HomeMy WebLinkAboutUse of north slope gas for heat and electricity in the railbelt 1983USE OF NORTH SLOPE GAS FOR
H EAT AND ELECTRICITY IN THE RAILBEL T
L
FINAL REPORT
FEASIBILITY LEVEL
ASSESSMENT
EBt(£:0
EBASCO SERVICES
INCORPORATED
SEPTEMBER 1983
~-ALASKA POWER AUTIIORITY _ _____,
S u s 1tna Join-t Venture
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Please Return To
DOCUMENT CONTROL
r -~ ~SE OF NORTH SLOPE GAS FOR -
HEAT AND ELECTR ICIT Y IN THE RAILBEL T
Fl AL REPO RT .
FEASIB~LITY LEVE L
ASSESSMEN T
EBfJSCO
EBASCO SERVI CES
INCORPORATED
SEPTEMBER 1983
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I am pleased to present this report prepared for the Alaska
Power Authority by Ebasco Services,Incorporated.The purpose of
this study is limited,and care should be taken not to draw un-
founded conclusions.
it is a feasibility assessment of certain technical aspects of
North Slope gas utilization in the Railbelt.The study examines
the engineering and environmental feasibility of three alternative
approaches for generating and transmitting electrical energy.For
each approach,the preferred type of power generation technology,
gas transport facility,and electrical transmission system is
identified.Based on representative electrical energy demand
scenarios,a representative scale ~nd conceptual design is
presented for each of the various facilities.The costs for
construction of the facilities are estimated at a reconnaissance
level.To provide a sound basis for the cost estimates,realistic
physical settings are identified for each facility.Siting and
environmental constraints are discussed.
The study does not purport to offer a complete power
development plan or to offer insight into the economic or
environment~l tradeoffs of Nort~Slope.gas utilization in relationtootherRallbeltpowergeneratl0noptlons.On the other'hand~'"
this report does provide a sound engineering,environmental and
cost basis for undertaking more comprehensive power generation
planning and analysis,where North Slope gas utilization might be
one part of an integrated power development plan.
The Power Authority's review of Ebasco's work has led to a
difference of opinion on the selected electrical transmission line
tower design and,therefore,on its construction cost.The Author-
ity's view of the matter is discussed in the attached memorandum.
The differences are a matter of professional judgement and resolu-
tion will require a more detailed level of analysis.
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LTBRAR-Z
August 29~1983
USE OF NORTH
SLOPE GAS FOR
HEAT AND ELECTRI-
CITY IN THE
RAILBELT
DATE:
FILE NO:
SUBJECT:
-----.......-·ate of Alaska
TELEPHONE NO:
ReadersTO;
MEMORAN'OUM
FROM.~~,.(~
Director of
Engineering
1~·4';;..~'-,\'
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Attachment:As Stated
9986/065
ARLIS
Alaska Resources
Library &Information Services
llnchorage,AJaska
'.02-001AIRev.10 179!
~
After meeting with EBASCD,I instructed Diversified Engineers to
prepare a conceptual tower design and,based on that design,prepare an
independent cost estimate for the North Slope to Fairbanks Transmission
System -Medium Load Forecast.Attachment 1 is a summary of the Diversi-
fied cost estimate.A copy of Diversified's detailed cost estimate and
tower design analysis is in the project file.(The Diversified concep-
tual tower design was reviewed and considered satisfactory by Mr.Yerkes).
To make the Diversified estimate comparable to the EBASCD estimate,I
adjusted the costs for Land and Land Rights and added a 20 percent
contjngency (see Attachment 2).The adjusted Divesified estimate is
$1,680,118 t OOO.This compares to the EBASCD estimate of $2,370,827,000
(Table 2-6).In my opinion,the Diversified estimate is the more
reasonable.
This study included project scoping,preliminary siting,conceptual
design and cost estimates for three alternative scenarios for the utili-
zation of North Slope natural gas to generate electricity for use in the
Railbelt Region.The three scenarios are based on generating facilities
located on the North Slope,at Fairbanks,and on the Kenai Peninsula and
the study is based on medium and low load growth forecasts.The concep-
tual estimates prepared by EBASCD can be grouped into three categories;
1)generating facilities,2)natural gas transmission and distribution
facilities and 3)electrical transmission facilities.After reviewing
the cost of estimates,it is my opinion that the cost estimates for the
generating facilities and natural gas transmission facilities are con-
servative,but reasonable and satisfactory for this level of study.
However,in my opinion,EBASeD's transmission facility cost estimates
are overly conservative (too high)and I cannot support them.
In order to try to resolve differences,I requested and received
estimating backup data from EBASCD,and on May 16,1983,Mike Yerkes of
our staff and Art Lee of Diversified Engineers and Constructors,Inc.11
met with the EBASCD staff at Bellevue,Washington.The EBASCD cost
estimates are high,because,in my opinion,they are based on a very
conservative transmission line tower design and because EBASCD used very
conservative cost assumptions.EBASCD still maintains their design
assumptions and cost estimates are reasonable.
MEMORANDUM
Project File
--.
August 26,1983
North Slope Gas Study,
Cost Estimates
Draft Final Report by Ebasco,
January 1983
State of Alaska'
DATE:
FILE NO:
SUBJECT:
TELEPHONE NO:
<i:>
!10 ,,!,'l'~
Robert A.Mohn ~n 9
Project Manager
Remy G.Williams ~
Cost Estimator
TO:
FROM:-
Thru:_
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Based on the Diversified estimate and on Power Authority bid
experience on the Anchorage-Fairbanks Intertie,I prepared cost estimate
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!iL)02-o<llA(Rev.10;79)
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Memo to Project File
Through Robert Mohn
From Remy G.Williams
August 26,1983
Page 2
summaries for the -remaining transmissi9n schemes.The summaries are
shown on Attachment 3 thru 7.In my opinion these estimates should be
used in lieu of the EBASCO estimates.
1/Diversified Engineers and Constructors,Inc.,is under contract
to the Alaska Power Authority to provide independent cost estimating
services on an as-needed basis.
North Slope to Fairbanks Transmission Line
Medium Load Forecast
May 26,1983
DIVERSIFIED ENGINEERS &CONSTRUCTORS,INC.
COST &ESTIMATE SUMMARY
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Item
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2.
3.
4.
5.
6.
7.
8.
9854/037
Description
Switching Stations
Substations
Energy Management System
Steel Towers &Fixtures
Conductors &Devices
Clearing
Subtotal
Land &Land Right
Engineering &Construction
Total Construction Cost
Amount
$86,190,302
140,399,826
5,786,116
891,777,010
36,238,112
143,253,589
$1,303,644,955
18,000,000
60,452,966
$1,382,097,921
-----"
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ALASKA POWER AUTHORITY
7/18/83 ,
R.Williams
COST SUMMARY
North Slope to Fairbanks Transmission System
North Slope Power Generator -Medium Load Forecast
(January '82 Dollars)
Item Description Amount
1.Switching Stations $86,190,302n-2.Substations 140,399,826
3.Energy Management System "5,786,116"--'-"--4.Steel Towers &Fixture 891,777 ,010
r:-5.Conductors &Devices 36,238,112
6.Clearing 143,253,589U
,.,
Subtotal $1,303,644,955
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7.Land &Land Right 36,000,000
[8.Engineering &Construction 60,452,966~.-Management
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Subtotal'$1,400,097,921
Contingency 20%280,019,584
I~Total Construction Cost $1,680,117,505L.:
Lc Rounded $1,680,118,000
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ALASKA POWER AUTHORITY
7/18/83 .
R.Wi l1iams
COST SUMMARY
Fairbanks to Anchorage Transmission System
North Slope Power Generation -Medium load Forecast
(January 182 Dollars)
This estimate is based on Power Authority experience on the
Anchorage -Fairbanks Intertie.
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820 mile x $750,000/mile
Contingencies 20%
Total Construction Cost
=$615,000,000
123,000,000
$738,000,000
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Note -This estimate is also for:
Fairbanks to Anchorage Transmission System
Fairbanks Power Generation -Medium load Forecast
9860/053 .
ALASKA POWER AUTHORITY
COST SUMMARY
7/19/83 ..
R.Williams
North Slope to Fairbanks Transmission System
North Slope Power Generation -Low Load Forecast
(January 182 Dollars)
36,000,000
60,452,966
263,501,558
Amount
$57,000,000
87,000,000
5,786,116
891,777,010
36,238,112
143,253,589
AITItt.H!'1£N'4
1,317,507,793
.},221,054,827
$1,581,009,351
$1,581,009,000
Contingency 20%
Subtotal
Rounded
Subtotal
Land &Land Rtghts
Engineering &.Construction
Management
Total Construction Cost
Description
Switching Stations
Substations
Energy Management System
Steel Towers &Fixtures
Conductors &Devices
Clearing.
9860/053
7.
8.
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4.
5.
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COST SUMMARY
Total Construction Cost $441,000,000
ALASKA POWER AUTHORITY
7/19/83 -
R.Williams
$367,500,000
73,500,000Contingencies20%
Fairbanks to Anchorage Transmission System
North Slope Power Generation -Low Load Forecast
(January 182 Dollars)
490 miles x $750,000/mile =
This estimate is based on Power Authority experience on the
Anchorage -Fairbanks Intertie
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Note -This estimate is also for:
Fairbanks to Anchorage Transmission System
Fairbanks Power Generator -Low Load Forecast
9860/053 AfTJl ':H !'-!~A'T .)
ALASKA POWER AUTHORITY
.-'.;~
7/19/83 Rev 8/25/83
R.Wi'll iams :.
COST SUMMARY
Kenai to Anchorage Transmission System
Kenai Area Power Generation -Medium Load Forecast
Submarine Cable Crossing Alternative
(January 182 Dollars)
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2.
3.
4.
5.
6.
7.
8.
9.
9860/053
Description
Switching Stations
Substations
Energy Management System
Steel Towers &Fixtures
Conductors &Devices
Clearing
Submarine Cable &Devices
Subtotal
Land &Land RIghts
Engineering &Construction
Management
Subtotal
Conti~gency 20%
Total Construction Cost
Amount
$120,000,000
5,000,000
151,200,000
7,200,00.0
36,000,000
104,080,000
$423,480,000
7,200,000
25,409,000
$469,089,000
91,218,000
$547,307,000
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7/19/83 Rev •.8/25/83
R.Williams
COST SUMMARY
Kenai to Anchorage Transmission System
Kenai Area Power Generation -Low Load Forecast
Submarine Cable Crossing Alternative
(January 182 Dollars)
This estimate is equal to the medium foreca$t estimate less
$40,000,000 for reduced substation cost.
$547,307,000
-40,000,000
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Total Construction Cost
9860/053
$507,307,000
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2999A
USE OF NORTH SLOPE GAS FOR
HEAT AND ELECTRICITY IN THE RAILBELT
FINAL REPORT
FEASIBILITY LEVEL
ASSESSMENT
EBASCO SERVICES INCORPORATED
with
FRANK MODLIN &ASSOCIATES
and
ALASKA ECONCMICS INCORPORATED
SEPTEMBER 1983
TABLE OF CONTENTS
-'!..••:
1.0 SlMMARY _ •It _ _ _. ......-... ..
Page
1-1
1.1 PURPOSE.......• • • • • • • • • •1-1
1 .2 STUDY APPROACH •••• • • • • • • •••1-1
1.3 SCOPE .•It • •• • • • • • • • • • • • •1-2
1.4 RESULTS.• • • • • • • • • • • • • •••1-6
2.0 NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST.2-1
2.3 COST ESTIMATES ••••••••••••
2.3.1 Constructton Costs ••••••••••••
2.3.2 Operation and Maintenance Costs ••••••
2.3.3 Fuel Costs •••••••••••••••••
2.3.4 Total Systems Costs ••••••••••••
2-1
2-1
2-2
2-7
2-7
2-10
2-12
2-14
2-15
2-16
2-16
2-18
2-19
2-19
2-20
2-20
2-22
2-22
2-24
2-24
•2-25
2-25
2-25
2-28
2-28
2-32
2-32
2-34
...
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General • • • • • • • • • • •
Combustion Turbine Equipment •••••••
Fuel Supply • • • • • • • • • • • • • •
SUbstation ••••••••••••••
Power Plant Support System Descriptions
Construction and Site Services ••••••
Operation and Maintenance ••••••
Site Opportunities and Constraints ••••
2.2.1 Overvi ew of the System • • • • • •••
2.2.2 Voltage Selection •••••••••
2.2~3 Towers •••••••••
2.2.4 Conductors •••••
2.2.5 Insulators ••••••••••••••••
2.2.6 Switching Stations ••
2.2.7 Fairbanks Substation •••••••••••
2.2.8 Construction ••••••
2.2.9 Operatton and Maintenance
2.2.10 Communications ......
2.2.11 Siting Opportunities and Constraints •••
2.2.12 Fairbanks to Anchorage Line.
2.2.13 Anchorage SUbstation •••••••••••
2.1.1
2.1.2
2.1.3
2.1.4
2.1.5
2.1.6
2.1.7
2.1.8
2.2 TRANSMISSION SYSTEM •••••
2.1 POWER PLANT ••••••••••••••
~...
~--
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2.4 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS ••2-34
2.4.1
2.4.2
2.4.3
2.4.4
2.4.5
Ai rResource Effects • • • • • • •
Water Resource Effects ••••••••••
Aquatic Ecosystem Effects • • • • •
Terrestrial Ecosystem Effects •••••••
Socioeconomic and Land Use Effects
2-38
2-41
2-43
2-44
2-49
ii
2999A
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TABLE OF CONTENTS (Continued)r
Page LJ
3.0 NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST · ·
•3-1 [
.1
3.1 POWER PLANT .······ ·
·····3-1
3.2 TRANSM ISS ION SYSTEM.······ ·
..3-3 [3.3 .COST ESTIMATES · ···· ·
·· ··3-5 1
3.3.1 Construction Costs ······· ·
··3-5 ['3.3.2 Operation and Maintenance Costs ·3-5
3.3.3 Fuel Costs ···· ·
· ········3-5
3.3.4 Total Systems Costs ·· · ····3-5 L3.4 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS 3-8 J
4.0 FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST •4-1 [
4.1 NORTH SLOPE TO FAIRBANKS NATURAL GAS PIPELINE 4-2 ,
4.1.1 Gas Conditioning Plant · ···0 •4-3 [
4.1.2 Pipeline ·· · ···· ··4-7 }········4.1.3 Compressor and Metering Stations ·····4-11 r4.1.4 Supervisory Control System ····4-11
4.1.5 Communications System •••··· · ·
•4-23 L· ·4.1.6 Operation and Maintenance Facilities ···4-23
4.1.7 Construction and Site Support Services 4-24 [
4.2 POWER PLANT 4-25 ~.:j.················
4.2.1 General ··· ·········· ··4-25 [4.2.2 Combustion Turbine Equipment.····· ··4-30
4.•2.3 Steam Plant ······· ·
······4-30 [4.2.4 Substation ······ ·
······4-35
4.2.5 Other Systems · ············4-35 ._-0
4.2.6 Construction and Site Support Services ··4-37
4.2.7 Operation and Maintenance ••••••4-37 [4.2.8 Site Opportunities and Constraints 4-38
..->oJ
4.3 TRANSMISSION SYSTEM ····· ·
· ·····4-39 [
4.4 FAIRBANKS GAS DISTRIBUTION SYSTEM 4-39······--j
4.4.1 Fairbanks Residential/Commercial [:Gas Demand Forecasts •••••••··4-39
4.4.2 Fairbanks Gas Distribution System 4-43 _...J·
4.5 COST EST IMATES ·· ·
· ··············4-55 l~
4.5.1 Capital Costs.··· · · · · ··4-55 [4.5.2 Operation and Maintenance Costs ····4-59
4.5.3 Fuel Costs.• • • • • • • • • •4-62 ..-.J
4.5.4 Total Systems Costs ·········4-62
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2999A t
iv
5.5 COST ESTIMATES ••••••••••••••
TABLE OF CONTENTS (Continued)
5-6
5-6
6-3
6-3
6-5
6-5
6-5
6-7
Page
4-69
4-74
4-77
4-79
4-81
4-82
5-1
5-1
5-2
5-3
5-3
5-6
5-6
5-6
5-8
5-8
5-10
·5-13
5-13
5-23
6-1
6-3
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.~.. .
... ..
6.1.1 General •••••••••••
6.1.2 Combustion Turbine Equipment ••••••••
6.1.3 Steam Plant ••••••••••
6.1.4 Fuel Supply ••••••••••••••
6.1.5 Electrical Equipment and Substation ••
6.1.6 Other Systems •••••••••••••••
5.4.1 Fairbanks Residential/Commercial Gas
Demand Forecasts •••••••••••
5.4.2 Fairbanks Gas Distribution System .••••
5.1.1 Gas Conditioni ng Pl ant • • • • • • • •
5.1.2 Pipeline •...•••••••.•••0 •
4.6 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS ••
4.6.1 Air Resource Effects •••••••
4.6.2 Water Resource Effects·.• • • • • •
4.6.3 Aquatic .Ecosystem Effects •.•••••
4.6.4 Terrestrial Ecosystem Effects •••••••
4.6.5 Socioeconomic and Land Use Effects ••••
5.2 POWER PLANT •••••••••
5.3 TRANSMISSION SYSTEM • ••••
5.3.1 Fairbanks to Anchorage
5.4 FAIRBANKS GAS DISTRIBUTION SYSTEM
5.0 FAIRBANKS POWER GENERATION -LOW LOAD FORECAST
5.1 NORTH SLOPE TO FAIRBANKS NATURAL GAS PIPELINE
5.5.1 Capital Costs •••••••••••
5.5.2 Operation and Maintenance Costs.
5.5.3 Fuel Costs ••••••••••••••••
5.5.4 Total Systems Costs •••••••
5.6 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS
6.0 KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST
6.1 POWER PLANT • • • • • • • • • • • •
v
2999A
APPENDIX A-REPORT ON EXISTING DATA AND ASSUMPTIONS
APPENDIX B-REPORT ON SYSTEM PLANNING STUDIES
APPENDIX C -REPORT ON FACILITY SITING AND CORRIDOR SELECTION
APPENDIX D-REPORT ON TRANSMISSION SYSTEM DESIGN
APPENDIX E -FAIRBANKS RESIDENTIAL/COMMERCIAL GAS DEMAND FORECASTS
APPENDIX F -OFFICE OF MANAGEMENT AND BUDGET DRAFT REPORT
COMMENTS AND ASSOCIATED RESPONSES
6.4 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS • •
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6-7
6-7
6-10
6-10
6-10
6-12
6-12
6-17
6-17
6-19
6-19
6-24
6-24 _
6-26
6-27
6-28
7-1
7-1
7-3
7-5
7-5
.7-5
7-8
7-8
7-8
8-1
9-1
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·..
·..
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TABLE OF CONTENTS (Continued)
7.3.1 Construction Costs •••••••••
7.3.2 Op~ration and Maintenance Costs ••••••
7.3.3 Fuel Costs •••••-••••••••
7.3.4 Total Systems Costs •••••••
6.4.1 'Air Resource Effects •••••••
6.4.2 Water Resource Effects ••••••••••
6.4.3 Aquatic Ecosystem Effects •••••••••
6.4.4 Terrestrial ECosystem Effects •••••••
6.4.5 Socioeconomic and Land Use Effects ••••
6.2.1 Kenai to Anchorage Line ••
6.2.2 Anchorage Substation ••••
6.2.3 Anchorage to Fairbanks Line.• ••••
6.2.4 Fairbanks Substation ••••••
6.3.1 Construction Costs •••••••••
6.3.2 Operation and Maintenance Costs •
6.3.3 Fuel Costs ••••••••••••
6.3.4 Total Systems Costs • • • • • • •
6.2 TRANSMISSION SYSTEMS
6.3 COST ESTIMATES •••••••••••
7.0 KENAI AREA POWER GENERATION -LOW LOAD FORECAST.
7.1 POWER PLANT •••••
7.2 TRANSMISSION SYSTEM
7.3 COST ESTIMATES •••
7.4 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS ••
8.0 COMPARISON OF SCENARIOS
9.0 REFERENCES •••••••
~~-LIST OF TABLES
Tab 1e Number Title Page
2-1 NEW CAPACITY ADDITIONS AND FUEL REQUIREMENTS
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST 2-3
2-2 COMBUSTION TURBINE WITH GENERATOR DESIGN PARAMETERS
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST 2-8
2-3 TRANSMISSION LINE DESI GN CRI TERIA
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST 2-17
2-4 FEASIBI LITY LEVEL INVESTMENT COSTS
77 MW SIMPLE CYCLE COMBUSTION TURBINE
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST 2-29
2-5 FEASIBILITY LEVEL INVESTMENT COSTS
220 MW COMBINED CYCLE PLANT
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST 2-30
'-'--':.2-6 FEASIBILITY LEVEL INVESTMENT COSTS
"..~
NORTH SLOPE TO FAIRBANKS TRANSMISSION SYSTEM
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST 2-31
--~
2-7 FEASIBILITY LEVEL INVESTMENT COSTS
~--FAIRBANKS TO ANCHORAGE TRANSMISSION SYSTEM
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST 2-33
--~
2-8 TOTAL ANNUAL CAPITAL EXPENDITURES
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST 2-35
~.~-
2-9 TOTAL ANNUAL NON-FUEL O&M COSTS-,NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST 2-36
2-10 TOTAL ANNUAL SYSTEMS'COSTS
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST 2-37
~2-11 ENVIRONMENT RELATED FACILITY CHARACTERISTICS
SIMPLE CYCLE COMBUSTION TURBINES
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST 2-39
~
3-1 NEW CAPACITY ADDITIONS AND FUEL REQUIREMENTS
_.~NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST 3-2
--:.-.3-2 FEASIBILITY LEVEL INVESTMENT COSTS
--NORTH SLOPE TO FAIRBANKS TRANSMISSION SYSTEM
NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST 3-6
vi
--'
LIST OF TABLES (Continued)
Table Number Title Page
3-3 FEASIBILITY LEVEL INVESTMENT COSTS
FAIRBANKS TO ANCHORAGE TRANSMISSION SYSTEM
NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST 3-7
3-4 TOTAL ANNUAL CAPITAL EXPENDITURES
NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST 3-9
3-5 TOTAL ANNUAL NON-FUEL OPERATION AND MAINTENANCE
COSTS
NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST 3-10
3-6 TOTAL ANNUAL COSTS
NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST 3-11
3-7 ENVIRONMENT RELATED POWER PLANT CHARACTERISTICS
NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST 3-12
4-1 GAS DELIVERY AND QUALITY SPECIFICATIONS
FAIRBANKS POWER GENERATION -MEDIlJt1 LOAD FORECAST 4-4
4-2 COMPRESSION STATION PIPE DETAILS
FAIRBANKS POWER GENERATION -MEDIlJt1 LOAD FORECAST 4-14
4-3 CIVIL DESIGN DETAILS,
FAIRBANKS POWER GENERATION -MEDIlJt1 LOAD FORECAST 4-15
4-4 BUILDING DETAILS
FAIRBANKS POWER GENERATION -MEDIlJt1 LOAD FORECAST 4-16
4-5 COMPRESSOR AND GAS SCRUBBER DETAILS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-17
4-6 REFRIGERATION SYSTEM AND GAS HEATER DETAILS
FAIRBANKS POWER GENERATION -MEDIlJt1 LOAD FORECAST 4-18
4-7 COMPRESSOR STATION ELECTRICAL SYSTEM
AND CONTROL SYSTEM DETAILS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-19
4-8 MISCELLANEOUS COMPRESSOR STATION SYSTEMS'DETAILS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-20
vii
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Tab 1e Number Title Page
[:4-9 METERS AND METERING STATION ELECTRICAL AND
CONTROL SYSTEMS DETAI LS
[FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-21
4-10 MISCELLANEOUS METERING STATION SYSTEMS'DETAILS
r~FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-22
4-11 NEW CAPACITY ADDITIONS AND FUEL REQUIREMENTS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-26
L 4-12 HEAT RECOVERY STEAM GENERATOR DESIGN PARAMETERS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-31
r -4-13 STEAM TURBINE GENERATOR UNIT DESIGN PARAMETERS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-34
C '4-14 FEASIBILITY LEVEL'INVESTMENT COSTS
NORTH SLOPE TO FAIRBANKS NATURAL GAS PIPELINE
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-56
C 4-15 FEASIBILITY LEVEL INVESTMENT COST ESTIMATESL77MWSIMPLECYCLEC()1BUSTION TURBINE
[FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-57
4-16 FEASIBILITY LEVEL INVESTMENT COSTS
220 MW COMBINED CYCLE PLANT
[FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-58
4-17 FEASIBILITY LEVEL INVESTMENT COSTS
[FAIRBANKS TO ANCHORAGE TRANSMISSION SYSTEM
FAIRBANKS POWER GENERATION -MEDIlt1 LOAD FORECAST 4-59
[J 4-18 0A VALUES
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-65
4-19 TOTAL ANNUAL CAPITAL EXPENDITURES
C FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-66
4-20 TOTAL ANNUAL NON-FUEL OPERATING AND MAINTENANCE
[COSTS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST 4-67
4-21 TOTAL ANNUAL COSTS
L FAIRBANKS POWER GENERATION -MEDIUM·LOAD FORECAST 4-68
viii
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Table Number Title Page
5-9 APPORTIONMENT VALUES FOR THE GAS DISTRIBUTION
SYSTEM
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST 5-19
5-10 CAPITAL COSTS ASSOCIATED WITH THE DISTRIBUTION
SYSTEM
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST 5-20
5-11 OPERATION AND MAINTENANCE COSTS
ASSOCIATED WITH THE DISTRIBUTION SYSTEM
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST 5-21
5-12 ANNUAL SYSTEMS COST SUMMARY FOR THE GAS
DISTRIBUTION SYSTEM
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST 5-22
5-13 ENVIRONMENT RELATED POWER PLANT CHARACTERISTICS
COMBINED CYCLE POWER PLANT
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST 5-24
6-1 NEW CAPACITY ADDITIONS AND FUEL REQUIREMENTS
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST 6-4
6-2 FEASIBILITY LEVEL INVESTMENT COSTS
77 MW SIMPLE CYCLE PLANT
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST 6-13
6-3 FEASIBILITY LEVEL INVESTMENT COSTS
220 MW COMBINED CYCLE PLANT
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST 6-14
•6-4 FEASIBI LITY LEVEL INVESTMENT COSTS
SUBMARINE CABLE CROSSING ALTERNATIVE
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST .6-15
6-5 FEASIBILITY LEVEL INVESTMENT COSTS
LAND BASED ROUTE ALTERNATIVE
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST 6-16
6-6 FEASIBILITY LEVEL INVESTMENT COSTS
ANCHORAGE TO FAIRBANKS TRANSMISSION SYSTEM
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST 6-18
6-7 ANNUAL CAPITAL EXPENDITURES
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST 6-20
x
LIST OF TABLES (Continued)
Tabl e Number Title Page
6-8 ANNUAL NON-FUEL OPERATION AND MAINTENANCE COSTS
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST 6-21
6-9 TOTAL ANNUAL COSTS
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST 6-22
6-10 ENVIRONMENT RELATED POWER PLANT CHARACTERISTICS
NATURAL GAS COMBINED CYCLE
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST 6-23
7-1 NEW CAPACITY ADDITIONS AND FUEL REQUIRa4ENTS
KENAI AREA POWER GENERATION -LOW LOAD FORECAST 7-2
7-2 FEASIBI LITY LEVEL INVESTMENT COSTS
SUBMARINE CABLE CROSSING ALTERNATIVE 7-6
KENAI AREA POWER GENERATION -LOW LOAD FORECAST
7-3 FEASIBILITY LEVEL INVESTMENT COSTS
LAND BASED ROUTE ALTERNATIVE
KENAI AREA POWER GENERATION -LOW LOAD FORECAST 7-7
7-4 ANNUAL CAPITAL EXPENDITURES
"KENAI AREA POWER GENERATION -LOW LOAD FORECAST 7-9
7-5 ANNUAL NON-FUEL OPERATION AND MAINTENANCE COSTS
KENAI AREA POWER GENERATION -LOW LOAD FORECAST 7-10
7-6 TOTAL ANNUAL COSTS
KENAI AREA POWER GENERATION -LOW LOAD FORECAST"7-11
7-7 ENVIRONMENT RELATED POWER PLANT CHARACTERISTICS
COMBINED CYCLE POWER PLANT
KENAI AREA POWER GENERATION -LOW LOAD FORECAST 7-12
8-1 COMPARISON OF SCENARIOS 8-2
xi
:::=:
LIST OF FIGURES
F;gure Number T;t1e Page
1-1 NORTH SLOPE SCENARIO 1-3
--1:'2 FAIRBANKS SCENARIO 1-5
"1-3 KENAI SCENARIO 1-7
2-1 SIMPLE CYCLE GAS TURBINE GENERAL ARRANGEMENT 2-4
2-2 SIMPLE CYCLE GAS TURBINE SITE PLAN 2-5
2-3 NORTH SLOPE POWER GENERATION -MEDIUM LOAD
FORECAST -SUBSTATION ONE LINE SCHEMATIC 2-9
2-4 NORTH SLOPE POWER GENERATION -MEDIUM LOAD
FORECAST -INITIAL STAGE OF SUBSTATION
~DEVELOPMENT 2-11
2-5 NORTH SLOPE POWER GENERATION -MEDIUM LOAD
FORECAST -TYPICAL TWO LINE SWITCHING
STATION SCHEMATIC 2-21
2-6 NORTH SLOPE POWER GENERATION -MEDIUM LOAD
FORECAST -FAIRBANKS SUBSTATION SCHEMATIC 2-23
2-7 NORTH SLOPE POWER GENERATION -MEDIUM LOAD
FORECAST -TYPICAL THREE LINE SWITCHING
--'STATION SCHEMATIC 2-26
---,2-8 NORTH SLOPE POWER GENERATION -MEDIUM LOAD
~:=j FORECAST -ANCHORAGE SUBSTATION SCHEMATIC 2-27
3-1 NORTH SLOPE POWER GENERATION -LOW LOAD
FORECAST -SUBSTATION ONE LINE SCHEMATIC 3-4
4-1 GAS CONDITIONING FACILITY 4-6
~4-2 HYDRAULIC SUMMARY -MEDIUM FORECAST 4-10
PEAK DAILY FLOW
·0
4-3 TYPICAL COMPRESSOR STATION LAYOUT 4-12
-:::}
4-4 TYPICAL METERING STATION LAYOUT 4-13-.
'-;~4-5 COMBINED CYCLE PLANT GENERAL ARRANGEMENT 4-27
-PLAN VIEW
4-6 COMBINED CYCLE PLANT "GENERAL ARRANGEMENT 4-28
.--ELEVATIONS
x;;
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LIST OF FIGURES (Continued)
Figure Number Title
4-7 COMBINED CYCLE PLANT SITE PLAN
4-8 COMBINED CYCLE PLANT FLOW DIAGRAM AND
HEAT BALANCE
4-9 FAIRBANKS POWER GENERATION -MEDIUM LOAD
FORECAST -SUBSTATION ONE LINE SCHEMATIC
4-10 CITY OF FAIRBANKS -GAS DISTRIBUTION
5-1 HYDRAULIC SUMl1ARY -LOW FORECAST PEAK
DAILY FLOW
.'
6-1 KENAI POWER GENERATION -MEDIUM LOAD FORECAST
SUBSTATION ONE LINE SCHEMATIC
6-2 KENAI POWER GENERATION -MEDIUM LOAD FORECAST
ANCHORAGE SUBSTATION ONE LINE SCHEMATIC
7-1 KENAI POWER GENERATION -LOW LOAD FORECAST
SUBSTATION ONE LINE SCHEMATIC
xiii
Page
4-29
4-32
4-36
4-45
5-4
6-6
6-11
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1 •.0 SUMMARY
1.1 PURPOSE
The purpose of this study is to examine the technical and environmental
feasibility of several alternatives for the utilization of North Slope
natural gas to generate electricity for use in the Railbe1t region,and
to develop feasibility level cost estimates for each alternative.The
alternatives are grouped into three scenarios based on selected
generating locations,and the study is based on the medium and low
growth forecasts of Rai1be1t electrical needs provided by previous
studies.One scenario also provides for the development of a
residential and commercial natural gas distribution system in Fairbanks.
Previous reports developed for this feasibility assessment have
detailed the existing data and assumptions to be used in developing the
scenarios,the technical and economic bases for establishing power
generating technologies,and the factors to be considered in facility
siting and corridor selection~Potential environmental effects are
detailed in this report.Tne previous reports are appended to this
report for completeness.
1.2 STUDY APPROACH
An initial survey of the electrical demand growth forecasts and the
availability and characteristics of North Slope gas provided a basis
for establishing candidate power generating technologies.Meetings and
discussions with knowledgeable officials and industry representatives
were held to focus the study on factors unique to each region,and
factors unique to North Slope natural gas.Candidate generating sites
and routing corridors (both electrical and natural gas)were
evaluated.Forecasts of po~ential natural gas demand in Fairbanks and
.details for a gas distribution system were prepared.
26478
1-1
Much of the above was completed prior to performing cost estimating
tasks.While this study uses assumptions consistent with previous
studies of other electrical generating scenarios for the Railbelt,cost
estimating tasks have not included fuel cost derivation nor the
development of cost of power values.Comparisons with alternative
electric generating scenarios are therefore outside the scope of this
studY.Such comparisons can be considered as .a logical extension of
these studies which m~be performed by the Alaska Power Authority.
1.3 SCOPE
The scope of the study was defined by the Al aska Power Authority to
consist of three distinct scenarios.Each scenario was evaluated for
.its feasibility to meet the medium and low load forecasts of recent
previous studies which examined the electrical demand requirements of
the Railbelt Region.The first scenario is characterized by the
generation of electricity on the North Slope using simple cycle
combustion turbines fired by untreated natural gas.A major,new
transmission line system would be required from the North Slope.to
Fairbanks,with substantial improvements to the transmission system
connecting Fairbanks and Anchorage.Figure 1-1 is a depiction of the
North Slope scenario showing the major differences between the medium
and low load cases.The medium load forecast requires 15 units with a
total capacity of almost 1400 megawatts (MW),two 500 kilovolt (kV)
circuits from the North Slope to Fairbanks,and three 345 kV circuits
from Fairbanks to Anchorage.The low load forecast can be met with 8
units (700 MW),two 500 kV circuits from the North Slope to Fairbanks,
and two 345 kV circuits from Fairbanks to Anchorage.The present worth
of costs of the medium load forecast is $3.8 billion versus $2.7
billion for the low load forecast.80th costs are in 1982 dollars and
do not include fuel costs.
The second scenario consists of two distinct parts:a generating
facility in the Fairbanks area and a gas distribution system in
Fairbanks.Transmission of the gas to Fairbanks from the North Slope
would require construction of a high pressure gas pipeline,although
26478
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SUBSTATION
SUBSTATION
AND LOCAL
DISTRIBUTION
SUBSTATION
AND LOCAL
DISTRIBUTION
EXISTING
INTERTIE
LOW,
LOAD
FORECAST
••••8 SIMPLE~-_..CYCLE UNITS
.1..1..1..1.
FAIRBANKS
POWER PLANT
PRUDHOE BAY
TRANSMISSION LINE
LENGTH =450 MILES
FAIRBANKS TO HEALY=110 MILES
WILLOW TO ANCHORAGE:50 MILES
ANCHORAGE
TRANSMISSION LINE
HEALY TO WIUOW:170 MILES
EXISTING
INTERTIE
NORTH SLOPE SCENARIO
SUBSTATION
ALASKA POWER AUTHORITY
NORTH SLOPE GAS
FEASIBILITY STUDY
HEALY
1-3
BASCO SERVICES INCORPORATED·
SUBSTATION
AND LOCAL
DISTRIBUTION
WILLOW
SUBSTATION
AND LOCAL
DISTRIBUTION
MEDIUM
LOAD
FORECAST
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the size of the pipeline would be somewhat smaller than that proposed
for the Alaska Natural Gas Transportation System (ANGTS).Electrical
power generation near Fairbanks would use combined cycle plants
consisting of gas fired combustion turbines,waste heat recovery
boilers and steam turbines.A gas conditioning facility would be
required on the North Slope.
The Fairbanks generating scenario is depicted in Figure 1-2 which shows
that five combined cycle and two simple cycle units are required to
meet the year 2010 medium load forecast (1400 MW).The low load
forecast (700 MW)requires three combined cycle units.The Fairbanks
generating scenario requires a 22 inch diameter gas pipeline from the
North Slope to Fairbanks and includes a natural gas distribution system
to meet residential and commercial heating needs.Three 345 kV
transmission circuits from Fairbanks to Anchorage ate required for the
medium forecast and two for the low load forecast.Present worth of
costs of the electrical generating scenarios,excluding fuel costs,in
1982 dollars is $5.4 billion (medium forecast)or $3.6 billion"(low
forecast).The present worth of costs for the Fairbanks gas
distribution system is $0.9 billion for the medium load forecast and
$1 .1 bi 11 i on for the low load forecast.
The third scenario is contingent on the construction of a major natural
gas ~ip1ine from the North Slope to tidewater on the Kenai Peninsula.
Delays in the construction of ANGTS have renewed interest in such an
all-Alaska pipeline.This system is described in the Governor's
Economic Committee on North Slope Natural Gas Report (1983)entitled
"Trans Alaska Gas System:Economics of an Alternative for North Slope
Natural Gas.II The Kenai e1 ectric generating scenari 0 incorporates the
anticipated energy demand from this system's tidewater facilities into
the Rai1be1t's demand forecasts.Fuel for the power plant will be
derived from a blend of waste gas from the conditioning facilities and
sales gas.A major transmission line would also be required from near
tidewater to the load center in Anchorage.The existing transmission
26478
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LOAD
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LOW
LOAD
FORECAST
PRUDHOE BAY
CONDITIONING PLANT
GAS PIPELINE
LENGTH =450 MILES
SUBSTATION
AND LOCAL
DISTRIBUTION
SUBSTATION
AND LOCAL
DISTRIBUTION
EXISTING
INTERTIE
___~..~3 COMBINED
-CYCLE UNITSPOWERPLANT
FAiRBANICS TO HEALY:110 MILES
WILLOW 10 ANCHORAGE =50 MILES
ANCHORAGE
FAIRBANKS
GAS DISTRIButiON SYSTEM
TRANSMISSION LINE
t£ALY TO WILLOW =170 MILES
EXISTING
INTERTIE
1-5
ALASKA POWER AUTHORITY
NORTH SLOPE GAS
FEASIBILITY 8TUDY
EBASCO SERVICES ..CORPORATED
FAIRBANKS SCENARIO
FIGURE 1-2
HEALY
WILLOW
SUBSTATION
AND LOCAL
DISTRIBUTION
2 SIM PLE CYCLE
UNITS
SUBSTATION
AND LOCAL
DISTRIBUTION
5 COMBINED ..........
CYCLE UNITS
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line from Anchorage to Fairbanks would have to be up-graded to handle
the generatiny capacity.
The Kenai scenario (Figure 1-3)includes seven combined cycle units and
one simple cycle unit to meet the energy demand in 2010 for the medium
load forecast,and four combined cycle units and two simple cycle units
for the low load forecast.In order to provide a highly reliable
electric transmission system from Anchorage to Fairbanks,two parallel
345 kV circuits are required,even though a single circuit would be
adequate in the low load forecast.Underwater cable crossing of
Turnagain'Arm is cost effective,with two 500 kV circuits from Kenai to
Anchorage.Cost estimates (excluding the pipeline and gas processing
facilities as well as fuel costs)result in a present worth of costs
for the medium load forecast of $2.0 billion,and $1.7 billion for the..
low load forecast (in 1982 dollars).
1.4 RESULTS
This work has resulted in the development of several scenarios for
meeting the electrical generating needs of the Rai1belt region using
North Slope natural gas for fuel.Each scenario has been refined to
establish schedules of generating capacity additions consistent with
medium and low load forecasts through the year 2010.Chapter 2 and
Chapter 3 detail the North Slope Power Generation scenario for the...
medium and low forecasts,respectively.Chapter 4 and Chapter 5 detail
the Fairbanks scenario,while Chapter 6 and Chapter 7 describe the
Kenai Power Generation scenario.
Engineering and cost evaluations of technologies capable of using
natural gas to generate electricity provide a consensus for the use of
gas fired combustion turbines.For the Fairbanks and Kenai scenarios,
the turbines are exhausted through waste heat recovery boilers to power
steam turbines.
26478
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LOW
LOAD
FORECAST
WILLOW
SUBSTATION·
AND LOCAL
DISTR I BUTION
SUBSTATION
AND LOCAL
DISTRIBUTION
SUBSTATION
AND LOCAL
DISTRIBUTION
ANCHORAGE
FAIRBANKS
FAiRBANI<S TO KEAL.Y=110 MIlES
ANCHORAGE TO .KENAI =87 MILES
WILLOW 10 ANCHORAGE =50 MILES
TRANSMISSION LINE
tEALY TO WlLLDW.ITO MIlES
EXISTING
INTERTIE
SUBSTATION
AND LOCAL
DISTRIBUTION
WILLOW
HEALY
SUBSTATION
AND LOCAL
DISTRIBUTION
SUBSTATION
AND LDCAL
DISTRIBUnON
I SIMPLE CYCLE
UNIT
d'
7COMBfNED ..
CYCLE UNITS ...
.I.
KENAI
POWER PLANT
.........4 COMBLNED
CYCLE UNITS.L .L 2 SIMPLE CYCLE
UNITS
~:.ALASKA POWER AUTHORITY
NORTH 8LOPE GAS
.,FEASIBILITY STUDY
KENAI SCENARIO
FIGURE 1-3
EBASCO SERVICES INCORPORATED
.........1-7
All of the scenarios will require substantial construction of electric
transmission lines.A power plant on the North Slope separates the
generation and load centers by almost 900.miles,requi ri ng special
transmission system design considerations to obtain a stable and
reliable system.Generation near Kenai,on the other hand,requires a
500 kV underwater crossing of Turnagain Arm.
Socioeconomic and environmental effects of generating significant
amounts of electricity are substantial in both the construction and
operation of the system.However,no effect would appear to preclude
any of the scenarios.Both air and water pollution control measures
associated with gas fired combustion turbines are generally modest
compared to other technologies.
Cost estimates are provided for each forecast of all three scenarios.
Because each scenario is distinctly different,except for providing the
required electricity,cost comparisons should not be the sole factor in
evaluating the desirability of any scenario.However,within the scope'
of this study,Kenai generation shows the least cost because it does
not factor in the cost of the Trans Alaska Gas System and its
associated processes.The Fairbanks scenario is the most costly
because it includes a 450 mile natural gas pipeline,and a gas
conditioning facility on the North Slope.The North Slope scenario is
in the middle of the cost range and is characterized by the high
capital cost of constructing high voltage transmission lines to
Fairbanks.
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2.0 NORTH SLOPE POWER GENERATION
MEDIUM LOAD FORECAST
The first scenario,under the medium load forecast,centers on a major
electric generating station on the North Slope at Prudhoe Bay,near the
source of natural gas used to fuel the station.By the year 2010,the
station would consist of 15 simple cycle combustion turbines capable of
generating almost 1400 megawatts (MW)of power to serve the Railbelt.
North Slope power generation does not require the construction of major
gas pipelines,but does require construction of 500 kilovolt (kV)
electric transmission lines from the North Slope to Fairbanks and
additional transmission lines of 345 kV from Fairbanks to Anchorage.
De.tai 1ed analysi s of the transmi ssi on system shows that a stabl e and
reliable system can be designed despite the generation and major load
centers being over 800 miles apart.The total construction costs for
the system described are $4.2 billion,with total annual operation and
maintenance costs of $1.1 billion.The present worth of these costs
excluding fuel costs is $3.8 billion as of 1982.Environmental and
socioeconomic effects of this scenario are substantial,but none have
been identified which would preclude the project.
2.1 POWER PLANT
The power generation technology selected for the North Slope scenario
employs simple cycle combustion turbines utilizing 91 MW baseload,
combustion turbine generators.The criteria and parameters which
resulted in this selection are discussed in the Report on Systems
Planning Studies (Appendix B).
2.1.1 General
Development of a North Slope site for the required generating units,
construction and maintenance facilities,worker housing,and access
2601B
2-1
facilities will be a major undertaking.In addition to continuously
expanding facilities for maintenance and operation,there will be
permanent construction facilities and a semi-permanent construction
staff.
The scenario for utilizing simple cycle gas turbine-generators to
generate power at the North Slope requires fifteen 91 MW (nominal)
units for satisfying load demand under the medium load forecast.The
units would be added in increments beginning in 1993.On the average,
slightly less than one unit per year is required through the end of the
study period in 2010.Incremental and total required new generation
capacity for this scenario are summarized in Table 2-1.
The functional parts of the plant will consist of a gas supply
system(s),the turbine-generators,various auxiliary and support
systems,a central control facility,switchyards,and the northern
terminus of the transmission line.
A single simple cycle unit will require approximately a 90 ft x 150 ft
enclosure as shown in Figure 2-1.It is planned that the units be
installed side by side as shown in Figure 2-2 up to the maximum of 15
units required for the medium load forecast.The site will include the
138 kV switchyard behind the units and a 500 kV transmission line
termination centered on the planned maximum plant site.A 300 ft wide
buffer area surrounding the site is planned,yielding a maximum total
site acreage of 90 acres.
2.1.2 Combustion Turbine Equipment
The combustion turbine plant design envisioned is based on using
currently available gas turbine units,rated by one manufacturer at
approximately 77 MW each.Various other manufacturers'turbines of
similar size could be used to satisfy the requirement of this study,
but it must be pointed out that the specific plant output and various
specific design parameters may be expected to change accordingly.
26018
2-2
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TABLE 2-1
NEW CAPACITY ADDITIONS AND FUEL REQUIREMENTS
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST
New Capacity (MW)Gas Requi red
Year (Increment/Total)(r.t4SCFy).!I Z/
1990 0/0 O.
1991 0/0 O.
1992 0/0 O.
1993 91/91 6,574.6
1994 0/0 6,574.6
1995 91/182 13,,149.1
1996 91/273 19,778.7
1997 91/364 26,287.3
1998 91/455 32,861.9
1999 0/455 32,861.9
2000 91/546 39,546.7
2001 0/546 39,436.4
2002 182/728 52,585.6
2003 0/728 52,585.6
2004 91/819 .59,325.0
2005 182/1001 63,546.9
2006 91/1092 66,548.2
2007 91/1183 69,538.7
2008 91/1274 72,540.2
2009 0/1274 75,530.6
201 0 91/1365 78,532.0
.!I MMSCFY =mill i on standard cubic feet per yea'r.
~Values as calculated are shown for purposes of reproducibility
only and do not imply accuracy beyond the 100 MMSCFY level.
2601B
2-3
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NORTH SLOPE GAS
FEASIBILITY STUDY
SIMPLE CYCLE GAS TURBINE
SITE PLAN
NORTH SLOPE
FIGURE 2-2
EBASCO SERVICES INCORPORATED
At International Standards Organization (ISO)referenced conditions
(59°F and sea level)plant performance will consist of a net unit
output of 77 MW.The ISO heat rate of the units will be approximately
11,900 Btu/kWh (higher heating value [HHV]).For the actual conditions
eXisting at the North Slope (average annual temperature of 9°F and sea
.level)the rating of the turbines is approximately 91 MW and the heat
rate is 11,500 Btu/kWh (HHV).
Each combustion turbine is a large frame industrial type with an axial
flow multi-staged compressor and power turbine on a common shaft.The
combustion turbine is directly coupled to an electric generator,and
can be started,synchronized,and loaded in about one half hour under
normal conditions.
The gas turbine generators are "pac kaged"units and as such include all
auxiliary equipment.The package generally includes:
(l)13.8 kV switchgear which houses the generator grounding
transformer,and generator air circuit breaker.
(2)Nonsegregated phase (iso-phase)bus work wnich runs from the
generator to the main transformer.
(3)A master control panel for overall operation and monitoring.
(4)A transformer (13.8/4.16 kV)sized to support the ancillary
load (estimated to be 2 megavolt-amperes [MVA]).
(5)A 4.16 kV switchgear with air circuit breakers for other loads
(e.g.800 horse power [HP]cranking motor).The largest load
(gas compressor)is fed from the pl ant common 4.16 kV
swi tchgear.
(6)Electrical protection equipment.
Each combustion turbine generator package also includes an inlet air
filtration system,fuel system,lUbricating oil cooling system,and
various minor subsystems as required,furnished by the manufacturer:
2601B
2-6
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The design parameters for each combustion turbine with generator are
presented in Table 2-2.Inlet air preheating using a heat exchanger
will also be necessary.
2.1.3 Fuel Supply
Annual fuel requirements for power generation at the North Slope will
be 6.5 BCFY (billion cubic feet per year)in 1993 and grow to 78 BCFY
by 2010 for the medium growth forecast.Maximum potential firing rate
for the medium load growth scenario will be 2.5 x 10 5 SCFM (standard
cUbic feet per minute)in the year 2010.
Fuel requirements on a year by year basis will vary with installed
generating capacity and are shown in Taple 2-1.These gas demands were
generated based on an average annualized unit heat rate of 11,500
Btu/kWh (HHV)for the simple cycle gas turbines at average ambient
conditions •.
The HHV of the fuel gas is assumed to be 1046 Btu/SCF (lower heating
value [LHV]942 Btu/SCF).These values reflect the fact that no gas
conditioning facilities will be required for the North Slope scenario.
The gas supply system will consist of piping from one or more of the
eXisting North Slope natural gas gathering centers,a pressure
reduction station and an in-plant distribution system •.The supply and
distribution system will be designed for maximum flexibility to operate
any configuration of the available gas turbines.The pressure
reduction system will be required to assure a constant gas supply
pressure at 250 psig.
2.1.4 Substation
The circuit diagra~of the power plant sUbstation is shown in
Figure 2-3:Two generators will be connected to the two primary
windings of the 250 MVA 13.8/138 kV transformers.The bus arrangement
will use a breaker and a half scheme unless reliability considerations
2601B
2-7
TABLE 2-2
COMBUSTION TURBINE WITH GENERATOR DESIGN PARAMETERS
NORTH SLOPE POWER GENERATION -MEDIU4 LOAD FORECAST
Turbine Type:l/Simp1e-cyc1e,single-shaft,·three bearing.
Generator Type:Hydrogen-coo1ed unit rated 130 MVA at 13.8 kV,with
30 psig hydrogen pressure at lOoC.
(Each Turbine -at ISO Conditions)Performance:
Heat Rate (LHV)
Heat Rate (HHV)
Air Flow
Turbine EXhaust Temp
Turbine Inlet Temp
Inlet Pressure Drop
EXhaust Pressure Drop
Overall Dimensions
10,700 Btu/kWh
11,500 Btu/kWh
609 1bs/sec
995°F
1985°F
3.5 in.water
0.5 in.water
38 ft.wi de by 118 ft.long by 32
ft.high
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Combustion Turbine Features:
Accessories include starting motor,motor control center for all
base-mounted motors,lubrication system,hydraulic control system.
EXcitation compartment complete with static excitation equipment.
Switchgear compartment complete with generator breaker,potential and
current transformers,disconnect link for auxiliary feeder,·and a power
takeoff.
Fuel system capable of utiliZing natural gas,mixed gas fuel,or liquid
fuel.
Fire protection system (low pressure C02).
1/Based on General Electric Model MS7001.
2601B
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21Z5MVA
I!IAICO .ERVICts 1NC000000ATED
NORTH SLOPE POWER GENERATION
MEDIUM LOAD FORECAST
8UB8TATION ONE LINE 8CHEMATIC
ALASKA POWER AUTHORITY
NORTH ILOPE GAS
FEASlBlLfTY ITUDY
TO FAIRBANkS
500kV
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TYPICAL
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mandate otherwise.Two 750 MVA 138/525 kV autotransformers will supply
each of the transmission line circuits.Each of the transmission lines
will have a circuit breaker.On the line side of the circuit breakers
will be the series capacitors and the shunt reactor~.This arrangement
has the advantage of being flexible as far as operation is concerned,
and can be expanded easily.The system1s flexibility is demonstrated
in Figure 2-4,which shows the initial development associated with the·
installation of the first generator.There are seemingly more circuit
breakers than necessary in this initial circuit;their purpose is to
facilitate future expansion work.
The grounding mat of the switchyard is connected to four insulated 1000
kCM1/cables which terminate in a grounding rod system driven into
the sea floor.The ground mat is also connected to the two
·counterpoises 2/which run under the entire length o~the transmission
line.
2.1.5 Power Plant Support System Descriptions
The auxiliary systems described in this section represent generally the
minimum necessary to operate a simple cycle combustion turbine
facility.These systems include water supply,waste management,fire
protection,electrical,and lUbricating oil sy~tems.
Plant makeup water will be derived from an assumed existing lake of at
least 150 acres to supply the needs of two water systems:a potable
water system for the plant and the camp,and a service water system.
The potable water system will be designed to supply water for the
maximum crew on hand through completion of the final unit.Service
water will be provided to all units for maintenance,construction uses
1/k04 stands for thousands of circular mils,a measure of the
cross-secti on of a cab1 e.
2/Counterpoises are buried grounding cables,running under
transmission lines,which are necessary in areas with poorly
conducting soils.
26018
2-10
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2-11
ALASKA POWER AUTHORITY
NORTH ILOPE GAS
FEASlBlLrry STUDY
NORTH SLOPE POWER GENERATION
MEDIUM LOAD FORECAST
INITIAL STAGE OF SUBSTATION
DEVELOPMENT
'IGUftE 2-4
EBASCO SERvtCES ItCORPORATED
and area cleaning.A water injection system should not be required for
NOx control on the North Slope (see Section 2.4.1 for further
explanation).
Waste control systems for the plant will consist of control and
processing through oil/water separation treatment of all floor drainage
from operation and maintenance areas.This treated effluent and
domestic wastes will be transported to an existing sanitary waste
treatment facility.Because the natural gas supply is low in sulfur
content,no sulfur dioxide (S02)emissions control will be required.
Due to the climatic conditions existing during most of the year,fire
protection will be ba~ed on standard halon systems rather than water
systems.Automatic halon systems will be installed for high risk
areas,and manual systems will be used for low risk areas.Also,each
system sel ected shall be compati bl e with any of the specific hazards it
is intended to combat.
A system for storing ~oth clean and dirty lubricating oil shall be
included.The system will include a central storage area and portable
units capable of transporting,replacing,and/or cleaning the
lUbricating oil in an operating gas turbine.
2.1.6 Construction and Site Services
The construction and operation of a simple cycle power plant will
require a number of related services to support all work activities at
the site.These site services will include the following for the North
Slope power plant:
(1)Access
(2)Construction Water Supply
(3)Construction Transmission Lines
(4)Construction Camp
2601B
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.Access
Gravel roads with a 5 foot minimum gravel base will be required to
connect the plant site with the existing road network at the North
Slope.It is expected that no more than 2 miles of new road
construction will be required.
It is anticipated that all personnel travel wi.ll be by air with
pre-arranged commercial charter carriers to Deadhorse Airport.All
perishable goods,mail,and rush-cargo,will be flown in.Equipment
for construction will be flown in only under extraordinary
circ umstances.
The site will use the existing marine landing facilities during the six
week IIthaw ll period to receive all major equipment and suppl ies.A
fenced interim storage area will be provided.The Dalton Highway (Haul
Road)from Fairbanks will be utilized for smaller shipments to the site.
Construction Water Supply
A complete water supply,storage and distribution system will be
installed.Due to the nature of the site,a heated and insulated
one-million gallon water storage tank will be incorporated into the
camp's design,with one-half of this storage capacity dedicated to fire
protection needs.The water supply will be derived from an existing
1ake.
Construction Transmission Lines
Power requirements during the construction phase will be supplied by
constructing a 69 kV transmission line tapped from the area1s existing
transmission system.
26018
?-,~
Construction camp Facilities
A 200 (maximum)bed labor camp will be provided unless an existing camp
can be utilized.All personnel housed in this camp will be on single
status.Provisions will be made to accommodate a work fo~e of both
men and women by providing separate facilities.
The 200 bed camp will accommodate the maximum required workforce for
those years when two turbines will need to be installed and started up
at the same time.For other years,a workforce of 50 to 100 (maximum)
is anticipated.This camp will also be used to house operating
personnel.
2.1.7 Operation and Maintenance
Plant Life
Each gas turbine will have a 30 year life expectancy.It is expected
that the gas turbine units will be overhauled in accordance with
manufacturer's suggestions and good operating practice for the life of
the units.
Heat Rate of Units
Unit heat rates for the plants will vary,depending on ambient
conditions at the sites.It is common practice for gas turbine
manufacturers to quote heat rates in terms of the lower heating value
(LHV)of the fuel.However,since fuel is purchased based on higher
heating values (HHV),HHV figures are used in,the balance of this
report.The site specific HHV heat rate is 11,500 Btu/kWh.ISO
conditions give a heat rate of 10,700 Btu/kWh (LHV)for base load
operation.
2601B
2-14
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Scheduled and Forced Outage Rate
It is expected that the forced outage rate will be about 8 percent.
Operational experience on other plants indicates higher forced outages
in the first few years,but this is attributed to operational
adjustments required for a new plant.It is expected that a slight
increase in forced outages will occur as the plant ages.
Scheduled outages will be an additional 7 percent based on two periods
of regular semi-annual maintenance requiring shut down and one 5 week
period every three years for overhaul.
Operating Workforce
The number of personnel required to operate a plant of this type can
vary widely,depending on plant utilization and system operating
practices.Based on Electrical Power Research Institute Operational
Development Group study figures,and considering the severity of
climate and operational failure,an on-duty operation and maintenance
workforce of 10 persons will be required starting in 1993,when one
unit is operating.This will grow as units are added until an on-duty
force of approximately 50 persons will be required for the 15 units
operating in 2010.Assuming a 12 hour shift and a 7-day-on,7-day-off
work schedule,the total required workforce will vary from 40 to 200
personnel.
2.1.8 Site Opportunities and Constraints
Climate is the single most important site characteristic affecting
design at the North Slope.As previously mentioned,the 77 MW rating
of the turbine is based on ISO conditions with an ambient temperature
of 59°F.As the ambient temperature decreases,the capacity of these
units increases.At O°F,the rated capacity of these units is 122
percent of the capacity at 59°F,or approximately 94 MW.The heat rate
decreases as the temperature decreases,and at O°F is 97.5 percent of
2601B
2-1;
that at 59°F,or approximately 11,600 Btu/kWh (HHV).Clearly a cold
climate site such as the North Slope offers some operational
performance advantages.This is especially true since the cold weather
also produces the annual peak loads for the Railbelt area.The average
annual temperature at the North Slope site is 9°F resulting in an
average annual unit capacity and heat rate of 91 MW and 11,500 Btu/kWh
(HHV),respectively.
The remoteness of the site combined with the climatic conditions
present the most significant problems to construction of this
scenario.The short construction season and the cost of construction
at the North Slope generally dictate that as much prefabrication as
possible be performed prior to shipping units to the site.In addition
the arrival of shipments via barge will be delayed until mid-summer
when the Arctic coast becomes free of ice.This further shortens the
construction season for shipped materials and may require storage over
winter for completion of construction the following summer.
2.2 TRANSMISSION SYSTEM
2.2.1 Overview of the System
For reasons of reliability,two parallel circuits have been
considered.The design criteria used in the study are presented in
Table 2-3.Additional details regarding system design and alternatives
are presented in Appendix D.The 450-mile length of the proposed
transmission system between the North Slope and Fairbanks will be
interrupted by two intermediate switching stations,one at Galbraith
Lake and one at Prospect Camp;this will establish three almost exactly
equal 150-mile-long segments.
The two circuits will originate in the Prudhoe Bay/Deadhorse area of
the North Slope.Each circuit will be supplied by two 750 MVA
transformers,protected by one circuit breaker and compensated with a
series.capacitor bank and shunt reactor.The two circuits will be
26018
2-16
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2601B
TABLE 2-3
TRANSMISSION LINE DESIGN CRITERIA
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST
maximum 18 kV per centimeter
1.5"radial thickness with 8 lbs/sq.ft.wind
load at 32°F
25 1 bs per sq.ft above the Arctic Circle and
8 lbs/sq.ft.below it;2.3 lbs/sq.ft.at
+86°F
36"north of the Arcti c Ci rcl e and 24"south
of it
minimum 38 feet with snow on the ground
maximum 50%of rated tensile strength
Ice on conductor:
Tension in conductors:
Temperature range:
Wi nd loads:..!.!
Clearance to ground:
Snow on ground:
Gradient on conductor
surface:~/
l/25.0 lbs per square foot corresponds to 100 mph wind
8.0 lbs per square foot corresponds to 55 mph wind
2.5 lbs per square foot corresponds to 30 mph wind
~/To reduce corona losses and mitigate radio and television interference
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located on opposite sides of the road for the first 60 miles,to Pump
Station 2.South of the 60 mile mark,the line may not necessarily be
located on the two sides of the road.
The first switching station will be at Galbraith Lake approximately 150
miles south of Prudhoe Bay.Immediately south of the switching station
is a 30-mi1e portion of the route where the suitable terrain narrows,
possibly requiring the two circuits to be placed on single towers.In
the Atigun Pass area the slopes of the mountainside are not overly
rugged and the two circuits could be constructed a few hundred feet up
the slopes from the roadway.The Atigun Pass section is about 5 miles
long and reaches an elevation of approximately 5,000 feet,the highest
point of the transmission system.
The second switching station will be located at Prospect Camp.It will
be identical to the one at Galbraith Lake.The line will cross the
Yukon River near the Yukon River Bridge,and will terminate in the
Fairbanks area.
2.2.2 Voltage Selection
Three voltage levels were investigated in detail:500 kV AC,765 kV AC,
and ~350 kV DC '(see Appendix D).Each of these are capable of
transmitting the required power from the 'North,Slope to Fairbanks.A
comparative cost study has been made using the methodology and cost
figures supplied by Commonwealth Associates (1978).The study
indicated that all three versions are within +10%as far as capital
investment is concerned,which is within the expected range of accuracy
of these types of calculations.Therefore,all three can be considered
to be equal with respect to capital cost.The 500 kV alternative was
chosen for detailed cost estimating because this version represents the
most conventional approach and would likely have the best reliability.
2601B
2-18
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2.2.3 Towers
Tubular steel H-frame towers will be utilized for the line;their
average height will be 90 feet and the average span will be 1000 feet.
There will be one dead end tower at approximately every 10 miles,or in
other terms 2%of the towers will be dead end.l /
Special consideration has been given to the crossing of the Yukon
River,about 1000 feet downstream from the highway bridge.The
required span will be approximately 3000 feet.At the selected
location the right (north)bank of the river is a flat,low floodplain,
but an approximately 300-foothill rises at the left (south)bank
making the design of the crossing easier.The span will be between two
lattice type dead end towers,one approximately 120 feet tall at the
north shore and the other approximately 100 feet tall on the top of the
hi 11 at the south end of the span.Thi s arrangement shoul d pose no
greater hazard to waterborne traffic than does the bridge.
2.2.4 Conductors
Bundled conductors will be used for the 1 ine with two conductors per
bundle at 18 inches apart.Except for the Yukon River crossing,Chukar
conductor,a 1780 kCM ACSR~/conductor wi th a rated strength of
51,000 lbs and an outside diameter of 1.6 inches,should be used.With
a 1000-foot average span,the maximum sag will be 42 feet,Which,with
a 95 foot tall tower,will provide adequate clearance to ground.In
satisfying all appropriate design criteria,the conductors will be
oversized with respect to current carrying capacity,consequently,one
circuit will be capable of carrying almost twice the required medium
forecast power.The line will be provided with spacer dampers.
11 A dead end tower is capable of withstanding a conductor break,
preventing structural failure of the transmission system from
proceeding beyond a dead end tower.
2/ACSR -aluminum conductor,steel reinforced.
2601B
2-19
For the Yukon River crossing a special conductor with an ultimate
strength of 235,500 1bs may have to be ordered,such as 61x5 strand
A1umoweld from the Copperwe1d Company.With the recommended towers,
minimum clearance to high water will be 70 feet during the summer and
45 feet in the winter.Construction of the span will be done during
the winter months when ice cover permits working over the river bed.
Special vibration studies must precede actual design and vibration
recording instruments must be installed after erection.
2.2.5 Insulators
Suspension insulators,such as type 5-3/4"x 10"x 50 K 1b,will be
used.Two strings in a V configurati on will ho1 d the conductor
bundle.Normally,25 insulators are in each string •.
For the first 60 miles from Prudhoe Bay fog type insulators will be
installed and the number of insulators in the strings will be increased
by two over that provided for the remainder of the route.Also,fixed
insulator washing installations will be provided at each tower,based
on the experience that Sohio has operating 69 kV lines at the North
Slope.A tank truck equipped with pumps,hoses and other equipment
will perform the annual washing in the fall.
2.2.6 Switching Stations
The two switching stations at Galbraith Lake and at Prospect Camp will
divide each of the line circuits into three,almost equal,150 mile
long segments.The circuit schematic can be seen in Figure 2-5.The
arrangement is conventional.The intermediate switching stations will
make it possible to switch a shorter segment out of the system in case
of a fault of a circuit,instead of the entire line length;this will
improve the stability,hence the reliability,of the power system.
2601B
2-20
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NORTH ILOPE GAS
FEAStBILfTY STUDY
FIQUflE 2-6
E8ASCO SERVICES ICORPORATED
NORTH SLOPE POWER GENERATION
MEDIUM LOAD FORECAST
TYPICAL TWO LINE
SWITCHING STATION SCHEMA TIC
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2.2.7 Fairbanks Substation
The Fairbanks substation one line schematic is shown in Figure 2-6.
Two 500 kV line.circuits,originating at Prudhoe Bay,will be connected
to the substation,through either one 1500 MVA or two 750 MVA 345/525
kV transformers.Three 345 kV circuits will leave the substation'in
the direction of Anchorage.Two transformers will provide power for
local area loads.The bus will be at 345 kV.The schematic shows two
static VAR compensators connected to the bus through dedicated
transformers.These static compensators will not necessarily be
located where shown in Figure 2-6;their connections to the system are
described in detail in Appendix D.The circuitry will use breaker and
a half .or double breaker arrangements.The substation will be designed
so that the loss of one line,transformer,circuit breaker or
compensator allows uninterrupted operatio~at full power.
2.2.8 Construction
Five camps will be used to house the work force;each camp will serve
about a 90-mile section of the line for most of the construction
period.The number of people will vary between 41 and 155 per camp,
including the camp crew.The one exception is the period of building
the gravel pads,when a total of 2400 people will have to be housed
during the first summer of construction,which may require the opening
of additional camps.
A 100'X 100'gravel pad must be constructed to serve as the base of
each tower,and every 18 miles 300'x 1200'pads will serve as
marshalling yards.Fifteen crews,with the aid of helicopters,can
erect the towers during a six month work period.The last operation
will be the stringing,which can be done by 5 crews,each with
helicopter assistance.The switchyards will be constructed during the
time that the line is stringed.
2601B
2-22
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MEDIUM LOAD FORECAST
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Pad building will take place in one summer using two 10-hour shifts.
All other operations,except for surveying,will each take six months
to perform and will be scheduled for fall and spring when the soil is
frozen,but when enough day1 i ght is avail ab1 e to work at 1east one
a-hour shift.
2.2.9 Operation and Maintenance
The least reliable equipment will be the series capacitors.The cost
of a series compensated 500 kV line is about the same as that of an
uncompensated 765 kV line.The 765 kV alternative should be
investigated in more detail during detailed design of the line.The
trade-offs of not having series capacitors are wider rights-of-way,
increased problems due to contamination near Prudhoe 8ay and i~creased
difficulties to construct the two circ'uits through Atigun Pass."
2.2.10 Communications
To provide adequate communications,a microwave system will be
installed.The North Slope-Fairbanks line will require 16 repeater
stations.Five channels will be required,at least,one for
supervisory voice communication,one for data transmission,one for
relaying,one for service communication (below 4 kHz)and for alarm
(above 4kHz),and one spare channel.Each repeater station will have a
radio transceiver to maintain voice communication between vehicles and
the dispatcher,using the service voice channel.
In addition,each transmission line circuit segment will be provided
with a line carrier,mainly to provide redundancy for vital transfer
tri p functi ons.
Though this project assumed a dedicated microwave system,t~e project
proponent may consider leasing microwave channels from ALASCOM.
Several options,including direct satellite link,may be cost effective.
26018
2-24
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2.2.11 Siting Opportunities and Constraints
An inspection of the route indicated that most of the route should not
cause significant construction problems.However,three areas are of
some concern.The first 60 miles of the line south from the North
Slope is a tundra area;civil engineering design and construction
methods will have to be carefully investigated.Second,the grounding
problems posed by frozen soil require that a bare copper conductor,
called a counterpoise,be buried under each circuit along the entire
length of the transmission line and be connected to the ground mats of
all the substations and SWitching stations.Third,crossing Atigun
Pass,as mentioned earlier,will require careful design;here the
counterpoises may have to be routed farther from the circuits or be
.carr.i ed on the towers.
2.2.12 Fairbanks to Anchorage Line
System studies perfonned by Ebasco (see Appendix D)indicate that
345 kV is a suitable voltage for this transmission line.This voltage
is compatible with the 345 kV Intertie under construction.Therefore,
two new 345 kV lines will be built and the Intertie will be extended
fully between Fairbanks and Anchorage.
At the time of writing this report,the detailed design of the Intertie
is available.Based on this information,the designs of the Intertie
extension and the two new lines are assumed to be the same as the
Commonwealth Associates (1981)design.The only additions will be the
intermediate switching station,shown in Figure 2-7,the series
capacitors and the shunt reactors.
2.2.13 Anchorage Substation
The Anchorage substation will be the termination of the three 345 kV
line circuits.The substation bus will be 138 kV,as can be seen in
Figure 2-8.All other details will be similar to that described for
the Fairbanks substation (Section 2.2.7).
2601B
2-25
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ALASKA POWER AUTHORITY
NORTH SLOPE GAS
FEASIBILITY STUDY
EBASCO SERVICES NCORPOAA TED
'tGURE 2-7
II
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NORTH SLOPE POWER GENERATION
MEDIUM LOAD FORECAST
TYPICAL THREE LINE
.....SWITCiilNG STATION SCHEMA TIC
ANCHORAGE
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PlAS.IUTY .TUDY
NORTH SLOPE POWER GENERATION
MEDIUM LOAD FORECAST
ANCHORAGE SUBSTATION SCHEMATIC
...lIM '-I
2.3 COST ESTIMATES
2.3.1 Construction Costs
2.3.1.1 Power Plant
To support the derivation of total systems costs which are presented in.
Section 2.3.4,feasibility level investment costs were developed for
the major bid line items common to a 77 MW (ISO conditions)natural gas
fired simple cycle combustion turbine and a 220 MW (ISO conditions)
natural gas fired combined cycle plant.These costs are presented in
Tables 2-4 and 2-5.The costs represent the total investment for the
first unit to be developed at the site.Additional simple cycle units
will have an estimated investment cost of $53,560,000 while additional
combined cycle units will have an estimated investment cost of
$218,820,000.The cost differential for additional units is due to
significant reductions in line items 1 and 15,improvements to Site and
Off-Site Facilities,and reductions in Indirect Construction Cost and
Engineering and Construction Management.
For the North Slope power generation scenario only simple cycle unit
costs have been used in the total system cost analysis (Section
2.3.4).Combined cycle costs were developed to support the cost
sensitivity analysis performed in conjunction with the system planning
studies (Appendix B).
2.3.1.2 North Slope to FairDanks Transmission Line
Transmission line feasibility level investment cost estimates for the
North Slope to Fairbanks connection are presented in Table 2-6.These
estimates are based on two 500 kV lines of 1400 MW capacity with series
compensation,and two intermediate switching stations.
2601B
2-28
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Construction Total
Descri pti orl!./
Material Labor Di rect Cost
($1000)($1000) ($1000)
l.Improvements to Site 385 4,800 5,185
2.Ea rthwork a nd Pi 1i ng 605 1,710 2,315
3.Circulating Water System 0 0 0
4.Concrete 25 450 475
5.Structural Steel Lifting
Equipment,Stacks 675 1,230 1,905
6.Buildings 4,625 1,710 6,335
7.Turbine Generator 11 ,200 2,700 13,900
8.Steam Generator and Accessories 0 0 0
9.Other Mechanical Equipment 460 ·985 1,445
10.Pipi ng 200 2,100 2,300
11.Insulation and Lagging 30 450 480
12.Instrumentation 100 300 400
13.Electrical Equipment 1,500 10,800 12,300
14.Painting 5 90 95
15.Off-Site Faci1itiesf!500 9,000 9,500
SUBTOTAL $20,310 $36,325 $56,635
Freight Increment 1,015
TOTAL DIRECT CONSTRUCTION COST $57,650
Indirect Construction Cost 3,505
SUBTOTAL FOR CONTINGENCIES 61,155
Co nti ngenc i es (15%)9,175
TOTAL SPECIFIC CONSTRUCTION COST 70,330
Engineering and Construction 2,300
Management
TOTAL CONSTRUCTION COST $72,630
2601B
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TABLE 2-4
FEASIBILITY LEVEL INVESTMENT COSTS
77 MW SIMPLE CYCLE COMBUSTION TURBINE
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST
(January,1982 Dollars)
The following items are not addressed in the plant investment pricing:
laboratory equipment,switchYard and transmission facilities,spare
parts,land or land rights,and sales/use taxes.
Costs for construction camp and construction workforce travel included
in Construction Labor category.
2-29
TABLE 2-5
FEASIBILITY LEVEL INVESTMENT COSTS
220 MW COMBINED CYCLE PLANT
NORTH SLOPE POWER GENERATION -MEDIUM LOAD·FORECAST
.(January,1982 Do 11 ars).
Construction Total
Descri pti onl.!
Materi a1 Labor Di rect Cost
($1000 )($1000)($1000)
l.Improvements to Site 385 4,800 5,185
2.Earthwork and Piling 1,860 5,460 7,320
3.Circulating Water System 0 0 0
4.Concrete 100 2,160 2,260
5.Structural Steel Lifting
Equipment,Stacks 900 2,400 3,300
6.Buildings 12,575 4,560 17,135
7.Turbine Generator 30,300 10,500 40,800
8.Steam Generator and Accessories 9,600 18,000 27,600
9.Other Mechanical Equipment 5,625 11 ,705 17,330
10.Pipi ng 1,470 12,000 13,470
11.Insulation and Lagging 290 2,880 3,170
12.Instrumentation 1,700 1,200 2,900
13.Electrical Equipment 4,500 36,000 40,500
14.Painting 25 360 385
15.Off-Site Facilities2/500 9,000 9,500
SUBTOTAL $69,830 $121,025 $190,855
Frei ght Increment 3,490
TOTAL DIRECT CONSTRUCTION COST $194,345
Indirect Construction Cost 8,760
SUBTOTAL FOR CONTINGENCIES 203,105
Contingencies (15%)30,465
TOTAL SPECIFIC CONSTRUCTION COST 233,570
Engineering and Construction 7,000
Management
TOTAL CONSTRUCTION COST $240,570
1/The following items are not addressed in the plant investment pricing:
laboratory equipment,switcnyard and transmission facilities,spare
parts,land or land rights,and sales/use taxes.
2/Costs for construction camp and construction workforce travel lncluded
in Construction Labor category.
2601B
2-30
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Construction ?:/Total
Materi al Labor Direct Cost
De sc ri pti onl/($1000)($1000)($1000)
Switching Stations 33,335 26,100 59,435
Substations 58,655 44,941 103,596
Energy Management System 12,900 12,000 24,900
Steel Towers and Fixtures 822,212 873,012 1,695,224
Conductors and Devices 63,962 149,760 213,722
Cl eari ng 0 85,200 85,200
SUBTOTAL $991,064 $1,191 ,013 $2,182,077
Land and Land RightSY 36,000
Engineering and Construction
Management 152,750
TOTAL CONSTRUCTION COST $2,370,827
Construction camp facilities and services are included in the
Construction Labor cost category.
The investment costs reflect two 500 kV lines,1400 MW capacity with
series compensation and two intermediate switching stations.A 15
percent contingency has been assumed for the entire project and has been
distributed among each of the cost categories shown.Sales/use taxes
have not been included.
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2601B
TABLE 2-6
FEASIBILITY LEVEL INVESTMENT COSTS
NORTH SLOPE TO FAIRBANKS TRANSMISSION SYSTEM
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST
(January,1982 Dollars)
Assumes a cost'of $40,000 per mile (Acres American Inc.1981).
2-31
2.3.1.3 Fairbanks to Anchorage Transmission Line
Transmission line feasibility level investment cost estimates for the
Fairbanks to Anchorage connection are presented in Table 2-7.These
estimates are based on two new 345 kV lines,with shunt and series
compen.sation aryd ·an intermediate switching station.The investment
cost estimates also reflect upgrading from 138 kV to 345 kV of the
Willow-Anchorage and Healy-Fairbanks segments of the eXisting grid.
2.3.2 Operation and Maintenance Costs
2.3.2.1 Power Plant
The power plant operation and maintenance (O&M)costs were derived to
support the system planning studies (Appendix B).They reflect a
review of figures from previous Rai1be1t studies,operation of other"
utilities,and salary requirements and expendable materials.The O&M
costs for this scenario are estimated to be $0.0063 per ki1lowatt hour
(6.3 mils/kWh).
2.3.2.2 Transmission Line Systems
Annual operation and maintenance costs (January,1982 dollars)have
been developed for the scenario's required transmission line facilities
and total $35 million per year.These costs should be viewed as an
annual average over the life of the system.Actual O&M costs should be
less initially,and increase with time.
2.3.3 Fuel Costs
For the economic analyses which follow fuel costs were treated as
zero.This approach permits fuel cost and fuel price escalation to be
treated separately;~nd makes possible SUbsequent sensitivity·analyses
of the Present Worth of Costs for this scenario based upon a range of
fuel cost and cost escalation assumptions.
2601B
2-32
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FEASIBILITY LEVEL INVESlMENT COSTS
FAIRBANKS TO ANCHORAGE TRANSMISSION SYSTEM
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST
(January,1982 Dollars)
Constructi on Total
Descri pti on.!!
Material Labor Direct Cost
($1000)($1000)($1000)
Switching Station 14,112 12,445 26,557
Substations 62,308 41 ,716 104,024
Energy Management Systems 12,300 10,960 23,260
Steel Towers and Fixtures 216,495 305,085 521,580
Conductors and Devices .33,678 78,361 112,039
C1 earing 0 83,144 83,144
SUBTOTAL $338,893 $531 ,711 $870,604
Land and Land Rights 2/0 0 27,600
Engineering and Construction 60,950
Management
TOTAL CONSTRUCTION COST $959,154
.l!The investment costs reflect two new 345 kV lines,1400 MW capacity with
shunt and seri es compensati on and an i ntermedi ate swi tchi ng stati on,and
upgrading of the WillOW-Anchorage and Healy-Fairbanks segments of the
eXistin~grid to 345 kV.
2/Assumes a cost of $40,000 per mile (Acres American Inc.1981).
2601B
2-33
2.3.4 Total Systems Costs
The total system for the North Slope scenario,medium load forecast,
consists of simple cycle gas turbines and an extensive transmission
line system.No gas conditioning facili-ties or pipeline are.
reqUired.Total annual systems costs reflect the relative simplicity
of thi s system.
The methodology and assumptions utilized to derive the systems'costs
which are presented below have been previously described in the Report
on Systems Planning Studies (Appendix B).This methodology is
consistent with previous studies of electric generating scenarios for
the Rai1be1t,specifically Acres American,Inc.(1981),Susitna
Hydroelectric ProJect Feasibi"lity Report and Battelle (1982);Railbelt
Electric Power Alternatives Study.The period of the analysis was
assumed to be 1982 through 201 O.
Annual capital costs for the system are presented in Table 2-8.
Annual non-fuel operation and maintenance (O&M)costs are presented in
Table 2-9.Total annual systems costs are then summarized in Table
2-10.
For scenario comparisons,the present worth of total annual costs for
the North Slope medium load f~recast has been.calculated.Assuming a
3 percent discount rate and excluding fuel costs,the 1982 present
worth of costs is $3.7 billion.The values are in 1982 dollars.
2.4.ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS
Development of a gas fired simple cycle combustion turbine facility at
the North Slope and transmission facilities to bring the energy to the
Rai1be1t region will engender a variety of significant environmental
effects.Precise quantification of environmental impacts will require
more detailed site-specific analysis.However,most major potential
2601B
2-34
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TABLE 2-8
TOTAL ANNUAL CAPITAL EXPENDITURES
NORTH SLOPE POWER GENERATION -MEDIUM LOAD1/FORECAST
(Millions of Januar,y,1982 Dollars)_
Calendar Electricity Generation 2/Transmi ssi on
Ye.ar Unit A Uni t B Line Total
1982 O.O.O.O.
1983 O.O.O.O.
1984 O.O.O.O.
1985 O.O.O.O.
1986 O.O.O.O.
1987 O.O.O.O.
1988 O.O.O.O.
1989 .O.O.1,803.30 1,803.3.1990 O.O.418.45 418.5
1991 19.07 3/O.823.50 842.6
1992 53.56 O.3'34.76 388.3
1993 O.O.O.O.
1994 53.56 O.O.53.6
1995 53.56 O.O.53.6
1996 53.56 O.O.53.6
1997 53.56 O.O.53.6
1998 O.O.O.O.
1999 53.56 O.O.53.6
2000 O.o.O.o.
2001 53.56 53.56 O.107.1
2002 o.o.o.O.
2003 53.56 O.O.53.6
2004 53.56 53.56 O.107.1
2005 53.56 O.o.53.6
2006 53.56 O.o.53.6
2007 53.56 O.o.53.6
2008 O.O.O.O.
2009 53.56 O.O.53.6
201 0 O.O.O.o.
Total $715.$107.$3,380.$4,202.
1/Values as calculated are shown for purposes of reproducibility
only,and should not be taken to imply the indicated accuracy of
significant figures..
~/Unit A refers to first unit built in a given year and Unit B to
the second unit built.
~/Construction of campsite and site preparation for all units.
2601B
2-35
TABLE 2-9
TOTAL ANNUAL NON-FUEL O&M COSTS
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST
(Millions of January,1982 Dollars)
Calendar Electricity Transmission
Year Generation System Total
1982 O.o.O.
1983 O.O.O.
1984 O.O.O.
1985 O.O.O.
1986 O.O.O.
1987 O.O.o.
1988 O.O.O.
1989 o.O.O.
1990 O.O.O.
1991 O.O.O.
1992 O.O.o.
1993 3.767 35.0 38.8
1994 3.767 35.0 38.8
1995 7.535 35.0 42.5
1996 11.334 35.0 46.3
1997 15.063 35.0 50.1
1998 18.831 35.0 53.8
1999 18.831 35.0 53.8
2000 22.661 35.0 57.7
2001 22.598 35.0 57.6
2002 30.133 35.0 65.1
2003 30.133 35.0 65.1
2004 33.995 35.0 69.0
2005 36.414 35.0 71.4
2006 38.134 35.0 73.1
2007 39.848 35.0 74.8
2008 41.567 35.0 76.6
2009 43.281 35.0 78.3
2010 45.001 35.0 80.0
Total $463.$630.$1,093.
2601B
2-36.
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TABLE 2-10
TOTAL ANNUAL SYSTEMS COST
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST
(Millions of January,1982 Dollars)
Calendar Capital o &M Total
Year Expenditures Costs Expenditures
1983 O.O.O.
1984 O.O.O.
1985 O.O.O.
1986 O.O.O.
1987 O.O.O.
1988 O.O.O.
1989 1,803.3 O.1,803.3
1990 418.5 O.418.5
1991 842.6 O.842.6
.1992 388.3 O.388.3
1993 O.38.8 38.8·
1994 53.6 38.8 92.4
1995 53.6 42.5 96.1
1996 53.6 46.3 99.9
1997 53.b 50.1 103:7
1998 O.53.8 53.8
1999 53.6 53.8 107.4
2000 O.57.7 57.7
2001 107.1 57.6 164.7
2002 o.65.1 65.1
2003 53.6 65.1 118.7 .
2004 107~1 69.0 176.1
2005 53.6 71..4 125.0
2006 53.6 73.1 126.7
2007 53.6 74.8 128.4
2008 O.76.6 76.6
2009 53.6 78.3 131.9
2010 O.80.0 80.0
Total $4,202.$1,093.$5,295.
Present
Worth @ 3%$3,156.$600.$3,757.
2601B
2-37
environmental concerns related to this scenario have been identified,
and may be categorized as follows:
(l)Ai r Resource Effects
(2)Water Resource Effects
(3)Aquatic Ecosystem Effects
(4)Terrestrial Ecosystem Effects
(5)Socioeconomic Effects
Each of these subject areas is discussed in the following subsections.
Power plant characteristics related to each of these subject areas is
summarized in Table 2-11.
2.4".1 Air Resource Effects
Development of the North Slope generating facility may be governed in
large part by air quality considerations.The federal Clean Air Act
and the Alaska rules for air quality control require the generating
facility to meet both atmospheric emission and ambient air quality
standards.Emission standards are defined in terms of New Source
Performance Standards (NSPS)and Best Available Control Technology
(BACT).NSPS apply generically to combustion turbines,and set a
ceiling of emission levels that cannot be exceeded.Because gas fired
power plants are relatively clean,NSPS levels do not pose a constraint
to the development of this generating facility.BACT requirements are
determined on a case-by-case basis,taking into account energy,
environmental,and economic impacts,but are never less stringent than
NSPS.
The Prevention of Significant Deterioration (PSD)program protects
relatively clean areas from undergoing substantial degradation through
ambient air quality standards.The PSD increments for particulate and
sulfur dioxide have not been exhausted on the North Slope,and
2601B
2-38
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TABLE 2-11
ENVIRONMENT RELATED FACILITY CHARACTERISTICS
SIMPLE CYCLE COMBUSTION TURBINES
NORTH SLOPE POWER GENERATION -MEDIUM LOAD FORECAST
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Particulate Matter
Sulfur Dioxide
Nitrogen Oxides
PhYsical Effects
Water Environment
Plant Water Requirements
Plant Discharge Quantity,
Including Sanitary Waste
and Floor Drains
La nd En vi ronment
Land Requirements
Plant and Switchyard
Construction Camp
Socioeconomic Environment
Construction Workforce
Operating Workforce
2601B
Below standards
Below standards
Emissions variable within standards -
dry control techniques would be used
to meet calculated NO~standard of
0.014 percent of total volume of
gaseous emissions •.This value
calculated based upon new source
performance standards,facility heat
rate,and unit size.
Maximum structure height of 50 feet
50 Ga 11 ons per Mi nute (GPM)
Less than 50 GPM
90 acres
5 acres
Approximately 200 personnel at peak
construction (power plant only)
Approximately 200 personnel employed
in the year 2010 (power plant only)
2-39
therefore do not constrain development.PSD increments for nitrogen
oxides,the major pollutant from combustion turbines,have not been
established.However,general PSD requirements dictate that Best
Available Control Technology be used to reduce nitrogen emission levels.
..
In the case of combustion turbines,BACT usually consists of using
water or steam injection techniques to control emission levels by
reducing combustion temperatures.Unfortunately,water or steam
injection in the Prudhoe Bay area causes undesirable levels of ice
fog.Furthermore,water or steam injection requires fresh water
supplies that are generally not economically available on the North
Slope.For these reasons,ai r qual ity regu1 atory agenci es have not
defined BACT for the North Slope to include using water or steam
injection to control nitrogen oxides.Im~osition of the requirement
for water or steam injection would add substantial costs and·
significantly decrease the relative feasibility of this scenario.For
the purposes of this study it is assumed that water injection for NO x
control would not be required.
Even with no water injection requirement,air quality regulations would
not be likely to hamper installation of a gas fired power plant in the
Prudhoe Bay area.However,a jUdicious siting effort would still be
necessary to avoid compounding any air pollution problems from existing
facilities.
The construction of two 500 kV transmission lines between the North
Slope and Fairbanks would result in temporary air quality impacts.The
use of heavy equipment and other construction vehicles would generate
fugutive dust and exhaust emissions.Slash burning of material to
clear the right-of-way would produce emissions.The impacts from these
construction-related activities are expected to be small because the
emi ssi ons wou1 d be wi de1:y.di spersed and occur in unpopul ated or
sparsely populated areas.
2601 B
2-40
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The long term impacts from operation of the transmission lines are
expected to be negligible.The transmission lines would generate small
amounts of ozone which would be undetectable at ground levels and would
not cause problems with nearby vegetation.
The air quality impacts of constructing the transmission lines from
Fairbanks to Anchorage would result from activities similar to those
mentioned above.The impacts are expected to be of approximately the
same magnitude t although the amount of slash material to be burned
would be greater within this corridor and would be within proximity to
more populated areas.
The long term impacts from transmission line operations would be
similar to those of the Prudhoe Bay-Fairbanks transmission line
cor.ri dora
2.4.2 Water Resource Effects
The principal effects of the proposed generating facility on the water
resources of the Prudhoe Bay area include consumptive withdrawals from
freshwater sources (existing lakes)for potable supplies and
miscellaneous uses such as equipment wash-down.Because the generating
station will require minor volumes of water and will be served by
existing waste treatm~nt facilities in the area t water resources
effects associated with these uses will not be significant.
For the medium load forecast t the site must have access to
approximately 50 gpm.This water will be taken from a nearby
freshwater lake of sufficient size so that the lake level and
~drologic balance is not significantly affected.
Transmission line construction between the North Slope and Fairbanks
may impact the quality of surface water resources through erosion
caused by landdisturbance t but has little or no impact on water
supplies.Erosion control t especially in steep terrain or areas of
2601B
2-41
susceptible soils,will be a major requirement imposed by permits
issued for right-of-way clearing and construction of the transmission
and related facilities,such as access roads.For example,the Bureau
of Land Management (BUM)land use plan for the Prudhoe Bay-Fairbanks
Utility Corridor (BUM 1980)within which the transmission facilities
would be routed,specifically requires protection of stream banks and
lake shores by restricting activities to prevent loss of riparian
vegetati on.
Construction activities of the transmission lines between Fairbanks and
Anchorage would result in temporary impacts.The transmission lines
would cross several large rivers and numerous creeks,resulting in
temporary stream siltation,bank erosion,and the potential for
accidental spillage of lubricating oils and o~her chemicals into the
watercourses.Construction equipment working along streambanks or
crossing smaller streams could cause direct siltation of the
watercourse or cause indirect stream bank erosion and siltation through
the removal of vegetation and disturbance of permafrost.The effects
of siltation could alter stream channels,fill ponds,or damage aquatic
flora or fauna.
Significant effects on watercourses may be prevented by keeping
•,.0 •
construction activities out of channels and away from stream b~nks.
Measures that could be taken to avoid impacts include a set back of 200
feet from watercourses for transmission structures as well as
establishment of a buffer strip along major watercourses to minimize
disturbance of vegetation and soils by construction equipment.In
cases where watercourses must be crossed by construction equipment,
such crossings could be conducted either during cold periods when the
stream is frozen or in a manner to limit pollution or siltation.The
use of helicopters to erect the towers will help to minimize overall
construction impacts,since ground access requirements will be
minimized.
2601B
2-42
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2.4.3 Aquatic Ecosystem Effects
The major aquatic ecosystems of the North Slope area include the marine
environment of the Beaufort Sea,the freshwater environments of the Sag
and Put Rivers and their tributaries,and estuarine habitats at the
rivers'mouths.Shallow lakes in the area do not support fish because
of complete freezing in the wintertime.Deeper lakes may contain
resident species such as stickleback,but in general,knowledge of
these lakes is presently limited.In the rivers and estuaries,two
groups of fish are considered important:river fish such as the
grayling,and anadromous fish such as the the Arctic char and cisco.
The anadromous species descend local rivers at ice-breakup to feed in
the shallow littoral and sublittoral zone of the Beaufort Sea.They
ascend these rivers in the autumn and overwinter in deep pools.These
fishod~not appear to undertake extensive migrations up the Sag or Put
Rivers.
These fishery resources could be affected by construction and operation
of a water supply intake,pipeline and access road construction,gravel
mining in rivers which could affect overwintering and general habitat
quality of the fish,and the need to cross larger river channels which
could interfere with fish passage.The latter item may require the use
of speci a]ocu1 verts to mai ntai n mi gratory routes.Each of these
potential effects would be analyzed on a site-specific basis,and
detailed impact avoidance or mitigation measures developed •.
Aquatic ecosystems within the transmission line corridor will also
require protection during project construction.Between the North
Slope and Fairbanks,the transmission lines may cross as many as 150
waterbodies which are utilized by fish for migration,rearing,
spawning,a~d/or wintering.Siting should avoid or minimize impact to
spawning areas in approximate~y 35 waterbodies and to wintering areas
in approximately 15 waterbodies.Information regarding specific
waterbodi es of concern is presented in Appendi x C,"Report on Faci 1i ty
Siting and Corridor Selection.II
2601B
2-43
Counterpoise (ground cable)construction may require excavation in
streambeds;this activity must be carefully planned (both spatially and
temporally)and monitored in accordance with individual permit
requirements.Conditions vary along the corridor,so that
environmental protection stipulations imposed by the regulatory
agencies will tend to be site-specific.
The transmission line corridor between Fairbanks and Anchorage makes as
many as 100 crossings of rivers and streams and comes within one mile
of numerous lakes and ponds.All of these waterbodies are important
habitat for endemic and anadromous fisheries.Impacts to fisheries
such as increased runoff and sedimentation could occur through clearing
of the right-of-way and crossing of watercourses by construction
equipment.The introduction of ·silt into streams·can delay hatching,
reduce hatchi ng success,prevent ·swimup,and produce weaker fry.
Siltation also redUces the benthic food organisms by filling in
available intergrave1 habitat.
The potential adverse impacts can be reduced or eliminated through
construction schedUling.Construction of the transmission lines during
the winter would minimize erosion since the snow protects low
vegetative cover that stabilizes soils.Ice bridges could be used by
construction equipment for crossing spawning areas,where possible.
Otherwise,where equipment would move through watercourses,
construction could occur during periods when there are no eggs or fry
in the gravel.
2.4.4 Terrestrial Ecosystem Effects
The North Slope area and specifically the river delta areas provide a
variety of habitats that are important to a diversity of plants and
anima1s.Project related impacts which require special consideration
include:(1)direct habitat elimination through the construction of
project facilities,access roads,and gravel borrow areas;(2)indirect
2601B
2-44
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habitat elimination resulting from access roads which impede drainage
or which generate significant traffic related dust;and
(3)restrictions to large mammal movements,especially caribou.
Construction of the powerplant,switchyard,construction camp and
related access road~will disturb approximately 65 acres of·land.All
construction equipment should be restricted to areas covered with a
gravel pad.Tundra adjacent to the generating facility should not be
disturbed.
Because the generating facility will be located within the Prudhoe Bay
industrial complex,terrestrial habitat impacts engendered by this
project will be an added increment to those which have already occurred
as a result of oil field development.Final siting efforts should
include evaluation of the factors listed above,and will be the
mechanism through which highly significant terrestrial impacts can be
avoided,particularly the indirect impacts and migratory blockages.
The direct impacts of habitat removal due to facility construction are
generally unavoidable,1>ut can be minimized through careful site
planning and construction management.
Construction of the transmission line facilities will require
vegetative clearing in forested areas.Clearing shoulq be restricted
to the following categories of vegetation:
(1)Trees and brush which may fall into a structure,guy,or
conductor
(2)Trees and brush into which a conductor may blow during high
winds.
(3)Trees and brush within 25 feet of a conductor,and trees
within 110 feet of the line centerline.
(4)Trees or brush that may interfere with the assembly and
erection of a structure.
2601B
.2-45
Between the North Slope and Fairbanks,much of the area south of
Nutirwik Creek will require clearing of trees within the right-of-way.
Because two lines will be built and trees within 110 feet of the line
will be cleared,the total width of cleared vegetation will be 440
feet.Over the length of the line,approximately 7000 acres will be
cleared.
The transmission line corridor passes through a wide variety of
terrestrial ecosystems,and is adjacent to several major federal land
areas which have been protected,in part,for their wildlife values.
The Bureau of Land Management (BLM)land use'p1an for the Utility
Corridor (BU4 1980)has identified several areas as containing critical
wildlife habitat.Specific management restrictions have not as yet
been formulated;however,measures may be re~uJred for a number of
areas.Details regarding these areas are given in Appendix C.
The land use plan also specifically requires protection of raptor
habitat and critical nesting areas.Protection of crucial raptor
habitats preserves the integrity of raptor populations and maintains
predator-prey relationships.
Facilities and long term habitat alterations are prohibited within one
mile of peregrine falcon nest sites unless specifically authorized by
the U.S.Fish and Wildlife Service,because of the endangered species
status of the peregrine falcon.
As the transmission line corridor generally avoids known nesting areas,
the restriction may only apply to material sites.Information
regarding specific raptor nesting areas and siting restrictions are
presented in Appendix C.
It is unlikely that the transmission line would be sited in or near
important Da11 sheep habitat.A primary concern is aircraft traffic
over critical wintering,lambing,and movement areas.Moose winter
browse habitat in the Atigun and Sag River valleys is limited to areas
2601B
2-46
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of tall riparian wjllow.Habitat has already been eliminated by the
construction of Trans Alaska Pipeline System (TAPS)and further
destruction of this habitat should be avoided or minimized.The willow
stand along Oksrukuyik Creek,in particular,should not be disturbed.
System design must allow free passage for caribou,but these animals
should not be a major consideration in siting.Carnivore/human
interaction is a major concern in facilities design and in construction
and operations methods,but not in siting considerations.
Line routing and tower siting should avoid or minimize disturbance of
the treeline white spruce stand at the head of the Dietrich Valley,
which has been nominated for Ecology Reserve status.
For the Fairbanks to Anchorage transmission line approximately 80
percent of the corridor is located in forested areas (Commonwealth
Associates,1982).Assuming two additional lines are built and the
Intertie is extended,a total of about 8700 acres will be cleared.The
principal impacts associated with clearing a right-of-way and
construction of the transmission line are the alteration of existing
habitats and SUbsequent disruption of wildlife species that use those
habitats and disturbance to indigenous fauna and bird populations.
Most big game species would relocate during the construction of the
transmission lines.The construction schedule should be flexible so as
to avoid construction near calving and denning sites.The moose,which
adapts to many different habitat types,would establish a sUbclimax
community in the cleared right-of-way.The distribution of caribou is
limited along the transmission line corridor but those that do occur in
the vicinity of the right-of-way would be displaced.The caribou,
however,generally utilize habitats with low vegetative cover,
resulting in little alteration of caribou habitat.
Grizzly and black bears would relocate to avoid construction activity
along the right-of-way,except where construction occurs near a den
2601B
2-47
si te during winter dormancy.Constructi onactivi ty near denning areas
should be avoided from October 1 through April 30.The alteration of
habitats could temporarily affect bear use of the right-of-way but this
impact is expected to be relatively short-term.
Wolves within the vicinity of the right-of-way would also be displaced
during construction of the transmission line.While these impacts
would be temporary,long term impacts would occur to the wolf if their
principal prey species,such as caribou,sheep,and moose were
adversely affected.
Oa11 sheep occur only at the northern end of the transmission line
corridor and would be impacted only minimally by construction
activities.The use of he1 icopters to construct the 1 ines in the Moody
and Montana Creek drainages could severely disturb sheep in the
vicinity of Sugarloaf Mountain.
The impact to the regional populations of any of the small game ~pecies
is expected to be neg1 igible.Small game speci es are expected to
relocate during construction activities and re-invade the right-of-way
once constructi on is over.
In heavily forested areas along the corridor,the fight-of-way clearing
could provide an improved habitat for most of the small game species
that utilize sUbclimax communities.
Migratory waterfowl are susceptible to disturbance from construction
activities from mid-April to the end of September when they are nesting
and brood reari ng •Constructi on ac ti vi ti es shou1 d be restricted from
May through August in areas with active trumpeter swan nesting
territories.Collisions with transmission lines,guywires,and
overhead groundwires are another potential impact.To date,however,
the levels of avian mortality from line collision have not been
biologically significant (Beau1aurier et a1.1982).
2601B
2-48
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Furbearers are not expected to be greatly affected by construction
activities except during the initial right-of-way clearing.Most
furbearers will either adapt to the presence of the cleared
right-of-way or undergo short term impacts.The maintenance of a shrub
community in the right-of-way will reduce the loss of individuals.
The impacts on nongame mammal sand bi rds are expected to be
insignificant.Some small mammals and nongame birds would undergo
population shifts during construction activities but populations are
expected to recover within one to two reproductive seasons.Raptors
may lose some habitat as a result of clearing.Benefits of a cleared
right-of-way could occur as some raptors could find that it provides
hunting habitat or hunting perches not previou~ly available.
2.4.5 Socioeconomic and Land Use Effects
Potential socioeconomic and land use effects of the North Slope
scenario include both temporary impacts related to the influx of
workers and permanent land use impacts.
Since the generating plant would be located within the Prudhoe
Bay/Deadhorse industrial complex,the in-migrating work force would not
significantly affect the social and economic structure of the region.
The work force requirements are small in comparison to the existing
size of the transient work force in the Prudhoe Bay region.FQr 5
months of each year during the period 1993 through 2010 a maximum of
200 employees will be needed to assemble the prefabricated units of the
plant.Housing facilities would be provided for the employees at the
adjacent construction camp.During off-work periods,the majority of
the employees would spend time outside of the borough.The operations
work force is expected to be approximately 150 and will reside in the
labor camp.The spending of wages earned by the employees within the
North Slope Borough is expected to be minimal due to the transience of
the work force.
2601B
2-49
The use of land for an electrical generating plant would be compatible
with the land uses of the industrial enclave.The Coastal Zone
Management Program for the North Slope Borough has delineated zones of
preferred development.Permanent facilities are allowed in the
industrial development zone,consisting of the existing Prudhoe
Bay/Deadhorse.complex and the Pipeline/Haul Road Utility corridor
(North Slope Borough 1978).The generating plant would be located
within the preferred development zone.
Within the Prudhoe Bay/Deadhorse complex,the plant would be located to
minimize interferences with existing or planned facilities,including
buildings,pipelines,roads,and transmission lines.Land ownership
and lease agreements will limit the land available for the electrical
generating facility.
Socioeconomic and land use impacts related to construction and
operation of transmission facilities between Prudhoe Bay and Fairbanks
will be strictly controlled as a result of the guidelines and
constraints for development within the designated utility corridor.
Construction employees would be housed either at the pump stations or
the permanent camp facilities constructed for the trans-Alaska oil
pipeline.Construction activities would be consistent with the land
use criteria developed by the BUM.The BLM has prepared land use plans
••0 ••
for the utility corrido!between Sagwon Bluffs and Washington Creek.
Road and highway crossings would be minimized,and areas of existing or
planned mineral development would be avoided.
Construction facilities would be sited at carefully selected locations
in the vicinity of Livengood Camp,Yukon Crossing,Five Mile Camp,
Prospect, Coldfoot,Chandalar,and Pump Station #3.Existing
facilities such as work pads,highways,access roads,airports,
material sites and communications would be used to the maximum extent
possible.
2601B
2-50
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The schedule for constructing the transmission lines is approximately 3
years with activities occurring mainly during the autumn and spring of
each year.A peak work force of 2400 employees would be required
during the first year of construction when the pads would be built,and
in subsequent years the total work force would be sUbstantially reduced
to approximately 500 in the second year,600 in the third year,and 670
in the final year.It is expected that these workers will be hired
from the Anchorage and Fairbanks union hiring halls.
Development of additional transmission facilities between Fairbanks and
Anchorage would engender potentially more significant socioeconomic and
land use impacts,since this segment is more populated and subject to
future land use development.Temporary campsites would be provided to
house the work crews at locations accessible by the Parks Highway or
the Alaska Railroad.'The work force requirements would be lower for
this corridor because pads would not need to be constructed.The
schedule for constructing the transmission lines is approximately 22
months.A peak work force of approximately 520 employees would be
required during the last 6 months and the average work force would be
approximately 300.It is assumed that the project would utilize the
labor pools of Fairbanks and Anchorage.
Impacts to local communities would be minimized through careful siting
of the temporary work camps.It is expected that the work camps would
be self-contained in order to keep to a minimum interaction between the
construction workers 'and the local residents.The project is expected
to have minor primary economic benefits since few,if any,residents
would be employed on the project.
Land use impacts could include encroachment of the project on
residential areas as well as preclude future residential development
land available for homesteading.The most significant potential impact
would be the crossing of recreation lands and the sUbsequent effects on
recreation and aesthetic vaiues these lands are meant to preserve.
26018
2-51
The potential aesthetic impacts of the proposed new and additional
transmission facilities are significant.The cumulative effects of
these facilities and previous linear developments (e.g.,TAPS)could
result in significant degradation of the aesthetic character of
pristine wilderness landscapes.The visibility of the transmission
lines from existing travel routes (Dalton Highway,Parks Highway,etc.)
will vary depending on distance,topography and intervening
vegetation.Special care would betaken in selecting final route
alignments in proximity to areas of special visual significance,such
as national parks,or high visual sensitivity,such as areas within the
viewing range of motorists on the Parks Highway.In locations where
visual impacts cannot be avoided through careful routing or tower
spotting,mitigating measures,such as the use of non-reflective paint
or vegetative screening,can be employed.
26018
2-52
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SCENARIO I
NORTH SLOPE POVVER GENERATION
LOW LOAD
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3.0 NORTH SLOPE POWER GENERATION
LOW LOAD FORECAST
The North Slope power generation scenario,under the low load forecast,
is conceptually the same as the medium growth case,except that units
are phased in at a slower rate.By the year 2010,eight simple cycle
combustion turbine units are required to produce 728 MW.The electric
transmission system requires two 500 kV lines;however,series
capacitors are not required to ensure system stability.Total system
cost is estimated to be $3.3 billion,with annual operation and
maintenance costs of $0.7 billion.The present worth of these costs
excluding fuel costs is $2.7 billion as of 1982.Environmental effects
of the project are sUbstantial,but would not preclude construction.
Information presented in this section is designed to highlight only
those conditions which are significantly different from those of the
medium load forecast presented in Chapter 2.
3.1 POWER PLANT
This scenario requires eight 91 MW simple cycle gas turbines to satisfy..
the low Toad forecasted demand.The first of these w.ill go on line in
.1996 and the eighth in 2010.Additions are summarized in Table 3-1 and
scenario details are addressed in Appendix B.Annual fuel requirements
for power generation will start at 6.60 BCFY in 1996 and grow to 47.2
BCFY in 2010.The maximum potential firing rate in 2010 will be
approximately 1.33 x 105 SCFM.Fuel requirements on an annual basis
are also shown in Table 3-1.
With the exception of the sUbstation,all details of individual plant
items are identical to those described for the m~dium load case.in
'Section 2.1.The sUbstation for this scenario differs from the medium
forecast design (Figure 2-3)in that there are no series capacitors
2589B
3-1
TABLE 3-1
NEW CAPACITY ADDITIONS AND FUEL REQUIREMENTS
NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST
New Capacity (MW)Gas Requi red!/
Year (Increment/Total)(MMsCFY)
1990 0/0 0
1991 0/0 0
1992 0/0 0
1993 0/0 0
1994 0/0 0
1995 0/0 0
1996 91/91 6,596.6
1997 91/182 13,149.1
1998 0/182 13,149.1
1999 0/182 13,149.1
2000 0/182 13,182.1
2001 0/182 13,149.1
2002 91/273 19,723.7
2003 91/364 26,287.3
2004 0/364'26,364.2
2005 182/546 39,216.5
2006 0/546 39,436.4
2007 0/546 39,436.4
2008 91/637 44,284.9
2009 0/637 45,736.1
2010 91/728 47,187.4
11 Values as calculated are shown for reproducibility only,and do not
imply accuracy beyond the 100 MMSCFY level.
2589B
3-2
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installed and the facility is smaller in size.The circuit diagram is
shown in Figure 3-1.Only four 13.8/138 kV generator transformers are
needed,and each transmission line circuit is supplied by only one 750
MVA 138/500 kV transformer.The initial installation is essentially
the same as in Figure 2-4 except that the series capacitors are not
required.
Personnel required for operation and maintenance will be less for this
scenario than for the medium load forecast.Ten on-duty personnel will
be required in 1996 for the first unit.This number will increase to
approximately 35 on-duty personnel when 8 units are operating in 2010.
The total two-shift,full year,work force would therefore range from
40 to 140 for the study period.
3.2 TRANSMISSION SYSTEM
The North Slope to Fairbanks,and the Fairbanks to Anchorage
transmission systems for the low load forecast scenario do not differ
significantly from the medium forecast designs.A voltage of 500 kV is
cost effective for the line between the North Slope and Fairbanks;
however,for this case,series capacitors will not be needed.For the
Fairbanks-Anchorage section,two 345 kV lines with series compensation
are sufficient.That is,one new 345 kV line will be constructed and
the Healy-Fairbanks and the Willow-Anchorage segments of the existing.
intertie will be upgraded from 138 kV to 345 kV.
The number and sizes of the intermediate switching stations remain
unchanged.There are two such stations on the 500 kV line (without any
series capacitors),at Galbraith Lake and at Prospect Camp.There is
only one switching station on the 345 kV line from Fairbanks to
Anchorage,but in this case it has to be at the midpoint of the line,
i.e.,some 30 miles north of the Devil's Canyon switchyard of the
medium forecast sc·enario.
The substation at Fairbanks and Anchorage are slightly scaled down from
those described in Section 2.3 and Figures 2-5 and 2-6.
2589B
3-3
250 MVA
TYPICAL
500kV
13.8kV
22 22 22 22
750MVA
TYPICAL
ZOO MVAR TYPICAL
1---'\"''''-.-III
TO FAIRBANKS
LEGENDoGENERAToR
=ORtw'I"TRANSFORMER
o CIRCUIT BREA!<ER
....IV\I\r-REACTOR
;k CAPACITOR
TO FAH?BANKS
ALASKA POWER AUTHORITY
NORTH ILOPE GAS
FEASIBILITY InlOY
NORTH IlOPE POWER GENERATION
lOW lOAD FORECAST
SUBSTATION ONE LINE SCHEMATIC
'ICIUflE a -1
.IAICO IERVICES ICOAPORATED
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3.3 COST ESTIMATES
3.3.1 Construction Costs
The capital cost of e~ch simple cycle gas turbine is the same as that
presented in Section 2.3 for the medium load forecast.
The feasibility study investment costs of the transmission line systems
are presented in Table 3-2 and 3-3.Table 3-2 presents the estimates
for two 500 kV,700 MW capacity lines without series compensation,and
two intermediate switching stations.Table 3-3 contains the estimates
for one new 345 kV line,700 MW capacity,with series compensation and
an intermediate switching station,and the required upgrading of the
Willow-Anchorage and Healy-Fairbanks transmission lines.
3.3.2 Operati~n and Maintenance Costs
Power plant operati on and maintenance (O&M)costs are the same for both
the medium and low load forecasts,6.3 mils/kWh.Transmission line O&M
costs are estimated to be $30 million per year.These costs should be
viewed as an annual average over the life of the system.Actual O&M
costs should be less initially and will increase with time.
3.3.3 Fuel Costs
For the economic analyses which follow fuel costs were treated as
zero.This approach permits fuel cost and fuel price escalation to be
treated separately;and makes possible sUbsequent sensitivity analyses
of the Present Worth of Costs for this scenario based upon a range of
fuel cost and cost escalation assumptions.
3.3.4 Total Systems Costs
The total sy~tem for the North Slope low load forecast,like the North
Slope medium growth forecast,consists only of simple cycle combustion
turbines and a transmission line system.
2589B
3-5
Construction Labor 2/
($1000)
Materi a1
($1000)
TABLE 3-2
FEASIBILITY LEVEL INVESTMENT COSTS
NORTH SLOPE TO FAIRBANKS TRANSMISSION SYSTEM
NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST
(January,1982 Dollars.)
Descri pti on.!!
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19,253 39,693
28,694 64,212
12,000 24,900
873,012 1,695,224
149,760 213,452
85,200 85,200
$1 ,167,919 $2,122,681
36,000
148,600
$2,307,281
20,440
35,518
12,900
822,212
63,962
$954,762
TOTAL CONSTRUCTION COST
Clearing
2589B
3-6
SUBTOTAL
Land and Land Right~
Engineering and Construction
Management
Conductors and Devices
Switching Stations
Substations
11 The investment costs reflect two 500 kV lines,700 MW capacity without
series compensation and two intermediate switching stations.A
15 percent contingency has been assumed for the entire project and has
been distributed among each of the cost categories shown.Sales/use
taxes have not been included.
2/Construction camp facilities and services are subsumed in the
Constructi on Labor cost category.
l!Assumes a cost of $40,000 per mile (Acres American Inc.1981).
Energy Management System
Steel Towers and Fixtures
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!!The investment costs reflect one new 345 kV line,700 MW capacity
without series compensation and an intermediate SWitching station,and
upgrading of the Willow-Anchorage and Healy-Fairbanks segments of the
Intertie to 345 kV.
2/Assumes a cost of $40,000 per mile (Acres American Inc.1981).
Switching Station 8,857 8,414 17 ,271
SUbstation and Switching 32,958 30,872 63,830
Station
Energy Management Systems 12,300 10,960 23,260
Steel Towers and Fixtures 129,214 182,083
311 ,291
Conductors and Devices 20,049 53,183 73,232
Clearing 41,572 41 ,572
SUBTOTAL $203,378 $327,084 $530,456
Land and Land Right~14,400
Engineering and Construction 37,130
Management
TOTAL CONSTRUCTION COST $581 ,986
Total
Di rect Cost
($1000)
Constructi on 2/
Material Labor
($1000)($1000)
3-7
TABLE 3-3
FEASIBILITY LEVEL INVESTMENT COSTS
FAIRBANKS TO ANCHORAGE TRANSMISSION SYSTEM
NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST
(January,1982 Dollars)
2589B
Description!!
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The methodology and assumptions utilized to derive the systems·costs
which are presented below have been previously described in the Report
on Systems Planning Studies (Appendix B).This methodology is
consistent with previous studies of electric generating scenarios for
the Rai1be1t,specifically the Acres American,Inc.(1981),Susitna
.Hydroe1ectric Project Feasibility Report ~nd Battelle (1982),Rai1be1t
Electric Power Alternatives Study.The period of the analysis was
assumed to be 1982 through 2010.
The annual capital expenditures are presented in Table 3-4.Annual
non-fuel O&M costs are presented in Table 3-5.The summary of all
annual costs in presented in Table 3-6.The 1982 present worth of
costs for this scenario (in 1982 dollars)is $2.7 billion,exclusive of
fuel costs.
3.4 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS
The power plant for the low load forecast will consist of 8 simple
cycle units,in contrast to 15 units for the medium load forecast.
Most environmental impacts will therefore be correspondingly smaller
than the medium load forecast.Environment related power plant
characteristics are summarized in Table 3-7.
Air emissions will be approximately one-half the medium,growth value
and will not pose constraining air quality problems.Approximately 25
gpm of fresh water will be pumped from a nearby lake to provide
equipment wash-down and potable water supplies.Wastewater discharges
will be less than 25 gpm and will be discharged to the existing
facilities in the area.
Aquatic resources,as for the medium load forecast,will not be
significantly affected.Plant acreage,i nc1 udi ng the constructi on camp
and switchyard,will be approximately 65 acres,as compared to 95 acres
for the medium load forecast.Terrestrial impacts,such as tundra
disturbance and habitat elimination,are correspondingly less.
2589B
3-8
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TABLE 3-4
TOTAL ANNUAL CAPITAL EXPENDITURES
NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST
(Millions of January,1982 Do11ars)1/
Calendar E1ectricitY'Generate~Transmission
Year Unl t A Unit B Line Total
1982 O.O.O.O.
1983 O.O.O.O.
1984 O.O.O.O.
1985 O.O.O.O.
1986 O.O.O.O.
1987 O.O.O.O.
1988 O.O.O.O.
1989 O.O.O.O.
1990 O.O.O.O.
1991 O.O.O.O.
1992 O.O.1,540.1 1,540.1
1993 O.O.358.0 358.0
1994 19.oi~./O.704.6 723.7
1995 53.56 O.286.4 340.0
1996 53.56 O.O.53.6
1997 O.O.O.o.
1998 O.O.O.O.
1999 O.O.O.O.
2000 O.o.o.O.
2001 53.56 O.O.53.6
2002 53.56 O.O.53.6
2003 o.o.o.o.
2004 53.56 53.56 O.107.1
2005 O.O.O.o.
2006 O.O.O.O.
2007 53.56 O.O.53.6
2008 O.O.O.O.
2009 53.56 O.O.53.6
201 0 O.O.O.O.
TOTAL $394 .•$54.$2,889.$3,337.
1/Values as calculated are shown for purposes of reproducibility
only,and should not be taken to imply the indicated accuracy of
significant figures.
2/Unit A refers to the first unit built in a given year and Unit 8
to the second unit built.
3/Construction of camp site and site preparation for all units.
·25898
TABLE 3-5
TOTAL ANNUAL NONFUEL OPERATION AND MAINTENANCE COSTS
NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST
(Millions of January,1982 Dollars))-
Cal endar El ectri ci ty Transmi ssi on
Year Generated Line Total
1982 O.O.O.
1983 O.O.O.
1984 O.O.O.
1985 O.O.O.
1986 O.O.O.
1987 O.O.O.
1988 O.O.O.
1989 O.O.O.
1990 O.O.O.
1991 O.O.O.
1992 O.O.O.
"1993 o.O.O.
1994 O.O.O.
1995 o.o.o.
1996 3.8 30.0 33.8
1997 7.5 30.0 37.5
1998 7.5 30.0 37.5
1999 7.5 30.0 37.5
2000 7.5 30.0 37.5
2001 7.5 30.0 37.5
2002 11.3 30.0 41.3
2003 15.1 30.0 45.1
2004 15.1 30.0 45.1
2005 22.6 30.0 52.6
2006 22.6 30.0 52.6
2007 22.6 30.0 52.6
2008 25.4 30.0 55.4
2009 26.2 30.0 56.2
201 0 27.0 30.0 57.0
TOTAL $229.$450.$679.
2589B
3-10
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TABLE 3-6
TOTAL ANNUAL COSTS
NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST
(Millions of January,1982 Dollars))
Calendar Capital o &M Total
Year Expenditures Costs Expenditures
1982 O.O.O.
1983 O.O.O.
1984 O.O.O.
1985 O.O.O.
1986 O.O.O.
1987 O.O.o.
1988 O.O.O.
1989 O.O.O.
1990 O.o.O.
1991 O.O.O.
1992 1,540.1 O.1,540.1
1993 358.0 O.358.0
1994 723.7 O.723.7
1995 340.0 O.340.0
1996 53.6 33.8 87.4
1997 O.37.5 37.5
1998 O.37.5 37.5
1999 O.37.5 37.5
2000 O.37.5 37.5
2001 53.6 37.5 91.1
2002 53.6 41.3 94.9
2003 O.45.1 45.1
2004 107.1 45.1 152.2
2005 O.52.6 52.6
2006 O.52.6 52.6
2007 53.6 52.6 106.2
2008 O.55.4 55.4
2009 53.6 56.2 109.8
201 0 O.57.0 57.0
Total $3,337.$679.$4,016.
Present
Worth @ 3%$2,345.$360.$2,.705.
2589B
3-11
TABLE 3-7
ENVIRONMENT RELATED POWER PLANT CHARACTERISTICS
NORTH SLOPE POWER GENERATION -LOW LOAD FORECAST
Ai r Envi ronment
Emissions
Particulate Matter
Su1 fur Di ox i de
Nitrogen Oxides
Physical Effects
Water Environment
Plant Water Requirements
Plant Discharge.Quantity
Including Sanitary Waste
and Floor Drains
La nd En vi ro nme nt
Land Requirements
Plant and Switchyard
Construction Camp
Socioeconomic Environment
Construction Workforce
Operating Workforce
2589B
Below standards
Be low standa rds
Emissions variable within standards -
dry control techniques would be used
to meet calculated NO~standard of
0.014 percent of total volume of
gaseous emissions.This value
calculated based upon new source
performance standards,facility heat
rate,and unit size •
.Maximum structure height of 50 feet
25 GPM
Less than 25 GPM
60 acres
5 acres
Approximately 115 personnel at peak
construction
Approximately 140 personnel
3-12
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Impacts associated with the transmission line from the North Slope to
Fairbanks are identical to those discussed for the medium load forecast
(Section 2.4).From Fairbanks to Anchorage only one line in addition
to the Intertie will be necessary,in contrast to two new lines for the
medium load forecast.Cleared acreage within the right-of-way will be
approximately 5200 acres,as compared to 8700 acres for the medium load
forecast.Impacts associated with vegetative clearing,including
erosion,sedimentation,and habitat disturbance,are correspondingly
less than those discussed in Section 2.4.
Construction of the project according to the low demand forecast would
result in a smaller work force than under the medium demand forecast as
well as a shorter work schedule.The construction work force is
forecasted to be 115 employees,or a 40 percent reduction over the 200
employees forecasted for the medium growth scenario.The operations
work force is predicted to be 140 persons,Which is 70 percent of the
work force requirements of the medium growth forecast.
Operation of the first generation unit would begin in 1996 compared to
1993 under the medium growth forecast.For five months of each of
seven years during the period 1996-2010 a prefabricated unit of the
plant would be assembled.During off-work periods,the majority of the
employees would spend time outside of the North Slope Borough.The
spending wages earned by the employees within the borough is expected
to be minimal due to the "transience of the workforce.
Despite the differences in work force reqUirements and schedule between
the low and medium growth forecasts,the socioeconomic impacts would be
expected to be similar.The relatively low level of impact can be
attributed to the location of the generating plant within the Prudhoe
Bay/Deadhorse industrial complex,which is isolated from communities.
The work force requirements and schedule for construction of the
transmission.lines is almost identical to that of the medium forecast
scenario,and,therefore,socioeconomic impacts will be essentially the
same as those discussed in Section 2.4.
2589B
3-13
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SCENARIO 1/. ....
FA!RBANKS POWER GENERATION
MEDIUM LOAD
4.0 FAIRBANKS POWER GENERATION
MEDIUM LOAD FORECAST
Fairbanks power generation,under the medium load forecast,re~uires a
gas conditioning plant on the North Slope,a medium diameter pip"e1ine
to the Fairbanks area,an electric generating station at the pipeline
terminus,and electrical transmission capacity between FairbankS and
Anchorage.The North Slope gas conditioning plant will remove carbon
dioxide (12%by volume of the raw gas)and natural gas liquids.
Initial and final peak delivery volumes are anticipated to be 230
MMSCFD and 407 MMSCFD,respectively,using a 22 inch diameter pipeline
operating at 1260 pounds per square inch of"pressure.The pipeline
will be buried.Initially,three gas compressor stations along the
pipeline route will be required,increasing to 10 by the year 2010.
The electric generating station necessary to produce almost 1400 MW of
capacity in 2010 will consist of 5 combined cycle units,each
consisting of two gas fired co~ustion turbines paired with two waste
heat recovery boilers and one steam turbine generator,and 2 simple
cycle gas turbines,which can be paired with waste heat recovery
boilers to form a sixth combined cycle unit after 2010.Transmission
lines to carry the power to·the load center in Anchorage will require
two additional (total of 3)345 kV lines from Fairbanks to Anchorage.
This scenario also includes the construction of a natural gas
distribution system in Fairbanks to serve residential and commercial
space and water heating needs.Forecasting a fuel demand which
replaces existing fuels is speculative,but highest demand (inclUding
growth)is based on 100 percent penetration of the potential market.
In Fairbanks,in 2010,this is estimated to be as much as 63 MMSCFD.
2648B
4-1
Costs for shared facilities have been apportioned between the electric
generating facility and the residential/commercial gas distribution
system.Given this apportionment,construction of the gas conditioning
facilities,gas pipeline,power generating facilities and transmission
systems,is estimated to cost $6.5 billion.Total annual operation and
.maintenance costs are estimated to be $0.8 billion.The present worth
of these costs excluding fuel costs is $5.4 billion.Construction costs
for the Fairbanks gas distribution system serving residential/commercial
markets total $1.2 billion,with total annual operation and maintenance
costs totalling $86 million.The present worth of costs for this system
consisting of a portion of the pipeline and gas conditioning facilities,
plus the distribution network itself,is $0.9 billion.
4.1 NORTH SLOPE TO FAIRBANKS NATURAL GAS PIPELINE
The design of the gas pipeline and the gas conditioning facilities
proceeded on the basis of preliminary gas demand calculations (detailed
in Appendix A).SUbsequent refinement of total peak demand for the
Fairbanks scenario based on domestic gas distribution and electric usage
(detailed in Appendix E and Appendix B,respectively)did not require
design changes in the pipeline but resulted in small differences in gas
demands in the sections that follow.The pipeline gas demands are as
foll ows:
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2648B
Pipe1 ine Design
(Preliminary Demand)
Power Generation
Annual Average Demand
Daily Peak D~mand
Residential/Commercial
Annual Average Demand
Daily Peak Demand
Totals
Annual Average Demand
Daily Peak Demand
4-2
Medium Load Forecast
(MMSCFD)
186
307
27
76
213
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The refined values on which the Fairbanks gas distribution system and
the electric generating un1t additions depend are as follows:
Utility Systems Design
(Re fi ned Demand)
Power Generation
Peak Daily Demand
Residential/Commercial
Peak Daily Demand
Totals
Peak Daily Demand
Medium Load Forecast
(MMSCFD)
271
63
334
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The refined gas demand is about 50 MMSCFD less than the preliminary
value,an amount insufficient to necessitate pipeline design changes.
4.1.1 Gas Conditioning Plant
Gas to be transmitted through the pipeline will first be conditioned on
the North Slope.The conditioning facility will receive the gas from
the production fields,treat it,and compress it to 1260 psig and a
temperature of 25 to 30°F.Initial design delivery volume \,ill be 230
MMSCFD;however,the plant will be capable of expansion to 407 MMSCFD
as future demand increases.These values are based on total Fairbanks
gas demand,compressor station requirements and a pipeline availability
of 96.5 percent.The gas delivery and quality specifications are
presented in Table 4-1.
The process assumed for carbon dioxide removal is Allied Chemical's
SELEXOL physical solvent process,the same process sel~cted for use
with ANGTS.A mechanical refrigeration process will control
hydrocarbon de~point.Water dewpoint control will be accomplished in
the dehydration equipment located in the eXisting Prudhoe Bay Unit
gas/crude oil separation sites called Gathering Centers and Flow
Stati ons.The hydrogen sul fi de content of the feed gas is very -10\'{.
It was therefore assumed that no process equipment will be required for
either water"dewpoint control or hydrogen sulfide removal.
2648B
4-3
TABLE 4-1
GAS DELIVERY AND QUALITY SPECIFICATIONS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
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2.0 volume %
1.0 grain/100 SCF
-10°F @ 1000 psia
-25°F @ 1000 psia
1260 psig
25-30°F
230 MMSCFD
407 fvMSCFD
Speci fi cati onsParameter
Initial Delivery Volume
Ultimate Delivery Volume
ijydrogen Sulfide Content (max.)
Hydrocarbon Dewpoint (max.)
Water Dewpoint (max.)
Delivery Pressure
Delivery Temperature
Carbon Dioxide Content (max.)
26488
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A simplified process flow diagram illustrates the basic process flow of
the conditioning facilities (Figure 4-1).Two trains will be
installed,one for continuous operation and the other as a spare.Feed
gas,originating from the gas/crude separators,will be compressed in
the Gdthering Centers and Flow Stations and flow to the inlet
separation unit.The inlet gas streams will be met~red,and any s01ids
or free liquids in the gas will be removed at this point.The feed gas
will flow first to the natural gas liquids (NGL)extraction section for
hYdrocarbon dewpoint control.The gas will then flow to the SELEXOL
section where the carbon dioxide is removed.The conditioned gas will
then go to the gas compressors where it will be boosted to pipeline
pressure,then refrigerated for transmission.SELEXOL solvent
characteristically absorbs,along with the carbon dioxide,a
significant quantity of hydrocarbons,particularly the heavier
hydrocarbons.During the regeneration of the SELEXOL solvent,both the
carbon dioxide and hydrocarbons are flashed from the solvent,producing
a low Btu gas.The gas will be utilized within the facility to offset
some of the energy requirements.
The hydrocarbon liquids from the NGL Extraction and SELEXOL flash gas
will be separated in the fractionation unit into propane,butanes,and
pentanes-plus products to facilitate disposal.Some propane will be
used for heating value control of certain fuel streams.The remaining
propane will be injected"into the pipeline gas.The butanes will be
eitner rnjected into the pipeline gas up to hYdrocarbon dewpoint limits
or into the crude oil delivered to the Trans Alaskan Pipeline System
(TAPS)as is presently accomplished at the existing central compression
facility for gas reinjection.The pentanes-plus will be injected into
the same crude oil stream.
The facilities will require approximately 175,000 total installed
horsepower including motors,power recovery units and gas turbines.
The bulk of this horsepower will be developed by 9 operating gas
turbines with 6 spare gas turbines.The major auxiliary systems will
include refrigeration,offsite and general utilities,and power
generation facilities.
2648B
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NORTH SLOPE GAS
FEASIBILITY STUDY
GAS CONDITIONING FACILITY
'IQUIlE 4-1
EBASCO 8ERVICES INCORPORATED
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The remoteness and severe environmental conditions at the North Slope
impose limitations on both the process and mechanical design of the
facilities.All equipment will therefore be housed in totally enclosed
modules. Modules,with contained equipment,will be fabricated prior
to shipment to the North Slope.They will De sea-lifted to the North
Slope by ocean-going barges.At Prudhoe Bay they will be offloaded by
crawler transporters or rUbber-tired vehicles and moved to their pile
supports on graveled sites.
A critical timing factor in any construction program at Prudhoe Bay is
the limited time period during which the sea lanes are passable.Major
plant components can only be delivered via ocean-going barges during
the short (4-6 weeks)period each year when the sea lanes are not
blocked by ice.Failure to deliver any critical major component during
the stheduled period could effectively delay full-capacity startup by
•••0"•
one fUll year.
4.1.2 Pipeline
4.1.2.1 Pipeline and Route
Gas to be transported will be provided to the pipeline from the gas
conditioning plant.Pipeline q~ality gas will be a hydrocarbon mixture
with approximately 88 percent m~thane,and a gross higher heating value
of approximately 1100 Btu/SCF.The pipeline will be designed and
operated to maintain the soil around the buried sections of the
pipeline in a frozen state.The operating temperature of the gas in the
pipeline will be between O°F and 32°F under normal conditions.
However,during transient periods,the gas in the line may exceed 32°F
or may go down to as low as _5°F for short periods of time.
The proposed p.ipeline route originates in the Prudhoe Bay area in
northern Alaska (refer to Appendix C).The pipeline will connect to .
the gas condJtioning plant at the metering station,designated
Milepost O.The pipeline route,which assumes the ANGTS right-of-way,
2648B
4-7
follows TAPS in a southerly direction to about Milepost 274 near
Prospect Creek.The pipeline route then follows TAPS in a
southeasterly direction to about Milepost 480,the assumed location of
the power plant metering station.A tap will be pr.ovided at Milepost
455 near Fox to supply gas to Fairbanks for residential and commercial
uses.
The pipeline will cross 15 major streams requlrlng special construction
considerations,such as heavy wall pipe,continuous concrete coating or
set-on concrete weights.At the Yukon River an existing aerial
crossing will be used.
There will be 20 uncased road crossings,27 road crossings with 28 inch
casings,and 8 road crossings with 36 inch casings.The pipeline will
cross TAPS at 21 locations,the TAPS fuel gas line at 1~locations,and
other pipelines at 3 locations.
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4.1.2.2 P.ipe1ine Design
The basic assumption that this pipeline will follow the ANGTS
right-of-way is a major one.Pipeline design and sUbsequently cost
could be greatly affected if this right-of-way could not be used.
Significant areas of concern would include the narrow Atigun Pass area
and the Yukon River crossing.
The pipeline design pressure will be 1260 psig,based on current proven
technology for resistance to crack propagation at low temperatures.
The pipeline has been designed for the daily peak flow required to
satisfy the gas demand associated with the medium forecast assuming a
pipeline availability of 96.5 percent.The following f10wrates were
used for the hydraulic design of the pipeline:
26488
Annual Average Flow (MMSCFD)
Daily Peak Flow (MMSCFD)
4-8
213/0.965 =220
383/0.965 =397
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Initial annual average daily capacity of the pipeline will be
127 MMSCFD with a peak daily load of 227 MMSCFD during extreme cold
weather periods.
The peak daily f10wrate will require a pipeline outside diameter of 22
inches.The pipe shall be API 5LX or API 5LS Grade X70 with a minimum
wall thickness of 0.275 inches for the majority of the length.At road
crossings,bridges,and within pUblic road right-of-ways,the minimum
wall thickness will be 0.330 inches.These thicknesses are based on
the entire pipeline being located in a Class 1 location as defined in
CFR 49,Part 192.
The peak daily f10wrate requires 10 compressor stations of
approximately 3400 HP each.The average daily f10wrate will require
the operation of only 3 compressor stations,Stations 2,4 and 7.The
compressor stations are at the locations selected by ANGTS and use the
same numbering system.The delivery pressure to the power plant will
be 1038 psig.Figure 4-2 summarizes this f10wrate condition.
Compressor station fuel consumption will be approximately 1 MMSCFD per
operating station.
A total of 28 mainline block valve assemblies will be provided at a
nominal spacing of 20 miles including the initial compressor sites..
where the mainline valves will be installed in the station bypa~s
loop.Seven of the 28 block valves will be installed at the additional
station sites to facilitate system expansion.Pig launchers and
receivers will be installed at the compressor and metering stations.
The pipe will be installed in a buried mode,using the proposed ANGTS
construction techniques.Pipe ditches will be selected from several
basic types,based on site-specific conditions.Special ditch
configurations will be required to provide for the mitigation of frost
heave e!!ects in areas having frost-susceptible soils.
2648B
4-9
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TOTAL "'0 MILES.22"0.0.PIPELINE •.WALL THICKNESS •Q215 INCH MINIMUM
STATION DESIGNATION .....c.•.I C••.I C.L'C.1.4 C.,••C.,••C•••,C.,••C.,••C.,.to '.....
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MILEPOST (MILES)D.O 4+.5''a'O.1 , \3.7 141.3 17'.1 2:~S:O 273.'J 320.7 3lrO.,....32..1 41rO.O
ELEVATION (FEET)21 3"Z.82.S'I S"'Z 5'305'0 3/S"'8 12.20 131 S'17:30 'i1''IlO /5'20 S'ao•3"M 31"8~STATION INLET VOLUME (MMSCf ID)407 407 .....0'"4Q5'404-403 402-401 400 3 c'nr..
;!TOTAL fUEL (M..SCFID)-1 ,1 I I I I ,,,-..
STATION OUTLET VOLUME (MMSCf/D)407 406 405"404-403 402..401 ....00 3er"'l 3CJW 3""7 31"8
ITATION SUCTION PRESSUR£('''0)/2.'-0 10-+7 /0(,.3 1057 1031 /0'3 "24 /0,S-103er 1021 '71 '038
STATION DISCHARGE PR£SSURE (PSIG)12'"0 1245 124S 1'2.4S 1'2.30 12.30 /2bO 12(;.0 1230 1230 ".,.~-
•COMPRESSOR SUCTION PRESSURE(PSIG)10'3'/047 /041 lOIS 1047 1I0'i!l 107'1023 1012...,S5 -0.-COMPRESSOR DISCHARGE PHESSUM (PSIG)125'12~/2.5'11:44-/2.44 1274 1'2.74 1244 /24...115'-..-...-=COMPR£SSIOH RATIO I.::20'/.II'1./48 I./711 1.2/3 1.22''.2/0 -..-I.2./.,1.200 1.2.22:I
0
HOftSEPOWI:,."(QUlftED 215"0 3200 3250 3"'00 -u -3400 315'0 3200 3400 2"00 '2..300
ALASKA POWER AUTHORITY
NORTH SLOPE GAS
FEASIBILITY 8TUDY
HYDRAULIC sur1~1ARY
t1EDIUt1 FORECAST
PEAK DAILY FLOW
FIGURE 4-2
EBASCO SERVICES INCORPORATED
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Pipeline corrosion control will be provided by a combination of
external coating and a cathodic protection system that will be
compatible with the sacrificial zinc anode system used on the adjacent
TAPS pipeline.The pipeline will be hydrostatically tested to 1.25
times the maximum allowable operating pressure.
4.1.3 Compressor and Metering Stations
Two metering stations will be provided.One will measure the quantity
of gas supplied to the pipeline from the gas conditioning plant at the
North Slope,and the other will measure the gas delivered to the power
plant just south of Fairbanks.Details of the compressor and metering
stations design are provided in the Figures 4-3 and 4-4.
Each compressor station site will require about 10 acres,and the
metering stations about 1.5 acres of land.Compressor stations will
include buildings for the compressors,refrigeration equipment,
utilities and control room,flammable liquids storage,warm storage and
garage,a gas scrubber unit,living quarters and interconnecting
hallways.Additional living quarters,office,and shop and warehouse
building will be included at compressor stations 2 and 7.
Two refrigeration units will be provided at every compressor station to
maintain the pipeline gas temperature.Gas heaters will be Rrovided at
compressor stations 2 and 4 to assure that gas temperatures will be
maintained above the hydrocarbon dewpoint of the mixture under all
operating conditions.Pipeline gas will be used to power the drivers
for the gas compressors,refrigerant compressors and electric
generators.Compressor station and metering station design and
equipment are summarized in Tables 4-2 through 4-10.
4.1.4 Supervisory Control System
A supervisory control system will be provided to operate the pipeline
system,perform related system balancing,and coordinate functions with
the gas conditioning plant at the North Slope and the Fairbanks power
plant.
26488
4-11
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NORTH SLOPE GAS
FEASIBILITY STUDY
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TYPICAL COt1PRESSOR STATION LAYOUT
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FEASIBILITY STUDY
TYPICAL t1ETERING STATION LAYOUT
FIGURE 4-4
EBASCO SERVICES INCORPORATED
TABLE 4-2
COMPRESSOR STATION PIPE DETAILS
FAIRBANKS POWER GENERATION -MEDIUM LOAD·FORECAST
Major piping -1280 psig design pressure
a.22"0.0.x 0.406"wall API 5LX,GR.X70 pipe
b.18"0.0.x 0.750"wall ASlM A333,GR.6 pipe
c.16"O.D.x 0.656"wall ASlM A333,GR.6 pipe
d.12"XS ASlM A333,GR.6 pipe
e.10"XS ASlM A333,GR.6 pipe
f.8"STD.WT.ASlM A333,GR.6 pipe
NOTE:API 5LX piping to have additional specifications for
-50°F Charpy Impact requirements and chemical
requirements for improved we1dabi1ity.
2648B
4-14
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2648B
e.Amuient temperature range-70°F to +80°F
TABLE 4-3
CIVIL DESIGN DETAILS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
30 1 height
30 I-50 I hei ght
50 1 -100 1 height
100 I hei ght
d.Wind loads will be:30 psf
40 psf
50 psf
.60 psf
a.All buildings and heated components will be elevated on steel
pile foundations above a gravel pad to allow free air
circulation under the structures.The pile embedment will be
adequate to prevent frost jacking of the structures.
Non-heated facilities will be supported by a granular fill and
sand paa.
b.Snow loads will be 60 psf
c.Edrthquake design will be Zone 3
f.Structural steel -inside heated structures,will use normal
s~eel materials.OUtside heated structures,will use suitable
low temperature steels.
g.The diesel fuel storage tank will be placed over an impermeable
liner covering the entire diked area.
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BUILDING DETAILS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
a.All buildings will be pre-engineered insulated-panel metal
structures,suitable for their intended use.
b.Buildings suitable for truck transportation through size or
modu1arization will be prefabricated.
c.Hazardous materials storage buildings will be mechanically
ventilated.Ventilation rates will be four air changes per
hour for normal ventilation and 15 air changes per hour for
emergency conditions.
d.The sizes of buildings will be as follows:
Scrubber bldg.20'"x 40'X 24 1 eave height
Compressor b1 dg.30 1 X 40 1 X 20'eave height
Refrigeration bldg.60'x 60 1 X 30 1 eave height
Warm Storage bldg.40 1 x 80'x 20'eave height
Ut i1i ti es bldg.50 1 X 60'X 16 1 eave height
Living quarters (except C.S.2 &7)30 1 X 60'x 16'eave height
Flammable Liquids Bldg.15'x 20'x 10 1 eave height
Living quarters (C.S.2 &7)30 1 X 100'X 16 1 eave height
Office (C.S.2 &7)20'X 30'X 8 1 eave height
Shop and Warehouse (C.S.2 &7)70'x 70'X 20'eave height
Hallways 6 1 -8 1 wide x 10 1 eave height
Meter b1 dg.40'x 50'X 20 1 eave heigh.t
Generator b1 dg.10 1 X 15 1 X 10 1 eave height
Control b1 dg.10'x 15'x 10'eave height
2648B
4-16
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2648B
TABLE 4-5
COMPRESSOR AND GAS SCRUBBER DETAILS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
Main Compressors - 1 each per compressor station
a.Compressor -1280 psig min.design pressure
1.23 pressure ratio
6000 ft.adiabatic head
2750 ACFM
b.Gas Turbine Driver -3800 ISO Horsepower
gas fueled
c.Typical Equipment -Solar Centaur Gas Turbine
Natural Gas Compressor Set with a C-304 Single Stage
Compressor,or equal.
Gas Scrubber -(l )each per station
a.Designed to remove 99.5%of all solid and liquid particles
1 micron and larger.
b.Design flowrates will range from 130 to 400 MMSCFD.
c.Typical Equipment -Peco Robinson filter and liquid-gas
separator,Model 75H-56-FG372,or equal ..
4-17
TABLE 4-6
REFRIGERATION SYSTEM AND GAS HEATER DETAILS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
Refrigeration System
a.Refrigeration system will be a compression/expansion type using
Freon gas and a gas turbine driver for the refrigerant
compressors.
b.Chillers will be shell and tUbe with natural gas in the tubes
at 1280 psig and Freon in the shell.
c.Condensers will be air cooled with multiple electric driven
fans.
d.Required capacity will be 2200 HP.
e.The system will be comprised of two parallel 50%refrigeration
trains to meet the total requi red capaci ty.
f.Typical Equipment -Two (2)1100 HP refrigeration trains using
Solar Saturn Gas Turbine Compressor Sets,or equal.
Gas Heater -One (1)each at Compressor Stations 2 and 4 only
a.Designed to add 5,000,000 Btu/hr to heat the pipeline gas
during low flow winter conditions.
b.Equipment will be a gas fired heater and utilize a water/glycol
solution to heat the gas in a shell and tube heat exchanger.
2648B
4-18
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TABLE 4-7
COMPRESSOR STATION
ELECTRICAL SYSTEM AND CONTROL SYSTEM DETAILS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
Electrical System
a.Each station will be self-sufficient in electric power with
its own power generation and distribution system.
b.Power will be 480 V.,3 phase,60 Hz.
c.Main genera~ors will be two (2)800 KW continuous duty
dual-fueled gas turbine driven generator sets,one will
normally supply the station load and one will be standby.
d.Emergency (lifeline)generator will be one (1)200 KW diesel
engine driven generator connected to the essential services
bus.
e.The emergency generator will be located in the warm storage
bUilding or another location remote from the main generators
in the utilities building.
f.Typical Equipment:
r~in generators -Solar Saturn GSC-1200,or equivalent
Emergency generator -caterpiller 3406 TA,or equivalent
Control System
a.Each station will have a control system designed for
completely remote and unattended operation.
b.The station Central Control Unit '(CCU)will be linked by
communications to the Operations Control Center (OCC)~
c.Each individual piece of station equipment will have its
individual control system which in "turn will be controlled by
the CCU which is the master controller.
d.The OCC input to the CCU will primarily be start/stop commands
and setpoint changes.
e.The oec will have sufficient information transmitted to it to
allow for full compressor station control.
2648B
4-19
TABLE 4-8
MISCELLANEOUS COMPRESSOR STATION SYSTEMS·DETAILS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
a.Blowdown and Flare System will be sized for 100,000 lb/hr.of
saturated light hydrocarbon gases and liquid storage capacity
of 10,000 gallons.
b.Nitrogen Purge System -for purging.
c.Instrument and Utility Air System -Instrument air to be clean
and dry for operating pneumatic control system components.
Utility air for power tools and maintenanc~.
d.Fuel Gas Conditioning -Gas for station fuel requirements will
be filtered,heated,reduced in pressure,and distributed at
500 psig.
e.Diesel Fuel - A diesel fuel storage and back-up fuel system
will be provided for electric power generation and heating.
The tank size will be 40,000 gallons to provide 14 days of
capacity.
f.Fire Protection -Station fire protection will be provided by
a Halon 1301 extinguishing system with a water/foam back-up
system.
g.Water System - A single 40,000 gallon water tank will provide
a source of water for potable uses as well as for the back-Up
water/foam fire system.The fire pump will be diesel driven.
The potable water will be filtered,chlorinated,and
distributed.
h.Sewage System -Sewage will be collected by a vacuum
collection system.Final disposal will be through a septic
system or a lagoon as site conditions warrant.Lagoon
disposal will reqUire secondary treatment ana chlorination.
i.Heating System -The station will be heated by a water/glycol
system utilizing waste heat from the station turbine
generators.A combustion boiler unit will be provided as
back-up to the waste heat system.
j.Cathodic Protection - A cathodic protection system will be
provided to protect all buried piping,tank bottoms,ana other
structures in contact with the soil.The station will be
electrically insulated by isolation flanges where the pipeline
enters and leaves the compressor station property.
2648B
4-20
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METERS AND METERING STATION ELECTRICAL AND CONTROL SYSTEMS DETAILS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
Meters
a.Each metering station will have 3 parallel meters with
provisions for future addition of a fourth meter.
b.Meters will be concentric orifice plate with differential
pressure transmitters.
c.Meter runs will be 12 inch diameter by 3D'long.
Electrical System
a.Both metering stations will be powered by an outside
cornmercial power source.
b.A 50 kW diesel-powered back-up generator will automatically
come on line during a power failure.
Control System
a.Designed for remote and unattended operation.
b.Gas flow will be computed by a microprocessor-based flow
computer with 100%redundancy.
c.The flow computer will be linked to the acc by
telecommunications •
2648B
4-21
TABLE 4-10
MISCELLANEOUS METERING STATION SYSTEMS'DETAILS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
a.B10wdown drum and vent stack system..
b.Nitrogen purge system.
c.Diesel Fuel - A diesel fuel storage system will be provided for
electric power generation.
d.Fire Protection -Fire protection will be provided by a Halon
1301 extinguishing system with a water/foam back-up system.
e.Heating System -Heating and ventilating will be by means of
redundant gas-fired furnaces and warm air duct systems.
f.Cathooic Protection - A cathodic protection system will be
provided to protect all buried piping,tank bottoms,and other
structures in contact with the soil.The station will be
electrically isolated by isolation flanges where the pipeline
enters and leaves the compressor station property.
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2648B
4-22
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The supervisory control system master station will be located near the
Fairbanks power plant at the operations control center (OCC).A
communication system will provide the voice and data intertie to each
compressor and metering station from the OCC.Each station will include
a control system that will interface through the communication link to
the acC.
Tne DeC in Fairbanks will include the dispatcher console,which will
provide the monitoring and control equipment necessary for centralized
operation of the pipeline.
4.1.5 Communications System
The communications system will include voice and data transmission...
systems,the mobile radio system,and record communications.A basic
communication system will be installed during the construction phase to
provide voice and data links among the pipeline and compressor station
camps,and the Fairbanks construction headquarters.
MObile radio equipmen~will be provided to permit communication by field
construction teams through a network of repeater stations to the camps,
stations and other facilities.This basic communication system will
later be modified to provide the operational communications system.This
operational system will support the supervisory control system.Data
communications will also be provided.
4.1.6 Operation and Maintenance Facilities
Operation and maintenance (O&M)facilities will be located at three sites
along the pipeline:Compressor Stations 2 and 7,and the Fairbanks
operations headquarters.Each O&M facility will include the following:
(1)Warehouse for storing project spare parts inventory.
(2)Maintenance shop,including maintenance equipment.
(3)District office.
(4)Living quarters for the O&M personnel.
26488
4-23
The Fairbanks operations headquarters near the power plant will also
house the OCC,the related supervisory control equipment,required power
supplies and the communications system equipment.
Stations 2 and 7 will serve as shop and warehouse with both living
qtlarters and maintenance facH ities.The other stations will have ·small
1 iving quarters attached.It is anticipated that a staff of 5 to 6 will
serve at each compressor station except stations 2 and 7,wnich will have
a total of 16 each,including 6 maintenance personnel.This would then
require a total staff of 80 for the medium load forecast peak demand (10
stations)•
4.1.7 Construction and Site Support Services
Temporary f~cilities will include those facilities requ~red to support
the construction phase activities.These facilities will include the
Fairbanks construction headquarters,the pipeline and compressor station
construction camps,airfields,access roads,material (borrow)sites and
di sposal sites.
Thirteen pipeline construction camps will be provided along the route,
including one located at the Fairbanks construction headquarters site.
These camps will be capable of accommodating between 250 to 1,300
persons,depending on location and planned use.
The camps,once completed,will be turned over to contractors for
operation.The twelve camps along the pipeline will be renovated
generally in place using equipment and modules obtained mostly from the
existing TAPS camps.Three compressor station construction camps will be
provided by relocating and renovating equipment and modules available
from eight existing TAPS pump station camps.
Airfields will consist of certain existing commercial airfields,as well
as renovatea private airfields previously built in support of TAPS.
Material (borrow)sites are available along the pipeline route to provide
26488
4-24
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construction materials,as well as areas to dispose of construction
spoil.Maximum haul distances should be kept under 5 miles.
A pipe yard at Fairbanks will be provided to receive mainline pipe,
store,externally coat,double-joint (weld)and insulate pipe as
required.Access roads will be provided as needed to allow access to
stations,borrow sites,pipeline spreads and related facilities.
4.2 POWER PLANT
The Report on System Planning Studies (Appendix B)concluded that
combined cycle power plants are the most technically feasible and
economical choice for satifying demand when generating electrical power
at a Fairbanks site.The individual combined cycle plants will consist
of two gas turbines,each with a heat recovery steam generator and one
steam turbine for a total of three ~urbine-generator sets.
4.2.1 General
The Fairbanks site will contain all required generating units,
construction and maintenance facilities,various auxiliary and support
systems,a central control facility and switchyards.This power
generation scenario calls for five 242 MW combined cycle and two 86 MW
simple cycle units to satisfy the demand for energy in the year 2010.
The first unit,a simple cycle gas turbine,is required in 1993 and in
SUbsequent years either gas turbines or steam turbines are added.
Incremental and total required new generation capacity for this scenario
are summarized in Table 4-11.
A single combined cycle unit will require an area with outside dimensions
of 300 feet by 440 feet.The arrangement of the three turbine-generator
sets,the air cooled condenser and auxiliary equipment is shown in
Figures 4-5.and 4-6.The site plan shown in Figure 4-7 illustrates the
planned installation method (side by side)for up to six units with
switchyards.This arrangement will require a total area of approximately
150 acres.
26488
4-25
TABLE 4-11
NEW CAPACITY ADDITIONS AND FUEL REQUIREMENTS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
Ne\1 Capaci ty (MW)Gas Requi red!!
Year (Increment/Total)O+'SCF)
1990 0/0 O.
1991 0/0 O.
1992 0/0 O.
1993 86/86 6,265.8
1994 0/86 6,265.8
.1995 86/172 12,531.6
1996 70/242 12,633.1
1997 172/414 25,132.7 .
1998 70/484 25,202.9
1999 0/484 25,202.9
2000 86/570 31,551.3
2001 0/570 31,467.3
2002 156/726 37,804.3
2003 0/726 37,804.3
2004 86/812 44,188.1
2005 156/968 45,809.0'
2006 86/1050 49,535.1
2007 86/1140 53,145.7
2008 70/1210 52,292.0
2009 86/1296 55,892.6
201 0 86/1382 59,424.8
l!Values as calculated are shown for reproducibility only,and
do not imply accuracy beyona the 100 MMSCF level.
2648B
4-26
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NORTH SLOPE GAS·
FEASIBILITY STUDY
COMBINED CYCLE PLANT
SITE PLAN
FAIRBANKS AND KENAI
FIGURE 4-7
EBASCO SERVICES INCORPORATED
The functional parts of the plant will be similar to those described in
Section 2.0 for the gas turbine portion of the plant.The steam cycle
will requi re the addi tion of neat recovery steam generators,steam and
auxiliary system piping,a steam turbine generator,condenser,condensate
polishing,water qUdlity control systems,and an increase in the quantity
of water used.
4.2.2 Combustion Turbine Equipment
All combustion turbine equipment will be identical to that described in
Secti on 2.1.
4.2.3 Steam Plant
The heat recovery steam generators (HRSG)are considered part of the
steam plant although physically the steam generators will be housed
together with the gas turbines in a large common building.
Each heat recovery steam generator package,one at each gas turbine·
eXhaust,will include the steam generator complete with ductwork from the
combustion turbine to the steam generator,a uypass damper and bypass
stack,and a steam generator exhaust stack.The steam generators will
have a steam outlet pressure of 850 psig at 950°F.Each steam generator
is designed to produce one half of the plant's normal flow for steam when
supplied with feedwater at a temperature of 250°F.The heat recovery
steam generators are designed for continuous operation.All steam
generator controls will be located in a common area in the central
control room.
During start-up and other load conditions,the bypass damper may be
operated to provide operational flexibility.By opening the bypass
damper and closing the louvered dampers,the combustion turbine exhaust
is routed to the stdck dnd does not reach the steam generator.Design
parameters for the heat recovery steam generators are shown in Table
4-12.The flow diagram and anticipated heat balance for a single
combined cycle unit is presented in Figure 4-8.
26488
4-30
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Steam production under normal operation will be achieved with an
exhaust "gas flow through the boiler of 2,286,000 lbs/hr at 970 0 F.
Feedwater will be supplied to theHRSG at 250°F from the feedwater
heater.
Watertube,forced circulation
TABLE 4-12
HEAT RECOVERY STEAM GENERATOR DESIGN PARAMETERS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
(Two Required Per Unit)
850 psig,950°F
250,400 lbs/hr
(Each Steam Generator)
Main Steam
Outl et Condi ti on
Quantity
Type:
Performance:
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Heat Recovery Steam Generator Features
Feedwater Heater
Economizer
Evaporator Section with Steam Drum
Superheater Section-
Econoini zer
Evaporator Section with Steam Drum
Exhaust Gas Bypass Dampers with Separate Stack
2648B
4-31
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CONCIJOTUAL ONLY
NOT GUARANTEED
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NORTH SLOPE GAS
fUSIBILITY STUDY
COMBINED CYCLE PLANT
FLOW DIAGRAM AND
HEAT BALANCE
ALA8KA POWER AUTHORITY
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The generator is rated 72 MW.The unit auxiliary transformer is a
three winding 15 MYA,13.8/4.16/4.16 kY.The two secondary windings
supply 4.16 kV buses 3A and 3B.The step-up transformer is rated 50
MVA,18/138 kY.
The main steam produced in the heat recovery steam generators will be
conveyed to a common turbine generator set.The turbine generator will
be a tandem compound,multistage condensing unit,mounted on a pedestal
with a top exhaust going to the air cooled condenser.Design
parameters for the turbine generator are shown on Table 4-13.The
turbine generator set will be furnished complete with lUbricating oil
and e1ectrohydraulic control systems as well as the gland seal system,
and the generator cooling and sealing equipment.
In addition to the combustion generators,steam generators and steam
turbine,-the building will also contain the feedwater pumps,condensate
pumps,vacuum pumps,deaerator,instrument and service air compressors,
motor control centers,control room,and diesel generator (see Figure
4-5).The diesel generator will be sized for black start-up service.
Heat will be rejected from the steam turbine cycle at the outside
mounted air-cooled condenser where air flowing across cooling fins
absorbs heat from the exhaust system.The condensate from the
condenser will then flow to the condensate storage tank where it will
be pumped back into the cycle.
Fuel requirements for this scenario will start at approximately 6.27
BCFY in 1993,when the first gas turbine starts delivering power,and
increase to 59.43 BCFY in the year 2010.The maximum anticipated gas
consumption rate,in the year 2010,with 1382 MW of capacity in
operation,is 1.88 x 10 5 SCFM.Detailed annual gas use figures are
presented in Table 4-11.
2648B
4-33
TABLE 4-13
STEAM TURBINE GENERATOR UNIT DESIGN PARAMETERS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
(One Required Per Unit)
Turbi ne Type:Multistage,straight condensing,top exhaust
Hydrogen-cooled unit rated 72MW at 13.8 kV
with 30 psig hydrogen pressure at lOGe
Generator Type:
Performance:Base Rating
Steam Inlet Pressure
Steam Inlet Temperature
Exhaust Pressure
Exh~ust Temperature
Speed
72 MW
850 psig
950°F
211 to 4 11 Hg
108°F
3600 RPM
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Steam Turbine Generator
Features:
26488
Common base mounted with direct-drive
couplings.Accessories include multiple
inlet control valves,electric hydraulic
control system,lUbricating oil system with
all pumps and heat exchangers for cooling
water hook-up,gland steam system and
generator cooling.Excitation compartment
complete with static excitation equipment.
Swi tchgear compartment compl ete wi th
generator and breaker potential
transformers..
4-34
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4.2.4 Substation
The circuit diagram of the powerp1ant sUbstation is shown in
Figure 4-9.It is quite similar to the North Slope sUbstation
(Figure 2-3).Two generators will be connected to the two primary
windings of the 250 MVA 13.8/138 kV·transformers,and the last
generator to a 125 MVA two winding transformer.The bus arrangement
will use a breaker and a half scheme unless reliabi1 ity considerations
mandate otherwise.One 600 MVA 138/345 kV transformer will supply each
of the transmission line circuits.Each of the transmission lines will.
have a circuit breaker.On the line side of the circuit breakers are
the series capacitors and the shunt reactors.This arrangement has the
advantage of being flexible as far as operation is concerned and can be
expanded easi 1y.
4.2.5 Other Systems
In addition to the potable and service water system described in
Section 2.1,this plant will require make-up water for the steam
cycle.To purify the make-up water a demineralizing system will be
required.
B1owdown from the HRSGs and waste from the demineralizer and the
condensate polisher represent additional waste handling capacity
requirements over and above that previously discussed (Section 2.1).
These waste streams will require treatment,in accordance with
regulation,prior to discharge.
Other systems such as fire protection or lUbricating oil will not
change in scope or capacity to any significant degree from those
presented in Section 2.1.
2648B
4-35
22 St2 22 22 22 22 22 22
'HIlMI:4-.
2 110 MVA
IIASCO .ERVICES INCORPORATED
FAIRBANKS POWER GENERATION
MEDIUM LOAD FORECAST
SUBSTATION ONE LINE SCHEMATIC
ALASKA POWER AUTHORITY
NORTH 'LOPE GAS
FEASIBILITY ,TUDY
LOCAL
.345 kV
~II
LOCAL
TO ANCHORAGE
220 MVA
TYPICAL
600 MVA
TYPICAL
75 MVAR 1TYPICAL
III--'W\r-
LEGENDoGENERATOR
=ORI'tn"TRANSFORMER
o C.IRCUIT BREAKER
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4.2.6 Construction and Site Support Services
The construction of this power plant in the Fairbanks area will require
the following services:
(l)Access Roads
(2)Construction Water Supply
(3)Construction Power Supply
All new roads will be of similar design to existing public roads in the
Rai1belt.The roads will be paved,and will meet all code design
requirements for the maximum loads expected.
A complete water supply similar to that described in Section 2.1 will be
provided,except the source of water will be wells.The construction
power supply will be a 12.47 kV line run from existing facilities.
Since a permanent construction force will be utilized through the period
of the study,it is assumed that the local area can supply living
accommodations for the work force.The number of workers necessary for
construction of the power station will vary over the total period of the
project from a low of 50 to a high of approximately 200.Construction
facilities required are:utility services;temporary construction office;
temporary and permanent access roa~s;temporary en~l~sed and open laydown
storage facilities;temporary office and shop spaces for various
sUbcontractors;sett1 i ng basins to collect constructi on area storm
runoff;and permanent perimeter fencing and security facilities.
4.2.7 Operation and Maintenance
Pl ant Life
Each unit will have a 30 year life expectancy,which is based on the life
of the gas turbine units.It is expected that the gas turbine units will
be overhauled a number of times throughout the 1ife of the units during
scheduled or unscheduled outages.
26488
4-37
Heat Rate of Units
The facility's heat rate will vary,depending on the number of gas
turbines and heat recovery units operating at a given time.Ideally,
with only combined cycle units in operation,a heat rate of 8290
Btu/kWh (HHV,ambient conditions)can be realized.
Scheduled and Forced Outage Rate
It is expected that the forced outage rate will be about 8 percent.
Operational experience on other plants indicates higher forced outages
in the first few years,but this is attributed to operational
adJustments required for a new plant.It is expected that a slight
increase in forced outages will Dccur as the plant ages.Scheduled
outages for annual maintenance and periodic overhaul are expected to be
approximately 5 percent.
Operating Workforce
The combined cycle power plant will require a con.tinuously increasing
staff over the s~udy period.The staff will start at approximately 10
on-duty personnel when the first gas turbine begins operation and will
increase to approximately 80 on-duty personnel in ~he year 2010.
4.2.8 Site Opportunities and Constraints
Fairbanks represents the nearest location to which North Slope gas can
be transported to and have the resulting generation of electrical
energy be fed directly into an exis~ing portion of the Railbelt
electric transmission network.Transportation of heavy equipment to
the site do~s not represent technical problems;however,the location
will require expensive overland transport from the port facilities at
Anchorage.
2648B
4-38
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4.3 TRANSMISSION SYSTEM
The power to be transmitted from Fairbanks to Anchorage equals the power
generated less the Fairbanks area load.This amount is the same as the
North Slope generation scenario,except for the line losses between the
North Slope and Fairbanks,which are not significant when compared to the
power generated.Therefore,the conditions for the Fairbanks to
Anchorage transmission line are almost exactly identical for both cases
and consist of two new 345 kV lines,and an upgrade of the
Wi 11 ow-Anchorage and Healy-Fa i rbanks segments of the Interti e from 138 kV
to 345 kV (Refer to Section 2.2).
4.4 FAIRBANKS GAS DISTRIBUTION SYSTEM
4.4.1 Fairbanks Residential/Commercial Gas Demand Forecasts
The following paragraphs are a summary of the study performed by Alaska
Economics Incorporated to forecast residential and commercial gas demand
in Fairbanks.The text of this report appears in Appendix E.
The potential residential and cOl1lllercial demand for natural gas in the
Fairbanks area is dependent on the price competitiveness of natural gas
with respect to No.2 distillate fuel.oil and propane in heating and
."water heating markets,and its price competitiveness with propane and.
electricity in cooking applications.The potential demand of natural gas
as a cooking fuel is estimated to be less than 5.0 percent of the total
potential demand for natural gas even if the gas were to fully displace
bottled propane in commercial cooking applications.
The forecasts of potential gas demand have been made conditional on the
gas achieving discrete percentages of the total market for heating and
cooking energy flO percent,25 percent,40 percent,and 100 percent
displacement of fuel oil and propane.in heating and of propane in
cooking).The size of the total market to which these percentages have
been applied "has,in turn,been projected to grow at a 1.43 percent
annual average rate from 1981 for the low growth forecast,and at a 2.30
26488
4-39
percent annual average rate for the medium growth forecast.These growth
rates are the rates of Fairbanks population growth implied,respectively,
by Battell e IS (1982)low forecast of the demand for e1 ectricity in the
Rai1be1t area,and Acres American1s (1981)medium forecast of Rai1be1t
electricity demand.
The prices at which residential and commercial users would have a minimum
financial incentive to convert from fuel oil to natural gas for heating
purposes have been derived.These "consumer breakeven ll prices are based
upon the assumption that the maximum discounted payback period for
consumers is 5 years.At the 1982 price of No.2 distillate,$1.22 per
gallon,the calculated consumer break even prices are $9.58 per MCF for
residential heating and $9.94 per MCF for commercial heating.These
prices will rise annually at approximately the real (inflation free)rate
of increase ~f fossil fuel prices in general.If this rate is the 2.0
percent real rate assumed by Battelle (1982)and Acres (1981),by the
year 2010 the breakeven prices in (1982 dollars)will have reached $16.68
per MCF (residential)and $17.31 per MCF (commercial).
The presence of calculated breakeven prices is necessary for the
forecasting of natural gas demand.However,break even price data and
price elasticity data are insufficient for such a forecast in this case.
These price and e1 astici ty data are insuffici ent because the situati on
involves a new product (natural gas)competing with an existing product
(e.g.,distillate oil,propane).Additional factors influence consumer
demand inc1uding:.(1)consumer perceptions of the two products;
(2)consumer inertia;(3)initial and/or unusual incentives offered by
suppliers of the competing fuels based upon their calculated present
worth of achieving certain market shares;and (4)other less defined
factors.Because of these unquantified factors,conditional demand
estimates have been forecast;and these are based upon price analysis
alone.
If natural gas is priced below the consumer breakeven level,users will
have an increased financial incentive to shift from fuel oil.For every
10¢by which the price of gas falls below the breakeven level,
2648B
4-40
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residential users will realize approximately $81.00 (1982 dollars)in
additional savings over the estimated cost of conversion.It might be
expected that extensive inroads against fuel oil will begin to be made if
gas is priced sufficiently below breakeven so as to cover conversion
costs and to achieve a significant level of savings (measured as the
excess of the present value of annual cash savings over conversion costs).
It must be recognized that the producers and suppliers of fuel oil are
likely to respond to the intrusion of natural gas by either lowering the
price of No.2 distillate or by offering other incentives.While the
intensity of reaction by oil suppliers cannot be forecast,it can be
assumed that suppliers are capable of at least offsetting the price
advantage that natural gas has traditionally enjoyed based on its
reputation as a "c1ean"fuel.Theref~re,the above calculation of
consumer breakeven prices correctly ignores the fact.thqt many consumers
might be willing to pay a premium for such natural gas properties.
DELIVERED GAS,BCF PER YEAR
1985 2010
The conditioned demand projections derived are presented in detail in
Appendix E and are summarized below for the medium growth projection.L
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MARKET GROWTH @ 2.30 PERCENT
10%of Market
25%of Market
40%of Market
100%of Market
0.527
1 .319
2.110
5.274
0.931
2.328
3.726
9.314
These values represent the annual demand for delivered gas conditional
upon the pertentage of market penetration indicated,where the total
market,defined in terms oT effective MMBtu'~/is set equal to 100
!!Effective MMBtu's (million Btu's)are delivered MMBtu's adjusted
for the fuel burning efficiency of heating ·units and cooking
units.For example,if oil burners are 65 percent efficient,one
delivered MMBtu equals 0.65 effective MMBtus.
2648B
4-41
percent of cOlllJ1ercial and residential heating energy requirements plus
29 percent of residential cooking energy requirements.The delivered
gas demand values were calculated based upon different thermal
efficiencies for oil and gas fired units.
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·The demand for gas would not be constantly distributed throughout the
year.Based on an appraisal of normal monthly heating degree days in
Fairbanks,and an assumed indoor temperature setting of 6So Fahrenheit,
approximately 16.6 percent of annual Fairbanks heating energy is
consumed in January,the peak month for demand.1/Although cooking
energy requirements may be more evenly spread across the year,the
relatively small size of cooking demand,less than 5.0 percent of the
total,suggests rather strongly that an apportionment of total demand
dccording to the conductive heat transfer formula will yield a good
estimate of peak monthly dem~nd.Use of this method implies the
foll owi ng peak monthly demand (January)for natural gas in Fai rbanks
for the medium growth projection.
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2648B
4-42
DELIVERED GAS,BCF PER PEAK MONTH
January January
1985 2010
1/Heat loss is proportional to the indoor-outdoor temperature
differential and inversely proportional to the insulation factor.
At an indoor temperature setting of 6So Fahrenheit,relative monthly
heating degree days is the appropridte measure of relative monthly
heat loss.
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0.155
0.386
0.619
1.546
0.087
0.219
0.350
0.875
10%of Market
25%of Market
40%of Market
100%of r~d rke t
MARKET GROWTH @ 2.30 PERCENT
Peak daily demand during the month of January can reasonably be
estimated as 0.0322 (1/31)of the monthly demand times a factor that
allows for extremes of cold.Between 1961 and 1982,the highest number
of January heating degree days recorded in Fairbanks was 3002 (in
January 1971).The January average was 2384.The ratio of the two
DELIVERED GAS,BCF,PEAK DAILY
January January
1985 2010
Peak hourly demand,defined as 0.0417 (1/24)times peak daily demand is
quite small.For example,in the maximal case of 2.30 percent growth
and 100 percent market penetration,the peak hourly demand is only
0.0026 BCF,or 2,600 MCF.
(l.26)when mu1ti·p1ied by 0.0322 yields an appropriate measure of peak
daily demand when their product is in turn multiplied by peak monthly
demand.Thus,peak daily demand equals 0.0406 times peak monthly
demand.The daily peaks are given in the following table for the
medium growth projection:
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MARKET GROWTH @ 2.30 PERCENT
10%of Market
25%of Market
40%of Market
100%of Market
0.004
0.009
0.014
0.036
0.006
0.016
0.025
0.063
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Finally,expansion of the Fairbanks steam district heating system could
reduce the demand for natural gas below the estimates presented above.
On the assumption that the district heating system supplies only
commercial and government users,the implied reduction is at most 15.0
percent of the estimates given above,since commercial use of gas is
projected to be at most 15.0 percent of total demand.
4.4.2 Fairbanks Gas Distribution System
The Fairbanks natural gas transmission and distribution system will be
designed in conformance with Part 5,Alaska Public Utilities
Commission,Chapter 48,Practice and Procedures;Federal Safety
Standards for Transportation of Natural Gas and Other Gas by Pipeline,
49 CFR Part 192,Latest Revision;and the American National Standard
Code for Gas Transmission and Distribution Piping ·Sys.tems,B 31.8,
Latest Edition.
2648B
4-43
The overall system network will consist of a transmission lateral from
a metering station near Fox to a City Gate Station with a minimum inlet
pressure to the gate station of 250 psig,a 125 psig high pressure
system to distribute gas to district regulators,and a 60 psig maximum
distribution system to carry gas to individual customer services.
Generally,the rural facilities will be considered in Location ~ass 3,
and those in the urban areas in Location Class 4.
4.4.2.1 Gas Transmission Line
The gas transmission line will connect to the 22-inch pipeline near Fox
(Figure 4-10).The line will b~in public right-of-way,adjacent to
the traveled roadway.The line will follow the Steese Highway to the
intersection of Farmers Loop Road to the City Gate Station.This is
approximately 12 miles of transmission line.
As load develops north of the Chena Hot Spring Road along the Steese
Hi ghway and McGrath Road,a secondary tap and gate stati on mi ght be
considered at the intersection of Chena Hot Spring Road and the Steese
Highway for service to this northern load,and as a back feed to the
McGrath and Farmers Loop Road facilities.
.The transmission line will operate at the main pipeline pressure of
approxilllately 1,000 psig at the take-off point and have a design
pressure of 1,260 psig.The gas flow will be metered at the take-off
poi nt.
The transmission line has been designed to provide peak hour coverage
for commercial and residential customers in the year 2010.At this
point,depending on actual growth and the location of additional supply
sources,the transmission line may have to be supplemented.The 2010
peak hour projections were used to detennine the range of transmission
line sizes required.
26488
4-44
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NOTES.
I HIGH PAESSunE DIS1RlDlHION FROM CHY OAT(STATION At 125 "SIO
2 LOW PRESSURE DIS1RIJunON FROM LOAD CENTER AT 60 PSKJ
3 LOAD Cf.NT£RS 0.@.ANO@ FOR fUTURE U~E
ALASKA POWER AUTHORITY
NORTH ILOPE GAS
FEASIBILITY STUDY
CITY OF FAIRBANKS
GAS DISTRIBUTION
"0""(4-10
(BASCO SERVICES M:~ATED
4.4.2.2 City Gate Station
The City Gate Station will be designed for an incoming gas pressure of
1,260 psig.TIle normal incoming operating pressure.could drop as low
as 250 psig during the medium forecast peak daily flowrates.The
outlet pressure Will be 125 psig.Gas heating equipment may be
required to prevent the gas temperature from dropping below _20 0 F.
The vicinity of the intersection of Farmers Loop Road and the old
Steese Highway appears to be a suitable location for the City Gate
Station.No specific inquiries were made as to availability and cost
of vacant land in the area.The station will be above ground and can
be accommodated on an average city lot.
United States Geological Survey (USGS)maps indicate that this is a
pennafrost area.One test bore in the immediate area indicates that
permafrost begins at a depth of 19 feet.Further analysis will have to
D~made to determine soil and founuation conuitions before any land
commitments are made.
Gas metering,conditioning,pressure reduction and flow control are the
basic functions that will take place at the gate station.It is
anticipated that the meter runs,control valves,odorization equipment
and instrumentation devices will be indoors.A single story concrete
block or insulated corrugated metal building approximately 20'x 50·
would fulfill the requirement.
Gas purity is a major concern to distribution companies and
specifications are incorporated into gas purchase contracts.The North
Slope gas conditioning facility,however,will produce a pipeline gas
that meets typical specifications for domestic and commercial natural
gas.It is therefore assumed that the only gas processing required at
the gate station will be particulate and liquids removal carried over
from the North Slope to Fairbanks pipeline after primary processing has
been accomplished.
2648B
4-46
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Suspended solids and liquids will be removed prior to pressure
reduction by means of a conventional scrubber,and liquid resulting
from the condensation phenomena accompanying pressure reduction will be
removed by liquid knockout drip pots.
A gas odorization system will be part of the gate station facilities.
The system will be designed to maintain a relatively constant rate of
odorizdtion with varying gas volumes.A liquid injection system based
upon gas volume measurement is anticipated.The odorization rate will
be in th~range of 0.25 to 1.00 pounds odorant per million cUbic feet
of gas.
Pressure reduction from 1,000 psig inlet pressure to 125 psig station
outlet pressure will be accomplished at the gate station.Conventional
pressure reducing valve(s)with pilots and bypasses will be used.The
outlet of the gate station (inlet to high pressure system)will also be
provided with overpressure protection.An atmospheric relief sized to
relieve at the maximum allowable operating pressure plus 10 percent or
series monitor regulation will be considered.
Metering and gas flow control will take place at parallel meter runs.
Station flow will be remotely controlled by the gas dispatcher from the
headquarters office.Remote control telemetering will allow the
station to be normally unmanned.
4.4.2.3 High Pressure System
Tne high pressure system will operate at an inlet pressure of 125 psig
from the City Gate Station.It is expected to traverse public
rights-of-way adjacent to traveled roads as shown on the conceptual
grid map (Figure 4-10).Laterals will branch off to load centers where
pressure reduction and overpressure protection will be provided at
~istrict regulating stations.From these regulator stations,gas will
be distributed to the individual 60 psig networks.
26488
4-47
HIGH PRESSURE SYSTEM MAINS .
Individual high pressure mains are sized based upon peak hour load
center estimates using the Spitzg1ass high pressure formula.The sizes
and footages of the high pressure mains based upon the preliminary
network analysis are listed below.The high pressure system will be
standard wall API 5L GR.8 steel pipe as required..
Size
8"
10"
12"
14"
18"
4.4.2.4 District Regulators
Length -Feet
6,000
15,000
27,375
7,500
District regulator stations will be 1pcated at the inlet to 60 psig
distrioution networks as shown on Figure 4-10.These fifteen (15)
stations will be designed to reduce the inlet pressure to 60 psig,and
to provide overpressure protection for the distribution system.The
method of overpressure protection (e.g.,atmospheric relief,monitor
regulators,etc.)will be determined during final design.
The type of construction and location of district regulator stations
will also be determined during final design.The options of
underground vault versus aboveground station construction must be
reviewed with respect to considerations of the availability of public
right-of-way,private easement,soil and groundwater characteristics,
equipment operating capabilities and safety.
4.4.2.5 Distribution Systems
The distribution systems as shown on Figure 4-10 will deliver maximum
60 psig and minimum 15 psig gas to individual customer services.The
lines will be polyethylene pi'pe,PE 3408 per ASTM D 2513.The pipe
will be SDR 11 for Class 4 locations and SDR 13.5 for Class 3
26488
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locations.The smoother inside surface of plastic pipe allows the same
sizes as steel pipe to handle the higher f10wrates.Individual lines
will be sized using the Spitzg1ass formula.In general,distribution
lines will be 2"as standard.Larger size lines will be the
exception.Distribution lines will be valved to comply with code
requirements and good operating practices.
The distribution lines will be laid in pUblic rights-of-way at a depth
of three feet to the top of the main.The lines will be laid on the
opposite side of the road from existing or proposed water mains.The
estimated footages by size of distribution mains are tabulated below.
SCHEDULE OF DISTRIBUTION MAINS
4-49
2648B
Services will be sized to deliver gas for maximum estimated demand of
approximately 225 cubic feet per hour (CF/HR).
Residential temperature compensated meters sized for this demand load
must also satisfy the following specifications:
Length -Feet
450,000
78,000
87,000
2,250
1,500
-0.5"Water Column (W.C.)
-30°F
-7"w.c.
-_70 0 F
.2"
4"
6"
8"
12"
Size
Maximum pressure drop
Gas temperature
In 1et pressu re
Ambient air temperature
Residential regulators sized to deliver the demand load at an inlet
pressure range 15 to 60 psig and an outlet pressure of 6"to ]"W.C.
will be specified for residential customers as standard.
4.4.2.6 Residential Services
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Residential services will be standardized as welded and wrapped steel.
The meter and regulator will,when desirable,be in the basement.The
service will have a curb cock where the meter and regulator is indoors.
If a service meter/regulator set cannot be placed indoors,consideration
will ~e given to enclosing them in a metal or wooden,insulated and
heated enclosure.In this case,a curb cock may not be required.The
service head will be designed to allow for flexibility of movement due to
frost heave and settlement.
Services will be sized for a 1.5 to 3 psig maximum allowable pressure
drop for inlet pressures of.15 psig minimum to 60 psig maximum.
Assuming an average service length of 100 feet (allowing for equivalent
length for fittings),and a 15 psig inlet pressure and a maximum 1..5 psig
pressure drop,a 1/211 steel service has the capacity of 395 CF/HR at a
specific gravity of 0.65 and a temperature of 30°F.This is in excess
of the 225 CF/HR estimated maximum residential demand,and the allowable
pressure drop is not exceeded.Therefore,a system standard of 1/2"
service size will be used for the average residential customer.
4.4.2.7 Commercial/Industrial Services
Commercial/industrial services will be designed and constructed following
the same general procedures as for residential services.However,no
attempt is made to standardize on size.Rather,each service will be
sizea to meet its special load requirements.In addition,it is highly
possible that some commercial/industrial customers may be better served
from a 125 psig main.In these cases,the requirement of dual regulation
or other secondary overpressure protection will be provided in the
service design.
4.4.2.8 Headquarters Building
The headquarters building will contain office space for the gas dispatch
and operati~g personnel.It will also include telemetry for controlling
2648B
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gas flow at the City Gas Station.Building size will be approximately
25 1 x 50'single story,constructed of concrete block or insulated
corrugated metal suitable for climatic conditions in Fairbanks,Alaska.
4.4.2.9 Cold Temperature Design and Environmental Factors
The Fairbanks gas distribution facilities will be designed to meet or
exceed the most stringent applicable minimum construction and safety
standards.However,there are technical considerations which are not now
specifically covered by code which must be investigated in great detail
and solutions developed prior to final site selection ana completion of
detailed design.In addition,there are environmental considerations
which must be investigated and addressed more fully during the design
phase of the project.Among these are:
1.Permafrost and Frost Heave
2.Field (hydrostatic)Testing
3.Cold Temperature Operation of System Components
4.River and Stream Crossings
5.Ice Fog
Permafrost and Frost Heave
United States Geological Survey data for the area of the gas distribution
system has been reviewed.This review indicates that the distribution
system will traverse three generalized units of subsurface conditions.
These are the Tanana-Chena River Flood Plain,the Upland Hills,and the
Creek Valley Bottom formations.
The Tanana-Chena River Flood Plain consists of alternating layers of
alluvial silt,sand and gravel.The top silt layers ranges from 1 to 15
feet thick.Permafrost is discontinuous and randomly located and.ranges
in depth to the top from 2 to 4 feet in older parts of the flood plain,
and to 25 to·40 feet in cleared areas.Where frozen,silt has a low to
modera~ice content in the form of thin seams.The silt will develop
2648B
4-51
some subsidence when thawed,and may undergo intense seasonal frost
heave.The portion of the distribution system lIin town ll is generally in
the flood plain formation.
Adjacent to the flood plain are gently rolling bedrock hills covered by
from 3 to 200 feet of windblown silt (loess).The Upland Hills are
generally free of permafrost although perennially frozen silt does occur
along the base of most hills.Portions of the transmission lateral along
the Steese Highway traverse this formation,as do portions of the
distribution system along Farmers Loop Road.
The valley bottoms of the upland contain silt accumulations that are
perennially frozen and have high ice content.The depth to permafrost is
from 1-1/2 to 3 feet on lower slopes and valley bottoms,from 5 to 20
feet near contact with the unfrozen silt zone,and from 10 to 25 feet in
cleared areas.
The seasonal frost layer is from 1-1/2 to 3 feet thick.Seasonal frost
action is intense,and there is great subsidence when permafrost thaws.
Sections of the transmission lateral along the Steese Highway as well as
part of the distributi on system along Farmers Loop Road cross thi s
formation.In addition,the proposed location of the City Gate Station
is within the limits of the Creek Valley Bottom formation.
The relation made between the distribution system and area geology above
is based upon subsurface formation areas generally described on USGS
Quadrangle Maps.Local variations may occur,particularly near the
interface between formations.Therefore,a detailed analysis of soil
conditions along the proposed right-of-way will be necessary to determine
where and to what extent frost susceptible soil and/or permafrost exist.
Final facilities location and design must be based upon flowing gas
temperatures within the system and subsurface soil survey and analysis.
Systems operating temperatures,at one extreme,may cause thermal
degradation of permafrost,and at the other extreme frost heave may be
26488
4-52
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the problem.In either case,specialized design may be necessary to
assure that the integrity of the system and/or the environment are not
jeopa rdi zed.
Field (HYdrostatic)Testing
The detailed design phase of the project will result in final
determination of the pipe specifications for the project.These will be
based upon the balance of service performance expectations and the
economics of purchase and installation.At that time,the final code and
permit requirements with respect to testing will be more exactly known.
HYdrostatic testing will require that procedures and specifications
address testing at ambient air temperatures below 32 0 F.,and dewatering
ana IIdrying li of pipe lines after testing.In addition,cold temperature
testing will require a review of brittle fracture mechanics for the
specifiea pipe material.
As generally designed now,the 60 psig distribution system would be
pneumatically tested to 100 psig.The 125 psig high pressure system
would be hydrostatically tested to 175 psig.The transmission lateral
would be tested hydrostatically to 1.4 times the maximum operating
pressure.
System Component Operation
The effects of subarctic temperatures and the temperature of flowing gas
will require particular attention and perhaps specialized design to
assure long,·trouble free operation of the system.Among the areas where
special effort may be required are:
Gas Meters:Diaphragm materials with acceptable lower operating
temperature limit to _70 0 F.must be provided.
Potential condensate problems must be analyzed.
Shut Off Valve:LUbricant freeze up potentidls must be investigated.
Valve box and operating nut accessibility in frozen
snow and ice must be reviewed.
2648B
4-53
Regulators:
Pipe Material:Effects of stress at cold temperature must be
considered.Stresses resulting from cold temperature
must be considered in design.
Effects of cold temperature and condensate freeze up
on diaphragm and valve discs must"be studied.
River and Stream Crossings
The conceptual system layout indicates that there are nine river and
creek pipeline crossings.They are:
Jesse1a Creek at Farmers Loop Road;
Isabella Creek at Farmers Loop Road;
Pearl Creek at Farmers Loop Road;
Chena River at N.Hall Street;
Noyes Slough at Illinois Street;
Noyes Slough at Alder Avenue;
Deadman Slough at Geist Road;
Deadman Slough at Loftus Road,and
Deadman Slough at Fairbanks Street.
It is anticipated that the major crossings can be made using existing
bridges.These will require close interface with highway officials and
engineers.Specialized design for support,thermal movement,
installation procedures,and protective coating may.be necessary.
Those crossings for which a bridge crossing is not possible will require
that stream flows,bed movement and scour,and potential fishery impacts
be analyzed,and that appropriate design and construction procedures be
developed accordingly.
keF~
Ice fog is a serious and complex problem which is still being studied.
Many solutions have been suggested to reduce the occurrence of ice fog.
The principal focus has been on reducing water vapor emissions from the
generation of heat and power.It is understood that as the quantity of
water vapor released to this atmosphere is reduced,the temperature at
which ice fog forms will decrease away from zero,thus decreasing the
frequency of occurrence.Any design of a gas distribution system in
26488
4-54
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Fairbanks must include appropriat~measures to reduce water vapor
released to the atmosphere.
4.5 COST ESTIMATES
4.5.1 Capital Costs
4.5.1.1 North Slope to Fairbanks Natural Gas Pipeline
Feasibility level investment cost estimates have been prepared for the
systems and facilities which comprise the North Slope to Fairbanks
natural gas pipeline.Thes~estimates are presented in Table 4-14.
4.5.1.2 Power Plant
To support the derivation of total systems costs which are presented in
Section 4.5.4,feasioility level investment costs were developed for the
major bid lin~s items cornmon to a 77 MW (ISO conditions)natural gas
fireu simple cycle combustion turbine and d 220 MW (ISO conditions)
natural gas fired combined cycle plant.These costs are presented in
Tables 4-15 and 4-16.Tne costs represent the total investm~nt for the
first unit to be developed at the site.Additional simple cycle units
will have an estimated investment cost of $33,900,000 while additional
combined cycle units will have an estimated investment cost of
$127,430,000.The cost differential for additional units is due to
significant reductions in line items 1 and 15,improvements to Site and
Off-Site Facilities,and reductions in Indirect Construction Cost and
Engineering and Construction Management.
4.5.1.3 Transmission Line Systems
Transmission line feasibility level investment cost estimates for the
Fairbanks to Anchorage connection are presented in Table 4-17.These
estimates are based on two new 345 kV lines,in parallel,1400 MW
capacity,with series compensation and an intermediate switching
26488
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TABLE 4-14
FEASIBILITY LEVEL INVESTMENT COSTS
NORTH SLOPE TO FAIRBANKS NATURAL GAS PIPELINE
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
(January,1982 Dollars)
Oesc ri pti onl./
Material s Cons~ructi on Total Oi rect
($1000)LaborJ ($1000)Cost ($1000)
22 in 0.0.Gas Pipeline 480,000 4,100,000 4,580,000
Compressor Stations -10 ea 96,800 83,400 180,200
Metering Stations -2 ea 2,800 6,000 8,800
Valve Stations -28 ea 2,500 3,800 6,300
Eng i neeri ng &Construction 286,500
Management
SUBTOTAL $582,100 $4,193,200 $5,061,800
Gas Conditioning Faci1 ity 3/780,000
TOTAL CONSTRUCTION COST $5,841,800
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has been di stributed among each of the cost categori es shown.r
Sales/use taxes and land and land rights expenses have not been LJ
incl uded.
?:./Construction camp facilities and services are sUbsummed in the C
Constructi on Labor cost category.
3/Factored pricing basis which includes engineering and construction [
management costs.
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TABLE 4-15
FEASIBILITY LEVEL INVESTMENT COSTS
77 MW SIMPLE CYCLE COMBUSTION TURBINE
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
(January,1982 Do 11 ars)
Construct;on Total
Descri pti onl/
Materials Labor Di rect Cost
($1000)($1000)($lOOO)
1.Improvements to Site 405 1,240 1,645
2.Earthwork and Piling 195 345 540
3.Circulating Water System 0 0 0
4.Concrete 475 2,145 2,620
5.Structural Steel Lifting 1,725 1,370 3,095
Equipment,Stacks
6.Buildings 750 1,440 2,190
7.Turbine Generator 11,100 650 11,750
8.Steam Generator and Accessories 0 0 0
9.Other Mechanical Equipment 460 235 695
10.Pi pi ng 205 510 715
11.Insulation and Lagging 30 110 140
12.Instrumentation 100 70 170
13.Electrical Equipment 1,510 2,590 4,100
14.Painting,70 250 320
15.Off-Site Facilities 300 1,080 1,380
SUBTOTAL $17,325 $12,035 $29,360
"Freight Increment 865
TOTAL DIRECT CONSTRUCTION COST $30,225
Indirect Construction Costs 1,665
SUBTOTAL FOR CONTINGENCIES 31,890
Contingencies (l5%)4,790
TOTAL SPECIFIC CONSTRUCTION COST 36,680
Engineering and Construction 2,200
Management
TOTAL CONSTRUCTION COST $38,880
1/The following items are not addressed in the plant investment pricing:
laboratory equipment,switchyard and transmission facilities,spare
parts,1and or 1and ri ghts,and sales/use taxes.
2648B
4-57
TABLE 4-]6
FEASIBILITY LEVEL INVESTMENT COSTS
220 MW COMBINED CYCLE PLANT
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
(January,1982 Dollars)0
Total
Constructi on Direct
Descri pti orJ/
Materi a1 labor Cost
($1000)($1000 )($1000 )
1.Improvements to Site 425 1,295 1,720
2.Earthwork and Piling 570 1,050 1,620
3.Ci rcul ati ng Watet·System 0 0 0
4.Concrete 1,485 6,730 8,215
5.Structural Steel lifting 3,800 3,530 7,330
Equipment,Stacks ,
6.Buildings 1,800 3,600 5,400
7.Turbi ne Generator 30,100 2;520 32,620
8.Steam Generator and Accessories 9,600 4,320 13,920
9.Other Mechanical Equipment 6,735 3,425 10,160
10.Pi pi ng 1,500 2,910 4,410
11.Insulation and lagging 290 690 980
12.Instrumentati on 1,700 290 1,990
13.E1 ectrica1 Equi pment 4,550 8,640 13,190
14.Painting 200 720 920
15.Off-Site Facilities 300 1,080 1,380
SUBTOTAL $63,055 $40,800 $103,855
Freight Increment 3,155
TOTAL DIRECT CONSTRUCTION COST $107,010
Indirect Construction Costs 4,235
SUBTOTAL FOR CONTINGENCIES 111 ,245
Contingencies (15%)16,685
TOTAL SPECIFIC CONSTRUCTION COST 127,930
Engin~ering and Construction 6,800
ptanagement
TOTAL CONSTRUCTION COST $134,730
11 Tne following items are not addressed in the piant investment pricing:
laboratory equipment,switchyard and transmission facilities,spare
parts,land or land rights,and sales/use taxes.
2648B
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4-59
2/Assumes a cost of $40,000 per mile (Acres American Inc.1981).
26,557
104,024
23,260
521,580
112,039
83,144
$870,604
27,600
60,950
$959,154
Total'
Di rect Cost
($1000)
12,445
41 ,716
10,960
305,085
78,361
83,144
$531,711
Cons tructi on
Labor ($1000)
Material
(S1000)
14,112
62,308
12,300
216,495
33,678
$388,893
TABLE 4-17
FEASIBILITY LEVEL INVESTMENT COSTS
FAIRBANKS TO ANCHORAGE TRANSMISSION SYSTEM
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
(January,1982 Dollars)
Oescri ption.!!
Switching Stations
Substations
Energy Management Systems
Steel Towers and Fixtures
Conductors and Devices
Cl ear'i ng
SUBTOTAL
Land and Land Rights 2/
Engineering and Construction
•Management
TOTAL CONSTRUCTION COST
!I The investment costs reflect two new 345 kV lines,1400 MW capacity,with
series compensation and an intermediat~switching station and upgrading
of 'the Willow-Anchorage and',Healy-Fa irbanks segments of the exi sti ng gri d
to 345 kV..
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4.5.1.4 Gas Distribution System
station.The investment cost estimates also reflect upgrading from
138 kV to 345 kV of the Willow-Anchorage and Healy-Fairbanks segments
of the existing grid.
Feasibility level investment cost estimates (January,1982 dollars)
have been prepared for the systems and facilities which comprise the
Fairbanks gas distribution system.The results of the analyses are
given below.A 15 percent contingency has been assumed for the entire
project and has been distributed between each cost category.Sales/use
taxes and land rights have not been included.
$59,700$48,200
Construction Total Direct
Labor ($1000)·Cost ($1000)
Materi a1 s
($1000 )
$11 ,500GasDistributionSystem
4.5.2.1 Gas Pipeline and Conditioning Facility
..
Annual operation and maintenance costs (January,1982 dollars)for the·
gas conditioning facilities are estimated to be as follows:
Engineering and
Construction Management
TOTAL CONSTRUCTION COST
4.5.2 Operation and Maintenance Costs
ITEM
Salaries
Maintenance Costs (Parts and
Expendables)
TOTAL
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4-60
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$63,282
ANNUAL COSTS ($1000)
$2,480
3,750
$6,230
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Annual operation and maintenance costs (January,1982 dollars)for the
gas compressor stations and pipeline maintenance activities are
estimated to be as follows:
operation and maintenance costs for the combined cycle facility at
Fairbanks are estimated to be $0.0040/kWh.These are based on
discussions with operating plant personnel,history of similar units,
Electric Power Research Institute data,published data and other
studies performed.
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ITEM
Salaries
Maintenance Costs (Parts,
Expendables,Other)
4.5.2.2 Power Plant
Total
ANNUAL COSTS ($1000)
$4,400
5,850
$10,250
4.5.2.4 Gas Distribution System
4.5.2.3 Transmission Line Systems
Annual operation and maintenance costs (January 1982 dollars)for the
Fairbanks gas distribution system a~e estimated to be as follows:
Annual operation and maintenance costs (January 1982 dollars)have been
developed for the scenario's required transmission line facilities and
total $12 million per year.These costs should be viewed as an annual.
average over the life of the system.Actual OaM costs should be less
initially,and will increase with time.
ANNUAL COSTS ($1000)
$1,290
500
$1,790
4-~
Total
ITEM
Salaries
Maintenance Costs
(Parts,Consumables,Other)
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(1)
(2)
PE/(P E +PR)=01
01 (I GC +I p)=ESCC
Where
peak natural gas demand for electricity generation
peak natural gas demand for residential and commercial uses
the proportion of investment costs charged to electricity
generati on
IGC =capital investment in the conditioning plant
I Q =capital investment in the pipeline
EsCC =e1 ectricservice re1 ated capi tal charges
4.5.4 Total Systems Costs
4.5.4.1 Cost Allocation Methodology
Capital cost allocation is based upon the peak demand for natural gas,
and consequently the capacity requirements of the ~ine.In this
all oc ati on it is useful to make 'the c onservati ve assumpti on that both
peak loads may occur simultaneously.Given that assumption,the
following formulas can be used to allocate capital costs:
4.5.3 Fuel Costs
For purposes of total system cost comparisons,natural gas pipeline and
conditioning plant costs from the North Slope to Fairbanks must be
allocated between electricity generation applications and
residential/commercial customer applications.In this way the
non-electric system costs can be removed from the total cost comparison
associated with electricity supply.Two types of costs must be
allocated:(1)capital investment costs;and (2)annual costs,including
operation and maintenance (O&M)costs and fuel costs (e.g.,for pipeline
compressor stations).
For the economic analyses which foll ow fuel costs were treated as zero.
This approach permits fuel cost and fuel price escalation to be treated
separately;and makes possible sUbsequent sensitivity analyses of the
Present Worth of Costs for this scenario based upon a range of fuel cost
and cost escalation assumptions.
4-63
26488
Annual costs are allocated on an energy basis rather than on a capacity
basis.Those costs are allocated by the following formula:
Again,disaggregation may be accomplished for 0cVt1 or fuel costs;and
this is accomplished by multiplying the 0A term by either SC OcVt1 or
SC F•Again,only shared costs are considered,and user community-
specific costs are not consi dered.
(3)
(4)
(5)
total shared annual charges
shared O&M costs
shared fuel costs
annual natural gas consumpti on for el ectrici ty generati on
annual natural gas consumption by residential and
c onrnerc ia1 users
the proportion of annual costs charged to electricity
generation
electrical service related annual costs
SCA =SC OcVt1 +SC F
ECE/(EC E T EC R)=0A
0A x SCA =ESAC
ESAC =
°=A
Where:
SCA =
SC OcVt1 =
SC F =
EC E =
EC R =
Given these formulae,costs may be disaggregated.Costs may be
al1oc.ated to residential and commercial users by substituting (1-01)
for 01 and (l-OA)for 0A.Precise comparison of the electrical
generation options can now be accomplished.
The second formula arrives at the specific dollar value for allocation
purposes.It can be applied either to I GC or I p separately when
capital costs must be disaggregated by component,or as shown for the
total capital burden.Neither formula is applied to investments that
are specific to one user community (e.g.the residential gas
distribution system),as those investment costs must be borne totally
by the appropriate users.
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4.5.4.2 Power Generation System Costs
The Fairbanks medium load growth scenario is far more complex than the
Prudhoe Bay medium load growth scenario in that it,inc1udes:(1)d
gas conditioning facility,(2)a natural gas pipeline,(3)power
generation faci1iti~s,and (4)transmission line facilities.
Further,the conditioning plant and pipeline facilities serve both
electricity and residential/commercial markets.As a consequence,the
capital,operating and maintenance,and fuel costs associated with the
conditioning facility and pipeline must be apportioned to the
respective user communities.
The method for apportionment has been previously described (see Section
4.5.4.1)'On thi s basi s 01 and 0A val ues are cal cu1 ated (0 refers
to the fraction of costs apportioned to the electricity segment of the
natural gas market).0 1,the capital cost apportionment term,is
calculated as follows for the medium load forecast:
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2648B
0A'the annual costs apportionment term,varies over time for the
medium load forecast.Values for 0A are presented in Table 4-18.
Gi ven the apporti onment tenns,the annual systems costs for the
electricity generation system can be presented.The annual capital
expenditures are shown in Table 4-19.The annual non-fuel O&M costs
are shown in Table 4-20.The summary of total systems costs is
presented in Table 4-21.The perlod of the analysis was assumed to be
1982 through 201 O.
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63 MMSCFD
271 MMSCFD
334 MMSCFD
0.82=
Total Peak Dai 1y F10\'I =
Electricity Generation =
Peak Daily Flow (2010)
Residential/Co~aercia1 =
Peak Da ily Flow (201 0)
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TABLE 4-18
o VALUEsl/A
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
Resi denti al El ectri cal Total
Calendar Demand .Demand Demand
Year (BCFY)(BCFY)(BCFY)°A
1982 O.o.O.NA~/
1983 O.O.O.NA
1984 O.O.O.NA
1985 O.O.O.NA
1986 O.o.O.NA
1987 O.O.O.NA
1988 O.O.O.NA
1989 O.O.O.NA
1990 O.O.O.NA
1991 O.O.O.NA
1992 O.O.O.NA
1993 1.219 6.266 7.485 0.84
1994 2.494 6.266 8.760 0.72
1995 3.827 12.532 16.359 0.77
1996 5.220 12.633 17.853 0.71
1997 6.676 25.133 31.809 0.79
1998 6.829 25.203 32.032 0.79
1999 6.986 25.203 32.189 0.78
2000 7.147 31.551 38.698 0.82
2001 .7.311 31.467 38.778 0.81
'2002 7.479 37.804 45.283 0.83
2003 7.651 37.804 45.455 0.83
2004 7.827 44.188 52.015 0.85
2005 8.008 45.809 53.817 0.85
2006 8.192 49.535 57.727 0.86
2007 "8.380 53.146 61.5L6 0.86
2008 8.573 52.292 60.865 0.86
2009 8.770 55.893 64.663 0.86
201 0 8.971 59.425 68.396 0.87
1/Val~es as calculated are shown for purposes of reproducibility
only,and do not imply accuracy beyond 100 MMSCFD.
~/NA -Not applicable
26488
4-65
TABLE 4-19
.TOTAL ANNUAL CAPITAL EXPENDITURES
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
(Millions of January,1982 Dollars)
Electricity Generat~al!Gas
Calendar Transmission Conditioning
Year Unlt A Unit B Line Pipeline Plant Total
1982 O.O.O.O.O.O.
1983 O.O.O.O.O.o.
1984 o.O.O.O.O.o.
1985 o.o.O.o.o.o.
1986 O.O.O.O.O.o.
1987 O.O.O.O.o.O.
1988 O.O.514.2 O.O.514.2
1989 O.O.118.1 1 ,383.6 O.1,501 !7
1990 O.O.232.4 1 ,383.6 319.8 1 ,935.8
1991 9.91Y O.94.5 1 ,383.6 319.8 .1,807.8
1992 33.90 O.O.O.O.33.9
1993 O.O.O.O.O.O.
1994 33.90 O.O.O.O.33.9
1995 56.97 O.O.O.O.57.0
1996 33.90 33.90 O.O.O.67.8
1997 56.97 O.O.O.O.57.0
1998 O.O.O.O..O.O.
1999 33.90 O.O.O.O.33.9
2000 O.O.O.o.O.O.
2001 33.90 56.97 O.O.O.90.0
2002 O.O.O.O.O.O.
2003 33.90 O.O.O.O.33.9
2004 33.90 56.97 O.O.O.90.9
2005 33.90 O.O..O.O.33.9
2006 33.90 O.O.O.O.33.9
2007 56.97 O.O.O.O.57.0
2008 33.90 O.O.O.O.33.9
2009 33.90 O.O.O.O.33.9
2010 O.O.O.O.O.O.
Total $554.$148.$959.$4,15l.$640.$6,451 •
!I Unit B denotes a second unit erected in any give year.
2/Incl udes all sit~preparation activities for multiple unit site.
2648B
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TABLE 4-21
TOTAL ANNUAL COSTS
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
(Millions of January,1982 Dollars)
Calendar Capital o &M Total
Year Expenditures Costs Expendi tures
1983 O.O.O.
1984 O.O.O.
1985 O.O.O.
1986 O.O.O.
1987 O.O.O.
1988 514.2 O.514.2
1989 1,501.7 O.1,501.7
1990 1,935.8 O.1,935.8
1991 1,807.8 O.1,807.8
1992.33.9 O.33.90
1993 O.28.1 28.14
1994 33.9 26.1 60.04
1995 57.0 29.2 86.29
1996 67.8 30.1 97.94
1997 57.0 35.9 92.94
1998 O.37.7 37.77
1999 33.9 37.6 71.57
2000 O.40.5 40.54
2001 90.9 40.3 131 .24
2002 O.44.8 44.81
2003 33.9 44.8 78.72
2004 90.9 .47.4 138.30 .-
2005 33.9 49.1 83.03
2006 33.9 50.4 84.39
2007 57.0 51.5 85.43
2008 33.9 52.6 86.54
2009 33.9 53.7 87.63
2010 O.54.9 54.90
Total $6,451 •$755.$7,206.
Present
Worth @ 3%$4,965.$415.$5,380.
2648B
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For comparison purposes,the 1982 present worth of power generating
costs has been calculated,assuming a real discount rate of 3 percent
and excluding fuel costs.The present worth of costs,expressed in
1982 dollars,is $5.4 billion.
4.5.4.3 Gas Distribution System Costs
The costs attributable to the gas distribution system are those costs
not associated with electricity generation.The capital costs include
a portion of the gas conditioning plant,a portion of the pipeline,and
the Fairbanks residential/commercial gas distribution itself.
Operation and maintenance costs,and internal fuel requirements,must
be treated in a like manner.
In Section 4.5.4.2 the values for 01 and 0A were presented.
Allocation of costs to the gas distribution system require the
presentation of (1-0)1 and (1-0)A values;and these are presented
in Table 4-22.These are required because,by definition,1-0 defines
the portion of costs associated with joint investments attributed to
non-electric purposes.
Given such values,the annualized expenditures associated with the
natural gas distribution system can be calculated.These are
summarized in Tables 4-23 through 4-25.The present worth of all costs
associated with the distribution system,as of 1982,is $0.9 billion
(January,1982 dollars),exclUding fuel costs.The period of the
analysis was assumed to be 1982 through 2010.
4.6 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS
Environmental effects associated with the Fairbanks power generation
scenario will be similar in many re~pects to those of the North Slope
scenario.Because the pipeline from-the North Slope to Fairbanks will
be buried and chilled,it will result in different environmental
effects and will require different types of mitigation than would a
2648B
4-69
2648B
TABLE 4-22
APPORTIONMENT VALUES FOR THE GAS DISTRIBUTION SYSTEM
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
4-70
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[-TABLE 4-23
TOTAL ANNUAL CAPITAL EXPENDITURES FOR THE GAS DISTRIBUTION SySTEM
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
['(Millions of January,1982 Dollars)
r Gas Gas
r'Calendar Distribution Conditioning
Year System Pipeline P1 ant Total
['1982 O.O.O.O.
1983 O.o.O.O.
1984 O.O.O.-0.
C 1985 O.o.O.O.
1986 O.O.O.O.
1987 o.O.O.O.
1988 O.O.O.O.r 1989 12.66 303.7 O.316.4
l~1990 12.66 303.7 70.2 386.6
1991 12.66 303.7 70.2 386.6
r 1992 12.66 O.O.12.7
L 1993 12.66 O.O.12.7
1994 O.O.O.O.
b 1995 o.O.O.O.
1996 O.O.O.O.
1997 O.O.O.o.
1998 O.O.O.O.
G 1999 O.o.O.O.
2000 O.O.O.o.
2001 o.O.O.O.
C 2002 O.O.O.o.
2003 o.o.O.O.
2004 O.O.O.O.
C 2005 O.O.O.O.
2006 O.O.O.O.
2007 o.O.O.o.
2008 o.O.O.o.
~2009 O.O.O.O.
2010 O.O.o.o.
[Total $63.$911.$140.$1,115.
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[4-71
TABLE 4-24
TOTAL ANNUAL NON-FUEL OPERATING AND MAINTENANCE COSTS
FOR THE GAS DISTRIBUTION SYSTEM
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
(Millions of January,1982 Dollars·)
Gas Gas
calendar Distribution Conditioning
Year System Pi pel ine Plant Total
1982 O.O.O.O.
1983 O.O.O.O.
1984 O.o.O.o.
1985 o.O.O.O.
1986 O.O.O.o.
1987 O.O.O.O.
1988 O.O.o.O.
1989 o.O.O.O.
1990 O.O.O.o.
1991 o.o.O.O.
1992 O.O.O.o.
1993 1.8 1.7 1.0 4.5
19:J4 1.8 3.0 1.7 6.5
1995 1.8 2.4 1.4 5.6
1!:I 96 1.8 3.0 1.8 6.6
1997 1.8 2.2 1.3 5.3
1998 1.8 2.2 1.3 5.3
1999 1.8 2.3 1.4 5.5
2000 1.8 1.8 1.1 4.7
2001 1.8 1.9 1.2 4.9
2002 1.8 1.7 1.1 4.6
2003 1.8 1.7 1.1 4.6
2004 1.8 1.5 0.9 4.2
2005 1.8 1.5 0.9 4.2
20U6 1.8 1.4 0.9 4.2
2007 1.8 1.4 0.9 4.2
2008 1.8 1.4 0.9 4.2
2009 1.8 1.4 0.9 4.2
2010 1.8 1.3 0.8 3.9
Total $32.$34.$20.$86.
2648B
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TABLE 4-25
ANNUAL SYSTEMS COST SUMMARY,GAS DISTRIBUTION SYSTEM
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
(Millions of January,1982 Do11ars)_
Calendar Capital OBM Total
Year Expenditures Costs Expenditures
1982 O.O.O.
1983 O.O.O.
1984 O.O.O.
1985 O.O.O.
1986 O.O.O.
1987 O.O.O.
1988 O.O.O.
1989 316.4 O.316.4
1990 386.6 O.386.6
1991 386.6 O.386.6
1992 12.7 O.12.7
1993 12.7 4.5 17 .2
1994 O.6.5 6.5
1995 O.5.6 5.6
1996 O.6.6 6.6
1997 O.5.3 5.3
1998 O.5.3 5.3
1999 O.5.5 5.5
2000 O.4.7 4.7
2001 O.4.9 4.9
2002 O.4.6 4.6
2003 O.4.6 4.6
2004 O.4.2 4.2
2005 O.4.2 4.2
2006 O.4.2 4.2
2007 O.4.2 4.2
2008 O.4.2 4.2
2009 O.4.2 4.2
2010 O.3.9 3.9
Total $1,115.$86.$1 ,201.
Present
Worth @ 3%$877 •$5l.$928.
2648B
4-73
transmission line through the same area.As in the North Slope
scenario,power plant emissions will bea significant consideration
because of existing air quality problems in the Fairbanks area.
Environmental impacts caused by the transmission line from Fairbanks to
Anchorage wi 11 be i denti ca 1 to those d.i.scussed ,for the North Slope
scenario,Sections 2.5 and 3.5,and are not repeated here.Power plant
characteristics related to environmental effects are summarized in
Table 4-26.
4.6.1 Air Resource Effects
Meteorological conditions in the Fairbanks area playa very important
role in determining the ambient air quality levels in the area.
Analyses of the Fai rbanks urban "hea't i sl and"have shown that winds are
generally light in the winter and that wind directions 'change
dramatically in the vertical direction during the wintertime.During
the \'/inter months,the air near the ground is relatively cold,compared
to the air aloft.This reduces mixing of the air i.n the vertical
direction,and when combined with relatively light winds,often leads
to periods of air stagnation.
In large part due to the winter stagnation conditions,the Fairbanks
area is'currently designated as a non-attainment area for carbon
monoxide (CO).Emissions of CO are largely due to automobiles.The
State Department of Environmental Conservation and the Fairbanks North
Star Borough Air Pollution Control Agency are implementing a plan to
reduce the ambient CO mainly through the use of vehicle emission or
traffic control techniques.In addition,relatively high levels of
nitrogen oxides have recently been monitored in the Fairbanks area.
Only an annual average nitrogen dioxide standard exists,but the short
term measurements of nitrogen oxides are as high as in major urban
areas such as Los 'Angel es.
The installation and permitting of a major fuel-burning facility,such
as a power plant,will require a careful analysis of the impact of its
26488
4-74
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TABLE 4-26
ENVIRONlwJENT RELATED POWER PLANT CHARACTERISTICS
COMBINED CYCLE POWER PLANT
FAIRBANKS POWER GENERATION -MEDIUM LOAD FORECAST
Land Environment
Plant Water Requirements 200 GPM
Plant Discharge Quantity Less than 200 GPM
including treated sanitary
waste,floor drains,boiler
blowdown and demineralizer
wastes
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Emissions
Particulate Matter
Sul fur Di oxi de
Nitrogen Oxides
Physical Effects
Water Environment
Land Requirements
Plant
Socioeconomic Environment
Construction Workforce
Operating Workforce
26488
Below Standards
Below Standards
Emissions variable within standards -
dry control techniques would be used
to meet calculated NO x standard of
0.014 percent of total volUlile of
gaseous emissions.This value
calculated based upon new source
performance standards,facility heat
rate,and unit size.
Maximum structure height of 50 feet
140 acres
Approximately 200 personnel at peak
construction
Approximately 150 employed personnel
4-75
emissions on ambient air quality.Because Fairbanks is a non-
attainment area,the operators of such a facility must demonstrate that
they will reduce,or offset,impacts of the power plant by reducing
emission levels of CO at other sources.Emissions .of CO from a natural
gas fired power plant are relatively low,and any displacement of the
burning of other fuels,such as coal or oil,will likely lead to
improved air quality.'This arises from the clean burning nature of
natural gas and from the fact that emissions from a major facility will
be injected higher in the atmosphere (due to plume buoyancy)than the
displaced emissions.During the very stagnant conditions in midwinter,
the plume from a power plant will likely remain well aloft with little
mixing to the surface layers.The complex urban heat island and
associated wind pattern will require a great deal of in-depth modeling
and analysis ~o determine air quality ~mpacts in terms that will
wi thstand reg u1 atory scruti ny.. .
A large combustion turbine power plant must meet the existing New
Source Performance Standards and Best Available Control Technology.
The nitrogen oxides limits will be the most constraining atmospheric
pollutant.The operation of the power plant will also consume a
portion of the allowable deterioration in air quality for nitrogen
oxides.While it is possible that the power plant could be sited near
Fairbanks,its installation would constrain other development efforts
which also might consume a portion of the air quality increment.The
nature,magnitUde,and duration of emission plumes must be studied as
well as the potential for beneficial impacts due to reduced combustion
at other sources within the area.
The Fairbanks area is also SUbjected to extended periods of wintertime
ice fog,and the Alaska Department of Environmental Conservation will
require the impact of any water vapor plumes to be carefully assessed.
A combustion turbine power plant which uses water or steam injection
techniques would have an adverse impact on the ice fog and icing
deposition nearby.For the purposes of this study,it is assumed that
Best Available Control Technology would be defined to not include water
or steam injection.
2648B
4-76
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Construction of the gas pipeline from the North Slope to Fairbanks will
result in fugitive dust and exhaust emissions from construction
vehicles.These air quality impacts will be temporary and located in
very sparsely populated areas,and will therefore be insignificant.
Ten comp~essor stations.~ill be located along the pipeline route,each
producing relatively low levels of emissions.The impacts of these
facilities will most likely not cause exceedances of the Alaska Ambient
Air Quality Standards and will not be required to meet the Prevention
of Significant Deterioration Increments.The emissions will not impact
any air quality sensitive areas.
4.6.2 Water Resource Effects
The gas fired combined cycle power plant described in Section 4.2 will
use approximately 200 gpm of fresh water for boiler make-up,potable
supplies,and miscellaneous uses such as equipment wash-down.Because
ample groundwater exists in the Fairbanks area and because the water
requirements are not particularly large,impacts on water supplies in
the area will not be significant.
Power plant wastes will consist of waSh-down water (for cleaning of
equipment),sanitary wastes,boiler blowdown,and demineralizer
regenerant wastes.The wash-down water will be treated for oil and
suspended solids removal.Sanitary wastes will be passed through a
sanitary wastewater treatment facility,and demineralizer wastes will
be treated for pH control.No treatment should be required for boiler
blowdown.The resultant wastewater stream,up to 200 gpm,will meet
all applicable effluent guidelines and will be discharged to a local
water body with sufficient assimilating capacity.
The gas pipeline from the North Slope to Fairbanks will cross 15 major
streams and rivers,inclUding the Yukon River,and could potentially
impact num~rous additional small streams and drainages.The pipeline
will be burfed for its entire length;vegetation will be disturbed
within a 50 ft wide strip.Without careful siting and construction
2648B
4-77
practices,erosion from exposed areas could cause sedimentation
problems in nearby water bodies.
To control soil loss and sUbsequent sedimentation effects,several
mitigation practices should be used during pipeline construction.
Existing work pads,highways,access roads,airports,material sites,
and disposal sites should be used whenever possible to minimize
vegetation disturbance.Pipeline rights-of-way and access roads should
avoid steep slopes and unstable soils.Hand clearing could be used in
areas where the use of heavy equipment would cause unacceptable levels
/
of soil erosion.A 50-foot buffer.strip of undisturbed land could be
maintained between the pipeline and streams,lakes,and wetlands
wherever possible.Construction equipment should not be operated in
water bodi es except.where necessary •.Where high 1eve1 s of sediment are
expected from construction activity,settling basins should be
constructed and maintained.All disturbed areas should be left in a
stabilized condition through the use of revegetation and water bars;
culverts and bridges should be removed,and slopes should be restored
to approximately their original contour.
A significant problem with the operation of a chilled,buried pipeline
is the formation of aufeis.Aufeis is an ice structure formed by water
overflowing onto a surface and freezing~with SUbsequent layers formed
by repeated overflow.Chilled pipe in streams can cause the stream to
freeze to the bottom in the vicinity of the pipe,creating aufeis over
the blockage.A chilled pipe through unfrozen ground can also form a
frost bulb several times larger than the pipe diameter.This frozen
area can block subsurface flow,forcing water to the surface and
causing aufeis.Road cuts can also expose SUbsurface flow channels,
causing aufeis build-up over the roadway.The potential for aufeis and
possible effects will require detailed considerations for all
construction areas.
All stream crossing facilities should be designed to withstand the
Pipeline Design Flood as defined for the ANGTS system.Streams should
be stabilized and returned to their original configuration,gradient,
2648B
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substrate,velocity,and surface flow.Water supplies for compressor
or meter stations should not be taken from fish spawning beds,fish
rearing areas,overwintering areas or waters that directly replenish
those areas during critical periods.
TIle YUKon River crossing will utilize an existing bridge.The Yukon
River will therefore not be significantly affected by the pipeline.
4.6.3 Aquatic Ecosystem Effects
The Fairbanks power plant will not cause significant impacts to the
aquatic resources.The water supply for the power plant will be
obtained from groundwater,and therefore will not affect surface
waterbodies.Discharges from the plant will be treated to meet
effluent guidelines before being released,so that fish habitat should
not be significantly affected.Discharge quantities will be relatively
low,less than 200 gprn.
The pipeline from the North Slope to Fairbanks will cross numerous
rivers and creeks,including the Yukon River.Aquatic resource impacts
will include all those discussed for the North Slope scenario (Section
2.5.3),and additional impacts caused by the chilled pipeline crossing
waterbodies.Several mitigation measures,in addition to those already
discussed,should be implemented to protect the fish habitat affected
by pipeline construction and operation.·Stream crossings·should be
constructed such that fish passage is not blocked and flow velocity
does not exceed the maximum allowable flow velocity for the fish
species in a given stream.If these criteria cannot be met,a bridge
should be installed.
Chilled pipes in streams should not cause:a)lower stream
temperatures so as to alter biological regime of stream;b)slow spring
breakup and delay of fish migration;or c)early fall freeze-up which
Would affect fish migration.In addition,the temperature of surface
or subsurface water should not be changed significantly by the pipeline
system or by any construction-related activities.
26488
4-79
All mitigation measures designed to reduce sedimentation of water
bodies (discussed in the Section 4.6.2)will protect fish spawning,
rearing and overwintering areas.
For the purpose of making recommendations regarding timing of ANGTS
construction activities,the pipeline corridor was divided into three
large geographical regions:Region I,Beaufort Sea to the Continental
Divide of the Brooks Range;Region II,Continental Divide of the Brooks
Range to the Yukon River;and Region III,Yukon River to Fairbanks.In
association with the ANGTS development,the following broad temporal
gUidelines were developed for recommendation for each gas1ine corridor
region based on fish use habitat (Schmidt et al 1981).These would
also be applicable to a smaller diameter pipeline.
Regi on I 1 May-20 July A cri tical peri od for most
Region II 15 April-15 July streams due to the occurrence
Regi on III 1 April-15 July of major spring migrations and
(early breakup streams)spring spawning (primarily
15 April-15 July grayling).
(late breakup streams)
Regi on I 20 July-25 August A sensitive period.Fry of
Region II 15 July-25 August spring spawning species have
Regi on III 15 July-l September emerged and major fall
emigrati ons have not yet
begun.Fish are mobile at this
time and can move to avoid or
reduce effects of disturbance.
Regi on I 25 August-1 OCtober A critical period for all
(small streams)streams.Fish must emigrate
25 August-15 OCtober from streams that do not
(l arge streams)provide winter habitat prior
Regi on II 25 August-l OCtober to freeze-up.Major upstream
(small streams)migrations and spawning of
25 August-15 OCtober fall spawning species occurs
(l arge streams)in streams that provide over-
Regi on II I 1 September-l November wintering habitat.
2648B
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The Fairbanks power plant will affect terrestrial resources primarily
through habitat disturbance.As discussed in the Report on Facility
Siting and Corridor Selection (Appendix C),potential pmler plant sites
in the Fairbanks area are located in developed or previously disturbed
areas.The.potenti al for adversely affecti ng terrestri·al habi tats ;s
therefore not considered to be.significant.
Region I
Region II
Region III
A preferred period for con-
struction in many streams that
do not provide winter habitat.
These streams generally are dry
or freeze to the bottom during
winter.This is a critical
period for fish overwintering
in springs,large rivers,and
lakes..
1 October-1 May
(small streams)
15 October-l May
(l arge streams)
15 October-15 April
(small streams)
1 November-15 April
(l arge streams)
1 Novemoer-l April
(early breakup streams)
1 November-15 Apri 1
(late breakup streams)
4.6.4 Terrestrial Ecosystem Effects
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Construction of the gas pipeline from the North Slope to Fairbanks will
require total clearing of a 50-foot right-of-way for the length of the
gas1ine.In addition,ten lO-acre compressor stations,two 1.5 acre
metering stations and a gas conditioning facility (15 acres)will be
constructed.Construction activities will disrupt terrestrial animals
near ~he corridor during the 3-year construction period.The pipeline
alignment will avoid the peregrine falcon nest sites near.the Franklin
ana Sagwon Bluffs,but other raptors may restrict construction schedules
(refer to Appendix C).Special construction measures may be necessary in
tile areas delineated by the BLlt!lana use plan,as discussed for the North
Slope scenario.Construction activities,especially aircraft traffic,
could disturb Dall sheep habitat in critical wintering,lambing and
movement areas.These construction-related impacts would be less than 3
years in duration.
Long term terrestrial impacts will result primarily from habitat
elimination •.Important moose browsing habitat,such as the willow stand
along Oksrukuyik Creek,should be preserved.The treeline white spruce
2648B
4-81
stand at the heaa of Dietrich Valley,which has been nominated for
Ecology Reserve status,should be avoided.The pipeline design should
allow for free passage of caribou and other large animals.
4.6.5 Socioeconomic and Land Use Effects
The potential socioeconomic and land use effects of locating an
electrical generdting facility in the vicinity of Fairbanks includes the
temporary impacts related to the influx of workers and permanent land use
impacts.
The size of the construction work force for the generating facility is
expected to be approximately 200 persons.These generation units will be
.constructed during the summer for about 4-5 months.
Since the project could draw on the large labor pool of Fairbanks,it can
be expected that the majority of workers will be hired locally.Economic
benefits to tile region will not be significant as employment on the
project will be temporary.Any in-migrating work force will have to seek
temporary housing on their own since housing will not be provided at the
project site.The extent of the impacts on the local housing supply will
depend on the vacancy rate for the summer of each year of construction.
As discussed in the Report on Facility Siting and Corridor Selection
(Appendix C),development of a generating facility on the outskirts of
the Fairbanks area should not engender significant land use conflicts,
since the focus of the final site selection activities will be on areas
which are presently used for industrial development.However,the
long-ten"staged development of a major electric generating complex will
certainly be a determinant of future land uses in the local area.
Construction activities at the generating plant site will generate
additional worker and construction vehicle traffic loads on the local
road system.However,disruptions to existing traffic patterns can be
minimized through site selection by utilizing major highways and
26488
4-82
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arterials to the maximum extent possible and by developing a local access
plan and schedule.Depending on the site selected,new access
requirements will be planned in recognition of local traffic requirements.
For construction of the gas pipeline in the North Slope-Fairbanks
corridor,employees will be housed either at the pump stations or the
permanent camp facilities that were constructed for the trans-Alaska oil
pipeline.Construction activities will be consistent with the BUM land
use criteria as discussed in Section 2.5.5.
The potential socioeconomic and land use impacts of the transmission
facilities between Fairbanks and Anchorage included in this scenario are
identical to those discussed in Section 2.5.5 for the North Slope
scenario,with-the addition of transmission facilities from the Fairbanks
generating site to the power grid.Again,assuming the site is located
on the outskirts of Fairbanks to the southeast,transmission -"
interconnections can probably expand on existing GVEA rights-of-way with
minimal additional impacts to existing land uses.However,future land
use patterns will be signficantly affected by the presence of the three
parallel 345 kV transmission lines.
2648B
4-83
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FAIRBANKS POVVC:R GENERATION
LOW LOAD
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5.0 FAIRBANKS POWER GENERATION
LOW LOAD FORECAST
The Fairbanks generation scenario,under the low load forecast,
requires all of the major systems of the medium growth forecast except
that fewer compression stations are required to transport the gas and
fewer units are required to generate electricity.The Fairbanks area
electrical generating station will require 3 combined cycle plants,
each consisting of two gas fired combustion turbines paired with two
waste heat recovery boilers,and a steam turbine generator for a
station capacity of 726 MW in 2010.Units will be phased-in by
bringing each combustion turbine on-line individually,followed by the
waste heat recovery boilers and steam turbine generator.Between
Fairbanks and Anchorage,one new 345 kV transmission line and upgrading
of the Healy-Fairbanks and Willow-Anchorage segments of the existing
line will be reqUired.The Fairbanks residential/commercial,gas
system peak demand at 100 percent penetration of potential market is
49 MMSCFD.
Construction of the gas conditioning facilities,gas pipeline,power
generating facilities and transmission systems,is estimated to cost
$4.9 billion.Total annual operation and maintenance costs are
~stimated to be ~q.4 billion.The present worth of costs exclUding
fuel costs is $3.6 billion.Construction costs of the Fairbanks gas
distribution system serving residential/commercial markers total
$1.6 billion,with total annual operation and maintenance costs
totalling S41 million.The present worth of costs for this system,
consisting of a portion of the pipe1irie and gas conditioning
facilities,plus the distribution network itself,is Sl.l billion.
5.1 NORTH SLOPE TO FAIRBANKS NATURAL GAS PIPELINE
As explained.in Section 4.1,pipeline design proceeded on the basis of
preliminary gas demand calculations.Because the refined demand values
2631B
5-1
did not warrant design changes,certain of the gas demand calculations
differ in the low load forecast as follows:
Pipeline Design
(Preliminary Demand)
Power Generation .
Annual Average Demand
Peak Daily Demand
Residential/Commercial
Annual Average Demand
Peak Daily Demand
Total
Annual Average Demand
Peak Daily Demand
Low Load Forecast
(MMSCFD)
108
179
14
40
122
219
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After refined demand values were available,the results were:
5-2
26318
5.1.1 Gas Conditioning Plant
For the low load forecast,the refined demand was 40 MMSCFD less than
the preliminary calculation.
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49
179
130
Low Load Forecast
(MMSCFD)
Uti11ty System Design
(Refined Demand)
Residential/Commercial
Peak Daily Demand
Total
Peak Daily Demand
Power Generation
Peak Daily Demand
The gas conditioning facility required for the low growth scenario will
utilize the SELEXOL physical solvent process,as described in Section
4.1.1.The design f10wrate will be 230 MMSCFD based on the daily peak
load anticipated for this growth forecast,a pipeline availability of
96.5 percent and compressor station demands.All other details and
specifications will be as described in Section 4.1.1.
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5.1.2 Pipeline
Similar to the medium forecast design,the pipeline will have an outside
diameter of 22 inches and will follow the same route,the ANGTS
right-of-way.Details regarding pipeline design and route are presented
in Section 4.1.2.
The peak daily flowrate,however,requires only three compressor
stations,which will be located at Stations 2,4 and 7 when using the
ANGTS numbering system.The flow conditions anticipated for the demand
scenario are presented in Figure 5-1.The design of the compressor
stations is indentical to that presented for the medium load forecast.
All other required systems,facilities and support services will also be
the same as those presented in Section 4.1.2.
5.2 POWER PLANT
The scenario for power generation at a Fairbanks site,under the low load
forecast requires three combined cycle plants to satisfy the anticipated
demand in the year 2010.The schedule for unit addition which resulted
from the analyses presented in the Report on System Planning Studies
(Appendix B)is shown in Table 5-1.
The details of p1~nt design and operation are identical to those
described for the medium load case in Section 4.2.Only where there are
variances due to the decreased number of units are specific items
addressed below.
Total operations and maintenance personnel will be less for this scenario
than the medium load case.Ten on duty operations and maintenance
personnel will be reqUired per shift in 1996 When the first gas turbine
begins operation.In the year 2010 when three complete units are
operating,60 on duty personnel will be required per shift.The plant.
site will be.approximately 90 acres in size and will include all three
units,two switchyards,and a 300 foot buffer zone around the plant.
2631B
5-3
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...2't ~f1110lL~,-~L-"ilia 1:1'1 !I II L"Za:;"~{:ilL f litgtp:
....z MM sCJ"j'b if?
TOTAL 480 MILES.22"0.0.PIPELINE.WALL THICKNESS •0.275 INCH MINIMUM
STATION DESIGNATIO,.M.L c.•.t c.•.I e.LI e.I.4 c.•.•c.•.•c.,.,c.,.•c.,.•e.L to POWI::-I.....,'RUDHOE lA,
MILEPOST (MILES)0.0 vo.1 '41.3 2.73."....'0.0
REVATION (FEET)2.1 "if2.S'305"0 '3/S"500•STATION INLET VOLUME (MMSCF /0),.,s-o 2.30 2.30 2.'2.~2.2.1..
~TOTAL FUEL (MMSCFID)-.,,I -..
STATION OUTLET VOLUME (MMSCFID)2.30 22.'2.2!2.2.7 '1S
STATION SUCTION PRESSURE (PSIG)12.'-0 II(H /()3~II 'lifo '0,",,'I
STATION DISCHARGE PRESSURE (PSIG)12.'0 IUO IIV~12.'0 -
•COMPRESSOR SUCTION PRESSURE (PSIG)ID.,,?/032."'0 -0
ii COMPRESSOR DISCHARGE PRESSURE (PSIG)12.'-+IIr,./2.&4--..-III
It COMPRESSION RATIO './37 -..-'.150 1.15'02
0 HORSE paW[lt RlQUIRED 1'32.0 -u ,....50 .'~70
.
ALASKA POWER AUTHORITY
NORTH SLOPE GAS
FEASIBILITY STUDY
HYDRAUL IC SUi'1f1ARY
LmJ FORECAST
PEAK DAILY FLOH
FIGURE !i-I
EBASCO SERVICES INCORPORATED
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TABLE 5-1
NEW CAPACITY ADDITIONS AND FUEL REQUIREMENTS 1/
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST_
Combined Cycle (MW)Gas Requi red
Year (Increment/Total)(MMSCFD)
1990 0/0 O.
1991 0/0 O.
1992 0/0 O.
1993 0/0 O.
1994 0/0 O.
1995 0/0 '0.
1996 86/86 5,957.6
1997 86/172 11 ,873.2
1998 0/172 11 ,873.2
1999 0/172 11 ,873.2
2000 0/172 11 ,904.7
2001 70/242 11,939.4
2002 86/328 17,876.4
2003 0/328 17,876.4
2004 86/414 23,873.6
2005 70/484 23,873.8
2006 86/570 29,814.1
2007 0/570 29,814.1
2008 86/656 33,413.4
2009 0/656 34,508.4
2010 70/726 32,228.9
!I Values as calculated are shown for purposes of reproducibility
only,and do not imply accuracy beyond the·100 MMSCFD 1eve 1.
2631B
5-5
Annual fuel requirements for power generation will grow from 5.96 BCFY
in 1996 to 32.23 BCFY in 2010.The maximum potential firing rate in the
year 2010,based on a heat rate of 8280 Btu/kWh,will be apprOKimate1y
9 x 10 4 SCFM.Annual fuel requirements for the study period are also
shown in Table 5-1.
5.3 TRANSMISSION SYSTEM
5.3.1 Fairbanks to Anchorage
This transmission system uses two 345 kV lines as described in
Section 3.2.Other details are similar,including series compensation.
5.4 FAIRBANKS GAS DISTRIBUTION SYSTEM
5.4.1 Fairbanks Residential/Commercial Gas Demand Forecasts
A study has been performed by Alaska Economics Incorporated to forecast
residential and commercial gas demand in Fairbanks.A summary of the
study's methodology and the results of the medium growth projection
appear in Section 4.4.1.The text of the stUdy appears in Appendix E.
Table 5-2 presents the study's results for the low growth forecast.
These forecasts have been made conditional on t~e gas achieving the
discrete percentages of the total market for heating and cooking energy
applications shown in Table 5-2.The size of the total market to which
these percentages have been applied has been projected to grow at a 1.43
percent annual average rate,the low growth forecast,beginning in
1981.This rate is the implied population growth rate for Fairbanks as
derived in Batte11e's (1982)low forecast of the demand for electricity
in the Rai1be1t area.
5.4.2 Fairbanks Gas Distribution System
The gas distribution system has been designed to supply Fairbanks a low
growth demand value of 5.2 BCFY.The differences in flowrates and
service areas between the medium and low growth scenarios affect the
2631B
5-6
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Delivered Gas,BCF Per Year
TABLE 5-2
FAIRBANKS RESIDENTIAL/COMMERCIAL GAS DEMAND
FAIRBANKS POWER GENERATION -LOW GROWTH FORECASTl/
".!!Refer to Appendix E for details.
Delivered Gas,BCF Peak Daily
Delivered Gas,BCF Per Peak Month
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Market growth at 1.43 Percent
10%of Market
20%of Market
40%of Market
100%of Market
10%of Market
20%of Ma rket
40%of Market
100%of Market
10%of Market
2"0%of Market
40%of Market
100%of Market
2631B
1985
0.510
1.275
2.039
5.098
1985
0.085
0.212
0.338
0.846.
1985
0.003
0.009
0.014
0.034
2010
0.727
1.818
2.908
7.720
2010
0.121
0.302
0.483
1.207
2010
0.005
0.012
0.020
0.049
size and lengths of the high pressure and distribution system mains.
The sizes and footages of the high pressure mains and the distribution
mains required for the low growth forecast are presented below.All
other system and piping details are the same as the medium growth
forecast which is described in Section 4.4.2.
High Pressure System Mains
Size (Inches)Length (Feet)
8 6,000
10 15,000
12 27,375
14 7,500
'Schedule of Distribution Mains
Size (Inches)
2
4
6
5.5 COST ESTIMATES
5.5.1 Capital Costs
Length (Feet)
450,000
78,000
90,750
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5.5.1.1 North Slope to Fairbanks Gas Pipeline
Feasibility level investment cost estimates have been prepared for the
systems and facilities which comprise the North Slope to Fairbanks
natural gas pipeline.These estimates are presented in Table 5-3.
5.5.1.2 Power Plant
The capital cost of simple cycle combustion turbines and'combined cycle
facilities are the same as that presented in Section 4.5 for the medium
load forecast.
26318
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TABLE 5-3
FEASIBILITY LEVEL INVESTMENT COSTS
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST
(Millions of January,1982 Dollars)
Total
Descriptionl/
Materials Constructi on Labor 21 Di rec t Costs
($1000)($1000)($1000)
22 in O.D.Gas Pipeline 480,000 4,100,000 4,580,000
Compressor Stations - 3 ea 30,300 25,300 55,600
Metering Stations - 2 ea 2,800 6,000 8,800
Valve Stations -28 ea 2,500 3,800 6,300
Engineering &Construction 279,000
Management
SUBTOTAL $515,600 $4,135,100 $4,929,700
Gas Conditioning Faci1 i ty3/538,300
TOTAL $5,468,000
1/A 15 percent contingency has been assumed for the entire project and has
been distributed among each of the cost categories shown.Sales/use
taxes and land and land rights expenses have not been included.•
2/Construction camp facilities and services are subsummed in the
Constructi on Labor cost category.
3/Factored pricing basis which includes engineering and construction
management.
2631B
5-9
5.5.1.3 Transmission Line Systems
Feasibility level investm~nt cost estimates have been prepared for all
required transmission line systems.The results of this analysis are
presented in Table 5-4.The estimate is of one new 345 ~V lines 700 MW
capacitys with series compenSation and an intermediate switching
stations and the required upgrading of the Willow-Anchorage'and
Healy-Fairbanks segments of the existing grid.
5.5.1.4 Gas Distribution System
Feasibility level and investment cost estimates (Januarys 1982 dollars)
have been prepared for the systems and facilities which comprise the
Fairbanks gas distribution system.The results of the analysis are
presented below.A 15 percent contingency has been assumed for the
entire project and has been distributed between each.cost category.
Sales/use taxes and land and land rights have not been included.
5.5.2.1 Gas Pipeline and Conditioning Facility
Annual operation and maintenance costs (Januarys 1982 dollars)for the
gas conditioning facilities are estimated to be as follows:
5.5.2 Operation and Maintenance Costs
Annua 1 Co sts ($l 000)
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3 s 390
$59 s890
$56 s500
$ls390
2,100
$3 s 490
$45 s200
Construction Total Direct
Labor ($lOOO)Costs ($lOOO)
5-10
Materi al s
($1000 )
$11 s300
Item
Total
Salaries
Maintenance Costs
(Parts and Expendables)
Gas Distribution System
Engineeri ng and
Construction Management
Total Construction Costs.
26318
1/'The investment costs one new 345 kV line,700 MW capacity with series
compensation and an intermediate switching station,and reflect
upgrading of the Willow-Anchorage and Healy-Fairbanks segments of the
existing grid to 345 kV.
2/Assumes a cost of $40,000 per mile (Acres American Inc.1981).
TABLE 5-4
FEASIBILITY LEVEL INVESTMENT COSTS
FAIRBANKS TO ANCHORAGE TRANSMISSION SYSTEM
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST
(Millions of January,1982 Dollars)
Total
Construction Di rect Costs
Labor ($lOOO)($lOOO)
8,414 17,271
30,872 63,830
10,960 23,260
182,083 311 ,291
53,183 73,232
41,572 41,572
$327,084 $530,456
14,400
37,130
$581,986
8,857
32,958
12,300
129,214
$203,378
Material s
($1000 )De sc ri pti onll
TOTAL
Cl eari ng
Conductors and Devices
SUBTOTAL
Land and Land Rights~/
Engineering and Construction
Management
Switching Stations
Substations
Energy Management Systems
Steel Towers and Fixtures
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26318
5-11
.Annual operation and maintenance cost (January,1982 dollars)for the
gas compressor stations and pipeline maintenance activities are
estimated to be as follows:
Operation and maintenance costs for the combined cycle facility at
Fairbanks are estimated to be $0.0040/kWh.These are based on
discussions with operating plant personnel,history of similar units,
EPRI published data and other studies.
Item
Sal ari es
Maintenance Costs
(Parts and Expendables)
Total
5.5.2.2 Power Plant
Annua 1 Co sts ($1000)
$2,090
1,750
$3,840
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5.5.2.3 Transmission Line Systems
Annual operation and maintenance costs (January,1982 dollars)have
been developed for the scenario·s required transmission line facilities
and total $8 million per year.These costs should be viewed as an
annual average over the life of the system.Actual O&M costs should be
less initially,and increase with time.
5.5.2.4 Gas Distribution System
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Annual operation and maintenance costs (January,1982 dollars)for the
Fairbanks gas distribution system are estimated to be as follows:
26318
Item
Sal aries
Maintenance Costs
(Parts and Expendables)
Total
5-12
Annual Costs ($1000)
$680
270
$950
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5.5.3 Fuel Costs
For the economic analyses which follow fuel costs were treated as zero.
This approach permits fuel cost and fuel price escalation to be treated
separately;and makes possible subsequent sensitivity analyses of the
Present Worth of Costs for this scenario based upon a range of fuel cost
and cost escalation assumptions.
5.5.4 Total Systems Costs
5.5.4.1 Cost Allocation Methodology
The methodology that was developed and presented in Section 4.4.4.1 is
equally app1 icabl e to the low growth scenari o.
5.5.4.2 Total System Costs
Like the Fairbanks medium load growth scenario,the Fairbanks low load
growth scenario involves a complex series of investments in a gas
conditioning facility,a natural gas pipeline,power generation
facilities,and transmission lines.Also,like the previous Fairbanks
scenario,the costs of the the gas conditioning facility and pipeline
must be apportioned according to the formulae presented in Section
4.5.4.1.After that apportionment,total annual system .costs can be
calculated.
The formulae for conditioning facility and pipeline cost apportionment
are the same regardless of growth;however,the resulting 01 and 0A
values are quite different between the low and medium growth scenarios.
For the low load forecast the 01 value is as follows:
~esidential/Commercial Peak =49 MMSCFD
Da i1y Flow (201 0)
El ectri-ca 1 Generati on Peak =130 MMSCFD
Da i1y Flow (201 0)
Total Peak Daily Flow (2010)=179 MMSCFD
01 =0.73
26318
The 0A values for the Fairbanks low load forecast are presented in
Table 5-5.Significant to note is the fact that in the low load
forecast case,the residential/commercial customers must assume a
higher share of the capital and annual cos~burdens 'of the gas
conditioning and pipeline facilities.
Given the joint systems cost apportionment,the total annual electrical
systems costs can be calculated.Total annual capital'costs are
presented in Table 5-6.Total annual O&M costs are presented in
Table 5-7.Total annual costs are then summarized in Table 5-8.The
period of the analysis was assumed to be 1982 through 2010.
The present worth of costs has peen calculated for comparison
purposes.The present worth of costs as of 1982,assuming a discount
rate of 3 percent,is $3.6 billion (1982 dollars)exclusive of fuel
costs.
5.5.4.3 Gas Distribution System Costs
The costs attributable to the gas distribution system serving
residential and commercial customers include a portion of ,the gas
conditioning plant,a portion of the pipeline,and all of those costs
associated with the distribution system within Fairbanks.Again,the
apportionment method discussed in Section 4.5.4.1 is an essential
precursor to the calculation of final total system costs.
Gas distribution costs depend upon calculating 1-0 1 and 1-0 A
.values.These are presented in Table 5-9.Pgain,it is clear that the
non-electric'customers must assume a larger portion of the capital and
operating expenses in the low load growth scenario as compared to the
medium load growth scenario.
Given those apportionment values,the total systems costs for the gas
distribution system can be calculated.Capital and O&M are presented
in Tables 5-10 and 5-11.Total annual systems costs are summarized in
Table 5-12.The present worth of these costs of 1982,assuming a real
discount rate of 3 percent,is $1.1 billion,exclusive of any fuel
costs.
26318
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[TABLE 5-5
~VALUES .
[FAIRBANKS POWER GEN TION -LOW LOAD FORECAST
[Residential El ectri cal Total
Calendar Demand Demand Demand['Year (BCFY)(BCFY)(BCFY)°A
r 1982 O.O.O.NA!/
1983 O.O.O.NA
1984 O.O.O.NA
L
1985 O.O.O.NA
1986 O.O.O.NA
1987 O.O.O.NA
1988 O.O.O.NA
P 1989 O.O.O.NA
L 1990 O.O.O.NA
1991 O.O.O.NA
C 1992 O.O.O.NA
L 1993 O.O.O.NA
1994 O.O.O.NA
1995 O.O.O.N/A
[1996 1.266 5.958 7.224 0.82
1997 2.568 11.873 14.441 0.82
1998 3.906 11.873 15.779 0.75
C 1999 5.283 11.873 17.156 0.69
2000 6.698 11.905 18.603 0.64
2001 6.794 11.939 18.913 0.63
l 2002 .6.891 17.876 24.767 0.72
2003 6.990 17.876 24.866 0.72
2004 7.090 23.874 30.964 0.77
2005 7.191 23.874 31.065 0.77
[.2006 7.294 29.814 37.108 0.80
2007 7.398 29.814 37.212 0.80
2008 7.504 33.413 40.917 0.82
C 2009 7.611 34.508 42.119 0.82
2010 .7.720 32.229 39.949 0.81
[1I NA -Not applicable
C.
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2631B
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TABLE 5-6
ANNUAL CAPITAL EXPENDITURES
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST
(Millions of January,1982 Dollars)
Electricity Generated!!
Gas
Calendar Transmission Conditioning
Year Unit A Unit B Line Pipeline Plant Total
1982 O.O.O.O.O.O.
1983 O.O.O.O.O.O.
1984 O.O.o.O.O.O.
1985 O.O.O.O.O.o.
1986 o.o.o.O.O.O.
1987 O.O.o.O.O.O.
1988 O.O.o.O.O.O.
1989 O.O.O.o.O.o.
1990 O.O.o.O.O.O.
1991 O.O.O.O.O.o.
1992 O.O.311.3 O.O.311.3
1993 O.o.71.8 1 ,199.6 o.1,271.4
1994 9.96Y O.141.4 1 ,199.6 196.5 1,547.5
1995 33.90 O.57.5 1,999.6 196.5 1,487.5
1996 33.90 O.O.O.O.33.9
1997 O.O.o.O.O.o.
1998 O.O.O.O.O.O.
1999 O.O.O.O.O.O.
2000 56.97 O.o.O.o.57.0
2001 33.90 O.O.O.o.33.9
2002 O.O.O.o. o.O.
2003 33.90 O.O.O.O.33.9
2004 56.97 O.o.O.O.57.0
2005 33.90 O.O.o.O.33.9
2006 O.O.O.O.o.O.
2007 33.90 O.O.O.O.33.9
2008 O.O.o.O.O.O.
2009 O.O.O.O.O.o.
201 0 O.O.O.O.O.o.
Total $327.O.$582.$3,599.$393.$4,901 •
!!Unit A refers to first unit built in a given year and Unit B to second
unit built.
2/Includes site preparation activities for multiple unit site.
2631B
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ANNUAL NON-FUEL OPERATION AND MAINTENANCE COSTS
[FAIRBANKS POWER GENERATION -LOW LOAD FORECAST
(Millions of January,1982 Dollars),
[~Gas
Calendar Transmission Conditioning
[Year Electricity Generated Line Pi pel i ne Pl ant Total
L 1982 O.O.O.O.O.
1983 O.O.O.O.O.
1984 O.O.O.O.O.
1985 O.O.O.O.O.
[~1986 O.O.O.O.O.
1987 o.o.o.o.o.
1988 o.o.O.o.o.
P 1989 o.o.o.o.o.
1990 o.o. o.o.o.Lj 1991 o.·0.O.o.o.
1992 O.o.o.o. o.r~1993 o.o. o.o.o.L 1994 o.o. o.o. o.
1995 o.o.o.o.o.
['1996 2.268 8.00 3.15 2.86 16.3
1997 4.520 8.00 3.15 2.86 18.5-"1998 4.520 8.00 2.88 2.62 18.0
U 1999 4.520 8.00 2.65 2.41 17.6
2000 4.520 8.00 2.46 2.23 17 .2
2001 6.360 8.00 2.42 2.20 19.0
2002 8.620 8.00 2.76 2.51 21.9[2003 8.620 8.00 2.76 2.51 21.9
2004 10.908 S.OO 3.00 2.69 24.6
2005 12.720 8.00 3.00 2.69 26.4
[2006 14.980 8.00 3.07 2.79 2.8.8
2007 14.980 8.00 3.07 2.79 28.8
2008 16.112 8.00 3.15 2.86 30.1
r:2009 16.640 8.00 3.15 2.86 30.7
2010 17.168 8.00 3.11 2.83 31.1U
Total $147.$120.$44.$40.$351.
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2631B
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TABLE 5-8
TOTAL ANNUAL COSTS
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST
(Millions of January,1982 Dollars)
Calendar Capital o &M Total
Year Expenditures Costs Expendi tures
1983 O.O.O.
1984 O.O.O.
1985 O.O.O.
1986 O.O.O.
1987 O.O.O.
1988 O.O.O.
1989 O.O.O.
1990 O.O.O.
1991 O.O.O.
1992 311.3 O.311.3
1993 1,271.4 O.1,271.4
1994 1,547.5 O.1,547.5
1995 1,487.5 O.1,487.5
1996 33..9 16.3 50.2
1997 O.18.5 18.5
1998 O.18.0 18.0
1999 O.17.6 17.6
2000 57.0 17 .2 74.2
2001 33.9 19.0 52.9
2002 O.21.9 21.9
2003 33.9 21.9 55.8
2004 57.0 24.6 61.6
2005 33.9 26.4 60.3
2006 O.28.8 28.8
2007 33.9 28.8 62.7
2008 O.30.1 30.1
2009 O.30.7 30.7
2010 O.31.1 31.1
Total $4,901 •.$351.$5,252 •
Present
Worth @ 3%$3,405.$185.$3,590.
2631B
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TABLE 5-9
APPORTIONMENT VALUES FOR THE GAS DISTRIBUTION SYSTEM
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST
Tenn Year Value
(1-0 )1 NA 0.27
(1-0 )A 1983-1995 NA
1996 0.18
1997 0.18
1998 0.25
1999 0.31
2000 0.36
2001 0.37
2002 0.28
2003 0.28
2004 0.23
2005 0.23
2006 0.20
2007 0.20
2008 0.18
2009 0.18
2010 0.19
5-19
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TABLE 5-10 [CAPITAL COSTS ASSOCIATED WITH THE DISTRIBUTION SYSTB~
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST r'(Millions of January,1982 Dollars)
l ,
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Calendar Conditioning Distribution
Year Plant Pipeline System Total '[
1982 O.O.O.O.['1983 O.O.O.O.
1984 O.O.O.O.
1985 O.O.O.O.f'1986 o.O.O.O.
1987 O.O.O.O.\.._"
1988 O.O.O.O.
1989 O.O.O.O.[1990 O.O.O.O.
1991 O.O.O.O.
1992 O.O.O.O.C
1993 O.443.7 12.0 455.7 I199472.6 443.7 12.0 528.3 '--
1995 72.6 443.7 12.0 528.3 [1996 O.O.12.0 12.0
1997 O.O.12.0 12.0
1998 o.O.O.O.
1999 O.O.O.O.[2000 o.o.o.o.
2001 O.o.o.o.
2002 o.o.o.o.C2003o.o.o.o.
2004 o.o.O.o.
2005 o.o.o.o.[2006 o.o.o.o.
2007 o.o.o.o.
2008 o.o.o.o.
2009 o.o.o.o.[2010 o.O.o.o.
Total $145.$1 ,331.$60.$1,536.f
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2631B L
5-20 ,L
TABLE 5-12
ANNUAL SYSTEMS COST SUMMARY FOR THE GAS DISTRIBUTION SYSTEM
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST
(Millions of January,1982 Dollars)
Calendar
Year Capital Cost o &t·'Cost Total Cost
1982 O.O.O.
1983 o.O.O.
1984 O.O.O.
1985 O.O.O.
1986 O.O.O.
1987 O.O.O.
1988 O.O.O.
1989 O.O.O.
1990 O.O.O.
1991 O.O.O.
1992 O.O.O.
1993 455.7 O.455.7
1994 528.3 O.528.3
1995 528.3 O.528.3
1996 12.0 2.3 14.3
1997 12.0 2.3 14.3
1998 O.2.8 2.8
1999 O.3.2 3.2
2000 O.3.6 3.6
2001 O.3.7 3.7
2002 O.3.0 3.0
2003 O.3.0 3.0
2004 O.2.6 2.6
2005 O.2.6 2.6
2006 O.2.4 2.4
2007 O.2.4 2.4
2008 O.2.3 2.3
2009 O.2.3 2.3
2010 O.2.3 2.3
Total $1 ,536.$41-$1,577 •
Present Worth
at 3%$1 ,075.$22.$1,097.
2631B
5-22
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-------------------._----------._-"--_._-_.-------_.------~----------_.__._~---------------~-----------;------------_.-._--------~._._-------=---.--------.~-------------~------~-- -----------~----._---~
5.6 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS
The Fairbanks power plant for the low load forecast will consist of three
combined cycle units in contrast to five combined cycle and two simple
cycle units for the medium load forecast.Power plant characteristics
are summarized in Table 5-13.
It is assumed that water or steam injection would not be required for
NOx control because of associated ice fog problems.Air emissions will
be reduced by apprQKimately one-half from the medium load forecast,and
will meet all applicable air quality standards.Groundwater will provide
approximately 100 gpm for eqUipment waSh-down,potable supplies,and
boiler make-up water.This relatively small amount of water will not
affect groundwater supplies in the area.Wastewater discharges will be
less than 100 gpm and will be treated to meet effluent gUidelines.
Aquatic resources,as for the medium load forecast,will not be
significantly affected.Plant acreage will be apprQKimately 90 acres,as
compared to 140 acres for the medium load forecast.Terrestrial impacts
on vegetation and habitat elimination are correspondingly reduced.
Pipeline-related impacts are identical to those discussed for the
Fairbanks scenario medium load forecast,Section 4.5.Impacts associated..
with the transmission line from Fairbanks to Anchorage are identical to
those discussed in Section 3.5 for the North Slope scenario,low load
forecast.Socioeconomic impacts are expected to be similar to those for
the medium demand scenario.
Soc i oeconomic impacts,as for the medi urn load forecast,are not expected
to be significant.The majority of workers will be hired locally.Any
in-migrating workforce will have to seek temporary housing on their own
but this number is expected to be low.
26318
5-23
Ai r Envi ronment
TABLE 5-13
ENVIRONMENT RELATED POWER PLANT CHARACTERISTICS
COMBINED CYCLE POWER PLANT
FAIRBANKS POWER GENERATION -LOW LOAD FORECAST
Emissions
Particulate Matter
Sulfur Dioxide
Nitrogen Oxides
Physi ca 1 Effects
Water Environment
Below standards
Below standards
Emissions variable within standards -
dry control techniques would be used
to meet calculated NO~standard of
0.014 percent of total volume of
gaseous emissions.This value
calculated based upon new source
performance standards,facility heat
rate,and unit size.
Maximum structure height of 50 feet
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Plant Water -Requirements 100 GPM
Pl ant Di scharge Quantity,Less than 100 GPM
including treated sanitary
waste,floor drains,
boiler blow-down and
demineralizer wastes
Land Environment
Land Requirements
Plant and Switchyard 90 acres
Socioeconomic Environment
Construction Workforce Approximately 100 personnel at peak
construction
Operating ~orkforce Approximately 50 personnel
2631B
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SCENARIO III
KENAI POWER GENERATION
MEDIUM LOAD
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6.0 KENAI AREA POWER GENERATION
MEDIUM LOAD FORECAST
The development of power generation facilities in the Kenai area which
will utilize North Slope natural gas is dependent on the construction
of a major,high pressure gas pipeline from the North Slope to a
tidewater location near Kenai.The details concerning this pipeline
and the attendant tidewater gas conditioning and liquefaction
facilities are presented in The Governor's Economic Committee (1983)
report entitl ed "Trans Al aska Gas System:Economics of an Al ternative
for North Slope Natural Gas."
The gas conditioning and liquefaction facilities associated with the
Trans Alaska Gas System (TAGS)will have numerous power loads,many of
which cannot be satisfied by any source except electricity.These
loads will include lighting,certain types of heating,ventilation and
air conditioning systems,pumps,various process coolers and
compressors,controls,tools,and any shaft horsepower requirements
that are intermittant,such as some refrigeration applications,or too
small to be economical for a combustion turbine.Based on the
electrical demand values required for the ANGTS gas conditioning
facility and discussions with gas liquefaction process equipment
vendors,the total peak electrical demand of these tidewater processing
facilities has been estimated to be approximately 300MW.This value
is only an approximation;the actual demand requirements will be
dependent upon the type of liquefaction facility selected for design
(e.g.compressor/expander system,cascade refrigerant system),and
specific design decisions regarding various process power sources made
during detailed engineering.To ensure that the Kenai power generation
scenario presents a realistic development approach and that the entire
Railbe1t utility system can support such a major contingency of demand,
the anticipated electrical requirements of these processing facilities
have been included in the electrical demand analysis.As TAGS will be
developed in phases,the total electrical demand of the facilities has
2554B
6-1
been proportioned~based on the flow rates anticipated during each
phase.
This scenario~then~centers on a major electric generating station in
the Kenai area near the terminus of the TAGS pipeline.By the year
2010~the station would consist of 7 combined cycle units and 1 simple
cycle gas turbine to satisfy the medium energy demand forecast for the
Rai1be1t and the additional power requirements of the TAGS gas
conditioning and liquefaction faci1ities~a total of 1743 MW.The fuel
for the power plant will be a blend of waste gas from the TAGS gas
conditioning facilities and TAGS sales gas.A major electrical
transmission system from the Kenai generating station to Anchorage is
required.The Kenai to Anchorage lines would be operated at 500 kV and'
emp10y·an underwater crossing of Turnagain Arm.To ensure system
re1iabi1ity~both the 500 kV lines from Kenai to Anchorage and the 345
kV lines from Anchorage to Fairbanks would consist of two parallel
lines.A residential/commercial gas distribution system for Fairbanks
is not an integral part of this scenario~although it is not precluded
as an adjunct to TAGS.The total construction cost of this scenario is
$2.1 bi11ion~with total operation and maintenance costs of $0.8
billion per year.The present worth of these costs excluding fuel
costs is $2.0 billion.
The Kenai development scenario described above represents a revised
scheme from that originally envisioned.The original scenario
anticipated the use of gas conditioning facility waste gas only to fuel
the electric generating station.Investigation of this alternative~
however~determined that the amount of waste gas available
(approximately 430 MMSCFD)would only result in approximately 350 MW of
electrical power.As this amount would probably be totally consumed
within the TAGS gas processing facilities~it was decided to supplement
the waste gas with TAGS sales gas to satisfy the electrical demands of
the Railbelt and the TAGS facilities.
2554B
6-2
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6.1 POWER PLANT
6.1.1 General
The power generation technology selected for the Kenai locale is
combined cycle utilizing 237 MW baseloaded plants (refer to
Appendix B).The plants are identical in configuration with those
described in Section 4.2.The difference in capacity rating is due to
the slightly higher average annual temperature encountered in the Kenai
1oca 1e.
Facilities required for the site and the site arrangement will be the
same as that described in Section 4.2.Equipment arrangement will be
as previously shown in Figures 4-1 and 4-2 and the site arrangement as
shown in Figure 4-3.A total of 7 complete combined cycle plants plus
1 simple cycle gas turbine will be required to satisfy the demand for
energy in the year 2010.The land area required for this development
will be approximately 175 acres.The schedule for addition of these
facilities is shown on Table 6-1 along with the total of new capacity
on a yearly basi s.
The functional parts of the power plant will include all the systems
described in Section 4.2.Additionally,a system for gas quality
monitoring will be necessary.The fuel.to be utilized ~i)l be a blend
of waste gas and sales gas from the gas conditioning plant (see Section
6.1.4 Fuel Supply)•
6.1.2 Combustion Turbine Equipment
The combustion turbines will be identical to those described previously
except for one operating detail.The gas burner nozzle in the
combustion chamber is typically designed to operate at a specific fuel
heat value pl us or mi nus 10 percent.A nozzl e purchased to burn 400
Btu/ft3 fuel will .be useful to 440 Btu/ft3•In order to burn
higher Btu content gas,a different nozzle would need to be installed.
Several nozzles for a range of potential fuels should be inventoried
for each turbine.
2554B
.6-3
TABLE 6-1
NEW CAPACITY ADDITIONS AND FUEL REQUIREMENTS
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST
New Capacity (MW)Gas Required (MMSCFy)l/
Year (Increment/Total)Waste Gas Sales Gas
1989 84/84 12,451.6 3,625.4
1990 84/168 24,903.3 7,250.7
1991 0/168 24,903.3 7,250.7
1992 237/405 49,864.6 14,518.3
1993 0/405 49,864.6 14,518.3
1994 69/474 49,924.1 14,535.7
1995 84/558 62,372.7 18,160.2
1996 84/642 74,827.0 21,689.7
1997 153/795 87,336.2 25,428.4
1998 84/879 99,786.8 29,053.5
1999 0/879 99,786.8 29,053.5
2000 69/948 99,848.2 29,071.4
2001 0/948 99,848.2 29,071.4
2002 168/1116 124,745.6 36,320.0 .
2003 0/1116 124,745.6 36,320.0
2004 69/1185 124,810.1 36,339.3
2005 168/1353 141,620.7 41,234.4
2006 69/1422 139,175.5 40,522.0
2007 84/1506 146,795.8 42,740.2
2008 153/1659 147,913.1 43,066.1
2009 84/1743 155,253.6 45,203.9
2010 0/1743 156,950.0 46,994.3
!!Values as calculated are shown for reproducibility only,and do
not imply accuracy beyond a 100 MMSCFD level.
25548
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6.1.3 Steam Plant
The effect of burning a low Btu content fuel on the heat recovery steam
generator {HRSG}will be negligible.Since the gas turbines are
controlled at a constant gas temperature,the response of the system to
a higher flow of noncombustibles in the waste stream will be to reduce
the amount of excess air while maintaining gas temperature and mass
flow constant.Therefore,no changes to the HRSG or the balance of the
steam cycle from that described in Section 4.2 is expected.
6.1.4 Fuel Supply
Depending upon the gas conditioning facility design chosen,a waste gas
stream comprised mainly of carbon dioxide and heavier hYdrocarbons may
be generated.It has been previously estimated {ref~r to Appendices A
and B}that a waste gas stream of approximately 430'MMSCFD with a
higher heating value of 195 Btu/ft3 could result.While it is
possible to directly burn this waste gas in combustion turbines,it
will require expensive redesign of the turbines,and increased
equipment supply costs.Since the waste stream alone could not supply
enough energy to satisfy demand through the year 2010,it was decided
to blend the waste ~as with sales gas to achieve a minimum heating
value of 400 Btu/ft {HHV}.Tnis resultant heating value does not
require combustion turbine modifications.The required amounts of both
waste and sales gas are shown in Table 6-1.
6.1.5 Electrical Equipment and Substation
The electrical equipment,including the generators,will essentially be
the same as that described for the North Slope and Fairbanks medium
forecast scenarios {Sections 2.1 and 4.2}.Major differences involve
the number of units installed,their actual ratings,and the bus
voltage.Figure 6-1 presents a simplifi~d one line diagram of the
substation.There will be 22 generators feeding the 11 transformers,
each rated 200 MVA 13.8/115 kV.For this alternative 115 kV bus
2554B
6-5
13.&kV
2 2 22 2 2 2 2 2 2 <:2 2 2 2 2 2 22 2·2 22
LOCAL
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KENAI POWER GENERATION
MEDIUM LOAD FORECAST
8UB~TATION ONE LINE ICHEMATIC
ALAlIA POWIR AUTHORITY
NORTH ILOPE GAl
FlAI.UTY lTUDY
500kV
TO ANCHORAGE
LOCAL
TO ANCHORAGE
200MVAR ~
TYPICAL R !
150 MYA
TYPICAL
LOCAL
200MVA
TYPICAL
LEGENDoGENERATOR
=ORI'\'W\TRANSFORMER
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voltage was chosen to be compatible with the existing 115 kV Chugach
Electric Association line in the area.Three circuits will provide
power for local area loads.The outgoing voltage will be 500 kV with
the two lines,each supplied by two 750 MVA transformers.The lines
will terminate in Anchorage.Whenever possible,a breaker and a half
configuration will be used.
6.1.6 Other Systems
Depending on interpretation of regulations.governing the application of
Best Available Control Technology (BACT),it may be necessary to add an
NOx control system to the gas turbines at the·Kenai location.All
other systems will be identical to those described for the Fairbanks
medium load growth forecast (Section 4.2).
The NOx control system will consist of either steam or water
injection directly into the combustion chamber.This is used to
control the gas temperature,keeping it below the range of high NOx
formation.
6.2 TRANSMISSION SYSTEMS
6.2.1 Kenai to Anchorage Lin~
6.2.1.1 Overview of the System
To transmit medium forecast power from Kenai to Anchorage,a 500 kV
transmission alternative was developed and found to be a cost effective
voltage.Two routes were investigated in detail:a 150 mile long land
based route around Turnagain Arm,crossing the mountains west of
Girwood to Anchorage;and an underwater cable crossing of Turnagain
Arm.The latter route was chosen as the better alternative.A brief
description of the line is presented below.
2554B
6-7
The line,with its two circuits on separate towers,will originate at
the Kenai generating plant substation and will run eastward to
approximately Sterling.The two circuits will then run towards the
northeast and follow an existing pipeline right-of-way.-The overland
route on the Kenai peninsula will be 65 miles in length and will..
terminate at Gull Rock.From this point 4 mile-long cables will carry
the power underwater to the north shore of Turnagain Arm to a location
marked Isle 29,which is less than a ha1f-mi1e northwest of McHugh
Creek.The remaining overhead line segment will parallel the
Seward-Anchorage highway for about 25 miles before reaching the
substation at Anchorage.
This routing is made possible by recent advancements in cable
technology developed by Pire11i of Italy and Standard Telefon O.G.
Kabel Fabrik A/S of Norway,which are a~out to install,for the ~ritish
Columbia ~dro and Power Authority,two 500 kV circuits,each
consisting of three single phase cables between the British Columbia
mainland and Vancouver Island.The Turnagain Arm crossing will consist
of 7 cables:3 for each circuit and 1 spare.
The system is simi 1ar to the one presented for the North Slope to
Fairbanks connection,except there will be no intermediate switching
stati ons and there wi 11 be a cab1 ecrossi ng.The desi gn of the·
overhead section of the line will be .identica1 to the North
Slope-Fairbanks connection described in Section 2.3 and Appendix 0,
except that guyed type transmission towers will be used for this line
and only 3 repeater stations will be required for communication
purposes.
6.2.1.2 Alternatives
Several alternative transmission corridors between Kenai and Anchorage
were considered in order to select a reasonable route for cost
estimating purposes.Factors considered were general engineering and
environmental constraints.Of the many potential routes,two were
investigated in detail.A·land based route was assumed to follow the
2554B
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existing Chugach Electric Association (CEA)right-of-way,which
generally follows the Sterling and Seward Highways,and which traverses
the eastern end of Turnagain Arm.However,closer examination of that
route in light of the major transmission facility requirements
disclosed the following severe constraints:
(1)The existing transmission lines between Portage and Indian Creek
are co-located with the Seward Highway and the Alaska Railroad on
a narrow bench between Turnagain Arm and the Chugach Mountains.
The bench is at the base of a unifonmly steep slope which rises to
above 3500 feet in elevation.The proposed transmission
facilities could not reasonably be accommodated within or adjacent
to the existing rights-of-way.One option for avoiding this area
would be to traverse the Chugach Mountains between Portage and
Anchorage.This woul d,however,.i nvol ve crossing difficult
terrain,much of which is included in the Chugach State Park.
(2)The existing CEA right-of-way parallels the Sterling Highway for
most of its length.In the vicinity of Bear Mountain,designated
wilderness areas within the Kenai National Wildlife Refuge are
within close proximity of the highway.Development of
transmission facilities of the magnitude required by this scenario
would engender severe aesthetic impacts to travelers along this
scenic highway,and possibly infringe on wilderness l.and use
val ues.
As a consequence of these severe routing constraints,this study
focused on a transmission line corridor which utilizes a Turnagain Anm
crossing from Gull Rock to McHugh Creek.The total length of this
preferred corridor route is 94 miles,as compared to the 150 mile route
which would be required for a completely overland route around the
eastern end of Turnagain Arm.
2554B
6-9
6.2.2 Anchorage Substation
The planned Anchorage substation is shown in Figure 6-2.The two
500 kV lines will terminate in two 750 MVA 345/525 kV transformers.
The bus will feed the area transmi·ssion system using 138n45 kV
transformers.From the bus two 345 kV lines will connect to
Fairbanks.These lines will have shunt reactors but no series
capacitors connected to them.
6.2.3 Anchorage to Fairbanks Line
This line must carry about half the amount of power that the Fairbanks
to Anchorage lines have to carry under previously discussed low growth
forecast conditions (5ection·3.2).Therefore,one 345 kV line would be·
adequate as far as power carrying capability and system performan'ce is
concerned.However,the reliability of electric power transmission
over a single line is very poor,making two lines in parallel a minimum
requirement.With two lines,neither series compensation nor an
intermediate switching station is required at 345 kV.Therefore,in
this scenario,the 345 kV intertie will be fully extended and a second
line will be built between Anchorage and Fairbanks using the Gilbert
Commonwealth (1981)design.
6.2.4 Fairbanks Substation
The Fairbanks substation will be the terminus of the two 345 kV lines.
It will be a conventionally designed 345/138 kV substation using a
breaker and a half scheme to supply the two 138/345 kV transformers
that will provide power locally.
25548
6-10
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KENAI POWER GENERATION
MEDIUM LOAD FORECAST
ANCHORAGE SUBSTATION ONE
LINE SCHEMATIC
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6.3 COST ESTn~ATES
6.3.1 Construction Costs
6.3.1.1 Power Plant
To support the derivation of total systems costs which is presented in
Section 6.3.4,feasibility level investment costs were developed for
the major bid lines items common to a 77 MW (ISO conditions)natural
gas fired simple cycle combustion turbine and a 220 MW (ISO conditions)
natural gas fired combined cycle plant.These costs are presented in
Tables 6-2 and 6-3.The costs represent the total investment for the
first unit to be developed at the site.Additional simple cycle units
will have an estimated investment cost of $35,680,000 while additional
combined cycle units will have an estimated investment cost of
$128,060,000.The unit cost differential for addition units is due to
significant reductions in line items 1 and 15,improvements to Site and
Off-Site Facilities,and reductions in Indirect Construction Cost and
Engineering and Construction Management.
6.3.1.2 Kenai to Anchorage Transmission Line
Transmission line feasibility level i·nvestment cost estimates for the
submarine cable crossing alternative are presented in Table 6-4.These
estimates are based on two 500 kV lines of 1400 MW capacity with series
compensation.A feasibility level investment cost estimate has also
been prepared for the land based route which traverses the eastern end
of Turnagain Arm.These estimates are presented in Table 6-5.As the
sUbmarine cable crossing alternative i~preferred,only this estimate
has been used in the derivation of total systems costs (Section 6.3.4).
25548
6-12
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FEASIBILITY LEVEL INVESTMENT COSTS
77 MW SIMPLE CYCLE PLANT
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST
(January,1982 Dollars)
Total
De scri pti onl/
Material Constructi on Di rect Cost
($1000)Labor ($1000)($1000)
l.Improvements to Site 475 1,410 1,885
2.Earthwork and Piling 75 500 575
3.Circulating Water System 0 0 0
4.Concrete 475 2,145 4,505
5.Structural Steel Lifting 1,725 1,370 3,095
Equipment,Stacks
6.Buil di ngs 750 1 ;440 2,190
7.Turbine Generator 11 ,400 685 12,085
8.Steam Generator and Accessories 0 0 0
9.Other Mechanical Equipment 955 530 1,485
10.Pi pi ng 265 590 855
ll.Insulation and Lagging 35 135 170
12.Instrumentation 100 70 170
13.Electrical Equipment 1,535 2,665 4,200
14.Pa i nting 70 250 320
15.Off-Site Facilities 300 1,080 1,380
SUBTOTAL $18,160 $12,870 $31 ,030
Frei ght Increment 910
TOTAL DIRECT CONSTRUCTION COST $31,940
Indirect Construction Costs 1,780
SUBTOTAL FOR CONTINGENCIES 33,720
Contingencies (15%)5,060
TOTAL SPECIFIC CONSTRUCTION COST 38,780
Engineering and Construction 2,200
Management
TOTAL CONSTRUCTION COST $40,980
11 The following items are not addressed in the plant investment
pr.cing:laboratory equipment,switchYard and transmission
facilities,spare parts,land or land rights,and sales/use taxes.
2554B
6-13
TABLE 6-3
FEASIBILITY LEVEL INVESTMENT COSTS
220 MW COMBINED CYCLE PLANT
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST
_(January,1982 Dollars)
Total
De sc ri pti onl/
Materi al Constructi on Di rect Cost-
($1000)Labor ($1000)($1000)
l.Improvements to Site 490 1,440 1,930
2.Earthwork and Piling 220 1,520 1,740
3.Circulating Water System 0 0 0
4.Concrete 1,485 6,730 8,215
5.Structural Steel Lifting 3,800 3,530 7,330
Equipment,Stacks
6.Buildings 1,800 3,600 5,400
7.Turbine Generator 30,700 2,590 33,290.8.Steam Generator and Accessories 9,600 4,320 13,920
9.Other Mechanical Equipment 6,230 3,120 9,350
10.Pi ping 1,630 3,055 4,685
1l.Insulation and Lagging 295 720 1,015
12.Instrumentation 1,700 290 1,990
13.Electrical Equipment 4,600 8,785 13,385
14.Painting 200 720 920
15.Off-Site Facilities 300 1,080 1,380
SUBTOTAL $63,050 $41,500 $104,550
Freight Increment 3,150
TOTAL DIRECT CONSTRUCTION COST $107,700
Indirect Construction Costs 4,310
SUBTOTAL FOR CONTINGENCIES 112,01 0
Conti ngencies (15%)16,800
TOTAL SPECIFIC CONSTRUCTION COST 128,810
Engineering and Construction -6,800
Management
TOTAL CONSTRUCTION COST $135,610
!/The following items are not addressed in the plant investment
pricing:laboratory equipment,switchyard and transmission
facilities,spare parts,land or land rights,and sales/use taxes.
2554B
6-14
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FEASIBILITY LEVEL INVESTMENT COSTS
SUBMARINE CABLE CROSSING ALTERNATIVE
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST
(January,1982 Doll ars)
Total
De scri pti on1/
Material Construction Direct Cost
($1000)Labor ($1000)($1000)
Switching Stations
Substations 63,073 43,729 106,802
Energy Management System 11,400 9,400 20,800
Steel Towers and Fi xtures 112,370 130,909 243,279
O.H.Conductors and Devices 12,726 29,919 42,645
Submarine Cable and Devices 77 ,900 52,200 130,100
Clearing 4,164 4,164
SUBTOTAL 277 ,469 270,321 547,790
Land and Land Ri ght~/7,200
Engineering and Construction
Management ..38,290
TOTAL CONSTRUCTION COST $593,280
1/The investment costs reflect two 500 kV lines,1400 MW capacity
with series compensation.A 15 percent contingency has been
assumed for the entire project and has been distributed among each
of the cost categories shown.Sales/use taxes have not been
i ncl uded.
Y Assumes a cost of $40,000 per mile (Acres American Inc.1981)•
2554B
6-15
TABLE 6-5
FEASIBILITY LEVEL INVESTMENT COSTS
LAND BASED ROUTE ALTERNATIVE
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST
(January,1982 Do 11 ars).
Total
De scri pti onl!Materi a1 Construction Di rect Cost
($1000)Labor ($1000)($1000)
Switching Stations 0 0 0
Substations 51,262 35,540 86,802
Energy Management System 11 ,400 9,400 20,800
Ste~l Towers and Fixtures 265,066 ·281,477 546,543
Conductors and Devices 20,522 48,248 68,770
C1 eari ng 0 6,720 6,720
SUBTOTAL 348,250 381,385 729,635
Land and Land Rightsfl 11,600
Engineering and Construction
Management 51,100
TOTAL CONSTRUCTION COST $792,335
1/The investment costs reflect two 500 kV lines,1400 MW capacity
with series compensation.A 15 percent contingency has been
assumed for the entire project and has been distributed among each
of the cost categories shown.Sales/use taxes have not been
i nc1 uded..
-2/Assumes a cost of $40,000 per mile (Acres American Inc.1981).
2554B
6-16
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6.3.1.3 Anchorage to Fairbanks Transmission Line
Feasibility level investment cost estimates have been prepared for the
Anchorage-Fairbanks connection.These estimates which are presented in
Table 6-6 are based on one new 345 kV line without series compensation
and an intermediate switching statiQn.The estimates also reflect
upgrading of the Willow-Anchorage and Healy-Fairbanks segments of the
present Intertie.
6.3.2 Operation and Maintenance Costs
6.3.2.1 Power Plant
The power plant operation and maintenance (P&M)costs were derived to
support the system planning studies (Appendix e).They reflect a
review of figures from previous Rai1be1t studies,operation of other
utilities,and salary requirements and expendable materials.The O&M
costs for this scenario are estimated to be $O.0040/kWh.
6.3.2.2 Transmission Line Systems
Annual operation and maintenance costs (January,1982 dollars)have
been developed for the scenario's required transmission line faci1itie~
and total $12 mi1~ion per year.These costs should be viewed as an
annual average over the life of the system.Actual OaM costs should be
less initially,and will increase with time.
6.3.3 Fuel Costs
For the economic analyses which follow fuel costs were treated as
zero.This approach permits fuel cost and fuel price escalation to be
treated separately;and makes possible SUbsequent sensitivity analyses
of the .Present Wor~h of Costs for this scenario based upon a range·of
fuel cost an~cost escalation assumptions.
25548
6~17
TABLE 6-6
FEASIBILITY LEVEL INVESTMENT COSTS
ANCHORAGE TO FAIRBANKS TRANSMISSION SYSTEM
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST
(January,1982 Do 11 ars)
Total
Materi al Constructi on Di rect Cost
Descri pti onll ($1000 )Labor ($1000)($1000)
Switching Stations
Substations 38,531 32,100 70,631
Energy Management System 12,?00 10,960 23,260
Steel Towers and Fixtures 129,.214 182,091 .311,305
Conductors and Devices 20,049 53,183 73,232
C1 eari ng 41,572 41,572
SUBTOTAL 200,094 319,906 520,000
Land and Land Right~14,400
Engineering and Construction
Management 36,400
TOTAL CONSTRUCTION COST .$570,800
!I The investment costs reflect one new 345 kV line without series
compensation or an intermediate sWitching station,and the
upgrading of the Willow-Anchorage and Healy-Fairbanks segments of
the Intertie to 345 kV.
2/Assumes a cost of $40,000 per mi 1e (Peres Ameri can Inc.1981).
2554B
6-18
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6.3.4 Total Systems Costs
Total systems costs for Kenai reflect a very different situation than
the North Slope or Fairbanks scenarios.The Kenai medium growth
scenario recognizes that a pipeline and gas conditioning facility are
required;however,these capital investments are external to the
electricity generation system per see The costs of the pipeline and
the gas conditioning facility should be reflected in the purchase price
of the natural gas rather than in the capital or O&M outlays.
The methodology and assumptions utilized to derive the systems costs
which are presented below have been previously described in the Report
on Systems Planning Studies (Appendix B).This methodology is
consistent with previous studies of electric generating scenarios for
the Railbelt,specifically Acres American,Inc.(1981),Susitna
Hydroelectric Project Feasibility Report and Battelle (1982),Railbelt
Electric Power Alternative Study.The period of the analysis was
assumed to be 1982 through 201 O.
The total systems costs for the Kenai medium growth scenario have been
calculated.Annual capital outlays are presented in Table 6-7.Annual
O&M costs are presented in Tabl e 6-8.Total annual costs are
summarized in Table 6-9.The present worth of these costs,exclusive
of fuel costs,is $2.0 billion as of 1982,assuming a discount rate of
3 percent and a value base of 1982 dollars.
6.4 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS
The Kenai power plant and transmission line to Anchorage and Fairbanks
will have many environmental effects similar to those discussed for the
North Slope and Fairbanks scenarios.The environmental and
socioeconomic considerations associated with the transmission line from
Anchorage to Fairbanks will be identical to those discussed in
Section 3.5,the North Slope Scenario (low load forecast),and
therefore will not be repeated here.Power plant characteristics
related to environmental impacts are summarized in Table 6-10.
2554B
6-19
TABLE 6-7
ANNUAL CAPITAL EXPENDITURES
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST
(Millions of JanuarYs 1982 Dollars)
Calendar Electricity Generated!!Transmi ssion
Year Unlt A Unit B Line Total
1982 O.O.O.O.
1983 O~O.O.O.
1984 O.O.O.o.
1985 O.O.621.2 621.2
1986 O.2/O.142.8 142.8
1987 10.6 O.282.2 292.8
1988 35.68 O.114.9 150.6
1989 35.68 O.o.35.7
1990 O.o.O.o.
1991 53.65 71.36 O.125.0
1992 o.o.o.o.
1993 53.65 o.o.53.7
1994 35.68 o.o.35.7
1995 35.68 o.o.35.7
1996 53.65 35.68 o.89.3
1997 35.68 o.o.35.7
1998 O.o.o.o.
1999 53.65 o.o.53.7
2000 o.O.o.o.
2001 35.68 35.68 o.71.4
2002'o.o.o.'0.
2003 53.65 o.o.53.7
2004 35.68 35.68
o.71.4
2005 53.65 o.o.53.7
2006 35.68 o.o.35.7
2007 35.68 53.65 o.89.3
2008 35.68 o.o.35.7
2009 o.o.o.o.
2010 o.O.o.o.
Total $689.$232.$1 s16l.$2 s083.
l!Unit A refers to first unit built in a given year and Unit B to
second unit built.
~/Includes site preparation activities for multiple unit site.
2554B
6-20
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ANNUAL NON-FUEL OPERATION AND MAINTENANCE COSTS
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST
(Millions of January,1982 Dollars)
Calendar Transmission
Year Electricity Generated Line Total
1982 O.O.O.
1983 O.O.O.
1984 O.O.O.
1985 O.O.O.
1986 O.O.O.
1987 O.o.O.
1988 O.O.O.
1989 2.21 12.0 14.21
1990 4.42 12.0 16.42
1991 4.42 12.0 16.42
1992 10.64 12.0 22.64
1993 10.64 12.0 22.64
1994 12.46 12.0 24.46
1995 14.66 12.0 26.66
1996 16.87 12.0 28.87
1997 20.89 12.0 32.89
1998 23.10 12.0 35.10
1999 23.10 12.0 35.10
2000 24.91 12.0 36.91
2001 24.91 12.0 36.91
2002 29.33 12.0 41.33
.2003 29.33 12.0 41.33
?004 31.14 12.0 43.14
·2005 33.64 12.0 45.64
2006 34.72 12.0 46.72
2007 35.81 12.0 47.81
2008 36.90 12.0 48.90
2009 37.99 12.0 49.99
2010 39.08 12.0 51.08
Total $501.$264.$765.
2554B
6-21
TABLE 6-9
TOTAL ANNUAL COSTS
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST
(Millions of January,1982 Dollars)
Calendar Capital o &M Total
Year Expenditures Costs Expenditures
1982 O.O.O.
1983 O.O.O.
1984 O.O.O.
1985 621.2 O.621.2
1986 142.8 O.142.8
1987 292.8 O.292.8
1988 150.6 O.150.6
1989 35.7 14.21 49.91
1990 O.16.42 16.42
1991 125.0 16.42 141.42
1992 O.22.64 22.64
1993 53.7 22.64 76.34
1994 35.7 24.46 60.16
1995 35.7 26.66 62.36
1996 89.3 28.87 118.17
1997 35.7 32.89 68.59
1998 O.35.10 35.10
1999 53.7 35.10 88.80
2000 O.36.91 36.91
2001 71.4 36.91 108.31
2002 O.41.33 41.33
2003 53.7 41.33 95.03
2004 71.4 43.14 114.54
2005 53.7 45.64 99.34
2006 35.7 46.72 82.42
2007 89.3 47.81 137.11
2008 35.7 48.90 84.60
2009 O.49.99 49.99
201 0 O.51.08 51.08
Total $2,083.$765.$2,848.
Present
Worth @ 3%$1,612.$436.$2,048.
2554B
6-22
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TABLE 6-10
ENVIRONMENT RELATED POWER PLANT CHARACTERISTICS
NATURAL GAS COMBINED CYCLE
KENAI AREA POWER GENERATION -MEDIUM LOAD FORECAST
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Particulate Matter
Sulfur Dioxide
Nitrogen Oxides
PhYsical.Effects
Water Environment
Plant Water Requirements
Water Injection
Other Requirements
Plant Discharge Requirements
Demineralizer
Steam Generators
.Treated Sanitary Waste
Floor Drains
Land Envi ronment
Land Requirements
Socioeconomic Environment
Be low standards
Below standards
Emissions variable within standards
-dry control techniques would be
used to meet calculated NO xstandardof0.014 percent of total
volume of gaseous emissions.This
value calculated based upon new
sou'rce perfonmance standards,
facility heat rate,and unit size.
maximum structure height of 50 feet
800 GPM
200 GPM
40 GPM
70 GPM
15 GPM
25.GPM
175 acres
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Operating Workforce
2554B
Approximately 200 personnel at peak
construction
Approximately 150 employed personnel
6-23
6.4.1 Ai r Resource Effects
As is typical of many exposed coastal locations,the air quality and
meteorological conditions are generally favorable to the development of
facilities such as power plants.It is not likely that an intense
ll mar ine 1ayer ll
,which may restrict dispersion of pollutants,develops
in this area.The air quality attains the applicable ambient
standards,but the locale is burdened with several existing petroleum
refinery emissions.A new natural gas fired power plant could probably
be sited in the area with the use of appropriate emissions controls
including water or steam injection to reduce nitrogen oxides
emissions.The impact of water vapor emissions on the formation of fog
must al so beconsi dered.The power pl ant must be carefully sited in
order to avoid adding to the air quality impacts of the existing
faci1 ities.
Construction of the transmission line from Kenai to Anchorage will
result in temporary air quality impacts.Heavy equipment and
construction vehicles will cause fugitive dust and exhaust emissions,
and slash burning will cause particulate emissions.As discussed in
Section 2.5,these emissions would occur rarely and would be widely
dispersed,generally in unpopulated areas.Long term impacts would be
negl igibl e.
6.4.2 Water Resource Effects
As in the Fairbanks scenario,water resource effects will be minimal.
Groundwater will supply up to 1000 gpm for water or steam injection
(for control of nitrogen oxides emissions),boiler make-up,potable
supplies and miscellaneous uses.Wastewater discharges wii1 consist of
boiler b10wdown,deminera1izer regenerant wastes and sanitary wastes,
each treated within the plant to meet the appropriate effluent
gUidelines.Because water used for water or steam injection is
consumed rather than recycled,wastewater quantities will be less than
200 gpm.
2554B
6-24
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The transmission line from Kenai to Anchorage would cross the streams
and creeks listed below.
The water quality of these streams should not be directly affected if
towers will be set back from the streambank at least 200 feet,and
construction activities stay out of stream channels.Indirect impacts
on the.waterbodies,however,will result from construction activity in
the small .drainageways that feed the main channel,primarily from
removal of vegetation (causing higher erosion rates),equipment
crossings of small drainages,and access road construction.Because
helicopter construction will be used along most of the route,the use
of heavy equipment,vegetation removal,and access road construction
should be minimal.
Moose River
Chickaloon River
Little Indian Creek
Furrow Creek
Chester Creek
Soldatna Creek
Mystery Creek
Big Indian Creek
Potter Creek
Campbell Creek
Ship Creek
The transmission line will cross Turnagain Arm from Gull Rock to the
mouth of McHugh Creek via seven buried submarine cables.Cqnstruction
phase impacts will consist of increased turbidity from the cable
installation,and construction activity near the shore on both
shorelines.Operation phase impacts will primarily be the potential
for cable rupture and sUbsequent cable oil contamination of Turnagain
Arm.The cable will be designed to have a very low probability of
rupture over the life of the project.A synthetic cable oil,
dodecobenzene,should be used for cable insulation.If this oil
accidentally leaks,it will rise to the surface and quickly evaporate
when exposed to air.This oil is used specifically to ~inimize
environmental effects associated with a cable rupture~
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6.4.3 Aquatic Ecosystem Effects
Because groundwater will provide the power plant's water supply,and
wastewater discharges will be low,the power p1ant;'n Kenai will not
significantly affect aquatic resources.
Soldatna Creek and Moose River flow into the Kenai River System,a
major river for anadromous fish habitat.Sodatna Creek provides
spawning and rearing habitat for silver salmon,and Moose River
contains king,silver,and sockeye salmon (U.S.Army Corps of Engineers
1978).Sedimentation of these water bodies,as discussed in the
previous section,could affect spawning and rearing habitat in these
streams.Because.helicopter construction will be used for most of the
route,however,sedimentation effects would be relatively minor.
Impacts to freshwater aquatic resources will be mitigated primarily
through the control of sedimentation of waterbodies,keeping
construction equipment out of streambeds and wetlands,and avoiding
areas of high biological value.These mitigation measures are
discussed in greater detail in Section 2.5.3 for the North Slope
scenari o.
Crossing Turnagain ~rm'with underwater cables poses additional
environmental hazards.Turnagain Arm is an environmentally sensitive
area in the general vicinity of the project that contains marine
mammals,inclUding harbor seals,sea lions and beluga whales (U.S.
Department of Commerce 1979).Salmon are present in some of the small
streams that enter this area (Alaska Department of Fish and Game 1978).
Installation of buried,submarine cables will temporarily disrupt the
sea floor along the cable route and increase turbidity and suspended
solids in the vicinity of the crossing.Tidal currents could carry
suspended sediment beyond the immediate crossing site.Special
construction techniques should be used to minimize disturbance of the
substrate.Installation should take place when biological activity is
at its lowest point in the yearly cycle.
2554B
6-26
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An accidental rupture of a cable would leak cable oil into the aquatic
environment.As discussed in the previous section,the cable oil used,
dodecobenzene,was chosen because it evaporates when exposed to air,
thereby minimizing environmental impacts.
The cables may operate at a temperature level above ambient
conditions.Because the cables will be buried six to ten feet,only
the substrate temperature and not water temperature would be elevated
(Bonneville Power Administration 1981).
6.4.4 Terrestrial Ecosystem Effects
Because the Kenai power plant will be located in an area already
extensively developed,little habitat degradation will occur.The area
disturbed for power plant construction,approximately 140 acres,will
not significantly affect terrestrial resources in the area.
The transmission route passes through an area of caribou habitat
northeast of Kenai (University of Alaska 1974).Little alteration of
caribou habitat will result from construction of the transmission line
because the animal utilizes cover types that require little if any
c1 eari ng.
Much of the route between Kenai and·Anchorage is within moose
rangeland.However,because moose utilize many different habitat
types,they will be the least adversely affected by habitat alterations
(Spencer and Chatelain 1953).Where the proposed route crosses heavily
forested areas,moose will benefit from additional clearing of the
right-of-way and the subsequent establishment ofa subclimax community
(Leopold and Darling 1953).The route does not cross Da1l sheep or
mountain goat habitat.
25548
6-27
The transmission line corridor passes near Chickaloon Flats and Potter
Marsh on Turnagain Arm,both key waterfowl areas.Various puddle
ducks,geese and sandhill cranes feed and rest during seasonal
migration periods in these areas.The shoreline of Turnagain Arm is
also used by seals and sea lions.Theotransmission line would not
directly affect this wildlife habitat.
Construction of the submarine cable could slightly affect terrestrial
habitat indirectly by increasing turbidity of Turnagain Arm and thereby
affecting food sources.This would be a temporary effect during the
construction phase only.
The transmission corridor passes through several vegetation types.
Between Kenai and Sterling,the vegetation is primarily bottomland
spruce-popl ar forest.As the corri dor extends northeasterly towards
Turnagain Arm,the vegetation becomes upland spruce-hardwood forest
and,on the foothills of the Kenai Mountains,coastal western
hemlock-Sitka spruce forest.North of Turnagain Arm,the vegetation is
primarily bottomland spruce-poplar forest (University of Alaska 1974).
Transmission line construction will necessitate clearing a 220-foot
wide corridor in all forested areas.Over the length of the corridor,
it is assumed that a total of 550 acres woul d be cleared withi n the .
ri ght-of-waj.
6.4.5 Socioeconomic and Land Use Effects
The socioeconomic effects of locating a gas conditioning facility and
electrical generating plant depends primarily on the size of the
in~igrating work force.Land use impacts are not expected to occur as
these facilities are compatible with the heavily industrialized
development that dominates the Kenai-Nikiski area.
2554B
6-28
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The size of the construction work force for the generating facility is
expected to be approximately 175 persons.The construction schedule
would require that a unit be constructed every year during the period
1993-2010,with the exception of 1994 and 1999,when no new units would
be required.The duration and time of the construction period would be
4 to 5 months in the summer.
The extent to which local people would be hired would depend on the
match of skills required for the project to those skills of the
available labor force.Labor union policies would also influence the
extent of local hires on the project.The in-migrating work force
would have to seek temporary housing on thei.r own since housing would
not be provided at the project site.The magnitude of the impacts on
the local housing supply would depend on the vacancy rate for the
summer of each year a unit was constructed.
The project is expected to have little effect on the unemployment rate
since employment on the project would be seasonal.In addition,these
job openings would be competitive with other employment opportunities
in seasonal industries such as construction and fisheries.
The operations work force is expected to be approximately 100.The
magnitude of potential impacts depends on the availability of local
labor to meet the work force requirements.If the majority of the
employees migrate to the Kenai-Nikiski region,.the demand for housing
could exceed the supply.
Construction of the transmission lines between Kenai and Anchorage is
expected to take 22 months.-The peak work force is estimated at 221
persons during the last 6 months and average construction work force is
expected to be approximately 163 workers.It is assumed that workers
would be hired from the labor pools of Kenai and Anchorage.
25548
6-29
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.SCENARIO III
KENAI POWER GENERATION
LOW LOAD
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7.0 KENAI AREA POWER GENERATION
LOW LOAD FORECAST
The Kenai area power generation scenario,under the low load forecast,
is also depedent upon the development of TAGS.The anticipated
electrical requirements associated with TAGS gas conditioning and
liquefaction facilities have also been included in the electrical
demand analysis.The development scheme will consist of 4 combined
cycle plants and 2 simple cycle combustion turbines conditioning
facility.Fuel for the power plant will bea blend of waste gas and
sales gas.A reliable electrical transmission system will require
parallel lines from the Kenai area to Anchorage (at 500 kV and
underwater across Turnagain Arm)and from Anchorage to Fairbanks (at
345 kV).A residential/commercial gas distribution system is not a
part of the scenari o.Constructi on costs for thi s scenari 0 are
$1.7 billion,with total operation and maintenance costs of
$0.6 billion.The present worth of these costs excluding fuel costs is
$1.7 billion.
The information in this section is intended to include only those
conditions which are significantly different from those for the medium
load forecast presented in Section 6.0.
7.1 POWER PLANT
This scenario will require four complete combined cycle plants,each
capable of generating 237 MW and two simple cycle combustion turbines,
to satisfy the low load forecast demand for energy in the year 2010.
The first gas turbine unit will go on line in 1990.The scheduled
additions are summarized in Table 7-1 and details are addressed in
Appendix B.·Fuel requirements for this scenario are also shown in
Table 7-1.
2593B
7-1
TABLE 7-1
NEW CAPACITY ADDITIONS AND FUEL REQUIREMENTS
KENAI AREA POWER GENERATION -LOW LOAD FORECAST
New'Capacity (MW)Gas Requirements (MMSCFD)!/
Year (Increment/Totai)Waste Gas Sales Gas
1990 84/84 12,451.6 3,625.4
1991 0/84 12,451.6 3,625.4
1992 153/237 24,962.1 7,267.8
1993 0/237 24,962.1 7,267.8
1994 84/321 37,413.5 10,893.2
1995 84/405 49,864.6 14,518.3
1996 0/405 49,864.6 14,518.3
1997 '153/558 62,372.7 18,160.2
1998 0/558 62,372.7 18,160.2
1999 0/558 62,372.7 18,160.2
2000 0/558 62,372.7 18,160.2
2001 84/642 74,827.0 21 ,689.7
2002 69/711 74,886.2 21,803.5
2003 0/711 74,886.2 21,803.5
2004 84/795 .87.,336.2 25,428.4
2005 84/879 99,786.8 29,053.5
2006 69/948 99,848.2 29,071.4
2007 0/948 99,848.2 29,071 .4
2008 84/1032 110,241.2 32,097.3
2009 0/1032 95,864.8 27,911.6
2010 84/1116 117,735.7 34,279.4
!/Values as calculated are shown for reproducibility only,and do
"not imply accuracy beyond a 100 MMSCFD level.
2593B
7-2
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Facilities required for the site and the site arrangement will be the same
as that described in Section 4.2.Equipment arrangement will be as
previously shown in Figures 4-1 and 4-2 and the site arrangement as sho~n
in Figure 4-3.The land area required for this development will be
approximately 120 acres.
The one line schematic of the low forecast generation plant substation is
shown in Figure 7-1.It is essentially a scaled down version of
Figure 6-1.The number of generators is reduced to 14 and only one
I
transformer will supply each of the 500 kV lines,which will be without
series compensation.
7.2 TRANSMISSION SYSTEM
The Kenai-Anchorage transmission system will be similar to the medium
forecast design inclUding the utilization of 7 cables:3 for each circuit
and 1 spare (Section 6.2).Series compensation is not required,however,
because the power transmitted to Anchorage in this low forecast case will
be much reduced from that of the medium forecast.
Installing a reduced number of cables under Turnagain Arm was investigated
but was not considered feasible because it is unlikely that the required
switehyards could be located at the two terminations due to the lack of
suitable land.During the system studies performed for this project,the
possibility of transmitting the power on two 230 kV circuits,with one
intermediate switching station,was also considered.Complete
investigation of this system would have required detailed studies far
beyond the scope of this project.However,such an alternative should be
investigated during detailed engineering.
At the substation in Anchorage the 500 kV voltage will be transformed to
345 kV for transmittal to Fairbanks and to supply local Anchorage loads.
The one line diagram would be similar to that presented in Figure 6-2,
except that there will only be two 750 kVA transformers at the substation
and the 500 k·V 1i nes will not be seri es compen.sated.The Fa i rbanks
SUbstation will terminate the two 345 kV circuits and supply,via
transformers,the local area load at 138 kV.
25938
7-3
ZOOMVA
TYPICAL
LOCAL
LOCAL
750MVA
TYPICAL
500KV
LOCAL
200 MVAR TYPICAL
I.-Jl/\/\_....1,/1
TO ANCHORAGE
LEGENDoGENERATOR
:=OR""",,TRANSFORMERoCIRCUITBREAKER
.JVV\r REACTOR
;:k CAPACITOR
TO ANCHORAGE
ALAlIA 'OWIER AUTHORITY
NORTH IlOH GAl
nAl.loITY lTUDY
KENAI POWER GENERATION
LOW LOAD FORECAST-
8UB8TATION ONE LINE ICHEMATIC
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7.3 COST ESTIMATES
7.3.1 Construction Costs
7.3.1.1 Power Pl ant
The capital cost of simple cycle combustion turbines and combined cycle
facilities are the same as that presented in Section 6.3 for the medium
load forecast.
7.3.1.2 Transmission Line Systems
Feasibility level investment cost estimates for the submarine cable
crossi ng a l.ternative for the Kenai -Anchorage 1i ne are presented in
Table 7-2.These estimates are based on two 500 kV lines of 700 MW
capacity without series compensation.A feasibility level investment
cost estimate has also been prepared for the land based route which
traverses the eastern end of Turnagain Arm.These estimates are
presented in Table 7-3.As the submarine cable crossing alternative is
preferred,only this estimate has been used in the derivation of total
systems costs (Section 7.3.4).
The construction costs associated with the Anchorage-Fairbanks line are
the same for both the medium and low growth forecasts.These costs
were previously presented in Table 6-6.
7.3.2 Operation and Maintenance Costs
Power plant operation and maintenance (O&M)costs are the same for both
the medium and low load forecasts,$0.0040/kWh.Transmission line O&M
costs are estimated to be $12 million per year.These costs should be
viewed as an annual average over the life of the system.Actual O&M
costs should be l~ss initially and will increase with time~
25938
7-5
TABLE 7-2
FEASIBILITY LEVEL INVESTMENT COSTS
SUBMARINE CABLE CROSSING ALTERNATIVE
KENAI AREA POWER GENERATION -LOW LOAD FORECAST
(January 1982 Dollars)
Total
Material Construction Di rect Cost
Description!!($1000)Labor ($1000)(-$1000)
Switching Stations
Substations 41,620 30,885 72,505
Energy Management System 11,400 9,400 20,800
Steel Towers and Fixtures 112,370 130,909 243,279
O.H.Conductors and Devices 12,726 29,919 42,645
Submarine Cable and Devices 77 ,900 52,200 130,100
Clearing 4,164 4,164
SUBTOTAL 256,016 257,477 513,493
Land and Land Ri ght~/7,200
Engineering and Construction
Management 35,950
TOTAL CONSTRUCTION COST $556,643
1/The investment costs reflect two 500 kV lines,700 MW capacity
with no series compensation.A 15 percent contingency has been
assumed for the entire project and has been distributed among each
of the cost categories shown.Sales/use taxes have not been
i ncl uded.
'E./Assumes a cost of $40,000 per mile (Acres American Inc.1981).
2593B
7-6
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TABLE 7-3
FEASIBILITY LEVEL INVESTMENT COSTS
LAND BASED ROUTE ALTERNATIVE
KENAI AREA POWER GENERATION -LOW LOAD FORECAST
(Janua~1982 Dollars)
Total
Materi a1 Constructi on Di rect Cost
Descri pti on.!/($1000)Labor ($1000)($1000)
Switching Stations
Substations 30,140 22,366 52,506
Energy Management System 11 ,400 9,400 20,800
Steel Towers and Fixtures 265,066 281,477 546,543
Conductors and Devices 20,522 48,248 68,770
Cl eari ng 6,720 6,720
SUBTOTAL 327,128 368,211 695,339
La nd a nd La nd Ri ghtsY 11 ,600
Engineering and Construction
48,700Management
TOTAL CONSTRUCTION COST $755,639
1/The investment costs reflect two 500 kV lines,700 MW capacity
with no series compensation.A 15 percent contingency has been
assumed for the enti re project and has been di stri buted among each
of the cost categories shown.Sales/use taxes have not been
i ncl uded.
Y Assumes a cost of $40,000 per mile (Acres American Inc.1981).
2593B
·7-7
7.3.3 Fuel Costs
For the economic ana1y"ses which foll ow fuel costs were treated as
zero.This approach permits fuel cost and fuel price escalation to be
treated separately;and makes possible sUbsequent sensitivity analyses
of the Present Worth of Costs for this scenario based upon a range of
fuel cost and cost escalation assumptions.
7.3.4 Total Systems Costs
Total systems costs for the Kenai low load growth scenario are
constructed in a manner identical to that used for the Kenai medium
load growth scenario,except for the number of power plants installed
an~operated.
The methodology and assumptions utilized to derive the systems costs
.which are presented below have been previously described in the Report
on Systems Planning Studies (Appendix B).This methodology is
consistent with previous studies of electric generating scenarios for
the Rai1belt,specifically Acres American,Inc.(1981),Susitna
Hydroelectric Project Feasibi1ty Report and Battelle (1982),Rai1belt
Electric Power Alternatives Study.The period of the analysis was
assumed to be 1982 through 2010.
Annual capital expenditures are presented in Table 7-4.Annual O&M
costs are presented in Table 7-5.The summary of all annual costs is
presented in Table 7-6.For comparison purposes the 1982 present worth
of costs,assuming a discount rate of 3 percent and excluding fuel
costs,is $1.7 billion (1982 dollars).
7.4 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS
The Kenai power plant for the low load forecast will consist of three
combined cycle units,in contrast to the five combined cycle and two
simple cycle units for the medium load forecast.Power plant
characteristics related to environmental resources are summarized in
Table 7-7.
2593B
7-8
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TABLE 7-4
ANNUAL CAPITAL EXPENDITURES
KENAI AREA POWER GENERATION -LOW LOAD FORECAST
(Millions of January,1982 Dollars)
Calendar Electricity Generated Transmission
Year Onlt A Omt B Line Total
1982 O.O.O.O.
1983 O.O.O.O.
1984 o.O.o.O.
1985 O.O.O.O.
1986 o.O.603.2 603.2
1987 o.O.138.6 138.6
1988 10.60 o.274.0 284.6
1989 35.68 O.111.6 147.3
1990 o.O.O.o.
1991 35.68 53.65 O.89.33
1992 o.O.O.O.
1993 35.68 O.o.35.7
1994 35.68 o.o.35.7
1995 O.O.O.O.
1996 53.65 35.68 O.89.3
1997 O.O.O.O.
1998 O.O.O.O.
1999 O.O.O.o.
2000 35.68 O.O.35.7
2001 53.65 O.O.53.7
2002 O.O.O.O.
2003 35.68 O.o.35.7·
2004 .35.68 O.O.35.7
2005 53.65 O.O.53.7
2006 O.O..O.O.
2007 35.68 O.O.35.7
2008 O.O.O.O.
2009 35.68 O.O.35.7
201 0 O.O.O.O.
Total $405.$89.$1 ,128.$1,710.
25938
7-9
TABLE 7-5
ANNUAL NON-FUEL OPERATION AND MAINTENANCE COSTS
KENAI AREA POWER GENERATION -LOW LOAD FORECAST
(Millions of January,1982 Dollars)
Calendar El ectri ci ty Transmission
Year Generated Line Total
1982 O.O.O.
1983 O.O.O.
1984 O.O.O.
1985 O.O.O.
1986 O.O.O.
1987 O.O.O.
1988 O.O.O.
1989 O.O.O.
1990 2.21 12.0 14.21
1991 .2.21 .12.0 14.21
1992 6.23 12.0 18.23
1993 6.23 12.0 18.23
1994 8.44 12.0 20.44
1995 10.64 12.0 22.64
1996 10.64 12.0 22.64
1997 14.66 12.0 26.66
1998 14.66 12.0 26.66
1999 14.66 12.0 26.66
2000 14.66 12.0 26.66
2001 16.87 12.0 28.87
2002 18.68 12.0 30.68
2003 18.68 12.0 30.68
2004 20 ..89 12.0 32.89
2005 23.10 12.0 35.10
2006 24.91 12.0 36.91
2007 24.91 12.0 36.91
2008 26.62 12.0 38.62
2009 23.15 12.0 35.15
201 0 27.68 12.0 39.68
Total $331.$252.$583.
2593B
7-10
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TABLE 7-6
TOTAL ANNUAL COSTS
KENAI AREA POWER GENERATION -LOW LOAD FORECAST
(Millions of January,1982 Dollars)
Calendar Capital o &M Total
Year Expendi tures Costs Expenditures
1982 O.O.o.
1983 O.O.O.
1984 O.O.-o.
1985 O.O.o.
1986 603.2 O.603.2
1987 138.6 O.138.6
1988 284.6 O.284.6
1989 147.3 O.147.3
1990 o.14.21 14.21
1991 89.3 14.21 103.51
1992 O.18.23 18.23
1993 35.7 18.23 53.93
1994 35.7 20.44 56.14
1995 O.22.64 22.64
1996 89.3 22.64 111 .92
1997 o.26.66 26.66
1998 o.26.66 26.66
1999 o.26.66 26.66
2000 35.7 26.66 62.36
2001 53.7 28.87 82.57
2002 O.30.68 30.68
2003 35.7 30.68 66.38
2004 35.7 32.89 68.59
2005 53.7 35.10 88.80
2006 o.36.91 36.91
2007 35.7 36.91 72.61
2008 O.38.62 38.62
2009 35.7 35.15 70.85
201 0 o.39.68 39.68
Total $1,710.$583.$2,292.
Present
Worth @ 3%$1,342.$331.$1,673.
2593B
7-11
TABLE 7-7
ENVIRONMENT RELATED POWER PLANT CHARACTERISTICS
COMBINED CYCLE POWER PLANT
KENAI AREA POWER GENERATION -LOW LOAD FORECAST
Air Environment
Emissions
Particulate Matter
Sul fur Di oxi de
Nitrogen Oxides
Physical Effects
Be low standards
Below standards
Emissions variable without standards -
dry control techniques would be used to
meet calculated NOx standard of 0.014
percent of total volume of gaseous
emissions.This value calculated based
upon new source performance standards,
facility heat rate,and unit size.
Maximum structure height of 50 feet
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Water Environment
Plant Water Requirements 500 GPM
Plant Discharge Quantities 100 GPM
Wastewater Holding Basin
including treated sanitary
waste,floor drains,boiler
blow-down,and demineralizer
wastes
Land Environment
Land Requirements
Plant and Switchyard 120 acres
Socioeconomic Environment
Construction Workforce Approximately 200 personnel at peak
construction
Operating Workforce Approximately 130 personnel
2593B
7-12
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Approximately 500 gpm of fresh water will be supplied by groundwater
for water or steam injection (for NOx control),equipment wash-down,
boiler make-up water,and potable supplies.This amount of water will
not significantly affect groundwater supplies in the area.Wastewater
discharges will be less than 100 gpm and will be treated to meet
effluent guidelines.
Aquatic resources,as for the medium load forecast,will not be
significantly affected.Plant acreage will be approximately 120 acres
as compared to 175 acres for the medium load forecast.Terrestrial
impacts are correspondingly reduced.
Impacts associated with the transmission line from Kenai to Anchorage
and on to Fairbanks are identical to those discussed in Section 6.4 for
the medium load forecast.
Socioeconomic impacts are expected to be similar to those for the
medium load forecast.They would be less significant for the low load
forecast.The in-migrating work force,which would have to seek
temporary housing on their own,would be smaller than for the medium
growth forecast,and thus would cause fewer demands on local housing
and public services.
25938
7-13
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COMPARISON OF SCENARIOS
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8.0 COMPARISON OF SCENARIOS
The three development scenarios have a common purpose of meeting the
electrical generating needs of the Rai1be1t region using North Slope
gas as a fuel source.However,the electric generating schemes and
auxiliary systems vary widely among the scenarios making comparison of
their relative merits complex.Table 8-1 is a side-by-side comparison
of some of the important features of the three scenarios for both
medium and low load forecasts.Each power plant meets the respective
electricity demand forecast for the Rai1be1t.The Kenai plants also
include the anticipated electrical requirements of the TAGS gas
conditioning and liquefaction facilities.Simple cycle units are the
recommended technology for electric generators on the North Slope,but
combined cycle is more appropriate for the other two scenarios.The
environmental and socioeconomic effects of all development scenarios
are SUbstantial,but none have been identified which would preclude any
project.All scenarios are technically feasible from an engineering
point of view.
The ultimate feasibility of each development scenario described herein
will depend upon a comparison of power costs between these scenarios
and alternative electric generating technologies.Such comparisons are
outside Ebasco's scope of work,bU~can be considered as a logical
extension of these studies which may be performed by the Alaska Power
Authority.
26038
8-1
Power Plant Location and Demand Forecast
TABLE 8-1
COMPARISON OF SCENARIOS
Factor
North Slope
Medium Low
Fairbanks
Medium Low
Kenai
Medium Low
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Power Plant
Capac i ty (MW)
Required Units (Simple
Cycle/Combined Cycle)
Plant Site Acreage
North Slope to Fairbanks
Transmission Lines (500 kV)
Fairbanks to Anchorage
Transmission Lines (345 kV)
1365
15/0
90
2
3
728
8/0
60
2
2
1383
2/5
140
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3
726
0/3
90
NA
2
1743
1/7
175
NA
2
1116
2/4
120
NA
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Kenai to Anchorage
Transmission Lines (500 kV)
North Slope to Fairbanks
Pipeline Compressor
Stations
POWER GENERATION
(1982 $P~ilion)
Capital Investment
Total O&M
Present Worth
DISTRIBUTION SYSTEM
(l 982 $Bill ion)
Capital Investment
Total O&M
Present Worth
1/NA -Not applicable
2603B
NA NA
NA NA
4.2 3.3
1.1 0.7
3.8 2.7
NA NA
NA NA
NA NA
8-2
NA
10
6.5
0.8
,5.4
1.2
0.09
0.9
NA
3
4.9
0.4
3.6
1.6
0.04
1.1
2
NA
2.1
0.8
2.0
NA
NA
NA
2
NA
1.7
0.6
1.7
NA
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NA
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REFERENCES
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9.0 REFERENCES
Acres Pinerican,Inc.1981.Susitna hydroelectric project -
feasibility report -Volume 1,engineering and economics aspects,
final draft.Alaska Power Authority.Anchorage,Alaska.
Alaska Department of Fish and Game.1978.Alaska Fisheries Atlas.
Vol urnes I and 11.Alaska Department of Fi sh and Game.Juneau',
Alaska..
Battelle Pacific Northwest Laboratories.1982.Rai1be1t electric
power alternative study:evaluation of rai1be1t electric energy
plans -comment draft.Office of the Governor,State of Alaska.
Juneau,Alaska (February 1982).
Beau1aurier,D.L.,B.W.James,P.A.Jackson,J.R.Meyer,and J.M.Lee,
Jr.1982.Mitigating the incidence of bird collisions with
transmission lines.Paper to be presented at the Third Symposium
on Environmental Concerns in Rights-of-way Management,San Diego,
California,February 15-18,1982.21 pp.
Bonneville Power Administration.1981.Underground cable systems:
.'Potentia1 environmental impacts,Draft Report.Bonneville Power
Administration,Washington,D.C.
Bureau of Land Management.1980.The utiliy corridor,land use
decisions.U.S.Department of the Interior,Bureau of Land
Management,Fairbanks,Alaska.
Commonwealth Associates,Inc.1982.Environmental Assessment Report
for the Anchorage-Fairbanks Transmission Intertie.Alaska Power
Authority,Anchorage,Alaska.
Commonwealth Associates.1978.Model for the ready definition and
approximate comparison of alternative high voltage transmission
systems.DOEIET 1591"6-1.
Commonwealth Associates,Inc.1981.Anchorage-Fairbanks transmission
intertie route selection report.
The Governor's Economic Committee.1983.Trans Alaska Gas System:
economics of an alternative for North Slope Natural Gas.State of
Alaska,Office of the Governor,Anchorage,Alaska.
Leopold,A.and F.Darling.1953.Effects of land use on moose and
caribou in Alaska.Transactions of the North American Wildlife
Conference.18:553-582.
North Slope Borough.1978.Coastal management program,Pr~dhoe Bay
Area.North Slope Borough,Barrow,Alaska.
2588B
9-1
Schmidt,D.R.,Neterer,C.,Willing,D.,Troy,P.Olson.1981.
Fisheries resources along the Alaska Gas Pipeline route (Prudhoe
Bay to Yukon Territroy)proposed by Northwest Alaskan Pipeline
Company.A summary report.Prepared for Northwest Alaskan
Pipeline Compay by LGL Alaska Research Associates,Inc.608 p.
Spencer,D.L.,and E.F.Chatelain.1953.Progress in the management
of the moose of South central Alaska.Transactions of the North
American Wildlife Conference.18:539-552.
u.S.Army Corps of Engineers.1978.Kenai river reivew.U.S.Army
Corps of Engi neers,Al aska Di stri ct.Anchorage,Al aska.
U.S.Department of Commerce.1979.Environmental assessment of the
Alaskan Continental Shelf,Lower Cook Inlet Interim synthesis
report.U.S.Department of Commerce,National Oceanic and
Atmospheric Administraton,Environmental Research Laboratories,
Boulder,Colorado.
u.S.Department of Commerce.Federal safety standards for
transportation of natural gas and other gas by pipeline.49 CFR
Part 293,Latest Edition.
U.S.Department of Commerce.American standard code for gas
transmission and distribution piping systems.B 31.8,Latest
edition.
University of Alaska,Arctic Environmental Information and Data Center.
1974.Alaska Regional Profiles,Southercentral Region.State of
Alaska,Office of the Governor,Juneau,Alaska.
2588B
9-2
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APPENDIX A
REPORT
ON
EXISTING QATA AND ASSUMPTIONS
NOVEMBER 1982
A4.0 GAS SUPPLY AND AVAILABILITY
••• • • • • • • • • • • • •0 • • • • •
A6.0 ECONOMIC ASSUMPTIONS . .
AS.O ENGINEERING ASSUMPTIONS
Aiv
A3-1
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TABLE OF CONTENTS
... ... . . ... ... ... . . .A3.0 GAS COMPOSITION
Al.O INTRODUCTION.
A2.0 BACKGROUND .•.
SUMMARY .. . .•.
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ADDENDUM A -BIBLIOGRAPHY
ADDENDUM B -LIST OF CONTACTS
Ai;
LIST OF TABLES
Tab1 e No.Tit1 e Page
A3-1 NORTH SLOPE NATURAL GAS COMPOSITION A'3-2
AS-1 PRELIMINARY GAS REQUIREMENTS FOR POWER AS-2
GENERATION AND FAIRBANKS RESIDENTIAL/
COMMERCIAL USE IN THE YEAR 2010
A5-2 TRANSMISSION LINE CONDUCTOR LOADINGS AS-5
A6-1 INVENTORY OF FUEL PRICES IN FAIRBANKS A6-2
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SUMMARY
Ebasco prepared this report to identify existing data and various
assumptions concerning the composition and availability of North Slope
gas and potential constraints to its use for meeting future energy
needs in the,Railbelt.The report plays an essenti~l role in the
ongoing feasibility level assessment by establishing a common data base
from which to proceed.The report discusses the physical composition
of North Slope gas,the quantity and availability of the gas,and
various engineering and economic factors.An extended bibliography and
a list of persons contacted to compile the data and assumptions are
appended.
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A1 .0 INTRODUCTION
This report is the first of a series in developing a feasibility level
assessment regarding the use of North Slope natural gas for power
generation in the Rai1be1t and for residential/commercial heating uses in
Fairbanks.Use of North Slope natural gas to meet these needs has not
been fully assessed by previous studies because it has been presumed that
all North Slope gas would be dedicated to the Alaska Natural Gas
Transportation System (ANGTS).Alternative evaluations for ANGTS were
based on transportation and utilization of the gas outside of the
Rai1be1t market area.It now appears that ANGTS will be substantially
de1~ed and that the gas may be available for Railbelt utilization.
The overall study of which this report is a part is charged with
developing the conceptual design with subsequent cost estimates and
environmental impact assessments of three energy development scenarios
for two energy demand forecasts:the medium demand forecast presented in
the final draft Susitna'Hydroelectric Project Feasibility Report 1 and
the 10\'/demand forecast presented in Battell e Pac;fi c Northwest
Laboratories'Evaluation of Rai1belt Electric Energy Plans -Cement
Draft.23 The scenarios included:
1)Electrical generation at the North Slope with attendant electrical
transmission to Fairbanks and on to Anchorage;
2)Electrical generation at the tenninus of a high pressure natural gas
pipeline to tidewater fueled by the "waste"gas byproduct of a gas
conditioning facility,with necessary electrical transmission to
Anchorage and Fairbanks;and,
3)Transportation of North Slope gas via a small diameter pipeline to
Fairbanks,with electrical generation at Fairbanks,electrical
transmission to Anchorage,and gas distribution for
residential/comercia1 use at Fairbanks.
2965A
A1-l
All three scenarios require an analysis of the energy demand forecasts to
determine optimum facility staging and capacity requirements,and an
analysis of facility and corridor siting constraints and/or
opportunities.These latter two topics are the subj~ct of other project
reports.
Ebasco has prepared this report to identify existing data and various
study assumptions which concern the composition and availability of North
Slope gas and potential constraints to its use.In addition,several
engineering and economic assumptions fundamental to the other aspects of
the study are presented.The report is based on a revie\'1 of the
literature as well as numerous discussions with knowledgeable agency and
industry representatives.
This report.plays an essential role in the feasibility level assessment
by establishing study assumptions so that all disciplines formulating the
technical details of the three scenarios will have a co~on data base
frolll which to proceed.A comon data base will also facilitate
comparisons among the scenarios.
The structure of this report begins with a short background chapter
(Chapter A2.D),which serves to establish an historical perspective to
the various studies that are re"ferenced.Following this background,is a·
discussion of the physical composition and characteristics of North Slope
gas (Chapter A3.D).Gas supply and availability (Chapter A4.D)are
reviewed and summarized.Engineering (Chapter AS.D)and economic
(~hapter A6.D)assumptions are provided to establish an early,common
data base for the scenarios.Chapter A7.D is reserved for issues of
concern to utilization of North Slope natural gas to meet the future
energy needs of the Railbelt.Following these chapters is an addendum of
literature on North Slope natural gas and Railbelt energy needs,and an
addendum listing Ebasco's contacts with agency and industrial personnel.
2965A
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A2.0 BACKGROUND
The natural gas reserves on the North Slope have been the subject of
numerous studies and reports since their discovery.Since development on
the North Slope began,various proposals to build a pipeline to carry the
gas to markets in the lower 48 states have.been formulated.As a result
of the proposals,an ~tensive literature of economic,technical,and
environmental studies that evaluate the alternatives to each proposal has
been accumulating.Many of these studies have been reviewed to assemble
the data contained in this report and are listed in the Addendum.*
Ebasco presents a background to the literature survey by summarizing some
of the most useful studies in chronological order in this chapter.
liThe Final Environmental Impact Statement for the Alaska Natural Gas
Transportation Systems"is representative of studies in support of the
initial attempts to develop North Slope natural gas.29 This statement
by the Federal Power Commission,which analyzes two separate proposals
and numerous alternatives for pipeline systems,was issued in April 1976
and is of principal interest for historical purposes.The document
established a preferred pipeline route from Prudhoe Bay to Fairbanks and
then through Canada to the lower 48 states.
A second study 9f interest is "Ana1ysi s of Prudhoe Bay Royal ty Natural
Gas Demand and t~e Proposed Prudhoe Bay Royalty Natural Gas Sa1e,"dated
.January 1977.34 While the analysis is out of date and should be used
for informational purposes only,the report covers many of the issues
which are relevant to the present stUdy.In particular,it discusses the
royalty share (12.5 percent)of the produced gas,the expected gas
production rate,and natural gas demand and demand growth.
*Reference numbers refer to the bibliography in the Addendum of this
Appendix.The bibliography also contains documents not referenced in
this report.
2966A
A2-1
Studies by electric power planning agencies during the early years of
development of the Prudhoe Bay field is typified by the report,IINorth
Slope Natural Gas Transport-Systems and their Potential Impact on
Electric Power Supplies and Uses in A1aska ll
•
36 This report by R.W.
Retherford Associates for the Alaska PO\ier Administration updated
various analyses presented in the previously cited Federal Power
Commission EIS concerning the impacts of a natural gas pipeline on
Alaskan electric power generation.This study is also out of date but
of interest because of its negative conclusions on the economics of
using natural gas for electrical generation.The studY concludes that
electricity from other sources should be used to power the gas pipeline.
In March of 1977,the A1 aska Department of Commerce and Economi c
Development issued a report written by the staff of Battelle Pacific
Northwest Laboratories enti t1 ed,"A1 askan North Slope Royal ty Natural
Gas -An Ana1ysi s of Needs and Opportunities for In-State Use ll
•
22
This report concludes that North Slope natural gas had no potential for
electrical generation since other less expensive fuels were available.
Like many of the studies prior to 1980,it assumed the timely
completion of a major gas pipeline carrying all of the available gas to
markets outside of Alaska.
In November 1977,Presi dent Carter desi gnated the A1 aska Hi ghway
Pipeline Project (A1can)for construction based on the provisions of
the Alaska Gas Transportation Act of 1976.The A1can proposal is the
project which is now referred to as the Alaska Natural Gas
Transportation System (ANGTS).Typical of the several informative
reports commissioned by the Alaska legislature concerning the ANGTS
project is the report by K.Brown and C.Barlow,IIAn Overvi e\/of
Natural Gas and Pipeline Issues,1I dated June 1978.24 The document
provides insight to the issues regarding development of North Slope
gas.While this study is a critique of the A1can project,it raises
issues on possible licensing and development constraints and the
effects of well head pri ce on the economi c vi abil i ty of the project.
2966A
A2-2
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In September 1978.the Ral ph M.Parsons Company produced a report
entitled.IlSa·les Gas Conditioning Facilities.Prudhoe Bay.
A1 aska 11.35 The i mportan~e of th;s document ;sin its spec;fi cati on
of the composition of North Slope gas and the conditioning needed to
produce a pipeline quality gas for ANGTS.The stuqy presumes a major
pipeline but many of the specifications are applicable to the present
feasibility level assessment.
The State of A1 aska Department of Natural Resources issued a report by
C.Barlow of Ar10n R.Tussing &Associates in March 1980 which presents
a highly informative technical discussion of the characteristics of
North Slope gas.written for the 1ayman.21 Titled IlNatural Gas
Conditioning and Pipeline Design.1I the report is particularly useful in
explaining the effects of carbon dioxide and penmafro~t on pipeline
design for the delive~of North Slope gas.
Among the later documents which are important to the present study
context is."A1aska-Historical Oil and Gas Consumption:'a report
written by Battelle and issued by the State of Alaska Department of
Natural Resources in January 1982 as a statutory requirement to the
Alaska legislature.37 The report provides a basis for projecting the
amount of gas required for the analyses in this feasibility level study.
A study representativ~of the current economic issues which arise
concerning North Slope gas utilization is a report by Kidder.Peabody.
and COr.1pany.IlReport to the Governor's Task Force on State of A1 aska
Participation in Financing the Alaskan Segment of the Alaska Natural
Gas Transportation System ll
•
31 This report is dated March 1982 and
explores alternatives the state could use to help finance the Alaska
Natural Gas Transportation System segment in Alaska.Likewise.a
recent report ti t1 edt IIA1 aska Natural Gas Development:An Economic
Assessment of Marine Systems.1I is representative of alternatives to
ANGTS for moving North ·Slope natural gas to markets outside"A1aska.30
2966A
A2-3
Several studies to utilize North Slope gas are currently being
conducted in addition to this feasibility level assessment.Booz,
Allen &Hamilton,Inc.is performing a study for the Alaska Department
of Natural Resources to screen a wide range of transport and use
options (including ANGTS),and to analyze economic and environmental
aspects resulting in a general ranking of promising options.Brown and
Root,Inc.is performing a study for the Governor's Economic Committee
on Alaska Natural Gas which focuses on a gas pipeline to a tidewater
conditioning plant in the Kenai/Nikiski area.The study is also
investigating various marketing options for the gas.Use of the waste
gas strea~from this conditioning plant is the basis of the Kenai
generation scenario in Ebasco's assessment.
The U.S.General Accounting Office recently contracted for another
study with Parsons,Brinkerhoff,Quade and Douglas,Inc.to generate a
financial report on engineering costs associated with transporting
Alaska natural gas to markets in the lower 48 states.
2966A
A2-4
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AJ.O GAS COMPOSITION
A detennination of the physical composition of North Slope natural gas is
essential to evaluate the economics of its utilization under alternative
scenarios.The trade-offs among gas conditioning,gas transportation,
and gas utilization alternatives depend on the types and quantities of
chemical compounds.present in the natural gas.In particular,North
Slope natural gas is characterized as II swee t and wet ll (generally
desirable factors),but is relatively high in carbon dioxide (undesirable
factor).21
Several studies and sources of data on chemical composition of North
Slope natural gas are available.21 ,35 The data are in substantial
agreement to support a preliminary feasibility level analysis.Variation
among the data sources may be attributable to the fact that North Slope
natural gas can be obtained from the top of the Sadlerochit fonmation
(the gas cap)or from the lower lying oil as a dissolved gaseous
constituent.
Ebasco,based on consultation with industry and government personnel,
will use the natural gas composition shown in Table AJ-l as the common
data base for each scenario.The Ralph M.Parsons Company assembled
these data in September 1978 to support a study for sales gas
conditioni"ng facilities at Prudhoe Bay.35 The Parson~·study,in
support of a major all-Alaska pipeline proposal,embodies several gas
composition assumptions appropriate for the three Railbelt scenarios
considered in Ebasco·s study.
The singl e most si gni fi cant factor in the composi ti on of North Slope
natural gas which influences the economics of its utilization is the
relatively high carbon dioxide content.Table A3-1 shows that over 12
percent (by volume)of the gas is carbon dioxide,a combustion product
gas which is a generally undesirable constituent,Carbon dioxi~e removal"
2967A
A3-1
0.00.08
TABLE A3-1
6.47
0.47
74.17
12.63
Vol ume Percent
NORTH SLOPE NATURAL GAS COMPOSITION
Ethane
Constituent
Methane
-----------------------------
Propane
Butanes
Pentanes-pl IjS
Raw Gas Heati n9 Val ue
2967A
A3-2
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is required to produce a high quality pipeline gas.The gas represents
an added transportation cost if conditioning facilities are not on the
North Slope.Carbon dioxide may also promote pipeline corrosion
through the fonmation of carbonic acid and must be removed if natural
gas is to be stored as liquid natural gas (LNG).(Carbon dioxide does
allow a pipeline to carry greater quantities of heavy hydrocarbons,but
the net benefit is rather small.)
The sulfur content of North Slope natural gas is low and treatment is
not required prior to pipeline transmission.35 Sulfur is an
undesirable constituent of natural gas which can increase treatment
costs considerably,contribute to air pollution,and promote pipeline
corrosion.The low sulfur content is denoted by the gas being termed
Iisweetll.
The rel atively hi gh proporti on of natural gas 1i qui ds (NGL)'compared to
methane is a desirable characteristic if natural gas is used as a
petrochemica~feed stock.21 ,24 Natural gas liquids are present in
North Slope gas because it is derived from an oil reservoir.The
heavier hydrocarbons (ethane,propane,and butane)which make up the
natural gas liquids are not desirable for domestic utility use where
IIdry gas ll is favored.The Ilwetll gas can be conditioned to remove the
heavier hydrocarbons.
The composition of the waste gas stream associated with the Kenai
electrical generation scenario arises from the assumption that gas
conditioning will be employed at the tidewater terminus rather than on
the North Slope.In the ,absence of a specific gas conditioning process
design,Ebasco derived a theoretical maximum gas composition based on a
stipulated waste gas heating value of 300 Btu/SCF.This analysis shows
that an unrealistic quantity of raw gas hydrocarbons is necessary to
achieve this heating value.Based on a brief analysis of available gas
conditioning processes,the waste gas stream could have an approximate
heating value of 175 to 195 Btu/SCF.An exact composition of the waste
gas stream cannot be specified at this time,but it will be high in
heavier'hydrocarbons and carbon dioxide.
2967A
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A4.0 GAS SUPPLY AND AVAILABILITY
Gas supply refers to the physical quantity of natural gas present in the
Prudhoe Bay field.Gas availability refers to phYsical and institutional
constraints on gas production.Most estimates of the total volume of gas
are in.the range of 30 to 40 trillion cubic feet (TCF)for the known
reserves in the Sadlerochit formation,of which some 25 to 30 trillion
cubic feet are recoverable.21 ,22,28,34 To place these quantities in
perspective,the North Slope contains 10 percent of the known U.S.
natural gas reserves and could supply 5 percent of the present demand in
the lower 48 states for 30 years.
For purposes of this study,Ebasco will use a quantity of 26 TCF as an
estimate of the recoverable reserves of North Slope gas.This is
consistent with the 1977 Battelle report on North Slope royalty gas.22
This quantity refers only to the Sadlerochit formation gas,for which the
State of Alaska royalty share is 12.5 percent of production.
Production of Prudhoe Bay natural gas will be at a rate to maximize
recovery of oil in the formation.At present,some 2 billion cubic feet
(BCF)of gas are brought to the surface with the oil each day.All but a
few percent are injected back into the gas cap in order to maintain
reservoir pressures and maximize oil recovery.The State of Alaska Oil
and Gas Conservation Committee establishes the operating methods through
pool rules,an administrative rule making procedure.Conservation Order
No.145 (June 1,1977)provides for annual average offtake rates of 1.5
mill i on barrel s per day for oil and 2.7 BCF per day for gas.The pool
rule production rate is consistent with other pUblished production
capabilities for the Prudhoe Bay field and therefore will be used by
Ebasco.A production rate of 2.7 BCF per day is assumed to yield 2.0 BCF
per day of conditioned gas.21
IIproducti on ll is·a term whi ch must be carefully defi ned in context once a
significant quantity of Prudhoe Bay gas can be utilized.According to
the Prudhoe Bay Lease Agreements,the State of Alaska royalty share (12.5
2968A
A4-1
percent)appl ies to gas that is II pro duced,saved,sold or used off said
land ll
,and does not include gas utilized to operate the oil field and gas
injected to maintain reservoir pressure.The only gas now being produced
is the 60 million cubic feet per day sold to Alyeska to.operate four of
the Trans-Alaska Pipeline System (TAPS)pump stations.If North Slope
gas is to be utilized solely for the scenarios considered in this stUdy,
the project proponent would have to enter into discussions with the
producers to negotiate for the sale of the gas.
Of the approximately 2.0 BCF per day of conditioned gas available for
use,the Railbelt low and medium future electricity needs could only
absorb on the average 0.11 BCF per day and 0.19 BCF per d~,
respectively.The Alaskan royalty share alone (12.5 percent)would
.generally be sufficient to meet both growth forecasts.
The waste gas stream associated with the Kenai electrical generating
scenario is incapable of meeting the needs of even the low forecast.The
amount of available gas is approximately 430 x 106 SCF/day,with a
heating value of 175 to 195 Btu/SCF.This is only about 50 percent of
the required en~rgy to meet the electrical needs in the low growth case.
The waste gas stream must,therefore,be supplemented with appropriate
quantities of sales gas to meet energy needs.
2968A
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Several engineering assumptions have been made to facilitate development
of the electrical generation scenarios.These include using the medium
load and energy demand forecasts presented in the final draft Susitna
~droe1ectric Project Feasibility Report (Table 5.7)1 and the low load
and energy demand forecasts presented in Battelle Pacific Northwest
Laboratories'Evaluation of Rai1be1t Electric Energy Plans -Comment
Draft (Executive Summary,Pageiv).23 It should be noted that the
latter forecasts are lower than the low range forecasts given in the
Susitna Feasibility Report.These particular forecasts are being used at
the request of the Alaska Power Authority to ensure comparability with
previous Rai1be1t electric energy analyses.It is also expected that
these fnrecasts will br?cket a revised medium range forecast which is
currently being prepared by Battelle Pacific Northwest Laboratories using
their existing RED model and based on revised economic forecasts
currently being prepared by the University of Alaska Institute of Social
and Economic Research.
Preliminary estimates of the amount of gas to meet power generation needs
are being based on the use of a conversion (heat)rate of approximately
10,000 Btu/kWh and a sales gas heating value of approximately 1,000
Btu/SCF.These values,when applied to the low electrical demand
forecast result in an annual average usage in the year 2010 of 39.4 BCF.
Similarly,the medium electrical demand forecast results in an annual
usage in the year 2010 of 67.9 BCF for electrical generation.These
annual average values as well as required peaking values and preliminary
Fairbanks residentia1/commercial usage estimates are presented in Table
A5-l.The assumptions utilized to generate Fairbanks gas demand are
presented in Chapter A6.0 The preliminary gas demand estimates presented
in Tab1 e A5-1 are presently being utilized for North Slope to Fai rbanks
small diameter gas pipeline design and the Fairbanks gas distribution
system design.When final estimates of gas demand are generated
appropriate refinements in gas pipeline and distribution system design
will be made.
2969A
AS-1
--------_...
TABLE A5-1
PRELIMINARY GAS REQUIREMENTS FOR POWER GENERATION
AND FAIRBANKS RESIDENTIAL/COMMERCIAL USE
IN THE YEAR 2010
USE
POWER GENERATION
Maximum Requirements*
(SCFM x 105)
Average Requirements**
(SCFM x 10 5 )
Average Annual Requirements
(BCFY)
LOW LOAD FORECAST
1.2
0.75
39.4
MEDIUM LOAD FORECAST
2.1
-1.3
67.9
['
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*Natural gas firing rate at peak demand based upon the following required
new gas fired generating capacity in the year 2010:741 MW for low load
forecast and 1278 MW for medium load forecast.
**Natural gas firing rate associated with total annual energy require-
ments:required new gas.fired energy requirements in the year 2010 are
3937 GWh for.low load forecast and 6788 GWh for medium load forecast.
A5-2
2969A
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5.3
44.7
Values represent "Extreme of Reasonable".
di scussi on.***
RESIDENTIAL/COMMERCIAL USE***
TOTAL AVERAGE ANNUAL REQUIREMENTS
(BCFY)
Average Annual Requirements
(BCFY)
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All three scenarios involve power plant facilities.The diversity of the
Alaskan environment requires each location to have different facility
design conditions.A North Slope facility must be built on steel piles
using modular construction in the manner of the existing Prudhoe Bay
facilities.Zone 1 earthquake design criteria will apply.For both
Fairbanks and Kenai,conventional construction methods for Zone.3
earthquakes are applicable,although Fairbanks also requires
consideration of greater temperature extremes.Air cooled condensers
will be used for steam cycles in order to avoid large cooling water flows
and problems associated with cooling water such as availability
limitations and intake icing.In many places in Alaska,evaporative
cooling water can also be a significant source of ice fog.
Engineering assumptions applicable to construction of a natural gas
pipeline to serve Fairbanks begin with the original ANGTS route using a
minimum separation of 200 feet with TAPS.This distance is commensurate
with that specified in the U.S.Department of the Interior grant of
right-of-way for ANGTS.43 Ebasco assumes the use of buried line which
requires the gas to be kept cooled to maintain the permafrost.An
initial line pressure of 1260 psig will be used in sizing the pipeline.
Because of the high carbon dioxide content of North Slope gas,the
Fairbanks scenario will include gas treatment for CO 2 removal at
Prudhoe Bay.The numb~r of compressor stations has not been determined..
yet,but will be established using standard computer programs.
Associated with the small diameter line to Fairbanks is a domestic gas
distripution system.Minimum inlet pressure will be 350 psig at gas
regulators,125 psig in the high pressure system to district regUlators,
and 60 psig in the distribution system to customers.Distribution lines
will be laid in public rights-of~ay at a depth of 3 feet using standard
2 inch 1 ines.
2969A
A5-3
For the purpose of slzlng the transmission lines from Prudhoe Bay to
Fairbanks and from Kenai to Anchorage,preliminary estimates of required
new generating capacity were made.These estimates,which accounted for
plant retirements,planned additions and energy demand forecasts,
resulted in required capacities for the year 2010 of approximately 700 MW
for the low demand forecast and 1400 MW for the medium demand forecast •.
ReQui red additions to and upgradi ng of the Anchorage-Fai rbanks Interti e
were designed to distribute capacity and ensure stability,and not to
optimize the entire Railbelt transmission system.Therefore,it was
assumed that 80 percent of the power that either arrives at Fairbanks
from Prudhoe Bay or is generated in the Fairbanks area,depending upon
the development scenario,is transmitted to Anchorage.Similarly,for
the Kenai scenario it was assumed that 20 percent of the power arriving
in Anchorage is transmitted to Fairbanks.The 4 to 1 split assumed is
based on the ratio of total utility sales in the Railbelt during 1980.11
For the Prudhoe Bay generation scenario,the transmission line from the
"-
North Slope to Fairbanks carries 100 percent of the generating capacity
through adverse environmental conditions.The contamination,due to
salt,dust,and moisture is severe from Prudhoe Bay to approximately 60
miles inland,requiring washing of insulators at the switchyard and on
that portion of the line to prevent flashover.Several combinations of
wind,temperature,and ice loading will he evaluated to determine
conductor design.Table AS-2 summarizes conductor loading conditions for
the Prudhoe Bay-Fairbanks transmission line.The stream crossing design
for the Yukon River requires special investigation.A DC alternative
will also be analyzed.With one AC line segment or one of the DC poles
out of service,the Prudhoe Bay-Fairbanks-Anchorage system will remain
stable in the steady-state at normal peak continuous loading.
The Fairbanks-Anchorage lines (330 miles)carry 80 percent of the
capacity for the Prudhoe Bay and Fairbanks generation scenarios,but only
20 percent for the Kenai scenario.The Fairbanks-Anchorage Intertie
which is presently under construction (170 miles at 345 kV AC)will be
2969A
AS-4
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CONDUCTOR LOADINGS FOR KENAI -ANCHORAGE TRANSMISSION LINE
CONDUCTOR LOADINGS FOR FAIRBANKS -ANCHORAGE TRANSMISSION LINES
TABLE AS-2
TRANSMISSION LINE CONDUCTOR LOADINGS
CONDUCTOR LOADINGS FOR PRUDHOE BAY -FAIRBANKS TRANSMISSION LINE*
Ice Thickness Wind Pressure
(radial inches)'(lb/sq ft)
100
60
30
100
60
30
100
60
30
Corresponding
Wi nd Speed
(miles per hour)
Corresponding
Wind Speed
(mil es per hour)
Corresponding
Wind Speed
(mil es per hour)
25
8
2.3
25
8
2.3
25
8
2.3
Wind Pressure
(l b/sq ft)
Wi nd Pressure
(l b/sq ft)
none
0.75
none
none
1.5
none
none
0.75
none
Ice Thi ckness
(radial inches)
Ice Thi ckness
(radial inches)
-60
32
86
-40
32
90
-60
32
86
Temperature
(OF)
Tempe ra ture
(OF)
Temperature
(oF)
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*All conductor loadings derived from published literature,evaluations
of environmental conditions,discussions with utility operations
personnel,and engineering jUdgement.
2969A
A5-5
fully extended (to 330 miles)in each scenario,and additional lines will
be considered,as required,to carry the projected loads.Only AC
operation will be considered.Conductor loading conditions for these
scenarios are also given in Table A5-2.
The Kenai generation scenario assumes construction of a Kenai-Anchorage
Intertie which would carry 100 percent of the load for about 150 miles.
Environmental conditions are moderate for this line including mild
contamination.Table A5-2 summarizes expected conductor loadings.
Design parameters for the AC switchyard at the generating station and
intermediate switching stations will assume breaker and a half bus
arrangement.
2969A
A5-6
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A6.0 ECONOMIC ASSUMPTIONS FOR FAIRBANKS NATURAL GAS DBMAND
Preliminary residential and commercial gas demand has been estimated for
Fairbanks so that the North Slope natural gas pipeline and the Fairbanks
natural gas distribution system conceptual design could proceed.
Numerous assumptions were made in order to develop the preliminary
forecast of natural gas demand.
Based upon an inventory of current fuel prices in Fairbanks (Table A6-1)
and a subsequent economic evaluation,the primary assumption is that
natural gas will be used exclusively for space and water heating;and
that it will compete directly with #2 distillate oil which is currently
used in most residential and commercial installations.It is assumed
that natural gas will not compete with coal,wood,or electricity for
either price or application reasons •
Given the age of the bui 1di ng stock in Fai rbanks,it is assumed that oil
fired equipment operates ~t a thenmal efficiency of 6~,and that
gas-fired units will have a thema1 efficiency of 74%.The cost of
conversion from oil to natural gas is assumed to be $600/unit,based upon
contacts with local oil dealers.There are about 23,000 residences in
Fairbanks to be heated.Average #2 distillate consumption is 1,500
ga1/yr,at a higher heating value of 138,100 Btu/gal.Natural gas for
distributio~is assumed to have a higher heating value of 1,000 Btu/ft3•
The commercial demand for natural gas is based upon an assumed
consumption rate of 160,000 Btu/ft2• A cOlIlJlercia1 building inventory
of 3.22 million ft2 of space exists in Fairbanks.
Given these assumptions,preliminary demand forecasts have been made.
They will be used,subsequently,in engineering analyses.
2970A
A6-1
TABLE A6-l
INVENTORY OF FUEL PRICES IN FAIRBANKS
A6-2
2970A
*Gplden Valley Electric Association.
**Fairbanks '-1unicipalUtilities System.
Fuel/Energy Type
#2 distillate
Residential Coal (Healy)
Wood (split and
del ivered)
Residential electricity
(GVEA)*
Residential electricity
(FMUS)**
Commercial electricity
(GVEA)
Commercial electricity
1981
Fuel Price
In Fairbanks
$1.23/gal
$61/ton
$lOO/cord
$0.1051 /kWh
$0.0906/kWh
$0.0922/kWh
$0.0770/kWh
Equivalent 1981 Price -
Efficiency Adjusted
(Simi 11 ion Bt u)
$14.84
$5.36
$9.83
$30.70
$26.55
$27.01
$22.56
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The extreme of reasonable value,used for sUbsequent engineering design
studies (capacity planning)is based upon replacing 63.3%of the #2
distillate demand in the year 2010.In this case the projections are as
foll ows:
The preliminary forecasts assume growth rates of 2%and 4.3%,per year,
in heating system demand.1 ,23 At a 2%/yr growth rate,the maximum
demand in the year 2010 will be 8.4 BCF,or 8.4 trillion Btu.At a
4.3%/yr growth rate,the upper 1imi t of demand in 201 0 ; s 15.9 BCF of
natural gas,or 15.9 trillion Btu.
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Growth Scenario
Low (2%/yr)
Medium (4.3%/yr)
Natural Gas Demand
(BCF)
5.3
10.1
Natural Gas Demand
(tri1li on Btu)
5.3
10.1
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These projections are based upon an initial break-even price between
natural gas and oil of $10.14/thousand cubic feet (MCF)for residential
applications,and $10.54/MCF for commercial applications (1981 prices).
After an assumed competitive response to natural gas by the ~orth Pole
Refinery,these break-even prices may drop to $9.07/MCF for residential
users and $9.43/MCF for commercial users (also 1981 prices).
These preliminary demand estimates will be expanded upon,and refined,
for the final report.Such refinement will be based upon additional data
now being developed.
2970A
A6-3
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A7.0 OTHER CONSIDERATIONS
·A7.1 POWERPLANT AND INDUSTRIAL FUEL USE ACT
A new gas or oil fired electric generating facility using North Slope
natural gas will be subjectto the provisions of the Power Plant and
Industri al Fuel Use Act of 1978 (FUA).Pursuant to section 201 of the
FUA,oil and/or natural gas may not be used as a primary energy source in
a new electric power plant unless special permission is obtained.
Special permission is granted by the Economic Regulatory Administration
(ERA)within the Department of Energy (DOE)in the form of an exemption
from the FUA prohibition of the use of natural gas.A statutory
exemption for Alaskan utilities was recently (December 30,1982)signed
into law by President Reagan as part of the fiscal 1983 Department of the
Interior Appropriations Bill (H.B.7356).The exemption,however,does
not apply to any new electric power plant which would use natural gas
produced from the Prudhoe Bay unit.
Prior to this exemption,a ver,y thorough analysis of the Act and
potential exemptions applicable to Alaskan utilities were provided as an
appendix to a report submitted to the Legislative Affairs Agency of the
Alaska State Legislature by G.Erickson.28 The analysis concluded that:
It appears there do exist grounds under which any of the
utilities along the Rai1belt might qualify for a permanent
exemption from the requirement of the Act to use coal or other
alternate fuel.Such grounds might include (a)lack of
alternate fuel supply for the first 10 years of the useful 1ife
of the facility;(b)lack of alternate fuel at a cost which does
.not sUbstantially exceed the cost of imported oil;(c)site
limitations (this seems less likely);(d)inability to comply
with applicable environmental requirements,and (e)inability to
use alternative fuel because of a State or local requirement.
It should he cautioned that this analysis has no legal implications and
that a final decision regarding an exemption will not be known until an
application is submitted to the ERA.For the purposes of this study,
however,the FUA is not considered prohi biti ve of development of new
electric power plants using Prudhoe Bay unit natural gas.
2973A
A7-1
A7.2 COST OF NATURAL GAS
Cost of North Slope gas at the point of use is fundamental to scenario
planning and the ultimate determinant of project viability.The
constraints,technical and institutional,to determining a reliable cost
have prevented,in large part,the implementation"of all previou·s
proposal s to use North Slope gas,and no definitive cost can be presented
here.However,upper limits to the wellhead cost of North Slope gas can
be established through comparison to alternative fuel costs by
subtracting engineering estimates of gas upgrading and transmission
(;-nc1uding distribution)system costs.Essentially all costs incurred
between the well and the consumer must be so accounted for.Thus,by
"backing out"the wellhead cost as a remainder,it can be determined
whether gas can compete with alternative fuels.
It has been determined,by Alaska Economics,Inc.,that natural gas will
compete almost exclusively with #2 distillate oil.The reasons,and
price comparisons,are discussed in Chapter A6.0 of this report.
Presently,#2 oil costs $14.84 per million Btu (efficiency adjusted)in
Fairbanks.In the simplest case,any combination of gas wellhead cost
plus upgrading and transportation cost (including distribution cost)plus
system conversion costs that is significantly less than $14.84 per
million·Btu (net heat delivered to the house)means gas can compete with
oil in Fairbanks.Ebasco·s approach will be to detennin~all
conditioning,transportation and system costs to allow the wellhead cost
of North Slope gas to be derived.The desired result of this calculation
is to obtain a value which indicates that for any given the cost,North
Slope gas will be either competitive or non-competitive (in price)with
alternative fuels.The only basis for estimating the cost of North Slope
gas at this time is the cost for gas used to operate the Trans-Alaska
Pipeline System stations.The delivered cost varies somewhat in time,
but is about $1.86 per million Btu.
Facility costs and derived wellhead values will also provide information
essential in the development of any comparative power costs between
alternative generation technologies.Such comparisons are outside
Ebasco·s scope of work,but can be considered as a logical extension
which may be performed by the Alaska Power Authority.
2973A
A7-2
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BIBLIOGRAPHIC MATERIALS FOR APA
NORTH SLOPE NATURAL.GAS FEASIBILITY STUDY
1.Acres American,Inc.,1982."Susitna Hydroelectric Project -
Feasibility Report -Volume I,Engineering and Economic Aspects,
Sections 1-8,Final Draft ll
•Alaska Power Authority.Anchorage,
Alaska.
2.Acres American,Inc.,1982."Susitna Hydroelectric Project-
Feasibility Report -Volume I,Engineering and EConomic Aspects,
Sections 9-19,Final Draft ll
•Alaska Power Authority.Anchorage,
Alaska.
3.State of Alaska,Dept.of Environmental Conservation,1982.
1 set containing:
1.Waste discharge permit application form
2.Copies of current waste discharge permits for
a.domestic wastewater to lands or waters of the state
b.wastewater from a desalination plant
c.discharge of drill muds and cuttings onto sea ice
d.oily waste injection facilities
4.State of Alaska,Dept.of Transportation and PUblic Facilities
Planning and Programming Map,PUblications by the Southeast Region
Mapping and Graphics Section.
5.State of Alaska,Division of Economic Enterprise,January 1978,
IIFairbanks,An Alaskan Community Profile"Fairbanks Chamber of
Commerce,City of Fairbanks,State of Alaska Division of Economic
Enterprise.
6.State of A1 aska,Di vi sion of Ec onomic Enterprise,March 1978,IINorth
Pole,An Alaskan Community Profile"City of North Pole,State of
A1 ask a Di vi si on of EC onomi c Enterpri se.
2972A
1
7.State of Alaska,Division of Economic Enterprise,November 1979,
II Ba rro\'1,An Alaskan COl!lJlunity Profi1e ll North Slope Borough,State of
Alaska Division of Economic Enterprise.
8.A1 aska Interi or Resources Co.,Inc.,October 1981 I~Methano1 /Energy
Complex,Fairbanks,Alaska -Executive Summary and Preliminary
Financing Plan ll Foster and Marshall,Inc.,Seattle,Washington.
9.Alaska Interior Resources Co.,Inc.,1981,IIMethano1 -Report to the
State of Alaska ~Feasibility of a Petrochemical Industry,Vol.4 of
1011 The Dow-Shell Group,Anchorage,Alaska.
10.A1 aska In teri or Resources Co.,Inc.,1981,II Energy Study -Report to
the State of Alaska -Feasibility of·a Petrochemical Industry,Vol.
80f 1011 The [Jo",-Shell Group,Anchorage,Alaska.
11.Alaska Oil and Gas Conservation Commission,1982,111981 Statistical
Report ll State of A1Slska,Alaska Oil and Gas Conservation Commission,
Anchorage,Al aska.
12.Alaska Oil and Gas Association,1~82,IIAlaska Oil and Gas Industry
Facts ll Alaska Oil and Gas Association,Anchorage,Alaska.
13.U.S.Dept.of Energy,Alaska Power Administration,February,1.982.
IIUpdate of 1972 North Slope Transmission Study II ,U.S.Dept.of
Energy,Alaska Power Administration.
14.Al askan Northwest Natural Gas Transportation Company,II Al aska
Natural Gas Transportation System,Al aska Segment -48 11 Natural Gas
Pipeline (Prudhoe Bay to Canadian Border).
15.Alyeska Pipeline Service Co.,no date,liThe Trans Alaska Pipeline ll
Alyeska Pipeline Service Co.,Anchorage,Alaska.
2972A
2
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16.Alyeska Pipeline Service Co.,no date,IIPump Station Oneil Alyeska
Pi peli ne Service Co.,Anchorage,Al aska.
17.Alyeska Pipeline Service Co.,no date,"Operating the Trans Alaska
Pipeline ll Alyeska Pipeline Service Co.,Anchorage Alaska.
18.Alyeska Pipeline Service Co.,1980,"Trans Alaska Pipeline Atlas -
Prudhoe Bay to Valdez ll Alyeska Pipeline Service Co.
19.ARCO Alaska Inc.,1981,"ARCO in Alaska"ARCO Alaska Inc.
20.ARCO Alaska Inc.,1982,IIWelcome to the North Slope"ARCO Alaska Inc.
21.Connie C.Barlow,March 1980,IlNatural Gas Conditioning and Pipeline
.Design"Arlon R.Tussing and Associates,Inc.for State of Alaska,
Dept.of Na tura 1 Resou rce's.
22.Battelle Pacific Northwest Laboratories,March 1977."Alaskan North
Slope Royalty Natural Gas -An Analysis of Needs and Opportunities
for In-State Use -Prel imi nary Draftll
•For Al aska Dept.of Commerce
and Economic Development,Division of Energy and Power Development.
23.Battelle Pacific Northwest Laboratories,February 1982.IIRailbelt
Electric Power Alternatives Study:Evaluation of Railbe1t Electric
Energy Pl ans -Conment Draft".For Office of the Governor,State of
Alaska Division of Policy Development and Planning.
'24.K.Brown and C.Barlow,June 1978,"An Overview of Natural Gas and
Gasline Issues"Legislative Affairs Agency.
25.COlilJ1onwealth Associates,Inc.,March 1982.IIEnvironmenta1
Assessment Report -Anchorage-Fairbanks Transmission Intertie ll
•
Alaska Power Authority,Anchorage,Alaska.
2972A
3
r
26.Ebasco Services Incorporated,April 1981.IlRailbelt Electric Power ('
Alternatives StuQy -Technology Assessment Profile Report -An l
Overvi ew ll
•For Battelle Paci fi c No rthwes t Labs.
27.Electric Power Research Institute,October 1978.IlCosts and
Benefits of Ove.r/Under Capacity in Electric Po\~e·r System Planning"
prepared by Decision Focus,Inc.Palo Alto,.CA for EPRI,EPRI
EA-927.
28.Gregg K.Erickson,March 1981.II Natural Gas and Electric Power:
Alternatives for the Railbeltll prepared for the Legislative Affairs
Agency,Alaska State Legislature.
29.Federal Power Commission Staff,April 1976.IIA1aska Natural Gas.
Transportation Systems,Final Environmental Impact Statement,Volume
I,General Economic Analysis Comparison of Systems ll for E1 Paso
Alaska Company Dockett No.CP 75-96 et a1.Federal Power Commission.
30.ICF Incorporated,Ed.,S~ptember 1982,IIAlaska Natural Gas
Development:An Economic Assessment of Marine Systems ll ICF
Incorporated for Maritime Research and Development,Office of
Maritime Technology.
31.Kidder,PeaboQy and Co.Inc.,March 1982 IlReport to the Governor1s
Task Force on State of Alaska Participation in Financing the Alaskan
Segment of the Al aska Natural Gas Transportation System IIKi dder,
Peabody and Co.Inc.New York,New York.
32.L;ndah1,Dav;d,November 1981,liThe Methanol A1 ternative to the
Al aska Natural Gas Transportati on System ll
,Congressi ona 1 Resea rch
Service,The Library of Congress,Environment and Natural Resources
PoliCY Division,Washington,D.C.
2972A
4
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I
L
33.H.Malone and B.Rogers,Chairmen,Sept.1980,"Final Report House
PO~/er A1 ternatives Study COrmJittee,Alaska State Legis1ature"State
of Alaska.
34.K.M.O·Connor and P.O.Dobey,January 1977."Analysis of Prudhoe
Bay Royalty Natural Gas Demand and the Proposed Prudhoe Bay Royalty
Natural Gas Sa1e ll
•State of Alaska,Dept.of Natural Resources,
Di vi si on of Mi nera1 s and Energy Management,Anchorage,A1 aska.
35.Ralph M.Parsons Co.,September 1978 "Sa1es Gas Conditioning
Facilities,Prudhoe Bay,Alaska -Volume I,Summary"Ralph M.
Parsons Co.,Job No.5795-1
36.Robert W.Retherford Associ ates,March 1977.II North Slope Natural
Gas Transport Systems and thei r Potential Impact on Elect"'i c Power
Supply and Uses in Alaska".Robert W.Retherford Associates,
Anchorage,A1 ask.a.
37.Scott,Michael J.et al,January 1982,"Alask.a -Historical and
Projected Oil and Gas Consumption II ,Battell e Pacifi c Northwest
Laboratories,Richland,Washington,for State of Alaska,Department
of Natural Resources,Division of Minerals and Energy Management.
38.Sl avi ch,A.L.,Jacobsen,J.J.,November 1982,liRa il be 1t El ectri c
Power Alternatives Study;OVER/UNDER (AREEP VERSION)Model Users
Manual -(Volume XI -Draft)1I Battelle Pacific Northwest
Laboratories,Richland,Washington,for Office of the Governor,
State of Alaska,Division of Policy Development and Planning and the
Governor·s Policy Review Committee.
39.Smith,Daniel W.,Ed.,Januar,y 1977,Proceedings:Symposium on
Utilities Delivery in Arctic Regions;Edmonton,Alberta.Report EPS
3-WP-77-1.
2972A
5
LIST OF CONTACTS (Continued)
Peter Christensen Brown &Root,Inc.
Name
R.H.Dempsey
Mead Treadwell
Don Hale
Don Wold
2910A
Organization/Agency
Al aska Interior Resources
Company,Vice President
Governor's Economic
Committee on Alaska Natural
Gas,Executive Director
Brown &Root,Inc.Manager
Pipeline Engineering
Department
Royalty Oil and Gas
Advi sory Board
6
Reason for Contact
Methanol Plant plans for
Fairbanks,gas and electricity
use.
Governor's Economic Committee
on Alaska Natural Gas study,
"was te"gas compositi on,"was te"
gas volumes,location of all-
Alaska pipeline route and
conditioning plant.
Governor's Economic Committee
on Al aska Natural Gas study,
"waste"gas composition,"was te"
gas volumes,location of all-
Alaska pipeline route.and
conditioning plant.
Governor's Economic Committee
on Alaska Natural Gas study,
"waste"gas composition,"waste"
gas volumes,location of all-
Alaska pipeline route and
conditioning plant.
Governor's Economic Committee
on Al aska Natural Gas study,
"waste"gas composition,"waste"
gas volumes,location of all-
Alaska pipeline route and
conditioning plant.
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48.Uni versity of Al aska,Arcti c Envi ronmenta 1 Infonnati on and Data
Center,July 1978,"Deadhorse"U.S.Dept.of Interi or.
49.University of Alaska,Arctic Environmental Infonnation and Data
Center,July 1978,"Nuiqsutll U.S.Dept.of Interior.
50.University of Alaska,Arctic Environmental Infonmation and Data
Center,July 1978,liThe Region"U.S.Dept.of Interior.
51.University of Alaska,Arctic Environmental Infonnation and Data
Center,July 1978,"Anaktuvuk Pass"U.S.Dept.of Interior.
52.University of Alaska,Arctic Environmental Infonnation and Data
Center,July 1978,I'Barrow -Sheet I II U.S.Dept.of Interi or.
53.H.K.Van Poollen and Associates,Inc.,March 1980,
"Three-Dimensional Reservoir Study,Sadlerochit Fonnation,Prudhoe
Bay Field"State of Alaska,Oil and Gas Conservation Commission,
Anchorage,Alaska.
2972A
7
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ADDENDUM B
LIST OF CONTACTS
Darrell Jordan ARCO-A1aska
NORTH SLOPE GAS FEASIBILITY STUDY
LIST OF CONTACTS
[
[
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PL;
Name
Ben Ball
Bob Crosky
Loren Doug1 as
William Friar
Organization/Agency
ARCO-A1aska
ARCO,Vice President
Alaska Affairs
ARCO-A1aska
ARCO-A1aska
Reason for Contact
Gas composition at Central
Compressor Plant.
Gas use and facilities tour.
AReo's electrical system.
General North Slope information,
facil i ti es tour.
Foundation design practice-North
Slope.
1
Archie Walker ARCO-Alaska
Richard Blumer SOHIO
29l0A
Gas use and plant tour.
ARCO's electrical system.
Facilities tour.
North Slope construction and
operation considerations.
General North Slope information,
faci1 ities tour.
Fairbanks'electrical system
and climatological data.
Fairbanks'electrical system
and climatological data..
Weight &size restrictions for
barged modules to North Slope.
Foundation design practice-North
Slope..
SOHIO's North Slope electrical
system and power plant design.
Gas use and plant tour.
ARCO-A1aska
Charles Elder SOHIO,Vice President
Al aska Affairs
Mary Jane Little ARCO-A1aska,
Administrative Supervisor
Paul Norga'rd ARCO-A1aska,President
Brad Spencer ARCO (Pasadena)
Richard Lipinski SOHIO,Manager
Construction Support
Paul Martin SOHIO,Vice President
Operations
Larry Co1p Fairbanks Municipal
Utilities System
Alan Martin Fairbanks Municipal
Utilities System
Jim Moreland
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LIST OF CONTACTS (Continued)
Name Organization/Agency
George Ott Fairbanks Municipal
Utilities System,Public
Services Director
William Per~Fairbanks Municipal
Utility System,General
Manager
Gary Rice Fairbanks Municipal
Utilities System
Keith Sworts Fairbanks Municipal
Utilities Systems
Harold Alexander Alyeska Pipeline Co.
Reason for Contact
General information.Chena
plant design.
Power requirements and plant
tour.
General Civil Information.Chena
Pl ant Desi gn.
General utility statistics -
fuel consumption by type;steam
and electric baseload data,
rate structure,expansion plans.
Chena plant design,facility
tour.
General information,facility
tour.
c
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Alyeska,Technical Manager,Proximity to TAPS,right-of-
ANGTS Relations way constraints.
Frank Fi sher
Jim Hdrley
Eldon Johnson
Joe Pitman
John Ratterman
Andrew Sma rt
Jim Weiss
Bela Gevay
Bonnie Rappaport
29l0A
Alyeska,Al aska Manager,
ANGTS Relations
Alyeska Pipeline Co.
Aleyska,Pump Station 1
A1yeska,Manager Publ ic
Affairs
Alyeska,Corrosion
Engineer
Artic Environmental
Informati on Data Center
Private Consultant
MAPCO (Parent of North
Pole Refine~)
2
Proximity to TAPS,right-of-
way constrai nts.
Climatological data.
Pump station operation.
General information,facility
tour.
Effect of HVDC on TAPS.
Climatological data.
Prudhoe Bay e1ectr.network data
Current fuel oil prices,
Residential Btu requirements.
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LIST OF CONTACTS (Continued)
Reason for Contact
Energy needs.
Potential fuel cell use in
Fai rbanks.
Power plant sta~tistics,fuel .
consumption by type;number and
area of buildings served for
both steam and electricity peak
and baseload data and expansion
pl ansa
Potential gas use.
Organization/Agency
Uni versity of Al aska
Plant Engineer
University of Alaska
(Fairbanks)Power Plant
Operator
Name
Gerald England
College Utilities
General Manager
Dr.James Ma10sh University of Alaska
(Fairbanks)Director
Dept.of Transportat;'on
Fuel Cell Study
George Gordan
Staples Brown
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Energy needs.
Right-of-way corridor.
Annual energy reports,energy
balance report,fuel source &
end use statistics.
3
City of Fairbanks,Right-
of-Way Agent
Ft.Wainwright Facility
Engineer
Energy Specialist -
Communi ty Resource Center,
Fa i rbanks
29l0A
Craig Helmuth
University of A1 aska Appliance stock and saturation
(Fairbanks)Cooperative data.
Extension Agency -Energy
Special ist
Mayor,North Star Borough Electricity and gas use.
Assessor,North Star Gas and electricity use and
Borough land values.
Director of Planning Gas and electricity use.
North Star Borough
Fonner Mayor,North Star Gas use.
Borough
Richard Van Orman Deputy Director of Planning Gas distribution right-of-way.
North Star.Borough
Robert 5i eforts
Bill Allen
Ca ry Brewster
Dave Braden
John Weaver
John Carlson.
Scott Burgess
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LIST OF CONTACTS (Continued)
Name
Major Terry Lane
Jan Bre\ter
John Vdradi
Wally Droz
Len McLean
Tim Wallace
A.W.Baker
Organization/Agency
Elmendorf AFB
Residential Energy Audit
Program
Shawani gan Engi neeri ng
City Manager,Fairbanks
Pacific Alaska LNG
Al aska Affai rs Manager
Doyan,Inc.,President
Golden Valley Electric
Association
Reason for Contact
Federal building fuel use in
Fairbanks.
Energy audit data base,
Fairbanks.
Prudhoe Bay electrical network
data.
Gas distribution system.
Status of LNG plant,gas
development plans,gas
prices.
Gas distribution.
North Pole and Fairbanks plant
design,tour.
['
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Ron Hansen
Eri c Haemer
Dan Li ndsey
W.McKinney
f4ark All i sson
Bruce Pasternak
Ben Schlesinger
Kathy Thomas
29l0A
Golden Valley Electric General utility statistics -
Association fuel consumption by type;steam
and electric baseload data,
rate structure,expansion plans.
Chugach Electric Beluga PO\'Ier Plant design,tour.
Association,Inc.Division
Manager-Systems Planning
Chugach Electric Beluga Power Plant design,tour.
Association,Inc.
G.E.A.,san Diego Air-cooled condenser design
information.
General Electric Co.Gas turbine data.
Seattle,Washington
Booz-Allen &Hamilton,Inc.To discuss DNR North Slope gas
Vice President,Energy and study,coordinate study efforts.
Environmental Division
Booz-Allen &Hamilton,Inc.To discuss DNR study,coordinate
Principal study efforts.
Booz-Allen &Hamilton,Inc.To discuss DNR study,coordinate
study efforts.
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LIST OF CONTACTS (Continued)
State of Alaska,~partment Gas revenues.
of Revenue
Reason for Contact
Constraints on use of North
Slope gas.
Constraints on use of North
Slope gas.
Organization/Agency
Attorney General's Office,
Supervising Attorney
State of Alaska,Attorney
General
State of Alaska,Department To discuss DNR study,coordinate
of Natural Resources,study efforts.
Budget &Management
State of Alaska,Department Gas composition,availability,
of Natural Resources,constraints and prices.
Special Assistant to the
COnuDissioner
State of Alaska,Department Gas revenues,production.
of Revenue,Petroleum
Revenue Division
State of Alaska Department Status of ANGTS,SPCO Library,
of Natural Resources,right-of-way constraints.
State Pipeline Coordinator
State of A1 aska,Department Gas production.
of Natural Resources.
State of Alaska,Department Determine gas supplies,
of Natural Resources,Oil constraints,availability.&Gas Conservation
Commission,Commissioner
State of Alaska,Department Determine gas supplies,
of Natura1'Resources,Oil constraints,availability.
&Gas Conservation
Commission,Commissioner
State of Alaska,Department Determine gas supplies,
of Natural Resources,Oil constraints,availability.
&Gas Conservation
Commission,Commissioner
Alvin G.Ott
Name
R.Maynard
Vi nce Wri ght
Ed Park
Ronald Ripple
B.Hennan
Chuck Logsdon
Mark Wittow
L.Smith
C.V.Chatsworth
H.Kugler
2910A
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LIST OF CONTACTS (Continued)
Peter Christensen Brown &Root,Inc.
Name
R.H.Dempsey
Mead Treadwell
Don Hal e
Don Wo1 d
2910A
Organization/Agency
Alaska Interior Resources
Company,Vice President
Governor1s Economic
Committee on Alaska Natural
Gas,Ex ec uti ve Di rector
Brown &Root,Inc.Manager
Pipeline Engineering
Department
Royalty Oil and Gas
Advi sory Board
6
Reason for Contact
Methanol Plant plans for
Fairbanks,gas and electricity
use.
Governor1s Economic Committee
on Alaska Natural Gas study,
Ilwaste ll gas compositi on,IIwas te ll
gas volumes,location of a1l-
Alaska pipeline route and
conditioning plant.
Governor1s Economic Committee
on Alaska Natural Gas study,
IIwas te ll gas compositi on,II was te ll
gas volumes,location of a1l-
Alaska pipeline route and
conditioning plant.
Governor1s Economic Committee
on Alaska Natural Gas stUdy,
IIwas te ll gas compositi on,IIwas te ll
gas volumes,location of a11-
Alaska pipeline route and
conditioning plant.
Governor1s Economic Committee
on Alaska Natural Gas study,
.lIwas te ll gas composi ti on,IIwas te ll
gas volumes,location of a1l-
Alaska pipeline route and
conditioning plant.
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APPENDIX 8
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APPENDIX B
REPORT
ON
SYSTEM PLANNING STUDIES
DECEMBER 1982
B2.1 Technology Review ••.••••••••
B2.2 Derivation of New Capacity Requirements •
B2.3 Application of Technologies to Requirements •
B2.4 Economic Evaluation ••••
. . ... . . ... . . .. .. ... .
B4.1 Technical Assumptions and Data ••.
84.2 Economic Assumpti ons and Input Data
Page
Bv
B1-1
.B2-1
B2-1
B2-1
B2-2
82-3
B3-1
B3-1
B3-2
B3-3
B4-1
84-1
B4 ...5
B5-1
B5-1
B5-1
65-5
B5-24
B6-1
B6-1
B6-1
B6-2
B7-1
. ....
..
TABLE OF CONTENTS
. . ... . . . . ... .
Bi i
B5.1 System Capacity Review.
B5.2 Selection of Unit Sizes
B5.3 New Capacity Requirements •
B5.4 Economic Analyses and Results
B6.1 Economic Conc1u~ion
86.2 Technical Conclusion
B6.3 Recommendation
B3.1 Simple Cycle Technology •
B3.2 Combined Cycle Technology.
B3.3 Gas Fired Boilers •••
3105A
B7.0 REFERENCES
B6.0 CONCLUSIONS AND RECOMMENDATIONS
B5.0 RESULTS •.••••.•••
B3.0 TECHNOLOGY REVIEW •••••••
B4.0 ASSUMPTIONS AND INPUT DATA .••
B1.0 INTRODUCTION.
B2.0 METHODOLOGY •
SLMMARY ••
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Tabl e Number Title Page
L84-1 CAPACITIES AND HEAT RATES FOR SIMPLE
AND COMBINED CYCLE UNITS B4-2
B4-2 ASSUMED CAP !TAL COSTS B4-4 [
B4-3 ECONOMIC ASSUMPTIONS B4-6 l-
B5-1 EXISTING CAPACITY,PLANNED ADDITIONS,
UNIT RETIREMENT SCHEDULE,AND PEAK DEMANDS B5-2 rB5-2 CAPACITY REQUIREMENTS AT PLANNING RESERVE
MARGINS -LOW LOAD FORECAST B5-3
B5-3 CAPACITY REQUIREMENTS AT PLANNING RESERVE [
MARGINS -MEDIUM LOAD FORECAST 85-4
B5-4 NEW CAPACITY ADDITIONS -LOW LOAD FpRECAST ['NORTH SLOPE 85-6
85-5 NEW CAPACITY ADDITIONS -LOW LOAD FORECAST [
FAIRBANKS 85-7 L
B5-6 NEW CAPACITY ADDITIONS -LOW LOAD FORECAST [KENAI B5-8
B5-7 NEW CAPACITY ADDITIONS -MEDIUM LOAD [FORECAST -NORTH SLOPE 85-9
85-8 NEW CAPACITY ADDITIONS -MEDIUM LOAD
FORECAST -FAIRBANKS B5-10 C
B5-9 NEW CAPACITY ADDITIONS -MEDIUM LOAD
FORECAST -KENAI 85-11 L85-10 PRESENT WORTH OF COSTS -0%ESCALATION B5-26
CB5-11 PRESENT WORTH OF COSTS -1%ESCALATION 85-27
,
B5-12 PRESENT WORTH OF COSTS -2%ESCALATION 85-28
85-13 PRESENT WORTH OF COSTS -3%ESCALATION B5-29 [
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SUMMARY
Ebasco prepared this report to identify from both an economic and
technical viewpoint,the power generating technology and scale which
.best satisfy the requirements associated with Railbelt electric.
capacity demand forecasts.The report also identifies on a preliminary
basis the year of installation of each new generating unit to be added
to the system through the year 2010.
As discussed herein,a 220 MW (ISO conditions)combined cycle plant
size is considered optimum for development for the Fairbanks and Kenai
scenarios for reasons of flexibility,economics,and number of units to
be installed.In the case of the North Slope,simple cycle combustion
turbines are preferred.Each 220 MW combined cycle plant is cemprised
of two 77 MW gas turbines and a 66 MW.steam turbine.Si·mple cycle
units are 77 MW gas turbines.These capacities are at ISO conditions,
as discussed within the text;actual capacities are higher at specific
locations due to temperature differentials.The staging plan
recommended for each location and technology is summarized below:
LOW LOAD FORECAST MEDIUM LOAD FORECAST
YEAR NORTH SLOPE FAIRBANKS KENAI NORTH SLOPE FAIRBANKS KENAI
1993 0/0 0/0 0/0 91/91 86/86 84/84
1994 0/0 0/0 0/0 0/0 0/0 0/84
1995 0/0 0/0 0/0 91/182 86/172 84/168
1996 91/91 86/86 84/84 91/273 70/242 69/237
1997 91/182 86/172 84/168 91/364 172/414 168/405
1998 0/182 0/172 0/168 91/455 70/484 69/474
1999 0/182 0/172 0/168 0/455 0/484 0/474
2000 0/182 0/172 0/168 91/546 86/510 84/558
2001 0/182 70/242 69/237 0/546 0/570 0/558
2002 91/223 86/328 84/321 182/728 156/726 153/711
2003 91/364 0/328 0/321 0/728 0/726 84/795
2004 0/364 86/414 84/405 91/819 86/812 84/879
2005 182/546 70/484 69/474 182/1001 156/968 153/1032
2006 0/546 86/570 84/558 91/1092 86/1050 84/1116
2007 0/546 0/570 0/558 91/1183 86/1140 0/1116
2008 91/637 86/656 84/642 91/1274 70/1210 69/1185
2009 0/637 0/656 0/642 0/1274 86/1296 84/1269
201 0 91/728 70/726 69/711 91/1365 86/1382 84/1353
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B1.0 INTRODUCTION
The use of North Slope natural gas,or any other fossil fuel,for
generating power to meet the demand for electrical energy in the
Rai1be1t region requires careful system planning to optimize the
addition of new generation capacity.Capacity additions must be sized
and scheduled to meet increased demand for energy,replace older units
as they are reti red,and provide a system reserve margi n that assures
an un~nterrupted power supply.
This system planning studY utilizes data from the Acres American Inc.
(1981)and Bal1el1e Pacific Northwest Laboratories (1982)studies to
detenmine demand levels for energy,an acceptable range for Rai1belt
system reserve margins,and the capacity deficits that must be...
satisfied with new electrical generation.This capacity deficit
forecast is then used to develop various scenarios for addition of new
capacity from one of the available technologies capable of utilizing
North Slope natural gas.
Planning for the growth of the system requires selection of a type or
types of technology to be used for the new generation capability.
Selection of the optimum technology(s)is a function of the fuel type
and cost,technology efficiency,required capacity additions,capital
and operating and maintenance costs,and licensing and cC?nstruction
times.'The purpose of this system planning study is to evaluate and
recommend,from both an economic and a technical viewpoint,the
techno1ogy(s)and scale which best satisfy capacity,reliability and
least cost criteria.Further,the study recommends on a pre1imina~
basis the year of installation of each new generating unit to be added
to the system through the year 201 O.
This System Planning Report is the second of a series in developing a
feasibility level assessment regarding the use of North Slope natural
gas for power generation in the Rai1be1t and for residential/commercial
heating uses in Fairbanks,and as such provides reqUired data necessa~
for the completion of the overall feasibility study.The results of
3105A
81-1
this analysis assure that the feasibility study analyzes scenarios
which meet the needS of the Rai1be1t region.The specific outputs
which will be used to complete the balance of the feasibility study are
selection of the optimum power generating technology and unit size,and
proper~iming of unit addition to maintain reserve margins,thus
providing the bases for facility design,siting,cost estimating,and
environmental assessment.
3105A
81-2
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B2.0 METHODOLOGY
B2.1 TECHNOLOGY REVIEW
It was detenmined that there are three applicable technologies that
could be used to generate electricity by using North Slope gas.These
are simple cycle gas turbines,combined cycle installations (gas
turbines with heat recovery boilers and steam turbines),and gas fired
boilers with steam turbines.Each technology was reviewed to
detenmined the state-of-the-art,efficiency,size,availability,
constructability,and conceptual design criteria.This review data was
then evaluated in light of the three locations considered in the
feasibility stuqy,(i.e.,the North Slope,the Fairbanks area,and the
Kenai area)to detenmine technology appl icabi 1ity.Fi nally,
advantages,disadvantages and potential problems associated wit~each
technology in each location were detenm1ned and evaluated.
B2.2 DERIVATION OF NEW CAPACITY REQUIREMENTS
Data from two sources were used to develop the new capacity
requirements for the Railbelt region.Reserve margins and low load
growth forecasts for the region were derived from Battelle's Evaluation
of Railbelt Electric Energy Plans -Comment Draft (Battelle 1982).
Medium load growth·forecasts,planned power plant additions for the
immediate future,and the retirement schedule for existing Railbelt
generating capacity were obtained from the final draft Susitna
Hydroelectric Project Feasibility Report (Acres American Inc.1981).
The reserve margins and load forecasts were used to establish maximum
required capacities for each year through the year 2010.Existing
capacity plus planned additions and retirements were used to establish
the balance of existing capacity for each year.These two derived data
sets were then used to establish the required new capacity for each
year.
3105A
B2-1
82.3 APPLICATION OF TECHNOLOGIES TO REQUIREMENTS
The results of the technology review provided the data necessary to
project the units of new generation capacity required to satisfy
electrical demand.The size of units for addition were selected based
on least capital cost and the range of unit sizes which satisfied the
new capacity requirements without greatly exceeding maximum reserve
requirements.These unit sizes were then applied to create scenarios
for new generating capacity.Of the three technologies previously
mentioned (simple cycle,combined cycle and gas boiler)two were found
to be acceptable for applicQtion in this study.Those two are simple
cycle and combined cycle gas turbines.The direct fired gas
boiler/steam turbine was jUdged to be non--competitive due to high
capital costs which are not offset by any significant advantage in
either heat rates or operating and maintenance costs.Operating costs
advantages which might be realized with this technology in very large
plants are not available in the unit size range (150-350 MW)being
consi dered here.
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3105A
Locale!!
Temp 2/Gas Turbine Steam Turbin~Heat Consumption
OF Capacity Change Capacity Change Change
North Slope 90 +18.2%+3.5%+14.6%
Fairbanks 26 0 +12.0%+2.2%+9.6%
Kenai 33 0 +9.5%+1.7%+7.5%
The two remaining technologies with the two different load growth
forecasts resul tin four basi c scenari os.It is then necessary to
consider the effect of ambient conditions on capacity and efficiency at
each of the three potential scenario locations.The primary factor
affecting operation is temperature.After reviewing the effects of the
average annual temperature on capacity and efficiency at each location,
it was decided that the locales must be considered separately.The
following table shows the effect of temperature on capacity and
efficiency.
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Changes are based on International Standards Organization (ISO)
conditions for base loaded units,which are 59 0 F and sea level.
Average annual temperature.
Applies to steam turbines as part of combined cycle only.
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These three sets of conditions combined with the four basic scenarios
result in 12 locale specific scenarios for evaluation and comparison.
As input for economic evaluation,the total energy (GWh)generated for
each scenario in each year was also developed.
82.4 ECONOMIC EVALUATION
Developed scenarios were analyzed to determine which resulted in the
lowest overall cost on the basis of present worth of costs.In order
to perform this analysis it was necessa~to develop capital,operating
and maintenance,and fuel costs for each technology and to calculate
the total energy generated in each year for each scenario.The
economic model yielded the total cost of each scenario in 1982 dollars.
3l05A
82-3
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B3.0 TECHNOLOGY REVIEW
Three mature and proven technologies were reviewed for application to
the Railbelt.They are Simple Cycle Gas Turbines,Combined Cycle
Systems (Gas Turbine with Heat Recovery Boilers and Steam Turbines),
and Gas Fired Boilers with Steam Turbines.
It is common industrial practice to quote heat rates for oil and gas
fired simple cycle turbines as a function of the lower heating value of
the fuel.However,fuel is purchased by higher heating value,and
other technologies'heat rates are in tenms of higher heating values.
In this report heat rates quoted and used for analysis are based on
higher heating values.Where applicable,lower heating value heat
rates are given in parentheses.
B3.1 SIMPLE CYCLE TECHNOLOGY
Simple cycle gas turbines are available from several vendors ina
variety of sizes.Review of the designs,lead times for licensing and
construction,and constructabi1ity of the gas turbines led to the .
conclusion that they would be applicable to all three potential
locations considered in the feasibility study.Heat rates for these
units vary from 11,800 to 13,000 Btu/kWh (10,600-11,700 Btu/kWh-LHV).
Pre-constructed simple cycle units for the North Slope can be shipped
by barge from a lower 48 port for installation at the slope.Existing
piling and support methods at the slope are adequate for units up to
100 MW,the largest commercially available unit size.Handling
capabilities for 2400 ton units a1reaqy exist at the North Slope and
are sufficient for this option.The units would be moved into place on
crawl ers,1eve led on pre-pl aced steel and concrete pilings,and
connected to the gas supply and electrical systems.Several gas fi:ed
simple cycle units of this type are already in operation at the North
Slope.
3105A
B3-1
A Fairbanks area location for gas turbines wou1 d all ow "i n p1 ace"
construction on typical spread footings or pilings.There are many
existing combustion turbine units in operation in the Fairbanks area
using distillate fuel.
The Kenai area option for simple cycle differs from that for Fairbanks
only in the quality of the fuel.The waste stream fuel to be used here
is expected to have a very low heating value (approximately 175-195
Btu/ft3 )and high CO 2 content.Gas turbines can be modified for
firing on fuel with heating values as low as approximately 150
Btu/ft3 •Such firing requires modification of the combustion
chamber,valving and piping,and requires that the units be started up
on higher Btu fuel such as distillate or natural gas.An additional
problem is that the high CO2 content of North Slope gas res~lts in a
c~nditioning facility waste gas that will be difficult to'burn due to
the quenching effect that CO 2 has in the combustion chamber.This
problem can be overcome by blending higher Btu content gas during
startup and less than full load operation,and through modifications to
hardware,similar to those for the low Btu problem.
The total energy available in the waste stream is insufficient to meet
the'energy needs of the Ra i 1belt.It is,therefore,necessary to
supplement the waste 'stream with some of the sales gas which will be
the main product of the conditioning facility.
B3.2 COMBINED CYCLE TECHNOLOGY
Combined cycle technology has matured in the past 10 to 15 years.
Typically larger gas turbines (50 MW and greater)are used for combined
cycle plants in order to supply enough waste heat for an economically
designed heat recovery boiler.Also,two or more heat recovery boilers
are used to drive one steam turbine.The range of heat rates for
operating combined cycle plant is 8,350 to 9,200 Btu/kWh (7550-8300
Btu/kWh-LHV).For the steam CYCle,the site environments considered in
this study strongly favor the use of air cooled condensers.Air cooled
condensers have been built for combined cycle plants and for steam
3105A
B3-2
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boiler plants as large as 350 MW,and have been operated under
applicable ambient conditions.An air cooled condenser is presently
operating in the Beluga area for the steam cycle of a 179 MW combined
cycle plant.
Combined cycle plants for the North SlQpe will be pre-constructed in
three subunits for assembly at the slope in a manner similar to that
described for simple cycle units.A plant would consist of two gas
turbine units with heat recovery steam generators,one steam
turbine-generator set with attendant equipment,and one air cooled
condenser.The heaviest unit to be handled is the steam
turbine-generator module that weighs approximately 2300 tons.
Constructability could be a problem since the three modular units and
the field-erected condenser would require assembly during the short.'.
North Slope construction season.It is felt,however,that careful
planning of logistics and manpower can make this feasible.
Combined cycle plants in the 150 MW range have been built within the
Railbelt region.Only one problem other than typical siting and
environmental questions is anticipated for either of the two southerly
locations.That problem is the low heating value and high CO 2
content of the conditioning facility waste gas which will also effect
the design of the gas turbines for the combined cycle units.Further,
this gas quality may a)so effect the'size and efficiency of the heat
recovery boilers and the steam cycle.
B3.3 GAS FIRED BOILERS
The direct fired steam boiler with steam turbine-generator is the most
widely used technology of the three being considered.Identical in
concept and general design features with coal fired plants,gas fired
boilers are most efficient and economical in larger units.For this
reason the technology was considered in 200 MW and larger sizes.
3l05A
B3-3
At the North Slope,the short construction period and phYsical size of
the boiler.present severe problems for erection of a gas fired boiler
unit.PhYsically handling a pre-assembled boiler on crawlers is not
practical,especially when one considers the difficulty .of maintaining
the integrity of the pressure parts and t~e casing.Another problem is
the physical size of the turbine-generator set.A 200 MW steam
turbine-generator pre-assembled on foundations far exceeds the North
Slope handling capacity of 2400 tons.Finally,the short construction
season of the North Slope does not allow erection at the site.An
alternative which may be viable,however,is to pre-erect the entire
unit on barges,move the barges to the North Slope and pennanently
anchor or beach them in shallow water.Three barges would be
necessary,one for the boiler,one for the turbine-generator,and one
for the air cooled condenser and auxiliaries.
Construction of gas fired boilers within the Railbelt (e.g.,at
Fairbanks and Kenai)does not present the severe problems seen at the
North Slope and could be accomplished in the same manner as the other
technical alternatives.As with the other alternatives,the waste gas
option presents problems.The low heating value of the gas will result
in much larger furnace volumes and lower efficiencies.
Gas fired steam turbine gener.ationsystems have higher capital costs
(approximately 50 percent higher)on a $/kW installed basis and higher
heat rates (9,500-ll,000 Btu/kWh)than combined cycle units.As a
consequence,it would not be advantageous to install them in any of the
considered locations,in that there would be a capital cost and fuel
cost disadvantage.Operating cost advantages which might be realized
with this technology in very large plants are not available in the
required unit size range.For these reasons gas fired boilers were
eliminated from further study.
3l05A
B3-4
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B4.0 ASSUMPTIONS AND INPUT DATA
B4.1 TECHNICAL ASSUMPTIONS AND DATA
The plant heat rates used in this study result from a review of
existing plants and data supplied by equipment vendors.As mentioned,
simple cycle gas turbines have heat rates which vary from 11,800 to
13,000 Btu/kWh (10,600-11 ,700 Btu/kWh-LHV).The simple cycle
capacities and heat rates used are listed in Table B4-1.
The range of heat rates for operating combined cycle plants is 8350 to
9200 Btu/kWh (7,550-8,300 Btu/kWh LHV)while available technology for
new plants claim heat rates as low as 8200 Btu/kWh for a 225 MW (net)
plant.The heat rates assumed in this study are shown in Table B4-1.
Fuel costs for coal,oil,and gas fired plants in the Railbe1t region
were investigated.At present coal generally varies from $2.10 per
million Btu for a mine mouth location to as much as $4.50 per million
Btu when remote from its source.Based upon discussions with utilities
in the Railbe1t region,distillate prices for uti1iti~s are presently
.ina range of $5.03 to $5.60 per mtll ion Btu.Thi s price is al so
sensitive to location and is higher at remote locations.A current
export market price for natural gas is $5.50 per million Btu,While the
Battelle (1982)IIRai1be1t Electric Power Alternatives StUdy:
Evaluation of Rai1be1t Electric Energy Plans"cites an anticipated
Fairbanks price of $5.92 per million Btu for North Slope gas.There
are existing contracts for sale of natural gas in the Cook Inlet area
at prices under $1.00 per million Btu.Due to these low prices and the
relatively high prices of alternate fuels,it was decided to utilize a
range of gas prices thus providing a sensitivity analysis for
technology selection as a function of fuel price.The fuel prices that
were used were $0.00,$1.50,$2.50,$3.50,and $5.50 per million Btu.
3105A
B4-1
TABLE B4-1
CAPACITIES AND HEAT RATES FOR SIMPLE AND COMBINED CYCLE UNITS
SIMPLE CYCLE GAS TURBINES
Locale Ambient Capacity Heat Rate
Temperature..!!(MW)(Btu/kWh)2/
North Slope 9°91 11,500
Fairbanks 26°86 11 ,600
Kenai 33°84 11 ,650
COMBINED CYCLE UNITS
Local e Jlmbient Capacity Heat Rate
Temperaturell (MW)(Btu/kWh)2I
North Slope 9°F 253 8,320
Fairbanks 26°F 242 8,290
Kenai 33°F 237 8,280
1I/Average annual temperature.
~Based on higher heating value.
3105A
B4-2
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Ebasco reviewed the operating and maintenance (DIM)costs used in the
Railbelt Electric Power Alternatives Study (Battelle 1981)for
applicability to this analysis.After comparing these to current
manufacturer's maintenance recommendations,other utility DIM costs and
to Edison Electric Institute's (1981)Guides for Operating Practice,it
was decided that th~~attelle figures remained adequate for application
to the Railbelt region scenario in this stUdy.For the North Slope
option,higher wages,shorter work seasons,and adverse working
conditions resulted in revised higher DIM costs.All DIM costs are
11 sted below:
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North Slope
Fairbanks or Kenai
Simple Cycle Units
(mil s/kWh)
6.3
4.6
Combined Cycle Units
(mil s/kWh)
5.5
4.0
Capital costs for each new technology were also developed.The costs
are in 1982 dollars/kWh for the unit sizes used in each technology.
These costs were derived after reviewing costs of past and current
similar projects in both Alaska and the lower 48 states.It should
also be noted that these costs refer only to the power generation
facilities and do not include costs associated with transmission lines
or fuel supply facilities.These costs are shown in Table 84-2.
In order to develop the number of gigawatt~hours generated for each
scenario,it was necessary to make several assumptions.First,it was
assumed that the new units would operate at an average capacity factor
of 0.75.Secondly,it was assumed that all existing hydro power would
be base loaded and operated at a capacity factor of approximately 0.50
(Acres Ameri can Inc.1981).It was also assumed that the new gas fired
3105A
84-3
TABLE 84-2
3105A
1/Adjusted for capacities at specific locations.
North Slope Simpl e Cycl e 798 589
Combi ned Cycl e 951 865
Fairbanks Simpl e Cycl e 452 394
Combined Cycle 557 527
Kenai Simpl e Cycl e 488 415
Combined Cycle 572 540
ASSUMED CAPITAL COSTs!./
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84-4
Capital Cost (1982 $/kW installed)
First Plant Subsequent PlantTechnologyRegion
L
units would replace older existing units for base load and that the
older units would become part of the reserve margin until they are
retired.Finally,all new gas fired capacity was assumed to generate
energy up to the lower of either their limit at 0.75 capacity factor,
or to the total required energy in each year after deducting the ~dro
supplied energy.The 0.75 capacity factor was selected as a
conservative estimate for individual gas turbine or combined cycle
units.The system capacity factor will be significantly lower.
84.2 ECONOMIC ASSUMPTIONS AND INPUT DATA
In perfonming the economic evaluation of the alternate development
scenarios,economic factors utilized in the Rai1belt Electric Power
Alternatives Study (Battelle 1982)were employed.These are summarized
in Table 84-3.The period of analysis was assumed to be 1983 through
201 O.The useful 1ife of the combusti on turbines and heat recovery
steam generators (waste heat boilers)was assumed to be 30 years.The
inflation ,rate was assumed to be 0 percent.Capital costs were assumed
to escalate at the rate of inflation.Operating and maintenance costs,
similarly,were assumed to escalate at the rate of inflation.Fuel
costs were assumed to escalate at a rate varying from 0 to 3 percent
greater than inflation,in 1%increments.The discount rate was
assumed to be 3 percent.
These standard factors were developed in order to make different
economic studies comparable.In some cases additional comment is
warranted.Inflation,for example,is taken at 0%in order to convert
all analyses into urea 1u doll ars.Capital costs are assumed to
escalate at the rate of inflation,as this trend has existed for the
last few years and has been documented by the Power Authority.Fossil
fuel costs (typically oil)are escalated at a rate higher than
i nfl ati on.
3105A
84-5
TABLE B4-3
Item
Period of Analysis
ECONOMIC ASSUMPTIONS
Assumptions
1983-2010
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Life of Boilers,Combustion Turbines,
and Heat Recovery Steam Generators
Salvage Value,All Cases
Fuel Costs
Inflation Rate
Capital Cost Escalation Rate
Fuel Cost Escalation Rate
O&M Escalation Rate
Discount Rate
3l05A
B4-6
30 yrs
$0
$0 to $5.50jmi11ion Btu (1982)
0%
0%(Real)
0%to 3%(Real)
0%(Real)
3.0%(Real)
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In addition,no salvage values were taken despite the fact that some
projected generating units only had a project life of 1 to 2 years
within the period of analysis.The elimination of salvage values (or
val ues of unuti lized capital)from the analysi s was made for two
reasons:1)it was assumed that if differentials in annual costs
occurred between technologies following the year 2010,they would
accentuate trends emerging within the period of analysis;and 2)it was
recognized that the influence of discounting,even at 3 percent,would
make any apparent differences after the year 2010 small (e.g.,one
dollar,discounted at 3 percent from 1982 to the year 2010,is only
worth $0.44).
3105A
84-7
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85.0 RESULTS
85.1 SYSTEM CAPACITY REVIEW
The capacity retirement schedule,planned additions,and resulting
balance of existing capacity are listed in Table 85-1 along with the
peak demand for both the low and medium forecasts.The total required
capacity for each reserve margin,the balance of existing capacity,and
the resulting requirements for new capacity are listed in Tables 85-2
and 85-3 for the low and medium load forecasts,respectively.The ve~
large reserve margins which exist at present are the result of the
isolated nature of the region1s utilities,wherein each small community
maintains a reserve capacity of 50-150%or more,and of the transition
that the region is going through from small local plants to larger
central generating stations.The retirement schedule is controlled by
a single input,the operating life of the existi-ng plants~
B5.2SELECTION OF UNIT SIZES
The size range of units'selected for the technologies was governed by
two items.The first was capital costs.Where there were significant
capital cost variance over the size range,the range was restricted to
the lower cost end.The second is the range of reserve margins within..
which the Rai1be1t system will operate.Previous studies have used a
loss of load probability (LOLP)of one day in ten years as the basis
for design (Acres American Inc.1981).The Battelle system evaluation
studies initially determined that this LOLP results in a range of
reserve margins of 24 to 32 percent (Battelle 1982).For all future
system evaluation studies,Battelle utilized an average reserve margin
of 30 percent.A1 so,the Battelle report states that the cost of power
is nearly constant within this range of reserve margins.This system
planning report employs the reserve margin range determined by Battelle
(1982).Unit sizes for the two technologies have been evaluated based
upon these reserve margins and other factors.
3105A
B5-1
TABLE B5-1
EXISTING CAPACITY,PLANNED ADDITIONS,UNIT RETIREMENT SCHEDULE
AND PEAK DEMANDS
Ex i sting P1anned*Unit**Peak Demand***
Year Capacity Additions Retirements Low Load Medium Load
(MW)(MW)(MW)Forecast Forecast
1982 1154.1 158.4 0.3 560 603
1983 1154.1 580 631
1984 1154.1 600 659
1985 1154.1 620 687
1986 1154.1 656 728
1987 1050.1 4.0 692 769
1988 1247.1 97 728 810
1989 1242.1 5.0 764 851
1990 1242.1 800 892
1991 '1223.7 18.4 808 910
1992 1190.0 33.7 816 928
1993 1173.2 16.8 824 947
1994 1142.3 30.9 832 965
1995 1094.8 47.5 840 983
1996 1023.9 70.9 836 1003
1997 927.5 96.4 832 1023
1998 811.7 55.8 828 1044
1999 871.7 824 1064
2000 853.1 18.6 820 1084
2001 852.9 0.2 830 1121
2002 775.1 77.8 840 1158
2003 722.1 53.0 850 1196
2004 722.1 860 1233
2005 609.5 112.6 870 1270
2006 604.3 5.2 896 1323
2007 604.3 922 1377
2008 577.9 26.4 948 1430
2009 577.0 0.9 974 1484
2010 577.0 1000 1537
*Derived from Table 6.3 of Susitna Feasibility Report (Acres American
Inc.1981).The 1988 additions consist of Bradley Lake (90 MW)and
Grant Lake (7MW).More recent Alaska Power Authority plans envision
a Bradley Lake Project with 135 MW of total installed capacity and
eliminate the Grant Lake Project (R.W.Beck and Associates 1982).
**Derived from Table 6.2 of Susitna Feasibility Report (Acres American
Inc.1981).
***Low load forecast derived from summary table (page iv)in Battelle
(1982);medium growth forecasts derived from Table 5.7 of Susitna
Feasibility Study (Acres American Inc.1981).
3105A
B5-2
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A gas turbine of 77 MW capacity (ISO conditions,baseload)was chosen
based on minimizing the number of plants and satisfying the new
capacity requirements range.Combined cycle unit increments are very
suitable to this study with gas turbine units of 50 to 100 MW being
available and steam cycles from 40 to 80 MW available for heat
recovery.Total combined cycle unit sizes of 220 MW (ISO conditions,
baseload)total were selected.This includes two 77 MW gas turbine
units and a 66 MW steam turbine unit.This size unit was selected for
economY of scale reasons and the fact that it closely matches the
required capacity additions.
85.3 NEW CAPACITY REQUIREMENTS
The requirements for new capacity and proposed additions are 1isted in
Tables 85-4 through 8-9 and are a function of the previously discussed
system characteristics and available unit sizes.Units were added as
appropriate to maintain the total capacity needed within the required
range.Twelve different tabulated scenarios resulted from this
-analysis with three locations having two technological and two load
forecast possibilities.
Possible variation in load growth for the region has been taken into
account by performing all analysis for both the low and medium load
growth forecasts.This provides a wide range for study since the total
hew capacity required in 2010 under the medium forecast is
approximately twice that for the low load forecast.
The new generating units to be added for each technology under each
load growth forecast are shown in Figures 85-1 through 85-12.In
applying the technologies,it was demonstrated that simple cycle unit
additions most closely followed the targeted total capacity
corresponding to the 30 percent reserve margin.Combined cycle systems
could be added within the target range,but were less flexible in
following capacity addition requirements than simple cycle combustion
turbines.
3105A
85-5
['
['TABLE B5-5
NEW CAPACITY ADDITIONS -LOW LOAD FORECAST
[-FAIRBANKS
r Actual New Capacity (MW)
Required New Capacity Simple Cycle Combi ned Cyc1 e
L
At Peak Demand (MW)(Increment/(Increment/
Year 24%RSRY 30%RSRY 32%RSRY Total)Total)
r 1990 0 0 0
-0/0 0/0
1991 0 0 0 0/0 0/0
['1992 0 0 0 0/0 0/0
1993 0 0 0 0/0 0/0.-"
1994 0 0 0 0/0 0/0r19950a140/0 0/0l.,;
1996 13 63 80 86/86 86/86r199710415417086/172 86/172L
1998 155 204 221 0/172 0/172
[1999 150 199 216 0/172 0/172
2000 164 213 229 0/172 0/172
C 2001 176 226 243 86/758 70/242
2002 267 317 334 86/344 86/328
C 2003 282 333 350 0/344 0/328
2004 344 396 413 ..86/430 86/414
'-
2005 469 521 538 86/516 70/484
C 2006 507 561 579 0/516 86/570
2007 539 595 613 86/602 0/570
6 2008 598 654 673 0/602 86/656
2009 631 689 709 86/688 0/656
[2010 663 723 743 0/688 70/726
.-
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U B5-7
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TABLE B5-6 CNEWCAPACITYADDITIONS-LOW LOAD FORECAST
KENAI [
Actual New Capac i ty (MW)[
Required New Capacity Simple Cycle Combined Cycle
At Peak Demand (MW)(Increment/(Increment/,.--~
Year 24%RSRY 3m RSRY 32%RSRY Total)Tota 1)L
1990 0 0 0 0/0 0/0 L19910 0 0 0/0 0/0
1992 0 0 0 0/0 0/0 L19930 0 0 0/0 0/0
1994 0 D 0 0/0 0/0
1995 0 0 14 0/0 0/0 [
1996 13 63 80 84/84 84/84
1997 104 154 170 84/168 84/168 [
L19981552042210/168 0/168
1999 150 199 216 0/168 0/168 r
2000 164 213 229 0/168 0/168 C
2001 176 226 243 84/252 69/237 [2002 267 317 334 84/336 84/321
2003 282 333 350 0/336 0/321
2004 344 396 413 ..84/420 84/405 ['--:.
2005 469 521 538 84/504 69/474
2006 507 561 579 84/588 84/588 l20075395956130/588 0/588
2008 598 654 673 84/672 84/642 C20096316897090/672 0/672
2010 663 723 743 0/672 69/711 l'
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3105A L
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[--TABLE B5-7
NEW CAPACITY ADDITIONS -MEDIUM LOAD FORECAST
r-'NORTH SLOPE
[Actual New Capacity (MW)
Required New Capacity Simple Cycle Combined Cycle
r At Peak Demand (MW)(Inc rement/(Increment/
Year 23 RSRY 30%RSRY 32%RSRY Total)Total)
---~
t:-1990 0 0 0 0/0 0/0
1991 0 0
0 0/0 0/0
r 1992 0 16 35 0/0 0/0
1993 1 58 77 91/91 91/91-c
n 1994 55 113 132 0/0 0/91
1995 124 .183 203 91/182 91/182I.-J
1996 1220 280 300 91/273 71/253
[1997 341 402 422 91/364 91/344L
1998 423 485 506 91/455 91/435
[1999 447 511 532 0/455 71/506
2000 491 556 578 91/546 91/597
[2001 537 604 627 0/546 0/597
2002 661 730 754 182/728 91/688
C 2003 711 783 807 0/728 71/759
2004 807 881 906 91/819 91/850
L 2005 965 1041 1066 182/1001 162/1012
2006 1037 1116 1142 91/1092 91/1103
2007 1103 1186 1214 91/1183 91/1194
C 2008 1195 1281 1310 91/1274 71/1265
2009 1263 1352 1382 0/1274 91/1356
[2010 1329 1421 1452 91/136~0/1356
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..--B5-9
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TABLE 85-8 [
NEW CAPACITY ADDITIONS -MEDIUM LOAD FORECAST
FAIRBANKS [
Actual New Capacity (MW)t'
Required New Capacity Simp1 e Cyc1 e Comb i ned Cyc 1e
At Peak Demand (MW)(Increment/(Increment/['Year 24%R5RY 3m R5RY 32%R5RY Total)Tota 1)
1990 0 0 0 0/0 0/0 ['
1991 0 0 0 0/0 0/0
1992 .0 16 35 0/0 0/0 L199315877,86/86 86/86
1994 55 113 132 0/0 0/86 R199512418320386/172 86/172 L..J
1996 1220 280 300 86/258 70/242
1997 341 402 422 86/344 172/414 ['
L
1998 423 485 506 86/430 70/484
1999 447 511 532 86/516 0/484 [
2000 491 556 578 0/516 86/570
2001 537 604 627 86/602 0/570 L200266173075486/688 156/726
2003 711 783 807 86/774 0/726 [2004 807 881 906 86/860 86/812
2005 965 1041 1066 172/1032 156/968
2006 1037 1116 1142 86/1118 86/1050 C
2007 1103 1186 1214 86/1204 86/1140
2008 1195 1281 1310 86/1290 70/1210 L
2009 1263 1352 1382 0/1290 86/1296
2010 1329 1421 1452 86/1376 0/1382 [,
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LOU LOAD FORECAST~NORTH SLOPE/SIMPLE CYCLE OPTION
~BALANCE EXISTING CAPACITY
~--------PEAK DEMAND
-------RESERVE MARGIN=.24
------RESERVE MARGIN=.3e
0 _--RESERVE MARGIN=.32
NEU CAPACITY
85 6 7 8 9 ge I 2 3 4 5 6 7 8 9 ee I 23 4 5 6 7 8 9 I e
YEAR 1985 THRU 2010
ALAIKA POWER AUTHORITY
NORTH .LOPE GAl
'EAI_UTY ITUDY
Plot of System Requirements and
Capacities for Simple Cycle Technolgy,
low load Forecast,with Generating
Facilities at the North Slope.
........1 85-1
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LO~LOAD FORECAST~FAIRBANKS/SIMPLE CYCLE OPTION
~BALANCE EXISTING CAPACITY
---------PEAK DEMAND
-------RESERVE MARGIN=.24
------RESERVE-MARGIN=.30
0 _--RESERVE MARGIN=.32
NEW CAPACITY
85 6 7 8 9 90 1 2 3 4 5 6 7 8 9 00 1 2 3 4 5 6 7 8 9 10
YEAR 1965 THRU 2010
ALAIKA POWER AUTHORITY
NORTH ILOPE GAS
nAS.l.fTY lTUDY
Plot of System Requirements and
Capacities for Simple Cycle Technology.
low load Forecast.with Generating
Facilities at Fairbanks.
'''''''1 B5·2
LO~LOAD FORECAST~KENAI/SIMPLE CYCLE OPTION
...._----.
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BALANCE EXISTING CAPACITY
PEAK DEMAND
RESERVE MARGIN=.24
RESERVE MARGIN=.3e
RESERVE MARGIN=.32
NE\oI CAPACITY
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YEAR 1985 THRU 2e1e
ALAIKA POWER AUTHORITY
NORTH 'LOPE GAil
fEAII.lLrrV 'TUDV
Plot of System Requirements and
Capacities for Simple Cycle Technology,
low load Forecast.with Generating
Facilities at Kenai.
,teUllI 85-3
I."KO IEAVlCU INCORPORATED
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~BALANCE EXISTING CAPACITY
2000 .~~~--~~--PEAK DEMAND
-----~.RESERVE MARGIN=.24
------RESERVE MARGIN=.30
0----RESERVE MARGIN=.32
NE\.I CAPACITY
1500
1000
500
85 6 7 8 9 90 I 2 3 4 5 6 7 8 9 00 1 2 3 4 5 6 7 8 9 I 0
YEAR '985 THRU 2~'0
ALASKA POWER AUTHOR"Y
NORTH aLOPE GAl
PEAI_ILITY aTUDY
Plot of System Requirements and
Capacities for Combined Cycle
Technology,Low Load Forecast,
with Generating Facilities at the
North Slope.
"'''''185-4
.aAICO ."VICE'1IC000000ATED
2000 .
LOW LOAD
o
FORECAST,FAIRBANKS/242 MW
BALANCE EXISTING CAPACITY
PEAK DEMAND
RESERVE MARGIN=.24
RESERVE MARGIN=.30
RESERVE MARGIN=.32
NEW CAPACITY
COMB.CYCLE OPTION
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1500
1000
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85 6 7 8 9 90 1 2 3 4 5 6 7 8 900 1 2 3 4 5 6 7 8 9 10
YEAR 1985 THRU 2010
ALAIKA POWER AUTHORITY
NORTH .LOPE ClAS
fUSIBILITY ITUDY
Plot of System Requirements and
.Capacities for Combined Cycle
Technology,low load Forecast,
with Generating Facilities at
FairbankS.
'''''''E 85-5
IIASCO aERVICEa INCORPORATED
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LOW LOAD FORECAST,KENAI/237 MW COMB.CYCLE OPTION
~BALANCE EXISTING CAPACITY
---------PEAK DEMAND
-------RESERVE MARGIN=.24
------RESERVE MARGIN=.30-0---RESERVE MARGIN=.32
NEW CAPACITY
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85 6 7 8 9 90 1 2 3 4 5 6 7 8 9 00 1 2 3 4 5 6 7 8 9 10
YEAR 1985 THRU 2010
ALASKA POWER AUTHORITY
NORTH ILOPE GAS
r:EASIBIUTY STUDY
Plot of System Requirements and
Capacities for Combined Cycle
Technology,low load Forecast,
with Generating Facilities at Kenai.
."""1 85-6
RASCO IEfMCES IICORPORATID
MEDIUM LOAD FORECAST,NORTH SLOPE/SIMPLE CYCLE OPTION
85 6 7 8 9 90 1 2 3 4 5 6 7 8 9 00 1 2 3 4 5 6 7 8 9 10
YEAR 1985 THRU 2010
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1500.
1000
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~BALANCE EXISTING CAPACITY
---------PEAK DEMAND
.------RESERVE MARGIN=.24
------RESERVE MARGIN=.30
0----RESERVE MARGIN=.32
NEW CAPACITY
,.,.'"
.,.,.
,.,.
ALAaKA POWER AUTHORITY
NORTH .LOPE GAl
'UI....rTY ,nJOY
Plot of System Requirements and
Capacities for Simple Cycle Technology.
Medium load Forecast.with Generating
Facilities at the North Slope.
'IIIUflE 85-7
IIAICO IEAVlCElItCOAPOAATED
r~r--,r---r---,Ci.------.,-----.,-r ':--0t_"".,..,).),'1 J,Jl )l ]I ;I ,
MEDIUM LOAD FORECAST,FAIRBANKS/SIMPLE CYCLE OPTION
85 6 7 8 9 90 I 2 3 4 5 6 7 8 9 00 1 2 3 4 5 6 7 8 9 10
M
E
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A
W
A
T
T
S
2000 .
1500
1000
500
o
~BALANCE EXISTING CAPACITY
......----PEAK DEMAND
.------RESERVE MARGIN=.24
------RESERVE MARGIN=.30
0----RESERVE MARGIN=.32
NEW CAPACITY
.!!
YEAR 1985 THRU 2010
...
......
ALAIKA POWER AUTHORITY
NOATH ILOPE GAlS
rEAI_ILIlY ITUDY
Plot of System Requirements and
Capacities for Simple Cycle Technology,
Medium load Forecast,with Generating
Facilities at Fairbanks •
'''''''1 85-8
M
E
G
A
W
~A
~T
a T
S
2000
1500
1000
500
MEDIUM LOAD FORECAST,KENAI/SIMPLE CYCLE OPTION
~BALANCE EXISTING CAPACITY
.~~~~~~~-PEAK DEMAND
.~---~-RESERVE MARGIN=.24
------RESERVE MARGIN=.30
D~---RESERVE MARGIN=.32
NEW CAPACITY
85 6 7 8 9 90 1 2 3 4 5 6 7 8 9 00 1 2 3 4 5 6 7 8 9 10
YEAR 1985 THRU 2010
ALAIKA 'OWER AUTHORITY
NORTH ILME GAl
FEAI_IlI'TY 'TUDY
Plot of System Requirements and
Capacities for Simple Cycle Technology,
Medium Load Forecast,with Generating
Facilities at Kenai.
....""E 85-9
IIASCO IEAVlCEI INCOAPOAA TED
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MEDIUM LOAD FORECAST,NORTH SLOPE/COMBINED CYCLE OPTION
...._------------------------
85 6 7 8 9 90 I 2 3 4 5 6 7 8 9 00 I 2 3 4 5 6 7 8 9 I 0
YEAR 1985 THRU 2010
18AICO ."VlCES INCOAfIOAATED
"'''''185-10
Plot of System Requirements and
Capacities for Combined Cycle
Technology,Medium load Forecast.
with Generating Facilities at the
North,Slope.
ALAIKA POWER AUTHORITY
NORTH ILOPE GAl
FEASIBlLfTY lTUDYo
500
1500
1000
~BALANCE EXISTING CAPACITY
2000 .---------PEAK DEMAND
.------RESERVE MARGIN=.24
------RESERVE MARGIN=.30
0----RESERVE MARGIN=.32
NEW CAPACITY
M
E
G
A
W
A
T
T
S
\\
"MEDIUM LOAD FORECAST,FAIRBANKS/COMBINED CYCLE OPTION
85 6 7 8 9 90 1 2 3 4 5 6 7 8 9 00 1 2 3 4 S 6 7 8 9 10
YEAR·198S THRU 2010
2000
M 1500
E
G
CXJ AU1
I
N WNA
T ·1000
T
S
500
o
~BALANCE EXISTING CAPACITY
---------PEAK DEMAND
.------RESERVE MARGIN=.24
------RESERVE MARGIN=.30
0----RESERVE MARGIN=.32
NEW CAPACITY
,
,,
ALASKA POWER AUTHORITY
NOATH ILOPE ClAI
fEAS.IlITY ITUDY
Plot of System Requirements and .
Capacitities for Combined Cycle
Technology,Medium load Forecast,
with ~enerating Facilities at
Fairbanks.
'HIURE 85-11
flAICO SERVICES 1tCON"ORATED
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85 6 7 8 9 90 1 2 3 4 5 6 7 8 9 00 1 2 3 4 5 6 7 8 9 10
YEAR 1985 THRU 2010
M
E
G
A
W
A
T
T
S
2000
1500
1000
500
o
.MEDIUM
o
LOAD FORECAST,KENAI/COMBINED CYCLE OPTION
BALANCE EXISTING CAPACITY
PEAK DEMAND
RESERVE MARGIN=.24
RESERVE MARGIN=.30
RESERVE MARGIN=.32
NEW CAPACITY
,,
ALAIKA POWER AUTHORITY
NORTH ILOPE GAS
FEAS.ll.rTY InJOY
Plot of System Requirements and
Capacities for Combined Cycle
Technology,Medium Load Forecast,
.with Generating Facilities at
Kenai.
'''''''1 85-12
18ASCO IEAVlCES IICOAPORATED
A resultant factor of this unit slzlng and staging for each technology
is that no two scenarios for new capacity result in the same amount of
total energy being supplied.This is also considered in the economic
analysis.
As will be discussed below,the simple and combined cycles costs are
nearly identical for low cost fuels at the North Slope.The simplicity
of operation and maintenance,combined with much lower freshwater
requirements result then in selection of simple cycle technology for
the North Slope scenarios.
The combined cycle alternative results in the least cost option for
Fairbanks and Kena~and will be applied exclusively to meet the
capacity requirements as shown in Tables 85-4 thrqugh 85-9 and Figures
85-1 through 85-12.As previously mentioned,other sizes of combined-
cycle plants are available.The alternatives are smaller gas turbines
and heat recovery boilers,and a combination of three or more heat
recovery boilers with one steam turbine.There are,however,no cost
advantages to be gained by either of these choices while a great deal
of flexibility is lost.The total number of plants would also increase
significantly if smaller plants were used.
85.4 ECONOMIC ANALYSIS AND RESULTS
Given the assumptions presented in Section 84.0,and the technologies
available,the systems analysis was made by applying the accepted
Alaska Power Authority model for calculation of the Present Worth of
Costs for the alternative options.All costs were considered for each
system;that is,the analysis included capital costs,operating and
maintenance costs,and fuel costs.These costs were accounted for in
the year they occurred.As a consequence,all capital costs were taken
in the year of installation and did not include interest during
construction.
3l05A
85-24
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This data when input to the model generated a total cost stream per
year for each scenario.This cost stream was then discounted back to
1982 at a rate of 3.0 percent.The discounted values,for each
scenario,were summed to achieve the present worth of costs for each
scenario.The present worth of costs for each scenario were then used
to compare different scenarios.The cost analyses made by employing
Alaska Power Authority economic analyses techniques were compared on
the basis of total present worth of costs for each scenario.
The results of the economic analysis of alternative technologies and
load growths are shown in Tables 85-10 through 85-13.These results
demonstrate that the combined cycle technology exhibits both the lowest
present worth of costs except in cases where natural gas costs were
less than $1.50/million 8tu.The results reflect the fact that the
combined cycle power plant has the lowest heat rate and a modest
installed capital cost,particularly in the size range considered in
thi s study.
3105A
85-25
TABLE 05-10
PRESENT WORTH OF COSTS FOR NATURAL GAS FIRED GENERATION
AS A FUNCTION OF LOAD GROWTH.LOCATION.TECHNOLOGY.AND FUEL PRICE
AT A0 PERCENT,FUEL PRICE ESCALATION
(VALUES IN 1982$x 109)
FUEL PRICE
LOAD GROWTH
FORECAST LOCATION TECHNOLOGY o 1.50
($x 106 Otu)
2.00 2.50 3.50 5.50
Low North Slope Sfmple Cycle 0.360 0.678 0.784 0.890 1.103 1.527
Combfned Cycle 0.420 0.692 0.783 0.874 1.056 1.419
Fafrbanks Sfmple Cycle 0.239 0.568 0.677 0.787 1.006 1.444
Combfned Cycle 0.256 0.517 0.605 0.692 0.866 1.215
Kenaf Sfmple Cycle 0.248 0.577 0.687 0.797 1.017 1.457
Combfned Cycle 0.284 0.542 0.628 0.713 0.885 1.229
Medfum North Slope Sfmple Cycle 0.707 1.370 1.591 1.812 2.255 3.319
Combfned Cycle 0.875 1.387 1.558 1.728 2.069 2.751
Fafrbanks Sfmple Cycle 0.486 1.157 1.381 1.604 2.052 2.946
Combfned Cycle 0.556 1.061 1.229 1.398 1.735 /2.408
Kenaf Sfmple Cycle 0.505 1.184 1.410 1.636 2.088 2.993
Combined Cycle 0.562 1.072 1.242 1.413 1.753 2.433
3105A
05-26
r----"">l 'en r----':'~::-T].:
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TABLE B5-11
PRESENT WORTH OF COSTS FOR NATURAL GAS FIRED GENERATION
AS A FUNCTiON OF LOAD GROWTH.LOCATION.TECHNOLOGY.AND FUEL PRICE
AT A1 PERCENT FUEL PRICE ESCALA~ION
(VALUES IN 1982$x 109)
FUEL PRICE
LOAD GROWTH
FOIi:CAST LOCATION TECHNOLOGY o 1.50
($x 106 Btu)
2.00 2.50 3.50 5.50
Low North Slope Simple Cycle 0.360 0.759 0.892 1.026 1.292 1.825
Combined Cycle 0.420 0.761 0.874 0.988 1.125 1.669
Fairbanks Simple Cycle 0.239 0.651 0.789 0.926 1.201 1.751
Combined Cycle 0.256 0.583 0.692 0.801 1.019 1.456
Kenai Simple Cycle 0.248 0.662 0.800 0.938 1•.213 1.765
Combined Cycle 0.284 0.606 0.714 0.821 1.036 1.467
Medium North Slope Simple Cycle 0•.707 1.530 1.805 2.079 2.628 3.726
Combined Cycle 0.875 1.509 1.720 1.932 2.354 3.119
Fairbanks Simple Cycle 0.486 1.319 1.600 1.875 2.430 3.541,
Combined Cycle 0.556 1.182 1.390 1.599 2.016 2.851
Kenai Simple Cycle 0.505 1.347 1.628 1.908 2.469 3.592
Combined Cycle 0.562 1.195 1.405 1.616 2.038 2.881
3105A
85-27
TABLE B5-12
PRESENT WORTH OF COSTS FOR NATURAL GAS FIRED GENERATION
AS A FUNCTION OF LOAD GROWTH,LOCATION,TECHNOLOGY,AND FUEL PRICE
AT A2 PERCENT FUEL PRICE ESCALATION
(VALUES IN 1982$x 10 9)
FUEL PRICE
LOAD GROWTH
FORECAST LOCATION TECHNOLOGY o 1.50
($x 10 6 Btu)
2.00 2.50 3.50 5.50
Low North Slope Simple Cycle 0.360 0.861 1.028 1.195 1.529 2.197
Combined Cycle 0.420 0.846 0.988 1.130 1.413 1.980
Fairbanks Simple Cycle 0.239 0.756 0.928 1.101 1.445 2.135
Combined Cycle 0.256 0.665 0.801 0.938 1.210 1.756
Kenai Simple Cycle 0.248 0.767 0.940 1.113 1.459 2.151
Combined Cycle 0.284 0.687 0.822 0.956 1.225 1.763
Medium North Slope Simple Cycle 0.707 1.748 2.088 2.429 3.110 4.472
ComM ned Cyc Ie 0.875 1.660 1.922 2.184 2.707 3.753
Fairbanks Simple Cycle 0.486 1.520 1.865 2.210 2.899 4.278
Combined Cyc1 e 0.556 1.331 1.590 1.848 2.365 3.399
Kenai Simple Cycl e 0.505 1.549 1.897 2.245 2.942 4.334
Combined Cycle 0.562 1.346 1.607 1.869 2.391 3.436
3105A
B5-28.
I~,--"]"'~-
r-J
TABLE B5-13
PRESENT9 WORTH OF COSTS FOR NATURAL GAS FIRED GENERATION
AS A FUNCTION OF LOAD GROWTH.LOCATION.TECHNOlOGY.AND FUEL PRICE
AT A3 PERCENT FUEL PRICE ESCALATION
(VALUES IN 1982$x 10 9)
FUEL PRICE
LOAD GROWTH
FORECAST LOCATION TECHNOLOGY o 1.50
($X 10 6 Btu)
2.00 2.50 3.50 5.50
Low North Slope Simple Cycle 0.360 0.988 1.197 1.406 1.825 2.662
Combined Cycle 0.420 0.952 1.129 1.306 1.661 2.369
Fairbanks Simple Cycle 0.239 0.887 1.103 1.318 1.750 2.614
Combined Cycle 0.256 0.767 0.937 1.108 1.448 2.130
Kenai Simple Cycle 0.248 0.898 1.115 1.332 1.766 2.633
Co)nbi ned Cyc 1e 0.284 0.788 0.956 1.124 1.460 2.132
Medium North Slope Simple Cycle 0.707 1.994 2.416 2.838 3.683 5.373
Combined Cycle 0.875 1.847 2.171 2.495 3.143 4.439
Fairbanks Simple Cycle 0.486 1.769 2.197 2.625 3.480 5.191
i
Combined Cycle 0.556 1.516 1.836 2.157 2.797 4.077
Kenai Simple Cycle 0.505 1.800 2.232 2.663 3.527 .5.253
Combined Cycle 0.562 1.533 1.857 2.181 2.828 4.123
3105A
B5-29
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86.0 CONCLUSIONS AND RECOMMENDATIONS
86.1 ECONOMIC CONCLUSION
The economic data as portrayed in Tables 85-10 through 85-13,and
particularly those in 85-12 (2%fuel price escalation rate)clearly
illustrate that for fuel costs greater than about $1.50/106 8tu for
both medium and low growth forecasts at all three locations,the
combined cycle technology has a clear economic edge,but less so at the
North Slope.Combined cycle is capital cost effective,and has a
slightly lower operating and maintenance factor than the simple cycle
option.It has the highest thenma1 efficiency of any of the
technologies considered.For these reasons,there is ample
justification for selecting the combined cycle technology as the method
for future power generation,should natural gas be available in the
quantities required.Higher fuel costs favor this technology even more.
86.2 TECHNICAL CONCLUSION
There are several technical factors favoring the selection of the
combined cycle option:a 220 MW plant (ISO conditions,baseload)
consisting of two 77 MW independently operated gas turbines and one 66
MW steam turbine generator offers virtually the same flexibility in
construction,timing,operation,and maintenance that the simple cycle
gas turbine offers;at the same time it achieves a heat rate far better
than the simple cycle units.
At the North Slope location,for the range of fuel costs expected
($1.00 to $2.00/106 8tu),the combined cycle option enjoys a very
slight margin in present worth costs versus simple cycle units.
However,to be weighed against this are the added complexities of
operating boilers on the North Slope with attendant water supply,water
treatment,water chemistry control and other more specialized
maintenance requirements of the higher temperature steam cycles.In
addition,spare parts reqUirements increase due to the addition of the
steam turbine cycle and attendant waste heat boilers,duct work,
dampers,and other equipment.
3105A
86-1
Thus,for the North Slope,the technical advantages of the simple cycle
unit outweigh the slight economic edge of the combined cycle.At
Fairbanks and Kenai,the advantages of the combined cycle unit,where
fuel prices are higher,clearly show combined cycle units being
favored,especially since operation of these units is more favorable
due to the availability of trained operators familiar with similar
units and fossil fired boilers and steam turbines.In addition,the
standard construction methods used in these areas more readily lend
themselves to combined cycle plants,whereas the North Slope requires
modular or non-standard methods.
86.3 RECOMMENDATION
Since both th~technical evaluation anq economic analysis favor use of
combined cycle plants for utilizjng North Slope gas to generate
electricity,this technology is recommended for the Fairbanks and Kenai
locations.For the North Slope,the range of fuel costs anticipated do
not outweigh the additional complexities of construction and operation
of the combined cycle unit,and the use of simple cycle units is
recommended.
As discussed previously,simple cycle plants are considered optimum at
the North Slope for reasons of operation flexibility and cost.The low
load forecast results in eight 77 MW (ISO conditions)simple cycle
units at the the North Slope site,for the medium load forecast this
would be fifteen units,as shown in Tables 85-4 and 85-7.
For Fairbanks and Kenai,for low load forecast,three 220 MW (ISO
conditions)combined cycle systems would be installed for the low load
forecast and 5 2/3 combined cycle systems for the medium load forecast
by the year 2010,as shown in Tables 85-5, 85-6,85-8 and 85-9.
3105A
86-2
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B7.0 REFERENCES
Acres American,Inc.1981.Susitna Hydroelectric Project -
Feasibility Report -Volume I,Engineering and Economic Aspects,
Final Draft.Alaska Power Authority.Anchorage,Alaska.
Battelle Pacific Northwest Laboratories.1982.Railbelt Electric
Power Alternatives Study:Evaluation of Railbelt Electric Energy
Plans -Comment Draft.Office of the Governor,State of Alaska.
Juneau,Al aska (February 1982).
Battelle Pacific Northwest Laboratories.1981.Railbelt Electric
Power Alternatives Study -Comment Draft Working Paper 3.1 -
candidate Electric Energy Technologies for Future Application in...
the Alaska Railbelt Region.Office of the Governor,State of
Alaska.Juneau,Alaska.
Edison Electric Institute.1981.Combustion Turbine Operational
Practices Guidebook.EPRJ Operating Development Group.Edison
Electric Institute.Washington,D.C.
R.W.Beck and Associates,Inc.1982.Kenai Peninsula Power Supply
and Transmission Study.Alaska Power Authority.Anchorage,Alaska
(June 1982).
3105A
87-1
NORTH SLOPE GAS FEASIBILITY STUDY
SYSTEM PLANNING REPORT
ADDENDUM 1
Supplemental infonmation for the economic analysis is contained in two
sets of.tables included in this addendum.Each set contains 12
separate tables.The first set shows energy requirements and gas
requirements for each of the twelve scenarios in each year of the study
period.The second set of tables is a summary of generation and
economic data input to the model for analysis of each scenario in each
year.
ENERGY USE AND GAS REQUIREMENTS TABLES
This set of tables utilizes the low and medium load forecasts and the
energy available from nYdro sources to detenmine the net energy
required from thenmal sources.The energy available from the new
plants utiliZing North Slope gas is then calculated.It is then
assumed that use of the new gas units will be preferenti aland actual
utilization of those plants is listed based on their supplying as much
as possible (up to a capacity factor of 0.75)of the net reqUired.The
last column then lists millions of cubic feet of North Slope gas·
required to generate the energy utilized.
There are twelve tables,six for each load forecast,within those six,
three for each technology,for the two technologies.All tables cover
every year of the study period.The North Slope locale tables assume
utilization of untreated gas at 1046 Btu/ft3 (HHV).The Fairbanks
scenario assume treated gas at 1104 Btu/ft3 (HHV)and the Kenai
assumes utilization of a gas treatment plant waste stream of up to 200
x 10 6 ft3/day at 195 Btu/ft3 (HHV).For the waste stream
utilization blending with sales gas to acheive a usable gas of 400
Btu/ft3 (HHV)is .assumed.This allows purchase of turbines with no
modification from those burning pure sales gas.
2573B
1
ELECTRICITY PRODUCED,COSTS AND HEAT RATES
The four data items listed in this table,electricity produced in
gigawatt hour,capital expenditure,operating and maintenance (0 &M)
expenditures and system heat rates,all for each year operation,are
the inputs for economic analysis generated by engineering.design and
estimating.
The project year is listed to indicate the discount period for each
cost item.The electricity produced combined with annual heat rates
and fuel prices yield annual fuel costs.
25738
2
r=L
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lh-"NORTH SLOPE GAS FEASIBILITY STUDY
SYSTEM PLANNING REPORT -ADDENDUM 1
TABLE 3
('-'TOTAL ENERGY USE AND GAS REQUIREMENTSL:~
LOW LOAD FORECAST,SIMPLE CYCLE GENERATION
['.
KENAI LOCALE
[.-
LOAD -HYDRO NET AVAILABLE UTILIZED GAS~EQ~DYEARGWHGWHGWHNSG-GWH NSG-GWH FT 10[f WASTE GAS SALES GAS
('1980 2550 254 2296
t 81 2646 254 2392
82 2742 254 2488
83 2838 254 2584r8429342542680
"-85 3030 254 2776
86 3194 254 2940
C 87 3358 254 3104
l~88 3522 648 2874
89 3686 648 3038
C 90 3850 648 3202
91 3892 648 3244
92 3934 648 3286
fJ 93 3976 648 3328
94 4018 648 3370
95 4060 648 3412
96 4046 648 3398 553 553 12,474.2 3,631.9
C 97 4032 648 3384 1104 1104 24,903.3 7,250.7
98 4018 648 3370 1104 1104 24,903.3 7,250.7
99 4004 648 3356 1104 1104 24,90'3.3 7,250.7
C 2000 3990 648 3342 1107 1107 24,970.9 7,270.4
01 4048 648 3400 1656 1656 37,354.9 10,876.1
02 4106 648 3458 2208 2208 49,806.5 14,501.5
G
03 4164 648 3516 2208 2208 49,806.5 14,501.5
04 4222 648 3574 2767 2767 62,416.1 18,172.8
05 4280 648 3632 3311 3311 74,687.3 21,745.6,.06 4412 648 3764 3863 3764 84,905.7 24,720.8
C 07 4544 648 3896 3863 3863 87,138.9 25,371.0
08 4676 648 4028 4427 4028 90,860.9 26,454.6,"
09 3808 648 4160 4415 4160 93,838.4 27,321.8
L 10 4940 648 4292 4415 4292 96,816.0 28,188.5
,.
[
I,e 2573B
.--"..,5
C
[
~NORTH SLOPE GAS FEASIBILITY STUDY
[SYSTEM PLANNING REPORT -ADDENDUM 1
TABLE 13
~.
[LOADS,COSTS AND HEAT RATES
LOW LOAD FORECAST,SIMPLE CYCLE GENERATION
C.NORTH SLOPE LOCALE
C ELECTRICITY CAPITAL O&M
PROJECT PRODUCED EXPENDI~URE EXPENDITURE HEAT RATE
[YEAR YEAR (GWH)($x10 )($x 106 )(BTU/KWH)
[1980
81
0 82
1 83
[,.2 84
J.3 85
4 86
r=5 87
L 6 88
7 89
['8 90
9 91
/--10 92
11 93
C 12 94
13 95 72.63
14 96 ,600 53.56 3.780 11 ,500
0 15 97 1,1~6 -0-7.535 11 ,500
16 98 1,196 -0-7.535 11 ,500
17 99 1,196 -0-7.535 11 ,500
C 18 2000 1,196 -0-7.535 11 ,500
19 01 1,196 53.56 7.535 11 ,500
20 02 1,794 53.56 11.302 11,500
G
21 03 2,391 -0-15.063 11 ,500
22 04 2,398 107.12 15.107 11,500
23 05 3,587 -0-22.598 11 ,500'.24 06 3,587 -0-22.598 11 ,500
C 25 07 3,587 53.56 22.598 11 ,500
26 08 4,028 -0-25.376 11,500
27 09 4,160 53.56 26.208 11 ,500
[j 28 10 4,292 -0-27.040 11 ,500
.,
L.-
~-
L 2573B
.-15
t
r
NORTH SLOPE GAS FEASIBILITY STUDY [SYSTEM PLANNING REPORT -ADDENDUM 1
TABLE 16
LOADS,COSTS AND HEAT RATES r
LOW LOAD FORECAST,COMBINED CYCLE GENERATION
NORTH SLOPE LOCALE [
['
ELECTRICITY CAPITAL O&M
PROJECT PRODUCED EXPENDI~URE EXPENDI~URE HEAT RATE
YEAR YEAR (GWH)($x10 )($x10 )(BTU/KWH)['
"
1980 ['81
0 82
1 83
2 84 R385L_":
4 86
5 87 E688
7 89
8 90 [9 91
10 92
11 93
12 94 [13 95 91.70
14 96 600 ·53.56 3.300 11 ,500
15 97 1,196 -0-6.578 11 ,500 C16981,196 -0-6.578 11 ,500
17 99 1,196 -0-6.578 11,500
18 2000 1,196 95.31 6.578 11 ,500 r19011,662 53.56 9.141 8,320 ,~20 02 2,260 -0-12.430 9,161
21 03 2,260 53.36 12.430 9,161
2'2 04 2,866 111.70 15.763 9,650 ['23 05 3,324 53.36 18.282 8,320 ~_c ;
24 06 3,764 -0-20.702 8,805
25 07 3,896 53.56 21.428 8,305 [26 08 4,028 -0-22.154 9.16t
27 09 4,160 -0-22.880 9,161
28 10 4,292 -0-23.606 9,161
[
L
2573B L18
.[
[
NORTH SLOPE GAS FEASIBILITY STUDY ['SYSTEM PLANNING REPORT -ADDENDUM 1
TABLE 18
LOADS,COSTS AND HEAT RATES [
LOW LOAD FORECAST,COMBINED CYCLE GENERATION
KENAI LOCALE [
['ELECTRICITY CAPITAL O&M
PROJECT PRODUCED EXPENDIlURE EXPENDITURE HEAT RATE
YEAR YEAR (GWH)($x10 )($x 106 )(BTU/KWH)[
1980 L81
0 821·83
2 84 R385L'4 86
5 87 [6 88
7 89
8 90
9 91 C1092
11 93
12 94 [;13 95 46.28
14 96 553 35.98 2.212 11 ,650
15 97 1,104 -0-4.416 11 ,650 [16 98 1,104 -0-4.416 11 ,650
17 99 1,104 -0-4.416 11 ,650
18 2000 1,104 53.65 4.416 11 ,650
19 01 1,557 35.68 6.228 8,280 t20022',109 -0-8.436 9,162
21 03 2,109 35.68 8.436 9,162
22 04 2,668 56.70 10.672 9,678 ~23 05 3,114 35.68 12.456 8,280
24 06 3,666 -0-14.664 8,787
25 07 .3,666 35.68 14.664 8,787 [26 08 4,028 -0-16.112 9,162
27 09 4,160 56.70 16.640 9,162
28 10 4,292 -0-17.168 8,280
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NORTH SLOPE GAS FEASIBILITY STUDY [SYSTEM PLANNING REPORT -ADDENDUM 1
TABLE 22 [LOADS,COSTS AND HEAT RATES
MEDIUM LOAD FORECAST,COMBINED CYCLE GENERATION
('
NORTH SLOPE LOCALE t
[
ELECTRI CITY CAPITAL O&M
PROJECT PRODUCED EXPENDITURE EXPENDITURE HEAT RATE r~YEAR YEAR (GWH)($x 106 )($x 106 )(BTU/KWH)
1980 [~81
0 82
1 83 r284
3 85 ~-'
4 86
5 87 [
6 88 L
7 89
8 90 [9 91
10 92 91.76
11 93 598 -0-3.289 11 ,500 [12 94 598 53.56 3.289 11 ,500
13 95 1,196 95.31 6.578 11 ,500 -,
14 96 1,667 53.56 9.169 8,320
15 97 2,260 53.56 12,340 9,161 [16 98 2,858 111.70 15.719 9,650
17 99 3,324 53.56 18.282 8,320
18 2000 3,933 -0-21.632 8,805 e19013,922 53.56 21.571 8,805
20 02 4,520 111.70 24.860 9,161
21 03 4,987 53.56 27.429 8,320 L22045,588 165.26 30.734 8,660
23 05 5,780 53.56 31.790 8,320
24 06 6,053 53.56 33.292 8,582
25 07 6,325 111.70 34.788 8,805 [26 08 6,598 53.56 36.289 8,320
27 09 6,870 -0-37.785 8,533
28 10 7,143 -0-39.287 8,533 [
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~NORTH SLOPE GAS FEASIBILITY STUDY
['SYSTEM PLANNING REPORT -ADDENDUM 1
TABLE 23r:"(-'.LOADS,COSTS AND HEAT RATEStoMEDIUMLOADFORECAST,COMBINED CYCLE GENERATION
~.---.
FAIRBANKS LOCALEr',
,-.-
[ELECTRICITY CAPITAL O&M
PROJECT PRODUCED EXPENDI~URE EXPENDI~URE HEAT RATE
r'---YEAR YEAR (GWH)($xl0 )($xl0)(BTU/KWH)f',
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1980
81
..;0 82
1 83
C~2 84
3 85
'4 86
C 5 87
6 88u789
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8 90
9 91
~;J 10 92 43.86
11 93 565 -0-2.260 11,600
[12 94 565 33.90 2.260 11,600
13 95 1,130 56.97 4.520 11 ,600
14 96 1,594 67.80 6,376 8,290
C 15 97 2,720 59.63 10.880 9,665
16 98 3,180 -0-12.720 8,290
17 99 3,180 33.90 12.720 8,290
E 18 2000 3,755 -0-15.020 8,789
19 0]3,745 93.53 14.980 8,789
20 02 4,770 -0-19.080 8,290
21 03 4,770 33.90 19.080 8,290
~22 04 5,349 93.53 21.396 8,641
23 05 5,780 33.90 23.120 8,290
24 06 6,053 33.90 24.212 8,560
C 25 07 6,325 59.63 25.300 8,789
26 08 6,598 33.90 26.392 8,290
27 09 6,870 33.90 27.480 8,510
[28 10 7,143 -0-28.572 8,702
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NORTH SLOPE GAS FEASIBILITY STUDY [SYSTEM PLANNING REPORT -ADDENDUM 1
TABLE 24
LOADS,COSTS AND HEAT RAT~S [
MEDIUM LOAD FORECAST,COMBINED CYCLE GENERATION
KENAI LOCALE L
[ELECTRICITY CAPITAL O&M
PROJECT PRODUCED EXPENDI~URE EXPENDI~URE HEAT RATE
YEAR YEAR (GWH)(Sx 10 )(Sx 10 )(BTU/KWH)[~
1980 L81
0 82 .
1 83
2 84 8385
4 86
5 87 C688
7 89 t~.
8 90 C991
10 92 46.28
11 93 552 -0-2.208 11 ,650
12 94 552 35.68 2.208 11,650 L13951,104 53.65 4.415 11 ,650
14 96 1,561 71.36 6.244 8,280
15 97 2,661 56.70 10.644 9,678 C16983,114 -0-12.456 8,280
17 99 3,114 35.68 12.456 8,280
18 2000 3,676 -0-14.704 8,787 e19013,666 92.38 14.664 8,787
20 02 4,671 35.68 18.684 8,280
21 03 5,223 35.68 20.892 8,636
22 04 5,588 92.38 22.352 8,924 O[
23 05 5,780 35.68 23,120 8,554 :=..;J
24 06 6,053 -0-24.212 8,787
25 07 6,325 56.70 25.300 8,787 C26086,598 35.68 26.392 8,280
27 09 6,870 35.68 27.480 8,503
28 10 7,143 -0-28.572 8,&98
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APPENDIX C
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APPENDIX C
REPORT ON
FACILITY SITING AND CORRIDOR SELECTION
EBASCO SERVICES,INCORPORATED
JAtmARY 1983
Page
C1-1
C1-1
C1-1
C1-1
Cl-2
Cl-5
C3-1
C3-1
C3-3
C3-4
C3-9
C3-10
C3-11
C3-25
C4-1
C4-1
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C4-8
C4-10
C4-11
C4-11
C4-13
C4-15
C4-16
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TABLE OF CONTENTS
C3.2.1 Prudhoe Bay-Fairbanks ••••••
C3.2.2 Fairbanks-Anchorage ••••••
C3.1.1 Description of Region ••••••
C3.1.2 Siting Considerations •••••
C3.1.3 Generic Site Description ••••
I NTROD UCT ION • • • • • • • • • • • • • • • • • •
C4.2.1 Routing Considerations ••••••
C4.2.2·Applicability of the ANGTS Route.
C4.3 GAS DISTRIBUTION SYSTEM FOR FAIRBANKS • • • •
C4.4 TRANSMISSION FACILITY ROUTING EVALUATION
C4.2 GAS PIPELINE ROUTING EVALUATIONS
C4.1.1 Description of the Region ••••
C4.1.2 Siting Considerations ••••••
C4.1.3 Candidate Siting Areas •••••••••••
C4.1.4.Generic Site Description ••
C3.2 TRANSMISSION FACILITY ROUTING EVALUATIONS • •
C2.1 OBJECTIVES ••
C2.2 SITING FACTORS
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C4.0 SCENARIO II -FAIRBANKS POWER GENERATION.
C4.1 GENERATING FACILITY SITE EVALUATIONS ••
CLO
C2.3 IDENTIFICATION AND EVALUATION OF CANDIDATE AREAS •
C2.4 DEVELOPMENT OF GENERIC SITE AND ROUTE DESCRIPTIONS.
C3.0 SCENARIO I -NORTH SLOPE POWER GENERATION
C3.1 GENERATING FACILITY SITE EVALUATIONS
C2.0 FACILITY SITING AND CORRIDOR SELECTION PROCESS.
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C5.2 TRANSMISSION FACILITY ROUTING EVALUATIONS .
C5.1 GENERATING FACILITY SITE EVALUATIONS ••
C5.2.1 Kenai-Anchorage Corridor •.•.
C5.2.2 Anchorage-Fa'irbanks Corri dor .••
C5.0 SCENARIO III -KENAI POWER GENERATION .••
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C5-1
C5-1
C5-1
C5-3
C5-5
C5-6
C5-7
C5-11
C6-1
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TABLE OF CONTENTS
• • • • • • • • • • • • •0 • •
C5.1.1 Description of the Region •••
C5.1.2 Siting Conditions ••..•••
C5.1.3 Generic Site Description .•.•
C6.0 REFERENCES.
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Table Number
C3-l
Fi gure Number
C3-l
C4-l
C5-l
LIST OF TABLES
Title
State of Alaska Temporal and Spatial
Protection Criteria for Nesting Raptors
LIST OF FIGURES
Title
Scenario I -North Slope Power Generation
Scenario II -Fairbanks Power Generation
SCenario III -Kenai Power Generation
iv
C3-20
C3-2
C4-2
C5-2
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Cl.O INTRODUCTION
The North Slope gas feasibility level assessment will result in a series
of four reports.This report on facility siting and corridor selection
is the third of that series.The complete series of reports is as
follows:
1.Report on Existing Data and Ass~mptions
2.Report on System Planning Studies
3.Report on Facility Siting and Corridor Selection
4.Feasibility Assessment Report (draft and final)
This overall study is focused on three alternative development scenarios
for power generation and gas and electrical transportation systems to
move the energy from its source to points of consumption:
o Electrical generation at the North Slope,with electrical
transmission to Fairbanks via a new transmission line,and on to
Anchorage via an upgraded Anchorage-Fairbanks Intertie;
o Transport of North Slope natural gas via a small diameter
pipeline to Fairbanks,with electrical generation at Fairbanks
and simi,lar upgrading of the In~ertie for transmission to
Anchorage;
o Electrical generation at the terminus of a high-pressure natural
gas pipeline to tidewater (Kenai-Nikiski area of the Kenai
Peninsula),fueled by a waste component of the gas stream,with
necessary electrical transmission to Anchorage and Fairbanks.
These are hereafter referred to as Scenario I:North Slope Power
Generation;Scenario II:Fairbanks Power Generation;and Scenario III:
Kenai Power Generation,respectively.-
26058
Cl-l
Following this introductory chapter,Chapter.C2 details the siting
process used in this study.Chapters C3,C4,and C5 provide complete
siting descriptions for each respective scenario.Maps of the scenarios
are provided in each of those chapters.
26058
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C2.0 FACILITY SITING AND CORRIDOR SELECTION PROCESS
C2.l OBJECTIVES
Prelimina~siting of the facilities included within each development
scenario was accomplished at a level of detail cOlll11ensur~te with the
conCeptual design requirements of this feasibility level assessment.The
objective of this stuqy component is to provide a realistic p~sical
setting for engineering,economic and environmental evaluations of the.
power generating,gas transport,and electric transmission facilities
included within each of the three scenarios under consideration,rather
than to identify specific sites or routes.The siting process has
emphasized those considerations most critical to facility cost.In
addition,siting opportunities and/or constraints associated with each of
the candidate areas and corridors are identified.
The general areas considered for siting the generating facilities and
routing the gas transportation and transmission facilities are identified
in Section C2.3 below.These areas were used to develop generic site and
route descriptions for each scenario.It is expected that further
planning studies will be required in order to select actual sites and
preci se routes.
C2.2 SITING FACTORS
Because the objectives of this study are oriented to the requirements of
conceptual engineering and cost estimating,and not toward the selection
of specific sites or rights-of-way,the siting factors developed for the
study's purposes are limited in number and are broad in scope.
Establishment of suitable factors was an interactive process in which
siting considerations important to each scenario/region were identified
by the stuqy participants,in parallel with the development of
prelimina~infonnation regarding unit sizing and generation/transmission
concepts.For example,based on the region's climatic extremes,it was
evident early in ·the stuqy process that the stuqy would focus on
2605B
C2-l
air-cooled (dry)condenser systems for combined-cycle plants.
Therefore,unlike ,most traditional power plant siting studies,the
availability of sUbstantial volumes of water for condensercoolfng
purposes would not be a significant siting criterion.
For each scenario (as discussed in succeeding chapters),relevant factors
were developed for land status and use,geotechnical,engineering and
environmental considerations.In general,the considerations were
developed to ensure that 1)significant site-related factors were not
overlooked in each scenario,2)descriptions of the pnYsical settings for
further evaluations of the generating and transmission facilities would
be focused on factors which are significant engineering and/or cost
Concerns and 3)"fatal-flaw"environmental constraints would not prohibit
development.
C2.3 IDENTIfICATION AND EVALUATION OF CANDIDATE AREAS
The regions encompassed by each generation scenario are large and can
pose significant constraints to industrial development.It was necessary
to substantially narrow the geographic focus of the siting activities
early in the study process,so that study resources could be allocated to
the development of a realistic pnYsical setting for the sUbsequent
assessments,rather than to a search for specific sites or routes which
offer the greatest development potentia).The following paragraphs
describe the basis for this "narrowing of focus,"first for the
generating facilities siting evaluations,and then for the transmission
and pipeline corridor delineations.
The potential siting area for a generating facility for Scenario I -
North Slope Power Generation -encompasses a vast region from the
Beaufort sea to the foothills of the Brooks Range.Primarily because of
the existing support infrastructure,including road and electrical
transmission systems and centralized waste treatment facilities,the
generating site evaluation was confined to locations reasonably close to
the Prudhoe Bay/Deadhorse development complex.Close proximity minimizes
2605B
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POWER PLANT SITING AREA
TRANSMISSION LINE
CORRIDOR
NATURAL GAS PIPELINE
CORRIDOR
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FIGURE C 3-1
StENARIO I
ALASKA POWER AUTHORITY
EBASCO SERVICES INCORPORATED
NORTH SLOPE POWER GENERATION
NORTH SLOPE GAS FEASIBILITY STUDY
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haul distances from the existing barge unloading facilities.and
minimizes new road construction.The Prudhoe Bay area is relatively
unifonn with respect to the occurrence of permafrost.small surface
lakes.topographY.and climate.ACtual site selection would consider the
following factors:1)minimizing interferences with ~isting land uses
and facili~ies such as the pipelines comprising ,the gathering system;
2)optimizing the use of the supporting infrastructure.particularly
roads;and 3)avoiding locations of significant environmental value.such
as snow goose nesti ng areas.For these reasons.a generic site
description encompassing significant factors likely to be encountered in'
most specific locations within the Prudhoe Bay area was developed.
Scenario II -Fairbanks Power Generation -is the most complex from a
siting perspective with topograpic.land use.and air quality/
meteorologic conditions exhibiting significant variation within the
area~This variation makes it difficult to define a homogeneous siting
area.For purposes of this stuqy.prelimina~evaluations considered an
approximate 50~ile radius centered on Fairbanks.Fairbanks is located
at the northern edge of the broad Tanana River Valley.Extensive low,
flat areas occur to the south and east,While the terrain rises
significantly just to the north and west of the city.Most of the area
south and east of Fairbanks is occupied by military reservations
(Ft.Wainwright and Eielson Air Foree Base);these designated land uses
have concentrated some industrial expansion from the city into a narrow
corridor along the Richardson Highway,particularly at or near the.
community of North Pole.This area would be potentially suitable for the
generating facility site.Industrial development north and west of
Fairbanks is limited by the steepening terrain and by federal land
holdings.The southern boundary of the White Mountains National
Recreation Area is about 25 miles north of Fairbanks.Suitable
topographY and access indicates that industrial development could be
accommodated to the southwest,toward Nenana,but that is in the opposite
directi on from the TAPS Corri dor.which passes to the east of Fai rbanks.
For'these reasons.the geographic focus of this stuqy was narrowed to
include Fairbanks itself and nearby areas suggested by local utility
2605B
C2-3
representatives.Specific candidate siting areas are discussed in
Chapter C4,along with a discussion of the climatic peculiarities of the
Fairbanks area which may influence the siting of new generating
facilities.The generic site description developed for Scenario II is
based on conditions likely to be encountered within a short distance
(10-15 miles)southeast of Fairbanks.This is not to imply that
generating facilities could not be sited elsewhere in the Fairbanks
region,but rather to provide a reasonable and realistic basis for the
subsequent engineering investigations.
Scenario III -Kenai Area Power Generation -encompasses a much smaller
area than the previous scenarios.This area is the assumed terminus of
an all-Alaska large diameter natural gas pipeline.The communities of
Kenai,Sa1amatof and Nikiski comprise a linear residential,commercial,
and industrial development area,linked together by the North Kenai Road,
along the west side of the Kenai Peninsula.The area occupies a
relatively narrow strip between the Kenai National Wildlife Refuge and
Cook Inlet.Within this well-defined area,p~sica1 and environmental
characteristics are relatively uniform.The area is relatively flat,
varying from 100 to about 150 feet in elevation,with spruce bogs and
small lakes predominating.The principal siting consideration is the
existing industrial infrastructure,which consists of petrochemical
refineries and supporting facilities,a gas-fired generating station and
transmission system operated by Chugach Electric Association,and one
major road.For this scenario,a "narrowing of focus "was·not necessary
for development of a generic site description.
The geographic focus of the transmission corridor evaluations under each
scenario was determined by the existence of established utility corridors
or routes.The established Utility Corridor was used as the basis of the
gas pipeline and electric transmission routing evaluations between
Prudhoe Bay and Fairbanks.The Utility Corridor is defined by the Bureau
of Land Management (BLM 1980)as a strip of land 336 miles in length from
Washington Creek (28 miles north of Fairbanks)to Sagwon B1 uffs (60 miles
south of Prudhoe Bay).It varies in width from 12 to 24 miles and
2605B
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contains about 3.6 million acres.The Corridor was withdrawn and
designated as a utility and transportation corridor by Public Land Order
5150 in 1971.For the purposes of.this stu~,the Utility Corridor (and
extensions to Prudhoe Bay and Fairbanks at either end)was divided into
seven segments,each exhibiting relatively uniform characteristics for
pipeline and transmission line routing.
Electric transmission between Fairbanks and Anchorage was assumed to
involve three geographic segments:
o the Anchorage-Fairbanks Intertie,now under construction between
Willow and Healy;
o existing Golden Valley Electric Association transmission
rights-of-way between Healy and Fairbanks;and
o existing Chugach Electric Association transmission rights-of-way
between Willow and Anchorage.
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The routi ng eval uati ons focused on upgrade requirements in each segment
rather than on alternative routes.Electric transmission between Kenai
and Anchorage was likewise assumed to be via the existing Chugach
Electric Association rights-of-way;these would also require substantial
upgrading and possibl ere-routing in selected areas.One such area i ~
the right-of-way alongside the highway which traverses the north
shoreline of Turnagain Arm.The ve~limited area available between the
shoreline and steep cliff in thi s segment milY preclude upgradi ng the
existing transmission line.Routing alternatives to avoid this severe
constraint include a submarine cable crossing Turnagain Arm.These
alternatives are discussed in greater detail in Chapter C5.
C2.4 DEVELOPMENT OF GENERIC SITE AND ROUTE DESCRIPTIONS
The methods described above were used to develop generic site and route
descriptions upon which the subsequent feasibility assessments are
26058
C2-5
based.For each generation and transmission scenario,a generalized site
and corridor description was developed by the study team.Important
parameters included access (in relation to the overall area),size and
surface characteristics,water resources,soils and foundations,and
environmental conditions.
.Gas transportation and electric transmission facility routes are
described on the basis of relatively homogeneous spatial segments,such
as the Arctic Coastal Plain.Significant routing considerations specific
to individual segments are given special attention in the generic route
descri pti ons.
26058
C2-6
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C3.0 SCENARIO I -NORTH SLOPE POWER GENERATION
The North Slope scenario consists of electrical generation at the North
Slope,with electrical transmission to Fairbanks via a new transmission
line,and transmission from Fairbanks to Anchorage via an upgraded.
Anchorage-Fairbanks Intertie.This scenario is illustrated in Figure
C3-l.
C3.l GENERATING FACILITY SITE EVALUATIONS
The·previous report issued in this series,"Report on System Planning
StUdies,"concluded that the best generating plant design for the North
Slope is either a series of 220 MW combined cycle units consisting of two
77 MW gas turbine units and a 66 MW steam turbine,or a series of 77 MW
simple cycle gas turbines alone,depending on fuel price.Three combined
cycle units with one simple cycle unit or nine simple cycle units alone
would be required for the low load forecast,while six combined cycle
units with one simple cycle unit or eighteen simple cycle units alone
would be required for the medium load forecast.In evaluating potential
sites for the generating facilities,the plant size corresponding to the
medium load forecast for both the combined cycle and simple cycle
alternatives was used,under the assumption that a~site appropriate for
the larger development scenario would be more than adequate for the other
a 1ter.natives.
The purpose of the generating facility site evaluations was to provide
realistic site characteristics for engineering,economic,and
environmental evaluations;not to identify a specific site.The
geographic focus 'of the North Slope site selection process was the
existing Prudhoe Bay/Deadhorse development complex,because of the
existing support infrastructure.An overview of the Prudhoe Bay region
is given below,followed by siting criteria and the generic site
d.escription.
2605B
C3-l
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C3.1.1 Description of Region -the Prudhoe Bay/Deadhorse Area
The Prudhoe Bay area is located at the northernmost reaches of the North
Slope in flat.treeless.lake-filled tundra that extends from the
foothills of the Brooks Range to the Arctic Ocean.It is an industrial
enclave eight to ten miles inland from the coast near the mouth of the
Sagavanirktok (Sag)and Putuligayuk (Put)Rivers.The Prudhoe Bay
industrial area consists of numerous facilities to support oil recovery.
processing and transportation.and a number of work camps housing
construction and operations personnel.The Deadhorse airport is located
in the southeastern section of the industrial area.
Pnrsical setting
The Prudhoe Bay area is located i'n the Arctic Coastal Pl ain.a
subdivision of the Interior Plains physiographic province.The Arctic
Coastal Plain topography consists of a smooth plain that rises from the
Arctic OCean to a maximum altitude of 600 feet at its southern border
(W~hrhaftig 1965).Since the area is poorly drained.numerous marshes
form in the summer.The land area is underlain by continuous pennafrost
approximately 2.000 feet thick which thaws a short distance below the
surface in summer.Common permafrost landforms include ice-wedge
pOlygons,braided streams,oriented thaw lakes.and pingos (University of
Al aska 1978b).
The Prudhoe Bay area is beset with harsh weather conditions.The
seasonal variation is dramatic due to the high latitUde.where d~light
lasts continuously during the summer and the sun remains below the
horizon for 56 d~s in midwinter.The prevailing winds are
east-northeast year-round with an average speed of 11 mph.Periods of
stagnation are very rare.Fog is a regular occurrence at Prudhoe Bay.
particularly during the summer months.Temperature ranges are large with
measured annual extremes of _60°F and +75°F.The ground is covered with
snow a major portion of the year but precipitation is less than 7 inches
per year (University of Alaska 1978a).
26058
C3-3
Social Profile
Prudhoe Bay/Deadhorse is the largest community in the North Slope Borough
with a transient population of approximately 6000.The second largest
cOlllnunity is Barrow,the economic center of the North Slope Borough,
located 110 miles northwest of Prudhoe Bay.As an industrial enclave,
Prudhoe Bay is geographically isolated from communities on the North
Slope and does not depend on the North Slope Borough for provision of
services.
Travel in the region is primarily by air carrier,although nonperishable
goods and bulkY items are shipped by barge during the navigable season,
generally a six-week period duri ng August and the first half of
September.The only major road is the Dalton Highway (Haul Road)which
links Prudhoe Bay to Fairbanks.
The Inupiat,or northern Eskimos,are the indigenous people of the North
Slope.The region is characterized by a dual economy of wage employment
and subsistence that allows many of the Inupiat to continue cultural
traditions using modern technology.In general,unemployment is a
serious problem among the permanent residents.Both economic and
cultural pressures have intensified the need for continued access to
subsistence resources.The Inupiat are oriented both to the sea and
interior regions for resources to maintain a subsistence lifestyle.
Bowhead whale,seal,and caribou provide the bulk of subsistence needs
for the Inupiat;waterfowl,furbearers,and fish are relied on to a
1esser degree.
C3.l.2 Siting Considerations
Development of siting criteria focused on major factors that could affect
the cost and design of the generating facility.Siting criteria for the
North Slope scenario were developed under the assumption that the plant
would be located in the Prudhoe Bay/Deadhorse industrial area,and would
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consist of six 220 MW combined cycle units and one 77 MW simple cycle
unit,or eighteen simple cycle units.
C3.1.2.1 Land Status and Use Considerations
The Coastal Zone Management Program for the North Slope Borough has
delineated zones of preferred development.Permanent facilities are
allowed in the industrial development zone,consisting of the existing
Prudhoe Bay/Deadhorse complex and the Pipeline/Haul Road Utility corridor
(North Slope Borough 1978).
Within the Prudhoe Bay/Deadhorse complex,land use criteria consist of
minimiZing interferences with existing or planned facilities,including
buildings,pipelines,roads,and transmission lines.Land ownership and
lease agreements will al so limi t the land availabl e for the electrical
generating facility.
C3.1.2.2 Geotechnical Considerations
Due to the uniformity of foundation conditions at the North Slope (i.e.,
a thin active zone overlying permafrost),the major geotechnical
consideration is developing a foundation scheme that would not cause
permafrost degradation.The entire area is in seismic zone one,so
seismic risk is not a significant siting criteria within the Prudhoe Bay
area.
C3.l.2.3 Engineering Considerations
The site must be sufficiently large to house the generating units,a
sWitchyard,and a construction and operations camp (should existing
facilities be inadequate)for approximately 400 workers (approximately 70
acres).The site should be fairly level and adequate drainage must be
provided.
2605B
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The site should be in close proximity to the barge unloading facilities
to minimize the cost of transporting equipment and should be close to
existing electrical transmission lines,access roads,and gravel borrow
areas to minimize cost and minimize land disturbance.
The site should have access to the existing sewage and solid waste
disposal facilities.It should be possible to route a natural gas
pipeline from the gas source (the compressor facility)to the site.
Combined cycle units require water for boiler feedwater makeup
reqUirements,potable demand and other minor miscellaneous uses such as
eqUipment wash down.Depending upon ambient air quality,a water or
steam injection system may be required to limit the emissions of oxides
of nitrogen (N~).In this syst~demineralized water is injected
directly into the combustors limiting the peak flame temperature which in
turn limits the fonnation of HOx •Typical water injection rates for
each unit at base load are about 50 gallons per minute (gpm)for gas fuel.
For the medium load forecast and both the combined cycle and simple cycle
alternatives,the site must have access to approximately 900-1000 gpm of
water if water injection for NOx control is required.If water
injection is not required,the combined cycle alternative will require
approximately 200 gpm while the simple cycle alternative will require
about 50 gpm.
C3.l.2.4 Environmental Considerations
The major environmental considerations for siting a generating facility
in'Prudhoe Bay relate to air quality,aquatic,and terrestri al ecology.
Air Quality
Air quality concerns playa signficant role in the siting of thermal
power plants anywhere in the United States,and Alaska is no exception.
The facility will be required to meet atmospheric emission standards and
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to demonstrate compliance with ambient air quality standards.TWo sets
of emission standards exist..These are the New Source Perfonnance
Standards (NSPS),which apply generically to combustion turbines;and the
Best Available Control Technology (BACT),which is the best control
system which can be affordably used on the plant's emissions.The
Prudhoe Bay area is currently undergoing an intensive development of its
oil resources.This development is having an impact on the air quality
of the region.The Clean Air Act Amendments of 1977 establish allowable
increments of degradation of ai r quality.These amendments,called the
"Prevention of Significant Deterioration"(PSD)program,protect the air
quality of relatively clean areas from undergoing substantial
degradation.However,the allowable PSD increments for particulates and
sulfur dioxide in the Purdhoe Bay area have not been used up.In
addition PSD increments for nitrogen oxides,the major pollutant from
combustion turbines have not been established.Therefore,it is unlikely
that the installation of a gas-fired 'power plant in Prudhoe Bay wou1d~be
hampered by air quality regulations,if a judicious siting effort is
undertaken to prevent the compounding of any air pollution problems from
existing facilities.
For combustion turbines,the PSD requirements would nonnally dictate the
use of water or steam injection techniques to reduce the emission of
nitrogen oxides to a level which meets the definition of Best Available
Control Technology.The use of water injection measures will lead to the
fonmation of ice fog in the Prudhoe Bay'area and will also require the
availabil ity of an adequate supply of suitabl e fresh water.These
additional requirements pose a substantial threat to the installation of
combustion turbines,which use water injection control,in the Arctic
e nvi ro lIDent.In the recent past,agenc i es wi th revi ew a uthori ty 0 ve r the
installation of the combustion turbines have granted a waiver from the
use of water or steam injection in the Prudhoe Bay area.It will also be
necessar,y in the specific case being examined to obtain a waiver from
these same requirements before the pl'anned combustion turbines can be
installed.The use of air cooled condensers or dry cooling towers is
also required in order to eliminate the fonnation of ice fog and its
2605B
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associated hazards (primarily the reduction of visibility for road
traffic)•
Aquatic Ecology
Two groups of fi sh util i ze the freshwater resources of the Prudhoe Bay
area and would thus require consideration ·during the detailed site
selection process:river fish such as the grayling,and anadromous fish
such as the Arctic char and cisco.The·anadromous species descend local
rivers at ice-breakup to feed in the shallow littoral and sublittoral
zone of the Beaufort sea.They ascend these rivers in the autumn and
overwinter in deep pools.These fish do not appear to undertake
extensive migrations up the Sag or Put Rivers.Potential
development-related impacts on fish which would require consideration
include:pipeline and access road construction,and gravel mining in
rivers which could affect overwintering and general habitat quality of
the fish;and the need to cross larger river channels which could
interfere with fish passage.The latter item may require the use of
special culverts to maintain migrato~routes.
Terrestrial Ecology
The Prudhoe Bay area and specifically the river delta areas provide a
variety of habitats that are important to a diversity of plants and
animals.The varied features of estuarine and river delta shorelines,
sand dunes and dr,y,moist,wet,and aquatic tundra provide conditions for
ma~types of vegetation that in turn provide breeding,feeding,nesting,
and staging areas for many birds and mammals.A prime eoncern relative
to the effects of any major development on the North Slope is the effect
of vegetation change on important wildlife habitat.In addition,the
ecological value of wetland vegetation has been nationally recognized,
and these areas have been granted special regulator,y status under section
404 of the Clean Water Act of 1977.Project related impacts which would
require special consideration during a detailed siting study include:
1)direct habitat elimination through the construction of project
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facilities,access roads,and gravel borrow areas;2)indirect habitat
elimination resulting from access roads which impede drainage or which
generate significant traffic related dust;and 3)restrictions to large
mammal movements,especially caribou.
C3.1.3 Generic Site Description
It is assumed that one or more locations could be found that would fit
the generic description given below.The descriptions are of p~sical
characteristics as they are assumed to exist,and emphasizes factors that
may significantly affect cost or engineering design.
C3.1.3.1 Location and Access
The electrical generating facility site is located within the industrial
enclave of Prudhoe Bay/Deadhorse,in the general vicinity of the existing
SOHIO-operated powerplant,approximately five miles from the Beaufort 'Sea
shoreline.This general location does not involve extensive transport
distances for equipment received at the barge unloading facilities,and
is also accessible for material transported by air or via the Haul Road.
The area is served by existing roads,transmission lines,and waste
treatment and disposal facilities,minimizing the cost for developing
these facilities.
C3.1.3.2 Size and Surface Characteristics
The power plant site is approximately 65 acres in size,inclUding the
power plant housing and switchyard.An additional five acres will be
used for the construction camp,operations personnel housing,and related
facilities.The construction camp site is located adjacent to the
generating facility site.
The power plant site is on a nearly level $lope,although final grading
will be achieved by shaping the gravel mat that will underlie the
structure.
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C3.1.3.3 Water Source
The power plant site is located adjacent to a lake of approximately
600 acres.The lake will be dredged to an appropriate depth to provide
adequate storage volumes.The lake will provide the water needed for
boiler feedwater req~irements~potable,and ~ther miscellaneous uses,but
will not provide sufficient quantities for water or steam injection
associ ated wi th NOx control.If water i njecti on is requi red,a
suitable fresh water source would have to be developed.
C3.1.3.4 Soils and Foundations
The existing soil profile consists of an active zone approximately
1.5 feet thick overlying permafrost.The permafrost in this area is
about 2000 feet thick.
Because mai ntenance of the permafrost is the pri mary geotechnical
consideration in building a generating facility on the North Slope,
foundation design will ensure permafrost integrity.A five foot thick
engineered gravel mat will be placed directly over the tundra.Power
plant modules will be set on 2-foot diameter steel pipe piles having a
wall thickness of one inch.The pipe piles will be placed in 30 to
35-foot deep pre-augered holes,and backfilled with a sand-water slurry.
A 90-day freezeback period will be required prior to loading any piling.
Piling will extend above the ground surface six to eight feet,resulting
ina total pil e 1ength of 36 to 43 feet.Thi s foundati on des i gn wi n
prevent any thawing of the permafrost from the generating facility.
C3.2 TRANSMISSION FACILITY ROUTING EVALUATIONS
The North Slope scenario involves transmitting electricity generated at
the North Slope to Fairbanks and on to Anchorage.Discussion of the
transmission route is divided into two sections,Prudhoe Bay to
Fairbanks,within the utility corridor,and Fairbanks to Anchorage,via
the Intertie now under construction.This scenario assumes that 100
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percent of the generated electricity woul d be transmitted to Fairbanks,
and approximately 80 percent transmitted on to Anchorage.
C3.2.1 Prudhoe Bay to Fairbanks
C3.2.1.1 Description of the Region
The designated utility corridor extending from Prudhoe Bay to Fairbanks
consists of a strip of land about 425 miles long and from 12 to 24 miles
wide.The portion of the corridor from Sagwon Bluffs,60 miles south of
Prudhoe Bay,to Washington Creek (28 miles north of Fairbanks)was
designated as a utility transportation corridor by Public Land Order
(PLO)5150 in 1971.This PLO also designated an inner corridor,
extending the entire length and var,ying in width from three to 20 miles.
The trans-Alaska oil pipeline (TAPS)occupies a 54-foot right-of-way
within the corridor.Related pipeline facilities such as pump stations,
material sites,and access roads are located along the corridor's
length.The Dalton Highw~(Haul Road)completed in 1974 to serve
pipeline construction-needs,·is a 28-foot wide,a1l~eather,gravel
highway within a 200~foot right-of-way granted to the State of Alaska.
It extends from the Elliott Highway to Prudhoe Bay.North of the Yukon
River the highway is closed to the public except during June,July and
August,when it is open as'far as Dietrich camp.
Physical Setting
The physiographic provinces along the corridor are the Arctic Coastal
Plain,Arctic Foothills,Arctic Mountains,and Northern Plateaus
Provinces.The Arctic Coastal Plain is a wet tundra and mosaic of small
lakes that extends from Prudhoe Bay to a maximum altitude of 600 feet.
To the south,the Arctic Foothills consists of rolling plateaus and low
linear mountains.The central and eastern Brooks Range and the Ambler-
Chandalar ridge and lowland section comprise the Arctic Mountains
Province.The Brooks Range is a series of rugged glaciated ridges that
2605B
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rise to summits of 7,000 to 8,000 feet in altitude in the northern part
and 4,000 to 6,000 feet in the southern part.Small cirque and valley
glaciers and lakes are cOlllllon features.
The Northern Plateaus Province includes the region south of the Brooks
Range and is cha racteri zed by ever:w-topped ri dges.These mountai ns
descend to the Yukon Flats characterized by gently sloping outwash fans
and nearly flat floodplains.Continuing south,the corridor extends into
the rolling uplands of the Yukon and Tanana valleys.
Five major federal land designations are located adjacent to or near the
corridor.Immediately to the west of the corridor in the Brooks Range is
Gates of the Arctic National Park.To the east is the Arctic National
Wildlife Refuge.Further south are the Yukon Flats National Wildlife
Refuge and the Kanuti National Wildlife·Refuge.To the south of the
designated utility corridor is the White Mountains National Recreation.
Area.
The climate along the corridor can be divided into two zones.The Arctic
zone extends from the Arcti c OCean to the Brook s Range and the
Continental zone,which is the predominant zone of Alaska,covers the
area from the Brooks Range to Fairbanks.Annual precipitation ranges
from less than 5 inches in some Arctic areas to 20 inches in the Interi or.
The corridor parallels major north-south rivers including the
sagavanirktok,Atigun,Dietrich,and Koyukuk Rivers.South of the Brooks
Range,river valleys are primarily in an east~est orientation and the
corridor crosses numerous streams.
North of the Brooks Range,in the foothills and coastal plain,the
vegetation consists mainly of moist tundra composed of dwarf shrubs,
sedges,cotton grass tussocks,mosses,and lichens with some high brush
occurring in the floodplains.Alpine tundra,consisting of dwarf birch,
willow,and low heath shrubs,and barren ground are found in the Brooks
Range.Upland spruce-hardwood forest occurs south of the Brooks Range
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along riverine systems.Treeless tundra occurs above 2,000 feet.In the
Yukon and Tanana Rivers region the vegetative cover is predominantly
bottomland spruce and hardwood forests.
Social Profile
There are few signs of human inhabitance along the Prudhoe Bay-Fairbanks
corridor.The villages of Livengood and Wiseman,and a number of small
mining operations.near the Wiseman area,are located near the Haul Road.
TAPS pump stations with transient personnel are located at Pump Station
2,Slope Mountain (Pump Station 3),Galbraith Lake (Pump Station 4),
Prospect (Pump Station 5)and the Yukon River (Pump Station 6).
Department of Transportation camps are located at Slope Mountain,
Chandalar,Dietrich,Coldfoot,Prospect and seven miles north of the
Yukon River.Some of these camps have worker dependents and a school is
located at the Yukon River camp.Comercia1 service establistlnents
(i.e.,truck stops)are located at Coldfoot and the Yukon River.
C3.2.1.2 Routing Considerations
Trans-Alaskan Pipeline System Restrictions
One of the most important siting criteria for the transmission line is to
protect the integrity of the existing TAPS line and to avoid interference
with pipeline operations.However,the present stuqy assumes that no
"fata1 fl aws"to the routi ng of ei ther a transmi ssi on 1i ne (Scena ri 0 I)
or a gas pipeline (SCenario II)would be imposed by the presence of the
TAPS line.This assumption is based on the fact that a major additional
linear facility (the ANGTS line)within the Utility Corridor has been
licensed.While it is reasonable to expect that either transmission or
new pipeline facilities could be routed within the corridor,such routing
would not be done without numerous local complications imposed by
physical and environmental constraints,including.the presence of the
TAPS line.
26058
C3-13
Specific TAPS restrictions would be negotiated during the detailed siting
procedure.However,the following general critiera would be applicable:
Minimize crossing the trans-Alaskan pipeline.Each crossing of the
TAPS line poses a risk to the pipeline's integrity."Crossing of the
li ne shoul d only take place where requi red by topograpfly,
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right-of-way,or other restrictions.
Locate the transmission line at least 200 feet from the existing oil
pipeline whenever possible.This was the minimum separation agreed
upon for the ANGTS line,and it can be assumed that a similar
separation would be reqUired for the transmission line.
Locate the transmission line downslope of TAPS and the haul road when
feasible.This would prevent a~ground slumping or deposition of
eroded materials from affecting the TAPS line.
Utility Corridor Considerations
The Bureau of Land Management (BLM)has prepared land use plans for the
Utility Corridor between Sagwon Bluffs and Washington Creek.These plans
provide for a minimum of interference among alternate land uses,
preservation of the environment,and appropriate use of the natural
resources within the corridor.The land use plans contain specific
programs for intensive land uses (such as pipelines,airports,and
roads),mineral development,forest products use,rangeland,watershed
protection,wildlife protection,and recreation.Specific components of
the land use plan that relate directly to transmission line construction
are sUllllla ri zed below (BLM 1980).
Consolidate all pennanent facilities except pump and compressor
facilities at carefully selected nodes in the vicinities of Livengood
Camp,Yukon Crossing-Five Mile camp,Prospect;Coldfoot,Chandalar,
and Pump Station #3 area.
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Take appropriate action to safeguard against damages to the pipeline
and aqy new pipelines and related facilities.
Protect stream banks and lakeshores by restricting activities to
prevent loss of streamside vegetation.
Restrict development of land within the floodplains of rivers to
avoid loss of property by floodwaters.
Protect raptor habitat and critical nesti ng areas.The Endangered
Species Act mandates protection of threatened and endangered wildlife
species.'Protection of crucial raptor habitats preserves the
integrity of raptor populations and maintains predator-prey
re 1ati onshi ps.
Protect fish overwintering habitat.The critical overwintering areas
have been mapped by BUM.Sufficient water levels should be
maintained to meet the needs of overwintering fish.Conditions va~
at each site,so stipulations should vary at each site to mitigate or
prevent adverse alterations in fish habitat.
The land use plan has identified several areas as containing critical
wildlife habitat.Specific management restrictions have not as yet been
fonnulated;however,measures may be required for the following areas at
the time of transmission-line construction:
A.The Galbraith Lake-Toolik Lake-Atigun Caqyon area.
B.The Sukakpak-Wiehl Mountain area.
Because of critical wildlife habitat,rare plants,
historical,and archaeological sites and scenic values
within the Corridor,all of vital national interest,
special management is needed to focus properly on these two
areas.
C.The Joe Creek-Chandalar Shelf area.
This area has a concentration of mineral licks,nesting
raptor sites,and a Dall sheep lambing area.
2605B
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D.The bluffs along the Yukon River.
E.sagwon Bluffs.
These ·areas have been identified as peregrine falcon
habitat.
F.The Jim River and Prospect Creek areas.
Thi s has the highest qual ity year-long habitat for salmon
in the Corridor.Proposed development and mining endanger
this habitat.Also,these areas have high archaeological
val ues.
G.The Bonanza Creek area.
Just below Bonanza Creek is an important salmon f~
overwintering area.Spri ngs originati ng here are the mai n
source of wintertime water flow.
H.The Ivishak River,Lupine River,Accomplishment Creek,Ribdon
•River area.
These are important char overwi nteri ng areas.
I.The Kanuti and sagavanirktok River areas.
J.The Wickersham Dome Area.
These areas have been identified as caribou winter range.
In addition to the BLM land use plans,general land use criteria include:
o Maximize use of existing facilities such as work pads,highw~,
access roads,airports,material sites,and communications.
o Minimize crossing roads and highways.
o Avoid areas of existing or planned mineral development.
Engineering Considerations
The design of the transmission line from Prudhoe Bay to Fairbanks faces
special challenges.This line must be able to serve the Rai1belt with a
substantial amount of power by the year 2010 and will provide for greater
than 50 percent of the state's total available capacity at that time.A
sudden loss of more than half,or almost three quarters of the power at
the low or the medium load forecast,respectively,would cause serious
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interruptions in the Railbelt's electricity supply.In order to prevent
this from happening,the line must be designed such that potential
outages will be kept to a minimum,and that the loss of a single line
segment will not jeopardize system operation even during peak loading.
The minimum condition to achieve this objective is to build two
transmission lines (i.e.,to have two circuits on separate towers):This
is obviously a major cost consideration,and will be treated in detail in
the subsequent Feasibility Assessment Report.The width of the
right-of~ay (ROW)of these 500 kV circuits is assumed to be 300 feet
each or 600 feet total if they run side by side.This is somewhat more
than the ROW used in the lower 48 (220 and 440 feet)but the rugged
conditions require heavier structures and therefore wider ROWs.In
general,two circuits would be routed side by side over the entire length
with local exceptions.In the Atigun Pass area,for example,separate
route alignments wou.l.d be necessary.
The alternating current transmission line with its two circuits would be
sectionalized by installing two switcqyards at about 1/3 and 2/3 of the
way along the line,or approximately 150 miles apart.With the
substations at the two ends of the line,switching can be accomplished at
four locations:Prudhoe Bay,Galbraith Lake (Pump Station 4),Prospect
Camp (Pump Station 5)and Fairbanks.Should a failure occur at any of
the line sections,a 150 mile stretch of one circuit has to be
disconnected.During such a time period,'one of the circuits would carry
the power over the 150 mile long section,While for the rest of the line,
both circuits would carry power.The circuits would be designed to carry
the full load without any damage.
As transmission line grounding poses severe problems in many areas,
including Prudhoe Bay,a continuous conductor wire,called contrepoise,
would be carried along the entire length of each circuit,buried
underground.This will assure proper behavior of the line during
switching operations.
2605B
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Access from the Haul Road to the transmission line right-of-way would be
provided at suitable locations along the entire route.Construction
personnel would utilize the existing camp facilities developed for TAPS.
Geotechnical Considerations
Geotechnical criteria consist of avoiding steep slopes,unstable soils,
bedrock slide areas,and active fault zones.In some segments of the
corridor,however,adverse geotechnical conditions cannot be avoided.In
these cases,tower foundations would be designed to accommodate
unfavorable subsurface conditions.Soil types within the corridor
consist of marine sediments,floodplain gravels,alluvial fan and
slopewash deposits,residual soil over bedrock and aeolian deposits.
Continuous and discontinuous penmafrost is also present.
Environmental Considerations .
There are numerous environmental considerations that must be taken into
account during detailed siting efforts and design engineering for a
Prudhoe Bay to Fairbanks transmission line.These considerations have..
been derived from numerous environmental studies perfonmed in conjunction
with the evaluation of the TAPS line and in support of the ANGTS
project.Some of the major considerations are discussed below.
Facilities and long tenm habitat alterations are prohibited within one
mile of peregrine falcon nest sites unless specifically authorized by the
U.S.Fish and Wildlife Service,because of the endangered species status
of the peregrine falcon.Along the utility corridor six nests are
loCated along Franklin Bluffs,and Sagwon Bluffs,and one nest on Slope
Mountain.As a transmission line or gasline alignment along or west of
the Dalton Highway would avoid the Franklin Bluffs and Sagwon Bluffs
locations,the restriction may apply primarily to material sites.
Other rap tors which may influence routing and siting include golden
eagles (at least 42 nests between the Yukon River and Slope Mountain),
26058
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rough legged hawk (24 nest locations between Slope Mountain and Prudhoe
Bay),and gyrfalcons (5 nest locations between the Yukon River and Atigun
Pass,11 nest locations from Atigun Pass to the end of Sagwon Bluffs).
Siting restrictions for these rap tors which were applicable to ANGTS are
presented in Table C3-l.
It is unlikely that the transmission line would be sited in or near
important Dall sheep habitat.A primary concern is aircraft traffic over
critical wintering,lambing,and movement areas.Moose winter browse
habitat in the Atigun and sag River valleys is limited to areas of tall
riparian willow.Habitat has already been eliminated by the construction
of TAPS and further destruction of this habitat should be avoided or
minimized.The willow stand along Oksrukuyik Creek,in particular,
should not be disturbed.
System design must allow tree passage for caribou,but these animals
should not be a major consideration in.siting.carnivore/human
interaction is a major concern in facilities design and in construction
and operations methods,but not in siting considerations.
Major impacts to fish would be from contrepoise construction.Between
Fairbanks and Prudhoe Bay,the transmission line may cross as many as 150
waterbodies which are utilized by fish for migration,rearing,spawning,
and/or wintering.Sit~ng should avoid or mini~ize impact to spawning
areas in approximately 35 waterbodies and to wintering areas in
approximately 15 waterbodies.Important spawning waterbodies include
large to middle sized rivers and streams such as the Chatanika River;
Kanuti River,Fish Creek,Bonanza Creek,Prospect Creek,Jim River,and
Koyukuk River and adjacent sloughs,Dietrich River and associated side
channels and sloughs and the Kuparuk River,and also such small streams
as Mar,y Angel Creek.Waterbodies that include important fish
overwintering areas include Fish Creek,Bonanza Creek,the Jim River,the
Koyukuk River,and the Dietrich River and associated springs and sloughs.
2605B
C3-19
TABLE C3-1
STATE OF ALASKA TEMPORAL AND SPATIAL PROTECTION CRITERIA FOR NESTING RAPTORS!I
Protection Criteria
Minor Major
Sensitive Aerial Ground Ground Facility Habftat
Species Time Period Activity 21 Acti vi ty Activity Siting Disturbance
Peregrine 15 April -1 mf h 1 mi 2 mf 2 mi 2 mi
falcon 31 August or 1500 ft v
Gyrfalcon 15 February-1/4 mi h 1/4 mi 1/4 mf 1/2 mi
15 A~gust or 1000 ft v
Golden eagle 15 Aprl1-1/2 mi h 1/4 mf 1/2 mi 1/2 mf
31 August or 1000 ft v
Rough-legged 15 Aprll-1/4 mi h 1/4 mi 1/4 mf 1/2 mi
hawk 31 August or 1000 ft v
Bald eagle 15 March.Y-1/4 mi h 1/8 mi 1/4 mi 1/2 mi 1/8 mi
15 August or 1000 ft v
Osprey 15 March-1/4 mi h 1/8 mi 1/4 mi 1/2 mi 1/8 mi
15 August or 1000 ft v
11 Extracted from l5ensitive wildlife areas of the Northwest Alaskan gas pipeline corridor l ,
C.E.Behlke,State Pipeline Coordinator,letter to E.A:Kuhn,NWA,15 July 1980 and
presented in Roseneau et·al •.1981..
2/h :=horizontal;v =vertical.
~I 1 March for areas between mileposts 472 and 573 (Tanana River from near North Pole to
near Gerstle River)..
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Identified overwi nteri ng areas such as SChroeder's Spring on the Dietri ch
River should be avoided altogether.Another ve~important area to be
avoided is the wetland between Pump Station 4 and the Dalton Highway.and
important rearing areas for fish in the Atigun Valley.
Line routing and tower siting should avoid or minimize disturbance of the
treeline white spruce stand at the head of the Dietrich Valley.which has
been nominated for Ecology Reserve status.
Transmission line construction may cause increased erosion rates in
disturbed areas.This impact can be minimized by routing the line so that
existing access roads can be used as much as possible.In addition.steep
slopes and highly erodible soils should be avoided wherever possible.
Water quality impacts.primarily increased suspended solids
concentrations.are closely related to'erosion effects~In addition to
the soil erosion considerations discussed above.the line should be routed
so that a buffer strip of vegetation can be maintained between the
disturbed areas and all water bodies.
C3.2.1.3 Generic Route Description
Because the topography and climateva~dramatically ~etween Prudhoe Bay
and Anchorage.the transmission line route has been divided into seven
segments,as shown in Figure C3-1.Within each segment,the engineering
design of the transmission line and tower foundations would be generally
uniform.A brief summa~description of each segment is given below,with
emphasis given to topographic and climatic factors that affect
transmission line costs.
Segment 1 -Arctic Coastal Plain (Prudhoe Bay to Pump Station 2)
The first segme~t encompasses the route from the Prudhoe Bay oil fields ta
Pump Station 2 of the pipeline.It is a 60 mile long segment.consisting
of fl at tundra wfth numerous 1akes and ponds.The soi 1 is mal nly coarse
26058
C3-2l
alluvium and is u~derlain with continuous penmafrost.Near the coast,
arctic sand,picked up by moist,salty winds would contaminate the
insulators in the late summer and/or early fal.l;this requires annual
washing of the insulators.
The temperatures in this segment range from -60 to 86°F,.with an average
annual snowfall of 35 inches.Wind speeds can be up to 100 miles per
hour.Ice thickness on transmission lines can reach 1.5 inches radially.
segment 2 -Northern Brooks Range (Pump Station 2 to Galbraith Lake)
The second segment is approximately 95 miles long and gently rises from
500 feet above sea level to 3000 feet.No serious contamination problems
are anticipated here because of the distance from the Beaufort sea and
because dust is generated only on the roads.The soil is alluvial
deposits,floodplain gravel and slopewash deposits;it is in the zone of"
discontinuous pennafrost.One of two intennediate switching stations
would be located at the end of this segment,at Galbraith Lake,.The area
is in the vicinity of Pump Station 4 and is easily accessible by road or
ai r all year round.
Temperatures range from -60°to 90°F,and winds reach 100 miles per hour.
Snowfall averages 63 inches annually,with a maximum of approximately 48
inches on the ground at any time."Maximum ice loading on the proposed
line would be 1.5 inches radial thickness.
Segment 3 -Atigun Pass (Galbraith Lake to Nutirwik Creek)
The Atigun Pass segment of the line is only 30 miles long.For most of
this length the road and the TAPS pipeline would be between the two,
circuits.Should any ROW be reserved for future pipelines or other
structures,this should be specified in advance in order to avoid future
conflicts.For about a 5-mile stretch at the pass itself at 3,000 feet
above sea level,the circuits would be routed on the mountainsides.
SUitably designed transmission towers can be erected on the slopes of
2605B
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Atigun Pass.Far more difficult terrains have been successfully crossed
with electric transmission lines elsewhere in the United States and
abroad.Avalanches,however,are a major consideration.Another
potential problem is that the contrepoises cannot be lowered into the rock
soil,in which case two alternatives are available.The contrepoises can
be either continued on the top of the towers as ground (aerial,s~)wires
or they can be routed a few hundred feet away from the circuits close to
the road and pipeline with tie connections to as many towers as possible.
The temperatures in this area range from -60°to 90°F.Average annual
snowfall is approximately 63 inches,with roughly 48 inches maximum snow
depth on the ground.Ice loading can reach 1.5 radial inches,and dust
contamination would occur from the haul road.Wind speeds reach 120 miles
per hour.
Segment 4 -Southern Brooks Range (tlItirwik Creek to Jim River)
From Atigun Pass to the Jim River the line would gradually descend from
3000 feet to 1000 feet in elevation.In this 90~il~section,extensive
geotechnical surveying is necessa~to identify a route Which provides
suitable soil for transmission tower footings.Being south of the
Continental Divide and having only the road as a dust source,no serious
contamination problems are expected in this segment.
Temperatures range from _75°to 90°F,with approximately 150 inches of
snowfall per year.Maximum snow depth is about 110 inches.Wind speeds
reach 90 mph.
Segment 5 -Caribou Mountain (Jim River to Yukon River)
The fifth segment runs between the Jim and Yukon Rivers and is 75 miles
long.It is charactertzed by rolling hills and some flat terrain with an
average elevation of approximately 1000 feet".Construction and operation
of the line would be less demanding here than many of the other segments.
The Prospect Camp/Airport area (about 25 miles south of the Jim River)is
2605B
C3-23
a good location for one of the fntenmediate switching stations.This site
is next to Pump Station 5 and a DOT camp and therefore,has year-round
access.
Temperatures range from -80 to 95°F,with 100 inches annual snowfall and
75 inches maximum snow depth.Wind speeds reach 80 mph.Dust
contamination occurs from the road.
Segment 6 -Yukon River Crossing
The Yukon River crossing was identified as a separate segment,because of
the dissimilar engineering problems it involves.The line would cross the
river west (downstream)of the highway bridge.The bridge is
approximately 2100 feet long and carries the TAPS line on its upriver
side.The span of the line,located several hundred feet downriver of the
bridge,is estimated to be approximately 2500 feet long.The span would
originate on the flat area on the north (right)bank of the river.It
would tenminate on top of a hill on the left bank,at some 300 feet in
elevation above the river.The hill provides the necessa~height
required for such a long span and eliminates the use of unusually large,
hea~,expensive and unsightly transmission towers.With a 100 foot tower
on the North Bank and a less than 200 ft tower on the South bank,on the
top of the hill,the profile of the conductors would be almost exactly a
half catena~curve,with the lowest point at the north end.The line
therefore,would not create an obstruction to river traffic.
Temperatures range from -80 to 95°F.Average annual snowfall is 66 inches
wi th a max imum snow depth of 50 inches.Wi nd speeds reach 70 mph.
Segment 7 -livengood (Yukon River to Fairbanks Area)
The last segment of the transmission line runs to.the Fairbanks area,the
site of the final substation.The line would be routed among rolling
hills.For approximately one mile the grade is in excess of 30 percent,
the steepest grade along the entire route.The soil is residual soil over
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bedrock with aeolian and silt deposits down-slope.The soil of the
smaller valleys consists of ice-rich silts to·a depth of over 100 feet.
and the larger streams have unfrozen floodplain gravels and sand.
Temperatures range from -70 to 98°F.with an .average annual snowfall of 66
inches and maximum snow depth of about 50 inches~Wind speeds reach 70
mph.Dust or other contamination problems can be serious near
c~nstruction sites or other disturbed areas.
C3.2.2 Fairbanks-Anchorage
C3.2.2.1 Description of the Region
The Anchorage-Fairbanks corridor encompasses these two economic centers
and the major portion of the State's population.The transmission
intertie would parallel the Alaska RailrQad as well as the Parks Highw~.
Which is the major transportation link between the two major cities.The
area falls within three jurisdictions.the Anchorage Area Borough.the
Fairbanks North Star Borough.and Matanuska-Susitna Borough.The Denali
National Park.adjacent to and west of the Parks Highw~.has national as
well as international importance and attracts thousands of visitors each
sUlJll1er.
Physical Setting
The topography of the area is dominated by the north to south river
valleys of the Susitna.Talkeetna.Chulitna.and Nenana Rivers.and the
Alaska Range to the west and north.The transmission line corridor falls
wi thi n the vall ey floor of these ri verso The hi ghestpoi nt along the
corridor is 2.300 feet at Broad Pass.which marks a watershed divide.The
p~siographY of the region is widely varied.The corridor crosses four
physiographic subdivisions that belong to the Pacific Mountain System
division.The Cook Inlet-Susitna Lowland.a glaciated lowland less than
500 feet above sea level.covers the area from Anchorage to Talkeetna.
This subdivision 'contains most of Alaska's developed agricultural land and
2605B
C3-25
is almost ice-free except for sporadic pennafrost present in the northern
part.The Broad Pass Depression is 1.000 to 2,500 feet in altitUde,a
trough having a glaciated floor that covers the area between Talkeetna and
Healy.To the north.the central and eastern Alaska Range consists of
rugged glaciated ridges broken at intervals by cross-drainages or low
passes.The Northern Al~~·ka Range Foothills includes the area between
Healy and Fairbanks and is characterized by flat-topped east-trending
t>ri dges sepa rated by roll i ng 1owl ands.The transmi ssi on corri dor is.~
situated in the glaciated valleys of this subdivision.
The region falls within the northern extension of the North American
boreal forest which is characterized by interior forests of willow,
spruce,and alder in the southern two-thirds and open woodland,shrubs,
and tundra in the northern one-third.The vegetation cover supports big
game species of moose,'caribou,brown and black bear,small game,
migrator,y game birds,furbearer,raptors,and other nongame mammals and
birds.The Susitna River Basin and portions of the Nenana River Basin are
important spawning grounds for anadromous salmon and common river species.
Social Profile•
The region is dominated by two population centers,Anchorage to the south
and Fairbanks to the north.small population centers are located in
Wasilla,Palmer,Houston,Talkeetna,Willow,Cantwell,and Healy with the
remaining population scattered along the Parks Highway and the Alaska
Railroad.Cantwell.Montana Creek,and Caswell are native villages within
the corridor•.The 1980 estimated population for the region was
approximately 247,000 with over 70 percent of that population based in
Ancjlorage.
Although Anchorage and Fairbanks are major centers with diversified
economic bases,the economy of the region between the two cities is
largely undeveloped.No significant additions to the project area's
economic base has occurred during the past decade except for the expansion
of commercial activity along the Parks Highway and the expansi'on of coal
2605B
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mining activities in Healy.Some major development projects proposed for
the region could dramatically impact the demographic and employment
outlook.
Outside of the Anchorage and Fairbanks labor markets,job opportunities
are limited mostly to construction labor and tourist and recreation-
oriented services.As a result,the labor force along the corridor is
highly mobile in search of work and the unemploYment rates are chronically
high with wide seasonal swings.
C3.2.2.2Routing Considerations
Route Descriptions
An existing transmission line corridor connects Fairbanks to Anchorage and
is essentially divided into three segments.From Fairbanks to Healy,a
138 kV transmission line is operated by Golden Valley Electric
Association.This 110-mile segment parallels the Fairbanks-Anchorage
Highway for its entire 1ength.
From Healy to Willow,the Intertie now under construction will consist of
a 345 kV line that will be initially operated at 138 kV.This line will
extend for 179 miles with a right-of-way width of 400 feet (Commonwealth
Associates 1982).
The Intertie corridor passes through the Montana and Mooqy Creek drainages
between Healy and Windy Pass,and is routed along the eastern portion of
Broad Pass.The route then passes east of Chulitna Butte and crosses the
Susitna River near Indian River,paralleling the Alaska Railroad until
just north of Deadhorse Creek.The route crosses the Talkeetna River near
Bartlett Hills,five miles east of Talkeetna,and proceeds south and west
to near the village of Montana.The route parallels the Matanuska
Electric Association right-of-way for the last 19 trlileS into the Willow
Substati on.
2605B
C3-27
Between Willow and Anchorage,an eXisting 115 kV line passes along the
eastern side of Knik Arm.In addition,a 138 kV line extends from
Tee1and,seven miles south of Wasilla,to Anchorage,along the western
side of Knik Arm.As part of the Intertie construction,the Teeland
substation will be connected to the Willow-Anchorage line with a 5.5 mile
new 138 kV segment.The re~ainder of the 30~ile line from Teeland ~o
Willow will then be converted to 138 kV.
Applicability of the Intertie Route
The transmission corridor selected for the Intertie balances concerns for
environmental resources,public interests,economics and reliability.
During route selection,substantial input was incorporated from both the
public and private sector,inclUding the Rai1be1t communities through the
Public Participation Program,the resource management agencies through
infonma1 meetings and fonmal presentations and the part'icipating Alaskan
Utilities through the Technical Review Committee (Commonwealth Associates
1982).Based on this methodical siting process,the designated Intertie
route 'was assumed to be the most appropriate for the.present study's
purposes.
The Intertie route was chosen specifically to minimize engineering and
geotechnical complications,land use interferences and environmental.,... ...
consequences.The route avoids most.of the local communities along the
Parks Highway and Alaska Railroad.The route includes no crossing of the
Denali National Park and Preserve,one crossing of the Denali State Park,
no crossings of the Parks Highway,and only two crossings of the Alaska
Railroad.
In addition to siting considerations,special measures are being
implemented during the construction phase to further minimize
environmental consequences.Several of these mitigating measures,as
presented in the Environmental Assessment of the Intertie (Common~ea1th
Associates 1982),are summarized below.
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In the ver,y steep areas,soils will likely be cleared by hand to avoid
excessive soil erosion.Soils susceptible to severe erosion or creep will
be avoided.
The transmission line will unavoidably cross several large rivers and
numerous creeks.However,all towers will be set back from water bodies
at least.200 feet where possible.A buffer strip will be established
along major watercourses to minimize siltation of streams.Equipment
crossings of streams will take place when the stream is frozen,whenever
possible.
Because trumpeter swans are ver,y susceptible to human disturbance,
construction activit~will be restricted from May through August in areas
with active trumpeter swan nesting territories.
The route avoids all known ba1 d and golden eagle nests.Peregrine falcons
are not known to utilize the project area except as migrants.
Because even a single equipment pass c~n cause serious penmafrost
degradation (Brown 1976),construction in penmafrost areas will be
completed when the ground is frozen.Construction in muskeg-bog soils
will also be completed when the ground is frozen.
Fisheries resources will be protected by mfnimizing erosion and the'
SUbsequent s iltati on of water bodi es.At stream crossi ngs where equi pment
will move directly through the water,the crossings will be made during
periods when there are no eggs or fry in the gravel.Generally,this will
be a period in June and July after the rainbow trout and Dolly Varden fry
have developed through swim-up and before the Pacific salmon start to
spawn.Activities will be closely coordinated with the Alaska Department
of Fish and Game.Construction activity will avoid small lakes and beaver
ponds that are important nurser,y habitat for local and anadromous fish
cOlllTluni ties.
2605B
C3-29
The Moody Creek-Montana Creek portion of the line will be constructed by
helicopter.In other areas,existing roads and trails will be used as
much as possible.
Upgrade Considerations
satisfying the forecasted electrical energy demands within the Railbelt
will require upgrading of each transmission line segment between Fairbanks
and Anchorage including the Intertie.For all development scenarios
evaluated in this study the existing 138 kY lines connecting Healy to
Fairbanks and Willow to Anchorage will have to be upgraded to 345 kY
essentially through line replacement.The Intertie would then be operated
at 345 kY.One or two additional 345 kY lines are also required,
extending the entire length of the corridor.In addition,various other
electrical equipment changes inclUding a switching station m~be
required,depending upon the developed scenario.Each aspect of the
required upgrade is presently under stuQy and will be specified in the
Feasibility Assessment Report.It is realized that incremental
environmental impacts will accrue due to line upgrading activities and
these will also be discussed in the Feasibility Report.Because
transmission line upgrading will utilize existing corridors,engineering
and/or environmental considerations which could significantly affect
system design or preclUde d~ve10pment are not envisioned at the present
time.It should be noted that substantial upgrading of the
Anchorage-Fairbanks Intertie,on the order of that described above,will
be requi red for any major energy development al ternati ve to serve
increased Rai1be1t power demands.
2605B
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C4.1 GENERATING FACILITY SITE EVALUATIONS
C4.0 SCENARIO II -FAIRBANKS POWER GENERATION
An overall description of the Fairbanks region,followed by power plant
siting criteria,a discussion of candidate siting areas,and the generic
site description is provided in this section.
The Fairbanks scenario (Figure C4-1)consists of a small diameter gas
pipeline from Prudhoe Bay to Fairbanks,a gas distribution system within
Fairbanks,an electrical generating facility in the Fairbanks vicinity,
and transmission of 80 percent of the energy produced to Anchorage.Each
of these components is discussed below.
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C4.1.1 Description of the Region
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Fairbanks is the regional conmercial center of interior Alaska.The
communities surrounding Fairbanks (e.g.,Fox,North Pole)are located to
the north,west,and southeast along the major transportation corridors.
Fairbanks and these neighboring communities comprise the Fairbanks North
Star Borough.
P~sical Setting
Fairbanks is located in a broad floodplain near the confluence of the
Chena and Tanana Rivers.Two vegetation types are located in the region.
The lowland spruce-hardwood forest is an interior forest of evergreen and
deciduous trees dominated by black spruce which sometimes occurs in pure
stands.The bottomland spruce-poplar forest,located adjacent to the
Tanana River,is a tall,relatively dense,interior forest primarily of
white spruce.The vegetation cover supports big game species of black and
grizzly.bear,moose,small game,migratory game birds,furbearers,
raptors,and other nongame mammals and birds.The Tanana River is an
important spawning ground for anadromous salmon,arctic grayling,and
whitefish.
26058
C4-1
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POWER PLANT SITING AREA
TRANSMISSION LINE
CORRIDOR
NATURAL GAS PIPf.LINE
;:ORRIDOR
FIGURE C 4-1
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SCENARIO II
FAIRBANKS POWER GENERATION
EBASCO SERVICES INCORPORATED
NORTH SLOPE GAS FEASIBILITY STUDY
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In the winter,stagnant conditions occur often,with ver,y light winds and
a strong temperature inversion in the v~rtical direction.These
conditions bring about persistent air stagnation with ice fog and high
levels of carbon monoxide.Ice fog,fonned through the concentration of
pollutants from automobiles,power plants,and domestic heating,settles
in the bowl-like depression in Fairbanks during these stagnant
conditions.Annual temperatures are extreme and range from a mean
minimum of -24°F in Januar,y to a mean maximum of 75°F in July.Extremes
can range from -60°F to over 90°F.The annual average precipitation in
Fairbanks is 11 inches,which includes roughly 70 inches of snow.
Soc ia1 Profil e
The 1980 population for the Fairbanks North Star Borough was
approximately 54,000.Data on non-agricultural wage and salar,y
employment indicates that in the Fairbanks area government is the largest
economic sector followed by trade and transportation,communications,and
utilities.Tourism is a major factor in the trade sector and this
activity has grown in the last few years.Since 1979,the average annual
unemployment rate has exceeded 10 percent (Alaska Department of Labor
1981)•
C4.1.2 Siting Considerations
.Siting a generating facility in the Fairbanks area is more complex than
on the North Slope,because of the diversity in topograpny and population
patterns.Preliminar,y siting efforts have concentrated on areas of
industrial development with space for expansion that are already served
by utility facilities and have adequate transportation access.
C4.1.2.1 Land Status and Use Considerations
Land use criteria for power plant siting in.the Fairbanks area are:
2605B
C4-3
1)Compatibility with existing land uses.The Fairbanks area is
bordered on the east and south by large milita~reservations.
It is assumed that siting a power plant on these reservations
would be precluded.While there are industrial areas within the
city's immediate vicinity,sufficient space does not appear to
.be available for major new electrical generating facilities.
Power plant siting on the outskirts of Fairbanks must take into
account compatibil ity with specific land ownership and uses,
such as new residential developments,the University of Alaska
campus,and the Fairbanks Airport and its zone of influence.
Preferably,the site would be located within or adjacent to an
existing industrialized area,isolated from residential and
commercial population centers.Ideally,the potential
generating facil ity site will be zoned for i.ndustri al
development.
2)Adequate existing transportation system.Because the generating
facility will involve a large number of construction and
operating personnel,the surrounding road network will
experience a significant increase in use.The development of
new roads or highways to provide site development access to as
yet undeveloped portions of the Fairbanks area is assumed to be
undesirable,both from a cost standpoint and because new
transportation facilities should be part of a comprehensive,
rather than project-specific,pl anni ng process.Therefore it is
assumed that the plant site must be located within a reasonably
short distance of existing major roads or highways.
3)Compatibility with adjacent utility corridors.The location of
the gas pipeline and electrical transmission lines to and from
the plant must not interfere with existing utility corridors.
However,it would be advantageous to locate new generating
facilities to optimize the use of existing pipeline and
transmission line rights-of-way,and to minimize,to the extent
possible,the acquisition of new rights-of-way.
2605B
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These land status and land use considerations suggest that the vicinity
of North Pole,east of Fairbanks along the Alaska Highway,should be
examined in more detail.candidate siting areas are disCussed in Section
C4.1.3.
C4.1.2.2 Geotechnical Considerations
In selecting the location of the power generating facility,the major
geotechnical criteria are:
1)Foundation soils with good bearing capacity and limited
settlement potential.
2)Suitable site drainage.
3)Primarily non-frost susceptible foundation materials.
4)Foundation soils generally free of penmafrost or penmafrost with
low ice content.
These criteria are conmon to any industrial facility.In addition,given
the imposed loads,the criteria allow the foundation design to consist of
a concrete mat on a grade,with or without an engineered gravel pad.
C4.1.2:3 Engineering Considerations
In general,the power plant should be sited in relatively flat terrain,
to minimize the amount of required grading and excavation.It will also
minimize the potential for adverse environmental impacts due to erosion
and transport of suspended solids to nearby waterw~s.The plant should
also be sited above the 100-year floodplain of any major surface water
resource in the area to avoid flooding.
An area's seismic activity can also be an important site differentiating
factor,with preference given to those sites located in regions of low
26058
C4-5
activity.In the Fairbanks area,however,all potential site locations
fall within regions of high seismic activity (Zone 3).While this will
not preclude development nor differentiate between the sites,it will
increase construction costs as more material will be re~uired to insure
plant foundation stability.The location and extent of all faults within
the general Fairbanks area should be studied during the actual site
selection process,as the plant should not be sited in close proximity to
faul t 1i nes.
Siting a power plant in close proximity to existing roads,railroads,and
transmission lines minimizes the cost associated with these required
connection links.Exhting electrical power will be necessary during the
initial construction phase.Railroads will be used to transport large
equipment as close to the site as possible,and trucks for the remaining
distance.The site must have acces~to approximately 200 gpm of fresh
water.'Thi s assumes that water injection for nitrogen oxides control
will not be required,in order to avoid severe ice fogging.
C4.l.2.4 Environmental Considerations
Air Qual ity
Meteorological conditions in Fairbanks playa very important role in
detenmining the ambient air quality levels in the area.Analyses of the
Fairbanks urban "heat island ll have shown that winds are generally light
in the winter and that wind directions change dramatically in the
vertical direction during the wintertime.During the winter months,the
air near the ground is relatively cold,compared to the air aloft.This
reduces mixing of the ~ir in the vertical direction,and when combined
with relatively light winds,often leads to periods of air stagnation.
In large part due to the winter stagnation conditions,the Fairbanks area
1S currently designated as a non-attainment area for carbon monoxide .
(CO).Emissions of CO are largely due to automobiles.The State
Department of Environmental Conservation and the Fairbanks North Star
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the ambient CO mainly through the use of vehicle emission or traffic
control techniques.In addition,relatively high levels of nitrogen
oxides have recently been monitored in the Fairbanks area.Only an
annual average nitrogen dioxide standard exists,but the short term
measurements of nitrogen oxides are as high.as in major urban areas such
as los Angeles.
The installation and permitting of a major fuel-burning facility,such as
a power plant,will require a careful analysis of the impact of its
emissions on ambient air quality.The operators of such a facility must
demonstrate that they will reduce,or offset,impacts of the power plant
by reducing emission levels of CO at other sources.
The protection of air quality in Fairbanks and its associated regulatory
framework will 'pose a significant concern for the siting of a major power
plant.However,these concerns will not preclude the development of at
least some form of a natural gas fired power plant.Emissions of CO from
this fuel source are relatively low,and any displacement of the burning
of other fuels,such as coal or oil,will likely lead to improved air
quality.This arises from the clean-burning nature of natural gas and
from the fact that emissions from a major facility will be injected
higher in the ~tmosphere (due to plume.buoyancy)than the displaced
emissions.During the very stagnant conditons in midwinter,the plume
from a power plant will likely remain well aloft with little mixing to
the surface l~ers.The complex urban heat island and associated wind
pattern will require a great deal of in-depth modeling and analysis to
determine air quality impacts in terms that will withstand regulatory
scrutiny.
A large combustion turbine power plant must meet the existing New Source
Perfonmance Standards and Best Available Control Technology.The
nitrogen oxides limits will be the'most constraining atmospheric
pollutant.The operation of the power plant will also consume a portion
of the allowable deterioration in air quality for nitrogen oxides.While
2605B
C4-7
it is possible that the power plant could be sited near Fairbanks,its
installation would constrain other development efforts which also might
consume a portion of the air quality increment.
The Fairbanks area is also subjected to extended periods of wintertime
~ice fog,and the Alaska Department of Environmental Conservatio~will
require the impact of any water vapor plumes to be carefully assessed.A
combustion turbine power plant which uses water or steam injection
techniques would have an adverse impact on the ice fog and icing
deposition nearby.The nature,magnitude,and duration of plumes must be
studied as well as the potential for beneficial impacts due to reduced
combustion at other sources within the area.The combustion turbine
facility would have to use water or steam injection techniques to meet
the standards of Best Available Control Technology.The requirements for
water injection will·be waived if and when it is determined that the
subsequent formation of ice fog will cause a traffic hazard (40 CFR
60.332)•
Other Environmental Considerations
If more detailed siting analyses were to be conducted for Scenario II,
the land use and air quality concerns previously discussed would provide
the only signiJic~n~screening criteria to discriminate among alternative
areas.At a more 1oc·al ized scale,there coul d be significant ecological
or cultural resources affected,but judicious siting and project planning
could avoid or mitigate such impacts.In this scenaricr,air quality and
land use concerns will override other envirorvnental concerns because the
si~ing effort would focus on previously disturbed areas or areas of low
biological significance.
C4.1.3 candidate Siting Areas
Three general areas in the Fairbanks vicinity have been identified by
local GVEA and Fairbanks Municipal Utility personnel as possible
locations for an electrical generating facility:1)near the Chena Power
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Plant in Fairbanks;2)in the North Pole area approximately 14 miles
southeast of Fairbanks •.and 3)in the Fox area.approximately 9 miles
north of Fairbanks.In addition.there may be additional potential
'generating facility sites in the Fairbanks region that have not yet been
identified.Each of the identified areas is described below in order to
provide a frame of reference for the subsequent description of the
generic site.
C4.l.3.l Chena Power Plant Area
The Chena power plant is located in downtown Fairbanks.The plant is
located on floodplain gravel.adjacent to the ChenaRiver.The area is
nearly fully developed;expansion of the plant would be restricted by
lack of available space.
C4.1.3.2 Nort'h Pole Power Plant Area
North Pole.Alaska is located 14 miles southeast of Fairbanks.on the
Richardson Highway.near the Tanana River.The town of North Pole has a
population of 470.although 6.000 people live in the municipal area.
Golden Valley Electrical Association (GVEA)operates a 130 MW power plant
outside of North Pole.Sufficient space exists for expansion of the
plant.The topograp~in this area is generally flat.with little forest
vegetation and sparse ground cover.
C4.1.3.3Fox Area
The town of Fox is located approximately nine miles north of Fairbanks.
The area consists of extensive dredge tailings remaining from past gold
mining operations in the Goldstream Creek Valley.The valley floor is
generally flat.and is about 300 feet higher in elevation than Fairbanks.
/
26058
C4-9
C4.1.4.Generic Site Description
C4.1.4.1 Location and Access
The generating site is assumed to be located within several miles of
Fairbanks,along a major transportation route.The area is served by
eXisting electrical transmission lines,so that electricity will be
availab1 e duri ng the construction phase.A rail road spur extends to
within several miles of the site;transportation of equipment over the
remaining distance will be handled by truck.The small diameter pipeline
route from Washington Creek (the southern end of the Utility Corridor
from Prudhoe Bay)is over relatively gentle terrain and does not cross
any major population centers,rivers,or other constraining features.
C4.1.4.2 Size and Surface Characteristics
The power plant site is approximately 65 acres in size.Because no
construction camp will be used at the Fairbanks site,no additional
acreage will be needed during the construction phase.
The terrain in the vicinity of the site is flat to gently rolling.Very
little vegetation is present because much of the area is already
disturbed by existing .or previous development.
C4.1.4.3 Water Source
The water supply for plant operations will be provided by wells,and
treated to bring the quality up to the necessary standards.The water
table in the area is within 20 feet of the surface.
C4.1.4.4 Soils and Foundations
The generic site soils can be described as river floodplain sands and
gravels with low ground ice content overlaid by approximately 5 feet of
silt with low to moderate ice content.The site is free of permafrost.
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concrete mat overlying a 5-foot thick gravel pad.The overburden silts
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will be excavated and spoiled.
C4.2 GAS PIPELINE ROUTING EVALUATIONS
A major component of the Fairbanks scenario is the construction of a
small diameter gas pipeline from Prudhoe Bay to Fairbanks.The pipeline
would have a 22-inch outside diameter with a maximum operating pressure
of 1260 psig.The pipeline would have ten compressor stations for the
medium load forecast,and three for the low load forecast.The pipeline
would be buried for its entire length,and would have an operating
temperature between 0 and 32°F.At the Yukon River the existing aerial
crossing would be used.The pipeline would be routed within the Utility
Corridor described in Section C3.2.1.1.
C4.2.l Routing Considerations
C4.2.1.1 Trans-Alaskan Pipeline System and Utility Corridor Restrictions
Development restrictions imposed by TAPS and the Bureau of Land
Management regarding transmission line construction from the North Slope
to Fairbanks,discussed in Section C3.2.1.2,would also be applicable to
the construction of the gas pipeline.
C4.2.1.2 Engineering and Geotechnical Considerations
Within the designated Utility Corridor,certain natural hazards exist
which must be identified and considered during pipeline design.Such
things as potential land slides,snow avalanche areas,earthquake faults,
and erosion areas cause a threat to the pipeline integrity.'Thus,their
location and potential magnitude is of primary concern.Additionally,
the construction of a workpad and the interaction of the pipe with the
soil thenmal regime and local hydrological conditions can significantly
2605B
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alter nonna1 terrain stability.liquefaction,ice damming,aufeising,
flooding,and thaw degradation are but a few concerns which must be
addressed.
Two major considerations of prima~importance to a safe design are the
mitigation or prevention of frost heave and thaw settlement.Both these
phenomena pose a hazard to a gas line by changing the delicate thermal
balance in certain soil conditions along the route.A significant effort
has been put into understanding these phenomena by A1yeska and Northwest
Alaskan Pipeline Company (NWA),but additional research will be required
to understand the specific interaction of any new design configuration or
construction mode.
Another potential pr~b1em concerns ~dditiona1 rights-of-way for future
pipelines or other structures in the Atigun Pass area.This region is
extremely narrow with little ground space available for pipeline
development.Should other rights-of-way be envisioned they should be
specified in advance so that the least costly alternative for all routes
can be achieved.
Some specific engineering criteria that must be considered during
pipeline design include:
1)Minimize cross drainage blockage.
2)Avoid thaw unstable slopes as much as possible.
3)Minimize traversing areas with frost susceptible soil.
4)Minimize the haul distance for construction materials.
5)Provide year-round,all-weather access to the proposed pipeline.
6)Maximize route cost effectiveness.
7)Prevent degradation of the permafrost.
26058
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C4.2.1.5 Environmental Considerations
The environmental considerations discussed in Section C3.2.1.2 regarding
transmission line construction from the North Slope to Fairbanks are
generally applicable to the gas pipeline system.Additional
considerations specific to the gas pipeline include:
1.Fish passage must not be blocked and flow velocity must not exceed
the maximum allowable flow velocity for the fish species on a given
stream.If these criteria cannot be met,a bridge must be installed.
2.Stream crossings must be able to withstand the pipeline design flood
as determined for each stream..
3.Chilled pipes in streams should not cause:a)lower stream
temperature so as to alter biological regime of stream;b)slow
spring breakup and delay of fish migration;c)early fall freeze-up
.which would affect fish migration.
4.Chilled pipe in streams should not .aggravate or initiate aufeis
buildup,if possible.
5.The original configuration,gradient,substrate, velocity,and
surface flow of streams should not be altered.
6•.For fish,construction scheduling should avoid in-stream construction
during critical sensitivity periods and be miniminal in moderate
peri ods..
7.Disturbance of wetlands should be minimized.
B.The temperature of natural surface or groundwater should not be
.changed significantly by the pipeline system or by aqy
constructi on-rel ated acti viti es.
C4.2.2 Applicability of the ANGTS Route
The Alaska Natural Gas Transportation System (ANGTS)route is located
within the Utility Corridor,set aside under Public Law Order 5150 in
1971.The Alaska Natural Gas Transportatio~Act (1976)and the
Presidential Decision (1977),routed the 4B-inch diameter pipeline within
this corrJdor,inclUding its infrastructure of roads,material sites,and
ancilla~development.The corridor,from Washington Creek north to
about 60 miles south of Prudhoe Bay,is managed by the Bureau of Land
2605B
C4-13
Management under a land use plan centered around nodal development.
Construction on State lands on the North Slope is further regulated
through North Slope Borough ordinances.In addition,private property
owners,native corporation lands,holders of sub-SUrface mineral rights,
and Alyeska had numerous stipulations that had to be resolved.
During the evolution of the gas pipeline routing,environmental,
socioeconomic,and land use decisions dictated gas1ine locale.The
selection process took several years while Northwest Alaskan Pipeline
Company (NWA)developed the resources and environmental data base to be
used for route selection and design criteria.NWA reviewed existing
trans-Alaska oil pipeline and State highway construction data,resource
agency files,and implemented biological,physical,and civil field
programs to further delineate constraints.
The infonmation provided by NWA was reviewed by State and Federal agency
representatives through the State Office of Pipeline Coordinator and the
Office of the Federal Inspector --a 'one window'coordinated effort
where government resource and NWA personnel developed acceptable
mitigation measures to be incorporated ;-n ANTGS route selection,project
design activities,and construction stipulations.
Through the processes described above,NMA minimized the crossings of the
trans-Alaska oil pipeline,the Alyeska gas1ine (Prudhoe B~to Pump
Station 4),and the Dalton Highway.The environmental and non-technical
programs conducted since the environmental impact report (1976)have
provided infonnation that altered the route to mitigate gasline impact on
sensitive areas (e.g.,a white spruce stand on the Dietrich River was
avoided).The gas1ine alignment has been reviewed in detail and the
general route approved by resource agency personnel.It has also been
reviewed by the public during the public participation program developed
by NWA.
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Based on the synopsis provided here.which is supported by years of field
research by NWA.Alyeska.and resource agencies.it is reasonable to base
the present st~dy on the assumption that the ANGTS route is a viable
pipeline route for the transportation of gas from the North Slope to the
Fairbanks area.
C4.3 "GAS DISTRIBUTION SYSTEM FOR FAIRBANKS
As indicated at the beginning of Chapter C4.SCenario II includes the
development of a gas distribution system within Fairbanks.It is
generally assumed that siting of this system would necessarily conform to
good engineering practice in municipal environments.Specific
engineering considerations related to facility location decisions are
discussed in the following paragraphs.
The overall system network would consist of a transmission lateral from a
metering station at the main pipeline near Fox to one or several city
gate stations.The metering station would be located where the gas
pipeline crosses the Steese Highway about 2 miles northeast of Fox.From
there a transmission line would run into Fairbanks in public
rights-of-way adjacent to traveled roadways.to the city gate station(s}.
The type of construction and location of district regulator stations will
be detennined during final design.The options of underground vault
versus aboveground station construction must be reviewed with respect to
considerations of the availab1ility of public right-of-way.private
easement.soil and groundwater characteristics.equipment operating
capabilities and safety.
The distribution lines would be laid in public rights-of-way at a depth
of three feet to the top of the main.The lines would occupy the
opposite side of the road from existing or proposed water mains.
2605B
C4-l5
C4.4 TRANSMISSION FACILITY ROUTING EVALUATION
The Fairbanks to Anchorage transmission line routing requirements for
this scenario are the same as those for the North Slope.power generation
scenario.The regional description,engineering and environmental
considerations,and route des~ription presented in Section C3.2.2 of this
report are also applicable to this scenario.
26058
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C5.0 SCENARIO I II -KENAI POWER GENERATION
The Kenai Power Generation scenario (Figure C5-l)is predicated on the
development of a large diameter natural gas pipeline from Prudhoe Bay to
a tidewater location near Kenai or Nikiski.This all-Alaska pipeline is
being studied by others.Several assumptions regarding this facility are
used in this report.A conditioning facility would be located at the
tidewater site to remove impurities (mainly carbon dioxide)from the gas
and liquefy the gas for transhipment to appropriate markets.The waste
gas from this conditioning facility would be used to fuel the power
generating facility discussed in this stuqy.Because the waste gas could
only produce a small amount of electrical power,.it would be supplemented
by sales gas from the pipeline to satisfy the requirements of both load
forecasts.Electricity generated at this plant would be transmitted to
Anchorage where 80 percent of the capacity would be used,by constructing
new transmission lines.The remaining 20 percent capacity would be
transmitted on to Fairbanks,via the upgraded Intertie.
C5.l GENERATING FACILITY SITE EVALUATIONS
Siting for the Kenai scenario focused on the coastal area between Kenai
and Nikiski.This section gives an overview of the region,siting
considerations,and the generic site description.
C5.l.1 Description of the Region
The Kenai-Nikiski area is on the western border of the Kenai Peninsula.
Kenai is situated on the Sterling Highway at the mouth of the Kenai
River.A corridor of industrial and rural residential development is
situated along the North Kenai Road,which extends about 20 miles north
of Kenai.The communities of Salamatof and Nikiski are included within
this area.Major onshore facilities are "l.ocated in Nikiski,including
refineries,an ammonia urea manufacturing plant,and natural gas
liquefaction facility.
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PhYsical Setting
The Kenai-Nikiski area ranges in elevation from 100 to 150 feet above sea
level.The shoreline on Cook Inlet is an abrupt,steep bluff.Much of
the surface is marshes or muskeg bogs interspersed among numerous small
lakes.Subsurface drainage ranges from good to poor,depending on the
nature of underlying sediments and topography.Vegetation ranges from
sedge-grass..moss cover on the wettest sites to mature stands of white
spruce,white birch,aspen and cottonwood on the drier sites (Karl strom
1958)•
Meteorological conditions in the area are generally favorable for the
development of facilities such as power plants.The site ;s in an
exposed coastal setting with generally moderate winds and good
.~tmospheric dispersion conditions.Fog develops often in the area during
the .winter months,but is relatively rare during the spring and summer
months.Temperature extremes can range from -30°F to 80°F in the site
area but the average winter temperature is 13°F while the average sUlll1ler
temperature is 54°F.
Social Profile
Kenai is the largest economic center on the Kenai Peninsula.The 1980
populations at Kenai and Nikiski were 4,324 and 1,109.,respectively.The
three largest economic sectors for the Kenai-Cook Inlet census subarea
are manufacturing,government,and wholesale and retail trade,in that
order.Unemployment is high due to the seasonality of construction and
cOJllJ1ercial fishing and averaged 13 percent in 1981 (Alaska Department of
Labor 1982).
C5.1.2 Siting Considerations
C5.1.2.1 Land Status and Use Considerations
Because the Kenai-Nikiski area ;s already extensively industrialized,
compatibility with existing land uses will not pose serious problems.
2605B
C5-3
Detailed facility siting analyses for this scenari.o should address
potential effects on locally significant land uses such as the Captain
Cook Recreation Area at the north end of the North Kenai Road;existing
and future rural residential developments;flight operations of the Kenai
Municipal Airport;and the numerous pipeline rights-of~ay serving the
area's refineries.New generating facilities might be sited to t~ke
advantage of the existing Bernice Lake .Generating Station operated by the
Chugach Electric Association.
C5.1.2.2 Geotechnical Considerations
In selecting the location for a generating facility,the key geotechnical
criteria are foundation s011s with good bearing capacity and limited
settlement potential,and suitable site drainage.These conditions are
prevalent just north of Kenai adjacent to the North Kenai Road,where
terrace and alluvial plain silts,sands.and gravels predominate.These
terrace and alluvial deposits are of glacio-lacustrine and glacio-fluvial
origin.The topography is flat to undulating.
C5.1.2.3 Engineering Considerations
General engineering considerations presented for both the North Slope and
Fairbanks power generating scenarios (Sections 3.1.2.3 and 4.1.2.3)are
also applicable to the Kenai area.
All potential site locations in the Kenai area fall within regions of
high seismic activity (Zone 3).While this will not preclude
development,it will increase construction costs as more material will be
required to insure plant foundation stability.The site must also have
access to approximately 1000 gpm of water because water or steam
injection for the control of nitrogen oxides will likely be required.
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C5.l.2.4 Environmental Considerations
Air Quality
As is typical of many exposed coastal locations,the air quality and
meteorological conditions are generally favorable to the development of
facilities such as power plants.It is not likely that an intense
"marine layer",which may restrict dispersion of pollutants,develops in
this area.The air quality attains the applicable ambient standards,but
the locale is burdened with several existing petroleum refinery
emissions.A new natural gas-fired power plant could probably be sited
in the area with the use of appropriate emissions controls including
water or steam injection to reduce nitrogen oxides emission.The impact
of water vapor emissions on the fonmation of fog must also be
considered.The power plant must be carefully sited in order to avoid
adding to the air quality impacts of th.e existing facilities.
Other Environmental Considerations
The Kenai-Nikiski industrial corridor,by virtue of its past development,
is generally not an ecologically important land area.The Kenai National
Wildlife Refuge,a few miles to the east,is a major environmental
resource which provides habitat protection for both resident and
migratory wildlife.However,there are other local environmental
concerns which must be con"sidered in siting additional power generating
facilities in the area.Effects on local residential developments,
recreational facilities and tourism must be addressed on a site-specific
basis,but probably would not preclude site development in this rural
i ndustri al area.
C5.l.3 Generic Site Description
C5.l.3.l Location and Access
Because the generating facility will be using waste gas and sales gas
from a gas conditioning facility,the plants will be located in close
2605B
C5-5
C5.1.3.3 Water Source
The power plant site is approximately 65 acres in size.
camp will be used at the site because sufficient local
be available.
proximity to each other.The generic site is in the general
Kenai-Ni ki ski area withi n a few miles of the coast.The area is served
by existing electrical transmission lines and access roads.
C5.1.3.2 Size and Surface Characteristics
No constructi on
housing appears to
The terrain in the site vicinity is flat to gently rolling.Vegetation
consists generally of sparse stands of shallow-rooted trees with local
patches of denser forest and shrub.
Groundwater will be used for all plant water needs.The water will be
treated to reach the qual ity needed for make-up water.Groundwater is
generally available in the Nikiski area,so that water supply will not
pose a significant constraint to development.
C5.l.3.4 Soils and Foundations
Generic site topographY and soils consist of flat to undulating
topographY and well-drained granular materials (i.e.,sands and gravel).
The foundation will consist of a concrete mat 2 to 4 feet thick on
grade.Other than clearing and grubbing,and perhaps some minor grading,
no other foundation work will be required.
C5.2 TRANSMISSION FACILITY ROUTING EVALUATIONS
All of the electricity generated at the Kenai/Nikiski site would be
transmitted to Anchorage via new transmission lines.Eighty percent of
the generated capacity would be used in Anchorage;the remaining 20
26058
C5-6
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percent woul d be transmitted on to Fairbanks vi a the upgraded I nte rti e.
The Kenai-Anchorage corridor is discussed first below,followed by the
Anchorage-Fairbanks corridor.
C5.2.l Kenai-Anchorage Corridor
C5.2.l.l Description of the Corridor
The transmission corridor between Kenai and Anchorage is maintained by
the Chugach Electric Association (CEA).The corridor generally parallels
the Sterling Highw~across the Kenai Peninsula to the upper end of
Turnagain Arm at Portage.It is located on a narrow bench along the
highway traversing the north shore of Turnagain Arm as far west as Indian
Creek,where it turns north to traverse Powerline Pass in the Chugach
Mountains.The corridor then descends to the northwest into Anchorage.
PhYsical setting
The corridor lies within the Coastal Trough and Pacific Border Ranges
phYsiographic provinces.That portion of the corridor which lies north
of Turnagain Arm is within the Cook Inlet-Susitna Lowland subdivision of
the Coastal Trough province.This is a glaciated lowland containing
areas of ground moraine and stagnant ice topography,drumlin fields,
eskers and outwaSh plains.The lowland is generally less than 500 feet
above sea level.That portion of the corridor to the ~outh of Turnagain
Arm lies within the Kenai-Chugach Mountains subdivision of the Coastal
Trough province.The Kenai Mountain range has been heavily glaciated and
is characterized by rock-basin lakes,U-shaped valleys,and incised
ravines.The Kenai Lowlands extend west of the mountains and are drained
by the Kenai Ri ver (Wahrhaftig 1965).
The Kenai River system is a major phYsiographic feature of the region.
The Kenai River and its tributaries are important spawning grounds for
king,sockeye,and silver salmon.The vegetation of the Kenai River
watershed lies in a transition ~one between the Pacific rainforest biome
and the Arctic-alpine biome.Vegetation types within this zone include
the coastal western hemlock-Sitka spruce forest,upland spruce-hardwoods,
2605B
C5-7
lowland spruce-hardwoods,high brush,muskeg,and tundra.These habitat
types support an abundance and variety of bird and mammal populations
CU.S.A~Corps of Engineers 1978).
The climate of the studY corridor varies with changes in the topography
and relationship to the Kenai Mountain range.The climate,in general,
is not as wet as that characteristic of the maritime climatic region and
is not as extreme as the continental climate of interior Alaska.Annual
precipitation ranges from 15 inches in Anchorage to 23 inches along the
western coast of the Kenai Peninsula.Temperatures in Kenai average 13°
F in winter and 54°F in summer CU.S.Army Corps of Engineers 1978).
Soci a1 Profi 1e
The studY corridor falls within the jurisdiction of the Kenai Peninsula
Borough.In 1980 the population of the borough was 25,282 with Soldotna
and Kenai the major communities within the corridor.The area around
Kenai,Soldotna,and Sterling has undergone rapid subdivision.Increased
tourism and recreational activity have contributed to the growth in
Soldotna and,to a lesser extent,in Ste·r1ing.Growth in population and
employment has been i nf1 uenced strongly by growth in the hydrocarbon
industr,y.As a result of petroleum and natural gas activity,the
peninsula has experienced extensive development,including pipelines,
marine tennina1s,refjneries and other processing facilities.The food
and kindred products industr,y is important to the regional economy,
particularly with regard to fish processing.Unemployment is currently..
and historically has been high,due in part to seasonal variations in the
1abor market.
The studY corridor falls with the Chugach National Forest,administered
by the U.S.Forest Service,and the Kenai National Moose Range,
administered by the U.S.Fish and Wildlife Service.These areas offer
numerous recreational opportunities to residents of the peninsula as well
as of Anchorage.
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C5.2.1.2 Existing Transmission Facilities
Chugach Electric Association,Inc.presently operates a 115 kV line from
Anchorage to Soldotna and Nikiski (Bernice Lake),via Portage and Quartz
Creek,and a 69 kV line between Quartz Creek and Soldotna which continues
to Homer.These transmission lines cannot be considered as part of the
system evaluated in this feasibility stu~because their load carr,ying
capacity is a small fraction of the considered electrical requirements.
The established rights-of-w~associated with these lines have been
considered to the maximum extent possible,however.
Engineering Considerations
Because of the relatively short distance there is no need for
intenmediate switching stations between Kenai and Anchorage,even in the
medium forecast scenario.The two circuits of the transmission line
req~ire a 440 foot wideright-of-w~or two 220 foot wide corridors.
Should less than 440 feet be available for the entire length,the two
circuits m~be routed for short distances on single towers,though this
would lower the avai1abi1ty of the system.
Environmental Considerations
Several environmental protection factors should be taken into account in
pl ann'ing and desi gn of an expanded right-of-way and,in certain areas,
for new rights-of-way.
To minimize soil erosion,steep slopes and highly erodible soils should
be avoided where possible.Existing access roads should be used at all
possible locations.New access roads should incorporate adequate
drainage systems to minimize erosion of the road surface.
The selected route should minimize the number of additional stream
crossings.Where stream crossings are unavoidable,the towers should be
set back a minimum distance from streambanks and a buffer strip of
26058
C5-9
vegetation should be retained along water bodies to minimize siltation of
streams.Equi pment shoul d cross streams usi ng well-desi gned bri dges that
protect the stream bank.
The present route passes through a small area of caribou habitat near
Kenai (University of Alaska 1974).Little alteration of caribou habitat
will result from construction of the transmission line because the animal
utilizes cover types that require little if any clearing.The route also
passes adjacent to Dall Sheep and Mountain Goat range between Cooper
Landing and Saxton,but does not extend into the rangeland at any
location.Much of the route between Kenai and Cooper Landing is within
Moose fall and winter rangeland.However,because the moose utilizes
ma~different habitat types,it will be the least adversely affected by
habitat alterations (Spenc~r and Chatelain 1953).Where the proposed
route crosses heavily forested areas,the moose will benefit from
.additional clearing of the right-of-way and the subsequent establishment
of a subc1imax community (Leopold and Darling 1953).
Fisheries resources can be protected by closely coordinating construction
activity with the Alaska Department of Fish and Game.Equipment should
not cross streams without bridges when eggs or fry are in the streambed.
C5.2.1.4 Route Description
Two 500 kV circuits are required for both the medium and low electrical
demand forecasts.No intennediate switching stations are required but
series compensation is required for the medium load forecast.
The line would originate at the powerhouse in the Kenai area.Routed in
an easterly direction,it would parallel the 115 kV Chugach line.It
would follow the Kenai River Valley,the north shore of Kenai Lake,and
would tur.n northeast along Quartz Creek.At the East Fork of the Bend
River it would make a sharp turn,and follow the river until the Granite
Creek Valley.The line would then follow the Seward Highw~around
Turnagain Ann to Girdwood.
2605B
C5-10
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The section between Girdwood and Rainbow Creek is the most difficult as
fa r as eng i neeri ng is concerned.In thi s report it is a sumed that the
line wQuld be located on the mountain side,which slopes to 1000 feet in
elevation with an average grade in excess of 50 percent and then,between
1000 and 2000 feet at a 20 percent slope.From Rainbow Creek to
Anchorage the area is flat and sufficiently wide to accommodate the line.
In order to avoid the Girdwood to Rainbow Creek section,other route
alternatives will be investigated.All alternatives would carry the
power using a Turnagain Arm crossing with undersea cables from Windy
Point to Bird Creek.From the Bird Creek table termination three
alternative routings will be investigated:1)traversing Bird Creek Pass
into the valley of the North Fork of Ship Creek;2)crossing from
Girdwood to Penguin Creek over the mountains and following Bird Creek
Pass as outlined above;and 3)following Penguin Creek across th~
mountains at an elevation of less than 3000 feet into Bird Creek and then
following the existing Chugach line through Powerline Pass to Anchorage.
C5.2.2 Anchorage-Fairbanks Corridor
The Fairbanks to Anchorage transmission line routing requirements for
this scenario are the same as those for the North Slope and Fairbanks
power generation scenarios.The regional description,engineering and
environmental consjderations,and route description presented in Section
C3.2.2 of this report are also applicable to Scenario III.
2605B
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C6.0 REFERENCES
Alaska Department of Labor,Research and Analysis section.1981.
Alaska economic trends.Juneau,Alaska.
Alaska Department of Labor,Research and Analysis Section.1982.
Personal communication.
Brown,J.1976.Ecological and Environmental Consequences of Off-Road
Traffic in Northern Regions.U.S.Department of the Interior.
Bureau of Land Management.1980.The Utility Corridor,Land Use
Decisions.U.S.Department of the Interior,Bureau of Land
Management,Fairbanks,Alaska.
Commonwealth Associates Inc.1982.Environmental Assessment Report for
the Anchorage-Fairbanks Transmission Intertie.Alaska Power
Authority,Anchorage Alaska.
Karlstrom,T.1958.Ground conditions and surficial geology of the
Kenai-Kasilof area Kenai Peninsula,South-Central Alaska.U.S.
Geological Survey map scale 1:63,360.
Leopold,A.and F.Darling.1953.Effects of Land Use on Moose and
Caribou in Alaska.Transactions of the North American Wildlife·
Conference.18:553-582.
North Slope Borough.1978.Coastal Management Program,Prudhoe Bay Area.
North Slope Borough,Barrow ,Alaska.
Roseneau,D.G.,C.E.Tull,and R.W.Nelson.1981.Protection strategies
for peregrine falcons and other raptors along the planned Northwest
Alaskan gas pipeline route.Unpub.rep.by LGL Alaska Res.Assoc.,
Inc.,Fairbanks,for Northwest Alaskan Pipeline Co.and Fluor
Northwest,Inc.,Fairbanks.'
Spencer,D.L.,and E.F.Chatelain.1953.Progress in the Management of
the Moose of South central Alaska.Transactions of the North
American Wildlife Conference.18:539-552.
U.S'.Army Corps of Engineers,Alaska District.1978.Kenai River Review.
Anchorage,Alaska.
University of Alaska,Arctic Environmental Information and Data Center.
1974.Alaska Regional Profiles,Southcentral Region.State of
Alaska,Office of the Governor,Juneau,Alaska.
University of Alaska,Arctic Environmental Information and Data Center.
1978a.Deadhorse.U.S.Department of the Interior.'
2605B
C6-1
~[
University of Alaska,Arctic Environmental Infonmation and Data center.l'
1978b.The Region.U.S.Department of the Interior.l
Wahrhaftig,Clyde.1965.P~siographic divisions of Alaska.Geological ['."
Survey Professional Paper 482.Washington,D.C.~~.
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KENAI POWER GENERATION
NORTH SLOPE GAS FEASIBILITY STUDY
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PIPELINE
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APPENDIX D
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APPENDIX D
REPORT
ON
TRANSMISSION SYST91 DESIGN
JANUARY 1983
TABLE OF CONTENTS
Oi
02.2 SPECIAL PROBLEMS PERTAINING TO THE NORTH SLOPE
PAGE
01-1
02-1
02-1
02-1
02-1
02-2
02-2
02-3
03-1
03-1
03-1
03-1
03-2
03-2
03-2
03-3
03-3
03-3
03-3
03-9
03-9
03-9
04-1
04-1
04-2
04-2
04-2
04-2
04-4
04-5
... . . . ..
02.2.1 Contamination Mitigation in the Prudhoe
Bay Area . . . . . . . . . . . . . • .
02.2.2 Grounding ••••••••••••••••
Meteorological and Climatic Conditions
Mitigation of Contamination
Transmission Voltages •••
Conductors and Bundle Types ••••
Cl earances •••••••••••••
Insulators •••••.••••••••
Safety Factors and Strength Requirements
of Support Structures . • • • • • • • •
03.2.8 Lightning Protection and Grounding •••
03.2.9 Oistance Between Parallel Lines,Route
and Pipeline ••••••••••
03.2.10 Corona Criteria for Conductor Size •••
03.2.11 Radio and Television Interference:
RI and TVI ••
03.2.1
03.2.2
03.2.3
03.2.4
03.2.5
03.2.6
03.2.7
02.1.1 One-L i ne Oi agram • • • •
02.1.2 Auxiliary Power Source.
04.2.J Conductor Selection •••••••
04.2.1.1 Current Carrying Criteria •••••••
04.2.1.2 Acceptable Conductor Gradient.
.04.2.1.3 Mechanical Oesign Selection of.
Conductor,Towers and the
Ruling Span •••••••••
04.2.1.4 Ri ver Crossi ngs • • • • • • • • • • •
D3.1 GENERAL............ . • • • . . • • •
03.2 OESI GN CO NSI OERA TIONS • . • • • • • • • • • • •
04.1 GENERAL ••••••••••••••••••
04.2 OESIGN OF THE 500 kV TRANSMISSION LINES.
03.0 NORTH SLOPE TO ANCHORAGE TRANSMISSION SYSTEM OESIGN •
04.0 TRANSMISSION OESIGN (HAROWARE)•••.••••
01.0 INTROOUCTION ••••••••
02.0 FACILITIES AT NORTH SLOPE.
02.1 SUBSTATION •••••
2560B
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04-6
04-7
04-8
04-8
04-8
04-9
04-9
04-9
05-1
05-1
05-3
• •e _
LINE • • • • •.-.• . • • • • • • • . . .
TABLE OF CONTENTS (continued)
04.6.1 Fairbanks Substation ••••••••••
04.6.2 Anchorage Substation •••••••
04.6.3 Series and Parallel Compensation
04.5 DESIGN DATA OF THE 345 kV TRANSMISSION LINES ••
04.6 SUBSTATIONS AND SWITCHING STATIONS •••••
04.3 DESIGN DATA OF THE 765 kV TRANSMISSION LINE •••••
04.4 OESI GN DATA OF THE +350 kV BI POLAR DC TRANSMISSION
04.7 COMMUNICATION SYSTEM ••••
05.0 SYSTEM DESIGN (LOAD FLOW STUDIES)•
05.1 GENERAL •••••••••••
05.2 PERFORMANCE STUDIES ••••
05.2.1 Alternatives A and AA -1400 MW Generation
at Prudhoe Bay,Two 500 kV Lines from Prudhoe
Bay to Anchorage and the 345 kV Intertie In
Parallel Between Fairbanks and Anchorage 05-3
05.2.2 Alternative B -1400 MW Generation
at Prudhoe Bay,Two 500 kV Lines Between
Prudhoe Bay and Fairbanks and Three 345 kV
Lines Between Fai rbanks and Anchorage • • •05-10
05.2.3 Alternative C -1400 MW Generation at
Prudhoe Bay,Two 765 kV Lines Between Prudhoe
Bay and Fairbanks and Three 345 kV Lines
Between Fairbanks and Anchorage • • • • • •05-13
05.2.4 Alternative 0 -1400 MW Generation at
Prudhoe Bay,Two Bi polar +350 kV DC Lines
Between Prudhoe Bay and Fii rbanks and Three
345 kV Lines Between Fairbanks and Anchorage 05-16
05.2.4.1 Description of the System.• •05-16
05.2.4.2 Perfonmance Studies.• • • • •05-20
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05.2.5 Alternative E -700 MW Generation at
Prudhoe Bay,Two 345 kV Lines from Prudhoe
Bay to Anchorage • • • • • • • • • • • • •05-22
05.2.6 Alternative F -700 MW Generation at
Prudhoe Bay,Two 500 kV Lines Between Prudhoe
Bay and Fairbanks and Two 345 kV Lines
Between Fairbanks and Anchorage • • • • • •••05-23
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TABLE OF CONTENTS (continued)
PAGE
06.0 CONCLUSIONS •..·.. ...· ·
·····06-1
07.0 SAG AND TENSION CALCULATIONS · ·
· · ·
. ... ..07-1
08.0 FIGURES •.·..··· · ···... .
08-1
09.0 REFERENCES . . .··· ···· ·
09-1
Oiii
TOWER OVERLOAD CAPACITY FACTORS (OFCs)
OVERLOAD CAPACITY FACTORS (OFCs)OF GUYS OF .
GUYED TOWERS
ELECTROSTATIC FIELD INTENSITY LIMITS AT .
1 METER ABOVE GROUND
Tabl e No.
0-1
0-2
0-3
0-4
0-5
0-6
0-7
P-8
LIST OF TABLES
Title
CONDUCTORS CONSIDERED • • .
CLEARANCES REQUIRED • • •
INSULATORS CONSIDERED •
Nt1PAC IT!ES
SYMBOLS ..
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Page
03-4
03-5
03-6
03-7
03-8
03-10
04-3
08-1
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LOAD FLOW ••••••••••• • • • • • • • • •D8-5
No Generation at Prudhoe Bay.One Line
Segment Open North of Fairbanks
ONE LINE SCHEMATIC WITH IMPEDANCES • • • • • • • •D8-3
1400 MW Capacity at Prudhoe Bay;500 kV
Transmission System;345 kV Intertie in
Parallel Between Fairbanks and Anchorage;
No Intermediate Transformation at
Fa;rbanks
1400 MW Capacity at Prudhoe Bay;500 kY
Transmission System;345 kY Intertie in
Parallel Between .Fairbanks and Anchorage;
Intermediate 138 kV Bus at Fairbanks
Page
D8-2....
• . • • .D8-4
Normal
LIST OF FIGURES
LOAD FLOW • • • • • • • • • • •
No Generation at Prudhoe Bay.
System Configuration
ONE LINE SCHEMATIC WITH IMPEDANCES
Title
D-3
D-2
D-4
D-l
Figure No.
D-5
D-6
D-7
D-8
D-9
2560B
LOAD FLOW • • • • • • • • • • • • • • • • • •••D8-6
No Generation at Prudhoe Bay.One Line
Segment Open North of Gold Creek
LOAD FLOW ••••••••• • • • • • • • • • • •D8-7
No Generation at Prudhoe Bay.One Line
Segment Open North of Gold Creek
Less One Reactor
ONE LINE SCHEMATIC WITH IMPEDANCES • • • • • •••D8-8
No Generation at prudhoe Bay.The 345 kV
Intertie Opened at Anchorage
LOAD FLOW •••••••••••• • • • • • • • •08-9
No Generation at Prudhoe Bay.The 345 kV
Intertie Opened at Anchorage,Less One
Reactor
LOAD FLOW • • • • • • • • • • • • • • • • • •••D8-10
No Generation at Prudhoe Bay.One Line
Segment-Opened North of Galbraith Lake
Dv
LOAD FLOW • • • • • • • • • • • • • • • • • •••08-13
1400 MW Generation at Prudhoe Bay.One
Line Segment Out of Service North of Fairbanks
LOAD FLOW • • • • • • • • • • • • • • • • • • • •08-17
1400 MW Generation at Prudhoe Bay.One
o of,the 500-345 kV Transfonners Out of
,Service at Fairbanks
ONE LINE SCHEMATIC WITH IMPEDANCES.• •08-18
1400 MW capacity at Prudhoe Bay;Two
500 kV Transmission Line Circuits Between
Prudhoe Bay and Fairbanks and Three 345 kV
Transmission Line Circuits Between Fairbanks
and Anchorage.
LOAD FLOW • • • • • • • • • • • • • • • • • • • •08-14
1400 MW Generation at Prudhoe Bay.One Line
Segment Out of Service South of Prudhoe Bay
LOAD FLOW •••• • • • • • •.'.• • • • • •••08-1 5
1400 MW Generation at Prudhoe Bay.One
500 kV Line Segment Out of Service South of
Fairbanks
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08-11
08-16
••08-12
••08-19
....
. .
Nonna1
Nonna1 System
1400 MW Generation at Prudhoe Bay.One
500 kV Line Segment Out of Service North of
Anchorage
LIST OF FIGURES (continued)
LOAD FLOW • • • . • . . • . • . • • . • . • •
Dvi
LOAD FLOW • • • • • • • • • • • • •
1400 MW Generation at Prudhoe Bay.
System Configuration
LOAD FLOW • • • • • • • • • • • • • • • •
No Generation at Prudhoe Bay.One Line'
Segment Opened North of Galbraith Lake,
Less One Reactor
Title
LOAD FLOW • • • • • • • • • • •
No Generation at Prudhoe Bay.
Configuration
0-10
0-12
0-11'
0-13
0-16
0-15
0-14
0-17
0-18
Figure No.
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0-19
0-20
0-21
0-22
LIST OF FIGURES (continued)
Title Page
LOAD FLOW • • • •••• • • • • • • • • •08-20
1400 MW Generati on at Prudhoe Bay.Nonnal
System Configuration.Generator Bus Voltage
1.05 p.u.
LOAD FLOW • •'.• • • • • • • • • • • • • • • • •,08-21
1400 MW Generation at Prudhoe Bay.Nonnal
System Configuration.Generator Bus Voltage
1.00 p.u.
LOAD FLOW • • • • • • • • • • • • • • • • • •••08-22
1400 MW,Generation at Prudhoe Bay.One
Line Segment Ou t 0 f Se rvi ce South of Prudhoe
Bay.Generator Bus Voltage 1.05 p.u.
LOAD FLOW • • • • • • • • • • • • • • • • • •••08-23
1400 MW Generati on at Prudhoe Bay.One
Line Segment Out of Service South of Prudhoe
Bay.Generator Bus Voltage 1.00 p.u.
Ovii
LOAD FLOW •.•• • • • • • • • • • • • •08-27
1400 MW Generation at Prudhoe Bay.Nonnal
System Configuration,
LOAD FLOW • • • • • • • • • • • • • • • •'.•••08-24
1400 MW Generation at Prudhoe Bay;One Line
Segment Out of Service North of Anchorage
LOAD FLOW • • • • • • • • • • • • • • • • • •08-25
1400 MW Generation at Prudhoe Bay;Two 765 kV
Transmission Line Circuits Between Prudhoe
Bay and Fa i rbanks and Three 345 kV Transmi 5si on
Li ne Ci rcuits between Fai rbanks and Anchorage,
•08-28
• • •••08-26
One 765 kV
• • • • 0 •
Nomal
ONE LINE SCHEMATIC WITH IMPEDANCES ••,•••••0 08-29
1400 MW capacity at Prudhoe Bay;HVOC
Transmission Between Prudhoe Bay and Fairbanks
and Three 345 kV Transmission Line Circuits
Between Fairbanks and Anchorage.
LOAD FLOW • • • • • • • • • • • • •
1400 MW Generation at Prudhoe Bay;
Line Segment South of Prudhoe
Bay Out of Service
LOAD FLOW..• • • • • • • • • •
No generation at Prudhoe Bay.
System Configuration
0-23
0-25
0-24
0-28
0-27
0-26
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LIST OF FIGURES (continued)
ONE LINE SCHEMATIC WITH IMPEDANCES • • • • • •D8-35
700 MW Capacity at Prudhoe Bay;345 kV
lransmission System with Series Compensation
LOAD FLOW • • • • • • • • • • • • • • • • •D8-33
1400 MW Generation at Prudhoe Bay;HVDC
Transmission Between Prudhoe Bay and Fairbanks.
Nonmal System Configuration;Voltage Raised
by 5%at Fairbanks
LOAD FLOW • • • • • • • • • • • • • • • • • • • •D8-34
1400 MW Generation at Prudhoe Bay;HVDC
Transmission Between Prudhoe Bay and Fairbanks.
One 345 kV Li ne Segment Out of Service North
of Anchorage;Voltage Raised by 5%at Fairbanks
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D8-37
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LOAD FLOW • • • • • • • • • • • • • •
No Generation at Prudhoe Bay;Nonmal
System Configuration
LOAD FLOW • • • • • •0 • • • • • • • • • • •••D8-32
1400 MW Generation at Prudhoe Bay;HVDC
Transmission Between Prudhoe Bay and Fairbanks
and One 345 kV Line Segment Out of Service
North of Anchorage
Dviii
Title
LOAD FLOW • • • • • • • • • •0 • • • • •
No Power Transfer Between Fairbanks and'
Anchorage.Nonma1 System Configuration
LOAD FLOW • • • • • • • • • •0 • • • • • •D8-31
1400 MW Capacity at Prudhoe Bay;HVDC
Transmission Between Prudhoe Bay and Fairbanks.
Nonma1 System Configuration
LOAD FLOW • • • • • • • • • • • • • • • •
No Generation at Prudhoe Bay;One Line
Segment Opened North of Fairbanks with the
Loss of an Additional Reactor
LOAD FLOW • •0 • • • • • • • • • • • •
No Generation at Prudhoe Bay;One Line
Segment Opened North of Fairbanks
D-33
D-31
D-30
D-32
D-35
D-29
D-34
D-37
D-36
Fi gure No.
LOAD FLOW • • • • • • • • • • • • • • • • • •••08-40
700 MW Generation at Prudhoe Bay,One Line
Segment Out of Service South of Prudhoe Bay
ONE LINE SCHEMATIC WITH IMPEDANCES • • • • • •08-41
700 MW Capacity at Prudhoe Bay;500 kV
Transmission Between Prudhoe Bay and Fairbanks
and 345 kV Transmission with Series Compensation
Between Fairbanks and Anchorage
.
No nna 1
•'.•••08-42
•••08-43
Page
08-39...
Nonna1
Nonna1
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LOAD FLOW • • • • • • • • • • •
No Generation at Prudhoe Bay.
System Configuration
LIST OF FIGURES (continued)
LOAD FLOW • • • • • • • • • • • • •
700 MW Generation at Prudhoe Bay.
System Configuration
LOAD FLOW • • • • • • • • • • • • •
700 MW Generation at Prudhoe Bay.
System Configuration
Title
D-39
0-41
D-38
0-40
0-42
Fi gure No.
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0-44
LOAD FLOW • • • • • • • • • • • • • • • • • •••08-44
700 MW Generation at Prudhoe Bay,One Line
Segment Out of Service South of Prudhoe Bay
LOAD FLOW • • • • • • • • • • • • • •.'• • •••08-45
700 MW Generation at Prudhoe Bay,One Line
Segment Out of Service North of Anchorage
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D1.0 INTRODUCTION
In the descriptions that follow,the North Slope-Fairbanks-Anchorage
system,medium load forecast level,is used as a model.However,many
of the findings are directly applicable to the Fairbanks and Kenai
generation scenarios and to the low load forecast cases.
An important aspect of this design study is that the load carrying
capacity of the lines is not the limiting factor of this transmission
system.Rather,the critical factor is the stability of the system,
and the system was designed around this factor.The North Slope medium
forecast scenario concentrates the bulk of Alaska's generation at one
location,from which the greatest part of the power has to be
transmitted over a long (almost 800 miles)line to the bulk of the load
at Anchorage.By the time the system is fully developed,all other
power generation stations connected to the system will be less than 50%
of the single large power station located at Prudhoe Bay and most of
them will be even further than 800 miles away from it.Therefore,in
addition to the criteria listed in Section 2.3,performance
considerations and criteria had to be introduced into the design
process.In the following pages,these additional
considerations/criteria are also described.
Sections D2.0 through D4.0 deal with the hardware aspects of the
transmission system and Section D5 summarizes the findings of the
system des.ign.Section D6 presents conclusions from the preceding
studies.Section D7.0 presents the results of the sag and tension
calculations and section D8.0 contains all Appendix D figures.
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02.0 FACILITIES AT NORTH SLOPE
02.1 SUBSTATION
02.1.1 One-Line Oiagram
The line diagram for the North Slope Substation is shown in Figure
2-3.1/There are 15 generators in the fully developed plan,with
each two connected,through 15kV iso-phase buses,to one 250/125/125
MVA,138/13.8/13.8 kV three-wi ndi ng transfonner,except one generator
which is connected to a two-winding 125 MVA transfonner.Each
generator can be synchronized to the 345 kV bus through its 13.8 kV
circuit breaker installed inside the plant.Four 450/600/750 MVA
OA/OAF/OAF,138/525 (or 765)kV step-up transformers,two connected in
parallel,feed the two transmission line circuits heading south to
Fairbanks.The 138 kV bus,whenever reliability considerations pennit,
uses breaker-and-a-half arrangements.The series capacitors and the
shunt reactors are on the 1 ine side of the 500 (or 765)kV circuit
breakers protecting the lines.,The arrangement enables the buswork of
the substation to be expanded gradually,as can be seen from Figure
2-4,in which the first stage of development is displayed.
02.1.2 Auxiliary Power Source
An auxiliary 69 kV tie line should be negotiated with SOHIO to avoid
installing additional diesel generators for black start.The tie and
13.8 kV distribution will be developed as each plant is built.
1/Fi gures 2-3 and 2-4 are in the main text.
02-1
2560B
02.2 SPECIAL PROBLEMS PERTAINING TO THE NORTH SLOPE
02.2.1 Contamination Mitigation in the North Slope
The 138 kV and 525 kV switchyard and 60 miles of transmission lines are
exposed to heavy pollution.The main source of contamination is dirt
picked up off the arctic desert (tundra)by wind mixed with salt from
the Beaufort sea,even when frozen,and,to a lesser extent,calcium
chl ori de spread on the roads as a dust supressor(Ruef 1981).Based on
local research performed by the SOHIO Company,effective washing of
insulators on their 69 kV and 13.8 kV lines is necessary to prevent
fl ashovers.
Experience with hot-line washing of insulators in substations in other
areas with .voltages above 230 kV demonstrated that the risk of using
mobile washing installations in high voltage substations is too high,
even in more temperate climates with higher temperatures and lower
winds.Therefore,it is planned that a fully automated,fixed hot-line
washing installation will be adopted for the substation,and a fixed
installation with mobile operation of the water pumps will be used for
the towers along the first 60 miles.
The fully automated fixed installation at the Prudhoe Bay substation
consists of two high pressure pumps,a demineralized water tank filled
with water from the water treatment plant of the power plants,fixed
washing nozzles around each substation insulator,and controls which
automatically start the washing of insulators when the test insulator
accumulates a given amount of pollutant.
The insulators on the transmission line are equipped with fixed nozzles
connected to a pipe that is brought down to the bottoms of the towers.
A truck equipped with a stainless steel water tank and a pump with a.
head and flow sufficient to spray the insulators is used.A hose and
02-2
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an operator will be lifted from the haul road to the pads at the
towers.The operator attaches the hose to the pipe at the tower and
washes the insulators.Special measures (such as blowing the water out
with compressed air)are taken after completing the washing of the
insulators to prevent freezing the water inside the fixed pipes of the
washing installations.
The cost of hot-line washing of insulators is relatively high but is
the only way to maintain the reliability of a transmission system on
the North Slope.The cost estimate,based on Ebasco·s experience in
designing and installing such installations,includes a hot-line
washing installation.
02.2.2 Grounding
The permafrost is an important obstacle in.obtaining a low resistance
grounding mat.In the Prudhoe Bay area the grounding mat of the Dalton
substation will be designed as follows:
A copper mat will be installed in trenches under the gravel inside the
switchyard perimeter.From this mat four 1000 kCM insulated copper
cables will be installed in trenches to the sea shore (about 6 miles
north)•
Four electrodes,each fifty feet long,will be driven into the bottom
of the sea near the shore,connected together,and connected to the
four cables.The vertical electrodes will be in the sea sufficiently
deep enough to avoid damages caused by movement of the ice.The
distance between the electrodes will be about 100 feet.
Both transmission line circuits will require counterpoises along the
entire length to Fairbanks.Both counterpoises will be connected to
the substation mat.
02-3
2560B
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03.0 NORTH SLOPE TO ANCHORAGE TRANSMISSION SYSTEM DESIGN
03.1 GENERAL
The transmission line routing from North Slope to Fairbanks follows the
Alaska pipeline (TAPS line)and the Haul .Road (offic·ially called Dalton
Highway)for approximately 450 miles.The route includes the crossing
of Atigun Pass and the Yukon River.The portion from Fairbanks to
Anchorage follows the ROW selected for the 345 kV Intertie
(Commonwealth Associates,Inc.1981).
The basic design criteria for this transmission line considers the
special climatic conditions,such as low temperature,heavy winds and
ice formation,as well as permafrost on most of the ROW.
03.2 DESIGN CONSIDERATIONS
03.2.1 Meteorological and Climatic Conditions
The transmission system is designed using the ,following basic design
c ri teri a.
03-1
25 1 bs per sq.ft north of the Arctic Ci rcle
and 8 lbs/sq.ft.below it;2.3 lbs/sq.ft.
at +86°F.
Temperature range:
Wi nd loads:
The reliability of transmission requires a minimum of two lines to be
built for any alternative.Each line (in the cae of two parallel
lines)ortwo lines (in the case of three parallel lines)should be
able to car~the entire design power,in order to provide
uninterrupted service in the event one of the line segments is tripped.
For the North Slope-Fairbanks Portion of the transmission system,the
following conditions were assumed:
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03-2
03.2.3 Transmission Voltages
03.2.4 Conductors and Bundle Types
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maximum 50%of rated·tensi1e strength.
maximum 18 kV R~S p~r centimeter.
36"north of the Arc ti c Ci rc 1e and 24"south
of it.
1.5"radial thickness with 8 1bs/sq.ft.
wind load at 32°F.
Ice on conductor:
Gradient on conductor
surface:
Tension in conductors:
compact snow on ground:
The conductors investigated are listed in Table 0-1.
Two AC voltage levels were investigated for each of the two load
levels.For the medium forecast load 500 kV and 765 kV AC
transmissions were compared.For the low forecast level 500 kV and 345
kV AC transmissions were analyzed.HVOC transmission was also
considered as an alternative for both forecast scenarios.
The above are values used in the overall design of the transmission
lines.In certain areas,like Atigun Pass,special conditions exist
and,therefore,different criteria would have to be established as part
of a detailed engineering process.
03.2.2 Mitigation of Contamination
EXcept for the portion from Prudhoe Bay to Pump Station #2,the line is
in a non-polluted atmosphere.However,in the first 60 miles the line
is exposed to heavy pollution in the periods between Septembe~and
January,when the northeast winds coat the insulators with a black
conducting film.For this portion of the transmission line the
insulation requires long leakage distance,and is provided with fixed
insulator washing nozzles.
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line clearances should permit safe operation in all climatic
conditions.Clearance to ground will be increased 36 or 24 inches
above minimum to account for the snow on the ground and clearances
required for maximum sag under ice conditions and are shown in Table
0-2.
03.2.6 Insulators
The insulators considered ane listed in Table 0-3.
For 60 miles from Prudhoe Bay to Pump Station #2,high leakage distance
(fog type)insulators are used and the number of insulators is
increased by two in each string.
03.2.7 Safety Factors and Strength Requirements of Support Structures
The overload capacity factors (OCF)applied for the structures and the
foundations are shown in Tables 0-4 and 0-5.
03.2.8 lightning Protection and Grounding
The Prudhoe Bay-Fairbanks portion of the system will not be equipped
with shield wir~s because the isokeraunic level (average number of.
thunder-days per year)is very low.However,one 4/0 AWG copper
conductor counterpoise will be planned beneath each line.The
counterpoise is connected to each tower and buried at least one foot
under ground level.At the substations and switching stations the
counterpoise will be connected to the ground mats.
The Fairbanks-Anchorage portion will be equipped with shield wires.
03-3
2560B
CONDUCTORS CONSIDERED
TABLE 0-1
Cardi na1 ACSR
Chukar ACSR
Bunting ACSR
Martin ACSR
Special 2"di ameter ACSR
Voltage kV
345 AC
500 AC
500 AC
765 AC
+350 DC
2560B
Code Word
Conductor
03-4
Type KCM
954
1781
1193
1351
2839
Conductors per
bundle
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500 AC
765 AC
+350 DC
To Ground
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38
45
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TABLE D-2
CLEARANCES REQUIRED
Minimum Clearance in Feet
26
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D3-5
TABLE 0-3
INSULATORS CONSIDERED
Strings Insu~ators per String
Voltage Size and Strength per Phase Suspens10n .Stra1n
345 AC 5-3/4"x 10"x 50 K 1b 1.!L 18 20
345 AC 5-3/4"x 10"x 50 K1b 2·V21 18 201n-
500 AC 5-3/4 11 X 10"x 50 K1b 2 in V 25 26
765 AC 6-3/4"x 11"x 50 K 1b 4 in V 28 29
+350 DC 6-3/4"x 11"x 50 K 1b 2 in V 28 28
ill Outside phases
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TABLE D-4
TOWER OVERLOAD CAPACITY FACTORS (OFCs)
Load NESC OCFl!
Vertical strength 1.50
Transverse strength
Wind load 2.50
Wire tension load at angles 1.65
Longitudinal strength
At crossi ngs
In general 1.10
At dead ends 1.65
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03-7
25608
1.00
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TABLE 0..5
OVERLOAD CAPACITY FACTORS (OFCs)OF GUYS OF GUYED TOWERS
Load
Transverse strength
Wind loaci
Wire tension load
Longitudinal strength
In general
At dead ends
II For heavy ice 1oadi ng the OFS is 1.1O.
03-8
25608
NESC OCFY
2.67
1.50
1.00
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03.2.9 Distance Between Parallel Lines,Route and.Pipeline
The transmission lines will follow the Prudhoe Bay-Fairbanks Highway
and the TAPS 1i.ne as closely as possibl e.Except at the substations
and switching stations,the distance between center lines of the two
parallel lines is such that failure of one line will not affect
operation of the other.For the 525 kV,345 kV and ~350 kV DC
alternatives the 1 ines are 200 feet apart.For the 765 kV alternative,
the lines are 300 feet apart.Distances to the highway and pipeline
will be desi gned to mi nimi ze e1ectromagneti c i nducti on into the
pipeline during line to ground faults and to maintain the level of
electrostatic field below harmful values at the edge of the
right-of-way as shown in Table 0-6.The admissible induced short
circuit current under the line is limited to a maximum of 5 rnA RMS as
recommended by the NESC.
03.2.10 Corona Criteria for Conductor Size
The minimum corona onset voltages of the selected conductor bundle are
1.25 times the rated line to ground voltage as follows:
249 kV for 345 kV lines
379 kV for 525 kV lines
552·kV for 765 kV lines
D3.2.11 Radio and Television Interference:RI and TVI
The noise level at 230 feet from the center line of the line at ground
level is less than that allowable for low residential density areas.
D3-9
25608
TABLE 0-6
All other terrain
At the edge of the line's ROW
Location
Publ ic road
Private road
ELECTROSTATIC FIELD INTENSITY LIMITS
AT 1 METER.ABOVE GROUND
kV/Meter
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04.0 TRANSMISSION DESIGN (HARDWARE)
04.1 GENERAL
The following alternatives were investigated in detail for the Prudhoe
Bay generating scenarios.
For the medium forecast generation alternative:
Two 500 kV transmission line circuits from Prudhoe Bay to Anchorage
and the existing 345 kV Intertie line from Anchorage to Fairbanks
fully extended and operating in parallel with the 500 kV lines.
Two 765 kV line circuits from Prudhoe Bay to Fairbanks and two new
·345 kV line circuits from Fairbanks to Anchorage with the existing
345 kV Intertie in operation as above.
Two +350 kV DC line bipo1es from Prudhoe Bay to Fairbanks and two
new 345 kV line circuit~from Fairbanks to Anchorage with the
existing 345 kV Intertie in operation as above.
For the low forecast generation alternative:
Two 500 kV transmission lines from Prudhoe·Bay to Fairbanks and two
345 kV lines (the extended Intertie and a new line)from Fairbanks
to Anchorage.
Two 345 kV transmission lines from Prudhoe Bay to Anchorage.
The five above alternatives were investigated to select a feasible
solution for economic comparison with the other generation scenarios.
04-1
2560B
04.2 DESIGN DATA OF THE 500 kV TRANSMISSION LINES
A cursory investigation of the 500 kV alternatives was performed to
select the most cost effective design for the transmission line.
04.2.1 Conductor Selection
04.2.1.1 Current Carrying Criteria
The maximum load of the medium forecast transmission is considered to
be 1400 MW.Assuming a 0.93 power factor,the line should be able to
carry 1500 MVA or 1730 A per phase.This current has to be carried by
a single circuit during emergencies.A bundle of two Chukar conductors
and a bundle of three Bunting conductors are compared in Table 0-7,
from which it can be seen that the current carrying capacity is not a
limiting factor for the conductor selection.
04.2.1.2 Acceptable Conductor Gradient
The noise level of the line depends on the electrical gradient.The
size and the number of conductors in the bundle as well as the
clearances determine the maximum gradient.For a bundle of two Chukar
conductors the allowable gradient is 18 kV RMS/cm while for three
Bunting conductors the allowable gradient is 18.8 kV RMS/cm.With
these values the noise level will stay within allowable limits at 230
feet from the centerline of the line.
Maintaining the gradient on the conductor surface under 18 kV rms/cm
will also satisfy the RIV and corona loss requirements for the line.
Using the curves of conductor surface gradients given in the EPRI
Transmission Line Reference Book (EPRI 1982),the surface gradients for
550 kV class are 17 kV/cm for three Bunting and 18 kV/cm for two Chukar
conductors.
04-2
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1 Conductor Bundle
TABLE D-7
AMPACITIES
Current carrying Capacity!!
Amperes
1730
1730
Required capacity
Amperes
2920
3480
1460
11603 x Bunti ng
2 x Chukar
Conductor Type
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Both conductors are acceptable for the proposed 500 kV transmission.
The equivalent cross-sections of the two bundles are 2x1781 =3562 KCM
for the Chukar conductor compared to 3x1993 =3579 KCM for the Bunting
conductor.Consequently,the resistances are practically the same and
the losses will also be nearly the same.
04.2.1.3 Mechanical Design Selection of Conductor,Towers and the
Ruling Span
The selection of long spans results in high towers.Selection of lower
towers on the other hand leads to shorter spans but larger number of
towers.Length of span and height of average tower is established from
preliminary sag and tension calculations.The following assumptions
were made:
Average tower height to the lowest crossarm should not "exceed 100
feet.
Low number of piles per tower for foundations and guys.
Easy shipping of towers to site.
Reduced manpower for construction on site.
The sag and tension calculations for Bunting and Chukar conductors are
shown in Section 07.0 of this Appendix.The calculations were
performed for six ruling spans:"1500,1200,1000,800,600 and 400
feet.The limiting condition for all spans is the 1.5"radial ice load
with 8 1b/sq ft wind pressure.In order to maintain the towers under
100 feet heights,with 13.5 feet long insulator and 38 feet clearance
to ground,the maximum sag must be under 48.5 feet.The maximum sag
for 1000 foot spans with two Chukar conductors is 41.7 feet while with
three Bunting conductors the sag is 56.7 feet.The ruling span of the
line is taken as 1000 feet.The average height of tower,for the
04-4
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Chukar,results in 41.7 +13.5 +38 =93.2 feet or approximately 95
feet;this compares to 108 feet tower"height to lowest crossarm if
Bunting conductors are used.Phase conductors are required to be
equipped with spacer dampers.
It is assumed for cost estimates that one dead end or angle tower is
installed every 10 miles,or roughly 2%of the towers.For the 30 mile
section at Atigun Pass the number of dead end and angle towers is
increased to 8%.
In order to provide work areas for the towers and maintenance areas,
100'x 100'gravel pads are built at each tower site between Prudhoe
Bay and Fairbanks.In addition,300'x 1200'gravel marshalling yards
are built every 18 miles along the Haul Road to permit helicopter work.
04.2.1.4 River Crossings
River crossings along the selected route,except for the Yukon River
crossing,do not raise special problems.The Yukon River will be
crossed downstream of the highway bridge.In this area the south shore
is approximately 300 feet above the water level.A special span of
3,000 feet with two dead end towers and high strength A1 umoweld
conductors is anticipated to permit overhead crossing.
The minimum clearance to high water level is 76 feet for +86°F ambient'
temperature and no wind.At this stage no attempt of optimization of
tower heights or exact location of towers was made.The main problem
is the special conductor that has to be manufactured to obtain the
lowest possible sag under maximum load.The worst loading condition is
during the winter when the conductors are covered with ice.However,
during this period the river is frozen and no barges or boats can pass
under the line.Therefore the minimum clearance to ice level with ice
load on conductors is only 45 feet.
04-5
2560B
The two dead end towers are of lattice type.Installation of
conductors is assumed during the winter when the river is frozen.
Special foundations will be used to avoid movement in the soil due to
pressure and temperature variation at surface.Automatic equipment tq
monitor conductor vibration and settling of towers will be necessary.
Alternatives with two low dead-end and one high tangent tower m~y
result in lower cost;however,for the feasibility level of estimating
the alternative with two high dead end towers is on the conservative
side.The height of the towers depends on the maximum sag of the
conductor.A bundle of two special 61 x 5 strand A1umowe1d conductors
with an ultimate strength of 235,500 lb.,manufactured on special order
by Copperwe1d,is able to carry the maximum current of 1000 A per
conductor.The maximum sag of the conductor for a 3000 foot span with
1.5"radial ice load and 8 1b/sq.-ft.wind pressure is approximately
105 feet.As a resu1 t,the requi red tower heights are 100 feet on the
northern shore and 70 feet on the southern shore.
04.3 DESIGN DATA OF THE 765 kV TRANSMISSION LINE
Following the same procedures as for the 500 kV line,the maximum
current per phase is 1195 A.A bundle of four Martin (1351 KOt1 ACSR)
conductors is able to carry 5000 A.The surface gradient for 800 kV
class conductors from Figure 5.4.34 of the EPRI Transmission Line
Reference Book (EPRI 1982)for a bundle of four Martin conductors is
17.5 kV/cm.The allowable lever for this conductor is 18 kV/cm.
The sag and tension calculation for six ruling spans are given at the
end of this Appendix.The limiting condition for this conductor is the
1.5"radial ice load with 8 1b/sq.ft.wind pressure.The most recent
design of 765 kV James Bay #3 line in Canada uses guyed towers for
special medium design load district and self supporting lattice type
towers for the spec;a1 heavy load di strict.However,Ni agara I~ohawk
Power Company used an H-frame design for their 765 kV line in 1974.
For the reasons of easy shipment and installation as well as simple
04-6
2560B
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foundation of the tubular steel towers,it is assumed that the 765 kV
line is also built on H-frame tubular steel towers.The sag and
tension calculations show that for a 1200 foot span the maximum sag is
61.07 feet.With this sag the height of the average tower results
H =61.07 +19.0 +45 =125.07 feet.With 1000 foot span the maximum
sag is only 42.28 feet and the total height would be 106.28 feet.The
17~decrease in tower height cannot compensate for the 20~i nC.rease in
the numoer of towers.The 1200 foot span is more economical.
Therefore,a 125 foot high tubular steel H tower is selected for the
765 kV line.It is assumed for cost estimating purposes that one dead
end or angle tower is installed each 10 miles or 2.27%of the towers
are dead end types.For the Atigun Pass portion (30 miles)the number
of dead end and angle towers is increased to 8~.
River crossings along the selected route,except the Yukon crossing,do
not raise special problems.The Yukon River will be crossed,similar
to·the 500 kV a1 ternative,near the highway bri dge.The same speci al
A1umowe1d conductor will be used as for the 500 kV line,only instead
of two conductors,a four conductor bundle will be used for each ..
phase.The dead end tower on the northern shore will be about 120 feet
high,and on the southern shore the tower will be 100 feet high.
04.4 DESIGN DATA OF THE +350 kV BIPOLAR DC TRANSMISSION LINE
The HVDC transmission uses two bipolar circuits.The selection of one
large conductor instead of a two conductor bundle reduces the ice load
on the line and the total cost of the line.For cost estimating
purposes it is assumed that the line will have a 1000 foot ruling span
with 90 foot high towers.The selected 2839 KCM conductor is able to
carry the normal 1000 A (700 MW)per bipo1e and 2000 A (1400 MW)per
bipo1e in case of an emergency.The conductor is similar to that used
for the Square Butte DC transmission line.
04-7
2560B
The towers will be of the guyed tubular steel type with a single pole,
except for the dead end towers which will be guyed A frames •
.The DC system is designed ~o not resort to ground return"during anY
conditions.This was necessa~to avoid corrosion of the pipeline due
to stray currents.Grounding of the line is similar to the AC lines
using counterpoise along the ROW.Special attention must be given to
the grounding electrodes on both ends of the transmission.Tests of
stray current magnitude along the transmission must be performed before
line commissioning.
04.5 DESIGN DATA OF THE 345 kV TRANSMISSION LINES
The 345 kV lines were based on the design developed by Commonwealth
Associates for the Anchorage-Fairbanks Intertie under construction.
04.6 SUBSTATIONS AND SWITCHING STATIONS
Several switching stations are required to insure reliable operation of
.the transmission in all AC alternatives.The switching stations must
be able to isolate a fault on any segment of the transmission lines
without affecting the operation of the rest of the system.The
switching stations are built with a breaker and half scheme.The
reliability of the system can be improved if double circuit breaker
arrangements are adopted for the switching stations,because this
prevents the loss of two line segments for a common breaker failure.
The one-line diagram of a typical switching station is shown on Figure
2-5.
04.6.1 Fairbanks Substation
The substation in Fairbanks is an intermediate point for the
transmission system,but it is also handling the power used in the
area.A one-line diagram is shown on Figure 2-6 for the preferred
transmission system.
04-8
2560B
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04.6.2 Anchorage Substation
The one line diagram is shown on Figure 2-8 for the preferred
transmission system.
04.6.3 Series and Parallel Compensation
Series and Parallel compensation is installed in several locations.
Each series compensation bank is built on insulating platforms for the
corresponding voltage and is equippee with full protective systems.
04.7 COMMUNICATION SYSTEM
In order to provide reliable service,a microwave link is proposed.
The number of repeater stations assumed is the same number ALASCOM has
between Prudhoe Bay and Fairbanks.Information received from them,
A1yeska Pipeline,and other sources form the basis of Section 2.2.10.
To provide redundancy for vital functions,a carrier system is also
p1 anned.
04-9
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05.0 SYSTEM DESIGN (LOAD FLOW STUDIES)
05.1 GENERAL
This series of alternatives is concerned with how the Prudhoe Bay,
medium forecast scenario would be integrated into the
Fairbanks-Anchorage system.Many alternatives were investigated,
however,this report contains only those alternatives which proved to
be vi abl e.
It was assumed that the electrical angular displacement between any two
buses should never exceed 45°.This is a rather generous allowance,
which assumes that voltage regulation at those terminal buses will be
sufficient to hold flat voltage schedules.Another criterion that was
used for ~ransmission systems extending from North Slope to Anchorage
was that the electrical displacement between the extreme ends of the
system should not exceed 60°.This is an attempt to limit the amount
of shunt compensation which would be required at Fairbanks and could
possibly be relaxed if extraordina~amounts of regulation were present
at Fairbanks.
It should be recognized that all of these angular criteria are merely
rough approximations.In case of detailed engineering design,the
chosen alternatives must be verified by transient stability studies.
In those cases performance will depend upon the nature of the testing
criteria,the duration of the faults,and the nature of the remedial
action,to determine what angular displacements are acceptable across
the system.
In adding shunt compensation to the system a philosophy had to be
developed.It was assumed in this case that the dynamic compensation
requirements at Fairbanks and Anchorage would best be met by static
compensation of an inductive nature.It was therefore attempted ·to
leave enough line-charging uncompensated on the lines so that all
05-1
2560B
losses during the worst outages would be supplied from the lines
without requiring a positive (capacitive)output from the VAR
compensators at Fairbanks and Anchorage.In the unloaded condition or
the zero generation cases,Anchorage and Fairbanks ~re forced to absorb
rather large amounts of reactive power.These may not be completely
ahsorbed by the VAR compensating devices,but may also be assisted by
switched shunt reactors.Although it was not always possible,there
was an attempt to limit the magnitude of the capacitive output of the
compensators at Fairbanks and Anchorage.
In determining the location of the VAR compensators at Fairbanks and
Anchorage,a compensator shoul d not be lost at the same time as a
critical line would be lost.This necessitates double breaker or
breaker and a half switching at the various stations,and also the
separation of the compensators from the ~tep down transformers at
Anchorage.To do otherwise in Anchorage would result in a common mode
failure potential for a transformer outage,which would remove both a
line and a static compensator from service simultaneously.At
Fairbanks the static compensators may be located on the tertiaries of
the step down transformers since the switching on the EHV bus at
Fairbanks is such that a transformer and a line will not be lost for a
common contingency.However,these details are not shown in the one
line schematics presen.ted in the main body of this report.
05-2
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D5.2 PERFORMANCE STUDIES
D5.2.1 Alternatives A and AA -1400 MW Generation at Prudhoe Bay,Two
500 kV Lines from Prudhoe Bay to Anchorage and the 345 kV
Intertie In Parallel Between Fairbanks and Anchorage
Alternative A was one of the first alternatives considered.It is
shown in Figure D-1 •This alternative consists of two 500 kV circuits
from Prudhoe Bay to Fairbanks and two 500 kV circuits from Fairbanks to
Anchorage.The latter two circuits would operate in parallel with a
345 kV Intertie under construction!!which is presumed to be extended
to both Fairbanks and Anchorage.
The 500 kV circuits are sectiona1ized at two places between the North
Slope'and Fairbanks so that the primary HV segments are approximately
15,0 miles i.n length.Between Fairbanks and Anchorage there is one
intermediate station which would be located ideally at the mid-point of
the system.However,for Alternative A,it is assumed to be 10caterl
at,or near,Gold Creek,which makes the segments approximately 190
miles from Fairbanks to Gold Creek and 140 miles from Gold Creek to
Anchorage.
Alternative A uses 50 percent series compensation for the 500 kV system
in all of .its segments,including terminal transformers.In each of
the six segments between the North Slope and Fairbanks and four
segments between Fairbanks and Anchorage a 200 MVAR shunt reactor has
been provi ded to compensate the 1i ne chargi ng of the system.
There are two transformers rated at 750 MVA at Prudhoe Bay for each
circuit,stepping up the voltage from 138 to 500 kV.A 1500 MVA
l/·Construction of the 345 kV 1ine is to begin in the spring of 19a3
with completion expected by the fall of 1984.
D5-3
2560B
transfonner cannot be used on one circuit because it would provide
excessively high current duties on 138 kV switchgear,but two banks in
parallel on each of the two circuits provide acceptable circuit breaker
and bus duties.The same configuration is maintained in·Anchorage.
However,the transformers there are sized 500 MVA each because of the
lower loadings expected at that point.Transfonnation is arso provided
at Fairbanks from 500 to 138 kV to serve the local loads at Fairbanks
and to connect to th~Intertie,which would consist of 500 to 138 kV
and 138 to 345 kV transfonnation.The transfonnation at Fairbanks
provides double transformation between the 500 kV and the 345 kV
systems.However,this is believed to be less expensive than providing
direct transformation from 500 to 345 kV.The 345 kV circuit,when
operating in parallel with the two 500 kV circuits,does not provide
significant support,so it is not.a critical support element in the
system.
The transfonners at Fairbanks are sized at 500 MVA each,even though
the load at Fairbanks is expected to be only about 250 MW.The extra
transfonner capaci ty is pro v;ded both to a 11 ow for through-flows
through the 345 kV system and to allow use of the transfonners at
Fairbanks for connection of a static VAR system or synchronous
condensers on their tertiaries.
The system of Alternative A was not directly tested for load flow.
However,a similar system,Alternative AA,was tested and is shown in
Figure 0-2.The difference between Alternative A and AA is that in
Alternative AA switching at North Slope and Anchorage was assumed to be
at 345 kV rather than 138 kV,but it turned out to be more expensive
than A1 ternati ve A•.However,performances of these two a1 ternati ves
are Quite similar.
Figure 0-3 shows Case AA1,where there is no generation at North Slope
and the system is unloaded;this,therefore,represents an extreme case
~where the line c~~~f the transmission system has to be absorbed
--~~.~"by the static compensators at Fairbanks and Anchorage.The reactive
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power absorbed is shown on the Fairbanks and Anchorage 345 kV buses.
In Alternative A they would be on the 138 kV bus or on the tertiaries
of the 500 to 138 kV transfonmers.The difference is rather
insignificant in the overall picture.Case AA1 shows that the system
north of Fairbanks produces about 262 MVAR of excess line charging and
the location of the shunt reactor and the series capacitors have been .
arranged so that the vol tage at North Slope is at the bottom end of its
possible range.This allows for a maximum voltage rise in the event
there are reactor failures or circuit outages.The voltage at North
Slope for this configuration is approximately 95%of nonmal,whereas
the voltage at Fairbanks is 102%.The locations of the shunt reactors
between Fairbanks and North Slope have been arranged in such a manner
that it produces the lowest possible voltage at North Slope.This is
ideal from the point of view of energizing the system from Fairbanks.
However,the arrangement may have to be"modified if the system is to be
energized initially from the North Slope end.The kind of modification
expected might be to relocate the shunt reactors from the northern ends
of their segments to the southern ends in one or more of the sections,
which would tend to ~eve10p a more·ba1anced voltage profile along the
.1ines.The configuration shown in Alternative AA,however,is that
which would give the lowest possible voltages on the 500 kV system
north of Fairbanks for contingencies involving outages of reactors or
segments when the system is only connected to Fairbanks.For the
ci rcui ts of the system south of Fai rbanks,reacti ve compensati on i's.not
particularly critical,since both Fairbanks and Anchorage are asssumed
to have substantial voltage regulating capabilities.In this case,
Fairbanks is required to absorb 242 MVAR of 1i ne charging and Anchorage
is forced to absorb 346 MVAR of line charging.This balance can be
changed by modification of transfonmer taps at Anchorage.However,as
shown in Figure 0-3,this system is designed so that Anchorage absorbs
the maximum amount of reactive power at no load,but it will be lightly
loaded when full power is being delivered.This is more compatible
witp the use of static compensators with inductive capabilities than
with synchronous condensers.
05-5
25608
The compensation of the 345 kY Intertie between Fairbanks and Anchorage
is not known exactly at thi s point;it ;s assumed that six 35 MYAR
reactors are on the line.The six reactors,shown in a later case,
appear to give a reasonable amount of compensation,and should not have
any significant effect on the conclusions regarding the remainder of
the 500 kY system.
The system was tested at no generati on to insure that it has enough
strength for energization and failures of components.Case AA2,Figure
0-4,for instance,shows a case where,at Fairbanks,a circuit breaker
on one of the 500 kY lines to the north would be open.The intent was
to see how high the voltage at the Fairbanks end of the transmission
line would go.In this case it goes up to 107%of normal voltage,
which is certainly well within the.capabilities of.the equipment
installed.The outage of this segment interrupts the major reactive
power flow and one could expect that the voltages at the far end'of the
system would also rise.In this case they went up to only 97%from
their system normal value of 94.6%.This is a relatively insignificant
voltage rise at the North Slope and the voltage rise at the Fairbanks
end of tne line is quite acceptable.
Opening of the Gold Creek end of the Fairbanks-Gold Creek Line segment
,is shown as Case AA3 in Figure 0-5.This being the 1.ongest segment,it
is believed to be a possible critical case for voltage rise.However,
all voltages are acceptable.The series capacitors at Fairbanks tend
to keep the voltage levels down because of the reactive flow from the
1ine to Fairbanks through the series capacitors.
Case AA4 in Figure 0-6 shows a double contingency,with a Fairbanks to
Gold Creek line segment open at Gold Creek and the shunt reactor
located on the line removed.The voltage increased in this case to
approximately 109%of normal.This is still acceptable.
An outage designed to test the suitability of the shunt compensation of
the 345 kY intertie is Case AA5,shown in Figure 0-7.This case
05-6
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represents a condi tion where the breaker at the Anchorage end is open.
The voltage rose to 10~which is considered to be ~cceptab1e.However
the amount of compensation is not sufficiently great that the loss of a
reactor in addition to the open ended line could be tolerated.This is
shown in case AA6,Figure 0-8,where the voltage level reaches 115%.
It can be concluded,therefore,that the amount of shunt compensation
on the 345 kV system as modelled was reasonable although it could
undergo some fine tuning.
Case AA7,shown in Figure 0-9,is another test to determine the
adequacy of the shunt compensation of the system and the location of
the shunt reactors.It shows an outage of the line from North Slope to
the first intermediate station which in this case is termed GL 500.
The voltage rise at both North Slope and the GL 500 end of the open
ended line is reasonable.
Case AAB,Figure 0-10,takes the preceding outage one contigency level
further by removing the shunt reactor on the open ended line.In this
case the voltage reached 110%which,again,should be acceptable.If a
modification were made to allow the system to be energized initially
from the North Slope end,the initial voltages at North Slope would be
higher than the 98%shown in Figure 0-3.In that case a higher amount
of shunt compensation might be required to keep voltages down to the
110%shown in Case AA8.The additional compensation ~ould be installed
in the intermediate switching station,rather than on the line and
could be viewed as switched spare reactors.
Case AA9,shown in Figure 0-11,deals with 1400 MW generation at the
North Slope.It is assumed that the power is divided between Fairbanks
and Anchorage with Fairbanks getting 250 MW and Anchorage getting the
remainder less losses.In Case AA9 the full load line losses are
approxmate1y 77 MW or roughly 5%of the total power generated.Case
AA9 shows electrical angular displacements between the generation-at
North Slope and Anchorage of 43 degrees.This appears to be acceptable
provided that ther.e is a substantial voltage support in Fairbanks which
05-725608.
is assumed for this case.In Case AA9 the North Slope generation
voltage schedule has been assumed to be 10~higher than the voltage
scheduled with no generation in service.This 10~swing on the
generator bus tends to maximize the reactive power output of the North
--
Slope generation and to minimize the swing required by the voltage
regulation at Fairbanks and Anchorage.In this case Anchorage absorbs
only 69 MVAR and ~airbanks absorbs 95 MVAR.With 1400 MW generation
both Fairbanks and Anchorage are lightly loaded with reactive power
because the generation is required to put out the most reactive power.
Voltages across the system are all quite reasonable,with the possi,b1e
exception of the intermediate switching station at Gold Creek,which is
down to about 94~and may require some shifting of the shunt reactor
locations to bring that up.
Figure 0-12 shows Case AA10 which represents one of the critical
outages of the system with one line segment north of Fairbanks out of
service.The most significant factor to note is the e1 ectrical ang1 e
across the system which increased from the 43 degrees of Case AA9 to
50.7-degrees.Though this seems to be a rather wide angular swing,it
is tolerable considering the voltage support provided at Fairbanks.
Voltages along the 500 kV system are all acceptable.Thereactive
power swing at Fairbanks is also reasonable;it is now a positive 60
MVAR instead of a negative 95 MVAR as it is in Case AA9.This is an
acceptable outage case.
Case AA11,shown in Figure 0-13,appears to be slightly more severe
that the previous case.The loss of a line segment between the North
Slope and the first intermediate sWitching station causes a slightly
higher impedance increase on the system.The electrical angle across
the system i~now 55.6 degrees,rather than the 50.7 degrees of Case
AA10.This,therefore,is probably the most severe outage to the
system.Even in this case,however,voltages are quite acceptable
across the system.The voltages at the intermediate stations are down
around 94 to 96~,but that is tolerable.The reactive output at North
05-8
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Slope is on the order of 90%power factor,which would tend to
determine the reactive rating of the generators.The reactive output
at Fairbanks is also moderate'with 88 MVAR,and Anchorage essentially
floats.So the original intention to have Anchorage absorbing on the
order of 350 MVAR appears to be well designed.
In Case AA12 of ~igure D-14 the outage of the Fairbanks Gold Creek line
segment is modelled.This case was run to see if it would compete in
severity with the outage of the line segment between the North Slope
and the first switching station.This contingency turns out to be less
severe because the electrical angle across the system is 49.5 degrees
which is less than the 55.6 degrees of Case AA11.Therefore it is of
no concern if Gold Creek is selected rather than a point eocactly
halfway between Fairbanks and Anchorage.This case also demonstrates
the potential magnitude of throughflow on the 345 kV Intertie.In this
case the intertie carries only l84MW between Fairbanks and Anchorage.
The 500 kV line segment remaining in service with its 50 percent series
compensation is much more significant as it carries 930 MW.Therefore,
whether or not the 345 kV intertie is in service is not a prime
consideration with this alternative.The loadings on the transformers
at Fairbanks are also quite acceptable,being only on the order of 217
MyA per DanK.Therefore,the bank size of 500 MVA is more than
adequate to handle the through flow.It could probably even handle an
outage of one of the transformers at Fairbanks in addition to this line
outage,and still stay within the 500MVA rating.Case AA12 represents
a condi ti on which produces the highest reactive output requi rement in'
Anchorage,in this case 81 MVAR.
Case AA13 deals with an outage of the Anchorage-Gold Creek line.It is
shown in Figure D-15 and appears to have approximately the same
severity as an outage at the Gold Creek-Fairbanks line,even though it
is shorter,because in this case the impedance of the step down
transformers is included with the line which is equivalent to an
increase in the length of·the line.The electrical angle across the
D5-9
2560B
system,however,is only 48.7 degrees and therefore the situation is
not as severe as an outage of any of the segments between the North
Slope and Fairbanks.
Case AA14 again is designed to test the effects of throughf10ws on the
345 kV system and·is shown in Figure 0-16.In this case,an outage of
one of the transformers at Fairbanks would load the remaining
transformer to 71%of its 500 MVA rating,indicating that the 500 MVA
rating is reasonable for these transformers.
Referring back to Case AA12,the increase in loading on the 345 kV
intertie for an outage on the Gold Creek-Fairbanks 500 line was on the
order of 60 MW.If this increase of 60 MW is added to Case AA14,the
loading on tile remaining bank would just be over 400 MW.This
demonstrates again that the sizing of the banks at 500 MVA is
sufficient to withstand the loss of even one bank and one-line between
Fairbanks and Gold Creek.
The previous case studies show that the Intertie1s presence or absence
does not appear to have a major impact on loadings across the system.
As a result,this alternative is overbuilt.Therefore sUbsequent
alternatives attempted to use weaker system configurations between
Fairbanks and Anchorage,such as two new 345 kV circuits,'instead of
the two 500 kV circuits,in addition to the Intertie under construction.
05.2.2 Alternative B -1400 MW Generation at Prudhoe Bay,Two 500 kV
Lines Between Prudhoe Bay and Fairbanks and Three 345 kV Lines
Between Fairbanks and Anchorage
The basic configuration of Alternative B is shown in Figure 0-17.This
alternative differs from Alternative A in that three 345 kV circuits
between FairDanks are substituted for the one 345 kV and two 500 kV
circuits of Alternative A.Alternative B therefore has switching at
Fairbanks at the 345 kV level and requires transformation at Fairbanks
05-10
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to step up to the 500 kV level used for the lines north of Fairbanks.
It also incorporates 345 to 138 kV transformation at Fairbanks purely
to serve the local area loads and to incorporate the reactive power
compensation of the system required at Fairbanks.Also shown is 345 to
138 kV transformation at Anchorage.Therefore,138 kV is present at
the Nortn Slope,Fairbanks,and Anchorage.
The 345 kV 1ines are 50 percent series compensated.The 50 percent
includes the impedance of the step down transformers when they are part
of the line switching,similarly to the previous alternative.The
shunt compensation of Alternative B on the 500 kV portion is identical
to that of Alternative A.The 345 kV lines,however,require less
shunt compensation since they produce less line charging.In this case
it is·assumed that each of the six line segments between Fairbanks and
Anchorage have one 75 MVAR shunt reactor attached to it.
The transformers in Alternative B are sized at 1500 MVA,or two 750
MVA,on each of the circuits from the North Slope to Fairbanks.Two
400 MVA transformers step down the voltage to 138 kV.The 400 MVA size
is selected because,in the absence of any through-flow problems,the
transformers are used to serve the local load.The three transformers
at Anchorage are sized at 600 MVA each,to allow 1200 MVA capability
remain even after the outage of one circuit.This is essentially the
same capability that remained in Alternative A with the loss of one 500
kV circuit between Fairbanks and Anchorage.
The intermediate switching station between Fairbanks and Anchorage is
assumed to be approximately half w~between the two cities,since a
190 mile long 345 kV line segment,which would result from a Gold Creek
location,might not be acceptable for this configuration.
Case Bl of Figure D-18 is a no generation case with no outages.The
attempt here is to duplicate the v.oltage profile of earlier
alternatives,so the voltages are approximately 95~at the North Slope
and about 102~at Fairbanks.It was also attempted to absorb as much
D5-11
2560B
reactive power as possible at Anchorage and to minimize the absorption
at Fairbanks.It turned out to bea success by 444 MVAR being absorbed
at Anchorage and 191 MVAR at Fairbanks.Voltages all across the system
are satisfactory.
Case 82 shows 1400 MW generation at North Slope.Conditions between
North Slope and Fairbanks are quite similar to those in Alternative A.
8etween Fairbanks and.Anchorage power flows are evenly distributed on
the three 345 kV lines since they are now equally series compensated.
Voltages along the system are also acceptable.The reactive absorption
as in the previous cases,is low,being down to 43 MVAR at Anchorage
and 64 MVAR at Fairbanks.The angular difference across the system is
47.4 degrees,compared to 43 degrees in Alternative AA.Therefore,the
e1 ectri cal conditions .are quite simi1 ar to those of A1 ternati ve AA.
This case is shpwn in Figure 0-19.
Figure 0-20 is labeled Case 83 and was run to show the effect of
changing the voltage schedule at the North Slope generator bus.In
this case the voltage was raised only 5%over the'no load case,instead
of 10%as in Case 82.That reduced the reactive output of the North
Slope generation by 97 MVAR.However,in doing so the reactive output
at Fairbanks had to increase by 105 MVAR and reactive output at
Anchorage increased by 45 MVAR.Therefore,it is highly desirable to
hold the highest possible operating voltage and the peak-to-off-peak
voltage differential at the North Slope to minimize the dynamic
reacti ve power requi rements of other pa rts of the system.
Case 84 (Figure 0-21)is quite similar to Case AAll of Alternative AA.
In either case it is an outage of the line from the North Slope to the
first intermediate switching station.In this case the electrical
displacement across the system is 58.7 degrees instead of 55.6.This
alternative,therefore,has only a slightly higher transfer impedance
between the North Slope and Anchorage than Alternative AA.The loading
on the one remaining circuit between the North Slope and the first
05-12
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intenmediate station is approximately 15 per unit current.Therefore,
all the facil ities on each of the 500 kV ci rcuits were sized at 1500
MVA.
Case B5 was investigated to measure once more the sensitivity of the
system to changes in voltage at Prud.hoe Bay.In this case,as is shown
in Figure 0-22,lowering the voltage by 5%during the outage reduced
the reactive output of the generator by only 57 MVAR,but Fai rbanks and
Anchorage must increase their outputs by 98 MVAR and 41 MVAR,
respectively.So again,this demonstrates that the voltage should be
held as high as possible at the North Slope,even during outage
condi ti ons.
Figure 0-23 shows Case B6 which represents an outage of one of the
three 345 kV circuits from the midpoint switching station to
Anchorage.The electrical displacement across the system is only 52.8
degrees thi s time.Therefore,it is significantly less severe than an
outage of one of the 500 kV circuits in Figure 0-15.Loadings on the
remaining two circuits in parallel are on the order of 520 MVA,
therefore they are within the 600 MVA capabilities that were assumed
for the transfonmers at the ends of the lines.Voltages are quite
acceptable.The reactive output requirement at Anchorage is 111 MVAR,
which is as high as it becomes for any contingency.
05.2.3 Alternative C -1400 MW Generation at Prudhoe Bay,Two 765 kV
Lines Between Prudhoe Bay and Fairbanks and Three 345 kV Lines
Between Fairbanks and Anchorage
Alternative C differs from Alternative B in that 765 kV is'used north
of Fairbanks.It is displayed in Figure 0-24.Instead of having two
500 kV series compensated circuits in parallel,it has two 765 IcV
circuits without series compensation.The impedances are on the same
order of magnitude as those.on the 10we~voltage circuits.One major
difference,though,is that the line charging of the 765 kV circuits is
sUbstantially higher than that of the 500 kV circuits.In Alternative
Ca ve~high degree of shunt compensation is required.In this case
05-13
2560B
660 MVAR of shunt reactors are placed at each 150 mile segment of the
765 kV line.The line charging from each of these segments is
approximately 700 MVAR.Therefore the 660 MVAR represents about 94~
shunt compensation of the lines •.Changes in net reactiv~output could
prove to be a problem if the frequency of the system should deviate
significantly from 60 Hertz.Other'than the higher voltage,the
circuiting is identical to that of Alternative 8.The transfonmers at
the North Slope remain at 750 MVA,each having two paralleled on each
circuit in the same manner as they were in the 500 kV alternative,and
the transfonmers at Fairbanks on the lines to the north also remain at
1500 MVA.
The shunt reactors have been located to lower the voltage as much as
possible at the North Slope.The shunt reactor compensation
requirements are large,and it is impossible to supply all the shunt
reactive requirements of the line segments in one location with
excessive open end voltages.Therefore,three 220 MVAR reactors are
connected to each line segment,with two of them being located at the
northern ends and one at the southern ends,to attempt a voltage
decrease from Fairbanks as the lines go north.
One of the great advantages of this alternative,in addition to reduced
losses,is that it does -not require series compensation on the 76~kV--.
lines.This could be important in view of the long maintenance times,
high maintenance cost and relatively low reliability record of such
series capacitors.Therefore,at detailed feasibi1ity-engineering
studies this alternative has to be considered.
Alternative C,Case C1 (Figure 0-25)is a no generation case comparable
to Case 81 of A1 ternati ve 8.The net 1i ne chargi ng output of the
circuitry north of Fairbanks is approximately 260 MVAR as it was in
Case 81.However,the absence of the series capacitor compensation in
the line makes it difficult to obtain the same voltage profile that was
obtainable in Alternative 8.In this case the voltage at North Slope
can be brought down only to 1.013 per unit with the distribution
05-14
25608
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of the shunt reactors as shown.Alternatives with series capacitors
could give more flexibility to obtain the desired voltage profile by
adjusting the location of the series capacitor compensation.Other
than this the voltage profiles across the system are quite similar to
those of Alternative B.
Case C2 (Figure 0-26)shows 1400 MW generation at the North Slope.The
voltage level at the generator bus was raised by 10%as it was in
previous cases.However,this appears to result in exce$sivel~high
voltages on both the 765 kV system and on the 138 kV bus at Prudhoe
Bay.Therefore,the 765 kV alternative may be more difficult to
optimize in tenns of producing maximum reactive output at the North
Slope.The voltage levels on the 138 kV bus are relatively easy to
clear up by changing the taps on the generator step up banks and the
765/138 kV banks.However,the voltage level of 1.069 on the 765 kV
line is probably excessive unless transfonners with higher rated
voltages are purchased.Therefore it may not be possible to raise the
voltage 10%from no load to full load with the 765 kV alternative
unless some further optimization of the shunt reactor locations can be
made.The electrical angular displacement across the system is
approximately 45 degrees which is again comparable to the other
alternatives that have been looked at so far.The reactive loading at
Anchorage is low,as it was in the other alternatives;at Fairbanks
approximately 154 MVAR would have to be absorbed.Line losses are only
75 MW,which is 35 lower than 'Alternative B.
Case C3,in Figure 0-27,shows an outage of the 765 kV circuit between
the North Slope and the first intennediate station.As in Alternative
B the electrical angle across the system is in the mid 50 degree range,
in this case 56.1 degrees,Therefore,it perfonns in quite a similar
fashion to that of the 500 kV system.For this case one should note
that the reactive output of Fairbanks and Anchorage is essentially
zero,This indicates that shunt compensation levels on the lines are
appropriate,if the North Slope voltage level can be maintained.
05-15
2560B
D5.2.4 Alternative D-1400 MW Generation at Prudhoe Bay,Two Bipolar
+350 kV DC Lines Between Prudhoe Bay and Fairbanks and Three
345 kV Lines Between Fairbanks and Anchorage
Alternative D is designed to carry 1400 MW from the North Slope to
Fairbanks using HVDC transmission.The inverter station,at Fairbanks,
converts DC to AC.From Fairbanks to Anchorage the transmission is at
345 kV AC.The DC performance and an AC perfonmance of the system can
be treated separately in the given configuration.The following
sections first describe the DC portion of the system followed by that
of the AC system portion.
D5.2.4.1 Description of the System
The system schematic is shown in Figure D-28.
A prima~design criteria for the DC system is system reliability.It
was concluded that a system of two bipoles would provide perfonmance
comparable to that of two AC circuits.
There are other compelling reasons why the two bipo1e arrangement is
better for the Prudhoe Bay to Anchorage transmission rather than a
system which has one bipole and is in monopolar operating mode during a
contingency.The main reason is to avoid potential problems with
ground return current flow in the TAPS line.In case of two bipoles
each one can be carefully balanced to assure that no DC current flows
in the ground.If only a monopolar DC line remains after an outage,
the·full DC return current would have to flow in the ground.That
current wou1 d be twice the operati ng current for the requi red power
level.Currents always t~to find the path of least resistance and
the pipeline provides an excellent means to provide a good path between
Prudhoe Bay and Fairbanks.Such currents would have destructive
effects on the pipeline and its operation.
D5-16
2560B
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The voltage to be selected for the DC system is a variable which can be
changed to meet a minimum cost criterion.Our calculations indicate
that a voltage level of approximately +350 kV on each bipole and
designed to carry normally 700 MW on each bipo1e is close to optimum,
and was,therefore,used in this developme"nt.The reliability
criterion applied was that either bipo1e should be able to carry the
entire 1400 MW.This,plus the influence of normal line loss
considerations,determine the approximate conductor size to be used on
each bipole.
Sizing the converter poles at each terminal is an independent
decision.In this case it is assumed that each of the four poles would
have a converter with 33%of full load capability.Thus one of the
four converters could be lost and still maintain full power transfer.
It can be assumed that the valves have 10%emergency capability,which
can be used in the event of a converter"outage.Thus each pole is
rated at 467 MW in an emergency,so that three of them would have a
total rating of 1400 MW in normal operation.This results in a
converter normal rating of 425 MW per pole,which was used for pricing
purposes.
These ratings apply to the converter/rectifier terminal at the North
Slope.The vol tage and power rati ngs of the converter poles at the
inverter terminal at Fairbanks are slightly lower because line losses,
normally amounting to some 6%,are dis~ipated in the DC tr~nsmission
system.The ratings of the converters at Fairbanks are assumed to be
400 MW normal and 440 MW emergency per converter pole,thus allowing up
to 1200MW to be inverted during one converter pole outage at
Fairbanks.Because higher than normal line losses occur during such a
contingency,the rectifier terminal and generator capabilities would
1imit rather than the inverter.
A major design consideration for the inverter is providing adequate
short circuit levels to enable commutation of the inverters.This is a
major problem for "the DC alternative,since much of the generation in
D5-17
2560B
Fairbanks and Anchorage will be decOlllDissioned by the time the Prudhoe
Bay generation is operating.For this case it is assumed that the
system would be very weak in the absence of local generation and it is
necessary therefore to add a large amount of synchronous condenser
capacity at Fairbanks to supply an adequate short circuit level.'It is
generally regarded that a short circuit level approximately 2 1/2 times
the DC 'power inverted is the minimum acceptable level of system
strength.At Fairbanks it is assumed that with much of the generation
shut down the short circuit level might be as low as 200 MVAR on the
system without augmentation by condensers.Therefore,the additional
short circuit level required was on the order of 3125 MVAR.This would
be supplied by synchronous condensers,which are assumed to have
transient impedances of 40%on their own base and connected to the
system with transformers having 5%impedances,a1 so on thei r own
base.Thus each MVA of condenser would be able to supply 1/0.45 or
2.22 MVA of short circuit capacity.To raise the system capacity by
3125 MVAR would therefore require 3125/2.22 or 1406 MVAR of synchronous
condensers,or approximately the same capacity as the inverter termi na1
is required to convert.
To connect the 1400 MVAR of synchronous condensers to the system,each
of the converter poles could conveniently have two converter
transformers (about 250 MVA each)associated with it,therefore there
are 8 converter transformers available for connecting the synchronous
condensers.If all 8 transformers have condensers on them,each of the
condensers would have to be rated at approximately 234 MVAR to tolerate
the outage of two condensers and still maintain adequate short circuit
levels.The 234 MVAR rating for the condensers is excessive in light
of the fact that the largest hydrogen-cooled condensers in the world
are 250 MVAR and gave unsatisfactory performance on the AEP system.
Also,the 234 MVAR rating would significantly influence converter
transformer sizing.
It should be noted that the assumption of the outage of two condensers
out of 8 amounts to a 25%outage rate.Hydro-Quebec concluded that a
05-18
25608
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30%reserve of condensers is needed on their system to meet an
acceptable level of availability.To counteract both the large number
of condensers and the poor availability,a second iteration on the
condensers was attempted.In this case,the tertiaries of the two
345/138 kV transfonners are also used to connect the condensers.This
allows 10 condensers to be in service and,planning for an outage of
two,allowed a rating of 176 MVAR per condenser to be used.This is a
more satisfactory arrangement.Alternatively,a rating of 195 MVAR
each would allow the loss of three condensers.Such refinements must
also depend upon more accurate detennination of condenser impedances
and short circuit contributions from other sources.
Although the synchronous condenser capacity installed at Fairbanks must
be on the order of 1750 MVA,the reactive power requirements of the...
converters themselves is on the order of 800 MVAR,with about half of
that provided by filters.Thus there is a substantial reactive power
capability in excess of that required by the converters at Fairbanks
which becomes available to control voltages on the AC system south of
Fairbanks.
The description is as follows.
The AC system south of Fairbanks consists of three 345 kV circuits with
one inte,nnediate switching station.Because the transient s1:ability
problems of this system are substantially less severe than that of the
other completely AC transmission system,series compensation is not
necessary for this portion of the system.The transmission
requirements are those of a power plant located at Fairbanks shipping
power to Anchorage.Therefore,a larger angular displacement can be
allowed between Fairbanks and Anchorage.
The AC line south of Fairbanks is compensated by shunt reactors in the
same way as Alternative 8 using 75 MVAR reactors on each of the six
line sectors.A description of the DC system operation is rather
trivial,hence the analysis shown in the following figures concentrates
on the AC system.
05-19
2560B
05.2.4.2 Performance Studies
Figure 0-29 displays case 01 showing the AC system with no power
transfer between Anchorage and Fairbanks.It represents either zero
generation at the North Slope or no more generation than is consumed by
the load of the Fairbanks are~.The excess line charging'of the AC
system is absorbed at Fairbanks and Anchorage.Fairbanks absorbs 107
MVAR and Anchorage absorbs 281 MVAR.It is assumed that Anchorage has
three static compensator systems.Each of the three static VAR systems
in Anchorage is sized at -100 to +200 MVAR.This represents the
addition of one static compensator system more than has been used in
Alternatives A,Band C.It also reflects the fact that series
compensation is not used in the AC portion of the transmission system
and,therefore,the changes in reactive line losses are greater during
outages and during load swings.
This approach of using more dynamic shunt compensation and no series
compensation was a natural outgrowth of the presence of the enormous
amount of reactive capacity available at Fairbanks.Therefore,this
approach appears to be more economical than to continue to use series
compensati on.
Case 02 shows full load generation at Prudhoe Bay (Figure 0-30),which
would result in approximately 1330 MW being inverted at Fairbanks.
This amount of power,less the Fairbanks load,is shipped from
Fairbanks to Anchorage (1080 MW).Voltage levels on the 345 kV system
are acceptable;however,Anchorage is forced to output 133 MVAR to
sustain its voltage level.It should be noted that the reactive power
swing from no load to full load at Anchorage is 464 MVAR.This,again,
is an indication of the effect of the omission of series capacitors and
indicates the approximate range of the dynamic reactive p·ower source
requi red at Anchorage.
Case 03,in Figure 0-31,shows an outage of one of the three circuits
between Anchorage and the mid-point switching station.It is the most
05-20
2560B
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severe outage of the AC system which can affect this alternative.It
increases the reactive power requirements at Anchorage from 183 to 405
MVAR.Thi"s outage agai n shows the 1arge increase in reacti ve power
losses caused because of the omission of series compensation.The 405
MVAR output of the condensor represents an increase of 686 MVAR over
the output of the same compensation system at no load.Also,the
~lectrica1 angular displacement across the system is increased to a
considerable 53°by this outage.However,when the DC power is fully
controlled,as it is in this alternative,transient stability concerns
on the AC system are substantially less important than they are in
conventional power systems,therefore a larger angular displacement can
be allowed in steady state.
Case 04,in Figure D-32,shows the effect of raising the voltage level
at Fairbanks by 5%at full load,as compared to the zero generation·
case.The net effect of this is the reduction of the reactive power
output of the static compensation system at Anchorage by 109 MVAR.
Case 05 (Figure D-33)shows the effect of a 5%voltage increase at
Fairbanks for the same contingency that was discussed as Case 03.In
this case the reactive power output at Anchorage is reduced from 405
MVAR to 298 MVAR,corresponding to a change of 107 MVAR.This appears
to be a desirable operating procedure because it reduces the magnitude
of the reactive power'requirements at Anchorage.It also has a
beneficial impact on the angular displacement across the system,
because the displacement is now only 50°instead of 53°.Raising the
voltage schedule at Fairbanks by 5%increases the reactive demands on
the'synchronous condensers at Fairbanks.In this case the AC system
lines require 332 MVAR.The demands of the converter terminals are on
the order of 800 MVAR,however,apprOXimately half of that would be
suppli ed by the fil terse Therefore,the total condenser 1o.adi ng at
Fairbanks for this case would be 732 MVAR plus whatever reactive demand
is present in the Fairbanks area.Since the condensers have a rating
in excess of 1700 MVAR,there is no need in this alternative to correct
the power factor of the load of Fairbanks.
05-21
25608
05.2.5 Alternative E -700 MW Generation at Prudhoe Bay,Two 345 kV
Lines from Prudhoe Bay to Anchorage
A1 ternative E provi des transmi ssi on for 700 MW of generation at the
North Slope.The system,as shown in Figure 0-34,consists of two 345
kV circuits north of Fairbanks with two intennediate switching
stations.The 345 kV circuits,including their tenninating
transfonners,are 5~seri es compensated.The system south of
Fairbanks also has two 345 kV circuits with one intennediate switching
station.It,too,is given 5~series compensation.Shunt
compensation is also provided on each of the circuits.The 150 mile
long segments north of Fairbanks have 100 MVAR shunt reactors and the
165 mile segments south of Fairbanks have 75 MVAR shunt reactors.In
this alternative,it is assumed to have dynamic ~eactive power
regu1 ati on at both Fai rbanks and Anchorage.At each station it is
assumed that there are two devices with -10OMVAR to +10OMVAR ranges.
For light load conditions this range would have to be supplemented by
additional switched reactors at each station and at the other
intennediate stations.
Case E1 shows the system energized with no generation at the North
Slope Figure 0-35.With the shunt reactors located at the northern
ends of all the circuits,a voltage level of about 94%is obtained at
the North Slope,which appears to be satisfacto~.The.exce~~line
charging is absorbed at Fairbanks and Anchorage,with Fairbanks taking
119 MVAR and Anchorage taking 277 MVAR.
Figure 0-36 shows case E2 which represents a no generation case,with
the line between Fairbanks and the first intennediate station north of
Fairbanks open at the Fairbanks end.Voltage levels on the open-ended
circuit are acceptable.
Case E3 goes further by one more contingency level.It removes the
shunt reactor from the line as well as open-ending it at Fairbanks
05-22
2560B
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(Figure 0-37).The voltage reaches a level of 111~at the Fairbanks
open end of the line;the North Slope voltage level has risen to only
102%,both are acceptable.
Case E4 represents Alternative E with 700 MW of generation at the North
Slope.Full load losses on the lines are 67.3 MW.The voltage
schedule at the North Slope has been raised by l~from the zero
generation case as can be seen on Figure 0-38.Voltage profiles across
the system are all near unity and are acceptable.Line charging has
been consumed to a great extent by the line losses.This is also
indicated by the loading of the reactive power sources at Fairbanks and
Anchorage which are required to absorb only 48 and 113 MVAR,
respectively.
Case E5 shows the worst outage for this alternative (Figure 0-39),
namely the loss of one line segment between Prudhoe Bay and the first
intermediate station.Line losses increase to 85.7 MW and voltage at
the first intermediate station drops to 95~.In other respects,the
system performs quite acceptably,the electrical displacement across
the system is 52°which,again,though on the high side,is still
acceptable.
05.2.6 Alternative F -700 MW Generation at Prudhoe Bay,Two 500 kV
Lines Between Prudhoe Bay and Fairbanks and Two 345 kV Lines
Between Fairbanks and Anchorage
Alternative F also provides a transmission system for 700 MW of
generation at the North Slope.The system shown in Figure 0-40
consists of two 500 kV circuits with two intermediate switching
stations,but without series compensation,between Prudhoe Bay and
Fairbanks.South of Fairbanks it is the same as Alternative E,with
two 345 kV circuits,one intermedi~te switching station,and 5~series
compensation of the lines and corresponding terminating transformers.
Reactive shunt compensation is provided on the circuits north of
Fairbanks in the amount of 200 MVAR for each of the circuits.South of
05-23
25608
Fairbanks the same 75 MVAR shunt reactors are provided on the 345 kV
circuits.Only the 345 kV lines are series compensated.At Fairbanks
two static VAR systems with ranges of +100 MVAR are provided and the
same is provided at Anchorage.At Fairbanks the reactive devices may
be locate~on the tertiaries of the 400 MVA transformers.At Anchorage
the reactive devices are located on the 138 kV bus to avoid their loss
if an outage of the 345 to 138 kV transformers occurs.
Alternative F at zero generation is shown in case F1 (Figure 0-41).
The voltage profile across the system from Fairbanks to North Slope is
reasonably flat.The same is true for the profile between Fairbanks
and Anchorage.The excess line charging is absorbed at Fairbanks and
Anchorage with Fairbanks taking 216 MVAR and Anchorage taking 303
MVAR.These amounts can be changed by varying the tap settings on the
transformers at Anchorage.
Case F2 shows 700 MW of generation at the North Slope.The voltage
schedule on the generation has been increased only 5%because of the
al ready hi gh no-load voltage as c an be seen 0 n Fi gure 0-42.Lo sses are
35.7 MW on the lines.The voltage profiles are all acceptable across
the system.The reactive power absorbed at Fairbanks and Anchorage has
been reduced to 123 MVAR and 121 MVAR,respecti vely.The electrical
angular displacement across the system is 45.40,which is acceptable.
Case F3 (Figure 0-43)shows an outage of one of the circuits between
the North Slope and the first intermediate switching station.It
results in a 60°electrical angle across the system and 45°electrical
displacement between Fairbanks and North Slope.This can be regarded
as the upper limit.It should be noted that the reactive power demand
at Fairbanks dropped to a level where Fairbanks absorbs only 10 MVAR.
This confirms that the initial loadings at Fairbanks are acceptable
while coping with this outage.
Case F4 represents an outage of the line from Anchorage to the midpoint
switching station as shown in Figure 0-44.Since the lines at this
05-24
25608
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point in the system are shorter than those north of Fairbanks and are
more lightly loaded,this is not as critical a contingency as an outage
of one of the circuits north of Fairbanks.This can be seen by
observing that the electrical angular displacement is only 53 0 rather
than 60 0 which was the case for an outage north of Fairbanks.
05-25
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06.0 CONCLUSIONS
With all the prefeasibility level design completed,a preliminary cost
estimate was made based on figures published by the Department of
Energy.Although these figures are based on lower 48 costs,their
relative value was used to do a cursory comparison.The results were
within ~10%dollar range for both the medium forecast and the low
forecast scenarios.This meant that within the accuracy of the level
of this study the costs of each of the alternatives described in this
Appendix is about the same.This meant that the following 15
transmission lines are about equivalent within their respective groups.
Prudhoe Bay Generation
Pruanoe Bay to Fairbanks
Medi um Forecast
(1)765kV,twocircuits
(2)500 kV,two circuits with series compensation
(3)+350 kV DC,two bipo1esl!
Low Forecast
(4)500 kV,two circuits
.(5)345 kV,two circuits with series compensation
(6)+350 kV,two bipo1esl/
l!The two HVDC versions may differ in current and/or voltage ratings.
06-1
2560B
Fairbanks Generation
Fairbanks to Anchorage
Medium Fo recast
(7)500 kV,two circuits and with or without the 345 kV
Interti e
(8)345 kV,three circuits with series compensation
Low Forecast
(9)345 kV,two circuits with series compensation
Kenai Generation
Kenai to Anchorage
Medi um Forecast
(10)500 kV,two circuits with some series compensation
(11)345 kV,two tircuitswith series compensation
·(12)345 kV,three circuits
Low Forecast
(13)500 kV,two circuits
(14)345 kV,with series compensation
Anchorage to Fairbanks
Both Medium and Low Forecasts
(15)345 kV,two circuits without an intermediate switching
station
D6-2
2560B
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It was much simpler to design the transmission system for the Kenai
generation scenarios than to do it for the Prudhoe Bay scenarios.The
reason:Kenai is much closer to Anchorage,the main bulk of load,than
is Prudhoe Bay.With the many studies made for the other scenarios
completed,the Kenai alternatives,with a 150 mile transmission
distance,!/needed only few computer runs.
As the costs of the versions within a group are nearly the same,the
final versions were selected in such a manner as to minimize the work
required for the detailed cost estimating.Ultimately,the following
seven versions were chosen for final evaluation:(2), (4), (8),(9),
(10),(13),and (15).
!!Initially,a 150 mile long route was selected around Turnagain Arm.
In the final round,an even shorter,90 mile route,with undersea
cable crossing,was selected.This final version should perfonm even
better.
06-32560B
07.0 SAG AND TENSION CALCULATIONS
This section contains·the computer generated sag and tension
calculations using Bunting and Chukar conductors.Calculations were
performed for six ruling spans:1500,1200,1000,800,600 and 400
feet.Towers were limited to 100 foot heights,with 13.5 foot long
insulators and 38 foot clearance to ground,thus limiting maximum sag
to 48.5 feet.Conductor loadings were specified as follows:
Special NESC Heavy
o lb/sq ft wind pressure
25 1b/sq ft wind pressure
8 1 b/s q ft wi nd pre ssure
2.3 '1 b/sq ft.wi nd pressure
No ice
No ice
1.5 11 radi al ice
No ice
-60°F
_60°F
32°F
86°F
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[
[-
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[
c-
-."
r-
L'
nu
E
B
C
C·
G
[
[
[
L
L_
e
08.0 FIGURES
TABLE 0-8
LETTER S'tMBOLS
BC -line charging MVAR at 1.0 per unit voltage
G -generati on
E -equivalent of the local area system
GL -Galbraith Lake (150 miles south of the North Slope)
OM -Prospect Camp (150 miles north of Fairbanks)
FB -Fairbanks
HE -Healy
DC -Gold Creek
MP -Midpoint
R -resistance in per unit on a 100 MVA base
X -reactance in per unit on a 100 MVA base
08-1
2560B
AL T£RNATIVE A
r .0025
x .0485
BC 315
1 1..0121
.0210
500
"VA
EACH
FIGURE 0-1
NORTH SLOPE GAS
FEASIBILITY STUDY
EBASCO SERVICES INCORPORATED
E
ONE LINE SCHEMATIC WITH IMPEDANCES
1400 MW capacity at Prudhoe Bay.
500 kV transmission system.
345 kV intertie in parallel between
Fairbanks and Anchorage.
intermediate 138 tV bus at Fairbanks
ALASKA POWER AUTHORITY
.05
200
"VA
r .0063
x .0716 .
BC 114
NCHORAGE 138
....I-HE 345
.0211 I500
MVA
.0046
1750
MVA
GEN.
'*
-.0093
-.0111 -.........L.I_
-.0093
FAIRBANKS 500
Notes
'*'200 MVAR
-35 MVAR50Percentseries compensation
For letter symbols.see Table 0.8
----1...--........-O'!500
-..----..41-GL500
1
750
MVA
EACH
nc.
C
B
o
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B
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-n._·._b
____L
--p
[
_.J
[-'
'..._-
·-:'1
-[
;-_1
-L
[
-r
-r
-r
r
r
-r
.L
:T~
F_L
*
-.0086
1.0121
*
*
1
.0186
NORTH SLOPE GAS
FEASIBILITY STUDY
ONE LINE SCHEMATIC WITH IMPEDANCES
1400 MW capacity at Prudhoe Bay;500 kV
transmission system;345 kV intertie in
parallel between Fairbanks and Anchorage;
no intermediate transformation at
Fairbanks.
FIGURE 0-2
DC 50u--,,,,_
ALASKA POWER AUTHORITY
1·0TAP 1
ANCHORAGE 345
r .0063
138 mi x .0716
BC 11~
-
-
*
*
FAIRBANKS 500
-.0093
-.0093 -
***r .0025
r .0046 x .0485
-.0093 100 mi x .0519 E BC 315
BC 83
lJ1 500 195 mi
**-.0093
1_.0093
ALTERNATIVE AA
!2m
*200 MVAR
-35 MVAR
50 Percent series compensation
For letter symbols.see Table 0-8
_.. .._GL 500
1
-.0091~I·oT~
1 I Th -.0057
.:°62.99 TAP
NORTH SLOPE 345
*
*
I
NORTH SLOPE GAS
FEASIBILITY STUDY
.945
.964
.952
DC 500-4""--"'-
.935
LOAD FLOH
No generation at Prudhoe Bay.Normal
system configuration.
ALASKA .POWER AUTHORITY
ANCliORAGE 345 1.00
I I 1.~]~
t 109
*242
CASE AAI
1.02
**
~AtRBA'KS 500t1311m
~
*200 MVAR**35 MVAR
50 Percent series compensation
For letter symbols.see Table D-8
.-
L_
C.
o
6
C
U
[
....-
[
Lt__-'
U"FIGURE 0-3
[...__...........__E_B_A_SC_O_S-E-R-VICES INCORPORATED
[
,-e
r-~-:
r
[--
[-:-
[
p-
u
[
[
[
["'
-,'
[.,
hj
["
.'
L..J
t:
:_J
L
:_--J
,[
r
r
T'
-r
T"
T
'r~
r.LJ
*
r1
I I
FIGURE 0-4
NORTH SLOPE GAS
FEASIBILITY STUDY
DC 50o-----.....~
LOAD FLOW
No generation at Prudhoe Bay.One line
segment open north of Fairbanks.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
ANCHORAGE 345 1.00
CASE AA2
1.021].~.t 113
*
FAIRBANKS 500
Notes
.,.200MVAR
-35 MVAR
50 Percent series compensation
For letter symbols.see Table D-8
.'
7010 I
II INORTHSLOPE345.970
-
~CASE AA3
s-']132 J!,"SANKS SOD 1.027]152 }52 ]120 IS,fI32
~1.013
~---'t U9
R-
**-1319
I"=';;
~.---......~()\500
II
FIGURE 0-5
NORTH SLOPE GAS
FEASIBILITY STUDY
LOAD FLm~
No generation at Prudhoe Bay.One line
segment open north of Devil's Canyon.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
ANCHORAGE 345
-
.993 *
'*I-OPEN
DC 500-
'**
I IrI I
NORTH SLOPE 345
Notes
'It 200 MVAR
-35 MVARSOPercentseries compensation
For letter symbols.see Table 0-8
[
[
c
c
;
G
[
[
[
L..•_.
U
[
T'
--r
--r
['
T'
'f-.
:-_.'
L'
A
.l,_~
r
-'
.-,..;
-~[
[
L
[
'..I
["-
,.-_..-.
.F'
[
.'j
[,
......:-J
-L
[--
-.-'.:
_.1
L,
i
FIGURE 0-6
NORTH SLOPE GAS
FEASIBILITY STUDY
LOAD FLOW
No generation at Prudhoe Bay.One line
segment open ~orth of Devil 's Canyon.
less one reactor.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORI.TY
•
951 I
3.2l t 317 .5t t138 .5t t138
ANCHORAGE 345 1.00NORTHSLOPE345.968
Notes
*200 MVAR
-35 MVAR
50 Percent series compensation
For letter symbols.see Table D-8
CASE AA4
1 flRBANKS 500 1.044
1 1 }344 }27
t235
1.004 f3~0 1.058
i129
****ot t49~
E
(If 500
**
OPEN
1.087 ~*
.**.918
*
OPEN T
**
DC 500
.949 i1l8-
*
I IIT 1-
*
I I
FIGURE D-7
NORTH SLOPE GAS
FEASIBILITY STUDY
DC 500-41-__.....-
No generation at Prudhoe Bay.The 345
IcV intertie opened at Anchorage.
EBASCO SERVICES INCORPORATED
LOAD FLOW -
ALASKA POWER AUTHORITY
OPEN
1.074
ANCHORAGE 345
**
~
*200 MVAR*'*35 MVAR
50 Percent series compensation
For letter symbols.see Table
CASE AA5
FAI RBANKS 500
1 I I 1 I r
_t 109
*'*t286
II
I r I
NORTH SLOPE 345
C···
---
(j
C
C,-
E
C~
[
L _
Ci__
GL__
L
n-
L
--
[
c--
[:
r~
[-
["
[-
F--
w
·C
L
..['
..-.,
.L
.c
[,
~~
L~:
-;
_'"._,J;
[--..
_4
.C
L~~,
·c
__.:oJ
-~
,~t
-f'
T~
:r
-r:
J
T-
~r:
!:....J
I I
FIGURE 0-8
NORTH SLOPE GAS
FEASIBILITY STUDY
LOAD FLOW
No generation at Prudhoe Bay.The 345
kV intertie opened at Anchorage.less
one reactor.
EBASCO SERVICES INCORPORATED
1.055
-t 104
**-
GL 500 DC 500
-
*
**
ALASKA POWER AUTHORITY
Notes
*200 MVAR
-35 MVAR50Percent series compensation
For letter symbols.see Table 0-8
CASE AA6
1 flRBANkS sob 1 1 1 r
ll09
*-t329
E
I IJr_~T..--~1.148 3~d t306
NORTH SLOPE 345 •-~A~NC~H~ORA~GE~34~5---"---"'-
*
*
r
I I
FIGURE D-9
NORTH SLOPE GAS
FEASIBILITY STUDY
DC 500 -4t---.....~
LOAD FLOW
No generation at Prudhoe Bay.One line
segment opened north of Galbraith
Lake.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
ANCHORAGE 345
E
I 11
CASE AA7
1.02
*
*
.970
FAIRBANKS SOD]131"]131
Notes
*200 MVAR
-35 MVAR
50 Percent series compensation
For letter symbols.see Table D-8
f«·.91 ]1::
]'441 I
NORTH SLOPE 345 .957
n
L
CL
*
I I
FIGURE 0-10
NORTH SLOPE GAS
FEASIBILITY STUDY
DC 500 --4....---4t--
LOAD FLOW
No generation at Prudhoe Bay.One line
segment opened north of Galbraith
Lake.less one reactor.
I;AASC~SI;AVICI;S INC~AP~AAn;D
ALASKA POWER AUTHORITY
ANCHORAGE 345NORTHSLOPE3451.058
Notes
*200 MVAR
-35 MVAR50Percent series compensation
For letter symbols.see Table Q..8
'CASE AA8
FAIRBArnCS 500 1.034]2l']23'1 1 1 r
t183
**-~390
E
1.035 CI4 500
~*l273
100741 ~.041
*279 ~70
J I I
r
FIGURE 0-11
LOAD FLOW
1400 MW generation at Prudhoe Bay.
Normal system configuration.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY.
NORTH SLOPE GAS
FEASIBILITY STUDY
LOSSES=
76.6 MW
ANCHORAGE 345 1.00 a
E
1073
121 ~t 17
CP.SE AA9
1.0~~
187 1T43I
Notes
*200 MVAR-35 MVAR
50 Percent series compensation
For letter symbols.see Table D-8
~t---..-OM 500
.996/Z1.4
FAIRBANKS 500
1.001 I
700]f233 I_lE 07
NORTH SLOPE 345 1.016/38.7
LL
[
8
C
[
G
[
'._o.
[
~~~
~.
[
-r
Li
[
~Ii
C't:,
_...._1
'.c
'._8
-~~
[
~·r
··.~··f-·..
..:::..:i-
,E,
['
~~t~
-1'
-r:
·T;
l~
-r
*
r
,..
I I
4/8 ill 18
NORTH SLOPE GAS
FEASIBILITY STUDY
FIGURE 0-1:2
LOAD fLOW
1400 *generation at Prudhoe Bay.One
line segment out of service north of
Fairbanks.
EBASCO SERVICES INCORPORATED
DC 500 ----4....---41-
ALASKA POWER AUTHORITY
1
LOSSES-
93.6 MW
ANCHORAGE 345 1.00~
181 JIi 35
CASE AAIO
-
-
**
.993 114.1
*
GL 500
.991~
FAIRBANKS 500
133~105
,..
1364 f t208
OM 50~990~
682 ttl04 -lLL...__
~
*200 MVAR**35 MVAR
50 Percent series compensation
For letter symbols.see Table 0-8
I I
10J242 I_18 H
NORTH SLOPE 345 1.015/46.5
*
r
II
NORTH SLOPE GAS
FEASIBILITY STUDY
FIGURE 0-13
DC 500 --411----1...-
LOAD FLOW
1400 ,..,generation at Prudhoe Bay.One
line segment out of service south of
Prudhoe Bay.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
1
LOSSES=
99.5 MW
1050 1t7
ANCHORAGE 345 1.00~
CASE AAll
E
r:A1 _KS 500 .ggO~ill187]48
187 t t55
FB 345"'---"'-
1.00/12.1 123 ~tz3
*-
Notes
*200 MVAR
-35 MVAR ,
50 Percent series compensation
For letter symbols.see Table D--8
--l...--.......-(lot 500
.957~
[
L
U,
C
C
i
rJ.,13
[
C
L
l.;_
L
\L __
[
[
,--
L
[
[
[
n
LJ
fl
L
.n
l
C
C
",!
L
L
....J
[
_",.J
[
-eJ
L
.-J
-[
i--'
L
r~
·L
913}[S9
1.018
1
I I
1400 MW generation at Prudhoe Bay.One
500 kV line segment out of service
south of Fairbanks.
NORTH SLOPE GAS
FEASIBILITY STUDY
FIGURE 0-14
DC 500 !"""""4I....--...:tt--.921~
LOAD FLOW
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
LOSSES=
88.7 MW
1061 t fSI 441 ~t38
ANCHORAGE 345 1.00~
179
**
E
*
CASE AA12
FB 345 .........__.._l.OO~~'184 t12-
*
*
FAIRBANKS 500 LDOl~1 21]12 2171
Notes
*200 MVAR
-35 MVAR
50 Percent series compensation
For letter symbols.see Table 0-8
-.....------lIt-OM 500
-e_--...........GL 500
I I
1 I I
NORTH SLOPE 345 1.015~
r
892 ~t 65
L&J
U-6:
L&J
(I)
u..o81 148
FIGURE D-15
LOAD FLOW
1400 MW generation at Prudhoe Bay.
One 500 kV line segment of service
north of Anchorage.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
NORTH SLOPE GAS
FEASIBILITY STUDY
LOSSESE
84.1
ANCHORAGE 345 1.00L!L
CASE AA13
1.009~~1'8A.KS 500
Notes
'*200 MVAR
-35 MVAR
50 Percent series compensation
For letter symbols.see Table D-8
NORTH SLOPE 345
I I
I I I
.7]52
[-
~-
[
[
[-
[
[
r1....----""
r
L.
[
6,
C
C
i
C
[
[
L
L
i ~_o
[
[
L
[
[
[
[
r~
b,..~
[
,
[
.J
.L
j
-~j
L
I
••j
L
[
r~
r
"[
t'
[~
f'""!:--=
r
L-
J
I
I I
fiGURE 0-16
NORTH SLOPE GAS
FEASIBILITY STUDY
DC 500 ,~..........
.9
LOAD fLOW
1400 MW generation at Prudhoe Bay.One
of the 500-345 kV transformers out
of service at Fairbanks.
EBASCO SERVICES INCORPORATED
E
I073t t80
LOSSES·76.5 MW
ANCHORAGE 345 1.00~
CASE AA14
ALASKA POWER AUTHORITY
**..v •.-
**
1.01 L1!.1
357]1"
}44.
*
FAIRBANKS 500
1
*
I I
J I I
NORTH SLOPE 345
Notes
*200 MVAR
-35 MVAR
50 Percent series compensation
For letter symbols.see Table 0-8
-"---4~GL 500
**
**
I::::
600 MVA
**
r .0077
x .0864
BC 138
r .0076
x .0864
BC 138
FIGURE 0-17
EBASCO SERVICES INCORPORATED
......,.,..-...**
NORTH SLOPE GAS
FEASIBILITY STUDY
ONE LINE SCHEMATIC WITH IMPEDANCES
1400 Krl capacity at Prudhoe Bay;two
SOD kV transmission line circuits
between Prudhoe Bay and Fairbanks
and three 345 kV transmission line
circuits between Fairbanks and Anchorage.
ALASKA POWER AUTHORITY
_.02581 r-
TAP=1.0
-.0216
MP345I I II I .·I-.0258
ANCHORAGE 138
FAIRBANKS 3451--..l'-...._T_A_P=_1_._O...----4~
ALTERNATIVE B
1500 ttVAITA:1.0 ~
.0062
r .0018
x .0373 -.0109 1500 MVA FB 138
BC 242
.025
400 MVA
r .0018
x .0373
BC 242
NORTH SLOPE 138
Notes
*200 MVAR**75 MVAR
50 Percent series compensation
For letter symbols.see Table 0-8
-.0111
.0046
1750 MVA,.014
750 TAP=l.OMVA_.._.._...._...._.._
\'-
L
[
C
C
6
L
[
[
[
L
[
[
r=
'-'
nL
".!
-[
or
or
[
r
~[
1
r'·.
I.,~,
[
.~~.,
[
o[
of
b.J
'L-.....;
J~.
L
••1
L. I
_...,:.,;J
.[
...;J
[
.1.015
o I ~191 Fa 138 1.00
**
FIGURE 0-18
NORTH SLOPE GAS
FEASIBILITY STUDY
LOAD FLOW
No generation at Prudhoe Bay.Normal
system configuration.
i 146
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
L;SES-1.8 I I I
1.8 ~t 444 .6t t 148
ANCHORAGE 138 1.0L1L
CASE B1
.~
198
FAIRBANKS 345 -4~--""~--"'---"'1.0246,!,
*
r-..1.P-Io18~.lt-l-.0....3}s.>------I ~131
NORTH SLOPE 138 .953".3
Notes
*200 MVAR
-75 MVAR50Percent series compensation
For letter symbols.see Table 0-8
1.011
-4~--"'-(JII 500
-CASE 82
674
..------;-.-1 I •~~----
30
r
L
c-
[-
[
[
[
[
L
n
L.i
.999
I I
LOAD FLOW
FIGURE D-19
NORTH SLOPE GAS
FEASIBILITY STUDY
1400 MW generation at Prudhoe Bay.
Normal system configuration.Generator
bus voltage 1.05 p.u.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
LOSSES=Ji
110.3 t
E
1040f t43 347.f 14
ANCHORAGE 138 1.0~
1.027..
NORTH SLOPE 138 l.017~
~
*200 MVAR
-75 MVAR
50 Percent series compensatio ft
For letter symbols.see Table D-8
c-
o,
c
c
[~
[
C
i _"
L
6
t .~
[
.
CASE B3.~
.~CaQ-140
[
[
'[
CL
'C
C..,.J
[.
,.J
C
'.c.J
[j
__1
[
_.::.J
[
.....-1
l
...J
L,,
.:...-.1
[
[
.[
[
n'
.~
....'r"P1>**
II
NORTH SLOPE GAS
FEASIBILITY STUDY
FIGURE 0-20
LOAD FLOW
1400 MW generation at Prudhoe Bay.
Nonnal system configuration.Generator
bus voltage 1.00 p.u.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
ANCHORAGE 138 1.00L2-
673~f19 f19 1Z5t t 16
FAIRBANKS 345 -4'-__~~__-4I...f ..._
.995/19.9
~.---........~~500
.975
.964
..........--.-..4~GL 500
NORTH SLOPE 138 .972~
!ill!
*200 MVAR
-75 MVAR
50 Percent series compensation
For letter symbols.see Table 0.8
."
250 t t 92 .
FB 138 1.0~
FIGURE 0-21
LOAD FLOW
1400 MW generation at Prudhoe Bay.
One line segment out of service south
of Prudhoe Bay.Generator bus
voltage 1.05 p.u.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
NORTH SLOPE GAS
FEASIBILITY STUDY
LOSSES=
.132.8
•
•.-r-~~---
27
663 I t 56 125 t i 42
FAIRBAtlKS 345 ~~---411""---411~--""""1.00~358 ~t 9
."
.992
663
CASE 84
-
-..~---ll'-~500.961~
Notes
'*200 MVAR
-75 MVAR50Percentseries compensation
For letter symbols.see Table D-B
700 f l286 t 571
NORTH SLOPE 138 1.012/55.3
."."
681 t ~61
MP~51 I I.997~
GL 500
1361't123
.945/36.7
.:.r.JPEN .".".".".".944
c
[
r
[
[
co;
[
n
L.J
[
o
c
C
FJti
C
[
l
Iit__
[
-r~
L
.[
.J
L
.-!
[
p-LJ
_.J
L,
~..i
L.1
l-
I_,...J
L
.J
L
.J
[
r~
T~
.~
T'
l
L
.J
[~
.j
r
L.-
.J
**
**
-
OAD FLOW
FIGURE 0-22
NORTH SLOPE GAS
FEASIBILITY STUDY
1400 MW generation at Prudhoe Bay.
One line segment out of service
south of Prudhoe Bay.Generator
bus voltage 1.00 p.u.
ALASKA POWER AUTHORITY
MP~51-I f
1101 t J56
ANCHORAGE 138 1.0~
660 ~t120 tI20 125t t 89
FAIRBANKS -345 ~.........._
.977/20
*
•
250 t f 190 6Q-98
. .FB 138
CASE 85
,..-----....t I.~
t 508
NORTH SLOPE 138 •964~
~...--......~GL 500
.910/37.9
~.....--......~lJ1 500.935~
~
'It 200 MVAR
-75 MVAR
50 Percent series compensation
For letter symbols.see Table D.8
1358 t t225
'"
"''''
513 ~t80 513 +t 80
1.006
FIGURE 0-23
250 t J 57
,.Fe 138 1.00~
1400 MW generation at Prudhoe Bay.
One line segment out of service
north of Anchorage.
LOAD FLOW
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
NORTH SLOPE GAS
FEASIBILITY STUDY
CASE 86
•t>----
125 t t 33
FAIRBANKS 345 -4"'--~l----"'---""-
1.000m.366 ~t 13
*'"
-.....--...-()l 500
.....r~*
......t----..-GL 500
Notes
*200 MVAR
-75 MVAR
50 Percent series compensation
For letter symbols.see Table D-8
C
L
[
o
C
b
L
[
[
L
6
[
[
[
[-
[
['
[
[
n
L)
r
T~
['
T'·
T~'
I~
L
-r·_":j_i
**
400
MVA
TAP-l.O
r .0076
x .0864
BC 138
.0258
~AP-l.O~.0167 MVA
EACH
**
.025
F.B 138
167 mi
r .0077
x .0864
167 mi BC 138
FIGURE 0-24
NORTH SLOPE GAS
FEASIBILITY STUDY
.025
EBASCO SERVICES INCORPORATED
ONE LINE SCHEMATIC WITH IMPEDANCES
1400 fill capaci ty at Prudhoe Bay i two
765 kV transmission line circuits
between Prudhoe Bay and Fairbanks
and three 345 kV transmission line
circuits between Fairbanks and Anchorage.
ALASKA POWER AUTHORITY
I I
ANCHORAGE 13
t t
1500 MVA
1750
MVA
.0046
l.066 TAP
*FAIRBANKS 345 ~""---"---"----4""-
OM 765
*
r .0005
x .0138Be700
150 mi
**-
**
r .0005
x .0138
BC 700
-
150 mi
r .0005
x .0138
BC 700
150 mi
*
--l....--'"'""'4I~GL 765
ALTERNATIVE C
Notes
*200 MVAR
-75 MVAR50Percent series compensation
For letter symbols.see Table D-8
.02
750
!"IVA
EAC.H-"'-"'_~.....,j"""'''''NORTH SLOPE 138
-------------
-
.987
-
ot ~186.FB 138 1.00~
-
LOAD FLOW
FIGURE 0-25
NORTH SLOPE GAS
FEASIBILITY STUDY
1.014
No generation at Prudhoe Bay.Normal
system configuration.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
t I 1.025j151
ANCHORAGE 138 1.00&'
MP 345 .ill1_88
0 °I I
1.033/-.4 I I I
190
LOSSES=1.6
'*
*FAIRBANKS 345 ""'""4.---_..o4l~--_..o4l~--......_
1.023/-.4
*
*
*
'*
CASE Cl
'*
'*'*
*
~43
NORTH SLOPE 138 1.013~
1.026
.-.ol....--.-.ot....GL 765
1.033
-''It---~~OM 765
Notes
*200 MVAR
-75 MVAR
50 Percent series compensation
For letter symbols,see Table D-8
E
C
[
D
C
L
[
[
L
C
[
[,
[
c
[
[
['
[
n
LJ
........
NORTH SLOPE GAS
FEASIBILITY STUDY
250 t ~1~
Fa 138 0
FIGURE 0-26
LOAD FLOW
1400 MW generation at Prudhoe Bay.
Normal system configuration.
i 10
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
3sa+t 21
693 ~i 118 125t l82
ANCHORAGE 138 1.00i1l
*
*FAIRBANKS 345
1.02/20
O!'!765 }....
1.042~
CASE ·C2
Notes
*200 MVAR
....75 MVAR
50 Percent series compensation
For letter symbols.see Table 0-8
350 t ~134 l536
NORTH SLOPE 138 1.092~
696t t 181
1.001I1'002
NORTH SLOPE GAS
FEASIBILITY STUDY
250t t 3
fB 138 .00Li.e.J
FIGURE D-27
1400 MW generation at Prudhoe Bay.
One 765 tV line segment south of
Prudhoe Bay out of servi ce.
LOAD FLOW
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
LOSSES=t 20
82.4 ~
1068 t f 3 356 +~1
ANCHORAGE 138 1.00LQ.
CASE C3
t 640
NORTH SLOPE 138 1.086~
Notes
*200 MVAR**75 MVAR
50 Percent series compensation
For 1etter symbo 1s.see Table D-8
*690 J t 9 125t l 1
*FAIRBANKS 345
l693tt76
1.00~4
OM 765
1.OO.@.:.!**
**
366 ~t 24
1.004
**~3451 I .'f**
695 1~103 1.001~t 5
366 ~t 40
*z *******L&Jn-o
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of'
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*
r .0077
x .0864ec138
**
HVDe TERMINAL AND
FAI RBANKS LOAD
COMPOSIT EQUIVALENT
HP 345
167 mi
FAIRDAMKS 345
ALTERNATIVE D
*
r
L
167 mi
AflCHORAGE 138
!!ill!.
*75 MVAR
No series compensation
For letter symbols.see Table D-8
r .0076
x .0864
BC 138
.0167
600 ~IVA
ALASKA POWER AUTHORITY
NORTH SLOPE GAS
FEASIBILITY STUDY
ONE LINE SCHEMATICS WITH IMPEDANCES
1400 MW generation at Prudhoe Bay;HVDC
transmission between Prudhoe Bay and
Fairbanks and three 345 kV transmission
line circuits between Fairbanks and
Anchorage.
FIGURE D-28
1;9ASCO SI;RVICI;S INCORPORATED
[
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[
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***
MP 345
1.035~.1
.1 f t 31
CASE D1
HVDC TERMINAL AND
FAIRBANKS LOAD
COMPOS IT EQUIVALENTott107
FAIRBArlKS 345
l.OOLJ
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**
FIGURE 0-29
NORTH SLOPE GAS
FEASIBILITY STUDY
No power transfer between Fairbanks and
Anchorage.Nonna 1 system confi guration.
LOAD FLOW
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
ANCHmL\GE 138 1.O~
~
*7S MVAR
No series compensation
For letter symbols.see Table D-8
[
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***
350 t la.63
MP 345--4.----...---....-
•97J.al.6
E HVDC TERMINAl AND
FAIRBANKS LOAD
t COMPOSIT EQUIVAlENT
193
FAIRSAr 345
l.QQS.9
CASE 02
GENERATION 1400 MW
HVDC LOSSES 70 MW
FAIRBANKS 250 MW
TO ANCHORAGE lOBO MW
[
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---j
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•991l!.3
FIGURE 0-3C
NORTH SLOPE GAS
FEASIBILITY STUDY
*
LOAD FLOW
1400 MW capacity It Prudhoe 81Y.HVDC
transmission between Prudhoe 8ay and
Fairbanks.Normal system configuration.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
*
340
1020 t 183 3401f61
ANCHO~\GE 133 1.0~
AC LOSSES-60.3 MW
!!!?ill.
*75 MVAR
No series compensation .
For letter symbols,see Table 0-8
*
*
FIGURE 0-31
NORTH SLOPE GAS
FEASIBILITY STUDY
LOAD FLOW
1400 MW generation at "Prudhoe Bay;HYDC
transmission between Prudhoe Bay and
Fairbanks and one 345 kV line segment
out of service north of Anchorage.
*
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
500 J tl54 500l t 154
.970 G.9
5c
OPE"l
CASE D3
1000t 405
ANCHORAGE 138
1.04
349 I t 40 349 t ~40
.936 £J4.5 349l f40MP345~.-......_
HYDC TERMINAL AND
FAIRBANKS LOAD
COMPOS IT EQUIVALENT
1080 l t 318
FAIRBANKS 345
1.00 L'53.4 360.t 106
AC LOSSES
&80.4
~
*75 MVAR
No series compensation
For letter symbols.see Table 0-8
GENERATION 1400 MW
HVDC LOSSES 70 MW
FAIRBANKS 250 MW
TO ANCHORAGE 1080 MW
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iENERATION 1400""
IVDC LOSSES 70 ,..,
:AIRBANKS 250 ,..,o ANCHORAGE 1080 ,..,
CASE 04
HVDe TERMINAl AND
FAIRBANKS LOAD
COMPOS IT EQUIVALENT
l080l1242
FAIRBANKS 345
1.05LJ].5
360l t81
351 ~*38
1.006aD.7
•MP 345----4.----.----..-
*
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*
.997 L:3.3
*
NORTH SLOPE GAS
FEASIBILITY STUDY
FIGURE 0-32
1400 MY generation at Prudhoe Bay;HYDC
transmission between Prudhoe Bay and
Fairbanks.Normal system configuration;
voltage raised by 5S at Fairbanks.
LOAD FLOW
EBASCO SERVICES INCORPORATED
*
ALASKA POWER AUTHORITY
1024 t t74 341 ~l25
ANCHORAGE 138
1.0 4..
AC LOSSES
•56.2
Notes
..75 MVAR
No series compensation
For letter symbols.see Table 0-8
**
FIGURE D-33
NORTH SLOPE GAS
FEASIBILITY STUDY
EBASCO SERVICES INCORPORATED
LOAD FLOW
1400 MW generation at 'Prudhoe Bay;HVDC
transmission between'Prudhoe Bay and
Fairbanks.One 345 ltV line segment out
of service north of Anchorage;voltage'
raised by 5~at Fairbanks.
OPEN1
CASE D5
ALASKA POWER AUTHORITY
3501160
MP 345 ~.-....._
0.981LJZ.7
10011298
ANCHORAGE 138
HYDC TERMINAL AND
FAIRBANKS LOAD
~COMPOSIT EQUIVALENT
1330-250=
1080 Net 332
At LOSSES
74.1
Notes
*75 MVAR
No series compensation
For letter symbols.see Table D-8
GENERATION 1400 MW
HYDC LOSSES 70 Mtl
FAIRBANKS 250 Mtl
TO ANCHORAGE 1080 Mtl
c:
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400.MVA.02
Fa 138
.02
r .0077
x .0864
Be 138
r .0076
x .0864
BC 138
....r.lrY"'**
MP 345 ~....--~....
-.0258
TAP-l.O
ANCHORAGE 138
-.0195
FAIRBANKS 345 --It-__-4....__-4.....T_A_P._1_.0~~
AL TERNATI VE E
*
*
*
r .0068
x .0778
BC 124
150 IIi
r .0068
x .0778
BC 124
r .0068
x .0778
BC 124
T -.0228 .0228
N..ATAPal.0
~~~~.0133 I ~rs'~AJ.~AP..99
tHRTH SLOPE 138
!!2!!!.
*100 MVAR
-75 MVAR
50~series compensation
For letter symbols.see Table 0-8
ALASKA POWER AUTHORITY
NORTH SLOPE GAS
FEASIBILITY STUDY
ONE LINE SCHEMATIC WITH IMPEDANCES
700 MW capacity at Prudhoe 8aYi 345 kV
transmission system with series
compensation
FIGURE 0-34
EBASCO SERVICES INCORPORATED
[
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[
**
.987
i 137
FIGURE 0-35
LOAD FLOW
No generation at Prudhoe Bay.Normal
system configuration.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
NORTH SLOPE GAS
FEASIBILITY STUDY
MP 345~"'--.-...4"'-
~
72
t 73 t 60
FAIRBANKS 345 ~'---....04~--....04~---41"'
1.015L3
*
~119
FB 138 1 0i:.,.3
CASE E1
1.001
.942
.98
.999
OM 345
1.009
.990
.951C.z .I IGEN.LOSSES=1.0J:.9~0 Ito t142 .023
.1 0 I I tUB
NORTH SLOPE 138 .94262 ArlCHORAGE 138 1.oCllP.,
~
*100 MVAR
**75 MVAR
501 series compensation
For letter sYlllbols.see Table D-8
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1.076
1.lsi
FAIRBANKS 345 ......-__-4~f---+---....-
1.015 114
*
CASE E2
1.0 .986
~.....
147
1.024
.5
[
f'
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*
FIGURE 0-36
I
NORTH SLOPE GAS
FEASIBILITY STUDY
No generation at Prudhoe Bay.One
1i ne segment opened north of
Fairbanks.
LOAD FLOW
EBASCO SERViCeS INCORPORATED
ALASKA POWER AUTHORITY
NCHORAGE
MP 345 ....t---.........-
GEN..980
,1:.9~to
-tIM sLol ..,o I
~
*100 MVAR**75 MVAR
50S series compensation
For letter symbols.see Table 0-8
1.00
FIGURE 0-37
LOAD FLOW
No generati on at Prudhoe Bay.one
line segment opened north or
Fairbanks with the loss of an
additional reactor.
EBASCO SERVICES INCOR~ORA TED
I I
ALASKA POWER AUTHORITY
NORTH SLOPE GAS
FEASIBILITY STUDY
o I fZ07
Fa 138
2 t l25
3.21 t 263 t106
-."'r"Ir'"**_
MP 34>~..---...-
ANCHORAGE 138
LOSSES=
4.26
•
1.061
*
1.056
CASE E3
.976
OPEN
1.109
~
251
J:'1.0~
J II
NORTH SLOPE 138 1.019 .
1.lZ8
!2!!!.
*100 MVAR
..75 MVAR
50~series compensation
For letter symbols.see Table D-8
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--Co
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-
.995
63 t tZ5
125 t j 481"FB 138 LOOLl}.2
FIGURE 0-38
NORTH SLOPE GAS
FEASIBILITY STUDY
LOAD FLOW
700 MW generation at Prudhoe Bay.
Normal system configuration.
259
254 l i 50
MP 345
1.014Lz..M"---"-
327
~
FAIRBANKS 345 ~"'---4~--~~---4~
1.006L1!.1
...-
1
*
ALASKA POWER AUTHORITY
CASE E4
1.00JLu.5
()I 345
.995
1.05&.4 JiI~LOSSES-t~76 l.~700 ,t 231 E 67.3 68
3S~98 I }S6 SOO t fll3 ZS4 ~tS7
NORTH SLOPE 138 1.021~ANCHORAGE 138 1.0~
~
*100 MYAR
-75 MYAR
50~series compensation
For letter s1lllbols.see Table 0-8
-
I
FIGURE D-39
NORTH SLOPE GAS
FEASIBILITY STUDY
LOAD FLOW
700 MW generation at Prudhoe Bay.
one line segment out of service
south of Prudhoe Bay.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTH.ORITY
317 I
254
MP 3450-01.._--liliii4i.-
1.00~3
FAIRBANKS 345
•99Sm·8
*
~
57
*
CASEE5
1.004
4+-
57
OPEJi
700 t GEN.1.0s~.0 IItLOSSES=c-;if'159 -.-700 t 276 £85.7 .
•9~OPEN~.1229 I 700 IZZ9 489 t t 96 Z4~t 48
NORTH SLOPE 138 1.017L!§.5 ANCHORAGE 138 1.0&
1.041
~
*100 MVAR
-75 MVARSOSseries compensation
For letter symbols.see Table D-8
C
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.;
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**
**
r .0076
x .0864
BC 138
r .0077
x .0864
BC 138
ALASKA POWER AUTHORITY
I I-·~58
.0167 .0167
600 HVA
"'P 345 .....,...--..........
ANCHORAGE 138
*
AL TERNATIVE F
1500 MVA
.0087
r .0018 FB 138x.0373
IC 242
.0087 .025 .025 400 "'VA
**TAP-I.0
FAIRBAPU<S 345
r .0018
x .0373
BC 242
r .0018
x .0373
BC 242
NORTH SLOPE 138
~....__~~(J1 500
~.----4~GL 500
Notes
*200 MVAR
-75 MVARSOlseries compensation at the 345 tV line only
For letter symbols.see Table D-8
NORTH SLOPE GAS
FEASIBILITY STUDY
ONE LINE SCHEMATIC WITH IMPEDANCES
700 MW capacity at Prudhoe BaYi 500 kV
transmission between Prudhoe Bay and
Fairbanks and 345 kV transmission with
series compensation between Fairbanks
and Anchorage.
FIGURE 0-40
.J
IL...
1 DO
-
.986
10025
LOAD FLOW
FIGURE D-41
NORTH SLOPE GAS
FEASIBILITY STUDY
No generati on at Prudhoe Bay.normal
system configuration.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
t Z16
FB 138
~91
.MP34S ..........--........
1.0~5
ANCHORAGE 138 1.00
LOSSES-}if
1.4 155
E
t303 t 1S1
.999
*
*
*
CASE Fl
1.042
--tt---....to-(J4 500
1.039
........
139
1.0Z8
.....jl-__....--.GL 500
J I I
NORTH SLOPE138 .999
Notes
*ZOO MVAR
-75 MVAR
SOS series compensation It the 345 tv line only
For letter symbols.see Table D-8
Ru
c:
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o
o
C
B
C
L
[
[
L
L
[
..
[
C'
C'
[
[
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•.[
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.,
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[
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._....J
W__.:1
.[
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~T~
O[
l~~
T-
t'
T~
:
0['
T1
b
I
l123
Fa 138 1.~.9
.995
63 t l64
**
FIGURE D-42
NORTH SLOPE GAS
FEASIBILITY STUDY
LOAD FLOW
700 MW generation at Prudhoe Bay.
Norna 1 system configuration.
ALASKA POWER AUTHORITY
270 Ji 54
1.022
CASE F2
*
344---~
78
*.
FAIRBANKS 345
1.016&.8
.0Iam·6
(If 500
346t 478
275 1l20
*
MP 345
1.01aLz...9
Gl 500
348 t ~1.01~.8'77
6
1.0sa5.4 JiI~LOSSES-t 73, t 253 E 35.7
J 3~0 l_03_I206 539 t f12l 210 ~t 60
NORTH SLOPE 138~03 ANCHORAGE 138 1.0~
Notes
*200 MVAR
-75 MVAR501series compensation at the 345 kV line only
For letter symbols.see Table 0.8
**
.9961.009
125 t t ~138
NORTH SLOPE GAS
FEASIBILITY STUDY
FIGURE D-43
LOAD FLOW
700 ~generation at Prudhoe Bay •one
line segment out of service south of
Prudhoe Bay.
EBASCO SERVICES INCORPORATED
ALASKA POWER AUTHORITY
MP 345~.-__..-04""
1.0ILz.9
340
1.001
6
*340~f4
FAIRBANKS 345
1.00JLl5
*
.97W.3
(Jol 500
345 1f15
.94~.3
Gl 500
NORTH SLOPE 138
343 f f8
345 1~15
690 1t 30
CASE F3
UJ
U->a::
L&J
*(1)
~
~°1 GEN.1.05/60.3 LOSSES=~
700 J t 359 E 42':J158
700JI 30.1 1__1 308 533 t {91 266 l t46
ANCHORAGE 138 1.0~
~
*200 MVAR
-75 MVAR50~series compensation at the 345 tv line only
For letter symbols.see Table D-B
D
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c
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Ruef,D.M.,1981.Experiences with Contaminated Insulators Under
Arctic Conditions.SOHIO Alaska Petroleum Company.
..
Commonwealth Associates,Inc.,1981.Anchorage-Fairbanks Transmission
Intertie Route Selection Report.
Transmission Line
0.9.0 REFERENG£S
Electric Power Research Institute (EPRI),1982.
Reference Book:345 kV and Above;2nd Ed.
~.
[
C·
C·
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[-
[
l~Commonwealth Associates,1978.Model for the Ready Definition and
~---------------A/YPl'oxfmifte-Comparfson-of-Alternative-Hi gft -Yoftage -fransm1ssi onnSystems.DOEIET15916-1..
Ld ..
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25608
09-1
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oo
APPENDIX E
APPENDIX E
FAIRBANKS RESIDENTIAL/COMMERCIAL
GAS DEMAND FORECASTS
JANUARY,1983
El.l BASE YEAR ENERGY CONSUMPTION •••••••••••
El.2 THE CONDITIONAL DEMAND FOR NATURAL GAS IN •••••
FAIRBANKS
TABLE OF CONTENTS
... .. . . . . . . . ... ... ..E-35
E-6
E-17
E-l. .. . ..
REFERENCES • • •
FAIRBANKS RESIDENTIAL/COMMERCIAL GAS DEMAND •
FORECASTS
E2.0
El.O
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Tab 1e Number
E-1
LIST OF TABLES
TITLE
FAIRBANKS NORTH STAR BOROUGH ESTIMATED 1981
ENERGY CONSUMPTION DELIVERED ENERGY,
SELECTED END USES
E-7
E-2 FAIRBANKS NORTH STAR BOROUGH ENERGY E-15
PARAMETERS USED IN THIS STUDY
E-3 FAIRBANKS NORTH STAR CONDITIONAL GAS DEMAND E-23
POPULATION GROWTH AT 1 .43%
E-4 FAIRBANKS NORTH STAR CONDITIONAL GAS DEMAND • •E-24
POPULATION GROWTH AT 2.30%
E-5 PRESENT VALUE ANNUAL SAVINGS IN EXCESS E-29
OF $600
E-6 DELIVERED ENERGY,PEAK DEMAND MONTH E-34
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E1.0 FAIRBANKS RESIDENTIAL/COMMERCIAL GAS DEMAND FORECASTS
The potential residential and commercial demand for natural gas in the
Fairbanks area is dependent on the price competitiveness of natural gas
with respect to No.2 distillate fuel oil and propane in space heating
and water heating markets,and its price competitiveness with propane
and electricity in cooking markets.The potential demand of natural
gas as a cooking fuel is estimated to be less than 5.0 percent of the
total potential demand for natural gas even if the gas were to fUlly
displace bottled propane in commercial cooking applications.
The forecasts of potential gas demand have been made conditional on the
gas achieving discrete percentages of the total market for heating and
cooking energy (10 percent,25 percent,40 percent,and 100 percent
displacement of fuel oil and propane in heating and of propane in
cooking).The size of the total market to which these p~rcentage~have
been app1 ied has,in turn,been projected to grow at a 1.43 percent
annual average rate from 1981 for the low growth forecast,and at a
2.30 percent annual average rate for the medium growth forecast.These
growth rates are the rates of Fairbanks population growth implied,
respectively,by Battelle's (1982)low forecast of the demand for
electricity in the Railbelt area,and Acres American's (1981)medium
forecast of Railbelt electricity demand.
The prices at which residential and commercial users would have a
minimum financial incentive to convert from fuel oil to natural gas for
heating purposes have been derived.These "consumer breakeven"prices
are basea upon the assumption that the maximum discounted payback
period for consumers is 5 years.At the 1982 price of No.2
distillate,$1.22 per gallon,the calculated consumer breakeven prices
are $9.58 per MCF for residential heating and $9.94 per MCF for
commercial heating.In real terms,these prices,will rise annually at
approximately the real (inflation free)rate of increase of fossil fuel
prices in general.If this rate is the 2.0 percent real rate assumed
by Battelle (1982)and Acres (1981),by the year 2010 the breakeven
prices (in 1982 dollars)will have reached $16.68 per MCF (residential)
and $17.31 per MCF (commerci al).
E-1
3088A
The presence of calculated break even prices is necessary for the
forecasting of natural gas demand.However,breakeven price data and
price elasticity data are insufficient for such a forecast in this
case.These price and e1 astici.ty data are insuffici.ent because the.
situation involves a new product (natural gas)competing with an
existing product (e.g.,distillate oil,propane).Additional factors
influence consumer demand including:1)consumer perceptions of the
two products;2)consumer inertia;3)initial and/or unusual incentives
offered by suppliers of the competing fuels based upon their calculated
present worth of achieving certain market shares;and 4)other less
defined factors.Because of these unquantified factors,conditional
demand estimates have been forecast;and these are based upon price
ana1ysi s alone.
If natural gas is priced below the consumer breakeven level,users will
have an.increased financial incentive to shift from fuel oil.For
every 10¢by which the price of gas falls below the breakeven level,
residential users will realize approximately $81.00 (in 1982 dollars)
in additional savings (present value)over the estimated cost of
conversion.If there is any s~gnificance to numbers like $500,one
might expect extensive inroads against fuel oil to begin to be made if
gas is priced below breakeven to cover conversi on costs and to achi eve
this level of savings (measured as the excess of the present value of
annual cash savings over conversion costs).
One must recognize that the producers and suppliers of fuel oil are
likely to respond to the intrusion of natural gas by either lowering
the price of No.2 distillate or by offering other incentives.While
the intensity of reaction by oil suppliers cannot be forecasted,it cafl
be assumed that suppliers are capable of at least offsetting the price
advantage that natural gas has traditionally enjoyed based on its
reputation as a "clean"fuel.Therefore,the above calculation of
consumer breakeven prices correctly ignores the fact that many .
consumers might be willing to pay a premium for such natural gas
properties.
E-2
3088A
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The conditi onal demand projecti ons derived are sumari zed below.
DELIVERED GAS,BCF PER YEAR
1985 2010
c
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MARKET GROWTH @ 1.43 PERCENT
1O~of Ma rket
25~of Market
40~of Market
1OO~of Market
MARKET GROWTH @ 2.30 PERCENT
10~of Market
25~of Market
40~of Market
100~of Market
0.510
1.275
2.039
5.098
0.527
1.319
2.110
5.274
0.727
1.818
2.908
7.720
0.931
2.328
3.726
9.314
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These values represent the annual demand for delivered gas conditional
upon the percentage of market penetration indicated,where the total
market,defined in terms of effective MMBtu·J/is set equal to 100
percent of commercial and residential heating energy requirements plus
29 percent of residential cooking energy requirements.The delivered
gas demand values were calculated based upon different thermal
efficiencies for oil and gas fired units.
.The demand for gas would not be constantly distributed throughout the
year.Based on an appraisal of normal monthly heating degree day.s in
Fairbanks,and an assumed indoor temperature setting of 65 0 Fahrenheit,
approximately 16.6 percent of annual Fairbanks heating energy is
!I Effective MMBtu·s are delivered MMBtu·s adjusted for the fuel
burning efficiency of heating units and cooking units.For example,
if oil burners are 65 percent efficient,one delivered MMBtu equals
0.65 effective MMBtu·s..
E-3
3088A
1/hI.'consumed in January,the peak month for demand.-Althoug coo~lng
energy requirements may be more evenly spread across the year,the
relatively small size of cooking demand,less than 5.0 percent of the
total,suggests rather strongly that an apportionment of total demand
according to the conductive heat transfer formula will yield a good
.estimate of peak monthly demand.Use of this method implies the
following peak monthly demand (January)for natural gas in Fairbanks.
DELIVERED GAS,BCF PER PEAK MONTH
Janua ry Janua ry
1~5 2mo
MARKET GROWTH @ 1.43 PERCENT
1.0%of Market
25%of Market
40%0 f Ma rket
100%of Market
MARKET GROWTH @ 2.30 PERCENT
0.085
0.212
0.338
0.846
0.121
0.302
0.483
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1/Heat loss is proportional to the indoor-outdoor temperature
differential and inversely proportional to the insulation factor.
At an indoor temperature setting of 65°Fahrenheit,relative
monthly heating degree days is the appropriate measure of relative
monthly heat loss.
Peak daily demand duri ng the month of January can reasonably be
estimated as 0.0322 (1/31)of the monthly demand times a factor that
allows for extremes of cold.Between 1961 and 1982,the highest number
of January heating degree days recorded in Fairbanks was 3002 (in
January 1971).The January average was 2384.The ratio of the two
(1.26)when multiplied by 0.0322 yields an appropriate measure of peak
daily demand when their product is in turn multiplied by peak monthly
demand.Thus,peak daily demand equals 0.0406 times peak monthly
demand.
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0.386
0.619
1.546
0.087
0.219
0.350
0.875
10%of Market
25%of Market
40%of Ma rket
100%of Market
3088A
E-5
The daily peaks are given in the following text table.
0.005
0.m2
0.020
0.049
0.006
0.016
0.025
0.063
0.003
0.009
0.014
0.034
0.004
0.009
0.014
0.036
10%of Market
25%of Market
40%0 f Ma rket
100%of Market
10%of Market
25%of Market
.40%of Market
100%of Ma rket
MARKET GROWTH @ 2.30 PERCENT
MARKET GROWTH @ 1.43 PERCENT
DELIVERED GAS,BCF,PEAK DAILY
January January
1~5 2mO
Peak hourly demand,defined as 0.0417 (1/24)times peak daily demand is
quite small.For example,in the maximal case of 2.30 percent growth
and 100 percent market penetrati on,the peak hourly demand is only
0.0026 BCF,or 2,600 MCF.
Finally,it is useful to note that any expansion of the Fairbanks steam
district heating system could reduce the demand for natural gas below
the estimates given above.On the assumption that the district heating
system supplies only commercial and government users,the implied
reduction is at most 15.0 percent of the estimates given above,since
commercial use of gas is projected to be at most 15.0 percent of total
demand.
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E1.1 BASE YEAR ENERGY CONSUMPTION
Table E-1 presents base year,1981,residential and commercial energy
consumption estimates for the Fairbanks area.The estimates represent
"delivered"energy,that is gross energy volumes mea~ured at the input
,'
to the various energy-us'ing devices beiOng powered.These estimates
reflect the quantity of energy that must be produced and supplied to
the marketplace.
For all Fairbanks residential and commercial users combined,the
estimates show that fuel oil and propane supplied appraKimate1y 65
percent of the 1981 delivered energy used for space heating and water
heating.Coal,wood,electricity,and steam supplied 1.8 percent,20.5
percent,8.0 percent,and 1.9 percent,respectively.
Because the appropriate end use surveys have never been made,
residential use of propane 1n lighting and appliance applications in
Fairbanks cannot be separately enumerated.Fairbanks consumers use
propane for space heating,water heating,powering vehicles,and
energizing lights and appliances.!!Faced with this difficulty,it
is assumed that propane accounts for 14.1 percent of the energy used
for residential lights and appliances in Fairbanks.The resultant 1981
total residential consumption of energy for this end use,258 billion
Btu's,results in an implicit per capita consumption for lighting and
appliances that is consistent with national averages.21
!!A survey detailed enough to yield more accurate estimates of
consumption by fuel and end use in Fairbanks was beyond the scope
of thi s work.
!I Using a July 1,1981 Fairbanks North Star population of 51,569
persons drawn from [3],estimated per capita consumption for
lights and appliances comes to 5.0 MMBtu in 1981.The few
national estimates we have seen place this figure between 5.0 and
5.5 MMBtu.See,for example [8],p.75.
E-6
3088A
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SPACE AND WATER HEATING
Fuel Oi1/Propane**3,043,752 22.041 467,368 3.384
Coal 97,127 5,582 0 0
Wood 1,109,815 59,990 0 0
Electricity 322,071 94,366 108,974 31,929
Steam ******101,263 104,395
Other 163,591
TOTAL 4,736,356 677 ,605
LIGHTS AND APPLICANCES
Propane 36,334 0.402 75,073 0.830
Electricity 221 ,511 64,902 149,000 43,656
TOTAL 257,845 224,073
2665B
***Less than 0.1%of residential total
**Conversion to units from MMBtu·s at fuel oil rate
Conmercia1
MMBtu'S Units*MMBtu'S Units*
E-7
Residential
TABLE E-1
FAIRBANKS NORTH STAR BOROUGH
EST1MATED 1981 ENERGY CONSUMPTION
DELIVERED ENERGY,SELECTED END USES
and Propane --Millions of Gallons
--Tons
--Cords
--Megawatt Hours
--Thousands of Lbs.Per Year
*Fuel Oil
Coal
Wood
£lec tri city
Steam
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Residential Space Heating and Water Heating:The estimates in Table E-1
were constructed in four steps:
Step 1:According to the Fairbanks North Star Borough Community
Research Center,University of Alaska Extension,Engineer AKe1
Carlson has estimated that the statistically average residence
in the Borough would use 1,500 gallons of No.2 distillate fuel
oil per year for space heating and water heating purposes if
fuel oil were the fuel exclusively employed.Given that there
were 22,751 occupied residences in the Borough on average
during 1981,!!that oil furnaces have an efficiency of 65
percent,and that a delivered gallon of No.2 distillate
contains 0.138MMBtu's,the implied total 1981 North Star
Borough residential space heating requirement,measured in
..
effective MMBtu's,is 3,070,000 MMBtu's.
Step 2 Based upon a survey conducted by the Interior Woodcutters
Association,and cross-checked with two additional surveys (see
the discussion below),it was assumed that in 1981 this total
space heating market was distributed among the available fuels
in the following manner:63.8 percent,fuel oil and propane;
25.3 percent,wood;9.6 percent,coal;and 1.3 percent,other.
1/This is 5.97 percent more than the 21,469 units shown in the 1980
Census of Housing,the same percentage increase over the Census
implied by the Borough's 1981 population estimate of 51,569
persons.(The Eie1son Reservation Census subarea is excluded from
these figures.)In effect it is assumed that the Census
.undercount (recognition of which would cause us to raise the
number of estimated occupied residences)and the existence of
vacant housing units (recognition of which would cause a reduction
in the number of estimated occupied residences),cancel each
other.The June 1981 Fairbanks Housing Survey conducted by the
Federal Home Loan Bank of Seattle showed only an overall 3.3
percent vacancy rate for the area.
E-8
3088A
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Step 3 Employing average equipment thermal efficiences of 65 percent
for fuel oil heaters,55 percent for woodstoves,60 percent
for coal burners,and 100 percent for electric heating units,
estimates of delivered energy by fuel type for residential
space and water heating were obtained.These are presented in
Table E-l.
Step 4 At MMBtu conversion factors of:0.138 MMBtu/gallon for fuel
oil;17.4 MMBtu/ton for coal;18.5 MMBtu/cord for wood;and
0.0034 MMBtu/kWh for electricity,the MMBtu'estimates of
delivered energy by fuel type were converted into unit
estimates,(also shown in Table E-ll.!!
Commercial Space Heating and Water Heating:The 1978 Fai,rbanks Energy
Inventory [5b]tabulateq the number of businesses and the square
footage of office·space'for each of eight commercial industries.For
these eight industries,estimates of heating energy used were also
provided.Inita11y,the list of industries appears incomplete with
respect to all types of units encompassed by what would be defined as
the Iconmercia1"sector.2/For purposes of ultimately determining
the demand for natural gas in commercial heating,a comprehensive
inventory of buildings is needed.This requirement is also considered
in the 1978 Energy Inve~tory:
"Data regarding numbers and types of businesses,as well
as the commercial building specifications,are necessary
for the initial analysis of the commercial sector.Such
!/These conversion factors are fairly standard but will differ
dependent upon how one calculates them.In the case of coal and
wood,the estimates of MMBtu/ton and MMBtu/cord are taken from
[5a].The estimate for wood is the mean for dry birch and dry
spruce.
2/The eight.industries are:Hotels &~otels;Restaurants &Bars;
Wholesale Trade;Retail Trade;Shopping Centers;Auto Sales &
Service;Other Services;Entertainment.
E-9
3088A
raw data are available through a cooperative effort by the Borough
Planning Department,the Borough Environmental Services Department,
and the State Department of Transportation,based on Borough
Assessor's records.The intent is to locate each building within
the Fai rbanks area in order to project new development,ai r
qual i ty,traffic,etc.Si nce these data a1 so 'inc1 ude the square
footage of each building,it can be used for energy planning as
well.II .
A diligent attempt was made to include all nongovernment,non-
residential,nonmanufacturing buildings in the data base.Since the
total number of businesses for which 1978 energy consumption was
estimated totalled 1,823 and since the total number of nongovernment,
nonmanufacturing Fairbanks North Star labor reporting units listed for
the third calendar quarter of 1978 by the Alaska Department of Labor
was only 1,210;it appears that the 1978 report ,was comp1ete.l!For
these reasons,the 1978 Fairbanks Energy Inventory estimates have been.
accepted as the best avail ab1 e estimates of commercial sector energy
consumption at a point in time in Fairbanks.
The same report provided estimates of both delivered heating energy and
effective heating energy used in the Fairbanks commercial sector in
1978 [5b,Table 25].The total of 528,000 MMBtu of effective heating
energy,when divided by the Borough square foot estimate of space,
yielded an average for 1978 of 0.175 t+1Btu of effective heating energy
required per square foot of commercial office space.
The estimates of delivered energy used in 1981 shown in Table E-1 were
then constructed in six steps.
!!A IIreporting unit ll is a place of business at which at least one
worker is a salaried employee.Multiple locations for a given
firm count as multiple reporting units.Many buildings contain
more than one labor reporting unit.On the other hand,some
reporting units are housed in more than one building.
E-10
3088A
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Step 1 Estimates of the total commercial square footage to be heated
in 1981 were made for each of the eight industries covered by
the FNSB in the year 1978.For each industry these were
defined to equal 1978 square footage plus the estimated change
in square footage between 1978 and 1981,where the change was
based on the estimated percent change in the number of
establishments reported oy the Alaska Department of Labor for
that industry.ll
Step 2 The 0.175 MMBtu per square foot of effective heating energy
used was reduced by ten percent to allow for increased
conservation and reduced temperature settings.21
Step 3 A 1981 estimate of effective heating MMBtu·s used in the
commercial sector was constructed by'mu1 tiplyi ng the adjusted
per square foot heating requirement by the estimate of total
square feet to be heated.The result came to 514,000 MMBtu·s.
Step 4 As discussed below,59.1 percent of the 1981 commercial sector
heating requirement (effective MMBtu·s)was estimated to be
satisfied by burning fuel oil,21.2 percent by electricity,
and 19.7 percent by steam district heating.
Step 5 Employing average heating efficiencies of 65 percent for fuel
oil heaters-and 100 percent for district steam heating and
electric heating,the MMBtu requirement estimates of delivered
energy were obtained,and they are shown in Table E-1.
11 See [7].The Department of Labor data are not as yet available
for 1981.For all eight lIindustries"we defined the 1980-81
percent change to equal 2.0 percent.
21 There are no good estimates of this effect in Fairbanks.However,
given the large.number of energy audits conducted there,failure
to allow for at least some reduction in heating requirements per
square f90t since 1978 would likely be a more serious analytical
error than an assumption of ten percent.
E-11
3088A
Step 6 At MMBtu conversion factors of:0.138 MMBtu/ga110n for fuel
oil;0.0034 MMBtu/kWh for electricity,and 0.970
MMBtu/thousand pounds for steam,the MMBtu estimates of
delivered energy by fuel type were converte~into unit
estimates (also shown in Table E-1).
Lights and Appliances:According to data by the Alaska Power
Administration and published in [4],total residential electricity
sales by GVEA and FMUS in 1981 came to 159,000 megawatt hours.!!The
electricity consumption estimate of 65,000 MWh for residential lights
and appliances is the 1981 residential sales total less our estimate of
94,400 MWh for heating.
The 43,700 MWh estimate of e1 ectricity consumed in the commerci a1
sector for lights and appliances is the North Star Borough1s pUblished
1978 estimate plus an increment of 8.5 percent.The 8.5 percent
increment is the 1978-1981 percent change in commercial sector square
footage estimated above,in Step 1.
Direct estimates of the amount of propane used in the residential
sector to fuel lights and appliances could not be obtained.Available
national and Alaska estimates of the delivered energy used per capita
to power residential lights and appliances suggest an average of
between 5.0 and 5.5 MMBtu per person per year.2/The estimate was
set at the MMBtu level which brought Fairbanks total residential
delivered energy use for lights and appliances to 5.0 MMBtu per person
per year.The resultant 36,300 MMBtuls of propane energy (402,000
gallons),comes to 14.1 percent of the total residential delivered
energy estimated to have been used in 1981 for lighting and appliance
app1 icati ons.
!!GVEA -Golden Valley Electric Association,FMUS -Fairbanks
Municipal Utility System.
2/The Kake end use survey led to estimates of 5.4 MMBtu per capita
for Kake.National estimates also are in this range,for example,
[8],p.75.
E-12
3088A
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The similarity of the estimated percents using fuel oil is notable as
shown in the text table.
The estimate of commercial propane use is the Borough's 1978 estimate
[5b,p.45]with the value for cooking uses increased by the estimated
1978-1981 employment growth in the industrial category "eating and
drinking places"(11.5 percent).!/
All three of these surveys were designed solely to estimate the percent
of Fairbanks residences which used each of several fuels for primary
and supplemental purposes.2/Noneof the surveys attempted to
measure total consumption of each fuel type by end use.
BATIELLEY
66.5
8.8
15.2
3.0
4.0
2.5
FCAC
61.2
22.7
9.6
1.8
1.3
5.7
WOODCUTTERS
63.3
25.3
L8
1.3
0.5
0.2
PERCENT OF SURVEYED RESIDENCES
USING FUEL AS PRn~ARY HEATING SOURCE
1981
E-13
The 1978-1980 published Alaska Department of Labor rate with an
added 2.0 percent assumed for 1981.Alaska Department of Labor
[7]..'
The Battelle survey also requested information on fuels used to
power lights and appliances.
Weighted average of responses for space heating (85 percent
weight)and water heating (15 percent weight).
2/
3/
3088A
Fuel Oil
Wood
Electricity
Coal
Propane
Other
Estimating Fuel Shares:Heating:There have been three residential
end use energy surveys conducted recently in the Fairbanks North Star
Borough:(l)a 526 response survey conducted by the Interior
Woodcutters Associ ati on [6J,(2)a 616 response survey conducted by the
Fairbanks Consumer Advocacy Committee and tabulated in (5d];and (3)a
408 response survey conducted by Battelle Northwest as part of the
Rai 1be1 t El ectric Power A1 ternatives Study.
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Weighting each set of survey results by their relative number of
responses yields the following estimates of percent of Borough
residences using each fuel for primary heating:fuel oil (63.3
percent),wood (19.9 percent),electricity (10.5 percent),coal (1.9
percent),propane (l.2 percent),other (3.2 percent).
For purposes of this study,it was assumed that these percentages also
represent the respec-tive shares of the residential heating requirement
(effective MMBtu·s)satisfied by each fuel type.
No direct 1981 information is available for the commercial sector.The
FNSB 1978 Energy Inventory [5b,Table 25]showed that commercial sector
heating requirements were then supplied as follows:59.1 percent,fuel
oil;21.2 percent,electricity;and 19.7 percent,s~eam.Since 1978
..the average commercial price of electricity (¢/kWh)in Fairbanks has
gone from 5.5¢/kWh to 8.5¢/kWh,while the price of fuel oil has risen
from 55¢to $1.22 per gallon.!!Thus,the relative price of
commercial electricity has declined by approximately 30 percent.In
spite of this drop in relative price,electricity as a source of
commercial heating energy remains over twice as costly per effective
MMBtu as fuel oil in Fairbanks (Table E-2).The high 1981 relative
price of electricity argues against there having been an increase in
e1ectricity·s share of commercial heating between 1978 and 1981,
despite the decline in re1~tive electricity prices over that period.
Further,since 1978 there has been an annual average 2.5 percent
decline over this period in total electrical energy generated by GVEA
and FMUs.2/Faced with this eVidence,and in the absence of direct
data,the share of space heating and water heating energy requirements
met by electricity has been held constant at the 21.2 percent estimated
by the Fairbanks North Star Borough for 1978.
!!Price quotes are taken from [5aJ.
2/Alaska Power Administration [4j.
E-14
3088A
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TABLE E-2
FAIRBANKS NORTH STAR BOROUGH
ENERGY PARAMETERS USED IN THIS STUDY
Natural
No.2 Oi 1 Gas'Coal Wood E1 ectricity Propane Steam
Units Gallons 'MCF Tons Cords kWh Gall ons I ,000 Ibs
MMBtu's/Unit .138095 1.02 17.4 18.5 .003413 .090476 0.970
Heating Efficiency*.65 .75 .60 .55 1.00 .70 1.00
Unit Prices**(1982)1.22 62.50 96.25 .109 1.24 6.50
Prices Per
Efficiency MMBtu 13.59 5.99 9.46 31.93 19.58 6.70
*Efficiency of wood burning predicated on FNSB estimates for airtight stoves.
**Price Source:liThe Energy Report,II August 1982,Fairbanks North Star Borough Community
Research Center
No.2 Oil -January 1982 through August 1982 monthly mean;August
1982 =$1.216
Coal -Augus~1982,wholesale price per ton,2 tons delivered
Wood -August 1982,dry,split,delivered,mean of birch and spruce
Electricity -August 1982,1,000 kWh,mean of GVEA and FMUS
commercial and residential (rate with cost of power adjustment
for GVEA)
Propane -July 1982
Steam -July 1982
E-15·
26658
According to Keith Swartz of the Fairbanks Municipal Utility System,
152.3 million pounds of steam were sent into the district heating
system in 1981.Indications are that the 1981 steam sales to the
commercial market are not significantly different from the steam sales
to the commercial sector in 1978.11 The 1978 estimate for steam heat
as a percent of the total co~ercia1 heating market,ther~fore,also
has been held constant at 19.7 percent.The resultant 104.4 million
pounds of delivered steam heat,allowing for line losses and other
users,is consistent with the 1981 total FMUS production of 152.3
million.
Since fuel shares must sum to 1.0,retention,of the 1978 electricity
and steam shares of commercial heating requirements implies retention
'of the fuel oil share,59.1 percent.
Relative Prices:Information ~n the various energy parameters used in
this study (Btu content,heating efficiency),recent 1982 unit prices
for each fuel as delivered and the equivalent prices per effective
heating MMBtu for each fuel,is presented in Table E-2.The latter
prices are defined as the unit prices divided by K,where K is defined
as the product of the efficiency factor and the MMBtu's per unit.No
natural gas prices are presented because natural gas is not now
commercially available in Fairbanks.
Two points are 'worth noting.
(1)All fuels identified,except electricity,are fossil fuels.
Electricity itself is 100 percent fossil fuel generated in
Fairbanks (fuel oil and coal).
11 Commercial consumption has accounted for over one-half of all the
.steam generated for heat by FMUS.Thus one wou1 d expect that
signiflcant changes in commercial consumption would appear as
significant changes in total consumption.In 1978,FMUS received
payment for 130 million pounds of steam.Allowing for
transmission losses this figure is not greatly out of line with
1981's 152.3 million pounds of steam produced.
E-16
3088A
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(2)Given the very high relative price of electricity as a heating
fuel,and the fact noted above that its relative price was even
higher four years ago,it seems reasonable to assume that
residential and commercial users of electricity for space and
water heating purposes are either ignorant of the price
d;sadvantage they face,or have some other reason for preferri ng
electricity as an energy source for heating.
The following analysis and the projection of the conditional demand for
natural gas as a space heating and water heating energy source is based
on the assumption that the demand for natural gas is determined by its
price sUDstitutability for fuel oil.The real price assumptions used
by Battelle Northwest [2]and Acres American [1]assume for all real
fossil fuel prices except coal to escalate at 2.0 percent per year,
with coal prices escalating at 2.1 percent per year.Under these price
escalation assumptions,1982 relative prices remain essentially
unchanged throughout the forecast peri od,wi th the excepti on of prices
relative to electricity.However,even if real electricity prices are
assumed to remain constant,fuel oil prices per effective MMBtu remain
26 percent lower than corresponding electricity prices in the year 2010.
E1.2 THE CONDITIONAL DEMAND FOR NATURAL GAS IN FAIRBANKS
At this time,the minimum required price for natural gas,delivered to
residential and comercia1 users in tairbanks,has not been
determined.That price is a function of the wellhead price of gas,the
cost of conditioning the gas,the cost of transporting it to Fairbanks,
and the cost of distributing it within Fairbanks.It is based upon the
ability of system owners to achieve an acceptable rate of return on
their major capital investments.The purpose of this analysis,
therefore,is to estimate the demand for gas,conditional upon price.
These conditional gas demand forecasts are formulated under each of two
sets of economic assumptions.The first set includes those assumptions
buttressing Battelle Northwest's "low"electricity demand projection of
E-17
3088A
February 1982,while the second set includes those which buttress Acres
Americanls 1982 Il middle ll projection.lI With respect to the
e1ec tri city demand components,both the Batte11 e H1 OW II and the Ac res I
IImiddl ell forecast are products of the Rai1be1 t Electricity Demand
model,developed by the University of Alaska for the Rai1be1t Electric
P"ower A1 ternati ves Study.
For the foreseeable future,the increasing demand for electrical items,
such as new office equipment,electronic games,and electrical
appliances,has apparently convinced Battelle and Acres to forecast an
increasing per capita demand for electricity in A1aska l s Rai1be1t.In
contrast,it would be wholly inappropriate for us in this study to
project an increasing per capita demand for fuel oil or natural gas.
The relative price assumptions discussed the end of the proceeding
chapter indicate that one cou1 d not "reasonably project more than a
small fraction of the demand for premium fuels to be for purposes other
than space heating or water heating.2/
Rising fossil fuel prices have induced a reduction in effective heating
energy requi rements across the Uni ted States.Such conservati on does
not appear to have reached its technological limits.For this reason,
this study does not simply adopt the rates of per capita increase in
electricity consumption and apply them to natural gas d~mand.Instead
this study derives the underlying Battelle and Acres rates of Fairbanks
population growth and makes natural gas consumption projections a
function of constant unit consumed/person values.
1I See [1]and [2].
2/The potential demand for gas in Fairbanks will be estimated from
the point of view of its SUbstitutability for other fuels in
specific end uses.If natural gas were available in Fairbanks,it
undoubtedly cou1 d fuel some decorati ve 1ights and be used as a
cooking fuel in some kitchens.However,demand from these sources
is likely to be either very small relative to the demand for gas
as a heating fuel and unlikely to increase in per capital terms.
E-18
3088A
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The data bases to which these two equations were fit are the six sets
of simulation results given on pages 3.8 and 3.13 of the Battelle
report [2];and the nine sets of simulation results given in appendiX
Table A3 through all of that report.!!
Because the R2 values were very high,the results of this study are
consistent with the earlier work.2/In particular,the rate of
population growth (annual average)in Fairbanks that is consistent by
this definition with the Battelle 2.2 percent rate of growth in
Six Observations
.7237*Rai 1belt E1 ectricity Demand
(14.2)%Change x 100 1980-2010
=-.0326 +.9299*Rai1be1t Pop.
(-7.6)(6.0)%Change x 100 1980-2010
R2 =.9954 Nine Observations
=-.0192 +
(-9.6)
R2 =.9991
Fairbanks Pop.
%Change x 100
1980-2010
Railbelt Pop.
%Change x 100
1980-2010
(1)
1/Alaska Economics,Incorporated calculated the 30-year compound
annual average percent changes from the pUblished simulation results
and then ran the indicated regressions.
2/Although statistically significant,the constant terms in these
two equations are quite sma],l (2/100 of a percent and 3/100 of a
percent).The implied elasticity of Rai1be1t electricity demand
with respect to Railbe1t population growth is (a)constant and (b)
equal to 1.38.This statement was verified by running regression 1
in reverse.This analysis was performed even though the .999 R2
and near zero intercept assured the result.
(2)
Approximating the Rai1be1t Model:The Battelle and Acres studies
focused on the Rai1be1t as a whole.The Acres study,in particular,
provided relatively little detail for Fairbanks:In order for this
study to be confidently based on rates of Fairbanks population growth
that are consistent with the Battelle and Acres rates of growth of
Rai1be1t electricity demand,it was necessary to develop a mathematical
Dridge between the forecasted rate of growth of electricity demand in
the Rai1be1t and the forecasted rate of Fairbanks population growth.
The equations that accomplish this are given below.(All percent
changes are thirty-year compound annual averages,t-statistics in
parentheses.)
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Rai1be1t electricity demand is 1.43 percent.When 2.2 is SUbstituted
into the right-hand side of the first equation above,and the result is
SUbstituted into the right-hand side of the second equation,the figure
1.43 is determined.Similarly,the rate of population growth in
Fairbanks that is consistent with the 3.5 percent Acres rate of growth
of Railbe1t electricity demand is found to be 2.30 percent.
Framework for Analysis:The relative price analysis leads to the
conclusion that the potential cOllll1ercia1 and residential demand for
natural gas in Fairbanks is limited to 1}use as a substitute for fuel
oil in space heating and water heating;2}use as a SUbstitute for
electricity and propane in cooking;and 3}some incidental uses.
Accepting that the small quantity of gas that might be used to fire gas
lamps can be ignored,the relative magnitude of the demand for cooking.
can be compared to the magnitude of demand for heating.
According to the U.S.Department of Energy,a modern gas cooking range
for the home uses between 6 MMBtu's and 13 MMBtu's of fuel per year,
depending on its efficiency.The same source records that in 1980,
approximately 29 percent of U.S.households that had modern ranges used'
natural gas and the remaining 71 percent used electricity.!!With
natural gas prices scheduled for complete decontrol,it is reasonaole
to conclude that the niitionalaverage price of natural gas to
residential and commercial users will rise relative to the price of
electricity.If so,the present 29 percent market penetration
nationally may be an upper limit for the foreseeable future,especially
when one considers the growing attractiveness of combination electric
range-microwave ovens.
!!"Estimate of Average Annual Energy Consumption of Gas App1 iances,II
Consumer Products Efficiency Branch,U.S.Department of Energy,also
(same source)"Estimate of Average Annual Energy Consumption of
Electric App1iances."
E-20
3088A
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Unless the Fairbanks price of natural gas relative to electricity is
unusually low,possiblY much lower than it has been nationally,one
would not expect gas ranges to account for more than 29 percent of the
home cooking units in Fairbanks.The only change in this market
relationship would result from a major innovation not yet made,or that
a Fairbanks preference biased in favor of natural gas for nonprice
reasons.!!The market penetration could be lower for natural gas
than the estimated 29 percent.The Department of Energy's estimated
825 kWh consumption per year for a low efficiency conventional e1ec.tric
range in Fairbanks costs approximately $82.50 per year to operate
today.Even if gas were free,the cash savings that could be achieved
by switching from an electric range to a gas range would not be
SUbstantial.
The demand for gas as a commercial cooking fuel may be more price
sensitive,because the commercial volume of cooking fuel required per
user year is much greater than for home cooking.Based on the
available data and conversations with commercial suppliers of
eqUipment,it appears that propane is presently the preferred
commercial cooking fuel in Fairbanks.The 1978 Borough survey,for
example,estimated that 85 p'ercent of the effective commercial cooking
MMBtu's were supplied by propane.2/On the assumption that this
percentage is correct,we define the maximum volume of natural gas that
would be demanded for commercial cooking in Fairbanks to be equal to 85.
percent of the projected demand for effective commercial cooking
energy.Because this volume is quite small relative to the potential -
demand for gas in space heating and water heating (75,000 delivered
MMBtu's for commercial cooking in 1981 compared to nearly 3.5 million
MMBtu's for space and water heating)commercial cooking demand amounts
!!If the penetration percentage was 29 percent of the modern ranges,
it would clearly be no larger as a precent of all home cooking units.
2/See [5b].
E-21
3088A
to something approaching rounding error in these projections of the
total demand for natural gas.!!
Fi nally,it shou1 d be noted that the total 1981 max·imum potenti a1
demand for gas ~s a commercial and residential cooking fuel (delivered
energy)amounts to·137,800"MMBtu's or approximately 135,000 MCF.2/
This is only 4.6 percent of the estimated 1981 maximum potential demand
for gas as a heating fuel (approximately 3.1 BCF).Because this
percentage is so low,it is clear that the potential of natural gas as
a heating fuel is the critical factor in detennining the overall demand
in Fairbanks.
The Conditional Demand for Natural Gas:The 1981 maximum potential
demand for natural gas is defined as the estimated volume of fuel oil
and propane used in space heating,·water heating and cooking measured
in effective MMBtu's,and adjusted to delivered Btu's based upon
efficiency correction.
Tables E-3 and E-4 present conditional forecasts of the demand for
delivered gas in Fairbanks (a)if it is priced so as to penetrate 10
percent;(b)25 percent;(c)40 percent;and (d)100 percent of the
total heating and cooking fuel market;(i.e.,1981 combined fuel
oil/propane share).Maximum potential demand for the low growth
scenario in the year 1981+t is defined in Table E-3 as 1981 maximum
!!The 3 million MMBtu's is the sum of the 1981 commercial and the
1981 residential demand for fuel oil and propane for space and water
heating,see Table E-1.
2/We have added 75,073 (commercial)and 62,679 (residential).The
residential estimate is the product of the 1981 number of occupied
residences (22,751),the factor .29 representing gas cooking
penetration,and an average 9.5 r+1Btu per year gas usage per rang~.
The 9.5 MMBtu consumption estimate is the mean of the Department of
Energy's gas range estimate of 6-13 MMBtu per year.
E-22
3088A
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TABLE E-3
FAIRBANKS NORTH STAR CONDITIONAL GAS DB~AND
POPULATION GROWTH AT 1.43%
(Delivered Energy)
1985 1990 1995 2000 2005 2010
10%of Market
Residential (MMBtu)439512.8 471849.7 506565.8 543836.0 551612.9 626804.6
Commercial (MM8tu)80488.0 86409.9 92767.4 99592.7 106920.2 114786.8
Sum (MMBTU)520000.9 558259.6 599333.2 643428.7 690768.6 741591.4
Residential (MCF)430894.9 462597.8 496633.1 533172.5 572400.4 614514.4
Commercial (MCF)78909.8 84715.6 90948.5 97639.9 104823.7 112536.1
Sum (HCF)509804.8 547313.3 587581.5 630812.5 677224.1 727050.4
25%of Market
Residential (MMBtu)1098782.1 1179624.3 1266414.4 1359590.0 1379032.1 1567011.6
Commercial (MMBtu)201220.0 216024.7 231918.6 248981.8 267300.5 286966.9
Sum (MMBTU)1300002.2 1395649.0 1498332.9 1608571.8 1726921.4 1853978.6
Residential (HCF)1077237.4 1156494.4 1241582.7 1332931.4 1431000.9 1536285.9
Commercial (MCF)197274.6 211788.9 227371.1 244099.8 262059.3 281340.1
Sum (MCF)1274511.9 1368283.3 1468953.9 1577031.2 1693060.2 1817626.0
40%of Market
Residential (MMBtu)1758051.4 1887398.9 2026263.0 2175344.0 2206451.4 2507218.6
Commercial (MMBtu)321952.1 345639.5 371069.7 398370.9 427680.8 459147.1
Sum (MMBTU)2080003.4 2233038.3 2397332.7 2573714.9 2763074.3
2966365.7
Residential (MCF)1723579.8 1850391.0 1986532.4 2132690.2 2289601.5 2458057.4
Commercial (MCF)315639.3 338862.2 363793.8 390559.7 419294.9 450144.2
Sum (MCF)2039219.1 2189253.3 2350326.2 2523249.9 2708896.4 2908201.7
1981 Fuel Oil/Propane Share of Market
Residential (MMBtu)2834857.8 3043430.7 3267349.1 3507742.2 3557902.9 4042890.0
Comme rc i a1 (101MB tu )475684.2 510682.3 548255.5 588593.0 631898.3 678389.9
Sum (t'l1BTU)3310542.0 3554113.0 3815604.6 4096335.2 4397720.4 4721279.8
Residential (MCF)2779272.4 2983755.6 3203283.4 3438962.9 3691982.4 3963617.6
Commercial (MCF)466357.0 500669.0 537505.3 577052.0 619508.2 665088.1
Sum (l1CF)3245629.4 3484424.5 3740788.8 4016014.9 4311490.6 4628705.7
E-23
2665B
TABLE E-4
FAIRBANKS NORTH STAR CONDITIONAL GAS DEMAND
POPULATION GROWTH AT 2.30%
(Delivered Energy)
1985 1990 1995 2000 2005 2010
lOt of Market
Residential (MMBtu)45478704 509549.7 570906.2 1)39650.7 654362.7 802969.9
Commercial (MMBtu)83285.2 93313.9 104550.1 117139.3 131244.4 147047.9
Sum (t1~Btu)538072.6 602863.6 675456.3 756790.0 847917.4 950017.8
Residential (MCF)445870.0 499558.6 559711 .9 627108.6 702620.6 787225.4
Commercial (MCF)81652.2 91484.2 102500.1 114642.4 128671.0 144164.6
Sum (MCF)527522,2 591042.7 662212.0 741951.0 831291.6 931390.0
251£of Market
Residential (MMBtu)1136968.4 1273874.3 1427265.4 1599126.9 1635906.8 2007424.7
Commercial (MMBtu)108213~1 233284.7 261375.2 292848.2 328111.0 367619.8
Sum (MMBtu)1345181.6 1507159.0 1688640.7 1891975.1 2119793.6 2375044.5
Residential (MCF)1114674.9 1248896.4 1399279.8 1567771.4 1756551.6 1968063.4
Commercial (MCF)204130.5 228710.5 256250.2 287106.1 321677.4 360411.6
Sum (MCF)1318805.4 1477606.9 1655530.1 1854877 .5 2078229.0 2328475.0
401£of Market
Residential (MMBtu)1819149.5 20381~8.9 2283624.7 2558603.0 2617450.8 3211879.5
Commercial (MMBtu)333141.0 373255.5 418200.3 468557.1 524977.5 588191.7
Sum (I+\B~u)2152290.5 2411454.4 2701825.0 3027160.1 3391669.8 3800071.2
Residential (MCF)1783479.9 1998234.2 2238847.7 2508434.3 2810482.6 3148901.4
Commercial (MCF)326608.8 365936.8 410000.3 459369.7 514683.9 576658.5
Sum (MCF)2110088.7 2364171.0 2548848.1 2967804.0 3325166.4 3725560.0
1981 Fuel Ofl/Propane Share of Market
Residential (I+\Btu)2933378.6 3286595.7 3682344.8 4125747.3 4220639.5 5179155.6
Commercial (MMBtu)492215.8 551485.0 617891.0 692293.2 775654.3 869053.2
Sum (!flBtu)3425594.4 3838080.7 4300235.8 4818040.5 5398195.5 6048208.9
Residential (MCF)2875861.4 3222152.7 3610142.0 4044850.3 4531903.2 5077603.6
Commercial (MCF)482564.5 540611.6 605775.5 678118.8 760445.4 852013.0
Sum (t~CF)3358425.9 3162824.3 4215917.5 4723569.1 5292348.6 5929616.5
E-24
2665B
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E-25
given a delivered price of $1.22 per gallon for distillate.
!I In turn,the 1981 maximum is defined by the combined share of fuel
oil and propane.
2/See the previous section.
3/Since the ~ooking component is less than 5 percent of the total.
Residential
Conmercia1
$9.58 per MCF
$9.94 per MCF
Based on the energy parameters presented in Table E-2,assuming
different heating efficiencies,a $600 conversion cost,a 3.0 percent
real discount rate and a required five year payback period (recovery of
conversion costs),the 1982 delivered prices at which consumers would
be financially indifferent between gas and No.2 distillate as heating
fuel are:
Whether a reasonable forecast of the actual demand for gas in any
single year should be set equal to zero,10 percent of maximum,25
percent of maximum,40 percent of maximum,or 100 percent of maximum,
is a function of the price set for gas relative to the price set for
its primary competitor as a heating fuel,No.2 disti11ate.3/This
requires a comparison of the two prices on an efficiency adjusted,
MMBtu basis,with an allowance for the cost of conversion of heating
units from fuel oil to natural gas.In addition,one must also allow
for any financial constraints that may prevent consumers from taking
advantage of lower priced gas {should it indeed be lower priced},for
any willingness to pay a premium for I c1ean"gas,and for the
inevitable effect of inertia.
potential demand times the factor {l.0143)t.!I Maximum demand,as
presented in Table E-4 for the medium growth scenario,employs the
factor (1.023)t.The two annual average percentage rates of growth,
1.43 percent and 2.30 percent,are the rates of Fairbanks population
growth discussed previOus1y.2
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In other words,at these prices users would have no financial
preference for one or the other fue1.1/At gas prices below these
$9.58-$9.84/MCF,gas is economically attractive.Because the typical
household in Fairbanks requires 135 MMBtu·s of effective heating energy
per year and the typicai commercial establishment requires 264 MMBtu's
per year,2/the typical commerci al'user wou1 d recover conversi on
costs more quickly than would the residential user for a given set of
gas and distillate prices.Consequently,the IIbreakeven ll price of
natural gas for the representative commercial user is higher than it is
for the representative househo1d.3/
Because real fossil fuel prices are assumed to escalate at a 2.0
percent rate in the Battelle and Acres studies,the projected real
co~sumer IIbreakeven··prices of gas a1 so esca1 ate at thi s rate.In any
year,1982+t,the constant dollar (1982 $)consumer breakeven prices
are (1982 $/MCF):
9.58*(1.02)t Residential
9.94*(1.02)t Commercial
!I The formula for this calculation is (ignoring conversion costs):
breakeven price.of gas =1.22*(Btuga*Effga)/(Btufo*Efffo);where
1.22 is the price per gallon of fuel oil and where Btuga =
MMBtu/MCF =1.02,Btufo =MMBtu/ga11on =.138,Effga =.75,Efffo
=.65.
2/The per residence figure is the Borough·s/Alex Carlson's 1,502
gallons of fuel oil converted to MMBtu·s and adjusted for 65
percent efficiency (that is 1502*.138*.65).The per
establishment figure is the total effective 1981 MMBtu·s required
as calculated in Section 4.4.1.2 (514,000)dividea by the
estimated 1981 number of establishments (1,947).
3/Conversion costs vary considerably.The $600 estimate was
obtained by Alaska EConomics,Inc.,as an average of three
estimates kindly provided by different plumbing/heating firms.
E-26
3088A
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CONSUMER BREAKEVEN GAS PRICES*
(1982 $/MCF)
1985 1990 1995 2000 2005 2010
Residential 10.17 11.23 12.40 13.69 15.11 16.68
Commercial 10.55 11.65 12.86 14.20 15.68 17.31
*1982 $/MCF at which gas is estimated to breakeven with No.2
distillate priced at 1982 S/ga11on =1.22*(1.02)t,where t is the
number (year-1982).These prices allow for conversion costs of
$600*(1.02)t.That is,they assume conversion costs escalate at
a 2.0 percent real rate also.Breakeven prices would be slightly
higher if conversion costs accelerate only at the rate of inflation.
Lumpy Demand:Virtually all of the pUblished gas demand studies derive
price and income demand elasticities by applying statistical methods of
estimation to historical data bases.These studies employ nonzero gas·
sales over the entire period for which the data are available.No
studies have been found that analyze the price and income
responsiveness of gas demand over a transition period during which
natural gas is at first unavailable,and then enters the marketplace.
This renders previous empirical estimates of the price and income
e1 astici ti es of gas demand unusabl e for our purposes.Were a gas
service to be formed in Fairbanks,and a new equilibrium between gas
and other fuels established,one could reasonably turn to previous
'.analyses to obtain insigh.ts as to how the equilibrium shares of the
market wou1 d change wi th changes in relati ve fuel prices and real
income.The interest in this study lies in determining 1)the price at
which gas become competitive;2)in suggesting a reasonable upper limit
to the quantity of gas that could be sold;and 3)in providing at least
some guidance as to how much of a share gas would garner of the
potential Fairbanks market if it were priced at different percentages
below consumer breakeven levels.Tables E-3 and E-4,and the consumer
breakeven prices presented above satisfy the first two of these
interests •.Of necessity,our discussion of the third will be somewhat
limited and rather conjectural.
E-27
3088A
The introduction of a new product is almost always preceeded by a
detailed marketing research effort.It almost always sparks some form
of response from competitors (in this case,principally the producers
and suppliers of fuel oil).Because the content and success of an
initial natural gas advertising campaign,and the extent to which the
competition would be prepared to lower prices or engage in
counter-advertising cannot be predicted,a definitive estimate of the
share of the market that gas might capture cannot be made.lI What
can be presented are estimates of the 1982 present discounted value of
the five-year annual savings that would accrue to commercial and
residential users of gas for every 10¢by which the price of gas falls
below the consumer breakeven level,assuming fuel oil is the
competition.The results are shown in Table E-5.
Reading from Table E-5,if residentially sold gas is priced
approximately 62¢per MCF below consumer breakeven,that is at $8.96 in
1982 assuming a $1.22 per gallon price of fuel oil,the typical
residential user would realize a present value savings of $500 in
excess of the estimated $600 conversion'cost.If there is any
marketing magic to round numbers like $500 and $1,000,it might be
reasonab1 e to expect that gas wou1 d achieve significant inroads agai nst
fuel oil if it were priced to save residential users $500 over the cost
of conversion (say 10 percent of the total market),and might be
expected to approach dominance (say,40 percent of the total market)if
the savings reached $1,000 in excess of conversion costs ($1.24 below
breakeven or $8.34IMCF if fuel oil is $1.22 per gallon).
!!For reasons of corporate security,Fairbanks producers and
suppliers of fuel oil would be ill advised to identify and to
quantify their potential competitive responses.
E-28
3088A
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PRESENT VALUE ANNUAL SAVINGS IN EXCESS OF $600
Discount*Residential Commercial
.10 80.70 158.04
.20 161.40 316.08
.30 242.10 474.12
.40 322.80 632.16
.50 403.50 790.20
.60 484.20 948.24
.70 564.90 1106.28
.80 645.60 1264.32
.90 726.30 1422.36
1.00 807.00 1580.40
1.10 887.70 1738.44
1.20 968.40 1896.48
L30 1049.10 2054.52
1.40 1129.80 2212.56
1.50 1210.50 2370.60
1.60 1291.20 2528.64
1.70 1371.90 2686.68
1.80 1452.60 2844.72
1.90 1533.30 3002.76
2.00 1614.00 3160.80
2.10 1694.70 3318.84
2.20 1775.40 3476.88
2.30 1856.10 3634.92
2.40 1936.80 3792.96
2.50 2017.50 3951.00
2.60 2098.20 '4109.04
2.70 2178.90 4267.08
2.80 2259.60 4425.12
2.90 2340.30 4583.16
3.00 2421.00 4741.20
*The discount is the amount in dollars that natural gas is priced below
the consumer breakeven price for gas.
E-29
3088A
These statements are,of course,speculative.Furthermore,one must
expect some competitive response from fuel oil producers and
suppliers.Nevertheless,one can reasonably conclude the following
(all prices are 1982 prices).
1)Natural gas should be no higher priced than consumer breakeven if
one expects it to have a viable market.
2)In all likelihood,gas would need to be priced below $9.00/MCF
(1982 price)to obtain a significant market share,unless
Fairbanks users have a strong preference for IIc 1ean ll gas.!/
Similar statements SUbstituting prices raised at approximately the same
percent per year as competing fuels can be made for any year in the
forecast period.2/
Returning to Tables E-3 and E-4 these statements can be translated into
BCF quantity values.Assuming a price of fuel oil of $1.22/ga110n in
1982,
3)If gas were priced at approximately $9.00IMCF (1982 price)and
rose in price at the same rate as the price of competing fuel s,
and if this were to lead to gas garnering 10 percent of the total
market,gas demand would be approximately 0.5 BCF in 1985,rising
to 0.7 BCF in the year 2010 -Battelle 1I10w";or in the Acres
IImidd1e ll case,0.5 BCF in 1985 rising to 0.9 BCF in the year 2010.
!I We implicitly assume in our breakeven calculations,that potential
price reductions by fuel oil dealers are 1a~e enough to offset
the price advantage gas enjoys as a IIc 1ean ll fuel.
2/We say lIapprox imate1 y ll because the appropri at~rate of esca1 ati on
is slightly less than the rate·of increase of competing fuel
prices if conversion costs escalate more slowly than that rate.
E-30
3088A
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5)If gas were priced so as to completely displace fuel oil and
propane as heating and cooking fuels,demand would be !/
4)If the gas price were to be set at approximately $8.34/MCF,and
rose in price at the same rate as the price of competing fuels,and
if this were to lead to gas obtaining 40 percent of the total
market,gas demand woul d be approximately 2.0 BCF in -1985 rising to
2.9 BCF in the year 2010 (Battelle)or in the case of the Acres
results,2.1 BCF in 1985 rising to 3.7 BCF in the year 2010.
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Peres middle
Finally,
DELIVERED BCF
1985 2010---
3.2 4.6
3.4 5.9
3088A
6)The total market (all fuels)if garnered by gas would amount to
Monthly Peak vs.Total Annual Demand:In the absolute,and as a
percentaye of the annual total,monthly'heating degree days in
Fairbanks average:2/
Battell e low
Ac res mi ddl e
DELIVERED BCF
1985 2010---5.1 7.3
5.3 9.3
E-31
As shares of the total market these would be 64.5 percent
(residential heating/cooking)and 59.1 percent (commercial
heating/cooking)•
National Oceanic and Atmospheric Administration.2/
1/
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Heat loss per unit of time between a structure and the outside is
directly proportional to the temperature differential and inversely
proportional to the amount of insulation between the two.In a
uniformly insulated structure,we have approximate1y:l/
1866 2337
13.0 16.3
549.211
3.8 1.5
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DEC
JUNE
NOV
MAY
OCT
1234
8.6
APRIL
1083
7.6
618
4.3
SEPT
1720
12.0
MARCH
AUG
304
2.1
1890
13.2
FEB
2384
16.6
JULY
148
1.0
JAN
Heating
Degree Days
%of Total
Heating
Degree Days
%of Total
where k is a thermal conductivity constant that declines as the
structure~s insulation increases;
T1 is the mean daily outside temperature in degrees;
T2 is the mean daily inside temperature in degrees;
L is the length of the path travelled by the heat.
Applying this formula one can approximate month to month consumption of
heating energy by defining July requirements as a reference level and
calculating relative heat loss from the formula above based on the
percentage difference between the number of heating degree days in a
given month and the number of July heating degree days.
11 See Lunde,Peter J.,Solar Thermal Engineering,(John Wiley and
Sons,New York)1980,pp.18-19,or one of many similar texts.
E-32
3088A
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This yields the percentages given above.
Applying these monthly fuel requirement percentages to our annual
projections of natural gas demand we derive the monthly peak demands
for methane (delivered MCF)shown in Table E-6.!/
Improved Efficiency:The results of this study are premised in part on
average heating efficiencies of 65 percent for fuel oil burners and 75
pecent for gas burners.Improved efficiency can be achieved for both
types of units.If heating efficiency improves,delivered energy
requirements decline.If one wishes,one can multiply our forecasts of
delivered MMBtuls by the factor (.75/Effga)to obtain an I'adjusted ll
efficiency forecast,where Effga is some alternative estimate of gas
heating efficiency.
!!Cooking energy is spread in the same proportions as heating
energy,a minor lIerrorll given our estimate of cooking demand
relative to the total (about 5%).
E-33
3088A
January,1985 January,201 0
Battelle IILow"
10%of .Market 117,255 167,222
25%of Market 293,138 418,054
40%of Market 469,020 668,886
1981 Fuel Oil/Propane Share 746,495 1,064,602
100%of Market 1,172,550 1,672,215
Acres l'-1i dd1 e"
10%of Market 121,330 214,220
.25%of Market 303,325 535,549
40%of Market 485,320 856,879
1981 Fuel Oil/Propane Share 772,438 1,363,812
100%of Market 1,213,300 2,142,198
3088A
TABLE E-6
DELIVERED ENERGY,PEAK DEMAND MONTH
.(MCF)
E-34
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E2.0 REFERENCES
[l J Alaska Power Authority,IISusitna Hydroelectric Project,
Feasibility Report,11 Volume 1,1982 (prepared by Acres
American,Inc.).
[2].Battell e Pacific Northwest Laboratories,IIRai 1be1 t E1 ectric Power
Alternatives Study:Evaluation of Rai1be1t Electric Energy
Plans,1I February 1982 (prepared for the Alaska Office of the
Governor)•
[3]COllUllun;ty and Regional Affai rs,A1 aska Department of,Al aska
Taxable 1981,(Di.vision of Local Government Assistance).
[4]Energy,U.S.Department of,Alaska Power Administration,Alaska
Electric Power Statistics;1960-1981,7th edition,August 1982.
[5]Fairbanks North Star Borough,Community Research Center:
(a)The Energy Report,August 1982.
(b)1978 Fairbanks Energy Inventory,July 1979.
(c)Community Research Quarterly,Summer 1982.
(d)The Energy Report,June 1982.
[6]Interior Woodcutters Association,IIFue1 Wood Utilization'in
The Fairbanks North Star Borough,II report of a survey
conducted November 1981 through January 1982.
[7]Labor,Alaska Department of,Statistical Quarterly,1978:3
and 1980:3 (Research and Analysis Section).
[8]Resources for the Future,Energy in Americals Future,(John
Hopkins Press,Baltimore),1979.
[9]Revenue,Alaska Department of,Petroleum Production Revenue
Forecast,Quarterly Report September 1982 (Division of
Petroleum Revenue).
E-35
3088A
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APPENDIX F
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APPENDIX F
OFFICE OF MANAGEMENT AND BUDGET
DRAFT REPORT COMMENTS
AND
ASSOCIATED RESPONSES
F-l
Conceptual
While this report provides substantial amounts of new
data and technical information,it does not constitute
a feasibility level analysis of the North Slope
natural gas alternative.A feasibility study generally
includes a cost-of-power analysis,based on a plan of
finance,and a comparison with alternatives.While
the information provided is extensive,such comparisons
are not and cannot be made.As such,the study more
closely fits the definition of a reconnaissance level
analysis.
Given the aforementioned,a second issue may be most
appropriately addressed at the next stage of analysis.
This study has as its focus an electric generation
facility based on North Slope natural gas which is
to supply the entire Railbelt electrical demand.
This concept follows the Susitna plan of completely
displacing existing facilities based on Cook Inlet
natural gas.The size of any element of the Railbelt
supply network will depend on its relative competi-
tiveness.There is no justification for assuming
that anyone supply source must be capable of deliv-
ering the-entire load.In fact,it appears that a
major drawback to Susitna is that it is too large
and too in~lexible.An optimal supply system will
RECEIVED
U~'f 17 1983
ENVIROSPHERE COMPAN'
SEAT'flE
Ebasco Draft Final
Report
Harch 29,1983
465-3573
DATE:
FILE NO.
SUBJECT:
Robert Mohn
Alaska Power Authority
Anchorage
Gordon Harrison,Associate
Director TELEPHONE NO:
Division of Strategic Planning
Ronald D.Ripple ~~v..R
Division of Strategic Plannig
Office of Management and Budget
The work performed thus far by Ebasco Seryices Inc.
on the use of North Slope natural gas for Railbelt
electrical and heating end-use adds significantly to
the data bank on Railbelt alternatives and to
alternative uses of North Slope natural gas.
My review will address conceptual issues first and
then technical issues.
MEMORANDUM
TO
FROM:
THRU:
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take into consideration the relative competitiveness
of all s\lpply sources and balance the size of each"
element on this basis.Cook Inlet natural gas is
close to the primary load center,plentiful,and
likely to very competitive with North Slope natural
gas for Railbelt electricity.Therefore,it does
not appear reasonable to eliminate Cook Inlet natural
gas fired genera.tion out-of-hand.
Technical
1.As discussed during our recent phone conversation,
the transmission line costs appear excessively
high.I understand that these costs are being
reviewed and an independent estimate has been
s~licited.
2.The Alaska Power Authority economic parameters
call for the use of a 3.5%real discount rate,
not 3.0%.
3.The text implies that the cost figures have been
discounted back to 1982.~ey have been discount-
ed to 1983.While it is in fact 1983,for
comparability,the 1982 figures would be useful,
and the tables do not represent the text.The
one year discounting differential makes about a
3%difference.This'is well within the 15%
contigency applied to most cost elements.How-
ever,the transmi ss ion--rIiies,wh ich account for
the bulk of the costs in the North Slope genera-
tion alternative,have no contigency attached.
4.Given the unusual nature of the transmission line
from the North Slope,i.e.,the length,terrain
and conditions,it would seem appropriate to
attach a contigency factor'to this element.
5.The handling of transmission line 0 &M is curious.
First,the annual average cost is approximately
1%of the total construction-cost.There is no
justification provided for using the 1%factor.
Second,it is noted that "Actual 0 &M costs
should be less initially,and increase with
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time."(po 2-32).However.Ebasco uses a flat
average annual cost.This has the tendency to
increase the present value of costs relative to
a stream of costs which increase over time.
6.Why was the 1260 psi pipeline scenario ch~osen?
This follows the ANGTS design.but justification
is not given.The TAGS design calls for an oper-
ating pressure o~1660 psi.In the TAGS report
(p.13)it is noted that while the higher pressure
line required thicker wall pipe the reduced
diameter lead to less weight per mile in pipe.
Presumably less steel will imply less cost.
This should be looked into.
Harch 29.1983-3-Ebasco Draft
7.Chapter 4 values for natural gas consumption in
2010 for a combined cycle facility show a 20 Bcf/
year savings over the simple cycle in Chapter 2.
At an unescalated price of $1 per mcf the saving
over the entire period is about $98 million.in
1982 dollars discounted at 3%.This is a subst-
antial saving.Moreover.in non-discounted
dollars.the savings in 2010 and beyond is $20
million annually.Why then is the simple cycle
chosen for the North Slope?
8.The relative capital costs between locations seem
out of line.Reference Table B4-2.Both the
North Slope and the Kenai location can make use
of barged.modular units which are constructed
in the 10wer-48 at lower labor and materials
cost.Fairbanks.on the other hand.cannot make
use of modular construction.The materials mus"t
be shipped from the lower-48.transported overland
and construction performed at the Fairbanks
site.Given this difference.it is surprising
that the Fairbanks facilities are the least
costly.especially when compared to Kenai.
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Please feel free to contact me if you have any questions.
cc:Lennie Boston
George Matz
9.Errors in representation of natural gas prices
still remain in Appendix.B.Reference p.B4-1 •.
The $5.50 export price is the Japan landed price,
not an ex-Alaska price.Also,Battelle's $5.92
per MMBtu is for Fairbanks,not Anchorage.
Ebasco Draft -4-March 29.1983 r
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RESPONSES TO OFFICE OF MANAGEMENT AND BUDGET QUESTIONS
CONCEPTUAL
We concur that this study does not constitute a feasibility level
analysis.The purpose of the study was to select the most appropriate
types of facilities for utilization of North Slope gas,to optimize
their scale and general configuration,and to estimate facility costs
at a reconnaissance level.The system studies undertaken were designed
.to complement this purpose,not formulate a complete power supply
system for the Rai1belt.The facilities described in this study will
be time phased and incorporated into comprehensive power supply plans
in the course of other power planning activities.These other
activities are not being limited to a single supply source and are not
dismissing Cook Inlet natural gas.
TECHNICAL
1)Ebasco's transmission line cost estimates reflect the unique
project setting and the system stability and reliability required.
The line will represent the major electrical service for the entire
state.Heavy duty towers (48 ton)and associated equipment were
required based upon high wind loadings (up to 130 mph),extreme
radial ice loadings (1.5 inches),and reliability requirements.
These design specifications were confirmed based upon discussion'
withARCO electrical engineers and their Prudhoe Bay experience
(ARCO operates 75 miles of 13.8 kV lines in this arctic
environment).Such specifications significantly increase costs.
The environmental and topographical constraints in the Kenai to
Anchorage transmission system required a submarine cable crossing
near Turnagain Arm.This served to increase the 1ine's cost.
Several construction factors also raised costs,inclUding the,
extreme remoteness of much of the routes,the very narrow time
window for construction,and compressed construction schedules due
to climatic conditions.
4045A
F-5
The Power Authority has solicited an independent cost estimate
which will be reported as an addendum to this study.
2)Current Power Authority economic parameters do use a 3.5~real
discount rate.A real discount rate of 3.0~was however previously
utilized by Acres American Inc.in their Susitna Hydroelectric
Project Feasibility Studies and by Battelle Pacific Northwest
Laboratories in their Railbelt Electric Power Alternatives Study.
The 3.0%rate was therefore utilized in this study to facilitate an
economic comparison with these previous efforts.
3)Discounting back to a specified year is a matter of convention.
Two conventions exist regarding whether the beginning or end of the
year is used as the point of cash flqw occurrence.We used the end
of year convention.The statement of the problem implies a
realization of the answer,and as noted,the difference (3%)is
well below the contingency included in each cost estimate.
4)A l5~contingency is included in the transmission line cost
estimates.It is factored into each bid line item cost.Please
refer to the notes cited in each table.
5)Based on Ebasco's experience,the one percent value is suitable and
appropriate for these transmission systems.It is derived from
Ebasco's transmission line experience and an analysis of recent
cost data supplied·by several local Alaskan utilities.It should
be noted that the effect on present value from the average
annualization of transmission line O&M costs is insignificant.
6)ANGTS was chosen as the convention because it is the proven,
licensed ~echnology.The Trans Alaska Gas System proposes some
unique design features which will have to be evaluated during
detailed engineering.
4045A
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7)Simple cycle is favored because of the added comp1eKity of
operating boilers on the North Slope with attendant water supply,
water treatment,water chemistry control and other more specialized
maintenance requirements of the higher temperature steam cycles.
In addition,spare parts requirements increase due to the addition
of the steam turbine cycle and other equipment.It was,thus,felt
that the technical advantages of the simple cycle unit outweighs
the slight economic edge of combined cycle.This decision is
explained in Appendix 8.
8)Factors such as water requirements and emissions standards (e.g.,
nitrogen oxides)cause variations in capital expenditures at
different locations.A water supply and water injection system to
control nitrogen QKides was assumed for the Kenai location.These...
systems were not included in the Fairbanks plant due to ice fog
problems.Please refer to our discussion of air quality concerns
in Chapters 4.0 and 6.0.
9)The discussion of natural gas prices presented in Appendix 8 (Page
84-1)briefly summarized our rationale for choosing the price range
utilized in our sensitivity analysis,i.e.,$0.00 through $5.50 per
MMBTU.The sensitivity analysis was performed to support our
recommendation of the most appropriate technology for each stUdy
location.There is no error in'representation.The $5.50 cited is
a direct quote from one of our contacts listed in Appendix A.If
this price is the Japan landed price as suggested it makes little
difference to the discussion.The Governor's Economic Committee
report estimates LNG shipping costs at $1.00~BTU in 1988 dollars
Which would be $0.66 in 1982 dollars when using the Committee's
reported economic parameters.SUbtracting $0.66 from $5.50 yields
$4.84.The $5.92 is for Fairbanks and not Anchorage.The text has
been corrected on this point.To further justify our range and our
recommendations,the following LNG costs are cited in the
Governor's Economic Committee report (see pages 43,44 and 45 of
the Economics Section);calculated 1982 values are also presented
for compari son.
4045A
F-7
F-8
4045A
In addition it should be noted that the majority of North Slope gas
which is reinjected has a negative wellhead price.The value
(delivered cost)of the small amount sold to Alyeska varies
somewhat in time but was about $1.86/MMBTU when the report was
written.
In light of the above cited prices it could possibly be argued that
the price range used in our sensitivity analyses should have been
expanded to include negative values and values greater than $5.50.
To do this,however,would not have increased the utility of the
analysis as the combined cycle technology was always favored when
natural gas prices were above about $1.50/MMBTU.
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$5.94 to $7.91
$3.95 to $5.27
Phase 1 System
LNG Tariffs
South Alaska
($/MMBtu)
$4.67 to $6.16
$3.11 to $4.10
Total System
LNG Tariffs
South Alaska
($/MMBtu)
1988
1982