansion plan compares
favorably with its alternatives,the Alaska Power Authority (APA)has
constructed and evaluated an optimal least cost Without-Susitna plan
of generation capacity necessary to meet projected Railbelt electricity
demand over the 1985-2025 expansion planning period.
Exhibit D,Chapter 2,Section 2.9.2,of this application describes the
alternative expansion plan in considerable detail.To summarize,the
Power Authority has determined that a combination of thermal power
plants using coal and natural gas are the indicated components of a
Without-Susitna Railbelt electricity generation system.Through the
use of the Optimized Generation Planning (OGP)model,(described in
Exhibit D),the Power Authority has constructed a thermal-based
alternative expansion plan in which necessary incremental additions to
capacity beyond currently planned projects are selected from among the
feasible thermal alternatives.This selection is based upon a
comparison of the long-term costs of the thermal power plant options,
evaluated at such time as increased demand would warrant additions to
generation capacity.Because fuel costs are major components of the
cost of a system based primarily on thermal power,the Power Authority
has developed a supporting analysis of fuel costs which is set out in
this Appendix D1.
851102 D1-1-1
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2 -WORLD OIL PRICE
Of special.significance to the Applicant's fuel cost analysis is the
projected world price of crude oil.Oil-fired power generation is not
likely to be widely used for Railbelt electricity production.However,
forecasted world oil price directly influences cost assumptions with
respect to all fuels assumed to be available in the thermal alternative
case.As described more fully below,the forecasted world price of oil
in large measure drives the forecasted price of natural gas,and also
influences some components of the projected cost of coal.
Forecasting any future series of oil prices is subject to uncertainties
that are characteristic of commodity markets generally,and oil markets
in particular.To reduce the risks associated with this uncertainty,
the Power Authority has evaluated the Susitna project against the
background of two different oil price forecasts:1)the forecast of
Sherman H.Clark Associates (SHCA)which has been used as a basis for
this case in previous documents (e.g.,Appendix 1 of the Alaska Power
Authority comments on theFERC DEIS,August 1984)and 2)a composite of
six independent oil price forecasts published in 1985 by private
organizations and public agencies.A forecast developed by Wharton
Econometrics (Wharton),which shows a somewhat lower price path than
either of the other two forecasts is used as a low sensitivity
analysis.
2.1 -The Sherman H.Clark Associates Forecast
The SHCA forecast has been used as a basis for the Power Authority's
analysis of the Susitna hydroelectric project in prior submissions to
the FERC (e.g.,Appendix 1 of the comments on the Draft Environmental
Impact Statement filed August,1984,and the July,1983,License
filing).Earlier iterations of the forecast are described in the
comments on the DEIS prepared in August 1984.The forecast was updated
by the Power Authority in February 1985 for the Alaska Power Authority
(SHCA,1985).That update forecast was made in 1984 dollars.It has
been restated,in January 1985 dollars,using the GNP Implicit Price
Deflator series (the conversion factor is 1.0252).The results are
shown below:
851102
Year
1985
1986
1987
1988
1989
1990
1995
2000
Dl-2-1
SHCA Forecast
(1985$/bbl)
$26.09
27.68
27.68
27.68
27.68
27.68
32.80
41.00
Year
2010
2020
2030
2040
2050
SHCA Forecast
(1985$/bbl)
61.50
85.00
96.00
106.00
117.00
The analytic reasoning supporting the SHCA forecast is summarized as
follows:
o The free world economy is projected to grow in real terms at
a long-term rate of about three percent,and this will
increase total demand for energy of all forms (at growth
rates of less than three percent/year);
r
o Real world oil prices will decline slightly and then
stabilize or flatten in real terms during the remainder of
this decade;
o During this period,the incentive to cheat among OPEC
nations will diminish,and OPEC will continue to hold a
significant market position;and
o By the next decade,non-OPEC oil production will face
serious limitations based upon stable and potentially
declining reserves,and will flatten out in the 22.5-23.0
million barrels/day range.OPEC market power will increase
in the 1990s and beyond as a consequence of their position
as the marginal oil producer.
The Without-Susitna thermal alternative plan which results from uS1ng
the SHCA forecast is presented in Exhibit D,Section 2.9.2.
2.2 -The Composite oil Price Forecast
In addition to using the SHCA forecast,the APA has evaluated the
Susitna project or system on the basis of a composite forecast which
represents the average of a range of independent forecasts.The use of
such a composite provides a means for reflecting mainstream oil price
forecasting'opinion and avoids the risk of reliance upon a position
that is significantly above or below the mainstream of informed
opinion.
In developing its composite,the APA considered as a point of
departure,a recent survey of forecasts published by the International
Energy Workshop (lEW)(Manne and Schrattenholzer 1985).The survey
included 36 organizations forecasting oil prices to the year 1990,33
organizations forecasting oil prices to the year 2000,and 11
851102 DI-2-2
organizations making projections to the year 2010.The forecasts were
made during the period 1983-85.The median values shown in the
International Energy Workshop survey of forecasts published during
1984-1985 are shown below.
Year
1990
2000
2010
Forecast
(l985$/bbl)
$39.14
47.67
61.66
What becomes apparent,from an analysis of the survey,is that the
European forecasts tend to be higher than the U.S.forecasts due to
intermingling of oil price effects and currency effects.Accounting
for this currency effect will produce a higher price trend.It is
significant that oil price forecasts have been dropping steadily over
the last four years (Manne and Schrattenholzer 1985).The median oil
price as forecast for the year 2000 has declined as follows:
Date of lEW Survey
December 1981
July 1983
January 1985
Approximate
Index
Value
175
150
109
Approximate
Year 2000 Forecast
(l985$/bbl)
$76.00
65.00
48.00
On this basis,three minimum criteria were established for developing a
composite oil price forecast appropriate for this analysis:
o The forecasting organization must be based in the U.S.to
avoid the intermingling of price and currency effects;
[-
o The forecast must have been performed in 1985 to incorporate
recent experience and to account for current trends;and
o To be meaningful for Power Authority planning purposes,the
forecast must extend at least to the year 2010.
In developing these criteria and in selecting from among available
forecasts,the Power Authority seeks to devise a composite which is
representative of the weight of current forecasting opinion.It is
also considered desirable to have represented in the composite a
variety of forecasting techniques (econometric,scenario,and Delphic).
851102 Dl-2-3
With these objectives 1n mind,the following forecasts were selected 1n
the present analysis:
o Sherman H.Clark Associates (SHCA)
o Wharton Econometrics (Wharton)
o U.S.Department of Energy (USDOE)
o Data Resources Inc.(DRI)
o Cambridge Energy Research Group (CERG)
o Alaska Department of Revenue (ADOR)
World Oil Price by Forecast (1985 $/bbl)
Forecaster
SHCA (1)
Wharton (2)
USDOE (3)
DRI (3)
CERG (3)
ADOR (4)
1985
$28.09
27.12
27.83
25.50
1990
$27.68
24.80
28.34
24.29
34.28
19.21
Year
2000
$41.00
31.26
46.14
37.91
52.48
20.03
2010
$61.50
40.65
71.94
50.95
61.22
21.26
r=
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AVERAGE/COMPOSITE 27.14
Average Growth Rates (%/yr)
26.55 38.14
1985-2010
1990-2010
2000-2010
51.25
2.6
3.4
3.0
(1)SHeA (1985).
(2)French (1985).
(3)Manne and Schrattenholzer (1985).All such forecasts are
represented based upon their index values.
(4)Alaska Department of Revenue (1985).
851102 Dl"';'2-4
extrapolation percentage,and the assumed technological limit to world
oil prices.This composite is shown below.
World Oil Price
Year (l985$/bbl)
1985 $27.10
1990 26.50
1995 31.80
2000 38.10
2005 44.00
r 2010 51.00
2015 59.00
2020 69.00
2023 75.00
The Without-Susitna thermal alternative plan which results from using
the Composite forecast is presented in Exhibit D,Section 2.9.2.
I
2050 75.00
2.3 -The Wharton Forecast
The Wharton Econometric Forecasting Associates (Wharton)forecast was
selected for use as a lower sensitivity forecast to evaluate the
Susitna hydroelectric project.The Wharton forecast is the lowest of
the econometrically based analyses used in the composite.The Wharton
forecast assumes declining or flat demand for oil in the near term,a
phenomenon significantly suppressing demand for OPEC oil.
In the midterm (1986-1994),Wharton expects a modest decline,followed
by a rebounding of oil prices as non-OPEC oil production reaches the
full capacity of non-OPEC producers,as world oil demand begins rising,
and as OPEC members outside the Gulf Cooperation Council begin
producing at or near full capacity.From 1995-2005,Wharton projects a
price increase,largely based upon economic growth.Beyond 2005,
Wharton projects a three percent annual price increase in oil until a
$75/bbl synthetic fuel price cap is reached.
Given the assumptions presented above,the Wharton forecast of world
oil prices (expressed as the prices for Saudi light crude oil)is shown
below (French 1985).
851102
Year
1980
1985
1990
1995
2000
D1~2-5
World Oil Price
(1985$/bbl)
$41.41
27.12
24.80
27.64
31.26
The sensitivity analysis of the present worth of base and alternative
generation plans based on the Wharton forecast are provided in
Exhibit D,Section 2.11.1.
851102
Year
2005
2010
2020
2030
2031
2050
Dl-2-6
World Oil Price
0985$/bbl)
35.07
40.65
54.63
73.42
75.00
75.00 r
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3 -NATURAL GAS
This section describes the Applicant's primary assumptions concerning
the expected price and supply of natural gas that are used in the
evaluation of the thermal alternative expansion plan.
3.1 -Cook Inlet Gas Prices
There are four components used to derive a natural gas price forecast:
1)definition of a pricing methodology,2)development of a data base
for price forecasting calculation,3)calculation of the price
forecast,and 4)confirmation of the price forecast.In developing a
pricing forecast,it must be recognized that the problem is largely of
a long-term nature.Short-term perturbations,therefore,are of less
significance than the fundamentals and trends.
851102
(a)Pricing Methodology
Several methods could be used to determine the price trend
for natural gas,including:1)netback pricing,2)contract
extrapolation,and 3)production costing.Of these options,
the Power Authority believes netback pricing to be the most
appropriate method for measuring natural gas prices over the
long term.
Netback pricing is a means for estimating a value of any
commodity at some point (e.g.,wellhead).It has been
accepted by the State of Alaska as a means for establishing
the wellhead value of natural gas for royalty interest
valuation purposes (see State of Alaska versus Phillips
Petroleum Company,1984,Joint Stipulation of Facts.Also
State of Alaska versus Phillips Petroleum,1984,Settlement
Agreement).Netback pricing requires establishing a market
value for any commodity,and then subtracting all costs
associated with getting the commodity to market in order to
establish a netback value.
Netback pricing of natural gas employs LNG to establish the
marginal or economic value of natural gas.Ultimately,the
economic value determines what consumers will pay unless
regulation forces a lower price and a consequent
underevaluation of the commodity.Currently,exported LNG
provides the highest wellhead value of natural gas,and the
highest value for royalty gas.The Power Authority believes
that for long-term planning purposes it cannot be assumed
that Cook Inlet gas will be priced at anything less than
this economic value.
D1-3-l
Evaluation of the market potential for LNG exports to the
Pacific Rim must begin with an examination of Japanese
markets •.Over the last ten to fifteen years the Japanese
have developed the institutions and infrastructure necessary
to use LNG for industrial,commercial,and general fuel
requirements.They have receiving/gasification facilities
capable of handling tens of millions of tonnes/yr of LNG.
The importation of LNG furthers explicit Japanese policy to
develop alternative energy sources including nuclear,coal,
and LNG in response to the political unpredictability of the
Middle East (Itoh,1985).At the same time,oil will remain
an important fuel (Itoh,1985).Forecasts of MITI reported
by Itoh (1985),Marubeni (1984),and others show oil
consumption as flat in absolute terms,with LNG and other
fuels assuming increasing shares of the market.
LNG has the advantage of supplying a clean burning fuel to
urban areas (Marubeni,1984).Its anti-pollution aspects
make it highly desirable to general industry in Japan
(Marube ni,1984).
Because LNG is a highly desirable fuel in Japan,national
policy has been reinforced with credits by the Export-Import
Bank of Japan,by loans from the Development Bank of Japan,
by exemptions from import duties,and by loans for LNG!users
(Hickel,et al.,1983).Institutionally,then,LNG has been
embedded into the Japanese economy.
The LNG market in Japan is substantial,having grown from
pioneer beginnings in 1969-70 to its current relatively
mature state (Sumitomo 1985).Historical LNG consumption ~n
Japan is summarized below based upon data contained in
Marubeni (1984).
Year
Japanese LNG Consumption
(thousand tonnes)(trillion Btu)
851102
1969
1970
1972
1974
1976
1978
1980
1982
167
958
955
3,775
5,909
11,519
16,779
17,584
DI-3-2
8.8
50.4
50.2
198.6
310.8
605.9
882.6
924.9
That growth trajectory is impressive.
above is 43 percent.Even the growth
signi ficant.
The annual rate of growth shown
before the oil embargo is
The dimensions of the future LNG market in Japan are equally
impressive.Forecasts by the Japanese Ministry of International Trade
and Industry (MITI)as quoted by C.Itoh &Co.,Ltd.(1985)are shown
below:
Year
Japanese LNG Imports
(million tonnes)(quadrillion Btu)TCF
1982 (l)
1990
1995
17.6
36.5
40.0
0.93
1.92
2.10
0.88
1.83
2.00
F
(l)Actua 1 his torica 1 val ues.
Current country-by-country market shares measured by capacity are shown
below (C.Hoh &Co.,Ltd.1985):
Japanese LNG Imports
Country (thousand tonnes)Percent
USA (Alaska)960 3.2
Brunei 5,140 17.1
Abu Dhabi 2,860 9.5
LNG 2,060 6.8
LPG 800 2.7
Indonesia 15,180 50.4
Malaysia 6,000 19.9
TOTAL 30,140 100.1
Alaska is thought to be in a favorable position to increase its exports
of LNG to Japan.Increased LNG shipments from Alaska to Japan would be
consistent with the Japanese strategy of energy supply diversification
(Hickel,et al.,1983).Further,it is reasonably close to Japan
(3,200 nautical miles versus 3,300 nautical miles for Arun,Indonesia,
and 6,500 nautical miles for Abu Dhabi),and its shipments are cost
competitive (Mitsui and Co.1985).Alaska,as part of the U.S.,
represents a source of supply that is politically stable,and stability
among energy suppliers to Japan is considered an objective along with
cost competitiveness (Itoh,1985).Alaska exports of LNG also could
contribute to a redressing of the balance of payments difficulties
between the U.S.and Japan (Hickel,et al.,1983).The calorific value
of Alaska's gas is slightly higher than the calorific value of
competing LNG products when measured on a heat content per unit mass
basis (Mitsui and Co.1985).
851102 Dl-3-3
During this century,LNG opportunities outside Japan will be limited.
However,Korea has signed a contract to import 2 million tonnes/yr of
LNG from Indonesia (equal to 100 BCF of gas or 103 x 10 12 Btu)and is
seeking an additional 1 million tonnes/yr of gas (equal to 50 BCF/yr)
from another source (Marubeni 1984).Taiwan is also progressing toward
LNG imports (Marubeni 1984).Korea,like Japan,follows a strategy of
energy resource diversification.
The long term forecast reported by Marubeni (1984)from the Central
Research Institute of Electric Power Industry (CRIEPI)in Japan calls
for demand of 42 million tonnes of LNG in the year 2000.Beyond the
year 2000 there is little quantitative data available and the Marubeni
report suggests caution in projecting market growth for LNG beyond the
year 2000.
Notwithstanding the above-noted limitations with respect to the ability
to forecast long-term demand in LNG markets,the Power Authority
believes that netback pricing is a reasonable methodology given the
available market data.Moreover,netback pricing has a sounder
analytic footing than either of the alternative methodologies available
for this purpose --(1)pricing by reference to existing clients,or
(2)pricing by reference to estimates of future natural gas production
costs.
With respect to contract pr1c1ng,only a few contracts (Enstar-Shell,
Marathon-Shell,and Phillips)have been entered into in the last
several years.Of these,the Phillips contract uses a netback
methodology.The others employ a methodology under which price is
redetermined periodically by reference to the price of distillate fuel
oil.But,while it is clear that the price of distillate fuel oil is
the economic basis for the price escalator provisions,neither the
contract terms nor information otherwise available offer any basis for
understanding the source of the base contract price.As might be
expected,the Enstar-Shell and Marathon-Shell contracts appear to be
the product of individual negotiations,and there is no basis upon
which to determine whether the factors governing the development of
those contract terms may be generally applicable to future
circumstances.As a result,such agreements make particularly
unreliable tools for forecasting prices for long-term future periods,
particularly for periods beyond the term of the contract.
The Power Authority has also concluded that production costing is not a
reliable method for forecasting the price of natural gas.This is due
largely to the substantial uncertainties associated with geologic data
supporting reserve estimates,a factor that significantly affects the
accuracy of production costs.Past regulatory attempts at the federal
level to determine future production costs of natural gas have been an
adject failure and have been abandoned.The consequence is that·
natural gas production costs cannot be reliably estimated for pricing
purposes.
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851102 Dl-3-4
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851102
(b)The Database for Netback Calculation
In order to establish a netback price for natural gas,it is
necessary to determine a market value for this commodity at
the point of delivery.That market value is considered to
be the world price of crude oil delivered in Japan.The
relationship between LNG and world oil prices is evident in
contractual terms,(see Thirteenth Amendatory Agreement to
Liquefied Natural Gas Sales Agreement between Tokyo Electric
Power Company,Inc.,Tokyo Gas Company,Ltd.,Marathon oil
Company,and Phillips Petroleum Company,effective April 1,
1982,and the Supplementary Administrative Memorandum),as
summarized in Table Dl.3.l.This relationship is further
shown by C.Itoh and Co.(1985)and by Mitsui and Co.
(1985)•
The value of the gas as sold,then,can be derived from
projections of the world oil price.It should be noted that
LNG will compete for gas supplies with urea and with other
uses.In order for ammonia and urea manufacture to exist
into the 21st century,they must be capable of paying the
same price for natural gas as LNG producers.In such cases,
LNG will set a floor for market pricing of natural gas
previously,in $/bbl.They are recast in terms of $/MMBtu
in Table D1.3.2 employing the world oil price values
discussed in Section 2.0 of this analysis.
Given the values of natural gas in Japan,it is necessary to
calculate the costs of liquefying that gas,transporting it,
and then regasifying it for use.These costs include
capital related charges,nonfuel operating and maintenance
costs,and fuel costs.The liquefaction and regasification
facilities can be accumulated into a production facilities
category.Fuel costs can be disaggregated from nonfuel
costs.This leaves a generic formula as follows:
Value of Gas in Japan
G =G·-(C+O)l - Cf - Ct (1)w J ,r
where Gw is the value of the gas at the wellhead;G'is
the value of the gas in Japan (equal to the value ot crude
oil in Japan on a $/Btu x 10 6 basis);(C+O)l r is the
capital and (non-fuel)operating costs of liquefaction and
regasification;Cf is the fuel costs associated with
liquefaction and regasification,and Ct is the cost of gas
transportation.All terms identified above are expressed in
1985$/Btu x 10 6 •
Dl-3-5
851102
(i)Nonfuel Liquefaction and Regasification Costs
Nonfuel liquefaction and regasification costs vary
depending upon whether the facility is existing or
new.Existing plants have depreciated capital
investments and therefore have lower capital recovery
costs.New facilities must provide for full capital
recovery.New facility netback costs are of more
relevance here,due to the long-term nature of the
forecast.
Liquefaction and regasification costs for this
analysis have been estimated based upon the TAGS
report (Hickel,et al.,1983).The TAGS data,
however,are for a system gasifying 950-2,830 MMCF/day
of (raw)natural gas,and shipping 740-2,190 MMCF/~ay
to Japan.Further,the TAGS report assumed use of
existing regasification facilities in Japan.Finally,
the data were provided in 1982 dollars.The following
modifications were made to the TAGS data:1)the
plant was scaled back to 200 MMCF/day output,
consistent with the size of the current Phillips plant
and the CIRI proposal (Tarrant 1985);2)
regasification facilities were added to all costs;and
3)costs were updated to January 1985 dollars.The
exponential scaling factors employed were 0.83 for
capital investments and 0.91 for operating costs.
These were derived directly from the TAGS report
(Hickel,et al.,1983).Regasification costs were
based upon Purvin and Gertz (1983)data.Updating was
based upon the Chemical Engineering Plant Cost Index
for capital costs,and the GNP implicit price deflator
series for operating costs.
Table Dl.3.3 summarizes the nonfuel production costs
for an LNG facility based upon the estimating
procedure described above.Also shown in Table Dl.3.3
are the fuel costs required for the liquefaction and
regasification operations.
In order to convert the data in Table Dl.3.3 into a
levelized nonfuel cost associated with production
operations,certain financial assumptions were made.
The project life was assumed to be 20 years (Hickel,
et al.,1983).The accelerated cost recovery period
was assumed to be 5 years.A real (inflation-free)
cost of capital of 9.9 percent was calculated based
upon data obtained from Value Line Investment Survey
for the following sample of energy companies:ARCO,
Chevron~Exxon,Mobil,Phillips,Sohio,and Tenneco.
Dl-3-6
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I
f
(ii)
Inflation was assumed at 5.5 percent.The total state
and federal tax rate was assumed to be 51 percent
(Hickel,et al.,1983).
The cost and financial data presented above led to a
long term nonfuel liquefaction and regasification cost
of $2.15/MMBtu of LNG.The individual cost components
of this value are shown in Table D1.3.4.
Transportation Costs
The TAGS report estimated a cost of $l.OO/MMBtu in
1988 for transporting LNG from the Kenai Peninsula to
Japan.Their cost was deescalated to 1982 dollars at
their assumed inflation rate of 7 percent/yr,and then
inflated to 1985 dollars by the GNP implicit price
deflator series.This procedure yielded a base
transport cost of 74~/MMBtu.Transportation costs
were escalated/deescalated at 50 percent of the rate
of change for fuel costs.This 50 percent factor
represented the split between fuel and nonfuel charges
in LNG shipping.The estimated transportation costs
for each oil price scenario are shown in Table
D1.3.5.
(iii)Fuel Costs for Production
Fuel costs for production are expressed as a
percentage of total gas entering the system.Fuel
costs were treated as an opportunity cost.They were
deducted by using the following equation:
o Delivered gas value -(nonfuel production costs +
transport costs)x .889 =wellhead netback value
(iv)Alternative Cost Values
The above paragraphs describe the netback valuation
methodology.Alternative costs also have been used
for sensitivity tests on the netback calculation.
These alternative costs include the direct TAGS
estimates,capturing capital,and operating gains from
scale.At the same time,a variety of transportation
cost assumptions were used.The results are discussed
in Section 3.1(c)below.
(c)Netback Wellhead Value Results
The netback valuation of Cook Inlet natural gas was
calculated as described above.The wellhead gas values,by
oil price scenario,are as follows ($/MMBtu):
851102 Dl-3-7
Scenario
Year Wharton Composite SHCA
1985 1.57 1.58 1.73
1990 1.26 1.50 1.68
2000 2.17 3.13 3.55
2010 3.49 4.97 6.43
2020 5.43 7.45 9.75
2030 8.08 8.30 11.30
2040 8.30 8.30 12.72
2050 8.30 8.30 14.27
The derivation of the Composite-based netback wellhead price
is shown in Figure Dl.3.1.It demonstrates the deduction of
costs from the delivered value of the natural gas.It is
significant to note that the value of natural gas rises at a
more rapid rate than the value of oil.This phenomenon is
based upon the presence of constant costs (e.g.$2.15/MMBtu
in nonfuel production costs)in the netback calculation.
(d)Verification of Wellhead Gas Netback Values
The values described above were subjected to a significant
verification process.Costs associated with the processes
were independently checked as described above.Further,ten
sensitivity cases were constructed for the Composite oil
price scenario based upon the alternative liquefaction,
regasification,and transportation costs as shown in
Tables D1.3.6 and D1.3.7.These 10 cases reflect variations
in the size,capital cost,O&M cost,and thermal efficiency
of liquefaction facilities projected for Alaska,either by
TAGS (Hickel,et.al.,1983)or by CIRI (see Tarrant 1985).
These alternative cases permit capturing substantial
economies of scale in liquefaction and regasification costs;
and more optimistic assumptions about LNG transport charges
(caused in part by assuming larger ships).The economies of
scale reduced the costs of LNG manufacture and transport,
thus raising the netback value of the gas at the wellhead.
The results of sensitivity runs are shown in Figure D1.3.2.
These calculations provide a netback envelope depending upon
case assumptions.The Phillips settlement and Enstar
contracts were then used to validate the netback
calculations to the year 2000.This cutoff date represents
the termination point of the Enstar contract (1989 is the
termination point of the Phillips contract).The results of
this validation are shown below for the Composite oil price
forecast.
851102 Dl-3-8
F
851102
(e)
Wellhead Gas Price (1985 $/MMBtu)
High
Year Base Netback Enstar Phillips Sensitivity
1985 1.58 2.21 2.25 2.30
1990 1.50 2.50 2.20 2.22
1995 2.25 2.92 2.65 2.97
2000 3.13 3.40 3.20
3.88
Of particular importance to the analysis is the year 2000
value,particularly because Watana is proposed to come
on-line in 1999.In that time frame ,the calculated netback
wellhead prices are within ten percent of the contract
prices -and base case netback values are more conservative
than the Enstar or Phillips contract values.It should be
noted,also;that an average of old plant and new plant
netback costs would be $4.00/MMBtu in the year 2000.Beyond
the year 2000,when oil prices are expected to rise
significantly in real terms,netback gas prices rise
concomitantly.It should be pointed out that netback prices
in the base case analysis assume a new LNG plant.If an
existing LNG plant is assumed,and capital charges are
treated as sunk costs,the netback values are $4.87/MMBtu 1n
2000.Significantly,the Marathon settlement associated
with the Phillips case documents a 1984 netback price of
about $3.03/MCF,or $3.18/MMBtu using an 18 percent rate of
return.The technique documented above yields a current
netback value of $3.32/MMBtu assuming a nominal discount
rate of 15.9 percent.The differential is well within the
error estimations.One could well argue that the netback
value based on the Phillips plant would hold until 1999,
when a new plant netback value would assume precedence.The
current forecast offers the lowest calculated natural gas
values to the year 2000.Beyond 2000,natural gas prices
rise more rapidly than contract extrapolations,reflecting
the total impact of petroleum prices on natural gas
economics.
Delivery Charges to Utilities
Utilities must pay not only the wellhead cost of natural
gas,but al~o charges associated with natural gas delivery.
These costs include metering,billing,overhead functions,
capital recovery,recovery on gas distribution pipelines,
and related costs.
The Alaska Public Utilities Commission performed a revenue
requirements study on a test year,1981 (APUC 1984).
Revenue requirements were calculated not only for the system
as a whole,but also for each major customer class.
Dl-3-9
Specific data were gathered for Chugach Electric Association
(CEA)and Anchorage Municipal Light and Power (AML&P).
Table Dl.3.8 contains the revenue req uirements da ta for
1981.These data have been updated to 1985 dollars using
the GNP implicit price deflator series.Table D1.3.9
contains the same estimate in 1985 dollars.Beca use the
Alaska Public Utilities Commission is moving toward rates
based upon cost of service (Pratt 1985),the 40~/MCF charge
is used.This charge is held constant over the life of the
analysis in real dollars.Table D1.3.l0 demonstrates the
calculation of the delivered cost of natural gas for the
Composite oil price scenario using the base case netback
assumptions.
Given the data presented above,an electric utility gas
price forecast has been developed as follows:
oil Price Scenarios
Sherman H.
Year Wharton Composite Clark
1985 1.97 1.98 2.13
1990 1.66 1.90 2.08
1995 2.05 2.65 2.80
2000 2.57 3.53 3.95
2010 3.89 5.37 6.83
2020 5.83 7.85 10.15
2030 8.48 8.70 11.70
2040 8.70 8.70 13 .12
2050 8.70 8.70 14.67
This forecast represents the estimated economic value of
natural gas to electric utilities in the Railbelt region,if
that economic value is determined by gas liquefied and sold
to a Pacific Rim market.
(f)Lower Sensitivity Analysis
The above paragraphs describe the Power Authority analysis
of natural gas prices for the Cook Inlet region of Alaska.
At the same time,however,the Power Authority has analyzed
the Susitna project assuming that na tural gas pricing will
follow either the Enstar or Phillips contract formulas.
When calculated over a wide range of prices,both the Enstar
and Phillip's contracts provide natural gas valued at about
50 percent of the Btu value of crude oil.Despite such
steep discounts in the price of natural gas,the
benefit/cost (B/C)ratio of the project remained favorable
as discussed in Exhibit D,Chapter 2,Section 2.11.6.
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851102 D1-3-10
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3.2 -Regulatory Constraints on the Availability of Natural Gas
Title II of the Power Plant and Industrial Fuel Use Act of 1978 (Fu\),
and 42 U.S.C.§8311-8324,generally prohibits the construction of new
electric power plants that do not have a capacity to use coal or
another alternative fuel (other than oil or natural gas)as a primary
energy source.The FUA provides various opportunities for exemption
from this general prohibition.Thus,although the express policy
objective of the Act is to preclude future reliance on oil and natural
gas for electric generation,the Act's terms do not operate as an
absolute bar to the development of new gas-fired generating capacity.
Nevertheless,the prospect of federal regulatory constraints on use of
natural gas significantly clouds the landscape of Railbelt power
planning.It can generally be assumed that peak load facilities will
not be prohibited under the FUA so long as operation is held to the
statutory limit of 1500 hours/year (42 U.S.C.§8302(18)A,8322(g)(2)).
However,neither the FUA nor its implementing regulations provide
comparable reassurance with respect to base load power plants.In
.1982,Congress did enact a limited exemption from the FUA restrictions
for new electric power plants in Alaska using Cook Inlet natural gas.
However,this general "Alaska exemption"expires on December 31,1985,
and no extension of the specialized exemptive authority for Alaska has
been secured to date.Moreover,the administration of the specialized
Alaska exemptive authority to date suggests that to qualify,applicants
must develop environmental and other data specific to a particular
plant site and design.The level of detail required appears to
preclude use of the exemption prior to its scheduled expiration to gain
authorization for future plants whose dates of service,design,or
location are yet to be determined.
After expira don of the special "Alaska exemption,"the construction of
new gas-fired generation capacity in the Railbelt is possible only if a
proposed new electric power plant is found to qualify for one of the
other exemptions available under the FUA.While certain exemptions may
eventually be found to apply in individual cases,such exemptions
cannot be gained except by discretionary federal administrative action.
Again,requirements for detailed,case-specific factual findings make
it difficult to predict the application of those provisions to future
generating capacity that,at this point,is only generally defined.As
a practical matter,neither the APA nor any of the Railbelt utilities
can plan for the availability of a FUA exemption substantially in
advance of a decision to build any natural gas-fired combustion
turbine,combined cycle,or steam turbine power plant.
The consequences of the FUA for Railbelt utility planners is quite
significant.The availability of natural gas for base load power
generation is generally assumed to be an essential prerequisite to any
economically feasible thermal system for the Railbelt.The prospect
that FUA exemptions would not be available threatens confidence in the
851102 Dl-3-11
validity of any long-term generation planning that includes the
possibility of building base load natural gas facilities.
In order to evaluate the Susitna system strictly on economic terms,the
Power Authority has not accounted for the effect of the FUA on natural
gas availability to utilities in performing its economic analysis of
the thermal system expansion plan.For analytic purposes the thermal r-
alternative expansion plan ignores this regulatory risk,and assumes
that utility planners will have unfettered discretion within the bounds
of price and physical supply constraints to select the least cost r
thermal response as demand for new capacity emerges.
In reality,however,the FUA creates considerable risk of regulatory F
impediment to the realization of any presumed benefits of the thermal \.
option.A utility may,over the long term,plan for the freedom to
select between coal and gas on the basis of comparative economic
factors such as physical availability and price.If those factors
dictate selection of a natural gas plant,however,a FUA exemption
would be required.If the exemption proves unavailable,the uti Ii ty
would be forced away from the natural gas facilities to coal-fired
plants even if the gas alternative were to be economically preferable.
In the context of a system expansion plan substantially dependent upon
the availability of natural gas,this would significantly impair r-
pursuit of the optimum generation additions.The regulatory !
constraints on gas availability imposed by the FUA raise a substantial
question whether the Railbelt can reasonably rely upon the opportunity
to actually implement a "least cost"thermal alternative,in the event L
a FERC license to construct the Susitna project is denied.
3.3 -Physical Constraints on the Availability of Cook Inlet Natural
Gas Supply
In addition to the regulatory constraints,there is a potential
physical limitation to Cook Inlet natural gas supply.This potential
physical limitation introduces added uncertainties into the power
generation planning process as discussed below.
3.3.1 -Estimates of Cook Inlet Gas Resources and Reserves
The Cook Inlet region has nine natural gas producing fields.1-
During the period 1980 to 1984,estimates of proven and
recoverable natural gas reserves ranged from 3.3 to 3.8 trillion
cubic feet (TCF).The Alaska Department of Natural Resources
(ADNR)January 1984 estimate was 3.3 TCF (Wunnicke 1985).
However,ADNR recently reevaluated its reserve estimates and
concluded that about one TCF of additional natural gas in the
Ivan River and MacArthur River fields had not been accounted for
in prior estimates.Accordingly,ADNR's January 1,1985 estimate
indicates that thete are about 4.5 TCF of proven recoverable gas
reserves in the Cook Inlet fields.For purposes of this
851102 Dl-3-l2
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analysis,the Power Authority has relied upon this last official
state estimate of proven and recoverable reserves as shown in
Table Dl.3.11.The best evidence available suggests that the
size of the Cook Inlet natural gas resource may be substantially
larger than the estimated proven and recoverable reserves.
Estimates of the size of potential undiscovered reserves have
been developed by Ross G.Schaff of the ADNR's Division of
Geological and Geophysical Services (Schaff 1983).The Schaff
analysis assigns a probability value to various estimates of
undiscovered Cook Inlet resources.The results of Schaff's
analysis (which have been confirmed by McGee (1985»are shown as
a probability distribution contained in Table Dl.3.12.The
reported distribution of total estimated in-place and recoverable
resources in Cook Inlet also is shown in Figure Dl.3.3.
The Schaff estimate posits a mean probability that 3.36 TCF of
natural gas exists as undiscovered resources.The probability
that substantially greater undiscovered resources exists is less
than 50 percent.The number shown has been rounded upward to 3.4
TCF.
Although the Schaff and McGee probability distributions
constitute the best source known to the Power Authority for
estimating undiscovered reserves in Cook Inlet,it is recognized
that there are substantial uncertainties associated with
estimating undiscovered resources.This is particularly true in
the Cook Inlet where substantial new exploration programs have
not been carried out within recent years.Despite this
uncertainty,it is necessary to estimate total field size for
planning purposes.The Power Authority has attempted to compens-
ate for the uncertainties involved by certain adjustments which
tend to bias the estimation of natural gas towards more,rather
than less,fossil energy being available.The Power Authority ,
has used total in-place undiscovered resources,rather than
economically recoverable resources,as a basis for analysis.
The distinction between resources and reserves is both
informational.and economic.A resource is,generally,a
concentration of mineral deposits in the earth's crust.Whether
or not a resource is considered to be a reserve depends upon its
size,depth,and other factors which dictate whether the resource
is capable of production (Thrush,et a1.,1968).The
distinctions between resources and reserves are illustrated by
the McKelvey Diagram,shown in Figure D1.3.4.
This total estimated undiscovered resource (3.36 rounded up to
3.5 TCF)is added to the estimated proven reserves (4.5 TCF),
yielding 8 rCF.The Power Authority therefore assumes that 8 rCF
of gas will be available for all future uses of Cook Inlet
na t ural gas.
851102 DI-3-13
3.3.2 -Current Use of Cook Inlet Natural Gas
Cook Inlet natural gas currently serves a full range of
residential,industrial,and commercial uses.Natural gas is
used by electric utilities for generation of electricity for
typical residential and commercial end-uses.In addition,the L
Railbelt's gas utilities deliver natural gas at retail for I
residential and commercial end-users.An ammonia-urea plant,
owned by the Union Oil Company,produces fertil izer from Cook i__
Inlet gas for delivery to agricultural use markets in the Lower
48 states.Also,the Phillips Petroleum Company operates a plant
on the Kenai Peninsula which produces liquefied natural gas (LNG)
for export to Japanese markets.The following sets out data r=
developed by ADNR regarding consumption of Cook Inlet g~s in I
1984:
Field Opera tions
Vented or Flared:
Used on Leases:
Shrinkage
Other
LNG
Ammonia-Urea
Public Power Generation
Military
Residential and Commercial
Producers
Other
20.5 BCF
65.5 BCF
50.9 BCF
30.5 BCF
4.1 BCF
19.3 BCF
12.0 BCF
4.3 BCF
3.3 BCF
14.6 BCF
2.6 BCF
0.003 BCF
SlM 207.1 BCF
Source:Alaska Department of Natural Resources 1985.
Table Dl.3.13 summarizes the growth of Cook Inlet natural gas
production and use for the period 1971-1984.As is shown in
Table Dl.3.13,Cook Inlet natural gas production and use has
undergone a 2.3 percent rate of increase over the past 13 years,
with the most dramatic growth occurring in ammonia-urea
production and in power generation.
3.3.3 -Future Use of Cook Inlet Natural Gas
The availability of Cook Inlet gas for expanded use for Railbelt
power generation depends on the extent to which forecasted demand
is likely to absorb the available natural gas resource over the
course of the 1985-2050 planning period.The Applicant has
therefore made estimates of future use of Cook Inlet gas over the
planning period.This projected use is then measured against the
estimated available Cook Inlet natural gas resource.The
851102 Dl-3-14
F
difference suggests the bound of supply limitations that would
constrain expanded use of natural gas for electricity generation.
Two forecasts are used in this analysis--a near-term analysis
covering demand projections over the 1985-1999 planning period,
and a long-term projection covering the years 1999-2050.
The Applicant has relied upon official state forecasts developed
by ADNR as the basis of its near-and midterm residential
forecast.The ADNR forecast predicts production and consumption
of gas in the Railbelt (Table D1.3.l4)through 1999.The
cumulative demand for Cook Inlet region gas as projected by ADNR
is 2.3 TCF for the period 1985-1999.
The Applicant's near-term forecast supplements the ADNR forecast
in two respects.The ADNR does not attempt to forecast the use
of gas for LNG production or for field operations associated with
producing Cook Inlet gas supplies.It was therefore necessary to
make assumptions with respect to both of these uses.
Projected LNG use was derived from an extrapolation of current
levels of LNG use for the Phillips LNG production facility.This
facility consumed 65.5 BCF in 1984.Prior years are within the
same range as shown in Table Dl.3.l3.The life expectancy of the
facility spans the period of the short-term forecast.Moreover,
Mitsui and Co.(1985)reports their expectation that the Phillips
contract will be extended 5-10 years beyond 1989.Therefore,it
can be confidently assumed that LNG use will continue,and will
account for a comparable share of gas use annually for the
remainder of the century.The cumulative projected demand for
the period 1985-1999 based on 65.5 BCF annual consumption is
approximately 1.0 TCF.
With respect to field operations,this analysis assumes that
field operations will continue to account for approximately 10
percent of total gas use (Table Dl.3.l4).Therefore,the
cumulative total consumption for field operation over the short
term,through 1999,is assumed to be approximately 0.34 TCF.
Thus,over the near-term planning period,the Applicant's
forecast projects a cumulative demand for 3.4 TCF of Cook Inlet
natural gas.Subtracting the 3.4 TCF of projected demand for
1985-1999 from the 8.0 TCF of natural gas resource assumed to be
available in Cook Inlet,a remaining resource level of 4.6 TCF is
assumed to be available for use in the next century.
ADNR does not forecast natural gas use beyond the year 2000.
Therefore,to project the demand for Cook Inlet gas in the
long-term period (2000-2050),it is necessary to develop a
forecast for each of the current categories of na tural gas use.
851102 D1-3-l5
851102
These incl ude:1)residential and commercial,2)existing power
systems,3)military,4)industrial markets,5)LNG exports,and
6)field operations.These markets will draw from the 4.6 TCF of
natural gas assumed to be available after the year 2000.
As a general matter,these market analyses are extrapolated from
current trends as well as trends projected by ADNR in the short
term analytic period in each use category.It is assumed that
field operations use will remain constant at 10 percent of total
production (this is equivalent to 11 percent of the natural gas
sold).Thus,the projected use for each market category has been
increased by 11 percent to reflect gas used for field operations
in connection with production of gas necessary to serve that
particular market.A summary of these market analyses is
described below:
(a)Residential and Commercial
Residential and commercial natural gas use (represented in
consumption data for gas utilities)increased from 10.2
BCF/yr to 19.8 BCF/yr during the period 1971-1984.This
represents a compound annual growth rate for gas consumption
of 5.2 percent (ADNR 1985).ADNR has forecast that these
uses will grow ata compound annual rate of 3.8 percent to
the year 1999.Considerable growth is forecast for the
Matanuska Valley,where natural gas is only now being
introduced as a residential fuel.
The current,more mature Anchorage residential and
commercial natural gas market is forecast by ADNR to grow at
a rate of 3.3 percent per year to the end of this century.
By 1999,residential and commercial gas consumption in the
Railbelt is forecast at 34 BCF/year.
For the development of projections from 2000-2050,several
growth rates may be assumed.The assumed growth rate may be
an extension of the ADNR mature market forecast trend (3.3
percent),zero,or the midpoint between those two rates.
All three mathematical trends are shown below.
Forecast Total Requirements 2000-2050
Growth Without With Field
Rate Year 2000 Year 2050 Field Operations
(%/yr)Consumption Consumption Operations 10%of Total
-0-34 BCF 34 BCF 1734 BCF 1930 BCF
1.65 34 BCF 79 BCF 2650 BCF 2940 BCF
3.30 34 BCF 177 BCF 4300.BCF 4770 BCF
Dl-3-l6
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The range of possible consumption levels is 1.9 to 4.8 TCF.
The midpoint rate of growth in residential and commercial
gas consumption was chosen for this analysis.On this
basis,a 2.9 TCF consumption level is assumed for
residential,commercial,and related uses of natural gas
from Cook Inlet.
It should be noted that the 2.9 TCF estimate involves a
decline in the rate of market growth for natural gas used 1.n
residential and commercial applications,as shown below:
Period
1971-1984
1985-1999
2000-2050
Annual Growth Rate
1.n Residential and Commercial
Natural Gas Consumption
5.2%(l)
3.3%(2)
1.65%
F
(1)Historical growth rate.
(2)Anchorage market,excludes Matanuska Valley.
(b)Electricity Generation
If Susitna is not constructed,electricity will be generated
and supplied to the Railbelt Region by a combination of
generation systems burning natural gas and coal.Assuming
gas supplies are unlimited and the use of netback pricing
grounded on the Composite oil forecasts,the OGP model has
forecast that the Railbelt consumption of natural gas will
peak at 40.0 BCF/yr in the Year 1998,decline to about 16 to
18 BCF/yr in 2000 to 2004,and then decline to 5 to 8 BCF/yr
for the period 2005 to 2050.Total consumption will be
about 300BCF (0.30 TCF).Total consumption for the period
2000 to 2050 will be 0.20 TCF,assuming the Sherman H.Clark
forecast.
(c)Military Use
Military uses of natural gas are small and largely devoted
to power generation.They have been projected as a constant
load of 4.6 BCF/yr to the turn of the century (ADNR 1985).
They are projected to remain at that level through 2050.
The military requirement is therefore considered to be
approximately 260 BCF (0.3 TCF)with field operations for
the period 2000-2050..
(d)Ammonia and Urea
The Union Oil Company ammonia-urea plant is a successful
venture for exporting Alaskan na tural gas in the form of
851102 Dl-3-17
fertilizer.Reserves are committed contractually to this
use through 1998.This use is also reflected in the ADNR
(1985)forecast of gas usage.
There is some evidence demonstrating that the long-term
outlook for ammonia/urea manufacture in the U.S.compared to
overseas locations is favorable.Such favorable
circumstance may exist for the long term due to several
factors,including favorable capital costs of new capacity
in the U.S.vis-a-vis overseas locations,and more favorable
currency exchange rates for U.S.manufactured commodities
based upon a projected weakening of the dollar (AGA 1985;
Hay 1985).Moreover,the Cook Inlet region may be
strategically located to serve the market place.This view
is not universally held,however.The World Fertilizer
Review posits the belief that the U.S.will have difficulty
competing in the nitrogenous fertilizer market over the long
term (Sheldrick 1984).
The American Gas Association (AGA)has calculated the costs
of manufacturing ammonia from existing and new plants in the
U.S.and in foreign countries.Their results are shown in
Table Dl.3.15,along with their estimated capital costs
associated with ammonia plants..
Because there is.some evidence supporting the belief that
the U.S.can compete in the nitrogen fertilizer market,and
that Cook Inlet has some advantages in that regard,it is
not reasonable to assume that there will be no continued
demand for urea production from Alaska beyond the year 2000.
For planning purposes,it is assumed that the current level
of natural gas consumption,some 50 BCF/yr,may be required
for ammonia/urea production.The consequence of such
natural gas demand would be a 2.5 TCF requirement before
associated field operations,or a 2.8 TCF total natural gas
requirement for the period 2000-2050.
(e)Liquefied Natural Gas (LNG)
The Phillips Petroleum LNG plant on the Kenai Peninsula
exports 0.2 BCF of gas per day to Japan.The Phillips plant
has a functional life expectancy to the end of this century
(see Mitsui &Co.1985).Continued demand for natural gas
for the duration of this life expectancy is reflected in the
Applicant's 1985-1999 forecast.
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Demand beyond 1999 is anticipated to come from the Pacific
Rim countries.This demand is discussed quantitatively in
Section 3.3.3.Other evidence of such demand is shown
below.Japan now imports LNG not only from Alaska ,but also j-
from Indonesia and other sources.
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Several ventures conceived in recent years in response to
perceived demand in the Pacific Rim lend credibility to the
assumption that the LNG market opportunities will extend
beyond the useful life of the Phillips plant.These include
the TransAlaska Gas System (TAGS)proposal,and the facility
proposed by Cook Inlet Region,Inc.(CIRI)and ARCO Alaska
to be built in North Kenai (Tarrant 1985).This latter
facility would be slightly larger than the Phillips
Petroleum plant (consumption =65 BCF/yr).If this plant
were constructed,3.5 to 4.7 TCF of natural gas would be
required for LNG operations for the period 2000 to 2050.
The TAGS proposal is for a gas pipeline from Prudhoe Bay to
the Kenai Peninsula.There,gas conditioning and
liquefaction facilities would be constructed.The Phase I
operation involves converting 0.95 BCF per day into 0.74
BCF of LNG.When Phase III is complete,the TAGS system
would convert 2.83 BCF/day into daily shipments of 2.2 BCF
of LNG.The LNG so produced would be shipped to Japan or
other nations on the Pacific Rim.The TAGS proposal remains
active,and in the gas marketing phase.
The TAGS proposal and the CIRI/ARCO Alaska program,along
with the success of the Phillips Petroleum and Indonesion
efforts,are evidence that a long term LNG market in the
Pacific Rim exists.The Power Authority therefore has
assumed a long-term opportunity for LNG production in
Alaska.However,because information is not sufficient to
estimate possible growth in LNG demand,it is assumed for
purposes of the natural gas supply analysis that current LNG
production levels will be sustained for the planning
period.
(f)Market Totals
Projected market totals for the period 2000-2050 have been
tabulated and they are presented in Table D1.3.16.The
total estimated market demand for natural gas in the Cook
Inlet area is 10.0 TCF for the 50-year period.This
includes the consumption demands by the military,urea
process facility ,existing power plants with extended
peaking capacity,liquified.natural gas,and the residential
and commercial demands.
(g)Conclusions Respecting Gas Availability
As described more fully above,the Applicant's analysis of
natural gas prices indicates that by the end of this
century,the economically preferred thermal fuel for
baseload generation will be coal rather than natural gas.
851102 Dl-3-19
851102
Based on pr~c~ng considerations alone,natural gas will be
an appropriate choice only for peaking facilities for the
duration of the long-term planning period.As a practical
matter,therefore,the foregoing discussion of likely supply
constraints on Cook Inlet region natural gas is not central
to the Applicant's base case analysis of the thermal
alternative.Nevertheless,to the extent that different
assumptions are made about natural gas prices,it is
necessary for planning purposes to examine the potential
effect of supply uncertainty on power planning in the
Railbelt.
The foregoing analysis of gas supply and projected demand
demonstrates that demand for Cook Inlet gas could
substantially exceed the total estimated resource of eight
TCF expected to be available over the course of the
Applicant's planning period.By the Year 2000,it is
anticipated that 3.4 TCF of the proven Cook Inlet reserves
will have been consumed.The result is that if ADNR's
official state estimates prove correct,the major share of
the 4.5 TCF of proven reserves is expected to be consumed
during the short-term planning period of 1985 to 2000.
The remaining 1.1 TCF of proven reserves is insufficient to
meet even the most conservative estimate of demand from the
residential and commercial sector for the long-term planning
period.Simply to sustain current retail sales levels in
the Railbelt region,natural gas utilities will require
almost two TCF during the long-term planning period of 2000
to 2050.
As a result,some additional development will be necessary
to meet minimum requirements for the long-term period for
military and stable residential and commercial demand.If
residential and commercial demand for the entire Railbelt
does not remain flat,but grows only at the modest rate of
1.65 percent,the total requirements for military,
residential,and commercial gas use will be 3.2 TCF.Thus,
even assuming that the estimated 3.4 TCF of undiscovered
resource is economically recoverable and is developed during
the long term,there would still be significant competition
between the industrial and power generation sectors for the
remaining 1.3 TCF expected to be available.
Such uncertainty surrounding the availability of gas over
the long term suggests that even if natural gas prices do
not constrain gas use for power generation purposes,Cook
Inlet gas supplies cannot reliably be expected to support
baseload generation expansion beyond the next decade.
Dl-3-20
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3.4 -North Slope Natural Gas
Vast resources of natural gas,approaching 36 TCF,have been found in
connection with North Slope petroleum (ADNR 1985).Table DI.3.17
delineates proven and undiscovered reserves and resources of natural
gas on the North Slope.
Currently,natural gas on the North Slope is used for local power gen-
eration and heating needs,and the operation of pumping stations.Most
of the gas produced is reinjected into the producing formations in
order to maintain pressure for oil production.
There is,at present,no infrastructure to move this natural gas into
the Railbelt region,although several proposals have been offered.
These proposals include the ANGST pipeline passing by Fairbanks on the
way to the midwest,the TAGS pipeline to the Kenai Peninsula (Hickel,
et al.,1983),and transmission lines for transporting natural gas in
the form of electricity from Prudhoe Bay to the Railbelt.
Construction of such pipelines can only be justified in the movement of
significant quantities of gas in order to reduce the unit cost of gas
transmission.Such quantities far exceed the needs of the Railbelt
market;this means that a substantial market for North Slope gas must
'materialize if TAGS or ANGTS is to be built.The TAGS project is pre-
dicated on an export market (from Alaska)and,as a consequence,the
city gate cost of natural gas in Anchorage (or elsewhere in the Rail-
belt)delivered by the TAGS pipeline will be the LNG netback price.
Thus,the Power Authority's pricing analysis effectively accounts for
the availability of North Slope gas delivered through the TAGS system.
If instead the ANGTS system were developed,North Slope natural gas
prices would necessarily be sufficient to include costs of conditioning
and transporting it to the point of end use.As estimated by Batelle,
the cost of ANGTS gas in the Fairbanks area would be between $4.03-
$6.32/MMBtu in 1983 dollars in the first year of pipeline operation,
assuming the wellhead price of gas is between $O.OO/MMBtu and $2.30 per
MMBtu,respectively.However,to the best of the Power Authority's
knowledge,there is no present expectation that a market in the lower
48 states for ANGTS-delivered gas is likely to develop at a price suf-
ficient to permit financing of the ANGTS system.In the absence of any
present reasonable prospect that the financing to permit construction
of ANGTS will be secured,the Power Authority has not attempted to
account for North Slope gas delivered through ANGTS in its pricing
ana lysis.
If an export LNG market does not exist,then the potential for moving
natural gas to the Railbelt is "by wire."To date,the technical and
environmental feasibility of such natural gas usage (including the
construction and operation of a transmission iine)has not been
established.Until such feasibility is established,the Alaska Power
Authority bel ieves that 'it is inappropriate to attempt to account for
this alternative in its analysis.
851102 Dl-3-21
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4 -COAL
This section describes the Applicant's analysis of the price and supply
of coal,which is used in the thermal alternative expansion plan.This
analysis examines four issues:1)current and projected supply of
Alaska coals;2)present and projected demand for coals mined in
Alaska;3)appropriate concepts for projecting coal prices;and 4)
current and projected prices of Alaska coals.
4.1 -Resources and Reserves
Alaska's identified coal reserves total nearly 10 billion tons.Its
total resources of coal are in the 2-6 trillion ton range,as is shown
in Table 01.4.1 (Davis 1984).Major coal resource regions include the
arctic,the interior,and the south central areas of Alaska.
Relatively few coal fields in these regions hold significant promise.
Those fields which'have substantial quantities of coal in the most
favorable geologic settings are located largely in the Railbelt region.
Such fields include Nenana,Beluga,Matanuska,and Kenai-Homer.Of
these,the Nenana and Beluga fields are the largest and offer the
greatest potential for economic development.
The Nenana and Beluga fields contain low sulfur bituminous coal with
fairly low heating value.The market potential of these two deposits
differs significantly,however,Nenana coal is situated in proximity to
a populated area of Alaska with some infrastructural development
(e.g.the Alaska Railroad).This coal field supplies the only
currently operating coal mine in Alaska.The Beluga coal field,on the
other hand,is in a totally undeveloped area located on the tidewater,
where highways and railroad spurs are absent;only a few small
settlements exist.
Nenana coal is accessible to the Alaska domestic market and is also
shipped via the Alaska Railroad 360 miles to Seward for export to
Korea.Beluga coal fields are close to tidewater.The proposed
Diamond Alaska coal project,for example,is only about 12 miles
inland.Because of transportation limitations,Beluga coal currently
could only move into the local marketplace through mine mouth power
plants tied into the Railbelt electric grid,although a railroad or
road could be built connecting the Anchorage area to Beluga if
sufficient development occurred to warrant it.It is assumed for these
analytic purposes,however,that the market potential for Nenana coal
will largely be domestically determined,and that Beluga development
will be dependent primarily on export opportunities.Over time,the
markets for Nenana and Beluga coals will tend to become distinct and
separate.
The Matanuska coal field is fairly small.Its resource potential for
surface mineable coal would be exhausted by the one power plant now in
the planning stages (M.P.P.Assoc.1985).The Kenai-Homer field is
851102 01-4-1
characterized by small,steeply dipping,faulted deposits of relatively
high grade coal that would be difficult to develop.Thus,neither of
the resources are further considered in this analysis.
4.1.1 -The Nenana Coal Field
The Nenana coal field is a large deposit of subbituminous coal in the
center of the Railbelt region.It is located in an area about 200
miles north of Anchorage and 60 miles south of Fairbanks.Estimates of
the size of this field are shown in Table D1.4.2.
The Nenana coal field consists of six noncontiguous individual
coal-bearing areas extending in a belt up to 30 miles wide.These
areas include the Healy Creek,Lignite Creek,Wood River,Tatlanika,
and Totalanika fields.These basins (inset)and the Nenana field coal
lease holders are shown in Figure D1.4.1.The coal being mined and
shipped to Fairbanks Municipal Utility System has the following
characteristics:
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4.1.2 -The Beluga Coal Field
The principal advantage of Nenana coal is its low sulfur content
typically 0.2 percent.
Higher heating values (as received)
Ash
Moisture
7,600 Btu/lb
8.3 percent
26.5 percent
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The Beluga field shown in Figure D1.4.2 is located in the Susitna coal
field on Cook Inlet,approximately 50 miles west of Anchorage.The
coal resources of the Susitna field are comprised of the Yenta area in
the north and the Beluga area in the south.Both areas contain
multiple seams of low sulfur,lignite-to-subbituminous coal.The
National Research Council has listed the indicated and inferred
resources for the Susitna field at 1.2 to 2.7 billion tons.
Hypothetical resources are listed at 27 billion tons (Wierco 1985).
The quality of Beluga coal is comparable to that of Nenana coal.
Weirco (1985)estimates the average as received calorific value at
7,500 Btu/lb.The Diamond Alaska Coal Company estimates the value to
be 7,600-7,700 Btu/lb.Ash,moisture,and sulfur content are
comparable to Nenana coal:
Ash
Moisture
Sulfur
851102
8 percent
28 percent
0.2 percent
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4.2 -Demand and Supply
The locational and infrastructural differences between Nenana and
Beluga make the economic analyses of each coal field distinctly
different.The future potential of the Nenana field is largely
oriented toward the domestic market,with some capacity dedicated to
exports.This is consistent with historical trends,although currently
about half of the coal mined is sold to each market.The Beluga field,
however,lacks the infrastructure to serve a locationally dispersed
domestic market.Its development is presumed to be largely predicated
upon exports.
4.2.1 -Nenana Field Demand and Supply
At present there is a modest domestic demand for Nenana field coal,
with some potential for growth in the market.The Usibelli mine,
located in this coal producing region in the general vicinity of
Fairbanks,is the only commercially active mine in Alaska.Usibelli
supplies 830,000 tons annually for domestic consumption,and also has a
15 year contract with Sun Eel (a Korean export company)to export
880,000 tons annually to the Korean Electric Power Company.The
Usibelli operations consist of a dragline and a fleet of front end
loaders and trucks.The Usibelli mine has a present capacity of 2
million tons/year.
Nenana coal production could increase in relation to the existing
Usibelli contract commitments under a thermal alternative expansion
plan.Such a plan would include 200-400 MW of capacity in the Nenana
area.The reserves of the Nenana field are sufficient to support both
increased Sun Eel exports and a level of production associated with
coal fired plants under the thermal expansion plan.The Usibelli
Mining Company surface mining capacity is 80-90 percent fully utilized
by the 1.7 million tons annual production at the existing Poker Flats
mine.Expansion of production beyond 2 million tons annually (e.g.,to
4 million tons/year)would entail a distinctly separate mining effort
with some dependence on existing systems (e.g.,shops).Additional
capital equipment would be required.
4.2.2 -Beluga Field Demand and Supply
The export potential for Beluga coal far exceeds that presented by the
domestic market.Table 01.4.3 shows the forecast of total steam coal
potential imports by Pacific Rim nations through 2040 in metric tons
coal equivalent (MTCE)and actual tons.One MTCE equals.27.8 MMBtu per
metric ton (2,204 pounds).Beluga coal has about 15 MMBtu per ton
(2,000 pounds).Hence,each MTCE equals 1.85 tons of Beluga coal.The
total Pacific Rim market for coal for electric power generation is the
potential market for Alaska coal.The Beluga field may serve a
significant portion of this market.
851102 01-4-3
New power plant demand for coal in Japan,Taiwan,and Korea will grow
rapidly after 1990.If no internal Alaska constraints limit Beluga
coal mine development,Beluga reserves are sufficient,and Beluga
production costs are low enough to justify Beluga producers capturing
10 percent of the total steam coal market by 2000 and about 18 percent
of the growing market by 2030.Beluga coal can be delivered to
tidewater for under $22 a ton (1985 dollars)(Wierco 1985).Even after
allowing for real production cost escalation,production costs will
remain well below competitive market prices throughout the Susitna
planning period,making this source of coal extremely competitive.
Based upon its competitive position,the potential for exports of
Alaska coal is substantial.The approximate potential size of the
market is shown in Table Dl.4.4,assuming no internal constraints limit
the number of mines opened or the environmental acceptability of mining
growth.These estimates represent unconstrained potential demand for
Alaska coal based on what the market could absorb,assuming 10 percent
market penetration by 2000 and 18 percent by 2030 (Dames &Moore
1985a).
Currently no active mines exist in the Beluga coal field.Diamond
Alaska Coal Company is planning for the development of a mine
ultimately capable of producing 10 to 12 million tons per year by the
early 1990s.Diamond Alaska Coal Company projects initiation of
exports by 1990.
The export market exists,and competitive Beluga coal supplies exist.
However,it would be exceptional for Beluga coal to be developed on a
scale and at a pace sufficient to accommodate the potential demand.
Any number of cultural,social,or ecological considerations could act
to constrain development of Beluga coal well below what the Pacific
market could absorb.While maximum allowable production levels cannot
be predicted,a reasonable development path that considers effective
management of potential sociological and environmental conflicts has
been forecast to achieve production growth as shown on Table Dl.4.5.
4.3 -Present and Potential Alaska Coal Prices
Pricing of Nenana and Beluga coals is as distinct as the estimation of
markets,supplies,and production potentials.Pricing in both cases,
however,requires the establishment of a base price and an escalation
rate.Both aspects of price analysis are treated below.
4.3.1 -Nenana Coal Production Prices
Because there are too few buyers and sellers to create a fully
competitive market,coal prices in the localized Fairbanks market
will be set by bilateral negotiation.No deterministic economic
model can project the price trend for Nenana coal.Consequently,
a present and projected production cost analysis of Nenana coal
resources is proposed for resource valuation.
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The wide range of contract prices for coal sold by Usibelli into
the Fairbanks market demonstrates the analytically indeterminate
nature of commodity prices in this small market.These mine
mouth prices,stated in 1985 dollars,range from $1.30 to $2.40
per MMBtu (Mann,Tillman,and Wade 1985).Prices are set by
negotiations between a single seller dealing with a few buyers.
The resulting prices,therefore,cannot be analytically predicted
except for the minimum and maximum prices.The minimum price is
set by production (and transportation)cost;the maximum is set
by the cost of substitute fuels.
Production costs were estimated to determine the minimum price
that might conceivably apply to future Nenana deliveries.This
is a conservative resource valuation approach and may understate
the long-term market price of coal in Nenana.Table Dl.4.6 shows
the production cost of Nenana coal delivered by rail to a coal
plant at Nenana.
The production costs shown in Table Dl.4.6 were derived from a
hypothetical mining study conducted by the Paul Weir Company
(Weirco 1985).This study estimated the costs of owning and
operating a 2 million ton per year major expansion of a mine ln
the Nenana coal field.The Weirco study is based on current
costs.Cost escalation over time,as forecast by Dames &Moore,
is discussed below.The reason for having current and projected
costs on a new mine is the fact that the current Usibelli mine
capability is large.Further,as Table Dl.4.6 illustrates,a new
mine would produce coal at a cost comparable to the price charged
by Usibelli Mining Company to FMUS.
4.3.2 -Nenana Coal Production Cost Escalation
For planning purposes,it is essential to forecast the rate of
cost escalation.Escalation is used here to mean cost increases
at a rate faster than the general rate of inflation,Le.,"real"
increases.Historical data support the fact that real coal
prices have trended upward throughout the 20th century.This
historical escalation in Alaska is shown in Table Dl.4.7.Data
for real coal prices in the lower contiguous 48 states were
obtained from a time series of bituminous coal prices compiled by
the U.S.Department of Commerce (1971).Overall,between 1900
and 1980,real coal prices have escalated at an average compound
annual rate of 1.2 percent.Even prior to the dramatic price
rise in 1973,coal prices from 1900 to 1973 escalated at a real
annual rate of 0.3 percent.
Historically,the factors driving real price escalation of coal
include real labor cost escalation,price escalation of
substitute energy sources,and resource depletion effects.
Countering the trend toward increasing coal mining costs were
increases in productivity which occurred as large-scale
851102 Dl-4-5
mechanized surface mining techniques replaced labor-intensive
underground mining.Despite these cost saving productivity
increases,real coal prices have increased steadily.There is a
good reason to expect this trend to continue into the next
century;the forces causing the escalation will likely continue,
while the productivity increases (which tend to lower prices)may
occur at a lower rate.
Because of the evidence of increasing coal prices over the past
80 years (a period comparable to the future planning period of
the proposed Susitna development),an analysis of factor costs
was made focusing on the cost components of labor,energy,
royalties,and other operating costs.Real increases in labor
and other costs over the project life will be reflected in the
price of coal.
Although long-term fuel supply contracts are usually negotiated
prior to constructing a coal-fired power plant,these contracts
ordinarily do not lock in a fixed price for coal.Agreements
between coal suppliers and electric utilities for the
sale/purchase of coal usually include a base price for the coal
and a method .of escalation to cover mining cost increases in
future years (Dames &Moore 1985a).The base price provides for
recovery of the capital investment,profit,and operating and
maintenance costs at the level in existence when the contract is
executed.The intent of the escalation mechanism is to recover
actual increases in labor and material costs from operation and
maintenance of the mine.Typically the escalation mechanism
consists of an index or combination of indices such as the
producer price index,various commodity and labor indices,and
consumer price index applied to operating and maintenance
expenses,and/or regulation-related indices.These
characteristics are exhibited by the Usibelli contracts with FMUS
and GVEA (FMUS 1976;Hufman 1981).The consequences in the
Nenana field are shown in Table D1.4.8.
>
From the above discussion,it is clear that coal production costs
with escalation of labor and energy input factors establish a
minimum price for Nenana coal.The consequences of this
escalation on the mine mouth cost of Nenana coal are shown in
Table D1.4.9.The production factors which are projected to
escalate are labor,fuels and lube,and electricity.Royalties,
which are assumed to be a fixed 12.5 percent of the realized
price,escalate in proportion to the increases in the above
factors.For the 2 million ton per year mine,the projected
mine mouth production costs are $22/ton in 1985 and $55/ton in
the year 2050 (in 1985 $).That is equivalent to about $1.45 and
$3.70 pe~million Btu,respectively.The composite real
escalation associated with that production cost .increase is 1.45
percent/year.
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The above discussion of production costs for Nenana coal does not
include the costs of coal transportation.Due to the proximity
of the field to Denali National Park,the coal would have to be
transported by rail before it is used in order to avoid violating
air quality standards.The Alaska Railroad (ARR)is the only
viable transportation alternative.Consideration of cost
escalation must,therefore,include rail cost escalation.
Analysis and projection of rail cost factors based on American
Association of Railroads'data yields an average annual
escalation of 2 percent (real).A second estimate based on
projection of historic data derived from the U.S.Department of
Labor Price Index for Rail Transportation yields a real price
escalation of 1.8 percent per year (Dames &Moore 1985a,pp.
34-37).The figure of 1.8 percent is used in this application.
Currently (1985),rail tariffs for moving coal from the existing
loading facility at Suntrana to Nenana are $5.92 per ton.At a
1.8 percent real escalation rate,this tariff will rise to $18.88
(in 1985 $)by 2050.Nenana is the shortest rail haul
destination which will not violate air quality standards.Other
destinations (such as Anchorage or Fairbanks)would have higher
tar iffs.
The current base price and real escalation rate for Nenana coal
provide a coal price trajectory.This trajectory includes both
production and transportation costs and is shown in Table D1.4.9.
The projected real rise in Nenana coal prices between 1985 and
2050 is 1.5 percent/year assuming that the coal is delivered in
Nenana.
4.3.3 Beluga Coal Netback Prices
The price of coal in the Pacific Rim market will determine prices
of Beluga coal under two conditions:
o When there is a demand for Alaska coal in the Pacific Rim
market at a price above Alaska production cost;
o When the Pacific Rim market can absorb all of the Alaska
prod uc t ion.
Unlike Nenana coal,the majority of Beluga coal will be sold
internationally.The basis for forecasting future Beluga coal
prices therefore is the value of Beluga coal on the Pacific Rim
market.The Pacific Rim will become a large and rapidly growing
coal market.Diamond Alaska anticipates producing 10 to 12
million tons annually for export before the end of this century.
Beluga coal producers will be able to sell all coal that can
851102 Dl-4-7
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reasonably be supplied into the Pacific Rim over the long term.
The Pacific Rim steam coal market will be sufficiently robust
that it will be capable of absorbing 3 to 4 times the amount of
coal that the Beluga field will be capable of producing.
Prevailing market prices should be well above Beluga production
cost.
Over the long run--the 50-year period of the Susitna project
evaluation--market conditions for coal in the Pacific Rim can be
expected to change from time to time,reflecting short-term
imbalances--relative surplus or shortage conditions--in the
market.Temporary periods of recession may reduce demand for
coal,causing lower prices.Temporary periods of fuel tightness,
such as could be caused by oil embargoes or gas supply
constrictions,could raise the demand for coal and cause higher
prices.There is no systematic basis for predicting over a
50-year period when minimum or maximum prices might occur for a
commodity such as coal.Thus,over the long run,the Pacific Rim
competitive market price trend FOB Alaska remains the most
reasonable economic basis for valuing Beluga coal.
The economic conditions of the competitive market model yield the
lowest prices that will match coal production and consumption.
Higher trend prices could be projected by assuming higher
resource rents or higher taxes as world energy resources become
more scarce over the long run.These "extra"market factors were
not estimated.Adopting Pacific Rim competitive market basis for
valuing the Alaska coal resource at Beluga accomplishes two
results:
o The Alaska resource at Beluga is valued at its highest and
best use that can reasonably be anticipated.
o The estimated coal price trend may remain understated
because other plausible economic conditions in the Pacific
Rim over the long term could exert an upward force on
market clearing prices.
Pacific Rim market prices were projected based on a supply/demand
analysis of the Pacific Rim market under both the SHCA and
composite oil price forecasts.The difference between the two
prices is largely caused by differences in diesel oil prices
caused by higher or lower crude oil prices.Diesel oil prices
determine the cost of transporting coal by rail from mine to
deepwater ports.As coal from the Powder River Basin becomes
increasingly significant,this differential is reflected in the
netback value of Alaska coal.Coal import figures were obtained
by projecting coal demand in Japan,Korea,Taiwan,and Southeast
Asia.These demand estimates were thenadj usted to ·reflect
estimates of indigenous (Le.,nonimport)supplies (Gordon 1984;
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Dames &Moore 1985c).Supply potential and costs were estimated
for export coal delivered to Japan--the key market point.Coal
supplies from Australia,Canada,Chinai the western lower 48
states and Alaska were included.The projected increase in
prices reflects the effects of reserve depletion as well as
increases in factor costs of coal production and transportation.
The Pacific Rim market price for Beluga coal is shown below.
BELUGA COAL NETBACK PRICES
(1985 $Million Btu)~
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Pacific Rim
Market Price
FOB Mines
f
1985
1990
1995
2000
2010
2020
2030
2040
2050
Composite
1,78
2.30
2.57
3.08
3.22
3.37
SHCA
1.78
2.13
2.55
3.30
4.10
5.12
f-
Based on Dames &Moore (1985a).
Deflated from 2000 to estimate 1985,1990,
and 1995 values.
4.3.4 -Beluga Coal Production Cost
Production costs also were estimated for Beluga coal,uS1ng
procedures identical to those described for Nenana coal.The
major difference was in the mine size.The Beluga analyses were
based upon mines of 8-12 million tons/year (Wierco 1985).The
base costs for this analysis are shown (in 1985 dollars)in Table
D1.4.10.
Given these base costs,the 1985 production costs (as escalated)
are as follows (based on Dames &Moore 1985a):
851102 Dl-4-9
Note that Beluga production costs escalate over time but remain
below the export market clearing price.Production costs for
Beluga coal escalate for the same reasons identified for Nenana.
Year
1985
1990
1995
2000
2010
2020
2030
2040
2050
Mine Mouth Coal
Beluga Production Cost
(1985 $/MMBtu)
1.17
1.26
1.36
1.46
1.69
1.96
2.27
2.63
3.04 ~
I
4.4 -Alaska Coal Prices Summarized
Table Dl.4.1l summarizes the Nenana and Beluga coal cost and price
trends discussed above.
[-
!-
851102 Dl-4-10
~-
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5 -DISTILLATE OIL
Distillate oil,i.e.,fuel oil used in diesel engine and gas turbine
generating units,is not a significant factor in the analysis of
Railbelt generation alternatives for the years 1993 to 2040.With an
electric interconnection between Anchorage and Fairbanks,generation
with diesel engines will be eliminated except in small isolated
communities.Any generation provided by oil-fired units will either be
the same for all alternatives or the differences will be so small that
they can be ignored in the economic comparison of the alternatives.
However,to provide a complete picture for fuels actually used in the
Railbelt for electrical generation,the following information on
distillate oil availability and price is presented.
5.1 -Availability
According to Battelle (1982),there is adequate availability of
distillate oil during the analysis period.Although part of the
distillate oil used in Alaska is imported,this fact alone will not
affect its availability.It has been assumed that distillate oil in
the required quantities will be available during the economic analysis
period 1993 to 2040 from refineries within Alaska or the Lower 48
states.
5.2 -Distillate Price
Regression analysis demonstrates that distillate oil prices are
generally $1.66/MMBtu above the cost of crude oil (Statistical
Abstracts,USDOC 1975,1984,1985).The $1.66/MMBtu represents some
refining charge plus a premium for fuel quality.Because netback
analysis yields natural gas prices in Alaska that are below the costs
of crude oil,while regression analysis demonstrates that distillate
oil always costs more than crude oil,distillate oil will not be
competitive fuel for future power generation in the Railbelt
interconnected power generation system.
851102 Dl-5-1
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6 -REFERENCES
Alaska Department of Natural Resources.1985.Historical and Projected
Oil and Gas Consumption,January 1985.Alaska Department of Natural
Resources Division of Oil and Gas.
Alaska Department of Revenue.1985.Petroleum Production Revenue
Forecast.Quarterly Report,June,1985.
Alaska Public Utilities Commission.1984.Cost of Service by Customer
Class Analysis for Revenue Requirements Study.Docket No.
U-84-59.
American Gas Association.1985.Energy Analysis:The Outlook for
Ammonia Production in the U.S.AGA.Arlington,VA.
Battelle Pacific Northwest Laboratories.1982.Railbelt Electric Power
Al ternative Study:Fossil Fuel Avai labi lity and Price Forecasts,
Volume VII.March 1982.Page 81.
Booz,Allen and Hamilton.1983.Evaluation of Alternatives for the
Transportation and Utilization of Alaskan North Slope Gas:Summary
Report.
C.ITOH &Co.,LTD.(Itoh 1985).LNG Marketing in Japan.February.
Chemical Engineering Magazine.1985.Vol.92,No.18.September 2.Page
7.
Dames &Moore,1985a.Analysis of Factors Affecting Demand,Supply and
Prices of Railbelt Coal.Volume 1 (Main Report).
·1985b.Analysis of Factors Affecting Demand,Supply and Prices.
--Volume 2.
•1985c.In house document containing calculations of Coal Price
--escalations.July.
•1984.Coal Production and Transportation Costs:U.S.and Canada
---Export Mines.February 1984 Revision of the April 1983 Report.
Davis,N.1984.Energy/Alaska.University of Alaska Press.
Energy Resources Company.1980.Low Rank Coal Study:National Needs for
Resource Development.Volumes 1-6.
Fairbanks Municipal Utility System.1976.Contract between FMUS and
Usibelli Coal Mine for the sale of coal to the Chena Power
Station.
851102 Dl-6-1
French,M.1985.Long Term Outlook for Petroleum Prices.Wharton
Econometric Forecasting Associates,Philadelphia,PA.June 30.
Golden Valley Electric Association,Inc.1981.Usibelli contract with
G.V.E.A.for Current Coal Pricing.
Gordon,Andrew.1984.Guide to World Coal Markets.Arlington:Pasha
Pub lica tions .
Hay,N.E.1985.The Outlook for Ammonia Production in the United
States.Gas Energy Review (AGA)13(7):9-12.
Hickel,W.,et ale 1983.Trans Alaska Gas Systems:Economics of an
Alternative for North Slope Natural Gas.Governor's Economic
Committee on Natural Gas.Anchorage,AK.
Hufman,R.L.1981.Letter from R.L.Huffman,General Manager,
G.V.E.A,to B.J.Brown,Regional Manager,Acres American Inc.
Mann,C.,D.Tillman and W.Wade.1985.Analysis of the Coal
Alternative for Supplying Power to the Railbelt Region of Alaska.
Prepared for the Alaska Power Authority,October.
Manne,A.S.and L.Schrattenholzer.1985.International Energy
Workshop:A Progress Report.June.
Marubeni Corporation.1984.Energy Situation and LNG Market in Japan.
Prepared for New Alaskan LNG Project.Tokyo,Japan.January.
McGee,D.1985.Letter to M.SeIdman,Dames &Moore,from Don McGee,
Chief Petroleum Geologist,State of Alaska,Department of Natural
Resources.July 1,1985.
Mitsui &Co.,LTD.1985.LNG Situation 1n Japan.Tokyo,Japan.
January.
MPP Associates.1985.Proposal for a Comprehensive Feasibility Study of
the Matanuska Power Project.Prepared for Matanuska Electric
Association,Inc.,Palmer,Alaska.
National Research Council.1980.Surface Coal Mining in Alaska:An
Investigation of the Surface Mining Control and Reclamation Act of
1977 in Relation to Alaskan Conditions.With the National Academy
of Sciences,Commission on Natural Resources,Board on Mineral and
Energy Resources,and the Committee on Alaskan Coal Mining and
Reclamation.As cited in Wierco 1985.
Pacific Alaska LNG Associates.Docket No.CP75-l40 Exhibit No.194
(JWO-15)..Capital and Operating Cost Estimates.
r
r
L
851102 Dl-6-2
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Pratt,S.1985.Personal Communication with Pratt,Financial Analyst
APUC and D.Tillman of Harza-Ebasco on May 2,1985.
Purvin and Gertz,Inc.1983.Gas Processing Seminar.Presented to
Panhandle Eastern Pipeline Co.
Sanders,R.B.1982.Coal Resources of Alaska.Alaska Geographic 9(4):
146-165.
Schaff,R.1983.Letter from Mr.Ross G.Schaff,State Geologist,
Department of Natural Resources,Division of Geological and
Geophysical Surveys,to Mr.Eric P.Yould,Executive Director,
Alaska Power Authority.February 1,1983.
Sheldrick,W.F.'1984.World Fertilizer Review and the Changing
Structure of the International Fertilizer Industry.A Paper
Presented at the Australian Fertilizer Manufacturer's Conference,
Perth,Australia.Washington,D.C.:Industry Department,World
Bank.November,1984.
Sherman H.Clark and Associates.1985.Oil Price Outlook:February
1985.Prepared for Harza-Ebasco Susitna Joint Venture.
Smith,D.1985.Personal Communication between Marvin Feldman,Dames &
Moore and Dennis Smith.Alaska Railroad.July 16,1985.
State of Alaska vs.Phillips Petroleum Company.1984.Joint Stipulation
of Facts Dated April,1984.In the Superior Court for the State of
Alaska.No.I-JU-81-698 CIV.
State of Alaska vs.Phillips Petroleum Company.1984.Settlement
Agreement.In the Superior Court for the State of Alaska.No.
1-JU-81-698 CIV.
Sumitomo Corporation.1985.LNG:Monthly Statistics in Japan.April.
Tarrant,B.1985.Another LNG Plant for Peninsula.Alaska Oil and Gas
News.Volume 4,Number 3,March,1985.
Thirteenth Amendatory Agreement to Liquefied Natural Gas Sales
Agreement between Tokyo Electric Power Company,Inc.,Tokyo Gas
Company,Ltd.,Marathon Oil Company,and Phillips Petroleum
Company,effective April 1,1982,and the Supplementary
Administrative Memorandum.State of Alaska,Department of Law.
Thrush,P.,et ale 1968.A Dictionary of Mining,Mineral,and Related
Terms.U.S.Bureau of Mines,Washington,D.C.
Title II of the Power Plant &Industrial Fuel Use Act of 1978 (FUA),42
U.S.C.para.8311-8324.
851102 Dl-6-3
u.s.Department of Commerce.1984.Statistical Abstract of the United
States.104th Edition.
•1985.Statistical Abstract of the United States.105th Edition.
•1975.The U.S.Fact Book:The American Almanac.95th Edition.
•1971.Historical Statistics of the U.S.Colonial Times to 1970,
----Part I (For 1910-1970)Series M96.
Weirco.1985.Hypothetical Mining Studies and Coal Price Estimates -
Beluga and Nenana Coal Fields,for Harza-Ebasco Susitna Joint
Venture.Job.No.2988-c.November.
wunnicke,E.1985.Letter from the Commissioner of the Alaska
Department of Natural Resources to Ben Grussendorf,Speaker,Alaska
.State House of Representatives with Attachment,March 11.
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851102 01-6-4
TABLES
I
TABLE D1.3.1:NATURAL GAS VALUES DELIVERED
IN TOKYO COMPARED TO CRUDE OIL VALUES
Crude Oil Crude Oil Natural Gas
(Price Pried.!Price.V
I ($/bb 1)($/MMBtu)($/MMBtu)
\ !
]10 1.72 1.71
20 3.45 3.44
[-30 5.17 5.16
40 6.90 6.87
50 8.62 8.60
60 10.34 10.31
70 12.07 12.03
75 12.93 12.89
1/bbl
$/bb1 x 5.8 MMBtu
G(n-l)(from Supplementary Administrative
p(n)=592.8 x 34.48 Memorandum)
\.p(n)=LNG price (4!MMBtu)
G(n-l)=Government selling price for crude oil in $/bbl.on the
last day of the month (n-l)prior to the month when the LNG
is sold.
Source:Thirteenth Amendatory Agreement to Liquefied Natural Gas Sales
Agreement between Tokyo Electric Power Company,Inc.,Tokyo Gas Company
Ltd.,Marathon Oil Company,and Phillip's Petroleum Company,Effective
April 1,1982 and the Supplementary Administrative Memorandum.
1
i
TABLE 01.3.2:WORLD 0 IL PRI CE FORECASTS BY CASE (
(1985 $/MMBtu)
Wharton Composite SHeA l~
Year Case Case Case
I
1985 4.70 4.70 4.80
1990 4.30 4.60 4.80 \
1995 4.80 5.50 5.70
2000 5.40 6.60 7.10
2010 7.00 8.80 10.60 I
L
2020 9.40 11.90 14.70
2030 12.70 12.90 16.60 \~
\
2040 12.90 12.90 18.30
:l205012.90 12.90 20.20
TABLE D1.3.3:ESTIMATED CAPITAL,OPERATING AND
MAINTENANCE,AND FUEL mSTS OF A 200
MMCF LIQUIFIED NATURAL GAS FACILITY
FOR mOK INLET,ALASKA
(Mill ion 1985 $)
Parameter Cost
[-
Capital Cost
Liquefaction
Regasification
TOTAL
Operating and Maintenance Costs
Liquefaction
Regasi fication
TOTAL
Fuel Requirements
Liquefaction
Regasi fication
TOTAL
Sources:Hickel,et al.,1983;Purvin &Gertz 1983;
Chemical Engineering Magazine 1985
652
304
956
l3.0/yr
4.l/yr
17.l/yr
10.6%of delivered
0.5%of delivered
11.1%of delivered
LEVELIZED NON-FUEL PRODUCTION COSTS FOR
LNG DELIVERED FROM COOK INLET TO JAPAN
TABLE Dl.3.4:
Cost Category
Capital
Liquefaction
Regasification
Subtotal
Operating and Maintenance
.Liquefaction
Regasi fication
Subtotal
Total
Real Levelized Cost
(1985$/MMBtu)
$1.32
.61
1.93
.17
.05
0.22
2.15
Percent of
Total Cost
61.4 %
28.4 %
89.8
7.9 %
2.3 %
10.2
100 %
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Parameter
TABLE D1.3.6:CAPITAL fiSTS FOR LIQUEFACTION
AND REGASIFICATION IN ALTERNATIVE LNG
SENSITIVITY CASES (1985$)
Case
TAGS-Phase II
Total$xl0 6 $/MMBtu/Yr
TAGS-Phase III
Total$xl0 6 $/MMBtu/Yr
1/By means of comparison the base case value is $9.36/MMBtu/Yr
'1:../By means of comparison the base case value 1S $4.36/MMBtu/Yr
Jj By means of comparison the base case value is $13.72/MMBtu/Yr
Sources:Hickel,et-al.,1983 ;Purvin &Gurtz 1983
Liquefaction
Rega si fi cat ion
Total
1,923
889
2,812
7.511/
3.472:./
10.981/
4,776
2,209
6,985
6.251/
2.892:/
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TABLE D1.3.7:ALTERNATIVE TRANSPORTATION COSTS
FOR SHIPPING LNG FROM mOK INLET TO JAPAN
(1985 $/MMBt u)
Condition/Scenario
Booz,Allen &Hamilton
TAGS Es timate
Weak Economy
Strong Economy
Flat Prices
Base Price
0.35
0.41
0.33
Governor's Economic Committee
New LNG Tankers
Chartered Tankersl/
El Paso Tankers
(Cha rtered)
1.23
0.74
0.65
1/Value used in this analysis.
Source:Booz,Allen &Hamilton 1983.
TABLE D1.3.8:1981 NATURAL GAS REVENUE REQUIREMENTS
(1981 $)
Cost Category
CEA and AML&P
Total ($)$/MCF
Total
To ta 1 ($)$/MCF
Total Gas Cons LmIed (MCF)
Expenses
operation &Maintenance
Production &Gathering
Transmission
Distribution
Cus tome r Accounts
Service &Info rmation
Sales
Adm inist rati ve
Depreciation
Non-Income Taxes
Return on Investment
9,959,127
6,476,280
170,714
208,523
1,850
224
432
234,086
464,058
90,243
1,331,532
N/A
.650
.017
.021
NEGL
NEGL
NEGL
.024
.047
.009
.134
29,835,835
19,425,580
640,770
2,266,666
1,643,280
199,421
384,394
2,963,339
2,550,172
708,468
7,304,108
N/A
.651
.021
.076
.055
.007
.013
.099
.085
.024
.245
r
Income Taxes
Total Cost of Service
-Cost of Gas
Acquisition 1/
Net Non-Fuel Cost
of Service
709,064 .071
9,759 ,0 06 0•98
(6,444,723)(0.65)
3,134,283 0.33
3,889,568
41,975,766
(19,307,344)
22,668,422
.130
1.41
(0.65)
0.76
1/65¢/MCF was the average cost of natural gas purchased by Enstar for sale
to its customers in 1981.This is confirmed by Master Tariff filings of
Enstar before the APUC.
Source:APUC 1984.
TABLE D1.3.9:1981 NATURAL GAS REVENUE REQUIREMENTS TO
UTILITIES EXPRESSED IN JAN.1,1985 $
[-
Cos t Category
Total Gas Consumed
Expenses
operation &Maintenance
Production &Gathering
Transmission
Distribution
Customer Accounts
Service &Information
Sales
Admini strat ive
Depreciation
Non-Income Taxes
Re turn on Inves tment
Income Taxes
Total Cost of Service
-Cost of Gas Acquisition
Net Non-fuel Cost of Service
Total Costl/
7,583,723
199,906
238,492
2,166
262
506
274,958
543,412
105,675
1,559,224
830,314
11,427,796
(7 ,5 46 ,771)
3,670,245
$/MCF
9,959,127 MCF
.761
.020
.025
NEGL
NEGL
NEGL
.028
.055
.011
.157
.083
1.140
( •761)
.38
1/Escalated from 1981 dollars by a factor of 229.07/195.60 =1.171.
Source:Calculated from Table D1.3.8.
CALCULATION OF GAS COSTS DELIVERED TO lITILITIES FOR '!HE
ffiMPOSITE OIL PRICE SCENARIO USING BASE CASE NETBACK
PRICE ASSUMPTIONS (IN 1985$/MMBtu)
GAS Cost
Wellhead Delivery
Value Charge
TABLE D 1.3 .10:
YEAR
1985
1990
1995
2000
2010
2020
2030
2040
2050
1.58
1.50
2.25
3.13
4.97
7.45
8.30
8.30
8.30
0.40
0.40
0.40
0.40
0.40
0.40
0.40
0.40
0.40
Total Cos t
1.98
1.90
2.65
3.53
5.37
7.85
8.70
8.70
8.70
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TABLE 01.3.11:ALASKA DNR ESTIMATES OF PROVEN AND REa:>VERABLE
COOK INLET NATURAL GAS RESERVES BY FI ELD
(Billion Cubic Feet)·
Field Remaining Recoverable
Reserves as of January 1,1985
Kenai 850
North Cook Inlet 650
Beluga River 800
Swanson River 260
Cannery Loop 300
)-
McArthur River and Trading Bay
Beaver Creek
Cook Inlet Associated Gas
Ivan River -Lewis River -
Pretty Creek -Stumplake
Other
Total
Source:Wunnicke 1985.
650
230
60
600
63
4,463
TABLE Dl.3 .12:ALASKA DNR ESTIMATE OF UNDI SOWERED
NATURAL GAS RESOURCES IN roOK INLET
BASIN (Trillion Cubic Feet)
Undiscovered Resources
Economically
Probabil ity Total Recoverable
.99
.95
.90
.75
.50
.25
.10
.05
.01
Source:Schaff 1983.
.47 .00
.93 .22
1.24 .43
1.98 .93
3.07 1.76
4.38 2.78
5.84 4.04
6.93 4.90
9.06 6.83
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TABLE D1.3.13:ALASKA DNR COOK INLET NATURAL GAS PRODUCTI ON AND USE
1971-1984
Gas Production and Use
(Billion Cubic Feet)
Field Ammonia Gas Producers
Year Ops LNG Urea Power Ut il it ie s11 Refiners Other Total
1971 45.3 63.2 19.5 14.7 10.2 NIA 14.1 154
1975 28.8 64.8 23.9 25.5 12.1 12.4 2.0 170
1978 25.9 60.9 48.9 29.7 13 .5 10.5 0.9 190
1981 20.6 68.8 53.8 33.6 15.8 5.6 0.4 199
1984 20.5 65.5 50.9 34.5 19.3 12.0 4.3 207
11 Residential and commercial use.
Source:ADNR 1985.
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This compares to an OGP derived forecast of 658 BCF.The ADNR forecast ~s
12 percent more conservative and is therefore used.
Treated as 10 percent of Total based on 1971-1984 average.
Extrapolated at current rates of consumption.
Source:ADNR 1985.II r
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TABLE 01.3.15:
Country of
Production
USA
Existing Plant
New plant
Mexico
Trinidad
Chile
Canada
USSR
Nigeria
Middle East
Indonesia
Australia
Source:AGA 1985.
mSTS ASSOCIATED WITH AMMONIA PRODUCTION
IN SELECTED mUNTRIES (1985 $/ton)
Cost of Ammonia Production
Product Total
Capital Cost Cost (delivered to U.S.)
$41 $132
185 256
208-281 244-343
209-282 246-349
209-282 256-349
206 272-277
282 319-359
209-282 256-349
209-282 266-369
209-282 266-379
206-267 313-405
TABLE D1.3.l6:roTENTIAL DEMAND FOR COOK INLET NATURAL GAS
2000-2050 (Trillion Cubic Feet)
Total Requirement for
50 Year Period
I
I
Market
Residential &Commercial
Existing Power Plants
and Peaking Units 1/
Mil itary
Urea
Liquefied Natural Gas
Total
Field Operations
=10%
2.9
0.3
0.3
2.8
3.7
10.0
1/There is an assumed commitment to any power plant that 1S
forecast by the OGP model to come on-line.
1 '
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TABLE D1.3 .17:ESTIMATED NORTH SLOPE RECOVERABLE
RESERVES OF NATURAL GAS
(Billion Cubic Feet)
1-
1
Prudhoe Bay Unit
Sadlerochit reservoir
Sag River reservoir
Lisburne reservoir
Endico tt
Point Thomson Area and
Flaxman Island Area
North Prudhoe Bay
West Dock Area
Milne Point Area
Gwydy r Bay Area
Shallow Cretaceous Sands
Kuparuk River Uni t
Subtotal
Undi scovered II
S tate Total
11 Derived by Harza/Ebasco.
Source:ADNR 1985.
Low
29,000
800
600
3,200
135
33,735
3,264
36,999
Mid
29,000
1,100
800
5,000
220
36,120
3.264
39,384
High
29,000
1,600
1,200
6,000
260
38,060
15,000
53,060
TABL E D1.4.1:SUMMARY OF ALASKA I S COAL RESO URGE S
Coal Resources (estimates in millions of tons)1-
Undis-
IIcovered
Resources
Identified Resources Hypo thet-
Demonstrated Total ica1 and Total
Region Measured Indicated Total Inferred Identi fied Speculative Resources
a b c=a+b d e=c+d f e+f
Arctic 35 2,760 2,800 118,000-60,000-402,000-462,000
119,000 1461.9 00 4,000,000 4,150,000
Northwest
Interior 862 2,700 3,560 3,380 6,940 10,400 17,300
Southwest
Southcentra1 767 2,070 2,820 7,850 10,700 1,480,000 1,490,000
Southeast
Total s1J 1,664 7,530 9,180 129,000-77 ,600-1,900,000-1,980,000-
130,000 164,000 5,500,000 5,660,000
11 This entry reflects the range in estimates given by Sanders (1982)rather
than the actual sum of demonstrated and inferred resources.
1/Totals do not add due to rounding on demonstrated measured resources.
Source:Davis 1984.
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TABLE Dl.4.2:RESERVES AND RESOURCE OF THE NENANA FIELD
Reserve/Resource Type
Reserve Base
Resources
Measured
Indicated
Inferred
TOTAL
Quantity
(million tons)
457
862
2,700
3,400
6,9001/
1/Totals do not add due to rounding on measured and
inferred.The reserve base is included in the
measured resources.
Source:Energy Resources Company 1980.
TABLE Dl.4.3:APPROXIMATE POTENTIAL PACIFIC
RIM COAL IMPORTS 1990-2040
(MILLION TONS)
1/May not convert due to rounding.
Source:Dames &Moore (1985a,Table 3-2,pg.42).
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Steam Coa 1 for
Electric Power
Metric Tons Actual
Coal Equivalent 1/(Beluga)
(MTCE)Tons 2J
63 100
108 200
176 300
256 500
349 600
395 700
27.8 million Btu/ton.
1990
2000
2010
2030
2040
Year
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TABLE 01.4.4:POTENTIAL UNCONSTRAINED
I
ALASKA COAL EXPORTS
(MILLION TONS)
Mill ion Tons
~Per Year
Year (Actual)
)-2000 31
2010 78
2020 131
2030 195
2040 226
Source:Dames &Moore (1985a).
TABLE D1.4.5:POTENTIAL BELUGA COAL DEVELOPMENT
UNDER MANAGED CONDITIONS
Year
2000
2010
2030
2050
Source:Dames &Moore (1985a).
Million Tons
Per Year
10-15
25-30
50-60
75-100
I
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TABLE D1.4.6:PRODUCTION COST ANALYSIS FOR NENANA COAL
(1985 $)
J-
Parameter
Production Rate (tons/yr)
Mine Li fe (yrs)
Average Stripping Ratio
Personnel Requirements
Operating
Mai ntena nce
Salaried
Total
Tons per Manshift
Capital Investment
Initial Investment (thousands)
Initial Investment per Annual Ton
Life of Mine Investment (thousands)
2 Million Ton/Yr
Incremental
Capacity 11
2,000,000
20
3.73
93
75
34
202
39.6
$75,059
37.53
140,350
Average Annual Operating &Maintenance Costs (per ton)
Average Depreciation of Total Capital
Average Total Production Costs
Levelized Coal Price Per Ton
At 8.2 percent real discount rate II
Levelized Coal Price Per Million Btu
At 8.2 percent real discount rate 1/
13.12
3.54
$16.66
$22.10
$1.45
II Incremental production to increase from 2 million to 4 million
tons/yr.
II Reflects nominal rate of return of 14.2 percent and underlying
rate of inflation of 5.5.percent.
TABLE D1.4.7:PRODUCTION COST ESCALATION FOR NENANA FI ELD COAL
Parameter
Base (Contract)Year
Base Coal Price
Current Coal Pricell
Escalation Period
Escalation Rate
Inflation Rate
During Escalation Period
Real Rate of Coal Price
Escalation
Usibell i Coal
Golden Valley
Electric Assn.
1974
$0.47/MMBtu
$1.30 IMMB tu
11.25 yrsl/
9.46%/yr
7.2%/yr
2.2%/yr'i../
Contract
Fairbanks Municipal
Ut iIi ty Sy stem
1976
$0.72 IMMB tu II
$1.56/MMBtu
8.5 yrs!!..1
"9.52%/yr
6.7%/yr
2.6%/yr
II $12.61/ton x ton/17.4 MMBtu
1/First quarter,1985 as reported by GVEA and FMUS.
1/Contrac t be ga n December 1,1973.
!il Contract began July 1,1976.
21 If the GVEA rate is calculated over a 20 year period,the
nominal escalation rate for coal is 8.0%/yr and the inflation
rate is 5.9%.The real escalation rate is 2.0%/yr~
Sources:Utility current coal prices;Usibelli contracts with GVEA
and FMUS.
Statistical Abstract (1984)and U.S.Department of Commerce.
~-
TABLE D 1.4.8:NENANA REAL mAL PRODUCTION COST ESCALATION
(Basis:Mine Mouth Coal Cost,1985 $)
Case Parameter
1985 Cos t
($/ton)
Escalation
Rate
(percent)
2050 Cos t
($/ton)
2 million
ton/year
Labor
Fuels and Lube
El ect ri city
Royal ty
Other Operating Costs,
Capital,and Taxes
TOTAL
8.26
0.97
o .76
2.76
9.33
22.08
2.2 36.04
2.2 2.25
1.3 1.76
1.4 1.1 7.05
0.0 9.33
1.45 1/56.43
1/Derived.
Source:Dames &Moore (1985a).
r 'I
TABLE D1.4.9:PRESENT AND PROJECTED NENANA mAL PRICES
($1985 per Million Btu)
1/Derived from Wierco (1985)and Dames &Moore (1985a).
~/Based on the 1985 ARR tariff of $5.92 per ton
(personal communication,Dennis Smith,ARR,7/16/85).
Co s t Componen t
Mine Mouth Rail
Coal Productionl/Transportation~/
)
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1.84
1.99
2.14
2.31
2.69
3.13
3.64
4.24
4.94
Delivered
Cos t
0.39
0.43
0.47
0.51
0.61
0.73
0.87
1.04
1.24
1.45
1.56
1.67
1.80
2.08
2.40
2.77
3.20
3.70
1985
1990
1995
2000
2010
2020
2030
2040
2050
Year
j
1
I-
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TABLE Dl.4.10:SUMMARY OF RESULTS HYPOTHETICAL
MINE STUDIES FUR LARGE BELUGA MINES
(1985 $)
Production Rate
Parameter 8 Million Ton/Yr 12 Million Ton/Yr
Mine life (years)
Average stripping ratio
Personnel Requirements
Operating
Maintena nce
Salaried
Total
Tons per manshi ft
Capital Investment
30
6.75
297
306
88
691
46.3
30
6.93
473
505
113
1,091
44.0
Initial investment (thousands)
Initial investment per annual ton
Life of mine investment (thousands)
Average Annual Operating and
Maintenance Costs (Per Ton)
Average depreciation of total capital
Average Total Production Costs
Leve1ized Coal Price Per Ton
$277,176 $424,369
$34.65 $35.36
$573,660 $866,420
$11.38 $11.71
$2.48 $2.46
$13.86 $14.17
At 8.2 percent real discount rat el/
Levelized Coal Price Per Million Btul/
At 8.2 percent real discount ratel/
1/Assumes 7,500 Btu/lb.
$17.50
$1.17
$18.34
$1.22
1/Reflects nominal rate of return of 14.2 percent and underlying rate of
inflation of 5.5 percent.
TABL E D1.4 •11 :PROJECTED COSTS OF COAL DELNERED IN
THE RAILBELT REGION OF ALASKA
(in 1985$/MMBtu)
Nenana Beluga Market Clearing Bel uga
Field Field
Year (Delivered)SHCA Composi te Production
1985 1.84 0.30)(l.42)1.17
1990 1.99 (1.45)0.54)1.26
1995 2.14 (1.60)(l .65)1.36
2000 2.31 1.78 1.78 1.46
2010 2.69 2.13 2.30 1.69
2020 3.13 2.55 2.57 1.96
2030 3.64 3.30 3.08 2.27
2040 4.24 4.10 3.22 2.63
2050 4.94 5.12 3.37 3.04
)
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FIGURES
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BASE CASE NATURAL GAS WELLHEAD NETBACK PRICE CALCULATION ILLUSTRATION
16
14
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TRANSPORTATION COST
LIQUEFACTION ENERGY COST
2020
YEAR
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OIL DERIVED DELIVERED ...
VALUE OF NATURAL GAS
1990
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14.012.010.08.06.04.0
COOK INLET NATURAL GAS RESERVES (TCF)
2.0
1.0 ESTIMATED RESERVES
w FOR PLANNING PURPOSES
0 O./z
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The McKelvey Diagram
Nonresources
Increasing degree of certainty
FIGURE D1.3.{
I
t•
Adv...,
AMAX c••,Co•
....do.lar",.,...
LIGNITE CREEK BASIN
Il'ClCU...\.C-O"::A::L=.;'-AS~I~N--S"';O~F~--'
THE NENANA REGIONo10.Un-
,,'I ••.......I _--:._.....'J__...''L',_...._U kll...,.,.
COAL LEASEHOLDERS IN THE NENANA COALFIELD
Lignite Creek and Healy Creek Basins
HEALY CREEK BASIN
llelb....Coal MIM.Inc.Ren."'w[
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FIG U RED 1.4.1
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N
MATANUSKA•
ANCHORACE
Kenai
Peninsula
5 10 15 20 25 mile.I I I -I ,
FIGURE D 1.4.2
5 0 5 15 25 kilometers
"'".....'_....'....._.:..'......I......,j!
o,5,
MAJOR COAL LEASEHOLDERS
Beluga-Venta Coalfields
Diamond
Shamrock
AMAX Coal Co.
.a ••-Hunt-WII.on
~Mob"0"Co.
Beluga
Coal Co.