HomeMy WebLinkAboutAPA2367JUl a 5 -
SOUTHCENTRAl RAIlBELT AREA.ALASKA
UPPER SUSITNA RIVER BASIN
SUPPLEMENTAL FEASIBILITY REPORT
APPENDIX -PART II
Section G-Marketability Analysis
Section H -Transmission System
Section I -Environmental Assessment for
Transmiss on System
Prepared by the
Alaska District,Corps of Engineers
Department of the ArmY
February 1979
SECTION G
MARKETABILITY ANALYSIS
United States Department of Energy
Alaska Power Administration
(j).:".';,..•.......-.~~c.
,
Department Of Energy
Alaska Power Administration
P.O.Box 50
Juneau.Alaska 99802
Colonel George R.Robertson
District Engineer
Corps of Engineers
P.O.Box 7002
Anchorage,Al~ska 99510
Dear Colonel Robertson:
April 2,1979
This is Alaska Power Administration's new power market report for the
Upper Susitna Project.It's an update of the previous power market
ana1ys~s provided for the Corps'1976 Interim Feasibility report.
The power market report includes:a new set of load projections for the
Railbelt area through year 2025 and a review of alternative sources of
power.Load/resource and total power system cost analyses were prepared
for different scenarios under various assumptions to determine effects
on power rates.
Under the assumptions made for this report,Alaska Power Administration
determines that the UpperSusitna Project is feasible from a power
marketing standpoint.
A draft of this report was circulated to the area utilities and con-
cerned State officers for informal review and comment.Comments have
been incorporated and the letters of comments are appended.
Sincerely,
"';"
.'.-',/',;C'-:,i.C~'i&'2...----~
Robert J.Cross
Administrator
"llII\••OtI
CON'TENTS
Introduction ,..
National Defense "..
Data '..
Al ternatives Considered •••••••••••••••••••••••••••••••••
PAGE NO.
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... ...... ...... ...... ........ ...."..
Lo cat ion._ -1
0
••••
Capaci ty , '.
Inves tment Costs -.
Coal
Fuel Cost and Availability .
Cost of Power •••.••••••••••.••••••••••••••••••••
Comparative Cost of Power (FERC)••••.•••••••••••
Oil and Natural Gas •••••••••••.•••••.••••••••••••••••
Hydro '--- .
Cri teria .
Summary .
Single Large Capacity Sites •••••••••••••••.•••••
Combinations of Small Capacity Sites ••••••••••••
Introduction '1'1 ..
PART VI -ALTERNATIVE·POWER SOURCES •••••••••••••••••••••••
Utili ty •••••••••.••••••••••••••••••••••••••
National Defense •••••••••••••••••••••••••.•
Self-Supplied Industry •••••••••••••••••••••
Estimate of Future Demands •••••••••••••••••.••••
Comparison With Other Forecasts •••••••••••'•.••••
Load Dis tribution •••••••••••••••••••••••••••••..••••••••
Capaci ty Requirements •••••••••••••••••••••••••••••••••••
Population ..
Utility _.
Analysis
PART V -PO~R REQUIREMENTS •••••••••••••••.•••••••••••••••
PART II -S~RY ..
PART III -POWER MARKET AREAS •••••••••••••••••••••••••••.•
Anchorage-Cook Inlet ••••••.•••••••••••••••••••••••••••••
Fairbanks-Tanana Valley ••-•••••••••••••••••••••••••••••••
Self-Supplied Industry •••••••••••••••••••••••••••••••
Energy &Power Demand Forecasts •••.•••.•••••••••.•••••••
Assumptions and Methodology .
PART IV -'EXISTING POWER SYSTEMS ••••••••••••••••••••••••••
Utility Systems and Service Areas ••.•••••••••••••••••.••
National Defense Power Systems ••••••••••••••••••••••••••
Indus trial Power Sys tems ••••••••••••••••••••••••••••••••
Existing Generation Capacity ••••••••••••••••••••••••••••
P 1anned Generation Capacity ••••••••.•••••••••••••.••••••
PART I -INTRODUCTION ••••••••••..••••••••••••••.••••••••••
TITLE
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A:verap"€,R,..e uet~nUJ;1..ar..J..on ..••'..••..•• •••••••••..•.••..•....••'.••..•'.'Barkeq ·..."i;'(',..:.ct~a '·'Orf!.iiI::"i-'"Trr,n,;."',"r -,'.~·v 1 .,.~•.Power 1:1ar.1te.tlI1g.a onsJ".ae-r<t.tf6tfs'·.;-.~.•..;'...-;•.-';'•.'.'.'.':,'•.'~nCt1f.:t'<'oe-Go".l(..:r:nl.:-'~'.'.~"'''M,a,IRet,As;g€ctsor .ume-t '!'tktrsntl!:i:Sictrt '/{~terngt:i:ves'.'.'''''''o':1..,.!,,;;u"1par~lSG1.l.ot Sus.1.)-1.""'!1':,.1>(1 '"<"r,!';.;l r;=!"1 I:r;;:,:.'\f ':'..'<',;:,~}t.['1·')1.1'1'_.a.n~or::a~e-CooK Tn eCAi'eit •~':.,'••••'.:•••'~'.:.'.;'::.~••••coJ~AJfrJJr?dof'Susifrla'td'Sfea:mp J:a:rt'Ls1Utlf and 'W'±thout .,.•
ii
1\._--------------------------
~.'
2.Previous Studies and Bibliography.
3.LOAD/RESOURCE AND SYSTEM COST ANALYSIS FOR THE RAILBELT REGION
OF ALASKA:1978-2010 --Informal Report--by Battelle Pacific Northwest
Laboratories,Richland,Washi~gton -January.1979.
4.Comments.
a.Federal Energy Regulatory Commission,San Francisco,California.
b.Battelle Pacific Northwest Laboratories,Richland,Washington.
c.Corps of Engineers,Anchorage,Alaska
d.The Alaska State Clearinghouse,Juneau,Alaska
e.Municipal Light and Power,Anchorage,Alaska
iii
TABLES
NUMBER PAGE NO.
1.
2.
RAILBELT AREA GENERATION CAPACITY SUMMARY -1977
BASIC POWER AND ENERGY FORECASTING DATA
ANCHO~~GE-COOK INLET AREA (INCLUDING SEWARD)
14
18
3.BASIC POWER AND ENERGY FORECASTING DATA
FAIRBANKS-TANANA VALLEY AREA ••..••.••••••.•.••..••..••19
4.BASIC POlfER AND ENERGY FORECASTING DATA
RAILBELT AREA (ANCHORAGE-COOK INLET AND
FAIRBANKS-TANANA VALLEY)..•••••.•••••.••••..•.•.•••..•20
5.NET GENERATION (GWH)
ANCHORAGE-COOK INLET AREA ......to •••••••••••••.PO .21
6.NET GENERATION (GWH)
FAIRBANKS-TANANA VALLEY AREA ••...••...••....•...••.•.•
7.AVERAGE ANNUAL UTILITY GROWTH SUMMARY •.•..••••••..•.•.
8.POPULATION ESTIMATES 1980-2025 •.....••.•....•.•..•..•••
22
26
34
9.NET ANNUAL PER CAPITA GENERATION (K\{H)
RAILBELT AREA UTILITIES •••.•.••.•.••......••....•....•39
10.POWER AND ENERGY REQUIRE~lliNTS
(ANCHO~~GE-COOK INLET AREA)••..•....•.••••.•.••.....••40
~\
11.POWER AND ENERGY REQUIRE~NTS
(FAIRBANKS-TANANA VALLEY AREA)43
12.RAILBELT ~EA POWER AND ENERGY REQUIREMENTS
ANCHORAGE-COOK INLET AREA AND FAIRBANKS-TANANA VALLEY
AREA COMBINED ..•••••.........•.••.....••..••........••46
13.COMPARISON OF UTILITY ENERGY ESTIMATES,
1975 MARKETABILITY REPORT,UPDATE OF 1975,
AND 1978 ANALYSIS •..••••••••.••••....••.....•..••.•.••49
14.UTILITY ENERGY FORECASTS (GWH)
ANCHORAGE-COOK INLET AREA .•••••••••••...•••..•.•.•.•••52
15.UTILITY PEAK DEMAND FORECASTS (MW)
ANCHORAGE-COOK INLET AREA •..••••••••.•••••....•....•..53
16.UTILITY ENERGY AND PEAK DEMAND FORECASTS
FAIRBANKS-TANANA VALLEY AREA ••.•..••....•..•..•.•••...54
iv
TABLES (Continued)
NUMBER'PAGE NO.
17.LOAD DISTRIBUTION CHARACTERISTICS
MONTHLY PEAK LOADS AND LOAD FACTORS ...................................59
18.MONTHL Y ENERGY REQUIREMENTS AS PERCENT OF ANNUAL
REQUIREMENT .........•••.........•................••...60
19.COMPARISON OF INVESTMENT COSTS FOR COAL-FIRED
STEAMPLANTS ....•.•...........•....••..................65
20.GENERATION COSTS FOR CONVENTIONAL COAL-FIRED
STE.Al1.PLANTS 69
21.SUMMARY OF THERMAL GENERATING CAPACITY ADDITIONS TO
THE YEAR 2010 .....•••....•..............•...•.........78
22.ANNUAL POWER SYSTEM COSTS :..0%INFLATION
(COMBINED ANCHORAGE-COOK INLET AND FAIRBANKS-TANANA
VALLEY AREAS)...•......•...•.••..•....•...............81
INVESTMENT COST SUMMARY ......••.••••••...•.•.•..•.•...88
REPLACEMENT COSTS •.....•.•.•...•••.•....•....•.•..••..96
.INVESTMENT AND OM&R COST SUMMARY 100
OPERATION AND MAINTENANCE COST SUMMARy................95
99
CONSTRUCTION COST SUMMARy.............................87
ANNUAL OPERATION AND MAINTENANCE COST ESTIMATE .'.'. • . . .92.
MARKET FOR UPPER SUS ITNA POWER (ANCHORAGE AND
FAIRBANKS AREAS)MEDIUM LOAD GROWTH ESTIMATES
COST SUMMARY COMPARISON WITH 1976 INTERIM
FEASlB ILITY REPORT ........•..................•.••••.••103
AVERAGE POWER COSTS ANCHORAGE-COOK INLET
AREA -0%INFLATION •.••..•..•....'.. . . . . . • . . . •. •. . . . . ••83
AVERAGE POWER COSTS -0%INFLATION
FAIR13ANKS-TANANA VALLEY AREA ...•...•..•..•..•......•..84
COMBINED ANCHORAGE-COOK INLET AND FAIRBANKS-TANANA
VALLEY'AREA AVERAGE ANNUAL POWER COSTS .••..••...•.••..85
AVERAGE RATE DETERMINATION
(WATANA AND DEVIL CANYON)......•..•............•••.•.•104
23.
24.
24a.
25.
26.
27.
28.
29.
30.
31-
32.
33.r-.
v
NUMBER
TABLES (Continued)
PAGE NO.
34.HISTORIC DATA (GLENNALLEN-VALDEZ AREA).......•.•..•...111
35.UTILITY NET GENERATION (GWH)
(GLENNALLEN-VALDEZ AREA)••••........•..••...••....•..•112
36.UTILITY FORECASTS (VALDEZ-GLENNALLEN AREA)..•••....•••113
37.TRANSMISSION SYSTEM INVESTMENT COST SUMMARY
(GLENNALLEN-VALDEZ AREA)•.••.••.•..•.....•••.•.•...•..114
38.TRANSMISSION SYSTEM OPERATION,MAINTENANCE,AND
REPLACEMENT COST SUMMARY (GLENNALLEN-VALDEZ AREA)115
vi
~.
I
FIGURES
NUMBER PAGE NO.
1.UPPER SUSITNA RIVER BASIN PROJECT
FEATURE SITE LOCATION •..••......•.•....•.•.••••..•.•..viii
2.UPPER SUSITNA RIVER PROJECT AREAS PRESENTLY
SERVED BY RAILBELT UTILITIES .•.•••.•••..••••••..•••.••11
3.ENERGY SECTOR RATIOS ANCHORAGE-COOK INLET AREAS AND
ANNUAL ENERGY GENERATED OR SOLD ANCHORAGE-COOK INLET
AREA 27
4.ANNUAL ENERGY USE PER CAPITA &PER CUSTOMER
ANCHORAGE-COOK INLET AREA •.•.•••••.•.•••••••••.••••.••28
5.ANNUAL POPULATION.EMPLOYMENT.AND UTILITY CUSTOMERS
ANCHORAGE-COOK INLET AREA •••.•.••.••.••••..••••••••.••29
6.ENERGY SECTOR RATIOS FAIRBANKS-TANANA VALLEY AREA
AND ANNUAL ENERGY GENERATED OR SOLD FAIRBANKS-TANANA
VAL-LEY 'AREA 30
ENERGY FORECAST ANCHORAGE-COOK INLET AREA ....•.••.••..41
PEAK LOAD FORECAST FAIRBANKS-TANANA VALLEY AREA .••.•••45
TOTAL RAILBELT AREA ENERGY FORECAST •....••.•••.•••••••47
ANNUAL ENERGY USE PER CAPITA AND PER CUSTOMER
FAIRBANKS-TANANA VALLEY AREA ••••.•••••••...•.~........31
42
44ENERGYFORECASTFAIRBANKS-TANANA VALLEY AREA
ANNUAL POPULATION.EMPLOYMENT.AND UTILITY CUSTOMERS
FAIRBANKS-TANANA VALLEY AREA .•••.•.•.••••.•.•..••.••..32
PEAK LOAD FORECAST ANCHORAGE-COOK INLET AREA
~7.
8.
9.
10.
II.
12.
13.
14.TOTAL RAILBELT AREA PEAK LOAD FORECAST ••.•••••••••.•..48
15.SYSTEM DAILY GENERATION CURVE ANCHORAGE AREA 1976 •.••.56
16.SYSTEM DAILY GENERATION CURVE ANCHORAGE AREA 1977-78 ••57
17.LOAD DURATION CURVE -1977 ANCHORAGE AREA 58
18.ANNUAL POWER SYSTEM COSTS WITH AND WITHOUT SUSITNA
COMBINED ANCHORAGE-COOK INLET AND FAIRBANKS-TANANA
VALL EY '.;/82
19.COMPARISON OF SUSITNA AND ALTEfu~ATIVE COAL-FIRED
STEk~LANT RATES CONSIDERING 5%ANNUAL INFLATION 107
vii
Figure 1
APA 12/78
viii .
."""'\.
,...5 __...·~(
PART I.INTRODUCTION
The Interim Feasibility Report of the Upper Susitna River Basin Project
(1976 report)was completed by the Alaska District Corps of Engineers
(Corps)in 1976.Alaska Power Administration (APA)provided the trans-
mission system and power market analyses for that report.
The Corps submitted the 1976 report to the Office of Management and
Budget (OMB)for review.In September 1977,OMB requested the Corps
obtain additional data before submitting the report to Congress.The
requested data were to:(1)provide additional geologic data for the
Watana damsite;(2)*reana1yze the cost estimate contingency factor;(3)
reanalyze area development benefits;and (4)reanalyze the projected
cOllstruction schedule.There were also questions about power supply and
demand,including sensitivity to developing a large block of power in
APA's area of responsibility.
This report updates the power market analysis and addresses OMB
concerns.It uses three years additional data on power usage,effects
of the oil embargo t and other faetors.Specifically,it (1)updates the
power demand forecasts reflecting data since the 1976 report;(2)
updates the transmission and project OM&R costs;(3)presents
load/resource analyses to determine timing of major generation and
transmission investments and reflect resulting impacts on power system
costs;(4)presents·system power cost analyses that show annual
system-wide costs of power with and without the Upper Susitna Project;
(5)examines the value of an Anchorage to Fairbanks interconnection with
and without Susitna;(6)provides a subanalysis of the feasibility of
delivering Susitna power to the Valdez-Glennallen area;(7)determines
power rates and marketability of Susitna power compared with alternative
generation methods;and (8)responds to the OMB questions in APA's areas
of responsibility.
APA gave the Corps,for their report purposes:updated transmission
system costs and project OM&R estimates;load estimates;detailed
load/resource and system cost analyses with and without Susitna project;
and proposed responses to OMB questions pertinent to APA areas of
responsibili ty.•
The Corps'current proposal for the Upper Susitn&Project is essentially
the same as plan 5 in the 1976 report:a two-phase,two-dam complex
including Watana and Devil Canyon dams and powerplants,with the Watana
phase and a transmission system interconnecting Anchorage and Fairbanks
coming on-line first.Power production facilities include Watana dam,
reservoir,and powerplant,and Devil Canyon dam,reservoir,and
powerplant.Watana dam would be an earthfill structure with reservoir
normal water surface elevation of 2,185 feet;the powerplant would have
795 MW capacity.Devil Canyon dam would be a double-curvature
concrete-arch structure with maximum pool elevation of 1,450 feet,
providing water for a 778-MW powerp1ant.The transmission system would
be constructed in conjunction with the first stage (Watana),and,
1
as planned,would be,totally required for system reliablilty.The
system would incude two parallel 230-kv single circuit lines from Watana
to Devil Canyon (30 miles),two parallel single circuit 345-kv lines
from Devil Canyon to Pt.McKenzie (Anchorage,135 miles),and two
parallel single circuit 230-kv lines from Devil Canyon to Ester-Gold
Hill (Fairbanks,198 miles).
Several significant changes were made by the Corps since the 1976
report:
(1)The Devil Canyon dam design and costs are presented for both a
gravity structure and a thin-arch concrete structure.The 1976 report
was based on a thin-arch concrete structure.
(2)The construction period for Wata.na was increased from 6 years to
11;'Devil Canyon from 4 years to 7;and the Anchorage-Fairbanks intertie
re-scheduled for 1991--three years before Watana POL.
(3)Watana dam (earth fill)was redesigned,based on new geologic data.
The APA power market report uses certain assumptions that differ from
the Corps plan,namely:
(1)Design power generation capacity:The Corps design capacity is
based on critical year primary energy and 50 percent annual plant factor
(1,392 W,.]).The APA load/resource analyses assume a design capacity
based on average annual energy and 50 percent plant factor (1,573 MlV).
APA analyses include both primary and secondary energy as well as firm
and non-firm power.
(2)'Transmission intertie schedule:
The Corps plans show a 1991 on-line date for the transmission intertie.
The APA system cost analyses examine alternative on-line dates of 1990,
1992,and 1994.The load/resource analysis showed the earliest intertie
dates could be 1986, 1989,and 1991.APA financial analyses are
consistent with the Corps schedule.
(3)For Devil Canyon Design:
The APA system cost and financial analyses.assume the thin-arch design
for Devil Canyon as presented in the 1976 report,rather than the more
costly gravity structure alternative now being used by the Corps for
feasibility testing.A separate analysis demonstrates the effect of the
gravity dam alternative on cost of power.
The term Tl1976 report"is used throughout this report.This term refers
to the Corps of Engineers Interim Feasibility Report on the Upper
Susitna project,dated December 1975,revised June 1976.It also refers
.to APA's·Power Market analysis dated 1975 and included as Appendix G in
the revised Interim Feasibility Report.
2
l""........__r .."""""",..>
Part II.SUMMARY
Current studies have updated and revised the power market analyses of
the 1976 Upper Sustina Report (1976 report).New estimates of power
requirements through the year 2025 have been prepared.
The 1976 report used energy and power estimates based on data through
December 1974.The new analyses benefit from three full years of
additional data through December 1977.This provides a 'full four years
of "post oil-embargo"data--especially significant from the viewpoint of
identifying conservation trends.Evidence of conservation shows in the
Anchorage-Cook Inlet area growth comparisons before and after the
1973-74 fuel crisis.The 1970-73 average annual growth in net
generation dropped from 14.2 percent to 12.7 percent in the 1973-77
period.The decrease was more dramatic for per capita net generation:
A drop from 8 percent to 3.8 percent.
Because the net generation kwh/capita raio seemed to reflect the closest
corr~lations.particularly in recent years,this ratio and population
were used to forecast net generation values between,1980 .and 2025.
The following Railbelt totals are detailed in Part V.Trended values
offer an interesting comparison but are not presented as part of the
forecast.The trend is an average annual growth of 12.3 percent
resulting from 12.7 percent for the Anchorage area and 10.5 percent for
the Fairbanks area.
Railbelt Area Energy Forecast
(GWH)
3
Area load characteristics data were updated and new estimates of monthly
energy distribution were made.The conclusion was that the 50 percent
plant factor sizing assumption is still valid.
A further review of possible power supply alternatives included oil and
natural gas,coal,alternative hydro projects,nuclear,wind,
geothermal,and tide.It concluded again that coal-fired steam plants
are the most logical alternatives for major ra~lbelt area power supplies
in the proposed Susitna project timeframe.
New estimates of cost of power from coal-fired steamplants were ~repared
using results of several recent studies.They indicate:
Investment costs of $1,620-$l,860/kw
Unit cost of power of 5.2-6.4¢/kwh (including transmission to
load center)
A set of load/resource and annual system cost analyses were performed to
examine the e,ffects of Susitna and the transmission intertie from an
overall power system approach.These analyses were needed to provide
respon~es to OMS questions regarding:(1)the value of an
interconnected transmission system between Anchorage and Fairbanks;(2)
scheduling.ofillflior powerplants;and,(3)sensitivity of developing
large blocks'of power.APA's response to the OMB questions are
appended.!Th):'e'fi cases were analyzed using three projected load growth
estimates:
Case 1..~without Susitna Proj ect and without transmission intertie
situation ~ssuming all generating capacity to be supplied by coal-fired
steamplaTj~:~.
Case 2.Same as case I but with transmission intertie.
Case 3.A with Susitna Project and with intertie situation assuming
additional ge-n,erating capacity supplied by coal-fired steamplants.
The load/resource analyses showed the schedule of new plant additions
needed for all three cases for 1978-2011.
The system cost analyses compared annual power system costs for all
three cases,assuming 0 and 5 percent inflation rates.The analyses
showed annual system cost savings of $2.23 billion between 1990 and
2011,with the Susitna project.Average power system rates for the year
2000 assuming no inflation will be:
4
Load
Forecast
High
Mid
L(;W
Case 1
Wi thout Susitna
or Intertie
6.6 1/
6.9 1/
7.5 J:../
¢/KWH
Case 2
Without Sus tina
With Intertie
6.4
6.6
6.7
Case 3
With Susitna
and Intertie
5.8
5.7
6.4
]j Anchorage and Fairbanks are not interconnected for case
combined system rate is shown for academic purposes only.
l',the
For the medium-energy use range,system rates,compared to those without
Susitna or interconnections,will be 5.7 1 /percent less with
interconnections 18.6 percent less with Susitna.-The analyses showed
Susitna will result in cheaper power cost to Anchorage and Fairbanks in
all load growth cases.It also shows that the Pf,Pj ect power could be
fully used under all projected power demand cases.-
In comparison with the 1976 report~investment costs are 89 percent
($1.567 billion)greater.Contributing factors are:interest rate
increase from 6 5/8 to 7 1/2 percent total construction period increase
from 6 years to 10 years,cost inflation;and redesign of Watana dam and
powerplant facilities.New construction cost estimates for.Watana dam
(containing effects of both design quanitity changes and unit cost
inflation)are $595 million (72.percent)higher.Construction cost
estimates for Devil Canyon dam (thin-arch concrete)power plant
facili ties,and the transmission system were updated primarily by
indexing.This resulted in a 54 percent increase over the 1976 report
($233 million for Devil Canyon and $82 million for the transmission
system).The total interest during construction increase is 265 percent
($657 million).In summary.the increases in construction costs are:
Watana
Devil Canyon
Transmission System
Interest during Construction
Total
$595
233
82
657
$1567
million
II
11
II
million project investment
cost increase
Financial ~malyses were based on the October 1978 price level,Fiscal
Year 1979 Federal interest rate of 7 1/2 percent,intertie in 1991 or
1992,and repayment of all principal and interest within 50 years after
the last unit is installed.
}j Case 2 Value (6.6%)-1
Case 1 Value (7.0%)
-5.7%;Case 3 Value (5.7%)-1
Case 1 Value (7.0%)
-18.6%
1/Interconnection benefits leading to lower rates involve load supply
flexibility,economics of scale and operations.decreased reserve
requirements,and better reliability.
5
A comparison .of the rate for Sustina at 4.7¢/kwh with the coal-fired
steamplant alternative at 5.2/kwh to 6.4¢/kwh shows Susitna is less
costly.
The Glennallen-Valdez area was considered as a market area supplementary
to the Railbelt.Ihe Copper Valley Electric Association (CVEA)plans to
construct a Glennallen-Valdez transmission line,and the presence of the
pipeline terminal in Valdez with its related economy has made this area
a more attractive market since the 1976 report.Service to the area
would require a l38-kv line from Palmer to Glennallen (136 miles).Area
market factors are subject to fluctuation.Potential industrial loads
are difficult to project at this time,but service to utility loads can
be evaluated for a probable range of demands.Energy costs to serve the
incremental market area will range from 2.6¢/kwh to 1.3¢/kwh for a range
of loads from 150 to 300 kwh/year in addition to the project energy cost
of .4.7¢/kwh.Inclusion of the market area costs with other project
costs for a single project-wide rate would not adversely affect the
rate.
.~.,
.~.
PART III.POWER MARKET AREAS
Throughout its history of investigations,the Upper Susitna River Basin
Proje~t has been of interest for hydroelectric power generation because
of its central location to the Fairbanks and Anchorage areas.These
areas have Alaska's largest concentrations of population,economic
activity,services,and industry.Under any plan of development,major
portions of the proj ect po~er will be used in these two areas.In
addition,the basic project transmission system serving Anchorage and
Fairbanks could provide electric service to present and future
developments between the two cities.
The potential maj or market areas "are the Anchorage-Cook Inlet area and
the Fairbanks-Tanana Valley area.
Anchorage-Cook Inletu~
This area includes the developed areas of the Matanuska Valley,Greater
Anchorage Area,and Kenai Peninsula.
This general area has been the focal point for most of the State's
growth in terms of population,business,services,and industry since
World War II.Major building of defense installations,expansion of
government services,discovery and development of natural gas and oil in
the Cook Inlet area,and emergence of Anchorage as the State's center of
government,finance,travel,and tourism are maj or elements in the
history of this area..
Because of its central role in business,commerce,and government,the
Anchorage area is directly influenced by economic activity elsewhere in
the State.Much of the buildup in construction and operation ·of the
Alyeska pipeline,much of the growth related to Cook Inlet oil
development,and"much of the growth in State and local government
services since Statehood has occurred in the immediate Anchorage
vicinity.
Initially,economists overestimated the impacts of completion of the
trans-Alaska oil pipeline.In a recent study prepared by the University
of Alaska Institute of Social and Economic Research,the projected 1980
population for Anchorage-Cook Inlet was lower than that of the
historical 1977 population.Though this has been corrected,it
indicates that the area's economy has been stronger than anticiapted.
The Greater Anchorage Are?Borough estimated its July 1,1977 population
at 195,800,an increase of nearly 55 percent since the 1970 census.This
was more than 48 percent of the total estimated State population in
1977 .
7
-----------,-~_._----
The Matanuska Valley includes several small cities (Palmer,Wasilla,
Talkeetna)and the State's largest agricultural'community.Other
economic activities include recreation and light manufacturing.Much
recent growth in th~Borough has been in residential and recreational
homes for workers in'the Anchorage area.Estimated 1977 population T.vas
15,740,'a 61 percent increase since 1974.
The Kenai Peninsula Borough includes the cities of Kenai,Soldotna,
Homer,Seldovia,and Seward.with important fisheries,oil and gas,and
recreation resources.Estimated 1977 population was 23,100,a 39
percent increase since 1974.
Present and proposed activities indicate likelihood of rapid growth in
this general Cook Inlet area for the future.Much of this activity is
related to oil and natural gas,including expansion of the refineries.
The State capital city site relocation issue remains unresolved.In the
November 1978 general election,voters turned down the $966 million bond
issue to relocate the capital.In the same election,voters approved an
initiative which would require full disclosure of the costs to move the
capital.Therefore,it is impossible at this time to include specific
assumptions concerning the capital move.
The area will continue to serve as the transportation hub of western
Alaska,and tourism will likely continue'to increase rapidly.Major
local development seems probable.
Fairbanks-Tanana Valley Area
Fairbanks is Alaska's second largest city -the trade center for much of
Alaska's Interior,the service center for several major military bases,
and the site of the main campus of the University of Alaska with its
associated research center.The outlying communities of Nenana,Clear,
North Pole,and Delta Junction are included in the Fairbanks-Tanana
Valley area.Historically,the area is famous for its gold.
The completion of the pipeline construction has taken its toll in
Fairbanks.The area is experiencing a severely depressed economy.
Employ~ent in the construction industry has decreased to half of the
previous pipeline level.There has been a slight increase in employment
generated by government,distributive industries,and retail trade.In
1977-78,Fairbanks and its outlying areas experienced a 16 percent
decline in population.
The .decision favoring the ALCAN route for the proposed natural gas
pipeline was made in late 1977.The proposed-gas pipeline will follow
the route of the trans-Alaska oil pipeline route from Prudhoe Bay to
Del ta Junction.Fairbanks has been selected as the operation
headquarters by the Northwest Pipeline Company,responsible for
construction and operation of the gas pipeline.The Fairbanks-Tanana
Valley area will probably be heavily impacted again by the pipeline
construction;however,a more stable permanent employment base is likely
to become established.
8
The Fairbanks;"'North Star Borough had an estimated 1977 population of
44,262 and an estimated additional 8,OOO:i,n the outlying communities
within the power market area.The total population decreased 10 percent
since 1974.
9
------~-------
PART IV.EXISTING POWER SYSTEMS
Utility Systems and Service Areas
The electric utilities in the Railbel t power market area are listed
below,and areas now receiving electric service are shown on figure 2.
A detailed listing of power generating units is in the appended Battelle
report,table 3.4.
Anchorage-Cook Inlet Area
Alaska Power Administration (APA)
Anchorage Municipal Light and Power (fu~&P)
Chugach Electric Association (CEA)
Matanuska Electric Association (MEA)
Homer Electric Association (REA)
Homer (Standby)
Seldovia,English Bay,Port Graham
Seward Electric System (SES)
Fairbanks-Tanana Valley Area
Fairbanks Municipal Utility System (TI1US)
Golden Valley Electric Association (GVEA)
1/Major generation supplied by CEA system.
Installed
Nameplate 2/
Capacity MW -
30.0
121.1
345.7
!/
0.3 Jj
1.8
5.5 1/
69.6
219.2
Y Consists of 4S WAf hydro.All the rest are fuel-fired (80%gas turbine~t,
10
A
.'1!1!1~!111Iil~ll!j\I!ll!ljjill!1111!:111i\\j~;lj!i[l\;jj,,;...
~-----
o
11
--------_._---------
Figure 2
SCALE;
50
APA 12/78
IOOMil.~
These totals differ from the Battelle appended report because the report ~
includes some planned units not installed in 1977 as well as use of some
ratings other than nameplate.
APA operates the Eklutna hydro·electric proj ect and markets wholesale
power to CEA.A..\fL&P.and MEA.
AML&P serves the Anchorage Municipal area.CEA supplies power to the
Anchorage suburbs and surrounding rural areas.and provides power at
wholesale rates to HEA.SES.and MEA.The HEA service area covers the
western portion of the Kenai Peninsula~including Seldovia.across the
bay from Homer.MEA serves the town of Palmer and the surrounding rural
area in the Matanuska and Susitna Valleys.
The utilities serving the Anchorage-Cook Inlet area are now loosely
interconnected through facilities of APA and CEA.An emergency tie is
available between the AML&P and Anchorage area military installations.
FMUS serves the Fairbanks municipal area.while GVEA provides service to
the rural areas.The Fairbanks area power suppliers have the most
complete power pooling agreement in the State.FMUS.GVEA.the Univer-
sity of Alaska.and most of the military bases have an arrangement which
includes provisions for sharing reserves and energy interchange.
The delivery point for Upper Susitna power to the GVEA and FMUS systems
is assumed at a substation of'GVEA near Fairbanks.
Other small power generating systems in the Fairbanks-Tanana Valley area
were included in determining the power requirements of the region.They
include:
Fairbanks-Tanana Valley Area
Alaska Power and Telephone Company
(Tok and Dot Lake vicinity)
Northway Power and Light Company
(Northway vicinity)
Installed
Capacity MW
2.28
0.48
National Defense Power Systems
The six major national defense installations in the power market area
are:
Anchorage area--
Elmendorf Air Force Base
Fort Richardson
12
Fairbanks area--
Clear Air Force Base
Eielson Air Force Base
Fort Greely
Fort Wainwright
Each maj or base has its own steamplant that is used for power and for
central space heating.Except for Clear Air Force Base,each is inter-
connected with the local utility.Numerous small isolated installations
are not included in this study.
In the past,national.defense electric generation has been a major
portion of the total installed capacity.With the projected stability
of military sites and the growth of the utilities,the national defense
ins~allation will become a less significant part of the total generating
capacity.
Industrial Power Systems
Three industrial plants on the Kenai Peninsula maintain their own power-
plants,but are interconnected with the REA system.The Union 76
Chemical Division plant generates its basic powe~to satisfy its energy
needs,receiving only standby capacity from HEA.The Kenai liquified
natural gas plant buys energy from REA,but has it,s own standby
generation.Tesoro Refinery buys from REA and also satisfies part of
its own needs..
Other self-supplied industrial generators include oil platform and
pipeline terminal facilities in the Cook Inlet area.
Existing Generation Capacity
Table 1 provides a summary of existing generating capacity.The table
was generally current as of 1978;The Anchorage-Cook Inlet area had a
total utility installed capacity of 504.5 Mt~in 1977-78.Natural
gas-fired turbines were the predominant energy source with 435.1 MW.
Hydroelectric capacity of 45 MW was available from two projects,Eklutna
and Cooper Lake.Steam turbines comprised 14.5 MW.Diesel generation,
mostly in standby service,accounted for the remaining 9.8 MW.
The Fairbanks-Tanana Valley area utilities had a total installed
capacity of 288.8 MW in 1977.Gas turbines (oil-fired)provided the
largest block of power in the area with an installed capacity of 203.1
MW.-Steam turbine generation prOVided 53.5 MW of power and diesel
generators contributed 32.1 MW to the area.
13
Area
Table 1
AAILBELT AREA GENERATION CAPACITY
Summary -1977
Upper Susitna Project Power Market Analysis
Installed Capacity -MW
Hydro
Diesel Gas Steam
Int.Comb.Turbine Turbine Total
Anchorage~Cook Inlet
utility systi§nt',
National Def~tis~..
Industrial System
Subtotal
Fairbanks-TananaVa11ey
utility System
National Defense
Subtota1
45.0
45.0
9.8
9.2
10.2
29.3
32.1
14.0
46.1
435.1
14.8
449.9
203.1
203.1
14.5
40.5
55.0
53.5
63.0
116.5
504.5
49.7
25.0
579.2
288.8
77.0
365.8
Notes:
Source:
The majority of the dieSel generation is in standby status.
Roundin~Causes differertces between summations of the parts
and the totals shown.
Utility reports to Alaska Public utility Commission to the
Department of Energy,the Alaska Air Command,the oil and gas
compahies,and APA files.
(Minor differences exis~between this table and the appended Battelle
Report.).
APA 11/78 ~,
14
Planned Generation Capacity
The two major utilities in the Anchorage-Cook Inlet area,AML&P and CEA,
plan to add a total of approximately 420 ffi~installed capacity to their
existing system between 1979 and 1985.k'1L&P plans to add a 16.5-MW
combined cycle system to their existing combustion turbine.In
addition,CEA has plans to complete the 230-kv interconnection loop with
MEA.
In December 1978,GVEA decided to postpone development of their proposed
Healy II steam turbine system (104 MW)until more favorable economic
conditions prevail.
A unit by unit breakdown of planned generating systems is presented in
the appended Battelle report,table 3.8 •
..
15
PART V.POWER REQUIREMENTS
I
Introduction
This summarizes the analyses of historic data and estimates of future
needs in the ,power market areas.The study examines in detail electric
utility statistics 1970 to 1977 with special effort to identify changes
in use patterns related to conservation measures since the 1973 oil
embargo.
Estimates of future utility power needs are derived from estimates of
individual energy use and area popu~ation.Population projections were
developed by the University of <Alaska,Institute of Social and Economic
Research (ISER).The individual use forecast was estimated by assumed
conservation-induced changes in kwh/capita growth rates.The end
results are forecasts of net generation (kwh)and peak load demand (kw).
The three energy use sectors analyzed in this study are:
Utility Includes all utilities which serve residential and
commercial/industrial customers.
National Defense -Includes all military installations.
Self-Supplied·Industry -Includes limited number of heavy industries,
i.e.,natural gas and oil processing industries on the Kenai Peninsula
which generate their own power.The study assumes that these industries
will purchase energy if it becomes economically feasible.Some have
interchange agreements vith local utilities.
Evaluations of monthly energy distribution and installed capacity
requirements are included and are premised on characteristics of area
power demands.
Data
This presents the basic parameters used in the analyses leading to the
Susitna Power Market forecast assumptions.
The historical data·summarizes the Anchorage-Cook Inlet and
Fairbanks-Tanana Valley areas which comprise the Railbelt area.Each
area is divided into utility,national defense,and self-supplied
industrial components (Fairbanks-Tanana Valley area has no known
significant self-supplied industries).
The utility component is divided into four sectors:
Commercial-Industrial,Total Sales,and Net Generation.
16
Residenti~l,
,,-----------------------------------------------
Data was collected from
government agencies,from
commands,by correspondence
publications and news media.
utility and industry reports to various
utilities directly,from Alaska military
wi thindus try,and from various statistical
Basic data needed for the 1970-1977 analysis are presented on tables 2,
3,and 4 included is utility annual energy and customers for each
sector,national defense and industrial annual energy consumption,
utili ty and national defense annua.1 peak load,industrial installed
capacity,annual population,and average annual employment.In
addition,utility net generation,listed on tables 5 and 6,was compiled
for the 1960-1977 period.
As part of the forecasting foundation,the following historical
chronology indicates fluctuations affecting Rai1be1t energy use.
1970.Uncertainty
construction,and approval.
Above average temperature.
concerning the oil
Native land claims
pipeline design,
legislation pending.
1971.
temperature.
Uncertainty concerning pipeline.Below average
1972.Uncertainty concerning pipeline.Coldest year of period.
1973.Start of fuel crisis and conservation publicity in December.
Below average temperature.
1974.Start of pipeline·construction.Near average temperature.
1975.
ture.
Peak of pipeline construction activity.Near average tempera-
1976.Start of pipeline construction "wind-down.II Electric pm.;er
cable across Knik Arm out of service for an extended period (all but one
circuit).Above average temperature.
1977.Oil started flowing in pipeline.Warmest year of period.
Residential construction boom in Anchorage.Large increase in
non-residential authorizations issued.
17
Year
1970
1971
1972
1973
1974
1975
1976
1977
Year
1970
1971
1972
1973
1974
1975
1976
1977
~>
Table 2 '\
.!
BASIC POWER AND ENERGY FORECASTING DATA
ANCHORAGE-COOK INLET AREA (INCLUDING SEWARD)
Upper Susitna Project Power Market.Analysis
Utility Energy Sales (G~{H)Net Generation (GWH)
Resi.Comm./lndu.Total ]j Utility 'l:./Nat.Def.1/Indu.
310.5 342.3 678.7 744.1 156.2 1.65
369.7 393.9 792.5 886.9 161.2
421.6 454.0 911.6 1,003.8 166.5 45.3
459.5 514.8 1,012.2 1,108.5 160.6
496.1 552.8 1,087.4 1,189.7 155.1 45.3
595.1 631.9 1,270.6 1,413.0 132.8
677.6 738.7 1,462.2 1,615.3 140.3
741.0 813.4 1,600.8 1,790.1 130.6 69.5
Utility Customers Peak Load (MW)
Resi.Comm./lndu.Total Utility Nat.Def.Indu.!!!
39,271 5,230 45,042 .165.2 34.6 12.3
42,501 5,581 48,670'184.8 ,-,.,
46,724 6,104 53,278 212.8 33.9 12.3
49,307 6,491 56,280 229.9
52,585 6,798 59,893 257.2 32.6 12.3
56,801 7,478 64,797 345.8
61,881 8,220 70,622 349.9
68,320 9,221 78,066 423.9 40.5 24.8
Population
Civilian Total
Employment
Avg.Annual
1970
1971
1972
1973
1974
1975
1976
1977
135,963
145,108
155,084
160,162
165,938
196,320
207,090
222,424
149,428
159,046
167,765
174,280
179,544
209,049
219,337
234,674
47,408
51,092
54,329
57,157
65,919
78,786
83,604
88,869
11 Excludes deliveries to national defense.
21 Total retail sales of energy +non-revenue energy used +losses.
31 Includes receipts from utilities,excludes deliveries to utilities.
41 Self-supplied industrial data is installed capacity rather than peak load.
GWH =million KWH
MW =thousand KW /~
KW =Kilowatt
APA 11/78
18
Table 3
BASIC POWER AND ENERGY FORECASTING DATA
FAIRBANKS-TANANA VALLEY AREA
Upper Susitna Project Power Market Analysis
Utility Customers
Year Resi.Comm./Indu.Total
Utility Energy Sales (GWH)
Year
1970
1971
1972
1973
1974
1975
1976
1977
1970
1971
1972
1973
1974
1975
1976
1977
Resi.
91.7
112.4
122.3
134.4
155.8
193.0
195.9
200.7
10,364
11,014
11 ,584
11,931
12,832
14,025
15,569
16,709
Comm./Indu.
108.3
119.8
127.3
139.5
150.3
196.3
204.2
221.6
1,721
1,779
1,839
1,929
2,069
2,247
2,435
2,580
Total 1./
210.2
244.3
262.9
282.3
323.0
409.2
420.5
442.7
12,268
12,947
13,611
14,041
15,084
16,447
18,179
19,463
Net Generation (GW'H)
Utility ..Y Nat.Def.'if
239.3 203.5
275.5 201.4
306.7 203.3
323.7 200.0
353.8 197.0
450.8 204.4
468.5 217.5
482:9 206.8
Peak Load (MW)
Utility Nat.Def.
56.3 44.4
65.3
66.6 41.4
72.7
87.5 40.8
110.0
102.6
118.9 41.0
Population
Civilian Total
Emp laymen t
Avg.Annual
1970
1971
1972
1973
1974
1975
1976
1977
42,310
43,188
45,516
45,396
51,137
60,884
58,051(e)
47,l55(e)
52,141
50,585
52,383
52,2Z.6
57,836
67,011
63,762
52,155
15,681
15,817
16,873
16,794
21,960
34,451
34,325
27,385
1/Excludes deliveries to national defense.
2/Total sales +non-revenue use +losses.
3/Includes receipts from utilities,excludes deliveries to utilities.
4/Self-supplied industrial data is installed capacity rather than peak load.
Gffi!=million Kffi!
MW =thousand KW
19
APA 9/78
----------------------------------------p-------
Table 4 ~\
BASIC POWER AND ENERGY FORECASTING DATA
RAILBELT AREA
Upper Susitna Project Power Market Analysis
Utility Energy Sales (GWH)Net Generation (GWH)
'Year ResL Comm.!Ingu.Total Utility Nat.DeL Indu.Total
1970 402.2 450.6 888.9 983.4 359.7 1.6 1,344.7
1971 482.1 513.7 1,036.8 1,162.4 362.6 25 (e)1,550.0
1972 543.9 581.3 1,174.5 1,310.5 369.8 45.3 1,725.6
1973 593.9 654.3 1,294.5 1,432.2 360.6 45.3(e)1,838.1
1974 651.9 703.1 1,410.4 1,543.5 352.1 45.3 1,940.9
1975 788.1 828.2 1,679.8 1,863.8 337.2 45.3(e)2,246.3
1976 873.5 942.9 1,882.7 2,083.8 357.8 45.3(e)2,486.9
1977 941.7 _1,035.0 2,043.5 2,273.0 337.4 69.5 2,679.9
Utility Customers Peak Load (MH)
Year Resi.Comm.!Indu.Total Utility Nat.DeL Indu.Total
1970 49,635 6,951 57,310 221.5 79.0 12.3 312.8
1971 53,515 7,380 61,617 ,150.1 77(e)12.3 (e)3:~r\
1972 58,308 7,943 66,889 279.4 75.3 12.3 36 {.O
1973 61,238 8,420 70,321 302.6 74(e)12.3(e).388.9
1974 65,417 8,867 74,977 344.7 73.4 12.3 430.4
1975 70,826 9,725 81,244 455.8 73 (e)12.3(e)541.1
1976 77,450 10,654 88,801 452.5 76(e)12.3(e)540.8
1977 85,029 11,801 97,529 542.8 81.5 24.8 649.1
Total Avg.Annual
Population Employment
1970 201,569 63,089
1971 209,631 66,909
1972 220,148 71,202
1973 226,526 73,951
1974 237,380 87,879
1975 276,060 113,237
1976 283,099 117,929
1977 286,829 116,254
APA 11~!
20
))')
Table 5
NET GENERATION (GWH)
ANCHORAGE~COOK INLET AREA
Upper Susitna Project Power Market Analysis
(Includes receipts of electric energy from military;excludes electric energy deliveries to military)
Year AML&P CEA APA MEA IlEA KU SES Total Growth %---_.-
1960 0.8 27.5 187.6 0.1 8.2 1.8 5.7 231.6
1961 3.2 44.8 193.8 0.1 3.6 2.0 6.2 253.7 9.5
1962 20.0 101.8 150.3 0.2 0 2.3 3.7 278.2 9.7
1963 55.7 100.5 152.7 0.2 0 2.7 0 311.8 12.1
1964 97.3 94.5 146.1 0.5 1.2 3.8 0 343.4 10.1
1965 101.2 167.4 132.1 0.6 1.4 4.1 0 406.8 18.5
N 1966 108.6 204.6 138.2 0.7 1.4 5.2 0 458.7 12.8......
1967 100.1 217.1 178.5 0.8 1.5 6.7 0 504.6 10.0
1968 125.3 280.0 155.5 0.8 1.7 10.1 0 573 .4 6.5
1969 148.1 314.6 158.2 0.9 2.2 8.9 0.1 633.0 17.8
1970 186.0 385.5 154.7 1.1 2.4 9.0 0.1 738.8 16.7
1971 24?3 476.6 144.9 1.3 2.7 8.0 0.1 878.9 19.0
1972 270.0 554.2 164.0 1.5 3.3 7.0 0.1 1 t OOO.1 13.8
1973 359.0 657.3 96.3 0.3 3.6 --0.1 1 t 116.5 11.6
1974 389.6 678.4 1.1 --4.2 --0.1 1,197.4 7.2
1975 384.3 888.8 135.1 --.3.4 --3.2 1,414.9 18.2
1976 442.9 1,054.5 118.5 --0.5 --1.5 1,617.3 14.3
1977 420.3 1,179.7 203.6 --0.5 --0.8 1,804.9 11.5
AHL&P
CEA
APA
MEA
HEA
KU ..
SES
-Anchorage Municipal Light and Power
-Chugach Electric Association
-Alaska Power Administration
-Matanuska Electric'Association
-Horner Electric Association
-Kenai Utilities
-Seward Electric System
APA 11-78
22
Analysis
Detailed investigations of relationships among the basic data components
are listed in tables 2,3,and 4.Analysis was done separately for each
major sector (utility,national defense,and self-supplied industry)
within eacn geographic area.
Utility
The analysis of utility data set out to develop assumptions for fore-
casting net generation and peak load.Investigations evaluated the
impact of changes in population,employment,customers,weather,
tariffs,and other events upon energy use.These evaluations then
helped to:(1)determine if energy sectors (residential,
commercial-industrial,total sales)other than net generation needed to
be forecast;(2)determine which energy ratio (kwh/capita,kwh/employee,
kwh/customer)to use in the forecasting procedure;(3)develop
procedure for forecasting utility annual net generation from energy use
assumptions and demographic parameters (population,employees,or
customers);(4)determine load factor with which to calculate peak load
forecast from the net generation forecast.
Constants,small amplitude cycles,or trends in relationships among the
energy use and customer sectors were investigated for use as forecasting
aids.If,for instance,the residential energy use/net generation ratio
remained almost constant from 1970 through 1977,only net generation
need be subj ected to the forecasting procedure.The same type of
analysis was app lied to energy use ratios:a look for an average or
trend to De used as a factor in forecasting net generation.
After developing the net generation forecast,the peak load forecast was
calculated using energy and an assumed load factor.Analysis of
historic load factors determined an average or trend from which the
assumed load factor was derived.Forecasted net generation and the
assumed future load factor were then used in the formula:Peak
load =8,760 hr/yr.x load factor x net generation ..
The evaluations showed a mix of similarity and contrast between the two
Railbelt areas.In both areas,the major energy use determinants were
the trans-Alaska oil pipeline construction and the fuel crisis of
1973-74.Other correlations with weather,tariffs,etc.,seemed
insignificant.For instance,energy growth increased in some years
despite above average temperatures which reduced energy need.
Anchorage-Cook Inlet Area Analysis Results
procedures resulted in the following
Anchorage-Cook Inlet area.
23
The foregoing
observations
evaluation
for the
----"_liflt'_i'i'lP_W_=_·_"'=.~I1_·,....._.,
(a)Observations indicate no significant shift in energy use patterns
or in share of total load among the various utility sectors
(residential,etc.).The ratios among the sectors (residential/total
sales;total sales/net generation,etc.)remained essentially constant
through the study period.This was true for both energy and customers.
Therefore,only one sector--net generation--represents all sectors in
the forecast.
(b)Energy rate of growth per customer and per capita had a significant
reduction after the 1973-74 fuel crisis.The 1973-77 per capita average
growth rate was about half that for 1970-73.It appears that
conservation can be considered an influence after 1973.
(c)Events impinging upon energy use are listed in the previous
section.Between 1973 and 1977,several events bear repeating for
emphasis:fuel crisis in 1974;start of pipeline construction in 1974;
peak pipeline activity in 1975;decreas~of pipeline'activity in 1976
and 1977;cables across Knik Arm,which carry a large share of Anchorage
energy,went out of service in 1976;warmer than average weather in
1974,1976,and especially 1977.Yearly growth rates'reflected rather
large fluctuations as different historical events influenced each
parameter.(This is a recurring phenomenon in Alaskan history).
(d)Parameters were not influenced alike as figures 3 through 8 attest.
For instance.customer growth reacted'to events in a steadier pattern
than did population and employment.Reasons for this are more people~,
per customer and time needed for connecting more customers to a utility
system at the initial onslaught of large demographic growth.
(e)Comparing the energy fluctuations with others,such as population
and employment,gave a measure of correlation between parameters.(The
energy use and customer growth fluctuations correlated only in part;
their patterns did not coincide every year).However,energy and popu-
la tion growth rate changes were coincidental for every year but 1977.
That is,when the energy growth rate increased,so did the population
growth rate;when the population growth rate decreased,so did the
energy growth rate.
(f)Energy use and weather comparisons were inconclusive.Warm weather
did not bring corresponding reduction in energy use.Cold weather
increases in energy use were buried in other events (pipeline
construction,etc.).
(g)Because the net generation kwhhapita ratio seemed to reflect the
closest correlations,particularly in recent years,this ratio and
population were used to forecast net generation values between 1980 and
2025.
(h)Values basic to the forecasting assumptions are the kwh/capita
ratio averaging 3.8 percent average annual growth between 1973 and 1977
and net generation averaging 12.7 percent.
(i)Aver age annual growth results'are summarized on tab Ie 7.Figures
.3,4,and 5 are graphs of pertinent elements of the analysis.
24
Fairban~s-Tanana Valley Area Analysis Results Some of the
Anchorage-Cook Inlet area evaluation results apply also to the
Fairbanks-Tanana Valley area,others do not.The following observations
parallel tl:ose of Anchorage-Cook Inlet.
(a)No significant shift in energy use patterns or in share of total
load among the various utility sectors (residential,etc.).Again,only
one sector--net generation--need be forecast.
(b)Energy growth was similar to that of Anchorage (somewhat smaller in
the pre-1973 period);but customer,population,and employee growth were
different in the two areas.Consequently,the energy use per customer,
per capita,and per employee ratios indicate different growth patterns
in Fairbanks.The large swings of employment and population in
Fairbanks during pipeline construction compared to almost constant
preconstructionvalues cloud comparisons of the two periods.
(c)Although the effects of pipeline construction are evident,the
population/employee ratio (2.29 average through the study period)was
constant enough to indicate that either population or employment can be
used as a forecasting parameter.
(d)The effects of weather on energy use could not be detected.In
some years,degree day variations were not in phase with energy use
variations.
(e)Energy use/capita exhibited wider variations than the other two
ratios,but,nevertheless,had the nearest to constant average ,annual
growth rates.Because of this and the other observations,net
generation kwh/capita and population were used to forecast net genera-
tion.
(f)As in the Anchorage-Cook Inlet area,values basic to the
forecasting assumptions are the net generation/capita growth,averaging
10.6.percent per year,and net generation growth,averaging 10.5
percent per year between 1973 and 1977.
(g)Growth rate results are summarized on table 7.Figures 6,7,and 8
are graphs of some pertinent elements of the analysis.
ALASKA RESOUR£ES UBR~RY
.,~•,I '
25
'Table 7 ~
AVERAGE ANNUAL UTILITY GROWTH SUMM..A.RY
ANCHORAGE-COOK INLET AREA
Upper Susitna Project Power Market Analysis
Avg.Growth Avg.Growth
1970.1973 1977 1970-1973 1973-1977
Energy GWH
Rj=sidential Sales 310 460 741 14.0% 12.6%
Commercial/Industrial 342 515 813 14.7 12.1
Total Sales 679 1,012 1.601 14.2 12.1
Net Generation 744 1,108 1,790 14.2 12.7
Energy Use,kwh/Customer
Residential 7,907 9.319 10,846 5.6 3.8
Commercial/Industrial 65,449 79,310 88,212 5.6 2.6
Total Sales 15,068 17,985 20,506 6.0 3.3
Energy Use,kwh/Capita
Residential 2,284 2,869 3,332 8.0 3.8
Commercial/Industrial 2,518 3,214 3,657 8.6 3.3
Total Sales 4,992 6,320 7.197 8.3 3.3
Net Generation 5,473 6,921 8,048 8.0 3.8 /-"",
Fairbanks-Tanana Valley Area
Avg.Growth Avg.Growth
1970 1973 1977 1970-1973 1973-1977
Energy GWH
Residential Sales 92 134 201 13.4%10.7%
Commercial/Industrial 108 140 222 9.1 12.2
Total Sales 210 282 443 10.2 11.9
Net Generation 239 324 483 10.8 10.5
Energy Use,kwh/Customer
Residential 8.852 11,262 12,010 8.3 1.7
Commercial/Industrial 62,931 72,303 85,899 4.8 4.4
Total Sales 17,134 20,104 22,746 5.4 3.1
Energy Use,kwh/Capita
Residential 1,759 2,572 3,848 13.5 10.6
Commercial/Industrial 2,077 2,670 4,249 8.7 12.3
Total Sales 4,031 5,403 8,488 10.3 12.0 ~Net Generation 4,589 6,196 9,259 10.5 10.6
APA 11/78
26
~------------------------------
Figure 3
t"l',lEEGY SECI'OP.PAT1C::;
.....,.e::--
=50.3%
46.1%Avg.a
Hc·~43
42 .F---------..."'...,-="-~-::.-::-:-::-~-:::--""-~~--_:_-----__
Res1dent1al Sales
41 l
40 ::-:::;------+1------+1------+1------+[.£N~·e:.:t~G~e::.n:.:e:.:r~a~tf.i:::o:.n:---....:A~"+.,g:!..:.:.....:::....::4~'1:':':.,:7:.:%:"-l
19(70 1971 1972 1973'1974 1975 1976 1977
YEl\PS
At'K:!!QI<I\GE-CCOK INTEr ARE.1\.
51 Upper Susitna Project Power Market Analysis
50 .['-'"-~~'-----'-------------'-"~~ial~'~~i~~~-------
"9 T Total Sales 'Avg.
~4.~I
tiP q,;.~46 ---~.~--~=~=.=:.:::::.:=:.:.:--~-~..:::-=------------
45 Residential Sales
44 Total Sales
N~CHO:Rl\GE-CCOK INLJTI'.l\.iWJ\
1977197613731972
Upper Susitna Project Power Market Analysis
1971
-1's {CillO ----
.1 S'"c ",.-:::::.._----1
1 (',-\st.,-1-"_~----r ci ,\l-n··(_,.,.".
_~::::::::::==~::::::::::::::::::::::::::::::::::::::::::::::::::~(::':':.T\"':..:G:_:'===::::,_::t.i31 S<l}c
5 ...,..t ••=====_ResideD .l=::==::--::::=-~"'i-.-'--==---------11-----,.....-------111-----+1-.----~f------
197'J 1975
18(\0
1700
I
1000
1SQO
~1400
1300s::
0 1200'M...;1100.-l T..-l
F-100011
~900
I;J
~SOO.....700 T;>.(,00 tl~
lr.500~
f1 ~OO 1:===300
1970
'fT::i\HS
APA 12/78
27
Figu:r:e 4
11,000
ANClIORl-.GE-CCOK n,-ru:r AHE.l\.
Upper Susitna Project Power Market Analysis
10,000
9,000
8,000
7,000
6,DOO •
5,000 •
4,000
3,000
J.977197619'15197319721971
L------cl------t------1-·------Ilf-------If----'----4'--J
1974
2,000
19'10
APA 12/78
28
.,I"""":
250.000
225,000
200,000
175,000
W
-J
0..o
~150,000
l.1.o
C/)
0::
W
m!25,OOO
:E
.J
Z
100,000 -
75,000
ANNU~~\L POPULATION t Er~iPLOY~..H;:NTt
AND UTiLITY CUSTOf.1ERS
ANCHORJ..'\GE-COO~<INLET AREA
Upper Susitna Project Power Market Analysis
Figure,5
'r-,
25.0°01----
1970
1l-_-L-'L__--lI __---"1~.1
1971 1972 1973 1974 1975 19-(6 1977
YEARS
APA 1/79
29
Figure 6
Avg.==41.3%"
Avg.=46.4%
Residenti.al Sales
(,Net Generation
Residential Sales
Total Sales
---=:.--:;;;;..
Commercial-Industrial Sales "
Total Sales Avg.=48.9%
38
ENERGY SECTOR RATIOS
FAIRBANKS-TANANA VALLEY AREA
Upper Susitna Project Power Market Analysis52
50
48-~460
z-440....42«
0:::
'denti.a1 Sales (GWH)
ReS.J,.
Upper Susitna Project Power Market Analysis
.a1 sa~es (G"..m)·a~_Industr.J,.ccmmeI:c.J,.
:3 6 l.....__--'''--__--II--....._---L-.....__.-.L .-.L .-.L --l
1970 1971 1972 1973 1974 1975 1976 1977
YEARS
ANNUAL ENERGY GENERATED OR SOLD
FAIRBANKS-TANANA VALLEY AREA500
:I:400
3=
~
zo--1300-1
~
"..
:r:
~200
z
>-(.!)
a:100
IJJ
Z
lJJ
-
-
O/9L.7~O-----:-l19-=7~1---19J-7-2--'-----'/9L.-7-3---,..1.9-74---,S.L7-S---/..J9-7S-----l1977
"YEARS
.30 APA 1i79
Figure 7
~~NNUAL ENERGY USE PER CAPITA
AND PER CUSTOMER
FAIRBANKS-TANANA VALLEY AREA
upper susitna Project Power Market Analysis
(Ttl.)
.ta ITt-i.)caP(1.\.., 1 sales per
Resident:La....
t .al <:ales Per capita
Conunex-ciaJ.-InduS r~-
3000
2000
.4000
J3pOO
10,000
J ',000
12,000
-'P
.....",
7000
>-"
C)
a:::·6000
w -.
Z
IJJ 5000
-.::I:9000
~
:t::
(r-.8000
1000
~---,I__I__I_-.-lI:"'-----I[_---,I,,---_l
1971 1972 197.3 1974 1975 1976 1977
YE~RS
I.
31
APA 1/79 ,
.j
Figure 8
70,000
ANNUAL POPULATION,EMPLOYMENT,
AND UTILITY CUSTOMERS
-EA.JR8AJ~U(S_~IAr{~N~_'l~L L~Y AREA
Upper Susi~~a Project Power Market Analysis
Ave:t:age ~l Employment
.,
.~
.(incl ...Total Po~ula-Uon
201 0c0
UJ
...Ja.o
w 401000a..
LLo
(J)
0::
IJJ.en 30,000
::E
::J
Z
10,000 Residential Customers .
..Commercial-Industrial CUstomers
1970 1971 1972 1973 1974
.-YEARS
1975 1976
32 A'PA 1/79
.~.
National Defense
Evaluation of historical national defense data resulted in net
'generation and peak load averages.The analysis encompassed the U.S.
Army and Air Force installations in the Anchorage and Fairbanks areas.
No definite trends surfaced--on1y a small,cyclic.decrease in the
Anchorage area net generation and an increase in peak load.In the
Fairbanks area,net generation increased slightly and peak load
decreased.Total national defense is about 15 percent of utility for
both net generation and peak load.
Self-Supplied Industry
Railbelt industry and the upper Kenai Peninsula complex showed no
significant change in capacity and energy generation until 1977 when the
chemical plant expanded.Therefore,the analysis consisted of a plant
factor .dete,rmination only.Other factors needed in forecasting are
discussed as assumptions in the next section.
Energy and Power Demand.Forecasts
This section presents future energy and power requirement estimates
developed from the previous analyses.Work for the new estimates
consisted of:(1)using the analyses to obtain forecasting assumptions;
(2)using the assumptions in forecasting utility net generation/capita;
(3)combining net generation/capita with Institute of Social and
Economic Research (ISER)population projections to obtain the utility
net gener:ation forecast,and forecasting national defense and industry
generation from pertinent assumptions;and (4)combining the net
generation forecast with load factors resulting from the historical dat.a
analysis to'obtain peak load (power requirement)forecasts.
Assumptions and Methodology
Population --The ISER econometric model of the Southcentral Region Water
Study (Level B)furnished high and low range population forecasts.The
model disaggregated the Anchorage':'Cook Inlet area.from a sta.tewide
population forecast.No recent,applicable forecast of Fairbanks-Tanana
Valley population was available;therefore,APA assumed statewide growth
rates from the ISER model applied to the Fairbanks-Tanana Valley areas.
(See table 8).
Utility -Assumptions,based on the preceding analyses,lead to the net
generation and peak load forecast.Net generation is the product of
forecasted energy use per capita and projected population.Peak load
demand is derived from net generation and the assumed utility load
factor.Multiplying these growth rates by forecasted 1980 values of
kwh/capita resulted in the energy use estimates •
33
Table 8
POPULATION ESTIMATES
1980-2025
RAILBELT AREA
Upper Susitna Project Power Market Analysis
II S .d II Fairbanks-Tanana Valley 1./Anchorage-Cook Inlet -tatew~e -
Year High Low High Low High Low
1980 270,200 239,200 513,766 500.225 62,020 60,390
1985 320,000 260,900 640,718 563,303 77 ,350 68,010
1990 407.100 299,200 790,042 618,397 95.370 74,660
1995 499,200 353,000 947,312 680,286 114,360 82.130
2000 651.300 424.400 1,157,730 743,034 139,760 89,700
2025 904,000 491,100 1,484,784 820,369 179,240 99.040
Notes:*No mid-range estimates are shown because,when the forecasts
were done,ISERll had made only the high and low projections.
A comparison of the mid-range forecast already performed (see
text for method)with one using the mid-range population,when
received,indicated no reason to re-do the forecasts.
*Values shown include national defense population
II From Iser,Southcentral AlaskaTs Economy and Population:A base
Study 1965-2025.September 1978 with December 1978 revisions.
II Calculated from statewide growth rates.
34
.~.
Since the ratios of residential.commercial':"'industrial.and total sales
energy to net generation remain constant.net generation is assumed to
be an appropriate forecasting parameter.The evaluations indicated that
the other sectors do not need individual forecasting.
The basic energy use (net generation kwh/capita)assumption for the
entire Railtlelt are~is a 3.5 percent average annual.mid-range.1980-85
growth rate.It is based on the Anchorage-Cook Inlet area value of 3.8
percent annual growth ffom .1973-77 and an assumed·continuation of the
post-1973 conservatiorr--trend.As mentioned in the Anchorage-Cook
Inlet area evaluations.a conservation trend was apparent when comparing
energy use growth rates for 1973-77 and 1970-73 (see table 7).Tied to
this is the assumption of gradually increasing effectiveness of future
conservation programs coupled with perhaps upper limits of.electric
energy use.These are reflected in an average annual growth by the year
2000 or 2 percent for high range,1 percent for mid~range,and 0 percent
for low range.These assumptions result in decreased growth rates for
each five-year increment,as shown below:
Time Period High Mid Low
1980-1985 4.5%3.5%2.5%
1985-1990 3.5% 3.0%2.0%
1990-1995 3.0%2.5%1.5%
1995-2000 2.5%2.0%1.0%
2000-2025 2.0%1.0%0%
Multiplying these growth rates by forecasted 1980 values of kwh/capita
resulted in the energy use estimates.
The 1980 mid-range value of kwh/capita was derived from the 1973-1977
average annual growth of net generation.The 1980 net generation was
estimated.The Anchorage-Cook Inlet mid-range assumption of 12 percent
annual load growth rate for 1977-80 net generation came from a
historical 12.7 percent.The respective Fairbanks-Tanana Valley values
were 10.5 percent assumed,10.6 percent historical.Mid-range 1980
kwh/capita was calculated using the estimated net generation and
projected population.The 1980 high and low range average annual
kwh/capi ta growth rates for Fairbanks-Tanana Valley were assumed 120
percent and 80 percent of the calculated mid-range value respectively.
Comparable values for Anchorage-Cook Inlet were 130 percent and 80
percent.The differences between the two areas reflect population
estimates and an attempt to derive a reasonable 1977-80 transition
period coupled with the population estimates.
Peak load (l~)forecasts were calculated using a 50 percent load factor.
Anchorage-Cook Inlet area load factor averaged 51.9 percent between 1970
and 1977 and 51.0 percent between 1973 and 1977.Fairbanks area
averaged 48.9 percent and 48.4 percent in the same periods.
1/Conservation here includes results of the fuel cr1S1S and perhaps
of nationwide publicity on the need for saving energy.Other factors
may be involved,but no other events are as coincidental with reduced
energy use as is the fuel crisis.
3S
"
National Defense -Historical data from Army and Air Force installations
in the Anchorage and Fairbanks areas indicate reasonable energy
assumptions to be:
1.0 percent annual growth for mid-range forecast,1 percent for high
range,and -1 percent for low range.
2.A 50 percent load factor was assumed for use with energy (net
generation)to obtain peak load.
Self-Supplied Industries -The following assumptions were developed from
existing data and conditions.consultations with many knowledgeable
people in government and industry,and from reports on future
developments.
1.Industries will purchase power and energy if economically feasible.
2.Forecast based on listing in the March 1978 Battelle report.
3.High range includes existing chemical plant,LNG plant,and
refinery as well as new LNG plant,refinery.coal gasification plant,
mining and mineral processing plants,timber industry.city and aluminum
smelter or some other large energy intensive industry.
4.Mid-range includes all of the above except the aluminum smelter.
5.Low range includes all listed under high range except the aluminum
smelter and the new capital.
6.In some instances,high,mid,and low range may be differentiated
by amount of installed capacity as well as the type of installations
assumed.
7.No self-supplied industries are assumed for the Fairbanks-Tanana
Valley area.Any industrial growth has been assumed either (1)included
in utility forecasts or (2)not likely to be interconnected with the
~rea power systems.
8.Net generation forecast calculated from forecasted capacity and a
plant factor of 60 percent.
The ISER model assumed the following Cook Inlet area industrial
scenario.It is compared to industries assumed for the self-supplied
industrial forecasts of this report.
36
ISER
Cook Inlet Industrial Scenarios
Assumptions
Self-Supplied Industries Forecast
HIGH RANGE
Oil treatment and shipping facilities
Small LNG
Beluga Coal (40 emp loyees in shipping)
New capital (2,750 employees 1982-84)
Refinery-petroche~ica1 complex l!
Pacific LNG
Bottom fish industry
Oil lease development
No new pulp mills or sawmills
Existing refinery (2,.4 MW)
Existing LNG plant (.4 to .6 MW)
Coal gasification (0 to 250 MW)2/
New city (0 to 30 MW)-
New refinery (0 to 15.5 MW)
New LNG plant (0 to 17 MW)
Mining and mineral plants (5 to 50 MW)
Timber (2 to 12 MW)
Existing chemical plant (22 to 26 MW)
Aluminum smelter or other energy intensive
industry (0 to 280 MW)
MiD RANGE 1/
LOW RANGE
Pacific LNG New LNG plant (0 to 17 MW)
Existing refinery (2.4 MW)
Existing LNG plant (.4 MW)
Existing chemical plant (22 MW)
Coal gasification (0 to lOMW)
New refinery (0 to 15.5 MW)
Mining and mineral plants (0 to 25 MW)
Timber (2 to 12 MW)
A recent decision by ALPETCO changes this to the Valdez area.
The changes involved were not enou~h to warrant forecast revisions.
Part of coal gasification could be equivalent to "Beluga Coal,"but
.it i.s much more than "40 emp loyees in shiPping."
At the time this forecast and analysis was performed,no ISER mid-range
projections of populations and employment had been developed.
37
Estimate of Future Demands
Using the high and low population proj ections and high,mid,and low
kwh/capita assumptions,six different net generation utility forecasts
were obtained.From these,the high population/high energy use and the
low population/low energy use were used for the high and low range final
forecasts.The mid-range final forecast came from averaging the high
population/low energy use and the low population/high energy use
forecasts.In lieu of a miq-range net generation based on a mid-range
population projection,these last two forecasts were enough alike to
justify the average as mid-range net generation.
Near the completion of this analysis,ISER provided APA with a mid-range
population proj ection.Comparing the previous results with forecasts
using these mid-range proj ections,APA concluded that the two were
consistent and that no changes were neeessary.
National defense and self-supplied industrial forecasts were calculated
from the assumptions and summarized with the utilities on table 10 for
the Anchorage-Cook Inlet area and tab Ie 11 for the Fairbanks-Tanana
Valley area.Railbelt totals,both peak load demand and net generation,
are summarized on table 12.Appropriate graphs follow each table on
figures 9 and 10 for Anchorage-Cook Inlet,11 and 12 for
Fairbanks-Tanana Valley,and 13 and 14 for the Railbe1t totals.
~
I
Trend lines based on 1973-1977 average annual energy growth are
superimposed on the energy graphs,figures 9,11,and 13."-"""
1973-1977 Average Annual Growth
Anchorage-Cook Inlet
Fairbanks-Tanana Valley
Railbelt
10.9%
7.1%
9.9%
Historical and forecast energy use comparisons are summarized in table
9.
Comparison with Other Forecasts
This section compares the present forecast (1978)with two previous
forecasts,and forecasts available from various utilities.
The previous forecasts included the 1976 report and its 1977 update.
The 1977 update used 1975 criteria and assumptions.See table 13 for a
comparison tabulation.In general,the present forecasts produced values
less than the previous ones.
38
Table 9
NET ANNUAL PER CAPITA GENERATION (KWH)
RAILBELT AREA UTILITIES
Upper Susitna Project Power Market Analysis
Historical
High
Mid
Low
Historical
High
Mid
Low
1970 1977 1990 2000 .2025
Anchorage-Cook Inlet Area
4980 7630
16,300 21,400 35,100
14,000 17,500 22,400
12,000 13,600 13,600
Fairbanks-Tanana Valley Area
5655 10,240
18,400 24,000 39,000
16,300 20,300 26,000
14,100 15,800 15,900
APA 11/78
Energy use per capita nearly doubled in both areas in the historical
seven years.Growing use of electric space heating,electric cooking in
place of gas and oil,and many other possibilities can justify the
assumptions shown.Again,conservation has been factored in through
decreasing growth rates.
39
J.<iUl.e l.V
POWER AND ENERGY REQUIREMENTS
ANCHORAGE-COOK INLET AREA
Upper Susitna Project Power Market Analysis
PEAK POWER
1970 1973 1977 1980 1985 1990 1995 2000 2025
MW MW MW MW MW MW MW MW MW
UTILITY
High 620 1,000 1,515 2,150 3,180 7,240
Mid 165 230 424 570 810 1,115 1,500 2,045 3,370
Low 525 650 820 1,040 1,320
1,520
NATIONAL DEFENSE
High 31 32 34 36 38 48
Mid 35 33 41 30 30 30 30 .30 30
Low 29 28 26 24 24 18
J:-INDUSTRIAL
0 IUgh 32 344 399
541 683 1,615
Mid 12 12 25 32 64 119 199 278 660
Low 27 59 70 87 104 250
TOTAL
High 683 1,376 .1,948 2,727 3,901 8,903
Mid 212 275 490 632 904 1,264 1,729 2,353 4,060
Low 581 737 916 1,151 1,4~8 1,788
ANNUAL ENERGY
GWH GWH GWH .GWH GWH GWH GWH GWH GWH----UTILITY
High 2,720 4,390 6,630 9,430 13,920 31,700
Mid 744 1,108 1,790 2,500 3,530 4,880 6,570 8,960 14,750
Low 2,300 2,840 3,590 4,560 5,770 6,670
NATIONAL DEFENSE
High 135 142 lfl9 157 165 211
Mid 156 161 131 131 131 131 131 131 131
Low 127 121 115 105 lOLl 81
INDUSTRIAL
High 170 1,810 2,100 2,840 3,590 8,490
Mid 2 45 70 170 340 630 1,050 1,460 3,470
Low 141 312 370 460 550 1,310
TOTAL
High 3,025 6,342 8,879 12,427 17,675 40,401
Mid 902 1,314 1,990 2,801 4,001 5,641 7,751 10,551 18,351
Low 2,568 3,273 4,075 5,125 6,424 8,061
eJ ;;,.'JA 2/79
;(
)
hj
1-'-
lQ
C
I-i
(D
\.D
LOW
Upper susitna Project Power Market Analysis
ANCHORAGE-COOK INLET AREA
ENERGY FORECAST
2000 1-
30,000
40,000
100,000 r'-r -.,
90,000 7 I
80,000
70,000
60,000
50,000
2"0,000
(J)
cr
::>
0:r:
l-10,000l-
<t 9000
3:8000
<t 7000
<:)-6000
C>
5000
4000
3000?;
~
.....
t'-J
"-...]
OJ
.r:--......
1000 II'1 1 I I !I I I I I I I
1970 1915 19711980 19851990 1995 2000 2005 2010 2015""2020 2025
YEAR
upper Susitna Project Power Market Analysis
ANCHORAGE-COOK INLET AREA
PEAK LOAD FORECAST
3000
4000
10 1 000'I
9000
8000
7000
6000
5000
2000
LOW
I /'./'-(J)
}-
./:"-}-N <r
3';1000«900
Cl 800
W 700~I I //~"'"'-
600
500
400
?ti 300V I hj
I /-'-~lQ
~
I-'I 11
IV CD
........200 I--.l I-'
00 0
100 I "I !I I I I.I I I J
1970 19751977 1980 1985 1990 19?~...·...l.·"2000 2005 2010 2015 2020 2025
.~AR
~c >
)')
Table 11
POWER AND ENERGY REQUIREMENTS
FAIRBANKS-TANANA VALLEY AREA
Upper Susitna Project Power Market Analysis
PEAK POWER
1970 1973 1977 1980 1985 1990 1995 2000 2025
MW MW MW MW MW MW MW MW MW---------UTILITY
High 158 244 358 495 685 1,443
Mid 56 73 119 150 211 281 358 452 689
Low 142 180 219 258 297 329
NATIONAL DEFENSE
High 49 51 54 56 59 76
Mid 44 41 41 47 47 47 47 47 47
.p-Low 46 44
42 40 38 29w
TOTAL
High 207 295 412 551 744 1,519
Mid 101 114 160
,
197 258 328 405 499 736
Low 188 224 261 298 335 358
I
ANNUAL ENERGY
GWH CWH GWH GWH GWH GWH GWH Glill GWH----------_.-
UTILITY
High 690 1,070 1,570 2,170 3,000 6,320
Mid 239 324 483 655 925 1,230 1,570 1,980 3,020
Low 620 790 960 1,130 1,300 1,440
NATIONAL DEFENSE
High 213 224 235 247 260 333
Mid 203 200 207 >207 207 207 207 207 207
Low 203 193 184 175 166 129
TOTAL
"
High 903 l,29!f 1,805 2,417 3,260 6,653
Mid 443 524 690 862 1,132 1,437 1,777 2,187 3,227
Low 823 983 1,144 1,305 1,466 1,569
APA 11/78
FAIRBAN~(S-TANANA VALLEY AREA /
OPper Susitna ~~c~tRp~wy'!r~c~~~~i~T ~~~~
",.9'd \G'r\0'1 ~\
24000
3000
10,000r'-.------""'7'"-------..
9000 7 I
8000
7000
6000
5000
J
100 I I I I !I I I I !,!I
1970 1975 1977 1980.1985 1990 1995 2000 2005 2010 2015 2020 2025.)
).
l
2020 20252015200520)01990.1995 2000
YEAR
1985
FAIRBANKS-TANANA VALLEY AREA
PEAK LOAD FORECAST
Upper Susitna Project Power Market Analysis
100C:I!1 I !I !!!I I I
1970 1975 1977 1980
4000
3000
10,000 i I
9000
8000
7000
6000
5000
2000
en
.t:'-I-
V1 to-«
~.~1000
«900
(!)800W
::a 700
600
500
400
~300
LOW
~
I
f-'
I
N
I
hJ
""--J 200
I
.....
co I
l.Qs::
Ii
CD
f-'
N
./:'-
0'1
Table 12
POWER AND ENERGY REQUIREMENTS
(RAILBELT AREA)
Upper Susitna Project Power Market Analysis
PEAK POWER
1970 1973 1977 1980 1985 1990 1995 2000 2025
MW MW MW MW MW MW MW MW MW------ -- --
-TOTAL
High 890 1,671 2,360 3,278 4,645 10,422
Mid 313 389 650 829 1,162 1,592 2,134 2,852 4,796
Low 769 961 1,177 l,l,[,9 1,783 2,146
Average Annual
Growth for period % %%%%%%%
High 11.0 13.4 TI .6.8 7.2 3.3
Mid 7.S 13.7 8.4 7.0 6.5 6.0 6.0 2.1
Low 5.8 4.6 4.1 4.2 4.2 0.7
ANNUAL ENERGY
TOTAL
High
Mid
Low
Average Annual
Growth for period
High
Mid
Low
Note:The increase
addition in 1985 of
(280 MW).
)
GWH GWH GOO GWH .GWH GWH.GWH GWH GWH
3,928 7,636 10,684 14,844 20,935 47,054
1,345 1,838 2,681 3,663 S,133 7,078 9,528 12,738 21,578
3,391 4,256 5,219 6,430 7,890 9,630
%%%%%%%%
13.6 14.2 6.9 6.8 TI 3.3
11.0 9.9 11.0 7.0 6.6 6.1 6.0 2.1
8.1 4.6 4.2 4.3 4.2 0.8
in 1980-1985 high range growth rates reflects the
the energy intensive self-supplied industry load
APA 11/78
)
Upper Susitna Project Power Market Analysis
TOTAL RAILBEL T AREA
ENERGY FORECAST
30,000
40,000
100,000 I )1
90,000
80,000
70,000
60,000
50,000
20,000.-
ma::
::>
0.r:--:r"--J
I-10,000 C ///LOWI-9000<X:8000~.
<t 7000
C!)
6000-
C!)
5000
4000
~3000 ~)'.hj
~.
;rJ LQr::H Iil'V CD"'-2000 .--.j •i-'OJ W
1000 I J I I I I I I I I I I I
1970 1975 1977 1980 1985 1990 1995 2000 2005 2010 2015 2020 202.5...YEAR
TOTAL RAILBELT AREA
PEAK LOAD FORECAST
Upper Susitna Project Power Market Analysis•
3000
4000
10 1000 i ::::;:;;;0'"I
9000
8000
7000,
6000
5000
Table 13
""",COMPARISON OF UTILT1 ENERGY ESTIMATES
)1976 MARKETABILITY REPORT-,Uf .....E OF 1976,AND 1978 ANALYSIS
Upper Susitna Project Power Market Analysis
Anchorage-Cook Inlet Fairbanks-Tanana Valley Total Railbe1 t
Forecast\1976 Update 1978 1976 Update 1978 1976 Update 1978
Year Ran~Report of 1976 Forecast Report of 1976 Forecast Report of 1976 Forecast
1974 Historic 1,305 1/1,189.7 1/330 353.8 1,635 1,543.5
1975 High 1,489 377 1,866
Mid 1,467 371 1,838
Low 1,450 367 1,816
Historic 1,413.0 450.8 1,863.8
+:--1976 High 1,699 430 2,129
\0 Mid 1,649 417 2,066
Low 1,611 407 2,018
Historic 1,615.3 468.5 2,083.8
1977 High 1,939 490 2,429
Mid -1,853 469 2,322
Low 1,790 453 2,242
Historic 1,790.1 1,790.1 482.9 482.9 2,273.0 2,273.0
1980 High 2,850 2,660 2,720 700 720 690 3,550 3,380 3,410
Mid 2,580 2,540 2,500 660 690 655 3,240 3,230 3,155
Low 2,410 2,460 2,300 610 660 620 3,020 3,120 2,920
1990 High 6,880 6,300 6,630 1,660 1,700 1,570 8,540 8,000 8,200
Mid 5,210 5,000 4,880 1,270 1,360 1,230 6,480 6,360 6,110
Low 4,420 4,410 3,590 1,050 1,180 960 5,470 5,590 4,550
2000 High 15,020 13,600 13,920 3,500 3,670 3,000 18,520 ·17-,270 16,920
Mid .9,4io 8,950 8,960 2,230 2,440 1,980 11 ,650 11,390 10,940
Low 6,570 6,530 5,770 1,530 1,750 1,300 8,100 "8,280 7,070
!.7-Fi14 historiclfata revised between 1975 and 1978.APA 11/78
GWH =million kwh
Further comparisons confirm that the 1976 report forecast was valid.
Historic values through 1977 fell between the high and low ranges of the
forecast.
The 1976 report was based on load data through 1974 and the following
assumptions for uti1it¥load growth:
Average Annual Growth Rates
1974-1980 1980-1990 1990-2000
High Range 14.1%9.0%8.0%
Mid-Range 12.4 7.0 6.0
Low Range 11.1 6.0 4.0
The following percentages compare this report and the above assumptions.
Average Annual Growth Rates From
1978 Utility Energy Forecast
High Range
Mid-Range
Low Range
1977-1980
14.5%
11.5
8.7
1980-1990
9.0%
6.8
4.5
1990-2000
7.5%
6.0
4.5
The 1976 report based the utility energy forecast on assumed average
annual growth rates.The 1978 report based the fOrecast on assumed
growth in population and per capita energy use.Both reports considered
energy conservation,but it was given more specific and higher
importance in the 1978 forecast.
Forecasts available from various utilities are tabulated on tables 14,
15,and·16.Some were done by the utilities,some by consultants,and
some by REA.All data was tabulated and,where necessary,extrapolated
as part of the State Alaska Power Authority Railbel t Intertie Study.
Comparisons are summarized in 5-year increments.
Utility Forecasts 1978 Susitna Forecasts
Energy (GWH)High Mid Low
1980 3,344 3,410 3,155 2,920
1985 6,277 5,460 4,455 3,630
1990 10,965 8,200 6,110 4,550
1995 17,748 11,600 8,140 5,690
2000 26,550 16,920 10,940 7,070
Peak (MW)
1980 725 778 720 667
1985 1,377 1,244 1,021 830
1990 2,.986 1,873 1,396 1,039
1995 3,835 2,645 1,858 1,298 ~2000 5,641 3,865 2,497 1,617
50
The utility forecasts run higher than those of this report.No definite
reason for the differences can be made other than the utilities assumed
higher growth rates.The basis of the utility assumptions was not
considered in this study.
51
----------------------------rF'---------------------------
Table 14 ~,
UTILITY ENERGY FORECASTS (GWH)
ANCHORAGE-COOK INLET AREA
Upper Susitna Project Power Harket Analysis
Year AML&P 1/CEA 2:../MEA '}j HEA !:./Total
1979 634 1,109 280 310 2,333
1980 699 1,283 333 374 2,689
1981 771 1,468 395 452 3,086
1982 847 1,679 468 546 3,541
1983 930 1,921 559 620 4,030
1984 1,018 2,197 668 705 4,588
1985 1,111 2,509 799 800 5,219
1986 1,210 2,810 954 909 5,883
1987 1,313 3,147 1,140 1,033 6,634
1988 1,422 3,525 1,322 1,155 7,424
1989 1,534 3,948 1,534 1,290 8,306
1990 1,650 4,422 1,779 1,442 9,293
1991 1,770 4,864 2,064 1,611 10,309
1992 1,891 5,350 2,394 1,801 11,437 ,.-,."
1993 2,014 5,885 2.706 1,978 12,584
1994 2,138 6,474·3,057 2,173 13,843
1995 2,245 7,121 3,455 2,388 15,209
1996 2,357 7,691 3,904 2,623 16,575
1997 2,475 8,306 4,412 2,882 18,075
1998 2,599 8,971 4,853 3,111 19,533
1999 2,729 9,638 5,338 3,359 21.113
2000 2,865 10,463 5,872 3,626 22,826
Source:Obtained from utilities in 1978 for Alaska Power Authority
Rai1be1t Intertie Study.
1/Anchorage Municipal Light &Power Department
2/Chugach Electric Association
3/Matanuska Electric Association
4/Homer Electric Association
APA 1/79
52
Table 15
UTILITY PEAK DEMAND FORECASTS (Mttl)
ANCHORAGE-COOK INLET AREA
Upper Susitna Project Power Market Analysis
Year AML&P 1/CEA Y MEA 2J REA I:..!Total
1979 124 239 67 64 495
1980 138 271 81 78 567
1981 152 310 97 94 653
1982 167 355 116 113 752
1983 184 406 142 129 860
1984 202 465 171 146 983
1985 221 530_207 166 1,124
1986 241 594 251 188 1,274
1987 263 655 303 214 1,445
1988 285 745 343 239 1,612
1989 309 835 389 267 1,800
1990 333 935 442 29)1 2,008
1991 358 1,028 501 334 2,222
1992 384 1,131 569 373 2,458
·1993 411 1,244 630 410 '2,695
1994 437 1,369 698 451 2,954
1995 461 1,505 773 495 3,234
1996 486 1,626 857 544 3,512
1997 512 1,756 950 598 3,816
1998 539 1,901 1,026 645 4,111
1999 568 2,048 1,108 696 4,421
2000 599 2,212 1,197 752 4,759
Source:Obtained from utilities in 1978 for Alaska Power Authority
Railbe1t Intertie Study.
1/Anch.orage Municipal Light &Power Department
2/Chugach Electric Association
3/Mat8muska Electric Association
4/Homer Electric Association
APAl/79
53
·,".........-,--,------,-----"4'4---------------------
Table 16 ~I
UTILITY ENERGY AND PEAK DEMAND FORECASTS
FAIRBANKS-TANANA VALLEY AREA
Upper Susitna Project Power Market Analysis
Net Energy (GWH)Peak Demand (MW)
Year GVEA 1./FMU :!:../Total GVEA FMU Total
1979 450 144 594 111 33 144
1980 502 153 655 123 35 158
1981 560 162 722 136 37 173
1982 625 172 796 151 39 190
1983 693 182 875 167 42 209
1984 769 193 962 .186 44 230
1985 853 205 1,058 206 47 253
1986 947 217 1,164 228 50 278
1987 1,050 230 1,280 252 53 305
1988 1,155 244 1,399 278 56 334
1989 1.271 259 1,529 305 59 364
1990 1.398 274 1,672 335 63 398 ~.1991 1,537 288 1.825 368 '66 434
1992 1,691 302 1.993 405 69 474
1993 1,843 317 2.160 440 72 512
1994 2.009 333 2,342 480 76 556
1995 2,190 350 2,540 521 80 601
1996 2,387 367 2,754 569 84 653
1997 2,602 386 2,987 619 88 707
1998 2,810 405 3,215 668 92 760
1999 3,035 425 3.460 722 97 819
"2000 3.278 446 3.724 780 102 882
Source:Obtained from utilities in 1978 for Alaska Power Authority
Railbe1t Intertie Study.
1/Golden Valley Electric Association
II Fairbanks Municipal Utilities
APA1/79
54
Load Distribution
Reservoir operation studies used in sizing reservoirs need an average
monthly distribution of annual energy to help relate hydroelectric
output to the elec;tric load.This section reports updated averages of
monthly energy use divided by annual energy use wi thin the
Anchorage-Cook Inlet area.
This section also reports a study of hourly load distribution in the
weeks of winter peak load (same as annual peak)and summer minimum peak
load.By studying these load curves from several years,hydroelectric
plant factor is evaluated.(See capacity section).
The utility systems have had combined annual load factors slightly over
50 percent in the past few years (54 percent in 1977 as shown on figure
17)-.Data presented in table 17 shows that mid-summer peaks have been
running about 60 percent of mid-winter peaks and that monthly load
.factors generally exceeded 70 percent.For 1977,the December load
factor was 76 percent.Figures 15 and 16 illustrate that winter and
summer loads are quite similar.The load duration curves of figure 17
present these daily load curves concisely.The 1976 report contains
daily load curves of previous years.Winter and summer curves are
plotted together showing similarities of slope and shape.
The update of average monthly energy'is presented.as percent of the
r-,annual value in table 18.Average percentages used in the 1976 report
compare closely with 1970-77 averages.Slight changes are reflected in
the "recommended distribution"column.Winter load is about two-thirds
of total.
55
SYSTEM DAILY GENERATION CURVEANCHORAGEAREAUpperSusitna project Power Market Analysis
,...'"'=#___.,.__~~_,."""""_"."""-_,.,,,,,,..,..,~_,.,;~-'-'~t,.
4~
;I
.i I i iI
i I
lJ1
0'1
,..'''"I,III'I'!I4.n111 I . I I II I '~
_:rn;H-t+t+t11 1 III 'lInWr--··--·..·~I '1'1 I --.n~l":I!m.h.e.,6 ..11.t91S I 'I .".
1rtliIIIIIIUIIIIWIIIIIL I I:II:I ·1 I I I 1,111 h-ru-
I ill,r!!1 I I l ",I ,I
1 I :!I 'I,ll I i I "'I '!:11 II i l i J
-,!I I;I,I I I
6...l11 \,1-111111111111111 1 1'11 I I I I 1"l..lr'11 I ':I ~
rr;:-----.:~
---+-J-t-t.-.w',rH-++-HJ+FlW1twttljh+ttllimttttlmtHm4-H-H~~FW-Wmn[[[OIITJ~II:I:-'i:,fl I ;I~......,.-.i"'"
-,',P·hi:I !
I I I,I:i I
:;:~;
120
/10
100i;j
~
f-'
N
'---.l
OJ
SUNDAY :':ONDAY TUESDAY WEDNESDAY SATURDAY
DAYS OF THE WEEK
)J .)
,
SYSTEM DAILY GL)ERATION CURVE·:',.)
'ANCHORAGE AREA Upper susitna Project Power Market Analysis
II ill i 11./i'lIIITTl rm I:
;tjlllll':lIfllllllllll!'I,1 , I I lilllillilTill'\-1 J Ii II
."',!mfI'II:I!II !rnmII
i !I !II i III i1:i II j 1III I I I I I I!i 11111'II !Ii I
'~-!f~..lf.;LL~-f-l-l.l-l..J...:.LL1.:!,.u.~-:!:-L.l:l.::L1..!:J..L!-W-~~~6~~.;~i ~i J
iT·1 I 1\1-r-rTl'T~1!'1 \I I:11111111\IIIIII\llllllllllllllllltll!rTr:lmmTn:llTlrmrrml .11;
SUNDAY TUESCAY •mNESOAY THURSDAY FilIl>AY SATURDAY
~.EXCESS 0'IH?:I OvER '918 .'"DAYS OF THE WEEK
..-.~-.--_._----"-----._--
Figure 17
ANCHORAGE AREA
LOAD DURATION CURVE
1977
Upper Susitna Project Power Market Analysis100r,---...,...---,..-----,---,.-----r--.,-----,--...,..---,---;
June 1977
December 1977
Summer Peak Load30
540/0 load Factor
70 ..I--Winter Peak Load
-.----.-~-------------------650(0
Winter Base Load
80
90
60
~«
L.tJ 50a...
~0 40
Summer Base Load
20
10
o 10 20 30 40 50 60 70 80 90 100
%TIME
APA 12/78
58
'Table Ii
LOAD DISTRIBUTION'CHARACTER1STICS
MONTHLY P~AK LOADS'AND LOAD FACTORS'.
Upper Susitna Prqj ect Power Market AnaIya.i~,;!
)
I
I
}'
I 1971-1972 .1972-1973 1973-1974 1974-1975 1975-1976 1975-1977.
.J ...-...;:J::.u -.u ::c .u ..,
JI.ffi l)~.~0 ~~0 ~~,I)JI.:;:U X .,.0,
r.!&to to ttl ~ttl ~t:I :;a d 2 lOa t;l
(}&14 (l)~.(l)t:..:...
~"l,O p.,""p.,"A "0 'I:0 't1 0 ~0 'd 0 ';;l 0 ';:l
~ri .s ~ri ttl ~ri,rl ri ro ~ri ",.....-I (5~ttl :::III .s ~III 0 ...ro oS ~~0 ~r:~.A g >.;;0;j ~g );I-l ...~;::I >.A ;::I ><h "'"~>-,.::
:3 e'0\~C'C t;'\G':.:c ~\.l .~l:H .~t:\.l .~C J.<,:>!.<J.<-r.:l .::(}S 1:.1 C <QJ I::.::(l),I::ttl <(J tJ (J -5 ('J c ~t:o·!J c::0 (l)c ~1:.1 C 5 <J C 5:::p.,.P ~dP ~:,,;Il<n w ::<:tl<.'1'14 tl<.,~:.::t..c'.'~:::
I
)eto!:lc::IS5.8 73 94.1 68 209.2 74 10B.8 70 224.3 B2 122.7 73 252.9 71 134.3 71 342.2 81 153.0 60 359.a S8 182.2 63.
~o'Je:;-';'er 222.8 aa 113.0 70 -236.3 83 124.4 73 269.6 98 .144.6 74 266.2 .75 156.0 a1 367.6 87 ,196.2 74 360.7 as 193.8'75
'ec~::-.ber 236.2 93 121.1 70 260.7 92 .143.3 74 266.9 97 147.0 74 314.9 89 -170.7 i3 420.5 100 226.3 72 ~oa.3 100 223.4 74.
ra:r~~::y 254.5 100 135.3 72 233.0 100 153.6 72'274.5 100 159.3 78 354.1 100 180.8 69 394.1 94 213.3 73 376.4 92 209.9 75
lal:':-t:.z.=y 22~.5 88 115.3 76 -259.6 92 127.5 73 264.5 .96 139.4 79 316.7 89 166.9 78,383.3 'n 203.5 i6 356.8 81 181.7 76
..
:arch 222.8 87 119.2 70 225.1 80 125.5 75 '2'-:9.4 '91 ·135.5 73 26B.6 .76 156.6 7S'342.,1'81 187.6 7'-:,369.0 90 :WS.&76
,p:il 176.7 69 96.6 76 196.4 69 105.4'75 201.6 73 112.4 77 249.0 70 129.2 72 2,85.3 6B 159.0 77 334.4 82 177;0 73
:ay 157.9 62 87.8 75 176.7 62 9a.5 75 180.4 66 104.17S 222.0 63 120.9 73 253.6 60 145.0 77 2St,.S 70 161.3 76
·~:'I.e ''152.1 66 78.5 72 165.2 58 87.6 74 176.2 64 95.4 75 209.0 59 113.Q 75 236.1 56 128.9 76 265.0 65 H8.1 79
'a1y 146.8 '52 76.6 70 162.8 59 .89.S 74,178.9 65 97.5 73 207.0 58 110.9 72 248.0 59 134.4 73 257.!.63 141.3 74
,\::.gust.134.5 54 86.9 75 175.9 64 96.2 73 195.7 71.101.9 70.211.5 61 UB.3 73 250.6 60 139.9 73 271.8 67 151.7 75
~pt.Cl:':ocr I 179.6
.
64 92.9 72 194.5 71 100.8 72 210.3 77 106.1 70 247.4 70 131.9 74 278.0 66 151.2 76 318.9 79 166.7 73
.
in,St:::,~e~·?~a:'{
=:57.7f.1 57.5t.1 64.2~58.59"56.~'G 63.O~.
~:,.~,·':'ntc=?O~:~
l/Rcprescnts s~m of loads fo~the Anchorage (kV~&?,C~A)
--and Fai~ba~~s (FMv,GVEA)utilities
Table 18 c~
MONTHLY ENERGY REQUIREMENTS AS PERCENT OF ~rruAL REQUIREMENT
Upper Susitna Project Power Market Analysis
1970-1972 1970-1977
Utility Utility Recommended
MONTH Loads 1/Loads 2/Distribution 3/
Oct.7.9 8.1 8.2
Nov.8.9 9.2 9.0
Dec.10.2 10.2 9.7
Jan.11.3 10.8 10.2
Feb.9.2 9.3 9.1
Mar.9.8 9.4 9.1
.April 8.0 7.8 7.9
May 7.2 7.3 7.6
June 6.5 6.6 7.0
July 6.4 6.7 7.1
Aug.7.1 7.1 7.4
Sept.7.5 7.5 7.7
Total 100.0 100.0 100.0
SEASONAL
Oct.-April 65.3 64.8 63.2
May-Sept.34.7 35.2 36.8
~
l/Combined loads of CEA~AML&P,GVEA~FMUS,for Oct.1970-Sept.1972.
Basis for (1975 Susitna Power market analysis)1976 report.
1/Combined net generation of CEA,fu~&P,APA,GVEA,FMUS,for Oct.
1970-Sept.1977.Updated Basis.
1/Assumes total requirements consisting'of 25 percent industrial loads
and 75 percent utility loads.Update of previous recommendations.
60
Capacity Requirements
With reference to the load factor evaluations in the previous section,a
trend towards somewhat higher annual load factors in the future is
anticipated.In addition to benefitting from any load diversity in the
interconnected system,peak load management (including such practices as
peak load pricing)offers considerable opportunity for improving load
factors,which in turn reduces overall capacity requirements for the
system in any given year.For planning purposes,it is assumed that the
annual system load factor will be in the range of 55 to 60 percent by
the latter part of the century.
Sys tem capacity
requirements plus
The 1Gwer summer
and'repairs.
requirements are determined by winter peak load
allowances for reserves and unanticipated load growth.
peaks provide latitude for scheduled unit maintenance
System daily peak load shapes indicate that a very small portion of the
capacity is needed for very low load factor operation.Some of the gas
turbine capacity now used for base load is expected to be used mainly
for peak shaving purposes,eventually.It will be operating during peak
load hours for the few days each year when loads approach annual peak,
and will be in standby reserve for the balance of the year.Figure 17.
the annual peak week duration curve,shows that the highest 10 percent
load occurs for 30 percent of the week (about two days).
Reliability standards would be upgraded as the power systems deveJ-op.
Likely in~lusions are specific provisions for maintaining spinning
reserve capacity to cover possible generator outages and substantial
improvements in system transmission reliability.
Results -Examination of the winter load duration curve (figure 9)
indicates that the base load portion is about 65 percent of total load
and the peak load is about 35 percent of total load.Load factor for
the peak portion is about 54 percent.Winter weekly load factors are
approximately 80 percent.This is illustrated in the winter and summer
load duration curves by proportioning the areas under the curves to the
total possible area if peak load occurred 100 percent of the time.
An annual plant factor of 50 percent is recommended for the proposed
Upper Susi~a Project.This is largely a judgment factor and is based
on the folloWing considerations:
1.The recommended plant factor provides for serving a proportional
share of both peaking and energy requirements throughout the year while
maintaining adequate flexibility to meet changing conditions in any
given year.
2.Any significant reduction in this capacity could materially reduce
flexib Hity.
61
------~--_.---------------.,,--------
3.A significant market for low load factor peaking capacity seems
unlikely within the foreseeable future.Load management and additional
industrial loads will probably increase the overall system load factor
in the future.It is expected that several existing and planned gas
turbine units could eventually be used for peak shav,;ing.
4.It is recognized that the mode of operation for the hydro will
change through time.In the initial years of operation,it is likely
that the full peaking capacity will be used infrequently.For example,
the mid-range Railbelt estimated system peak load for the year 2000 is
2,852 MW.Assuming load shapes similar to the current Anchorage area
loads,the winter peak week would require about 1,850 MW of continuous
power to cover the base loads and about 1,000 MW of peaking power.Load
factors of the peak portion would be about 50 percent.
A design capacity based on 50 percent plant factor applied to average
annual energy (primary plus secondary)appears appropriate.Machine
overload capability contributes to spinning reserves for emergencies or
other short term contingencies.
The Corps based nameplate capacity on 50 percent plant factor applied to
critical year firm energy.This smaller capacity,when applied to
average annual energy,results in a 56 percent plant factor.APA feels
the smdller design capacity may unduly reduce flexibility.
62
.~.
1
PART VI.ALTERNATIVE POWER SOURCES
Introduction
This section examines alternative power supply options in the Railbelt
in lieu of the Upper Susitna Project and presents detailed cost
estimates of power from new coal-fired steam plants.
Alternatives premised on unproven technology were eliminated.
Alternatives Considered
Potential 8,lternative sources of electric power generation are identi-
fied by energy type.They are coal,oil and natural gas,hydro,
nuclear,wind,geothermal,and tide.
Some alternatives will be restricted in time or capacity because of
Federal energy policy controlling use of energy resource.Others will
be restricted by practical available energy supply.Still others are
impractical because of lack of large-scale technology.
Coal
Evaluation of coal utilization is based on mine-mouth coal-fired steam
generation.Potential advanced technology,such as gasification,is not
considered because,development would not be available within this study
period.
Recent studies provide general information about possible locations,
s~z~ng,and cost of new steamplants,but Alaska specific data are
limited and extrapolations have been made for local conditions.
Information sources of specific interest for this analysis are:studies
by Battelle Pacific Northwest Laboratories (March 1978);the Electric
Power Research Institute (EPRI)(January 1977);and the Washington
Public Power Supply System (WPPSS)(June 1977);the Federal Energy
Regulatory Commission (FERC)determination of power values for the
Bradley Lake Project (October 1977)and the Upper Susitna Project
(October 1978);and evaluations of costs for the proposed Golden Valley
Electric Association (GVEA)plant additions at Healy.These are all
listed in the bibliography.
Location It is assumed that new coal-fired steamplants would be
located near the Beluga fields for service to the Anchorage-Cook Inlet
area and at Healy for service to the Fairbanks-Tanana Valley area.The
plants would use known but undeveloped coal resources at Beluga and the
existing coal mining operation near Healy.
63
It is recognized that other locations are possible.For example,it may
be possible to locate a coal-fired plant on the Kenai Peninsula and use
coal from either local reserves or Beluga.A Kenai location might offer
co-generation possibilities because steam could:be reused in
manufacturing by the petrochemical industry.The potential for mining
coal on the Kenai Peninsula is substantially less attractive thaI].for
Beluga because of thin coal seams and other geologic factors.
Capaci ty -These analyses are for two-unit 200-W;""and SOO-MW plants.
This size range is considered appropriate for new coal-fired plants that
might come on-line between 1985 and 2000.
Investment Cost -Table 19 summarizes unit investment costs for new
coal-fired plants presented in several recent studies.The data
assembled by each entity is quite complex with respect to original
estimated price levels,inflation to updated price levels,or projected
future on-line dates,size,pollution control equipment,location,type
of plant.and other items.Price levels were not adjusted to a uniform
date because of the complexity of data involved.
All 1977 and 1978 estimates are substantially higher than APA estimates
for the 1976 Alaska Power Survey and the 1976 report.
The most in-depth analysis was the WPPSS study which investigated the
construction.of 1,OOO-MW steamplants at 10 plant sites in Washington,
Montana,and Wyoming.Several grades and sources were assumed.Costs
were estimated for with and without sulphur dioxide scrubbers
(scrubbers).Twenty-two options of plant sites,coal supply,and trans-
portation were investigated.
APA's estimate of coal-fired steamplant investment costs is derived from
the WPPSS study,Procedures for adjusting costs to current Alaska
conditions are similar to the analysis used in the appended Battelle
report.
The basic cost in the WPPSS study for a 1,000 MW single unit plant in
operation during mid-1976 was:
,-...
Without Scrubbers
With Scrubbers
$554/kw
$684/kw
The WPPSS procedure increased these costs for the quality of the coal
used and other specific powerp 1ant site conditions.The coal quality
problems have not been considered in this estimate,and the construction
site variable is assumed to be included in the Alaska factor.
64
-)')
Table 19
COMPARISON OF INVESTMENT COSTS FOR COAL-FIRED STEAMPLANTS
Upper Susitna Project Pow~rMa~ketAn'ciiysi'~
0'1
\JI
Source of Estimate
ALASKA LOCATIONS
APA ))
APA Susitna River Studies
Golden Valley Electric
Association'!:../
3Battelle-/
Price
Level
'Oct.1978
Oct.1978
Oct.1978
Oct.1978
Jan.1975
Jan.1975
1974
1977
1977
1978
Jan.1977
Jan.1977
Jan.1977
Jan.1977
Jan.1977
Jan.1977
Location
Healy or Beluga
Healy or Beluga
Healy or Beluga
Healy or Beluga
Healy or Beluga
Healy or Beluga
Healy
Healy
Healy
Healy
Beluga
Beluga
Healy or Nenana
Healy or Nenana
Anchorage
Anchorage
Size,MW
200
200
500
500
200
500
132
150
150
100
200
200
200
200
200
200
No.of
Units
2
2
2
2
2
2
2
2
2
1
1
1
1
1
1
1
Scrubbers
No
Yes
No
Yes
Ye-s
Yes
No
No
Yes
Yes
No
Yes
No
Yes
No
Yes
Investment
Cost,$/kw
1,500
1,860
1,300
1,610
726
630
950
1,400
1,700
1,800
1.220 to 1,571
1,400 to 1,766
1,470 to 1,920
1,710 to 2.158
1,120 to 1,440
1,280 to 1.690
Oct.1978
Jan.1977
Oct.1978
Federal Energy Regulatory
Commission Y Anchorage or
Kenai Areas
Anchorage or Kenai
------'-------~.-Areas
Healy
450
450
230
2
2
-2
Yes
Yes
Yes
900
1,220 to 1;240
1,475 to 1,510
Tah1e 19 (cont.)
COMPARISON OF INVESTMENT COSTS FOR COAL-FIRED STEAMPLANTS
Vpper Susitna Project ,Power Mi.HlcetAna!ysis
Source of Estimate
Price
Level Location Size.MW
No.of
Units Scrubbers
Investment
Cost.$/kw
The 1978 estimates assume operation
include 5 percent annual inflation.)
!I APA's estimate is based 1argly on the WPPSS study with adjustments for Alaska conditions and size of plant.
Future inflation not shown.".
2/GVEA 1974 estimate assumed units hecoming operational in 1983 and 1986.
-in 1984 at $2.500/kw assuming 7%inflation.
3/Battelle's estimates are based on adjusting both WPPSS and EPRI study data.The higher figures are from the
-EPRI study.Their studies with future operation dates include inflation.
4/Scrubbers are assumed included in the cost.
S/This is the basic study adjusted by APA and Battelle above.The 1987 costs
~.).cThe July 1976 price level includes costs for init )operation in 1978.
7i J"The price level is 1975 costs adjusted to show cm:h:."s for a 1984 operation date.
Adjusting the cost for the time between mid-1976 and October 1978 us~ng
the Handy-Whitman Steamp1ant Cost Index increased the cost 18.4 percent.
Without Scrubbers
With Scrubbers
$656/kw
$810/kw
Powerplants smaller than the 1,000 ffi{that will fit near-future Alaska
power needs have a smaller total cost,but a larger cost per installed
kilowatt.An adjustment needs to be applied to the costs to compensate
for the loss of economy of the large scale plants.The factor recom-
mended is the ratio of the plant size to the 0.85 exponent.A 500-MW
plant thus costs 55.5 percent of a 1,000 MW plant,and a 200-MW plant
costs 25.5 percent.Scaling the plants to 200 MW and 500 MW gives:
.Plant Size
Without Scrubbers
With Scrubbers
$Million
167,000
207,000
200 MW
$/kw
835
1,035
$Million
364,000
450,000
500 MW
$/kw
728
899
An Alaska factor of 1.8 was used to adjust Pacific Northwest costs to
Alaska wages and conditions:
Plant Size
Without Scrubbers
With Scrubbers
$Million
300,000
372 ,000
200 MW
1,500
1,860
$Million
655,000
810,000
500 MW
1,310
1,620
Fuel Cost and Availability -There is a wide range of opinions about the
probable future cost of coal.For many years,coal prices were set at a
small margin above production costs so that coal could compete with
low-cost oil and natural gas.This situation has changed drastically
because of price increases for oil and gas and incentives for power
generation and has resulted in industrial conversion to coal.Coal
production costs are also increasing rapidly due to normal inflationary
and regulation factors.FERC reported the national average price of
coal at 96,.2¢/million Btu in July 1977,up from 80.8¢in July 1975.and
39.8¢in August 1973.
Alaskan coal prices have shown sizable increases recently.The cost of
coal at Healy in September 1978 was 80 cents per million Btu,up from 62
cents in 1975.The Fairbanks Municipal Utility System (f:t.1US)pays an.
additional $6/ton shipping cost for Healy coal resulting in a price of
$1.15 per million Btu at the powerplant in Fairbanks.
67
--"""1,---------------------
In October 1978,owners of the Beluga coal field stated that large ~.
reserves in the Beluga coal field may compete in the world energy market
at a price of $1.10 to $1.40/million Btu stockpiled on the shore of Cook
Inlet.The conclusions were based on company studies that included
geologic investigations,drilling,bulk sampling programs,'mining
preparation,environmental evaluation,and navigation and shipping
studies.
FERC estimated $1.DO/million Btu for determination of power values in
the Bradley Lake Project (October 1977).Other recent studies suggest
this is a reasonable current (1978)cost for Beluga coal delivered to a
steamplant at Beluga,with no allowance for price increase in future
years.
Earlier MA studies for the 1976 FPC Power Survey and the 1976 Susitna
report .assumed $1.00 to $1.50/million Btu for coal at 1985 price levels
in 1974 dollars.This included consideration of future economies of
scale of larger mining operations.
APA analyses for this report are still based on a coal cost of $1.00 to
$1.50/million Btu for a mine-mouth plant at either Beluga or Healy for
mid-1980 conditions.This is comparable with $1.28 in 1985,estimated
by GVEA for Healy coal by increasing the current 80 cents by 7 percent
annually.Because of the wide diversity of studies and opinions,
analyses based on a range of costs are .presented.
In this study,we are assuming fuel values will increase about 2 percent~.
per year--more rapidly than overall price indexes.This is consistent
with other analyses.
68
Table 20
GENERATION COSTS FOR CONVENTIONAL COAL-FIRED STEAMPLANTS
Upper-Susitna Project Power Market Analysis
1985 COSTS (1978 PRICES)l/Plant Size,MW
200 500
Number of Units
Investment Cost,Railbelt,$/kw
Capital Cost,mills/kwh
2
1,860
38.5
2
1,620
33.5
Operation and Maintenance,mills/kwh
Subtotal
Assumed Fuel Costs,mills/kwh
Transmission Cost to Load Center
Total Energy Cost,mills/kwh
1994 ENERGY COST
Capital Cost,mills/kwh
Operation and Maintenance,mills/kwh
Transmission Cost,mills/k~m
Subtotal
Fuel,Inflated 2%1985 to 1994
Total
6.5 5.6
45.0 39.1
1.00/mmBtu 1.50/mmBtu
10.0 15.0 10.0 15.0
4.0 4.0 3.0 3.0
59.0 64.0 52.1 57.1
Fuel escalated 2%/year 1985 to 1994
38.5 33.5
6.5 5.6
4.0 3.0
49.0 42.1
12.0 17.9 12.0 17.9
61.0 66.9 54.1 60.0
Fuel Escalated 7%/Year from 1985 to 1994;
Capital Cost and O&M Escalated 5%/Year from 1978 to 1994
Capital Cost
Operation and Maintenance
Transmission
Subtotal
Fuel
Total
80.0 69.7
13.5 11.6
8.3 6.2
101.8 87.5
18.4 27.6 18.4 27.6
120.2 129.4 105.9 115.1
l/APAestimate based on studies by Washington Public Power Supply System
Studies 1977.
69
Cost of Power -The estimated total cost of electric power that would be
generated by a coal-fired steamplant alternative to the Susitna project
is presented in table 20.Development of the estimated cost applied to
a plant in either the Beluga or Healy area is based on the investment
and fuel costs discussed earlier in this section,and includes other
criteria developed in this report.In summary,the parameters are:
L Investment cost includes all construction,overhead,and interest
during construction,and is based on updating and adjusting WPPSS
Pacific Northwest costs for Alaska conditions.Annual capital costs are
based on a 35-year life and 7 percent interest rate.
~
2.Operation and maintenance costs are based on a detailed WPPSS
personnel and materials estimate adjusted for plant capacity in the same
manner as investment costs,increased by 50 percent for Alaska
condi tions,as developed in the 1976 Alaska Power Survey,and indexed
from January 1977 to'October ).978 using the U.S.Department of Labor
index.
3.Fuel costs of both $1.00 and $1.50/kw are presented with a heat
rate of 10,000 Btu/kwh.
4.Transmission costs are for lines connecting Beluga with Anchorage,
and Healy with Fairbanks.
The resulting average unit cost of electric power from coal-fired .~
steamplants to supply the Railbelt market area ranges from 5.21 to
6.40¢/kwh,varying with fuel cost and plant capacity.
Table 20 also presents an analysis of the cost of energy with fuel costs
escalated at 2 percent anually from 1985 through 1994 (Susitna project,
Watana phase on-line)and fuel cost escalated at 7 percent annually from
1985 through 1994.
Comparative Cost of Power (FERC)-FERC evaluated alternative costs for
coal-fired steam plants at Beluga for the Anchorage area and Healy for
the Fairbanks area as part of their power benefit studies for the Upper
Susitna Project.•
The FERC estimates of 4.93 to 5.64¢/kwh are in the same range as those
estimated by APA for the Anchorage area.However,the FERC estimates of
4.02 to 4.30¢/kwh for the Fairbanks area are low compared to MA
estimates.FERC estimated construction costs (July 1978)at $1,475/kw
compared to $1,8l0/kw estimated by MA.In addition,GVEA recently
estimated a cost of $1,800/kw for a comparable Healy steamplant.
FERC data are based on:
1 •An Anchorage area plant assumed to be a two-unit 450-MW plant with
fuel cost of $l.lO/million Btu and a heat rate of 10,000 Btu/kwh.The
Fairbanks plant is assumed to be two units,totaling 230 MW,with a fuel
cost of $O.SO/million Btu and a heat rate of 10,500 Btu/kwh.For ~.
non-Federal cases,the Anchorage area plant investment cost was
estimated at $l,240/kw and the Fairbanks investment cost at $1,47S/kw.
70
2.Financing is based on a composite Anchorage-Kenai interest rate of
7.9 percent with 75 percent financing by REA at 8.5 percent and 25
percent by the municipality of Anchorage at 6.25 percent.The interest
:rate for Fairbanks is 5.75 percent assuming State of Alaska Power
Authority financing.In comparison.a Federal rate of 6.875 percent is
used for both areas.the same rate used in the Corps of Engineers
benefit analysis.
Oil and Natural Gas
The Upper Susitna Project involves a large new power supply beginning in
1994,with an expected life in excess of 100 years.
APA does"not believe that oil and natural gas are realistic alternatives
for equivalent power supplies,particularly in .new of the timeframe
(start in 1994)and very long life (through 2094).
Hydro
Criteria -Evaluation of possible hydroelectric generation alternatives
to the Susitna project is based on comparing:(1)the potential
generation capability,and (2)unit cost of power.Possible sites are
identified by:(1)single sites with sufficient capacity to supply the
projected power demands;(2)combinations of smaller sites within
selected geographic areas and river basins;and (3)a combination of the
best sites from all areas accessible to the Railbelt.
The hydro evaluation considered power requirements ran.ging from 600 MW
to 2,290 MW,which are,respectively,the low-range and high-range
projected increases in Railbelt demands from 1990 to 2000.Associated
annual firm energy requirements would range from 2,670 gwh to 10,260
gwh.By comparison,the Susitna project is scheduled to provide about
1.573 MW capacity and 6,100 gwh annual firm energy.
Possible hydro generation alternatives were selected from the APA
inventory of hydroelectric resources.The inventory estimates unit cost
of power at the generator bus bar based on 1965-1966 cost at 3 1/4
percent intl~rest rate.Susitna inventory cost data indexed to 1975
price levels give unit costs within 10 percent of that determined for
the 1976 report.
Single Large Capacity Sites Seven single sites have sufficient
capaci ty potential to be an alternative to supplying minimum Susitna
market area requirements.These are within a maximum of 1.4 times the
unit cost for Susitna power.However,land use designations (National
Parks and Honuments and Wild and Scenic Rivers)and/or known maj or
environmental impacts preclude.consideration of developing any of the
sites at the present time.
71
The sites are:
Site
Holy Cross
Ruby
Rampart
Porcupine
Woodchopper
Yukon-Taiya
Wood Canyon
Stream
Yukon R.
Yukon R.
Yukon·R.
Porcupine R.
Yukon R.
Yukon R.
Copper R.
(~,
Firm Capacity Percent
Energy MW of Susitna
G';<1H/yr Cost
12,300 2,800 140
6,400 1,460 62
34,200 5,040 32
2,320 530 79
14,200 3,200 71
21,000 3,200 52
21,900 3,600 51
None of the above sites can be considered available resources in the
1990's timeframe.This is due to:(1)Holy Cross,Ruby,Rampart,and
Woodchopper are main-s tem Yukon River sites with known maj or environ-
mental problems,(2)Porcupine,Woodchopper,and Yukon-Taiya have major
international c.onsiderations,and (3)Wood Canyon has a known major
fishery problem.
Si tes wi thin the Nenana River basin have also been identified in past
work.Their economic feasibility depends upon being developed as a
unit.However,several of the sites are located partially within Mount
McKinley National Park and are precluded from development.
In conclusion,no single,large hydro generation sites are available as
alternatives to the Upper Susitna Project.
Combination of Small Capacity Sites -Combinations of single sites with
less capacity than the Susitna project consist of 78 sites within the
Matanuska,Tanana,Yentna-Skwentna,Talkeetna,and Chulitna River
basins,the northwest drainage of Cook Inlet,the Kenai Peninsula,and
scattered small sites and small basins within the Railbelt area.None
of these areas contain sites with total capacity potential to supply
minimum Susitna requirements.(Site combinations with the most
capacity--the Yentna-Skewntna River basin and Kenai Peninsula--total 609
ffi~and 646 ~w respectively,but with costs for individual sites ranging
from 1.4 to 20 times Susitna costs.)
If consideration is given to combining the best small sites from each of
the geographic areas,12 sites totalling 1,276 MW are within the range
of twice the cost of Susitna.Only one (Chakachamna)is near Susitna
cost (103 percent),and has 366 MW potential.
Chakachamna is partly within the new Lake Clark National Monument.Other
new or proposed Federal land withdrawals would preclude sites with about
half of the total potential of the combined sites.Other sites have
various environmental impact potentials.Some streams that would be
affected have major anadromous fish resources.Also,because the sites
are widely distributed,the needed transmission systems would be fairly
extensive and costly..~
72
p~Summary -Based on examination of individual sites and combinations of
sites.there are no hydro generation opportunities available to provide
enough power to be an alternative to the Susitna Project.Small
individual sites may be available.but would satisfy only a small
portion of the market area demand.Other sites,with apparently
acceptable quantity and economic capability.have been or will be
precluded by land status designation.
Nuclear
Nuclear gen,=ration may be technically viable in Alaska.but probable
cost and siting problems eliminate.it as a potential alternative to
Susitna.Available information indicates that in other states.nuclear
is economically competitive with coal,depending on specific conditions.
Difficult conditions.possible seismic and environmental siting
problems.and readily available coal indicate that nuclear generation
will probably not be economically attractive in Alaska in the
foreseeable future.
Wind
The State has shown serious interest in wind generation technology by
developing pilot projects in the bush communities of Ugashik,Nelson
Lagoon,and Kotzebue.Wind seems to provide near-term power for small
communities presently dependent on high-cost diesel generation.
The cost and applicable scale of technology does not make wind power a
viable alternative for large near-future power demands.
Geothermal
Investigations to date have found no high quality geothermal resources
suitable for power development in areas accessible to the Railbelt area.
Geothermal potential is considered high in the Wrangell Mountains and
portions of the Alaska Range,and may be applicable to the Railbelt in
the future.At this time,insufficient data are available to define the
resource.even for appraisal of the large Susitna project market.
Tide
There is a large physical potential for tidal power development in the
Cook Inlet area where the State estimates that a total of 8,560 MW could
be harnessed.A potential of 785 MW is estimated for Knik Arm alone,
and approximately twice that amount for Turnagain Arm.
Several different concepts have been developed for the Cook Inlet tidal
potential because of the interest in alternative energy sources •There
is merit to preparing a good reconnaissance of this alternative,as
pointed out in the 1976 report.However.the scope of work involved to
develop the tidal resource,the large cos t of development,and the
important environmental considerations eliminate tidal power as a
reasonable alternative to the Susitna project.
71
Conclusion
The range of power options for the Alaska Railbelt is narrowing rapidly.
1.Oil and natural gas are very suspect in terms of long-range
national supply and availability for use in power production.
2.Coal is proving to be far more expensive as a power source than
previously anticipated.
3.Many hydroelectric alternatives have moved to the "unavailable"
classes because of land area designations.The remaining are less
desirable in terms of cost and ability to meet projected requirements.
4.Nuclear is expected to be as expensive as coal.
5.Geothermal,tide,and wind are unrealistic planning alternatives at
this time.
74
PART VII.LOAD/RESOURCE AND SYSTEM POWER COST ANALYSES
Introduction
A series of load/resource and system cost
demonstrate impacts of the Susitna project in
system costs.
analyses were made to
terms of overall power
~..
The load/resource analysis determined probable timing of new maj or
investments in generation and transmission facilities.It also shows
annual energy from each type of plant.The load/resource analyses were
prepared for these basic power supply strategies:
Case 1.All additional generating capacity assumed to be coal-
fired steam turbines without a transmission interconnection between the
Anchorage-Cook Inlet area and the Fairbanks-Tanana Valley area load
centers.
Case 2.All additional generating capacity assumed to be coal-
fired steam turbines,including a transmission interconnection.
Case 3.Addli tional capacity to include the Upper Susitna proj ect
(including transmission intertie)plus additional coal as needed,and
for the three load limits (high,medium,and low).
I
The system cost analyses,keyed to the load/resource,determined cost by
year to amortize investments and pay all annual costs·(fuel,O&M
expenses,etc).Inflation rates of a and 5 percent ~ere considered.
APA developed a number of the
costs,etc.APA contracted
prepare the report.
key inputs,e.g.,demands,unit sizes and
with Battelle to make the studies and
This section summarizes key assumptions and results.More detailed
information is available in the appended Battelle report.
Basic Data and Assumptions
Basic data and assumptions used in the load/resource and system power
cost analyses are:
1.Interest rate for repayment of facilities =7 1/2 percent.
2.Inflation rates of 0 and 5 percent,with construction costs
increasing at inflation rate,and fuel costs increasing at 2 percent
above inflation rate.
3.System reserve capacity of 25 percent for non-interconnected load
centers and 20 percent for interconnected systems.
4.Transmission losses of 1.5 percent for energy and 5 percent for
capacity.
75
.,"
5.Retirement schedules for proposed generating facilities (economic
facility lifetime):l/
Years
Coal-Fired Steam
Oil-Fired Steam
Gas-Fired Combustion Turbine
Oil-Fired Combustion Turbine
Hydroelectric
Diesel
35
35
20
20
50
20
6.Plant factors for new and most of the.existing facilities
are:
Percent
Hydro
Steam
Combustion turbine
Diesel
50
75
50
10
The factor for combustion turbines was reduced to 10 percent in the·
study when adequate steam turbine capacity was available.
l/See tables 3.4 and 3.5 of appended Battelle report for estimated
retirement dates of existing facilities.
7.Hydro plants designed for 115 percent of nameplate capacity for
limited reserve requirements.
8.Watana power on-line (POL)in 1994 and Devil Canyon POL in 1998.
9.Existing and planned generating facilities for Anchorage and
Fairbanks are shown in the appended Battelle report.
10.New coal-fired steamplants for Fairbanks assumed to be 100-}rn units
(first six),then 200-MW units.Anchorage units assumed to be 200 MW
(first five),then 400-Mlv units.
11.New coal-fired steamplants to be located at Beluga for Anchorage
area and at Healy (or other sites within 100 miles)for Fairbanks.
12.Fuel costs--see appended Battelle report.
13.Power demands will be met by resource allocation using Susitna
hydro generation first,coal-fired second,and natural gas and oil last.
14.Heat rate for new coal-fired steamplants =10,500 Btu/kwh.
76
15.Total investment cost in October 1978 dollars.
Plant ($million)($/kw)
100-~1W Coal Steam Turbine 245.4 2,454
200-MW Coal Steam Turbine 372.0 1,860
400-~1W Coal Steam Turbine 646.8 1,617
Watana Dam (795 MW)and 2,020.7 2,554
Transmission Line 470.5
Devil Canyon Dam (77 8 MW)834.0 1,072
Total Susitna Project (1,573 MW)3,335.2 2,120
16.Operation,maintenance,and replacement costs.
Plant
100-MW Coal Steam Turbine
200-.MW Coal Steam Turbine
400-MW Coal Steam Turbine
Watana Dam (795 MW)
Devil CanyonDam (778 MW)
New Transmission Facilities
Study Methodology
($million/yr.)
3.76
5.7
9.8
0.74
0.73
($/RW/yr .)
37.6
28.5
24.5
0.941/
0.941/
2.0))
~..
As stated in the introduction,three cases were analyzed to determine
timing of generation and transmission (G&T1 investments and their impact
on total power system costs.
The first step in estimating the cost of power from alternative
generation and transmission system configurations was to perform a
series of load/res?urce analyses.These analyses determined the
schedule of major investments based on assumptions of load grovrths,
capaci ty and energy production of the potential generating facilities,
and constraints as to when the facilities could come on-line.The
load/resource analyses also determined the annual power production from
each type of generating plant in the system.
The system cost analyses then determined the annual cost for amortizing
and operating the facilities.Summing the annual cost for generation
and transmission of each of the generating facilities gave a total cost,
by year,for the entire system being analyzed.Dividing the total
annual cost by the power produced gave an average annual cost of power
for the entire system.
1/This breakdown of OM&R costs by proj ect feature for convenience of
the load/resource analysis resulted in slightly higher cost.Signifi-
cance to Susitna rate is,at most,~ess than 1 percent.
77
p=o •I
Rounded Thermal generating capacity additions to the year 2010 from the
previous tables are summarized as follows:
Table 21
SUMMARY OF THEfu~GENERATING CAPACITY ADDITIONS TO THE YEAR 2010
Upper Susitna Project Power Market Analysis
Case 1:Without Interconnection &Without Susitna
Assumed Load Megawatts
Growth Anchorage Fairbanks Total
Low 2,600 471 3,071
Mid 4,600 871 5,471
High 8,200 1,471 9,671
Case 2:Interconnection Without Susitna
Assumed Load Megawatts
Growth Anchorage Fairbanks Total
Low 2,200 471 2,671
Mid 4,200 671 4,871 ~,
High 8,200 1,271 9,471
Case 3:Interconnection With Susitna
Assumed Load Megawatts
Growth Anchorage Fair'banks Total
Low 1,000 171 1,171
Mid 3,000 371 3,371
High 6,600 1,071 7,671
Note:Bradley Lake and Susitnahydroe1ectric projects are not included •
.~.
78
Results
Load/Resouree Analyses
The schedule of new plant additions for Anchorage and Fairbanks for
1978-2011 are shown in the appended Battelle report.A summary of the
thermal generating capacity additions is in table 21.Further
discussion of the computer model results and graphs are also shown in
the appended Battelle report.
Under the criteria used,completion of construction for interconnection
is scheduled in 1986,1989,and 1994 for high,mid and low load growth
cases,respectively,without Upper Susitna.With Upper Susi tna,the
corresponding dates are 1986,1989,and 1991.
System Power Costs
Annual system costs and unit power costs are presented in detail,both
tabular and graphically,in the appended Battelle report.The following
tabulations summarize these findings.Table 22 shows annual'power
system costs for cases 1,2,and 3,high,mid and low range,with 0
percent inflation.The first few years after Watana comes on-line,the
total annual power system costs increase slightly.However,comparing
the total annual power system costs for the 1990-2011 period to case 1,
construction of the Susitna project·results in a savings of $2.20
.~billion,or 12 percent.
.Figure 18 shows the relative savings in
Susitna,and case 1,without Susitna,
assumptions.
annual cost for case 3,with
for the three load growth
Tables 23, 24,and 24a summarize Anchorage and Fairbanks separately plus
the combined system average annual power costs in ¢/kwh for 1978-2011-
The tables verify the feasibility of the intertie in power cost savings
for Anchora.ge and Fairbanks.By the year 2000,system wide power rates
would be:
79
4
Average Power System Rates for Anchorage and Fairbanks -0%Inflation
(¢/kwh)
Case 1
Without Susitna
or Intertie
Case 2
With Intertie
Case 3
With Susitna
and Intertie
Combined Combined Combined
Anch.Fbks.System Anch.Fbks.System Anch.Fbks.System
High 6.2 8.8 6.6 1/6.1 8.0 6.4 5.8 6.2 5.8
Mid 6.6 8.9 6.9 II 6.2 8.4 6.6 5.5 6.7 5.7
Low 7.1 9.2 7.5 Y 6.2 8.8 6.7 6.1 7.8 6.4
.•
Comparison of Power Costs by Year 2000
Percent Change in Cost of Power Below Case 1 -0%Inflation
Case 2 Case 3
Combined Combined
Anch.Fbks.System Anch.Fbks.System
High -1.6 -10.0 -3.1 -6.7 -41.9 -13.8
Mid -6.5 -6.0 -4.5 -20.0 -32.8 -21.1
Low -14.5 -4.5 -11.9 -16.4 -17.9 -17.2
For the Anchorage-Cook Inlet area,inclusion of the Susitna Project into
the system (case 3)generally raises the cost of power above cases 1 and
2 during the first two to four years after Watana comes on-line,but
lowers power costs during the 1996-2011 period.This reduction in the
cost of power is significant in most cases.
For the Fairbanks-Tanana Valley load center construction of the inter-
connection (case 2)again generally reduces the cost of power compared
to without an interconnection (case 1).The inclusion of the Susitna
project (case 3)generally raises the cost of power above case 2 for
about two years after Watana comes on-line,but,as with the
Anchorage-Cook Inlet area,results in lower power costs during the
1996-2011 period.
1 I .Anchorage and Fairbanks are not interconnected for case 1,the
combined system rate is shown for~ademic comparison purposes only.
80
Figure 18 .
'COMBINED .e~NCHORAGE-COO£-(ff\!LET AND
FAfR8ANi<S-TANAr~A VALLEY
ANNUAL POWER SYSTEr,,4 COSTS
\fIlTH AND \VITHOUT SUSITNA
Upper Susitna Project Power Market Analysis
Case I High
2010
.-_-'Case I Low
982000
,-~~--+-------lCase 3 Low
cc:c-3
1990 94
YEAR
!----I-------+--....."e+----!----;p--------fl Case 3 Medium
t----+--------+-----~e::-I-----___:;fCase·I Medium ~;
1----+-------+-------II-----~'____i1 Case 3 High
2400·
2200
2000
z 18000
,-J
-J
~1600
~,.1400en....en
0 12'00U
a:::w 10003:
0a..
-J 800
<:t:
::>
Z
Z 600
<t.
400
200
'0
78 1980
Case I:without :Susitna
Case 3:with Susitna
82 .A PA 1/79
·Table 23
ANCHORAGE-COOK INLET AREA
AVERAGE POWER COSTS -CENTS PER KILOWATT HOUR -0%INFLATION
Upper Susitna Project Power Market Analysis
Case 1 Case 2 Case 3
Year High Medium Low'High l'1edium Low High Medium Lm.,
78-79,1.3 1.3 1.4 1.3 1.3 1.4 1.3 1.4
79-80 1 ..4 1.5·1.7 1.4 1.5 '1.7 1.4 1.7
:80-81 1.3 1.6 ,1.8 1.3 1.6 1.8 1.3 1.8
81-82 1.2 1.6 1.9 1.2 1.6 1.9 1.2 1.9
82-83 3.2 2.9·2.2 3.2 2.9 2.2 3.2 2.2
83-84 3 ..6 2.8 2.1 3.6 2.8 2.1 3.6 2.1
84-85 4.0 2.8 2.2 4.0 2.8 2.2 4.0 2.2
85-86 4.6 4.3'2.4 4.6 4.3 2.4 4.6 2.4
86-87 5 ..0 4.2 2.3 4.8 *4.2 2.3 4.8 *2.3
87-88 4.8 .4.7 3h 5.3 '4.7 3.7 5.3 3.7
88-89 5.4 4.4 3.5 5.1 4.4 3.5 5.1 4.4 3.5
89-90 5 ..1 4.8 4.2 5.7 4.5 *4.2 5.7 4.5 *4.2
90...,91,4.8 4.5 4.1 5.4 4.8 4.1 5.4 4.8 4.1
"91-92 5.2 5.0 4.1 5.7 5.3 4.1 5.7 5.3 4.6 *,
92-93 5 ..5 5.6 4.7 5.4 5.9 4.7 5.4 5.9'4.4
93-94 5 ..3 5.3 4.6 5.7 5.6
'4.6 5.7 5.61 5.0
94-95 5.5 5.1 5.3 5.5 5.4 4.9 *6.4#6.9\;#7.3 #
95-96 5 ..8 5.6 5.7 5.6 5.8 5.4 6.0 6.5 6.8
96-97 5.9 6.2 6.5 5.8 6.4 5.8 6.2 6.1 6.5
97-98 6.0 6.5 ,6.3 5.9 6.1 6.6 6.2+5.8 +'6.3+
98-99 6.1 6.3 6.1 6.0 6.5 6.4 6.1 5.8 6.1
99-2000 6 ..2 6.6 7.1 6.1 6.2 6.2 5.8 5.5 6.1
00-01 6 ..3 6.4 6.9 6.2 6.6 7.2 5.5 5.3 5.9
01-02 6 ..1 6.3 6.9 6.3 6.4'7.2 5.6 5.2 5.6,
02-03 6 ..2 6.6 6.8 6.4 6.3 7.1
5.7 '5.7 5.7
03-04 6.3 6.5 6.8 6.2 6.7 7.1 5.6 5.6 5.6
04-05 6 ..1 6.4 6.7 6.1 6.6 7.0 5.8 5.5 5.6
05-06 6.3 6.9 7.6 6.2 6.5 7.0 5.9 5.4 5.5
06-07 6.4 '6.8 7.5 6.3 6.4 7.0 5.8 5.8 5.5
07-08 6.3 6.8 7.5 6.5 6.9 7.0 5.9 5.8 5.5
08-09 6.4 6.7 7.5 6.3 6.8 6.9 6.0 5.7 5.4
09-10 6 ..5 6.6 7.5 6.4 6.7 6.9 5.9 5.6 5.4
10-11 6.3 6.9 7.5 6.5 6.7
6.9 6.0 5.9 5.4
*Interconnection Installed
#Watana on-line
+Deveil Canyon on-line
83
APA 11/78
""=::1
Table 24
AVEAAGE PCWER COSTS -0%INFLATIO::i (¢/KWH)
FAIRBAJ.'JKS-TANJl.NA VAI..L1::."'Y AREA
Upper Susitna Project Power Market Analysis
Case 1 case 2 case 3
Year High Medium Low High Medium IDw'High r-~edium !.oN
78-79 4.1 4.3 4.4 4.1 4.3 4.4 L3 4.3 4.4
79-80 4.1 4.3 4.5 4.1 4.3 4.5 L4 4.3 4.5
80-81 4.1 4.3 4.7 4.1 4.3 4.7 L3 4.3 4.7
81-82 4.0 4.3 4.7 4.0 4.3 4.7 L2 4.3 4.7
82-83 3.8 4.2 4.7 3.8 4.2 4.7 3.2 4.2 4.7
83-84 3.4 3.8 4.3 3.4 3.8 4.3 3.6 3.8 4.3
84-85 5.2 3.4 3.9 5.2 3.4 3.9 4.0 3.4 3.9
85-86 4.7 5.4 3.6 4.7 5.4 3.6 4.6 5.4 3.6
86-87 5.9 5.1 3.3 5.5 *,5.1 3.3 '4.8 *5.1 '3.3
87-88 5.6 4.8 3.0 5.1 4.8 3.0 5.3 4.8 3.0
88-89 5.5 4.8 3.1 5.0 4.8 3.1 5.,1 4.8 3.1
88-90 6.5 6.3 5.6 4.7 5.8 *5.6 5.7 5.8 *5.6
90-91 6.5 6.4 5.8 4.6 5.9 5.8 5.4 5.9 5.8 ~.
91-92 6.2 6.2 5.9 4.4 5.7 5.9 5.7 5.7 7.2
92-93 6.8 7.3 5.6 6.3 5.4 5.6 5.4 5.4 6.9
93-94 6.6 7.1 5.5 7.3 5.2 5.5 5.7 5.2 6.8
94-95 7.4 6.9 ,7.1 7.0 6.5 6.7 *6.4 #6.8 =If 8.8 #
95-96 7.2 6.9 7.3 7.8 7.7 6.9 6.0 6.7 8.9
96-97 7.6 7.8 7.1 8.2 7.4 8.3 6.2 6.4 8.6
97-98 8.1 8.3 7.9 8.7 7.8 9.1 6.2 6.9 7.8
98-99 8.'9 9.1 9.4 8.3 8~7 8.9 6.1 +6.9 +7.6 +
99-2000 8.8 8.9 9.2 8.0 8.4 8.8 5.8 6.7 7.8
00-01 8.3 8.7 9.3 7.7 8.3 8.8 5.5 6.6 7.8
01-02 8.0 8.6 9.3 ,7.5 8~2 8.8 5.6 6.5 7.7
02-03 7.7 8.4 9.1 7.2 9.0 8.7 5.7 7.3 7.6
03-04 8.5 9.8 9.1 8.0 8.9 8.7 5.6 7.2 7.6
04-05 8.2 9.7 9.1 8.7 8.8 8.7 5.8 7.1 7.5
05-06 8.0 9.5 9.0 8.4 8.6 8.6 5.9 7.0 7.4
06.,.07 7.8 9.4 9.0 8.2 8.6 10.1 5.8 6.9 7.4
07-08 8.5 9.-3_9.1 8.1 8.5 10.1 -S.9 6.8 7.4
08-09 8.4 9.2 9.0 7.9 8.4 10.1 6.0 6.8 7.4
09-10 8.2 9.1 9.1 7.7 8.3 10.2 5.9 6.7 7.4
10-11 8.0 9.1 9.1 7.6 8.2 10.2 6.0 6.6 7.4
*Interconnection Instal1e::l
#Watana on-line
+Devil Canyon on-line ~\
84
......
Table 24a
COMB~EDANCHORAGE-COOK INLET AND FAIRBANKS-TANANA VALLEY
AREA AVERAGE ANNUAL POWER COST 1./(¢/KWH)
Upper Susitna Project Power Market Analysis
Case 2 Case 3
YEAR HIGH MEDIUM LOW HIGH MEDIUM LOW
1978-79
1979-80
1980-81
1981-82
1982-83
1983-84
1984-85
1985-86
1986-87 4.90 *4.90 *1987-88 5.31 5.31
1988-89 5.07 5.07
1989-90 5.56 4.79 *5.56 4.79 *1990-91 5.24 5.06 5.24 5.06
1991'-92 5.52 5.39 5.52 5.39 5.14
1992-93 5.58 5.83 5.58 5.83 4.89
1993-94 5.94 5.57 5.94 If 5.57 if 5.35 if
~.1994-95 5.71 5.63 5.28 *6.67 6.91 7.59
1995-96 5.92 6.19 5.69 6.25 6.52 7.25
1996-97 6.18 6.61 6.29 6.35 6.17 6.93
1997-98 6.34 6.44 7.08 6.30 6.01 6.56
1998-99 6.36 6.88 6.91 6.14 +5.96 +6.39 +
1999-2000 6.37 6.61 6.68 5.84 5.68 6.42
2000-2001 6.47 6.87 7.54 5.70 5.50 6.23
2001,-2002 6.53 6.75 7.51 5.89 5.40 6.16
2002-2003 6.55 6.75 7.39 5.93 5.99 6.02
2003-2004 6.51 7.06 7.37 5.90 5.90 5.98
2004-2005 6.47 6.96 7.33 6.05 5.80 5.93
2005-2006 6.52 6.85 7.30 6.11 '5.71 5.88
2006-2007 6.58 6.76 7.55 5.97 6.02 5.85
2007-2008 6.71 7.18 7.53 6.04 5.94 5.82
2008-2009 6.57 7.09 7.51 6.11 5.86 5.79
2009-2010 6.62 7.01 7.50 6.10 5.78 5.76
2010-2011 6.67 6.92 7.48 6.23 6.07 5.74
1:./Case I not interconnected,therefore combined system rate does not
apply.
*Interconnection Installed
If Watana on-line
+Devil Canyon on-line
/"-
85
Part VIII.INVESTMENT COSTS
Construction costs for power producing facilities were prepared by the
Corps of Engineers (Corps);those for the transmission facilites by
Alaska Power Administration (APA).APA prepared estimates of interest
during construction based on 7 1/2 percent.
Corps estimates
Canyon--thin-arch,
(USBR).and the
conservative.
include alternative design concepts
as orginally proposed by Bureau of
concrete gravity design,which is more
for Devil
Reclamation
costly and
Transmission estimates are based on same plan presented in 1976 report,
with costs updated by indexing.
Current costs for transmission facilities are based on indexing
construction costs presented in the 1976 report (January 1975 prices)to
current levels (October 1978 prices)by applying a factor of 1.38 to
clearing and rights-af-way,1.33 to all other transmission line
components (access roads,structures,etc.).and 1.28 to substations and
switchyards,resulting in an overall factor of about 1:32.The clearing
and rights-of-way factor is based on experience of the Alaska Department
of Transportation and on recent experience of the USBR and Bonneville
Power Administration (BPA).The 1975 prices are based on component
prices from BPA with an increase of 90'percent for labor and 10 percent
for material transportation from the Pacific Northwest to Alaska.
Examination indicated that these factors are also valid for this
analysis,but should be reevaluated if more detailed cost estimates are
made in future years.
Transmission system costs are summarized in table 25.
Investment costs are calculated by adding interest during construction
at the 'annual rate of 7 1/2 percent to construction costs presented
previously.
The project schedule includes (1)first-stage construction of Watana dam
and powerplant and the total project transmission system.and (2)
second-stage Devil Canyon dam and powerplant.The transmission system
will be completed about three years before completion of Watana to
develop interconnection benefits by deferring of required steamplant
capacity (discussed in Part XIII,Load Resource Analysis).
Table 26 summarizes the investment costs required.
86
Table 25
CONSTRUCTION COST SUMMARY
Upper Susitna Project Power Market Analysis
Item
Transmission Lines
Clearing
Right-of-Way
Access Roads
Line Structures
Subtotal -T.L.
Switchyards and Substations
Fairbanks Substation
Talkeetna Substation
Anchorage Substation
Healy Switchyard
Watana Switchyard
Devil Canyon SWitchyard
Subtotal -S.S.
Total
Rounded
87
Construction Cost ($1,000 -10/78)
System
No.5
$3,350
5,000
19,110
242,190
$269,650
$11,710
10,100
15,890
4,770
6,360
19,660
. $68,490
$338,140
$338,000
APA 10/78
, i
Table 26
INVES'IMENT COST SUMMARY ($!MILLION)·
Upp~r Susitna Project Power Market Analysis
Stage
Power Production Facilities
COnstruction
Interest during Construction
Investment
Power Transmission Facilities
COnstruction
Interest during Construction
Investment
Watana
(1st)
1,427.0
603.7
2,030.7
338.0
132.5
470.5
Devil
canyon
(2nd)
665.0
168.6
833.6
Total
2,092.0
.772.3
2,864.3
338.0
132.5
470.5
,.7'
Total Investment -Susitna
88
2,501.2 833.6 3,334.8
PART IX.OPERATION,MAINTENANCE,AND REPLACEMENT PLAN AND COSTS
Operation and Maintenance
This updates information furnished in the 1976 report.Operation,
maintenance,and r-eplacement costs were indexed for this report.
Plan Description
This plan assumes Federal operation of the facilities.
The plan assumes the headquarters and main operations center for the
Susitna project will be near Talkeetna or at some other equally
accessible point.Equipment at the center will remotely control the
operation of t~e generation and transmission system and operation of
Devil Canyon and Watana dams and reservoirs.Electrician/operators and
mechanic/operators will be located at the powerplants to provide routine
maintenance and manual operation when required.
Specialized personnel,such as electronic technicians and meter and
relay repairmen,will service both powerplants and the substations and
switchyards from the project headquarters.Project administration,
including supervision of power production,water scheduling,and
transmission facilities,will also be from the project headquarters.
Major turbine and generator inspection and maintenance will be done by
electricians,mechanics,engineers,and other experienced personnel from
APA.Manufacturers'representatives and other specialized expertise
will be consulted.
Alaska Power Administration's (APA)headquarters office in Juneau will
handle power marketing,accounting,personnel management,and general
administrative services.
Transmission line maintenance will be performed by two line crews,with
assistance from the existing Eklutna Project line crew.Transmission
line maintenance warehouses and parts storage yards will be at Devil
Canyon or Watana,approximately mid-way between Devil Canyon and
Fairbanks,and at the project headquarters.Line crew personnel will be
stationed along the lines at designated maintenance stations and at the
major substations to provide routine line patrol and maintenance tasks.
Crews from throughout the project will be assembled for major work.
Visitor facilities with provisions for self-guided powerplant tours will
need assistance from operation personnel.
Project-related recreation facilities will require cooperation between
Federal,State,and local interests,and are assumed to be maintained by
a State or local entity.
89
Project operation,maintenance,and administration could be combined
with the existing Eklutna Project.Eklutna could be supervisory
controlled from the Susitna project operations center with
electrician/operators and mechanic/operators stationed at Eklutna.It
is estimated that approximately $lOO,OOO/year could be saved by joint
operation •.
Marketing and Administration
Marketing and administration include three main functions:
1.Administration
Personnel management
Property management
Budgeting
Marketing policy
Rate and repayment studies
2.Accounting
Customer billing
Collecting
Accounts payable
Financial records
Payroll
3.Marke~ing
Rate schedules
Power sales contracts
Operating agreements
System reliability and coordination
Part of this work would be carried out by the project,with overall
administration and support services provided by the APA headquarters
staff.'
Annual Costs
The estimated annual costs for operation,maintenance,marketing,and
administration are based on itemized estimates of personnel,equipment,
supplies,and services needed to do the work,with a provision for
contingencies.
The -estimate assumes Federal classified personnel providing management
and administrative functions and wage grade personnel performing
technical operation and maintenance activities.Classified salaries are
based on a mid~grade rate.Hage grade rates are based on those in
effect in the Anchorage area and include basic hourly rates,benefits,
and overtime.
90
*
1-"",
"
Costs of supp).ies,equipment,and personnel requirements are based on
Bureau of Reclamation (USBR)guidelines and the experience of the
Eklutna and Snettisham Projects.The Eklutna Project is fully staffed,
including a line crew,which has been in operation since 1955.The
Snettisham Project is isolated;it is separated from the Juneau load.
center by 45 miles of rugged terrain and water.A maintenance crew
resides and performs routine maintenance at the powerp lant;proj ect
operations are remotely controlled from Juneau.The Susitna project
would have some characteristics of both projects.
Itemized costs for operation,maintenance,marketing,and administration
are presented in table 27.
Costs by major category and number of personnel are summarized in table
28.
Rep lacements
The annual replacement cost prOV1S1on establishes a sinking fund to
finance replacement of major items which have an expected service life
of less than the 50-year project repayment period.The objective is to
cover costs and ensure financing for a timely replacement of major cost
items to keep the project operating efficiently throughout its life.
The replacement cost is based on factors developed from USBR experience.
The factors apply to the total powerp lant,substation,swi tchyard,
transmission tower,fixtures,and conductors.Replaceables include
generator windings,communication equipment,a small percent of the
transmission towers,and items in the substation and switchyards.Items
covered by routine annual maintenance costs include vehicles,small
buildings,camp utilities,and materials and supplies.Major features,
such as dams and powerplant structures,are considered to have service
lives longer than the 50-year repayment period.Their costs are not
covered by the replacement funds.Right-of-way and clearing costs are
not included.The 7~percent interest rate used for project repayment
was used to establish the replacement sinking fund.
Table 29 presents calculations of the annual replacement fund.•
The following tabulation summarizes the operation,maintenance,and.
replacement costs:
.Watana
Devil Canyon
Total
Annual Operation
and Maintenance
$1,000
$2,360
530
$2,890
Annual
Rep lacement
$1,000
$260
170
$430
Total
OM&R
$1,000
$2,620
700
$3,320
Price base -October 1978.
91
------------.....,..-----------~---------------------
Table 27
ANNUAL OPERATION &}L~INTEN~~CE COST ESTIMATE
Upper Susitna Project Power Market Analysis
October 1978 Prices
Dam and Powerplant.Total Transmission System
/~,
,'--.
Tab Ie 27 (cant.)
ANNUAL OPERATION &MAINTENANCE COST ESTIMATE
Miscellaneous
Telephone
Official travel
Vacation travel
Supplies,Services &Maintenance--Powerplant
Supplies &Services--Vehicles &Equipment
Employee training
Line spray
Government camp maintenance
Subtotal -Miscellaneous
Equipment Operation,Maintenance,and Replacement
Annual
Cost
$10,000
19,000
19,000
125,000
50,000
6,000
25,000
19,000
$273,000
Initial Service
No.Cost Life
Tractor with Dozer 1 $150,000 10 $15,000
Loader 1 75,000 10 7,500
Maintainer 1 75,000 10 7,500
Pickup 10 80,000 7 11 ,400
Sedan 1 5,000 7 700
Tractor &Lowboy 1 75,000 10 7,500
Dumptruck 1 25,000 10 2,500
Flatbed 2 20,000 7 2,900
Fir,etruck 1 25,000 10 2,500
Sno trac 2 16,000 7 2,300
Backhoe 1 35,000 10 3,500
Crane,50 ton 1 200,000 20 10,000
Hydraulic Crane,20 ton 1 100,000 20 5,000
Line truck 4 200,000 10 20,000
Subtotal -Equipment $98,300
APA Headquarters Marketing and Administration 165,000
Subtotal 1,966,000
Contingencies (20%+)394,000
TOTAL WATANA &TRAN~~ISSION $2,360,000
93
'Table 27 (cont.)
ANNUAL OPERATION &MAINTENANCE COST ESTIMATE
Devil Canyon Dam and Powerplant
Personnel
Watana and Devil Canyon,supervisory controlled from a remote'
operation-dispatch center.
Increase base staff for
Assistant operators
Electricians
Mechanics
Maintenance
Subtotal
Devil Canyon.
2@15.00/hr.
2@lT.00/hr •
1@17.00/hr.
1@15.00/hr.
Overtime
Government Contributions
Foreman Pay
Subtotal
Subtotal -Personnel
Miscellaneous
Vacation travel
Employee training
Supplies,Services &Materials
Supplies and Services
Subtotal -Miscellaneous
Equipment
Pick up
Snow tractor
Initial
Cost
2 @ 16,000
1 @ 10,000
Service/
Life
7
7
$2,300
1,100
Subtotal -Equipment
APA Headquarters Marketing and Administration
Subtotal Devil Canyon Additions
$
$
3,400
35,000
444,000
Contingencies (20%+)
TOTAL DEVIL CANYON O&M ADDITION
TOTAL WATANA·AND TRANSMISSION
TOTAL SUSITNA PROJECT
94
M
86,000
$530,000
2,360,000
$2,890,000
.~.
)
Table 28
OPERATION AND MAINTENANCE COST SUMMARY
Upper Susitna Project Power Market Analysis
Watana &Trans-
mission System
Number Dollars
Personnel:
Devil Canyon
Number Dollars
Total Devil Canyon,
Watana &Transmission
Number Dollars
~
VI
Salaries/Wages,Allowances
Classified Personnel 7
Wage Board Personnel 31
Miscellaneous:
Telephone,Travel,Supplies,
Services,Training,Line
Spray,Camp Maintenance
Equipment:
Annual cost Replacement
Marketing and Administration
APA Headquarters
Subtotal
Contingencies (20%+)
TOTAL -
$1,429,700
273,000
98,300
165,000
$1,966,000
394,000
$2,360,000
$274,700
o
7
130,900
3,400
35,000
$444,000
86,000
$530,000
$1,704,400
7
38
403,900
101,700
200,000
$2,410,000
480,000
$2,890,000
Table 29
REP~CEMENT COSTS
Upper Susitna Project Power Market Analysis
Watana and Transmission
System Devil Canyon .Total
Annual Annual Annual Annual
Rep lace-Rep lace-Rep lace-Replace-
ment Construction ment Construction ment Construction ment
Feature Factor Cost Cost Cost Cost Cost Cost----".
Powerp1ant 0.0010 $197,370,000 $197,370 $120,860,000 $120,860 $318,230,000 $318,230
Transmission towers,
fixtures,Ii.conductors 0.0001 251,32 Lf,000 25,130 ----251,324,000 25,130
\0
0\Substations and
switchyards 0.0033 11,000,000 36,300 14,760,000 _48,710 25,760,000 85,1HO
Total $258,000 $169,570 $428,370
Rounded .$260,000 $170,000 $430,000
Replacement factors are based on 7 1/2 percent interest rate.
Construction cost based on the portion of the feature subject to replacement.
)-)
PART X.FINANCIAL ANALYSIS
This part estimates the market for project power and evaluates power
rates needed to repay the investment in power facilities.Power market
size is in more detail in tHis study than in the 1976 report.Likewise,
costs are slightly more detailed.
The Upper Susitna Project is primarily for hydroelectric power
generation and transmission.,Minor portions of'project costs (less than
1 percent)would be allocated to other purposes,such as recreation and
flood control.Project financial viability is the essential element in
demonstrating feasibility of the power development.The repayment rate
is influenced principally by size of the market,amount of investment,
and applicable interest rates.Operation,maintenance,and replacement
costs are a minor part of total annual costs;they influence these rates
insignificantly.If rates needed to repay the hydro project are
attractive in comparison to other available alternatives,the project is
economically justifiable.
'The 1976 report compared the costs of five dam and reservoir plans for
developing the Susitna River hydroelectric potential and found all costs
were within a 15 percent range.Therefore,the scoping analysis was not
repeated for this study.
In addition to analyzing the basic Susitna project plan,variations were
also analyzed for sensitivity.These included interconnection with
additional service areas,different timing for interconnection between
Anchorage and Fairbanks,use of the more expensive Devil Canyon gravity
dam instead of the arch dam,low load growth,and the-effect of
inflation.In addition,the load/resource and system cost analyses
examine impact of the Susitna Project on overall system costs.
Market for Project Power
Upper Susitna will operate as part of a hydro/thermal power system.
The 1976 report assumed the market for Susitna firm energy as 75 percent
of the mid-range utility requirements.Average rates for firm energy
were estimated on that'basis.
For this analysis,the market for firm energy was assumed to be
approximated by load growth after Susitna power becomes available,plus
market made available through retirement of older plants.
The balance of the Susitna energy is assumed marketable as secondary
energy for fuel replacement,as long as all energy fits under the load
curve.A value is assigned for marketable secondary energy based on
estimated future coal costs.The actual value is probably significantly
higher.
97
The value of fuel replacement energy is the same as that used in the
load resource analysis,which is $1.00 to·$1.50/million Btu by 1985.
This is based on the concept that large,efficient coal mines will be
developed in the Beluga area by then.T.he price is escalated at 2
percent per year above the zero inflation rate from 1985 to 1994,
resulting in a cost of $1.20 and $1.80/million Btu's.
Table 30 summarizes the estimated market for Susitna energy using these
criteria.
Cost of Project
Table 31 summarizes the construction cost,interest during construction,
operation,maintenance,and replacement costs for Devil Canyon and
Watana phases.Construction costs were furnished by the Corps for an
October 1978 price level.Interest during construction was calculated
from Corps construction cash flow estimates with interest accumulated
until the project becomes operational.OM&R costs were updated from APA
earlier estimates.
Costs have increased from the 1976 report for several reasons.Table 32
presents a summary comparison of the cost factors.Interest rates have
increased from 6 5/8 to 7 1/2 percent.Design and cost changes were
made by the Corps as a result of foundation drilling.Costs'were
updated for the Devil Canyon dam and the transmission line by indexing
procedures.The major change in operation,maintenanae,and replacement
costs was due to inflation in personnel wages and provisions for con-
tingencies such as unlisted items and state of the art.Watana's
construction period was extended from 6 years to 10 years,increasing
its construction period from 10 years to 14 years.The revised project
investment cost is 89 percent higher than in the 1976 report.
98
>--------------------------------------------
TABLE 30
MARKET FOR UPPER SUSITNA POWER
ANCHORAGE AND FAIRBANKS AREAS
Upper Susitna River Project Power Market Analysis
MEDIUM ESTIMATE
Year
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
Firm Energy
Sales GWH
633
1,385
2,231
2,873
3,531
4,244
4,686
5,055
5,630
5,983
6,352
6,767
6,787
Fuel Replacement
Sales GWH
2,401
2,043
1,197
555
2,872
2,543
2,101
1,732
1,115
804
235
20
o
COMPARISON WITH TOTAL AREA POWER REQUIREMENTS
Year
1995
2000
2005
Estimated Anchorage
and Fairbanks Energy
Annual Energy
Million KWH
10,323
13,288
15,083
Estimated Market for
New Hydroelectric Power
Annual Energy
Million KWH
1,385
(13)1/
4,686 -
(35)1/
6,767 -
(45)];..1
!/Percent of total area requirements
Data Source:APA Load/Resources Analysis
Medium Load Gro~h Estimates,
Energy Losses are included.
99
._-..,-
Table 31
INVES TMENT AND OM&R COST SUMMARY
Upper Susitna Project Power Market Analysis
Unit
Completion Date
Watana
1994
Costs -$1,000
Devil Canyon
1998
Total System
Power Production Facilities
Construction Costs
Interest During Construction
Investment Cost
Transmission Facilities ~/
Construction Costs
Interest During Construction
Investment Cost
Total System Investment Cost
1,427,000
603,700
2,030,700
338,000
132,500
470,500
665,000 1/
168,600
833,600 2,864,300
470,500
3,334,800
Annual Operation and Maintenance
Annual Replacement
Annual OM&R
2,890
430
3,320
Price level is October 1978.Interest rate for repayment purposes in FY
1979 is 7-1/2%.
11 Costs are for arch dam plan at Devil Canyon.
2/Transmission system assumed online in 1991.
100
Average Rate DetJrmination
Table 33 summarizes the estimated average firm energy rate for firm
energy needed to repay project facilities investment for mid-range load
growth conditions.The method used is similar to that used in the 1976
report.Present Federal criteria for power producing facilities require
repayment of project costs,with interest,within 50 years after the
unit becomes revenue producing.The applicable interest rate for Fiscal
Year 1979 is 7 1/2 percent •.Revenues were credited to the project from
sale of secondary energy at a fuel replacement rate of l.2c/k,m during
early years of project operation.The average required rate for
repayment over 50 years after the last unit is installed is 4.7¢/kw.
Total repayment period will be 54 years with Devil Canyon coming on-line
four years after Watana.
Alternatives to the basic project plan were analyzed to determine
effects on average power rates:
1.Devil Canyon gravity dam in lieu of the thin-arch dam:
Investment cost increased $204.9 million.
Average rate for firm energy increased to a total of 4.9C/kw.
2.Transmission investment deferred until Watana phase comes on-line
/_(1994):
Watana phase investment reduced $76 million.
Average rate reduced O.lC/kw to a total of 4.6C/kw.
3.Mid load growth case,5 percent inflation:
Investment cost increased $3.598 billion.
Revenue needs increased $243 million annually.
Firm energy is the same for all mid growth cases.
Average rate for firm energy increased 4.7¢/kwh to 9.7C/kwh.
4.Low load growth case:
Revenue needs same as for mid range growth case.
Firm energy sales decreased;fuel replacement sales increased.
Average firm energy rate increased L 7¢/kw.
All Corps plans are based on completing Watana first,followed by Devil
Canyon four years later.This is appropriate for mid range and high
range growth conditions,but if low range conditions remain,it may mean
the Devil Canyon unit could be deferred a few years.
101
Power Marketing Considerations
The average rate is useful for comparing the proposal with the
alternatives.Actual marketing contracts will likely include separate
provisions for demand and energy charges,wheeling'charges,reserve
agreements,and other factors.
There are some built-in inequities for any method of pricing.What
amounts to a postage stamp rate is used by most utilities and large
Federal systems.That is,power rates are the same for all delivery
points on the system.Actual costs vary with the distance,size,and
characteristics of load--it is more costly to serve a small load several
miles from the power source than to serve a large load nearby.Policies
vary from system to system as to "hookup"costs born by the customers.
102
Table 32
COST SUMMARY COMPARISON
WITH 1976 INTERIM FEASIBILITY REPORT
Upper Susitna Project Power Market Analysis
Difference
Item
(Costs $Million)
Interest Rate for Repayment
Construction Period
Watana
Devil Canyon
Transmission System
Total
Construction Cost
Watana
Devil Canyon
Transmission System
Total
Interest During Construction
W'atana
Devil Canyon
Transmission System
Total
1976
Interim
Feasibility
Report
6-5/8%
6 yrs.
5
3
10 yrs.
832.0
432.0
256.0
1,520.0
165.4
57.2
25.4
248.0
1978
Marketability
Analysis
Update
7-1/2%
10 yrs.
8
3
14 yrs.
1,427.0
665.0
338.0
2,430.0
603.7
168.6
132.5
904.8
Amount
+7/8%
+4 yrs.
+3
o
+4 yrs
+595.0
+233.0
+82.0
+910.0
+438.3
+111.4
+107.1
656.8
Percent
+13
+67
+60
o
+40
+7.2
+54
+32
+60
+265
+195
+422
+265
Investment Cost
W'atana
Devil Canyon
Transmission System
Total
Annual Cost for Repayment
of Investment
Annual Equivalent OM&R
Total Annual Equiv.Cost
(Less Secondary Energy Sales II
-(Fuel Replacement Sales)-
Total Net Annual Equiv.Cost
Annual Equiv.Energy GWHlI
Total Annual Equiv.Energy
Cost -¢/KWH
.,--,.11 Median load growth
997.4
489.2
281.4
1,768.0
113.34
2.27
115.61
5.77
109.84
5,218
2.11
2,030.7
833.6
470.5
3,334.8
239.20
3.14
242.34
11.34
231.00
4,923
4.69
+1,033.3
+344.4
+189.1
+1,566.8
+125.86
+0.87
+126.73
+5.57
121.16
-295
2.58
+104
+70
+67
+89
+111
+38
+110
+97
+110
-6
+123
Note:Total energy during period of analysis is the same in both reports.
Difference is due to variation in load build-up.
103
------------;----------------rl-----~-----------------
Project Costs
$1,000
Table 33
AVERAGE RATE DETERMINATION
(WATANA AND DEVIL CANYON)
Upper Susitna Project Power Market Analysis
199L.PW Costs
$1,000
Project Energy Sales
Million KWH
Investment OM&R
2,501,200 2,437
2,267
2,109
1,962
(1998-2047)
624,200 32,256
Revenue
Producing.
Year Investment'OM&R
1994 2,501,200 2,620
1995 2,620
1996 2,620
1997 2,620
1998 833,600 3,320
I-'1999 3,320
0 2000 3,320.t:-
2001 3,320
2002 3,320
2003 3,320
2004 3,320
2005 3,320
2006-2047
Totals 3,334,800
Annual Equivalents
...
3,125,400
.239,200
41,031
3,1L.l
Firm Fuel Replacement 1994 PW Fuel Replace-
Energy Energy Sales Finn Energy IDent Sales
(1994-2005)
633 2,401 •589 2,233
1,385 2,043 1,198 1,768
2,231 1,197 1,796 964
2,873 555 2,151 416
3,531 2,872 2,459 2,000
4,244 2.543 2.750 1,648
4,686 2,101 2,824 1,266
5,055 1,732 2,834 971
5,63,0 1,115 2,937 582
5,983 804 2,903 390
6,352 235 2,867 106
6,767 20 2,841 8
6,787 000 36,171
64,320 12,352
4,923 845
(3)Equivalent Annual Firm Energy Sales
(4)Average Rate For Repayment ($231,000,000/
4,923,000,000 l~)
Average Rate Computation:
(1)Annual Costs:
(2)Revenue From Fuel Replacement Energy
at 12 mills per kilowatt hour
).)
Capital
OM&R
Total
$239,200,000
3,140,000
$242,3L~0,000
-11,340!000
$231,000,000
4,923,000,000 KWH
46.9 mills/KWH
)
Actual rates for the Su~itna system could reflect several items of costs
and revenues not identified in the project studies.For example,during
its life,proj ect facilities would likely be used to wheel power from
other sources.Wheeling revenues will lower overall project power rates
somewhat.Conversely I wheeling costs for proj ect power delivered over
non-Federal transmission lines will be added to project rate schedules.
This is now done under APA marketing contracts for the Snettisham
Project;there are similar situations in other Federal power systems.
Market Aspects of Other Transmission Alternatives
It is reasonable to expect modifications of the project transmission
system as requirements (or needs)change.The main 345-kv and 230-kv
lines could be upgraded substantially by adding compensation and
transformer capacity.Substations eQuId be added as future loads
increase to a case-by-case determination of economics.Similarly,
extensions of the project transmission lines to serve other areas would
be considered on the basis of needs,economics,and available
alternatives.
Anchorage-Cook Inlet Area
The costs in the proposed plan are premised on delivery points to
substations near Talkeetna and Anchorage.Rough estimates indicate
similar costs for a plan with delivery points at Talkeetna,Anchorage,
and the existing APA Palmer substation.~asically the proposed plan
includes costs to provide for delivery points on the existing CEA and
APA systems north of Knik Arm,but does not include costs of delivering
power across or around the Arm.
With or without the Susitna project,additional transmission capability
is needed on the approaches to Anchorage.CEA plans for a Knik Arm
system considers 230-kv transmission an important step in developing
this capability,but more capacity will be needed by the mid-1980's.
Essentially the same problems will exist with alternative power sources,
such as the Beluga coals..
Following project authorization,detailed studies will be needed to
consider alternatives for providing power a~ross Knik Arm.Costs would
be worked into rate structures through wheeling charges on non-Federal
lines or annual costs on project lines,if needed.
The transmission plan to deliver project power in Anchorage will need to
be worked out in the detailed post authorization studies.It will
involve added costs,either wheeling charges for project power over
non-Federal lines,or constructing project transmission lines around or
under Knik Arm.These costs could be about the same for alternative
power sources such as the Beluga coals.
It is essential that scheduling of project facilities be closely tied to
the marketing function.
105
Comparison of Susitna to Steamplants With and Without Inflation
Without inflation,the 4.7¢/kwh rate for the Susitna project is
significantly ,lower than the estimated cost of power from coal-fired
steamplants at 5.2 to 6.4¢/kwh at October 1978 costs.Considering
inflation,the capital costs of botH the steamplant and hydro powerplant
increase until construction is complete.For the completed projects,
inflation affects only the hydro project operation and maintenance cost,
a small part of the energy cost.For the steamplant,inflation
continues to increase the fuel cost as well as the much larger operation
and maintenance cost.
The difference of the effect of inflation is shown on figure 19.
Capital and O&M costs are assumed to inflate at 5 percent per year for
both.Fuel costs are assumed to inflate 2 percent per year higher than
a base price of $1.00 or $1.50 per million Btu in 1985.The conclusions
are that Susitna is considerably less susceptible to inflation than
steamplants.
106
COMPARISON OF SUSITNA .'Figure 19
AND ALTERNATIVE COAL-FIRED STEAMPLANT RATES
CONSIDERING 5%ANNUAL INFLATION
17
16
15
14
13
12
II
:r:
~
~IO
.......en..-
29w
,~,'u
w 8..-
.q:
a:
7
6
5
4
3
2
o
tpper Susitna Pro ect Power M rket Anal f!s s /
/y
/
'j
/
/
I
//
STEAMPLANT /VALTERNATIVE\
~V/
V'V
//
V V....
/'L Sl.JSITNA
.
"
1978 i980 1985 1990 1994 1995 2000
YEAR OF PRICE BASE
*(Fue I cost infla1ed 2%higher)
107 APA 1/79
~--------~--_._----------
PART XI.GLE~~ALLEN AND VALDEZ
Introduction
The primary justification for the Upper Susitna proj ect is to supply
power and energy to the State's two largest power market areas,
Anchorage-Cook Inlet and Fairbanks~Tanana Valley.
The Glennallen-Valdez area is recognized as a possible additional market
area.The two communities are the principal load centers for the Copper
Valley Electric Association (CVEA).At present,both are supplied from
oil-fired generators.
CVEA is now moving into initial construction phases of its Solomon Gulch
hydroelectric plant near Valdez,and is in final design stages for a
l38~kv transmission line extending 104 miles to interconnect Valdez and
Glennallen.CVEA could be interconnected ,nth the major ui tlities in
the Anchorage-Cook Inlet area by adding a transmission line between
Palmer and Glennallen.The transmission distance is 136 miles;minimum
transmission voltage would likely be 139 KY.Depending on future
demand,a higher voltage such as 230 kv may be justified.
VeD7 preliminary studies summarized in the following section indicate a
good chance that the Palmer-Glennallen intertie is feasible.
Power Market Area
Introduction
Similar to Fairbanks,both Glennallen and Valdez have been heavily
impacted by trans-Alaska oil pipeline construction and operation.The
pipeline term~.]'11 storage and shipping facilities are at Valdez.The
pipeline was completed and went into operation in 1977.The
Glennallen-Valdez area 1977 population was approximately 9,905,39
percent higher than in 1974.However,the 1976 population (13,000)
decreased 31 percent in 1977.
Valdez is the proposed site of a maj or refinery and petruchemical
complex to process the State's royalty share of Prudhoe Bay oil.Plans
are not yet finalized,but construction could begin as early as 1980.
This would have major impacts in terms of both construction employment
and a long term increase in employment and population for Valdez.The
operations phase of the refinery involves 1,000 new jobs according to
recent reports.Glennallen I s population and economy are expected to
continue to grow.
Existing Power System
The Copper Valley Electric Association (CVEA)serves both Glennallen and
Valdez.CVEA's radial distribution lines extend from Glennallen,30
miles north on the Copper River.55 miles south on the Copper River to ,~
Lower Tonsina,and 70 miles west on the Glenn Highway.Figure 2
outlines the area.
'''0
CVEA plans to .construct 104 miles of 138-kv lOng transmission line
between Valdez and Glennallen.This is related to the Solomon Gulch
12-MW hydro development now beginning construction.At present,the
utili ty loads are served totally by diesel generation of 17.7 MW:10.1·
MW at Valdez and 7.6 MW at Glennallen.Two small utilities serving
limited areas on the highways north of Glennallen are included in
historical data.Their installed diesel capacity totals 1/3 MW.
The Alyeska oil terminal faGili ty at Valdez has 37.5 MW in oil-fired
steam-turbine capacity.This is a total energy facility that satisfies
the terminal's electrical and steam requirements.
Power Requirements
This section summarizes historic energy use and related data,
information from a 1976 load forecast prepared for CVEA,and some
general observations on likely magnitude of future power requirements.
Historic Data
Energy use and peak demand data were obtained from three power
generating sources in the Valdez-Glennallen area:CVEA,the utility
serving over 95 percent of the area;Chistochina Trading Post;and
Paxson Lodge,Incorporated.The utility data yielded information on
energy use,peak demand,and customer sector breakdowns.
Population and employment data were derived from statistics provided by
the State of Alaska Department of Labor.This information illustrates
demographic characteristics of the study area.
The 1970-77 Valdez-Glennallen area is summarized on table 34.Net
generation by utility from 1960-77 is on table 35.
Analysis
The energy use,population,and employment data reflect events tied to
construction and operation of the Alyeska oil pipeline.The 'large jumps
"in population and employment during the construction years cannOt be
directly tied to utility power requirements since most of the workers
were housed in construction camps that supplied their own power.
The 1977 use data show total utility requirements at more than four
times the 1970 level.Total number of customers tripled during the
period.
Per customer residential use increased from 3,846 to 6,423 kwh per year
over the 7-year period.
This historic data prOVides no clear insight to probable future levels
of power use--any trends that would be useful in forecasting are hidden
by the construction impacts.
109
"'P~~I""I"_
Forecast
Table 36 summarizes future power demand estimates from CVEA's 1976 power
requirements study ..The study included estimates of demands through
1991;APA made a rough extension to the year 2000,assuming a 6 percent
rate of increase.
The average energy capability of the Solomon Gulch project is estimated
at 55 million kwh/year.'The·forecasts indicate that the Solomon Gulch
power would be fully utilized as soon as it comes on-line.By the time
Upper Susitna power would be available,CVEA total demands would exceed
'Solomon Gulch capability by around 100 million kwh/year.
The CVEA study predated the plans for the oil refinery at Valdez,pence
there is substantial likelihood that the actual requirements will exceed
the'forecast amounts.
Transmission Plan And Cost
Incremental service to the Glennallen-Valdez market areas would require
constructing transmission facilities from Palmer to Glennallen to
connect to the CVEA system serving the market area.Susitna project
generation and transmission to the Anchorage-Cook Inlet a"rea would be
sufficient to accomodate the incremental service.
The Palmer-Glennallen transmission system would have 136 miles of single
circuit 138-kv line,with a substation at Palmer and a switchyard'at
Glennallen.The Palmer substation would have a 230/138-kv transformer.
a 230-kv breaker.and a 138-kv circuit-breaker.The Glennallen switch-
yard would include two 138-kv circuit breakers.and would connect with
the planned CVEA 138-kv line extending to Valdez.Peak'capacity of the
138-kv Palmer-Glennallen line would likely be from 50 to 80 ~v.This is
an assumption for study purposes (stability.sizing J and power flow
studies were not made).
System costs are based on comparable elements of other project
transmission systems,indexed from the 1976 report (January 1975 prices)
to October 1978 prices (about 32 percent increase).The basic prices
are based on Bureau of Reclamation (USBR)and Bonneville Power
Administration (BPA)with adjustments for Alaska conditions (refer to
Part VIII).Advance planning would analyze evaluations of structural,
operation control.environment,and other elements affecting route
location,design,and operation of the system serving this area.
Investment costs are calculated by adding 7~percent interest annually
during construction.The Palmer-Glennallen line would be ccnstructed
during the same period as other facilities,and would be ready for
service when project power is available in 1994.Table 37 summarizes
construction and investment costs.
Table 34
HISTORIC DATA
GLENNALLEN-VALDEZ AREA
Upper Susitna Project Power Market Analysis
Net Generation
Peak Load (MW)
Utility Energy Sales (G~'iH)
Res CI Total
1970 2.1 7.4 9.9
1971 2.6 7.8 10.8
1972 2.8 7.6 10.8
1973 2.9 8.3 11.6
1974 3.7 10.4 14.5
.1975 7.7 16.0 24.4
1976 10.3 22.4 33.5
1977 10.9 31.0 42.9
utility CustoU'ers
Res CI Total
1970 546 221 793
,"'-"".1971 681 226 939
1972 655 237 926
1973 684 247 965
1974 911 317 1,268
1975 1,172 361 1,576
1976 1,677 404 2,128
1977 1,697 427 2,183
Utility
11.9
12.8
13.0
13.8
16.8
28.2
40.7
48.7
utility
2.4
2.5
2.6
2.7
4.0
7.3
8.6
9.3
Industry
39.4
Industry
37
(38.6 installed
capacity)
1970
1971
1972
1973
1974
1975
1976
1977
Population (Total)
3,098
2,932
3,464
3,568
3,833
9,639
13,000
9,905
Res residential
CI commercial-industrial
III
Employment (Avg.Annual)
831
1,085
904
985
1,526
4,626
7,818
3,918
APA 12/78
·~
Table 35
UTILITY NET GENERATION (GWH)
GLENNALLEN-VALDEZ AREA
Upper Susitn~Project Power Market Analysis.
Year CVEA CTP PLI Total Growth %
1960 3.2 0.1 3.3
1961 3.4 0.1 3.5 6.1
1962 4.0 0.1 4.1 17.1
1963 4.5 0.1 4.6 12.2
1964 4.2 0.1 4.3 -6.5
1965 6.5 0.2 ..6.7 55.8
1966 8.0 0.2 8.2 22.4
.1967 8.2 0.3 8.5 3.7
1968 8.6 0.4 9.0 5.9
1969 9.7 0.4 0.5 10.6 17.8
1970 10.7 0.4 0.7 11.8 11.3 d!#<
1971 11.7 0.4 0.7 12.8 8.5
1972 1l.8 0.4 0.7 12.9 0.8
1973 12.6 0.4 0.7 13.7 6.2
1974 16.6 0.4 0.7 17.7 29.2
1975 26.9 0.4 0.7 .28.0 58.2
1976 39.3 0.4 .0.7 40.4 44.3
1977 47.4 0.4 0.7 48.5 20.1
CVEA -Copper Valley Electric Association
CTP -Chistochina Trading Post
PLI -Paxson Lodge,Inc.
APA 12/78
112
Table 36
VALDEZ-GLENNALLEN AREA UTILITY FORECASTS
Upper Susitna Project Power Market Analysis
Energy (gwh)Peak Demand (HW)
CVEA 1/CVEA Y
Year Glennallen Valdez Total Glennallen Valdez
1976 12.5 24.5 37.0 40.7 Y 3.1 6.0
1977 21.0 27.0 48.0 48.7 Y 4.2 5.9
1978 22.1 27.2 49.3 4.4 5.8
1979 24.0 27.6 51.6 4.6 5.8
1980 45.9 27.9 73.8 7.3 5.8
1981 48.5 30.5 79.0 7.7 6.3
1982 50.0 33.0 83.0 8.1 6.8
1983 52.2 35.5 87.7 8.5 7.4
1984 55.0 38.2 93.2 9.0 8.0
1985 57.6 41.4 99.0 9.5 8.6
1986 60.0 45.0 105.0 10.1 9.3
1987 63.1 48.5 111.6 10.6 10.1
1988 66.0 52.5 1'18.5 1l.1 10.9
1989 69.1 56.8 125.9 11.7 11.8
'1990 72.3 61.4 133.7 12.4 12.8
1991 75.0 66.4 141.4 13.0 13.8
1995 180
2000 240
2025 1,025
y Copper ,Valley Electric Association Forecast from
1976 REA Power Requiremertts Study.
y Historical values
113
____..,..-----------""-w---''''''F------·----------------
Table 37
INVESTMENT COST SUb~RY
GLENNALLEN-VALDEZ AREA TRANSMISSION SYSTEM
Upper Susitna
Transmission Line
(Palmer-Glennallen}
Clearing
Right-of-Way
Access Roads
Line Structures
Subtotal
Project Power Market Analysis
(Costs-$l,OOO 10/78)
Construction Interest Investment
During
Construction
$1,540
310
5,490
25,760
$33,100
Switchyards &Substations
Palmer Substation
Glennallen Switchyard
Subtotal
Total
$3,880
920
$4,800
$37,900 $2,900 $40,800
~'I
Operation and Maintenance Costs
Addition of tb~l36-mile Palmer-Glennallen transmission line would
involve comparatively minor increases in overall system operation,
maintenance,and replacement costs.
For purpose of this analysis we are assuming the incremental O&M costs
would be roughly equivalent to 1/3 of the annual cost of one transmission
line maintenance crew.Adding an allowance for replacements,the
annual OM&R cost is estimated at $131,000 per year.This is indicated
on Table 38.
114
Table 38
OPERATION,MAINTENANCE,AND REPLACEMENT COST SUMMARY
GLENNALLEN-VALDEZ AREA TRANSMISSION SYSTEM
Upper Susitna Projec~Power Market Analysis
Annual Cost -$1,000
Full Crew 1/3 CrewOperationandMaintenance
Personnel
Salary &allowances for 6 Wage Grades 240 80
/'-
Miscellaneous
Telephone,travel,supplies,services
training,line spray,camp maintenance
Equipment (Replacement)
Marketing and Administration
Subtotal
contingencies 20%+
Subto,tal -O&M
Rounded
Replacement
Transmission towers,fixtures,conductors
0.0001 x $25,766,000
Substations &Switchyards
0.0033 x $4,800,000
Subtotal -Replacement
Rounded
Total OM&R
115
10 3.3
8 2.7
22 7.3
280 93.3
60 20
340 113.3
113
2.6
15.8
18.4
18
131
Assessment of Feasibility
A minimum intertie between Palmer and Glennallen would involve
incremental investment costs on the order of $40.8 million.Incremental
annual costs are estimated as:
Amortiza t ion
OM&R
Total Annual Cost
$3,140,000
131,000
$3,271 ,000
..~...-.
Based on the utility forecast for CVEA,it is possible that a market in
excess of 100 mil1ion kwh/year could be supplied over the
Palmer-Glennallen line.This would equate to transmission costs of
3.3¢/kwh.
The ·100 million kwh/year would be equivalent to 22.8 MW at 50 percent
annual load factor.This is substantially less than half the estimated
capacity for a 138-kv Palmer-Glennallen line.
Full utilization of the intertie could involve transmission of 200 to
300 million kwh/year,in which case,average transmission cost would
drop from one-half to one-third the cost indicated above.
Regardless of the source of power--coal ,oil,hydro--generation costs
for CVEA will likely be higher than for the larger utility systems .~
serving the Anchorage-Cook Inlet area.In this context,transmission
costs on the order of 1.1 to 3.3¢/kwh between Palmer and Glennallen may
be justifiable.
APA concludes that the Palmer-Glennallen intertie has a good chance for
feasibility,and that a more detailed examination is warranted .
APPENDIX
1.Letter dated January 3,1979 to Col.G.R.Robertson,Alaska
District Corps of Engineers,.transmitting responses to OMB questions
falling in APA's area of responsibility.
2.Previous Studies and Bibliography.
3.LOAD/RESOURCE AND SYSTEM COST ANALYSIS FOR THE RAILBELT REGION
OF ALASKA:1978-2010 --Informal Report -by Battelle Pacific Northwest
Laboratories,Ric"hland,Washington -January,1979.
4.Comments.
a.Federal Energy Regulatory Commission,San Francisco,California,
March 6,1979.
b.Battelle Pacific Northwest Laboratories,Richland,Washington,
February 27,1979.
c.Corps of Engineers,Anchorage-,Alaska,March 19,1979.
d.The Alaska State Clearinghouse,Juneau,Alaska,March 23,1979.
e.Municipal Light and Power Company,Anchorage,Alaska,March 1,1979.
117
',"",,r<
Deoartment Of Energy•Alaska Power Administration
P.O.Box 50
Juneau,Alaska 99802
Colonel George R.Robertson
Alam(a District Engineer
Corps of Engineers
P.O.Box 7002
Anchorage,AK 99510
Dear Colonel Robertson:
January 3,1979
Attached are our responses to the Susitna project o~m questions we
agreed to provide (re:our letters dated January 20,24,1978).
Copies of these responses were sent via Go1dstreak direct to Captain
Mohn December 28,1978.
Sincerely,
Donald L.Shira
Chief,Planning Division
1
OMB question 5.1,and .2.
OI'-lB asked that the analysis of the "without"project condition be expanded
to clearly analyze:
1.Why,with natural gas projected to be in such short supply,the
Anchorage utilities have only contracted for 55 percent of proved
reserves or 25 percent of estimated ultimate reserves,and,
2..The sensitivity of the analysis.to the collapse of OPEC and the
cost of shipping oil to the East Coast.
Both questions must be considered in terms of national en~rgy policy_
The Nation needs to reduce dependency on oil i~ports on both a short-
term and a long-term basis,and to accomplish a major shift a\,;ay from·
oil and natural gas to alternative energy sources.The reasons for this
include national economic considerations,as well as very real.limits on
national and world supplies of oil and natural gas.
In terms of national energy policy,oil and natural gas are not available
alternatives for lo?g-term production of electric power.There are .
remaining questions as to how quickly exist~ng uses will be phased out
and on how complete the prohibitions will be on new oil.and natural gas-
fired powerplants.
There is general .agreement.that implementation of national policy must
include stropg efforts in conservation,substantial in~rease in use of
coal,and major efforts to develop renewable energy sources.Each of
these components is sensitive to energy price and snpply variables.A
reduction in world oil prices or·a period of oversupply serves as a
marketplace disincentive for conservation efforts and \olork·on alterna-
tiveenergy sources.
The lowest cost alternatives and those with fully proven technology are
the least sensitive;those that depend on further R&D are most easily
sidetracked.
Tht:!Susi.tna Proj ec·t involves l<l.rge blocks of pOtver and ne,v e.ne.rgy from
a rene,....able source,fully proven technol.ogy,long revenue-produci.ng
period (in excess of 100 years),and essential freedom from long-term
price increases.Its unit costs appear attrac~ive in comparison to
coal-·fired pm.·;erplants.It is a t,vo-stage project "lith opportunity to
defer the second st.age if demands are lO\v2r than present estimates or if
price relationships cha.nge.
The above factors suggest that t:he Upper Susitna Project is much less
sensitive to short-:-term oil price and supply variations than most other
u.s.energy options.
-""-------------...,._._--------~----,.."..------------------------
2
If it i!;as'-:;lIl:lecl that 1\lClsktm oil and natUl~al gas ",ill be isolated fro:n
U_S_and world demalld Cluel pric.:ing,l\)aska \<Joulc1 pr(lb~lbly continue to use
its oil ':-Inc1 getS for most of its pover.Tbi!;its!;1.lmption did,in fact,
prevail h(~t\<lecn the initinl oi.l and gas c1i.~;covc:r.ies in the Cook Inlet
area and the 1973 oil cmb".rgo.In J.960 ,the l~nchorilge-Cook Inlet n:ce,l
pO\4er supplies came almost:·entirely from coal and hydro.'l'he 10'.'1 cost,
abundant:gas brought a halt to hydro dcvelop,uent:and destroyed the
arei!.t s coal industry.'l'he one re..-uaining l\laskan coal mine barely made
it tIlro.ugh the 1960's because of compc"tition from relatively cheap oiL
The Cook Inlet gas has been subjected to increasing competition in ·the
last fe':l years,including proposals for LNG facilities,aC1ditional
petrochemical plants,~nd consideration of pipeline alternatives to tie
in \oTith the Alcan pipeline project.The competition resulted in :increas-
ing prices and increasing difficulty in obtaining long-term co~~itments
o~gas for power.The ~ompetitions and the price increases are expected
to continue..
The real question on gas availability as it pertair;s to Upper Susitna'
is:"lhat is the out·look foi long-term gas supplies for po\ver after
1990?That out-look is not good in terms of competing uses and national
policy ..
.3
3
Response to Of.m question 5.3.
"The Necessity for an Anchorage-Fairbanks intertie at:a cost of $200-300
million"
The estimated construction cost (1978 dollars)for the transmission
lines from the Susitna project to the Fairbanks area is $152 million,
and $186 million for the lines from the project to the Anchorage area
(total $338 million).
Th .1 .d"1/h d t .h t f "b'l"ere are:severa prev~ous stu 1es-t at emons rate 1n eren easl 1 1 ty
of an Anchorage-Fairbanks intertie with or without construction of the
Upper Susitna Project.The main reason that the intertie is not now in
place is that short term benefits to the Anchorage area are quite small,
i.e"most of the short term benefits for the intertie \-10uld occur
through reduced energy and power costs in the Fairbanks area.
APA studies in the 1975-feasibi1ity report evaluated Susitna Project
power to Fairbanks on a cost-of-service basis (see Appendix I,p.6-89).
This was a specific demonstration of feasibility of including Fairbanks
as part of the Upper Susitna Power Market area.
1/Amongr the previous studies are:.
Alaska Power Survey,Federal Power Commission,1969.
Central .Alaska Power Pool,working paper,Alaska Power Administration,
October 1969.
Alaska Railbelt Transmission System,working paper,Alaska Power Admin-
istration,December 1967~·
Electric Generation and Transmission Intertie System for Interior
and Southcentral Alaska,CH2M Hill,1972.
Central Alaska Power Study,The Ralph M.Parsons Company,undated,
Alaska Power Feasibility Study,The Ralph M.Parsons Company,1962.
4
Further verification of feasibility of the intertie is provided in the
new load-resource analyses and system cost analyses prepared for the
current studies.These general cases were analyzed:
j
!,
i
Case 1.
Case 2.
Case 3.
All future generating capacity assumed to be coal-fired
steam turbines without intertie.
All future generating capacity assumed to be coal-fired
steam turbines with intertie.
Future generating capacity to include Upper Susitna Project
plus coal~fired_steam plants as needed.Includes intertie.
Results of power cost analyses for Anchorage and Fairbanks for the year
2000,with and without intertie are as fQl1ows:
Power Costs for Anchorage and Fairbanks (0%Inflation)
(¢/KWH)
Case 1 Case 2 Case 3
Without Intertie with Intertie With Susitna
and Intertie
Anchorage Fairbanks Anchorage Fairbanks Anchorage Fairbanks
High 6.2 8.8 6.1 8.0 5.8 6.2
Med 6.6 8.9 6.2 .8.4 5.5 6.7
LmV'7.1 9.2 6.2 8.8 6.1 7.8
The following table presents a comparison of the costs of power in the
"year 200~for Case 2,and 3 as compared to Case 1.As shown the costs
of power are reduced below the cost of power for Case I in all cases.
The reduction in the cost of power is typicallY greater in the
I~'Fairbanks-Tanana Valley area than in the Anchorage-Cook Inlet area
because the Anchorage-Cook Inlet area will have a higher percent of its
generation supplied by steam plants which are more costly than Susitna.
Comparison of Power Costs for Year 2000
Percent Change in Cost of Power Below Case 1 -0%Inflation',
Anchorage Fairbanks
High Medium Low High Medium Low
Case 2 -1.6 -6.5 -14.5 -10.0 .-6.0 -4.5
Case 3 -6.9 -20.0 -16.4 -41.9 -32.8 -17.9
Table 1 compares annual system costs for all three cases for Anchorage
and Fairbanks during the 1990-2011 period.
Table 1 shows the following percent savings in system costs (1990-2011)
for Ca.ses 2 and 3 compared to Case 1:
Case 2
Case 3
Anchorage
-0.4
-10.7
Fairbanks
-7.9
-28.1
Total
-1.4
-14.1
.)
Table 1.Annual Power System Costs for Power Supply Under
Cases I,II,and III -Mid-Range Load Projections -0%Inflation
($Million)
Period Case I Case II Case III
Anchorage Fairbanks Anchorage Fairbanks _Anchorage Fairbanks
1980-90 272.0 90.6 254.5 84.2 254.5 84.2
90-91 274.2 96.8 293.8 89.0 293.8 89.0
-91-92 324.2 98.2 343.8 90.2 343.8 90.2
92-93 387.5 119.5 409.9 88.2 409.9 88.2
93-94 391.7 120.9 414.1 89.2 414.1 89.2
94-95 398.9 122.2 421.3 114.9 537.5 120.5
95-96 463.7 127.6 486.1 143.7 537.9 124.8
96-97 549.0 152.4 571.5 143.2 543.0 124.0
97-98 615.9 167.8 578.7 158.5 549.3 139.2
98-99 627.7 -192.0 650.2 182.6 576.3 145.1
1999-2000 694.4 193.8 657.2 184.5 577.2 145.7
Sub total 4,999.4 1,481.8 5,081.1 1,368.2 5,037.3 1,240.1
00-01 691.8 194.9 714.3 185.5 573.4 146.5
01-02 698.6 196.2 721.1 186.8 578.5 147.4
02-03 760.3 195.0 723.1 208.2 658.6 168.6
03-04 767.9 230.8 789.8 209.6 665.1 169.6
04-05 776.0 232.2 798.5 211.0 670.8 170.6
05-06 864.0 232.1 807.1 210.9 677.6 170.2
06-07 872.8 233.5 815.9 212.3 744.4 171.2
07-08 881.9 235.1 904.4 213.8 751.6 172.3
08-09 891.1 236.5 913.6 215.2 759.0 173.4
09-10 901.6 238.1 923.1 216.9 .766.7 174;6
10-11 969.9 239.6 932.7 218.4 834.3 175.7
'1.'0 tal 14,075.1 3,945.8 14,124.7 3,656.9 12,717.3 3,080.2
/'
).J
(j\
7
ReSpOnSE!to Qr·m question 5.4.
"Scheduling of po~.,eEpla.nts and t.he reduced risk of building small
incrcment.s."
The LoacVResource analysis for without project condition addresses,the
.'.
scheduling of steamplants and size of units needed.This is demonstrated
in Chapt:er VII of the marketability report.Annual power system costs
shown in Table 1 under question 5.3 show savings from Susitna over the
without Susitna case.The steamplants are smaller units than Susitna,
but thei.r higher cost contributes to higher overall system costs.An
analysis of hydro alteinative~indicate that there are not economical
sites available in sufficient quantity to be comparSlble to Susitna.
This is supported by APA's draft report on "Analysis of Potential
Alternat:ive Hydroelectric sites to Serve Railbel t Area.II
..,
8
Response to OMS question 6.1,.2,and .3.
Demand Estimates
The analysis of load growth should be more specific with respec~
to:
1.Increasing use by consumers;and,
2.Increasing number of consumers.
3.Industrial groTtl"th,i.e.,Ttlhere-does Alaska's comparative ~
advan~age lie ou~side the area of raw materials and governmen~
functions?
The new estimates of future P9wer demand are responsive to the first two
parts of this question.APA completed a very careful analysis of recent
power use trends by class of customer,with particular emphasis on
identifying recent trends that could be attributed ~o conservation
efforts.The future demands are based on future population estimates
developed by the University of Alaska's Institute of Social and Economic
Research and incorporate assumptions of substantially improved efficiency
in use of electric power through conservation.
The third part of the question requires consideration of the overall
Alaskan economy,present and future,and the role of Upper Susitna
power.
Alaska is not a heavily industrialized State nor is it expected to be.
$
The oil and gas industry is presently the dominating sector of the
State's GNP,and ~.;ill continue to be so for at least the balance of .the
20th century.This is the principle source of revenues for the State
and thus the driving force behind State programs for education,local
government assistance,....lelfare,and so on.Other important industries
are the fisheries,forest products,and recreation-tourism.
The low-and mid-range population estimates incorporate very modest
assumptions of industrial expansion based on pioneering of Alaskan
natural resources for the most part.The specific industrial assumptions
reflect proven sources of natural resources and projects that are well
along in the planning stages.
w
9
Extraction and processing of natural reso?rces will undoubtedly continue
to be major aspects of the Alaskan economy.Other important aspects
include.~usiness activities of Native Corporations and increasing amounts
of land made available to State and private mmership.Actions pending
on the new National Parks,Refuges,and wild and Scenic Rivers will
encourage further development of the recreation and tourism industries.
As inmost parts of the country,Alaska employment is not dominated by.~.
the industrial sectors.l-lost jobs are in service.industries,the coinmer-
cial establishments,transportation,utilities,and government.The new
population estimate by ISER indicates that the distribution of employment
will not change sUbstantially.The anticipated gro\~h in the economy,
employment,and in power demands is primarily in the non-industrial
sectors.
It should be nbted that the Railbelt area demands for electric energy in
1977 were 2.7 billion kilm.,ratt-hours,which is approaching the firm
energy capability of the Watana Project.The load resource analyses
demonstrate full utilization of Watana energy essentially as soon as it
becomes available,even under the lower power demand case.This basically
leads us to a finding that the Upper Susitna justification is not dependent
on major industrial expansion in Alaska.
10
.~.
Response to Qr.m Question 7.
Under the topic Sensitivity Analysis,OMB provided the following comments:
"POl-ler demand should be subjected to a sensi tivi ty a.nalysis to better
assess the uncertainties in development of such a la.rge block of power.
The typical utility invests on the basis of an 8-10 year time horizon .
.The Susitna plan has an 11-16 year horizon in face of risks that loads
may not develop and the option of l-lheeling p0l-ler to other markets is not
available.It should be noted that.the pO"ler demand for Snettisham t.,as
unduly optimistic l-lhen it w'as built.This resulted in delays in installing
generators.A similar error in a project the size of Susitna ,'!ould be
much more costly and wouLd have a major adverse effect on the project's
economics."
.
The new power demand estimates,load resources analyses,and financial .~.
analysis presented in this report,all provide a better basis for examining
these questions.In addition,there is need to review some of the
Snettisham Project history to bring out similarities and differences
with the Upper Susitna case.
Snettisham Review
The Snettisham Hydroelectric Project is located near Juneau,Alaska,and
is now the main source of power for the greater Juneau area.The project
was authorized in 1962 on the basis of feasibility investigations by the
Bureau of Reclamation,constructed by the Corps of Engineers,and opera-
ted by the Alaska Power Administration.
The-project ,vas conceived as a .two-stage development and construction of
the first,or Long Lake,stage was completed in late 1973 with first
commercial power to Juneau in December 1973.The second,or Crater
Lake,stage would be added when power demands dictate.
,,-
,~,'
11
Juneau was,and is,an isolated power market area.Difficult terrain
and long distances have thus far prevented electrical interconnection
with other Southeast Alaska communities and neighboring areas of Canada;
hmvever"such interconnections may prove feasible ...Ii thin the next 15 to
20 years.The project planning and justification waS premised on per-
vice only to the greater Juneau area.
The Snettishamauthorization was based on power demand estimates by the
Alaska District,Bureau of Reclamation (no~'1 Alaska PO\'1er Administration)./-
l!The estimates were based on actual power use through 1960 and projec-
tions to the year 1987.The outlook'at that time \-laS that the first
stage construction would be completed in 1966,and that total project
capability would not be needed until 1987.
A comparison of power demand estimates at the time of authorization with
actual demands is shovm on Table 1.The 1977 energy load waS 112,197
megawatt-hours or 81 percent of the amount estimated in 1961 based on
historical records through 1960.
l!Re,~raisal of the Crater-Long Lakes Division,Snettisham Project,
Alaska,USER,November 1961.
----------''''1---------------------'
Table 1 Power ana Energy Requirements-Juneau Area
12 ..~
Forecasted Demands at
Actual Demands Time of Authorizatipn 11
Fiscal Year Peak I>l~v MWH Peak MW
(Oct.1 -Sept.30)
1958 23,945 4,788,
1959 26,297 5,321
1960 28,499 5,465
1970 58,266 12,420 73,400 ·15,230 ,~
1971 63,786 13,780 80,700 16,750
1972 70,225 14,910 88,800 18,430
1973 75,753 15,470 97,500 20,240
1974 83,059 l6,220 106,900 22,190
1975 94,609 17,840 116,900 24,260
1976 106,296 19,800 127,600 26,480
1977 .·1:12,197 20,440 139,100 28,870
Project,A.).~~$'il,.USBR,November 1961.
1/.From Reapp;r;J~~~'~the Crater-D:mg Lakes Division,Snettisham
)'::~~:,,:i.....~:;r·:'-:;,
"F .~~.
13
The inherent flexibility of a staged project proved to be very benefi-
cial in the case of Snettisham.APA made periodic updates of the power
demand estimatesoduring construction of the Long Lake stage.For
several years,these forecasts indicated a'need to proceed with the
Crater Lake stage construction immediately on completion of th~Long
Lake stage.The Corps of Engineers construction schedules and budget
requests,based on the APA power demand estimates,anticipated start of
construction on Crater Lake in FY 1977.Major factors in these fore-
casts were plans for a major new pulp mill in the Juneau area and for
iron ore mining and reduction facility in the vicinity of Port Snettisham.
Ned ther of these developments \iere anticipated at the time of authoriza-
tion.Both of these resource developments fell through,and this
resulted in a substantial reduction in the APA power demand estimate and
a decision in late 1975 to defer.the Crater Lake cons·truction start.
The pulp mill was particularly influential in the change in demand
estimates.The mill was planned for operation in the early 1970's with
a large population and commercial impact on Juneau~Initial access
faciliti,es \...ere constructed and site preparation \'1as well underway when
the project became entangled in protracted la\'1 suits involving logging
practices in SOutheast Alaska.Several court decisions were made in
favor of the development,but a last minute remand put the project back
to base one and led to cancellation in early 1975.
This type of uncertainty faces all utility planners.The staged project
like Snettisham'affords a great deal of capability to adjust to changes
in'demand.
Nany other factors influenced Juneau area power demands and utilization
of project power.Of particular concern at the moment is impact of
Alaska's capital move initiative.This would certainly change use of
project power,with the most likely outcome that the cornmunity would
move more quickly into an all-electric TOClde (space heating and electric
vehicles appear particularly attractive in this area)and industrial use
of power would increase through economic diversification.
-------------------------------------,---------------------
14
The key points of the ~nettisham revieH are:
1.The project was planned and authorized with intent to handle grov~h
in area power requirements for'a 20-year period.
2.The load forecasts used·as a basis for authorization were reasonably
accurate.
3.The actual use of project power may turn out to be substantially
different than originally anticipated.
4.The flexibility of staged projects was actually used.
5.The outlook for financial viability appears excellent at this time
in history •.
Implications for Susitna
First,the norm for utility investments cannot remain as the basis of an
8 to lO.year time horizon.This is evidenced by experiences since about
1970 on time required to plan,obtain necessary permits or authorizations,
find financing,and then build new powerplants and major transmission
facilities.The 8 to 10 years is much too short for nuclear,coal,and
hydro plants and for major transmission lines.
It appears appropriate to require a 20-year planning horizon with careful
checks at each step in the process and business-like decisions to shift
construction schedules if conditions (demands)change.We believe the
snettisham experience is very positive in this light.
The Susitna Project is similar in that project investment is keyed to
two major stages.The commitment of construction funds for Natana would
be needed in 1986 or 1987 to have power on line by 1993 or 1994.If .~
conditions in 1986 indicate need to defer the project,it should be
deferred.Similarly,start of actual construction on Devil Canyon can
.(.1,
15
and should be based on conditions that actua:py prevail at the time the
decision is made.
The level of uncertainty for Upper Susitna is greater than was the case
for Snetltisham on counts of higher interest costs and larger total
investment.Sensitivity to change in demands is much less for Susitna
because of its large and diversified power market area.There are many
more \'1ays that Susitna Project pm'1er could be effectively utilized in
the even"t that traditional utility power markets are smaller than
anticipa"ted at the present.
Upper Susitna'does not have as many uncertainities in terms of environ-
mental ~uestions as would equivalent power supplies from coal or nuclear
plants.Uncertainties on air quality are particularly relevant for any
larger Alaskan coal-fired powerplants.
-,---_---------:--------------...,1---------------------------
16
.~)
Current Evaluation
Power demands were estimated for High,Medium,and Low cases to year
2025 assuming logical variations in population and energy use per capita.
The projections reflect energy use per capita based on detailed studies
of 1970-1977 data from both the Anchorage and Fairbanks areas.The
projections considered variations in per capita use ranging from increased
use of electricity in the horne to anticipated effects of con~ervation on
decreasing the growth rates.A detailed discussion of the development
of the power demands is included in Chapter 5 of this report.
The load/resource and cost analysis provided system cost for comparison
of cases both with and without the Susitna Pn?ject.The analysis also
compared the power demands to the resources required to determine sizes
and timing of new plants (the load/resource analysis is summarized in
Chapter VII}.Table 2 summarizes the resources needed during the 1990's
for the range of projections..~.
The Table indicates that even under the ITDst conservative load growth
condition (low),1,500 Miv are needed to meet the combined Anchorage-
Fairbanks demands,which is roughly the capability of Susitna.
Tables 3 and 4 show the pOyler costs for Anchorage and Fairbanks during
the 1990's with an interconnection and with and without the Susitna
·Project.It is readily apparent the rates are less for the case with
Susitna.
For example,in the medium case for the year 2000,Anchorage costs are
5.5¢/kwh or 13 percent less than without Susitna.In the Fairbanks
costs,the difference is much larger,6.7¢/kwh or 25 percent less than
without Susitna.
In Table 5,annual system interest costs are composed with and without
Susitna with intertie from 1990 to 2011.Examination of the system cost
on an annual basis reveals the case with Susitna is cheaper than the
without Susitna case for each year except the first few years after
Watana comes on line.
'l'able 2.Schedule of Plant Additions -l~i
17
Cases with "Interconnection without Upper Susitna
Anchorage Fairbanks
Period .'High Median !.ow High Median Low·
89-90 400 *200 *100
90-91 200
91-92 400 200 ~
92-93 400 200 200
93-94 400 100
94-95 *100 *
1""""'"95-96 400 400 200 .100 100
96-97 400 400 200 100 100
97-98 400 400 200 100 100
98-99 400 400 100
99-00 400
TOTAL 90-2000 3200 2000 1200 700 "400 300
*Interconnection Installed in 1987 for high case,1990 for median case,
&1995 for low case.
Repla,cement of military powerplants,many of which also supply heat for
buildin<;rs are additional but not shown here.
---"''"t""--------------------,,---
TABLE 3.Power Costs for Anchorage and Fairbanks Areas With
Interconnection and Without Upper Susitna -0%Inflation
(cents/kwh)
18
~.
,:au
Anchorage Fairbanks
Period High Median Low High Median Low
89-90 5.7 4.5 4.2 4.7 5.8 5.6
90-91 5.4 '4.8 4.1 4.6 5.9 5.8
91-92 5.7 5.3 4.1 4.4 5.7 5.8
92-93 5.4 5.9 4.7 6.3 5.4 5.6
93-94 5.7 5.6 4.6 7.3 5.2 5.5
94-95 5.5 5.4 4.9 7.0 6.5
6.7
95-96 5.6 5.8 5.4 7.8 7.7 6.9
96-97 5.8 6.4 5.8 8.2 7.4 8.3
97-98 5.9 6.1 6.6 8.7 7.8 9.1 ~,
98-99 6.0 6.5 6.4 8.3 8.7 8.9
99-00 6.1 6.2 6.2 ,8.0 8.4 8.8
TABLE 4.Pb,.;er Costs for Anchorage and Fairbanks Areas With
Interconnection and With Upper Susitna Coming on
IJine in 1994 -0%Inflation
(cents/kwh)
Anchorage Fairbanks
Period Hig~Median Low High Median La,.;
89-90 5.7 4.5 4.2 4.7 5.8 5.6
90-91 .5.4 4.8 4.1 4.6 5.9 5.8
91-92 5~7 5.3 4.6 4.4 5.7 7.2
92-93 5~4 5.9 4.4 6.3 5.4 6.9
93-94 5.7 5.6 5.0 7.3 5.2 6.8
94-95 6.4 6.9 7.3 7.9 6.8 8.8
95-96 6,,0 6.5 6.8 7.7 6.7 8.9
96-97 6.2 6.1 6.5 7.2 6.4 8.6
97-98 6.2 5.8 6.3 6.6 6.9 7.8
98-99 6.1 5.8 6.1 6.5 6.9'7~6
99-00 5.8 5.5 6.1 6.2 6.7 7.8
19
20
~.
TABLE 5.Po\"er System Annual Costs for Anchorage and Fairbanks
With Upper Susitna Coming On Line in 1994 -0%Inflation
(million $)
Anchorage Fairbanks
Period High Median Low High Median Low
89-90 508.5 254.5 173.4 85.2 84~2 63.4
90-91 514.1 293.8 175.0 89.0 89.0 68.5
91'-92 591.8 343.8 206.0 90.2 90.2 87.4
92-93 597.3 409.9 205.0 137.8 88.2 85.5
93-94 666.0 414.1 244.5 166.8 89.2 86.4 .ao
94-95 798.5 537.5 372.3 192.2 120.5 115.6
95-96 806.1 537.9 368.4 198:0 ·124.8 119.2
96-97 898.6 543.0 368.5 198.5 124.0 117.5
97-98 793.1 549.3 369.9 192.5 139.2 109.2 ,..-".
98-99 1,009.1 576.3 376.1 .201.3 145.1 109.7
99-00 1,018.9 577.2 3910 7 203.5 145.7 114.9
00-01 1,025.1 573.4 381.4 228.6 146.5 114.5
01-02 1,101.3 578.5 380.3 254.0 147.4 114.5
02-03 1,172.1 658.6 375.3 254.3 168.6 111.9
03-04 1,190.4 665.1 376.6 291.6 169.6 112.0
04-05 1,287.7 670.8 376.8 296.0 170.6 112.1
05-06 1,366.8 677.6 378.0 296.1 170.2 110.7·
06-07 1,386.8 744.4 379.4 299.2 171.2 110.8
07-08 1,467.2 751.6 380.8 302.4 .172.3 110.9
08-09 1,548.1 759.0 382.2 305.7 173.4·111.1
09-10 1,569.9 766.7 383.7 343.5 174.6 111.2
10-11 1,671.6 834.3 385.2 347.0 175.7 111.4
Total 22,989.0 12,717.3 7,430.5 4,973.4 3,080.2 2,308.4
'21
(con1;inued)
TABLE 5.Power System Annual Costs for Anchorage and Fairbanks
Without Upper Susitna Coming,On Line in 1994 -0%Inflation
(million $)
Anchorage Fairbanks
Period High Median Low High Median Low--
89-90 508.5 254.5 173.4 85.2 84.2 63.4
90-91 514.1 293.8 175.0 89.0 89.0 68.5
91-92 591.8 343.8 185.7 90.2 90.2 71.1
92-93 597.3 409.9 223.3 137.8 88.2 69.2
93-94 666.0 414.1 227.2 166.8 89.2 70.1
94-95 678.0 421.3 252.4 169.<1 114.9 87.2
95-96 750.0 486.1 290.9 201.3 143.7 91.8
96-97 843.4 571.5 327.9.224.8 143.2 113.1
97-98 918.8 578.7 389.8 253.4 158.5 127.6
98-99 998.3 650.2 396.7 256.3 182.6 128.4
99-00 1,074.0 657.2 397.9 259.7 184.5 '129.3
00-01 1,160.8 714.3 470.6 262.3 185.5 129.6
01-02 1,238.6 721.1 472.5 265.3 186.8 130.2
02-03 1,310.9 723.1 469.8 265.8 208.2 128.3
03-04 1,331.0 789.8 472.8 303.5 209.6 128.8 .
04-05 1,350.7 798.5 474.8 341.2 211.0 129.3
05-06 1,431.7 807~1 477.8 343.1 210.9 128.4
06-07 1,513.3 815.9 480.9 346.5 212.3 151.7
07-08 1,615.1 904.4 484.0 350.1 213.8 152.2
08-09 1,638.1 913.6 487.1 353.7 215.3 152.8
09-10 1,721.4 923.1 490.3 357.5 216.9 153.3
10-'-11 1,801.7 932.7 493.6 361.4 218.4 153.9
Total 24,253.5 14,124.7 8,314.4 5,484.3 3,656.9 2,558.2
22 ,~.
It should be noted that in the 10\0'energy use estima.te the total system
cost for Anchorage during this period amounts to $883.9 million less
with Susitna than ~vithout.the project.,The difference is even larger in
the medium and high cases.The combined Anchorage-Fairbanks cash savings
for the Same period based on the medium power use estimate is almost'$2 Billion~
Previous Studies
There \.,as a fairly substantial backlog of power system and project
studies relevant to the 1976 evaluation of the Upper Susitna River
Project.The previous studies most relevant include:
1.Advisory Committee studies completed in 1974 for the Federal Power
Commission's (FPC)1976 Al~ska Power Survey.The studies include
evaluation of existing power systems and future needs through the year
2000,and the main generation and transmission alternatives available to
meet the needs.The power requirement studies and alternative
generation system studies for the 1976 power survey were used
extensively.
2.,A·series of utility system studies for Railbelt area utilities
include assessments of loads,power costs,and generation and trans-
mission alternatives.
3.Previous work by the Alaska Power Administration,the Bureau of
Reclamation,·the utility systems,and industry on studies of various
plans for Railbel t transmission interconnections and the Upper Susi tn'a
hydroelectric potential.
It should be noted that many of the studies listed in the bibliography
represent a.period in history when there \vas very little concern about
energy conservation,growth,and needs for conserving oil and natural
gas resourc~s.Similarly,many of these studies reflected anticipation
of long term,very low cost energy supplies.In this regard,the
studies for the 1976 power survey are considered particularly
significant in that they provide a first assessment of Alaska pmver
system needs .reflecting the current concerns for energy and fuels
conservation and the environment,and the rapidly increasing costs of
energy in the economy.
The latter concern for conservation,etc.has been carried even further
in this report.As yet unpublished studies by the Alaska Power Admini-
stration have made a definite reflection of conservation assumptions.
The resulting load forecasts were used in load/resource analyses done
and reported by Battelle Pacific Northwest Laboratories in 1978 and
1979.(Ba:Helle also published a report in 1978 entitled Alaska
Electric Power,and Analysis ~Future Requirements and Supply
Alternatives for the Railbelt Region.)Pop'ulation and employment used
in the recentfurecasts lvere proj ected and reported by the Institute of
Social and Economic Research in September 1978.The result of their
econometric:model is entitled South Central Alaska's Economy and
Population,1965-2025:A Base Study and Projection.A partial
bibliography of related studies including those of the 1976 Susitna
report,is appended.
25
PARTIAL BIBLIOGP~PHY OF RELATED STUDIES
The 1976 Alaska Power Survey,Federal Power Commission Vol.I and
Vol.II.
Alaska Regional Energy Resources Plant Project -Phase I,Alaska
Division of Energy and Power Development,Department of Commerce
an.d Economic Development,October 1977.
Volume I -Alaska's Energy Resources,Findings and Analysis
Volume II -Alaska's Energy Resources,Inventory of Oil,Gas,
Coal,Hydroelectric,and Uranium Resources
Jobs and Power For Alaskans:A Program for Power and Economic Develop-
ment,July 1978.Department of Commerce and Economic Development.
Appendix:Power and Economic Development Program,July 1978.
Alaska Electric Power Statistics 1960-1976,Alaska Power Administration,
July 1977.
The Proposed Glennallen-Valdez Transmission Line.An Analysis of
Available Alternatives.Robert W.Retherford Associates,May 1978.
Power Requirements Study,Matanuska Electric Association,Inc.Rural
Electrification Administration,May 1978.
26
Southcentral Railbelt Area,Alaska,Upper Susitna River Basin
Interim Feasibility Report.Hydroelectric Power and Related
Purposes,Corps of Engineers,December 1975.
Appendix I,Part I:(A)Hydrology,(B)Proj'ect Description
and Cost Estimates,(C)Power Studies and Economics,
(D)Foundation and Materials,(E)Environmental Assessment,
(F)Recreational Assessment·
Appendix I,Part II:(G)Marketability Analysis,(H)Trans-
mission System,(I)Environmental Assessment for Transmission
Systems
Appendix II:Pertinent Correspondence and Reports of Other
Agencies.
A Hydrologic Reconnaissance of the Susitna River Below Devils Canyon.
Environaid,October 1974.
Solomon Gulch Hydroelectric Project.Definite Project Report.
Robert W.Retherford Associates,March 1975.
Electric Power in Alaska,1976-1995.Institute of Social and Economic
Research,University of Alaska,August 1976.
Southcentral Alaska's Economy and Population,1965-2025:A Base
study and Projection.
Economic Research,University of Alaska,September 1978 (Draft Report).
27
Interior Alaska Energy Analysis Team Report.Fairbanks Industrial
Development Corporation for Division of Ener~and Power Development,
June 1977.
Natural Gas Demand and Supply to the Year 2000 in the Cook Inlet
Basin of Southcentral Alaska.SRI International for Pacific Alaska
LNG Company,November 1977.
Load/Resource and System Cost Analysis for the Railbelt Region of
Alaska;1978-2010.Battelle Pacific Northwest Laboratories,
January 1979.
Participation in Healy It Electric Generation,Fairbanks Mun~cipal
Utilities System.Harstad Associates,Inc.June 1978.
Economic Feasibility of a possible Anchorage-Fairbanks Transmission
Intertie.Robert W.Retherford Apsociates for Alaska Power Authority
(not yet completed).
1976 Po'wer Systems Study,Chugach Electric Association,Inc.Tippett and
Gele.March 1976.
Comparative Study of Coal and Nuclear Generation Options in the Pacific
Northwest,Washington Public Power Supply System,June 1977.
Coal-Fired Powerplant Capital Cost Estimates,Electric Power Research
Institute,January 1977.
28
Analysis of the Economics of Coal Versus Nuclear for a Powerplant Near
Boise,Idaho,Idaho Nuclear Energy Commission,March 1976.
Alaska Electric Power,AD Analysis of Future Requirements and Supply
Alternatives for the Railbelt Region,Battelle Pacific Northwest
Laboratories,March 1978.
Geology and Coal Resources of the Horner District Kenai Coal Field,Alaska,
Geological Survey Bulletin lOSS-F,19S9.
Development of the Beluga CoalField,a status report,A.M.Laird,
Placer Arnex Inc.,San Francisco,California,October 1978.
TTidal Power From Cook·Inlet,Alaska,Swales,M.C.and Wilson,E.M.,
published in Tidal Power,Proceedings of the International
Conference on the Utilization of Tidal Power,May 1970.
Advisory Committee Reports for Federal Power Commission Alask~
Power Survey:
Report of the Executive Advisory Committee;December 1974
Economic Analysis and Load Projections,May 1974
Resources and Electric Power Generation,May 1974
Coordinated Systems Development and Interconnection,December 1974
Environmental Considerations and Consumer Affairs,May 1974
29
Alaska Power Survey ,Federal Pmver Commission,1969.
Devil Canyon status Report,Alaska Power Administration,May 1974.
Devil Canyon Project -Alaska,Report of the Commissioner of Reclamation,
March 1961,and supporting reports.Reprint,March 1974.
Reassessment Report on Upper Susitna River Hydroelectric Development
for the State of Alaska,Henry J.Kaiser Company,Sept.1974.
Project Independence,Federal Energy Administration,1974.A main
report,summary,seven task force reports,and the draft environmental
impact statement.
Engineering and Economic Studies for the City of Anchorage,Alaska
Municipal Light and Power Department,R.W.Beck and Associates
and Ralph R.Stefano and Associates,August 1970.
Power Supply,Golden Valley Electric Association,Inc.,Fairbanks,
-Alaska,Stanley Consultants,1970.
Copper Valley Electric Association,Inc.-15 Year PO\ver Cost Study,
Hydro/Diesel,Robert W.Retherford Associates,October 1974 .
.-,-------------.....,.--------------.,,------------------------
30
Environmental Analysis for Proposed Additions to Chugach Electric
Association,Inc.,Generating station at Beluga,Alaska,Chugach
Electric Association,October 1973.
Central Alaska Power Pool,working paper,Alaska Power Administration,
October 1969.
Alaska Railbelt Transmission System,working paper,Alaska Power
Administration,December 1967.
Electric Generation and Transmission Intertie System for Interior and
So~thcentral Alaska,CH2M Hill,1972.
Central Alaska Power Study,The Ralph M.Parsons Company,undated.
Alaska Power Feasibility Study,The Ralph M.Parsons Company,1962.
"...}
PNL-2896
INFORMAL REPORT
LOAD/RESOURCE AND SYSTEJl1 COST ANALYSIS
FOR THE RAILBEt.T REGION OF ALASKA:
1978-201 0
for
ALASKA POWER ADMINISTRATION
u.s.DEPARTMENT OF ENERGY
by
J.J.Jacobsen
W.H.Swift
J.A.Haech
January 1979
Pacific Northwest Laboratory
Richland,Washington 99352
"----nv---""----,----'j"--------------r""'i-----------------
CONTENTS
LIST OF FIGURES
LIST OF TABLES .
1.0 INTRODUCTION
2.0 SUMMARY AND CONCLUSIONS
3.0 LOAD/RESOURCE ANALYSES
3.1 ANALYSIS METHODOLOGY
3.2 ASSUMPTIONS
3.2.1 Forecasted Power and Energy Requirements
3.2.2 Existing and Planned Generating Capacity
3.2.3 Reserve Margin
3.2.4 Transmission Losses
3.2.5 Construction Schedule Constraints
3.2.6 Plant Availability Constraints
3.2.7 Economic Generating Unit ,Size
3.3 SYSTEM CONFIGURATIONS =DEFINITION OF CASES ANALYZED
3.3.1 Case 1:Without Interconnection and Without Upper
Susitna Project
3.3.2 Case 2:With Interconnection,Without Upper Susitna
Project .
3.3.3 Case 3:Interconnected System With Upper Sus itna
Project
3.4 RESULTS OF LOAD/RESOURCE ANALYSES
4.0 SYSTEM POWER COST ANALYSES
4.1 FACTORS DETERMINING THE COST OF POWER
4.1.1 Capital Costs
4.1.2 Heat Rate
4.1.3 Operation,Maintenance,and Replacement Costs
4.1.4 Financing Discount Rate
4.1.5 Payback Period
4.1.6 Annual Plant Utilization Factor
4.1.7 Unit Fuel Costs
4.1.8 General Inflation Rate.
4.1.9 Construction Escalation Rate
iii
v
'Ii
1
4
7
8
8
8
15
15
21
21
22
25
25
25
26
30
31
66
66
'66
68
68
69
69
69
69
73
73
__~"""""',.,.......~----~'*~_~_m __---_
4.1.10 Fuel Escalation Rate ..73
4.2 METHOD OF COMPUTING THE ANNUAL COST OF POWER FROM INDIVIDUAL
GENERATING FACILITIES 73
4.3 METHOD OF COMPUTING AVERAGE SYSTEM POWER COST 75
4.4 RESULTS OF SYSTEM CASH FLOW AND POWER COST CALCULATIONS 76
iv
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.11
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
FIGURES
Railbelt Region Peak Loads
Anchorage-Cook Inlet ~rea Annual Energy
Fairbanks Area Annual Energy
Plant Utilization Factor versus Plant Age
Railbelt Region Showing the Watana and Devil Canyon Damsites,a
Possible Route for the Interconnection,and the Beluga Area
Load/Resource Analysis for Anchorage-Cook Inlet Area Without
Interconnection and Without Susitna Project (Case 1).
.Load/Resource Analysis for Anchorage-Cook Inlet Area With
Interconnection but Without Upper Susitna Project (Case 2)
Load/Resource Analysis for Anchorage-Cook Inlet Area With
Interconnection and With Upper Susitna Project Coming On Line in
1994 (Case 3)
Load/Resource Analysis for Fairbanks-Tanana Valley Area Without
Interconnection and Without Upper Susitna Project (Case 1)
Load/Resource Analysis for Fairbanks-Tanana Valley Area With
Interconnecti on but Without Upper Sus itna Project.(Case 2)
Load/ResourceP..na lys i sfar Fairbanks-Tanana Valley Area ~.Jith
Interconnecti on and With Upper Sus i tna Project Comi og On Li ne in
1994 (Case 3)
Components of the Total Annual Cost of Power
Estimates of Future Coal Prices -.2%and 7%Escalation
Estimates of Future Natural Gas Prices -2%and 7%Escalation
Estimates of Future Fuel Oil and Diesel Prices -2%and 7%
Esca.l ation
Power Costs for Anchorage Low Load Growth Scenario
Power Costs for Anchorage Medi urn Load Growth Scena ri 0
Power Costs for Anchorage High Load Growth Scenario
Power Gnsts for Fairbanks Low load Growth Scenario
Power Costs for Fairbanks Medium Load Growth Scena~io
Power Costs for Fairbanks High Load Growth Scenario
v
12
13
14
23
28
60
61
62
63
64
65
67
70
71
72
116
117
118
119
120
121
TABLES
3.6
3.5
3.7
3.4
58
54
56
19
20
27
32
6
9
10
19
16
11
18
3.8
3.9
3.10
3.11
Comparisbn of Power Costs for Year 2005
Anchorage-Cook Inlet Area Power and Energy Requirements
Fairbanks-Tanana Valley Are?Power and Energy Requirements
Total Power Requirements;Anchorage-Cook Inlet Area and
Fairbanks-Tanana Valley Area Combined.
Existing (Fall-1978)Generating Capacities for Anchorage-Cook
Inlet Area
Existing (Fall-1978)Generating Capacities for Fairbanks-Tanana
.Valley Area
Anchorage-Cook Inlet Area Existing Capacity and Maximum Annual
Plant Utilization (October 197&)
Fairbanks-Tanana Valley Area Existing Capacity and Maximum
Annual Plant Utilization (October 1978)
Planned Additions for Railbelt Region (1979-1995)
,Transmission System Alternatives.
Load/Resource Balance for Case 3:Medium Load Growth Scenario .
Schedule of Plant Additions (Megawatts)Base Cases Without
Interconnections
3.12 Schedule of Plant Additions (Megawatts)Cases With
Interconnection Without Upper Susitna .
3.13 Schedule of Plant Additions -(Megawatts)Cases With
Interconnection With Upper Susitna Coming On Line in 1994
2.1
3.1
3.2
3.3
4.1 Anchorage-Cock Inlet Area,Low Load Growth Scenario,Case 1,
O~~Infl ation 78
4.2
4.3
4.4
Anchorage-Cook
5%,rnf1 ation
Anchorage-Cook
0%Infl ati on .
Anchorage-Cook
5%Inflation
Inlet Area,Low Load Growth Scenario,Case 1,
Inlet Area~Low Load Growth Scenario,Case 2
Inlet Area,Low Load Growth Scenario,Case 2,..'
79
80
81
4.5
4.6
4.7
Anchorage~Cook Inlet Area,Low Load Growth Scenario,Case 3,
0%Inflation.
Anchorage-Cook Inlet Area,Low Load Growth Scenario,Case 3,
5%Inflation.
Anchorage-Cook Inlet Area,Medium Load Growth Scenario,Case 1,
0%lnfl ati on
82
83
84
v;
TABLES (contd)
4.8 Anchorage-Cook Inlet Area,Medium Load Growth Scenario,Case 1,
5%Inflation.85
4.9 Anchorage-Cook Inlet Area,Medium Load Growth Scenario,Case 2,
0%Inflation .86
4.10 Anchorage-Cook Inlet Area,Medium Load Growth Scenario,Case 2,
5%Infl ation .87
4.11 Anchorage-Cook Inlet Area,Medium Load Growth Scenario,Case 3,
0%Inflation 88
4.12 Anchorage-Cook Inlet Area,Medium Load Growth Scenario,Case 3,
,5%Infl ation 89
4.13 Anchorage-Cook Inlet Area,High Load Growth Scenario,Case 1,
0%Infl ation .90
4.14 Anchorage-Cook Inlet Area,High Load Growth Scenario,Case 1,
5%Inflation .91
4.15 Anchorage-Cook Inlet Area,High Load Growth Scenario,Case 2,
0%Infl ation .92
4.16 Anchorage-Cook Inlet Area,High Load Growth Scenario,Case 2,
5%Inflation .93
4.17 Anchorage-Cook Inlet Area,High Load Growth Scenario,Case 3,
0%Inflation 94
4.18 Anchorage-Cook Inlet Area,High Load Growth Scenario,Case 3,
5%Inflation 95
4.19 Fairbanks~Tanana Valley Area,Low Growth Scenario,Case 1,
0%Inflation 96
4.20 Fairbanks-Tanana Valley Area,Low Growth Scenario,Case 1,
5%Inflation.97
4.21 Fairbanks-Tanana Valley Area,Low Growth Scenario,Case 2,
0%Inflation.98
4.22 Fairbanks~Tanana Valley Area,Low Growth Scenario,Case 2,
5%Inflation.99
4.23 Fairbanks-Tanana Valley Area,Low Growth Scenario,Case 3,
0%rnfl ation .100
4.24 Fairbanks-Tanana Valley Area,Low Growth Scenario,Case 3,
5%Inf1 ation .101
4.25 Fairbanks-Tanana Valley Area,Medium Growth Scenario,Case 1,
0%Infl ation .102
4.26 Fairbanks-Tanana Valley Area,Medium Growth Scenario,Case 1,
5%Inflation.103
vii
......__....__------,---------L_..-----"F'I-------------------
.~
'I
TABLES (contd)
4.27 Fairbanks-Tanana Valley Area,Medium Growth Scenario,Case 2,.
0%Inflation.104
4.28 Fairbanks-Tanana Valley Area,Medium Growth Scenario,Case 2,
5%Infl a tion ·105
4.29 Fairbanks-Tanana Valley Area,Medium Growth Scenario,Case 3,
0%Infl ation ·106
4.30 Fairbanks-Tanana Va 11 ey Area,Medium Growth Scenario,Case 3,
5%Infl atian ·107
4.31 Fairbanks-Tanana Valley Area,High Growth Scenario,Case 1,
·0%Inflation ·108
4.32 Fairbanks-Tanana Valley Area,High Growth Scenario,Case 1,
5%Infl ation '.109 ..
4.33 Fairbanks-Tanana Valley Area,High Growth Scenario,Case 2,
0%Inflation 110
4.34 Fairbanks-Tanana Valley Area,High Growth Scenario,Case 2,
5%Inflation 111
4.35 Fairbanks-Tanana Va 11 ey Area,High Growth Scenario,Case 3,~
0%Inflation ·112
4.36 Fairbanks-Tanana Va 11 ey Area,High Growth Scenario,Case 3,
5:~Inflation ·113
viii
LOAD/RESOURCE AND SYSTEM COST ANALYSIS
FOR THE RAILBELT REGION OF ALASKA -1978-2010
Prepared fqr the
Alaska Power Administration
by
Battell e
Pacific Northwest Laboratories
January 1979
1.0 INTRODUCTION
The Alaska RaiTbelt region presents some unique attributes for considera-
tion in future power system planning.The region currently consumes 83%of
the State1s electric power and even the lower estimates of electrical load
growth (5%~erannum)for the region are above the national average.
The State,and particularly this reg10n,is a difficult one in which to
forecast load growths.This difficulty results from the nature of the economic
activity base being influenced by external forces such as oil and gas develop-
ments and transportation systems with their cyclical tendency.Also,since the
economic base is still not large,the injection of a competitively scaled
industry such as major ~etroleum refinery or electrochemical industry can sig-
nificantly perturb a forecast.•
A major shift in the Alaskan Railbelt future power generating mode appears
inevitable.The Cook Inlet Region's capacity is presently dominated by combus-
tion turbines fired by currently low-cast natural gas;the Fairbanks-North Star
Borough by a mix of coal-fired steam turbine generation and oil-fir'ed combus-
tion turbines.The oil and gas based mode of generation,however,are highly
exposed to inflationary pressures,external market forces,and Federal regula-
to ry i nterven ti on.
The Railbelt region,however,does have a number of options open in the
future.These include:
•Continued use of oil and gas in existing plants.
•Increased coal based thermal generation both in the interior based on the
Healy Coal Field and in the Cook Inlet Region based on several coal
fields~including the very large reserves in the Beluga Region.
•Development of the signiftcant hydroelectric potential.including Upper
Susitna River and Bradley Lake.
• A transmission intertie between the Cook Inlet and Fairbanks load centers
is of obvious interest as a means of increasing rel1ability or alternately
reducing additional generating capacity needed for reliability.Marketing
of power from Upper Susitna projects will be dependent upon such an·
intertie.
Electric power generation by whatever means is a very capital intensive
activity.Different forms of generation,however,have different levels of
exposure to inflation and escalation and,cost comparisons on a straight S/kW .~
of installed capacity can be misleading.Thus a higher cost per kilowatt hydro-.,
electric project has this exposure largely limited to the time period during
planning and construction.On the other hand,a fossil fueled plant faces
rising fuel costs as well as operating and maintenance costs in the future.
Regardless of these factors,all generation options are faced with long lead,
times from decision to proceed to commercial operating date.
The purpose of this report is to examine the probable timing of major
generation and transmission investments and their impact on system power costs
under a range of assumptions about power demands and inflation and escalation
rates for the following general Railbelt power supply strategies:
Case 1.All additional generating capacity assumed to be coal fired steam
turbines without a transmission interconnection between the .8.nchorage-
Cook Inlet area and the Fairbanks-Tanana Valley area load centers.
Case 2.All additional generating capacity assumed to be coal fired steam
turbines,including a transmission interconnection.
Case 3.Additional capacity to include the Upper Susitna Project (including
transmission intertie)plus additional coal as needed.
The first step involved in estimating the cost of power from alternative
generation and transmission system configurations is to perform a series of
load/resource analyses.These analyses determine the schedule of major invest-
ments based on assumptions about the load growth,the capac;ty and power produc-
tion of the prospective generating facilities,and constraints as to when the
facilities can come on line.
The load/resource analyses provide information on the annual power produc-
tion of the various types of generating plants.Once the annual plant utiliza-
tionsare known,they can be used in conjunction ~ith estimates of annual
system costs to calculate the annual cost of producing power from the facili-
ties.Summing the annual cost for generation and transmission of each of the
generating facilities gives a total cost for the entire system being analyzed.
Dividing the total annual cost by the power produced gives an average annual
cost of power for the entire system.By comparing the average annual power
costs over the period of interest (1978-2010)the alternative configurations
can be ranked based on the cost of power.All other things being equal,the
system configuration producing power at the lowest cost should be selected as
the most desirable system.
The report was prepared on contract to the Alaska Power Administration (APA)
as input to APA's power market analysis for the Upper Susitna Project.The APA
furnished,and is responsible for,a11 data on power requirements,cost assump-
tions,and certain key criteria for the study.The balance of the criteria were
~eveloped jointly by the APA and Battelle.
Chapter 2 contains a bri ef summary of the results of the study.The loadl
resource analyses are described in Chapter 3.Chapter 4 presents the methodol-
ogy and results of the cash flow and power cost calculations.Appendix A con-
tains the data used in the load/resource analyses.Appendix B contains a list-
ing of the computer model (AEPMOD)used to perform the load/resource matching.
The output of AEPMOD for the cases analyzed in this report are presented in
Appendix C.Appendix 0 contains a listing of the model used to compute the cost
of power and Appendix E contains some selected results of ECOST 4 model runs.
3
2.0 SUMMARY AND CONCLUSIONS
Load/Resource Matchinq
•Forecasted peak loads for the Anchorage/Cook Inlet and the Fairbanks/
Tanana Valley load centers have been matched with schedules of plant addi-
tions for low,median,and 'high forecasted load growths.These were
replicated for cases considering 1)continued separation of the load cen-
ters.2)interconnection without development of Upper Susitna hydroelec-
tric power,3)interconnection including development of the proposed Upper
Susitna hydroelectric projects beginning in 1994.
•Thermal generating capacity additions to the year 2010 were estimated as
follows:
Case 1:Without Interconnection and Upper Susitna
Assumed Load Megawatts
Growth Anchorage Fairbanks Total
Low
Median
High
2600
4600
8200
471
871
1471
3071
5471
9671
Case 2:Interconnection wi thout Upper Sus itna
Assumed Load Megawatts
Growth Anchorage Fairbanks Total
Case 3:Interconnection with Upper Susitna
Assumed Load Megawatts
Growth Anchorage Fairbanks Total
Low
Median
High
Low
Median
High
2200
4200
8200
1000
3000
6600
4
471
671
1271
171
371
1071
2671
4871
9471
1171
3371
7671
•Provision of the interconnection without Upper Susitna reduces thermal
plant addition requirements by 200 to 600 MW over the period.
•Interconnection with Upper Susitna reduces thermal plant addition require-
ments by 1500 to 1800 MW depending on the assumed load growth.
•Under the criteria used.the interconnection is called for in 1986. 1989.
and 1994 for high.median;and low load growth cases.respectively.with-
out Upper Susitna projects.With Upper Susitna.the corresponding dates
are'1986,1989.and 1991.
System Power Cost
•F6r the Anchorage-Cook Inlet load center construction of the inter-
connection reduces the cost of power compared to the case without an
i nterconnecti on ~
•For the Anchorage~Cook Inlet area inclusion of the Upper Susitna project
into the system generally raises the cost of power above the other cases
during the first 2 to 4 years after the Watana Dam comes on line with
results in lower power costs during the 1996-2010 time period.
Q For the Fairbanks-Tanana Valley area construction of the interconnection
again generally reduces the cost of power.
•For the Fairbanks-Tanana Valley load center inclusion of the Upper Susitna
project generally raises the cost of power above the case with the.inter-
connection for about 2 years after the Watana Dam comes on line but,as
with the Anchorage-Cook Inlet area,results in lower power costs during
the 1996-2010 time period~
•Table 2.1 presents a comparison of the costs of power in the year 2005
for the cases evaluated in the report using the case without either the
interconnection or the Upper Susitna projects (Case 1)as the base.The
costs of power computed in Case 1 are compared to cases with the inter-
connection (Case 2).and with Upper Susitna coming on line in 1994 (Case 3).
As shown,the costs of power are reduced below the cost of power for
Case 1 in but one case.This reduction varies from 4.3%to 39.3%depend-
ing upon the situation.
5
______________-,.-,-.------""'F'"-----.-r"'""....------.-------------
TABLE 2.1.Comparison of Power Costs for Year 2005
Percent Change in Cost of Power
Below Case 1 5%Inflation
Anchorage Fairbanks
High Median Low High Median Low
Case 2 -4.3 -1 C.1 -12.2 +8.9 -9.6 -4.2
Case 3 -10.5 -30.3 -39.3 -8.9 -30.8 -26.3
6
3.0 LOAD/RESOURCE YScS
The load/resource analysis is intended to match forecasted electric power..
requirements with appropriate generating capability additions.The analysis
schedules new plant additions,keeps track of older plant retirements,and com-
putes the loading of installed·capacity on a year-by-year basis over the period
1978 to 2010.
The analysis schedules the additions to assure that both peak loads and
energy requirements (including reserves)are met on a year-by-year basis with
the least amount of installed capacity and with generating plants loaded in any
preselected order,typically in ctcier of lowest to highest marginal power costs.
A number of factors must be taken into account:
1.Forecasted loads in terms of peak power requirements in megawatts (MW)and
annual energy requirements in millions of killowatt hours (MMkWh).
2.The stock of existing generating capacity by type,size,year of retirement,
/'-..,and maximum allowable plant factor.
3.Desired reliability reserve margin to Pi J ide ~
outages,unforeseen delays in plant availabili t..J'
of those anticipated.
''ince against forced
~r lOed qrowths in excess
4.Transmission and distribution losses.
5.Construction schedule constraints;i.e.,lead times necessary between unit
selection and first power on line date.
6.Plant availability constraints based on type~Jnd age.(Thermal plants
generally have lower availability at the start and end of their economic
1 He.)
7.Assumptions about the economic size of future generating plants in relation
to the loads.
8.System configuration;i.e.,interconnections,alternative siting strategies.
7
-,.0_,....1AA....~_--------r-
3.1 ANALYSIS METHODOLOGY
The load/resource matching is done on an annual basis.The Alaskan.elec-
tric utility systems experience their annual peak load requirements during the
winter months and resources must be available to meet these peak loads.During
recent years the annua~load factor for Railbelt electrical demand has typi-,
cally been about 46-50%.It is expected to remain in the range of 50-52%
during the time horizon of this study.The existing and planned future gener-
ating capacity in the Railbelt region is capable of operating at a capacity
factor either equal to or greater than 50%.Because of this,the decision to
add n~w capacity will usually be based on the need for capacity (kW)rather
than energy (kWh).Thus in this analysis capacity additions are scheduled
based on peak loads rather than upon average annual energy.
The general approach to load/resource analysis is to summarize existing
and planned gross resources for each year,adjust them downward for a reliabil-
ity margin and for system transmission losses to arrive at net resources.If
these net resources exceed the critical period load for the year being analyzed,
plant additions are not called up and the analysis proceeds to the next year
and is repeated~At some point,the net resources will not meet the forecasted
peak loads and additional capacity must be added.Also,for each year,the
energy generated by each class of plants (e.g.,hydl~O,steam turgine,combus-
tion turbine,anD diesel is computed so that plant utilization factors are
available for review and system energy costs can be developed.The stepwise
calculations are continued to the end of the period being studies (2010).
3.2 ASSUMPTIONS
3.2.1 Forecasted Power and Energy Requirements
The analyses are based on forecasts prepareo by the Alaska Pmver Adminis-
tration for both the Anchorage-Cook Inlet and the Fairbanks-Tanana Valley areas.
Probable high and low bounds were provided along with median forecasts.These
are presented in Tables 3.1 through 3.3 and are shown graphically in Figures 3.1
through 3.3.In addi ti on to util ity loads,Anchorage-Cook In1 et forecasts
include both national defense and industrial loads and the Fairbanks-Tanana
Valley forecasts include national defense loads.
8
l!MW =Megawatts
GWh =Gigawatt-hours (Equivalent to MMkWh =Millions of kilowatt-hours)
Source:Alaska Power Administration,October 1978
9
10
TABLE 3.3.Total Power Requirements;<,rage-Cook Inlet Area
and Fairbanks-Tanana Valley M·ca ::Jliibi ned
PEAK pmJER
1977,/1980 1985 1990 1995 2000 2025
MW -MW MW MW MW MW ~~\~
TOTAL
High 890 1,671 2,360 3,278 4,645 10,422
Median 650 829 1,162 1,592 2,134 2,852 4,796
Low 769 961 1,177 1,449 1,783 2,146
ANNUAL ENERGY
,
Gi'i:-'GWh GWh GWh GWh GWh GWh---
TOTAL
High 3,928 7,636 10,684 14,844 20,935 47,054
Median 2,681 3,663 5,133 7,078 9,528 12,738 21,578
Low 3,391 4,256 5,219 6,430 7,890 9,630
l!~~W =Megawa tts
GWh =Gigawatt-hours (Equivalent to MMkWh =Mil1i~ns of kilowatt-hours)
Source:Alaska Power-Admi ni stra ti on,GeL._~
11
FAIRBANKS-TANANA VALLEY AREA
ANCHORAGE -COOK INLET AREA
200 L
3000
2000
6000
5000 .
4000
tn LOWI--
I--«
$:«
0 1000u...!
~900
0 800<:
0
-l 700~«600wc..
500
400
300 LOW
100-l..--__.....l-I.-:.:....-_.....l-__---J'--__.........__----'....L-__--'-'
1980 1985 1990 1995 2000 2005 2010
FIGURE 3.1.Railbelt Region Peak Loads
12
~.
z:10,000
o 9000
--I
--I 8000
~~7000
>-.
r,,:)6000c:::
l..t-I
3 5000
.....I
<C
~4000
z
<C
3000
2000
Anchorage-Cook Inlet Area Annual Energy
13
2005 20la
3000
.~...
~...1000
o 900
800
700
600
500
300
200
6000
5000
4000
::2:->
(,:)
c::
UJz
UJ
-J<:
=:l 400zz
<:
100 1..-__....L-__-.J-__---l..l.-__.....l-__~_____a..I
1980 1985 1990 1995 2000 200S 2010·
·.FIGURf 3.3.Fairbanks Area Annual Energy
14
The Alaska Power Administration data h'-o ::that approximately 80%of
the Railbelt region loads are expected to be in :he Anchorage-Cook Inlet area.
These loads have been interpreted as recognizing distribution losses.
3.2.2 Existing and Planned Generating Capacity
The exi sting stock of gen~rating capacity for the Anchorage-Cook Inl et
area and the Fairbanks-Tanana Valley area is presented in Tables 3.4 and 3.5,.
.respectively.
The.total existing capacities and maximum plant utilization
.the various generating types for the Anchorage-Cook Inlet area and the
Fairbanks-Tanana Valley area are ,:I~own in.Tables 3.6 and 3.7,respectively..--"
The Toad/resource matchi ng analyses use these totals for the fi rst year of the
analyses (1978-1979).
Generating capacity additions can be specified to be added in'one of two
ways_It can either be added i~a specified year or can be added when it is
required to maintain adequate generating capacity.In the former case the
generati ng units are added whether they are requi red or not.The pl anned addi-
tions shown in Table 3.8 are brought on line ;"i the V"'O>I'"S specified.National
defense generating units are assumed to be replaced_~:;am turbine generating
units the same year as they are retired.(See Sectior 3.2.7 ~or 3 discussion
of the units aded as required to maintain adequate generating capacity.)
3.2.3 Reserve Margin
Utility systems invariably carry a reserve rnli~gin of generating and trans-
mission capacity as insurance against loss of l"",-,c,unexpected .peak require-
ments as a result of severe weather,load growths more rapid than anticipated,
adverse:hydroelectric.conditions,and delays in the commercial operation of new
generation_.The.most appropriate.reserve margin will vary from system to
system depending on the nature of the loads and types of resources and special
factors.Typically,a reserve capacity at peak of 20%is used nationally.
However,this can vary to as low as T2%as is the present case for the Pacific
Northwest with its predominance of reliable hydropower and interruptable loads.
15
TABLE 3.4.Existing (Fall 1978)Generating Capacities
for Anchorage-Cook Inlet Area
1988
1993
1996
1995
1996
1996
1996
1983
1992
1998
NA
1982
1982
1984
1988
1992
1995
1995
Retirement
Year
33,000
54,600
9,300
65,000
67,810
68,OOOCe)
32,200
8,370
17,860
18,000
16,500
S.c:C.To}
S.C.C.T.
R.C.C.T.*
S.G.C.T.
R.C.C.T.
S.C-C.T.
S.C.C.T.
C.C.
S.C.C.T.
S.C.C.T.
S.C.C.T.
Hydro
Berni ce Lake
Bernice Lake
Bernice Lake
Cooper Lake
;Beluga
Beluga
Beluga
Beluga
Beluga
Beluga
Beluga
Beluga
;~,
Deisel
Unit 1
Unit 2
Unit 3
Unit~4,.
Unit 5.
Unit 6
Type of Capacity
Unit Reference/Name Location Generation (kW)
ANCHORAGE MUNICIPAL LIGHT AND POWER (AML&P)
Anchorage Diesel 2,200
Anchorage S.C.C.T.*15,130
Anchorage S.C.C.T.15,130
Anchorage S.C.C.T.18,650
Anchorage S.C.C.T.31,700
'Anchorage S.C~C.T.36,000
Anchorage C.C.16',500'
Subtotal 137,500 (a)
;,'...::..:.:.:::.=:...:.:::;;.;.-==.:;~:..=..-:...=:...=..=.;...:..:.....:..:~(...,;;.C==-EA.;.L.)
Tal keetna Di es e1
HOMER ELECTRIC ASSOCIATION (HEA)
.Eng1 ish Bay Diesel
S.T.*
Subtotal
MATANUSKA ELECTRIC ASSOCIATION
1993
1993
1985
1991
1987
1993
1993
1995
100
200
300(c)
7,000(d)
30,510
18,140
10,OOOCt)
449,.790
(MEA)
Di esel
S.C.C.T.~
S.C.C.T.I
S.C.C.T.
Diesel
S.C.C.T.
Port Graham.
Homer'
Homer
Talkeetna.
English Bay
Homer'&Kenai e
Combined
Homer Combined
Port Graham
Combined
16
TABLE 3.4 (contd)
Type of
Unit Reference/Name Location Generation
HOMER ELECTRIC ASSOCIATION (HEA)
Capacity
__(t~
(contd)
Retirement
,Year
Seldovia Combined Seldovia Diesel
Subtotal
SEWARD ELECTRIC SYSTEM (SES)
Subtotal
ALASKA POWER ADMINISTRATION
Seward Combined Seward Diesel
1 ,500
9)100
3)000(b)
2,500
5,500
(APA)
1980
1985
1996
Ekl utna
Ft.Ri chardson/
Emendorf
Kenai
Ek1 utna Hydro
Subtotal
NATIONAL DEFENSE
S.T.
Diesel
Diesel
Subtotal
INDUSTRIAL
,S.C;C.T.
TOTAL
30,000
30,000
40,500
7)300
2,000'
49)800
12,300(g)
685,290
NA
1991
1985'
1991
1988
J •
3.
4.r
*S.C.C.T.-Simple Cycle Combustion Turbine
R.C.C.T.-Regenerative Cycle Combustion Turbine
S.T.-Steam Turbine
C.C.-Combined Cycle
1a)Capacities for individual units are from sources 1 and 2.These sum
to 118,810 kW.Total shown is from source 2.
(b)Standby
(c)Leased to CEA
(d)Leased to HEA by Golden Valley Electric Assoc~"ion for 1977-1979.
(e)Included in this study,but late 1978 plans are ~o defer 8etuga 8
until 1980 and double the capacity.
(f)Nameplate capacity derated to 10,000 KW from 14,500 KW.
(g)Recent data shows industrial load to be 25,000 KW rather than 12,300
KW.
SOURCES:
Electric Power in Alaska,1976-1995,ISER,University of Alaska,
.pp.J.5.2-7.4,August 1976.
2.Alaska Electric Power Statistics 1960-1976,Alaska Power Administra-
tion,pp.15-17,July 1977.'
1976 Power System Study,Chugach Electric Association,Inc.,Tippett
and Gee,Dallas,TX,p.7,March 1976.
Alaska Power Administration,August 1978.
17
TABLE 3.5.Existing (Fall '1978)Generating Capacities
for Fairbanks-Tanana Val1ey Area
Unit
Reference
Name Location
Type
Generation
Capac;ty
(kW)
Year of
Retirement
FAIRBANKS MUNICIPAL UTILITIES SYSTEM (FMUS)
Chena 2 Fairbanks S .T.2,000 1988
Chena 3 Fairbanks s.r.1,500 1988
Chena 1 Fairbanks S.T.5,000·1988
Chena 4 Fairbanks S.C.C.T.5,350 1983
Oi esel 1 Fairbanks Di esel 2,664 1988
Di~sel 2 Fairbanks Diesel 2,665 1988
Diesel 3 Fairbanks Diesel 2,665 1988·
Chena 5 Fairbanks S.T.20,000 2005·
.Chena 6 Fairbanks S.C.C.T.23,500 1996
Subtotal 65,345
GOLDEN VALLEY ELECTRIC ASSOCIATION (GVEA)
Fairbanks Diesel 24,000 1984
Healy #1 Healy S.l.25,000 2002
Fai rbanks S.C.C.T.40,000 1992
Delta Di esel 500 1988
North Pale #1 North Pole S.C.C.T.70,000 1997
North Pale #2 North Pole S.C.C.T.70,000 1997
Subtotal 229,500
NATIONAL DEFENSE
CombiJled
CTear A.F.B.and
Ft~Greely
Ft:.vlai nwrig'ht and
Eils.on,A.-F'~B."-'
Diesel 14,000 1988
S.T.24,500 1995
S.L 32,000 (a)1990
Suhtotal 70,500
fa)5 MW pTantat Eilson A.F.B.installed in 1970 and old 1.5 MW plant
-at Ft.Wai nwright were i nadvertant1y omitted.
SOURCE;
1.Interior Alaska Energy Analysis Team,Final Report,June 1977.
2.Alaska Power Administration,August 1978.
18
TABLE 3.6.Anchorage-Cook Inlet Area Existing
Capacity and Maximum Annual Plant
Utilization (October 1978)
Hydro
Steam Electric.•Combustion Turbine
Diesel
Capacity
(MW)
46.5
50.5
575.01
19.13
Plant
Util ization
(%)
50.0
75.0
50.0
15.0
TABLC 3.7.Fairbanks-Tfrnana Valley Area Existing
Capacity and Maximum Annual Plant
Utilization (October 1978)
Hydro
Steam Electric
Combustion Turbine
Di ese 1
Capacity
(t~i~)
o
110
208.9
46
19
Plant
,Utilization.
(%)
50.0
75.0
50.0
10.0
.
TABLE 3.8.Planned Additions for Railbelt Region (1979-1995)
Unit Reference!Year of
Name Installation Location
Type of
Generation
Capacity
(kW)
Unit 7
Unit 6
ANCHORAGE MUNICIPAL LIGHT AND POWER (AML&P)
1979 Anchorage S.C.C.T.
1979 .Anchorage C.C.
65,OOO~~~
16,500
GOLDEN VALLEY·ELECTRIC ASSOCIATION (GVEA)
As Required "Healy S.T.
Beluga #9
X-I
Bern ice Lake #4
X-2
Berni ce .Lake #5
Healy #2
CHUGACH ELECTRIC ASSOCIATION
1979 Beluga
1980
1981 Bernice Lake
1982 .
1984 Bernice Lake
(CEA)
C.C.
S.ex.!.
S.C.C.L
S.C.C.T.
S.C.C.T.
32,200(C)
100,000
18,000
100,000
18,.000
/
100,000
Bradley Lake
ALASKA POWER ADMINISTRATION (APA)
1985 Bradley Lake Hydro
NATIONAL DEFENSE
1985 Ft.Ri cha rdson and
Emendorf A.F.G.S.T.
1988 Fairbanks Combined S.T.
1990 Ft.Greely and
Clear A.F.B.S.T.
1991 Ft.Ri cha rdson and
Ernendorf A.F.B.S.T.,
1995 Ft.Greely and
Clean A.F.B .S.T.
70,000
T,300
14,000
32,000
42,500
24,500
.
(a)Unit #7 is a simple cycle combustion turbine unit which also supplies
exhaust heat to Unit-#6.
(b)This increase.reflects the increase in capacity 'resulting from the addition
of Unit:#T..
(e)Beluga.#9 is.a steam unit addition to Beluga #7 {converts these to a 100 MW
combined cycle unit}.
SOURCES:
1.1976 Power System Study,Chugach Electric Association,Inc.,Tippett and
Gee,Dallas,TX,pp.7 and 25,March 1976.
2.Electric Power in Alaska,1976-1995,ISER,University of Alaska,
pp.J.5.2-7.4,August 1976.
3.Alaska Power Administration,August 1978.
~o
Since a reserve margin effectively increases the amount of generating
r--ca'.Hyin place at any given time~it does contribute costs to the system.
Therefore~an excessive reserve margin is to be avoided while at the ~ame time
recognizing that an inadequate reserve margin could,on outage,result in a
wi de va ri ety of sad a1 cos ts.
For the purposes of this study,the Alaska Power Administration has
suggested that the analysis be based 6n reserve margins of 25%and 20%for non-
interconnected load centers and the interconnected systems~respectively.In
the future,a more refined analysis of the desired reserve margin appears'
warranted.
3.2.4 Transmission Losses
Transmission losses must be added to forecasts of peak and energy loads to
establish net capacity and energy at the plant substations.The Alaska Power
Administration expects losses as follows:
%
Capacity
Energy
5
1.5
The results of the load/resource analysis are thus in net deliverable capacity
and energy and do nc~include energy and capacity required for internal plant
operations.
The above losses are reasonably applicable for the independent operation.
of the load centers~for interconnected systems including the Upper Susitna
project and for configurations with future generation capacity additions being
distributed proportionally near the load centers.In the case of interconnec-
tion without Upper Susitna and with a tendency to centralize Rai1be1t thermal
generation,the transmission losses may be considerably higher as discussed
later in Section 3.2.8.
3.2.5 Construct~on Schedule Constraints
Due to the lead times necessary for the permit processes and construction,
generating unit and site selection must take place a number of years in advance
21
-------------,-~~-------r"'--,--
of the forecasted date when the units commercial operation will be required.
For coal-fired thermal plants,the Pacific Northwest Utilities Conference
Committee estimates a 62 month (5.2 years)period from final site selection to
commercial operation for plants in the 500 MW and higher range based on recent
U.S.experience.
Although individual thermal plant capacities appropriate to Alaska's loads
are somewhat smaller and may require less field erection work,the construction
season is shorter and the 5 to 6 year scheduling period appears reasonable.
For the potential Upper Susitna hydroelectric projects,the scale of
effort is more demanding and increased site evaluation is necessary.Current
understanding is that the Watana Dam and power plant could be brought to commer-
cial operation by 1994,followed by Devil Canyon no sooner than 1998.
A transmission interconnecti.on between Anchorage-Cook Inlet and Fairbanks-
Tanana"Valley could be brought into service prior to completion of Watana,
possibly as early as 1986.
The load/resource analysis technology recognizes the above schedule con-~
straints by not allowing callup of new generation or transmission'capacity that
could not be made available.
3.2.6 Plant Availability Constraints
Generating and transmission plant availability can be expressed in terms
of maximum and minimum plant utilization factors (PUF).These factors are
primarily dependent upon plant type and plant age.For purposes of this analy-
sis we have assumed the following economic facility lifetimes after which the
facility is retired from service.(l)
Years
Coal-Fired Thermal Generation 35
Oil-Fired Steam Generation 35
Gas-Fired Combustion Turbine 20
Oil-Fired Combustion Turbine 20
Hydroelectric Generation 50
(1)See Tables 3.4 and 3.5 for dates of expected retirements for existing
systems.
22
Due to the nature of the system,some plants could be retired from service
P17~to the expiration of their economic life.In actual practice,however,
it is expected that utilities may elect to retain the units on standby.In
order to assure their avai1ability in emergencies,the utilities vlil1 periodi-
cally operate the \.unitsto make sure they are in working condi tion.
Experience has shown that large thermal plants experience a learning curve
during the first few ye'ars of operation as IIbugs il are worked out.Once past
this period they reach a maxiTliumthat aliows for scheduled maintenance and
replacement conducted during the off-peak season.Toward the end of the
economic life,increased frequency and duration of outages for maintenance
usually occur and the maximum plant util ization facto-r decl i.f:1es.For purposes
of this analysis,we have assumed constraints on the maximum PUF for new coal-
fired steam electric plants as shown in Figure 3.4.
80
70
60a::o
I-u
~50
z:o.....
~40N.....
-I.....
I-
:::l 30
L-
Z:
~
-I
0.20
10
o
105a 15 20 25 30 35
PLANT AGE (YEARS)
FIGURE 3.4.Plant Utilization Factor versus Plant Age
23
-----.-.'----~i _,~------nv_m _
Other types of generating capacity are allowed to rUll at their maximum·
PUF frornthe start ..For ne\v capacity and most types of existing capacity,the
following maximum PUFs are assumed:
Maximum Plant
Utilization (%)
Hydro 50.0
Steam Electric 75.0
Combustion Turbine 50.0
Diesel 10.0
Hydroelectric generation systems,as a result of their storage ability
and conservative ratings,can make additional power available for ·peaking and
it is assumed they can be scheduled at 115%of design capacity for this
service.
As pointed out earlier in Section 3.1,the p~ak demand during the winter
usually determines the amount of generating capacity required rather than the
annual ~nergy.Because of this,some generating units are utilized at less
than their maximum annual plant utilization factors.The decision as to·which
units should not be loaded is usually based on the margin cost of operating
the facilities.In this analysis it is assumed that diesel capacity has the
highest margin operating cost followed by combustion turbines,steam turbines
and hydroelectric capacity in that order.It is assumed that diesel PUFs can
be reduced to O~O while the PUFs for combustion turbine and steam electric
capacity is not allowed to go below 10%.
Transmission plant availability is generally not as schedule constrained
as are generating p~ants with their long lead times.For purposes of these
analyses,the interconnection between the Anchorage-Cook Inlet area and the
Fairbanks-Tanana Valley area will be provided 3 years before the completion of
the Watana dam or when the Healy 1 (existing 25 MW)and Healy 2 (planned
100 MW net)plants become fully loaded.whichever occurs first.(2)This
assump~ion in effect places oil-fired plants serving the area on standby after
that date.
(2)It wilT probably be desirable to provide at least a portion of the inter-
connection prior to Watana date on-line as a source of power for
construction.
24
~1
~.•
1.2.7 Economic Generating Unit Size
The selection of optimum generating size c~n be a complex process involv-
ing uncertain assumptions regarding probability of future load growth paths,
desirability of sizing individual units in comp'1rable sizes and types for each
of maintenance,assuring that system reliabili+y is not penalized by addition
of too large a single unit,smoothing of construction schedules for possible
multiunit plants,and maintaining as small as possible departure from the
desired rel iability margin.A fun optimization does not appear warranted
thi's stage and is beyond the scope of this analysis.
Thus for the purposes of thi s <:"':udy,the fi rs t six coa I-fi red steam
electric.plants in the Fairbanks ;Inana Valley area are assumed to be 100:MW
units.Any additional units are assumed to be 200 MW units.In the Anchorage-,
Cook Inlet area the first five coal-fired steam electric plants are assumed to
be.200 MW units,while any additional plants are assumed to be 400 MW units.
These size ranges,though probably not exact optimums,appear reasonable block
sizes for introduction and typically become fully loaded at about 10%of plant
;r-:-1 He.
3.3 SYSTtM CONFIGURATIONS:DEFINITION OF CASES ANALYZED
3.3.1 Cas e -!Without Interconnection and Without Upper Susitna Project
The base case consists of power supply to the Anchorage-Cook Inlet and
Fairbanks-Tanana Valley on a noninterconnected basis.In this instance,no
power is available from the Upper Susitna project.
Future capacity additions.for the Anchorage-Cook Inl et load center are
assumed to be.near-mine,..mouth coal-fired units located on the ..../est side of Cook
Inlet-with a,nominal 50-mile transmission distance using two 345 kV circuits
with a capacit.:r of 1600 MW.Capital cost of this transmission system is
$228 million in October 1978 prices~
Further capacity additions for the Fai rbanks-Tanana Vall ey load center are
assumed to be coal-fired units with a nominal lOO-mile transmission distance.
The'Healy site is used as a proxy recognizing,however,that the Prevention of
Significant Deterioration (PSD)provisions of the Clean Air Act may preclude
25
Advantages
a)Lower capital and operating costs for generation.
b}Econom;es of scale can be achi eved;
c)Siting problems in the interior may be avoided.
Disadvantages
a)Higher transmission losses (and costs)are incurred for the fractipn of
power fl owi ng to the Fa i rbanks-Tanana Va 11 ey load center.These costs
may cancel out savings from the advantages.
b}The latter area becomes strongly dependent upon reliability of the
transmission system--possibly to the point of requiring a second cir
cui t or maintenance of additional standby combustion turbine capacity.
c}Any actverse.environmental effects are borne by a single area notneces
sariTy bene.fiti ng in proporti on.
Z.Coal Plants Sited in Proportion to Relative Load Growth {Distributed
Siti!!g}.
3.3.2 Case 2:With Interconnection,Without Upper Susitna Project
In the case of an interconnected system without;the Upper Susitna project·
._.'c,·i<"J C:E;X~~~0~~1
and all new capacity coal fired,the load/r~source analysis is not as straight:-
forwar~.in that it is not readily apparent what strategy for siting plants
shoul d be foll owed.Two primary options are apparent:
1..All coal plants sited ata single location{T)(Concentrated Siting).,
the siting of additional plants beyond the planned Healy 2 100 MW unit.A
230 kV single circuit will transmit up to 400 MW and a 230 kV double c.ircuit,
800 MW.Capital costs are $44 million and $70 million,respectively.
Table 3.9 provides a summary of the transmission system alternatives.A map of
the Railbelt region showing the Watana and Devil Canyon dam sites~a possible
route for the interconnection,and the Beluga area is presented in Figure 3.5.
(1)For the purposes of this analysis~mine~mouth location at Beluga is used-as ~~,
a proxy.
26
'))
TAIlLE 3.9.Transrni ssion Sy~tem AlterrHlti V~$(l)
Approx .
Capad ty .Capa~i ty Investment
Location Ci rcul t t'lW loss,%Cost --.J!1r1 $/kW--,.,
Isolated Load Centers
He~ly -Fairpank$
100 mil es 230 kV Single·400 6 44 110
230 kV Double 800 6 70 88
Beluga -AnchQrage
100 mil es 345 kV Single 400 114 285
800 114 142
N Two 345 kV Single 800 228 285
"-.j 1600 228 142
Interconnected WithoutSusitna
Anchorage -He~lY
200 miles 230 kV Single 200 6 .88 293
300 8 88 225
345 kV Single 400 3 228 570
560 5 228 407
Interconnection With Susitna 1573(2)5·471 .(299 )
(1)Source:Alaska power Administrat on
(2)Actual peak power availabilHy co ld be about 15%higher Qr 18Q8 MW,
ALASKA POWe:R ADMINISTRATION
o
SCALE:
/
iOOIWiles
FIGURE 3.5.Railbelt Region ShO\'ling the Watana and Devil Canyon
Damsites,a Possible Route for the Interconnection,
and the Beluga Area
28
Advantages
Siting problems rel ated
tne latter a.rea.
a)
b)Generation costs in the Fairbanks-Tanana·Valley
a)The interconnection becomes lightly loaded,thus reducing transmission
losses to some degree although charging losses would continue.
b)Transmi S5 i on i nterconnecti on rel i abil ity dependence is reduced as the
intertie assumes more o.f a capacity reserve characteristic.
c)Environmental burdens are distributed,possibly with more equity.
In this report.coal plants are assumed to be sited in proportion to the
relative,load growths of the two load centers.As with Case 1,additional
coal-fired generating units are sited at Beluga to serve the Anchorage-Cook
Inlet area and at HealyjNenana to serve the Fairbanks-Tanana Valley areas.
The transmission interconnection is used for capacity reserve allowing
the reserve fi1'i.rgin for both load centers to be reduced from 25%to 20%(see
Section 3.2.3 Under this scenario there is no net energy transfer during
any single year.If one load center is low on capacity the other load center
provides the additional capacity required assuming it has a surplus.If no
surplus exists the original load center must add capacity.
The interconnection is assumed to be brought on line in the same year as
the Healy 2 coaT plant becomes .fully loaded and new generating capacity would
be:required in the Fairbanks-Tanana Vaney area.Addition of the interconnec-
tion allows the.Fairbanks-Tanana,Vaney area to ge.t capacity reserve from the:
Anchorage-Cook InTet Area.This allows the Fairbanks area to postpone the
construction of additional capacity by 2 to 6 years depending upon the
scenario.
In the high 10acLgrowth case the interconnection would be completed in
1986,in the medium load growth case it would come on line in 1989,and in the
r<"...;I;,oW load growth case it would come on line in 1994-.In all cases 45%of the
cost of the interconnection is assigned to the Fairbanks-Tanana Valley load
center.
--------------~-----
3.3.3 Case 3:Interconnected'System With Upper Susitna Project
In addition to the interconnection described in the previous section,
Case 3 includes two hydroelectric generating facilities.The Watana dam is
schedul ed to come on 1 ine in 1994.The date';s assumed to be the same for all
three load growth scenarios.The Devil Canyon dam is assumed to come on line.
as soon as required following 1994 but nat before 1998.It is assumed it
would take at least 4 years to complete the Devil Canyon dam following comple-
tion of the Watana dam.It turns aut that the Devil Canyon dam is required in
1998 in the medium of high load growth scenarios but not until 1999 in the low
load growth scenario,
Because of reservoir fiTling requirements it is assumed that both dam~.
will take 2 y~ars to reach full capacity and power output.The capacities,«.:i/i:\:;j:?~
power production and plant utilization factors for the two dams 'are show below .
.Watana
Capacity Energy Util i za ti on
Year (MW)(MMkWh)(%)
703 3080 50.0
2+795 3480 50.0
Devil Canyon
1 689 3020 50.0
2~778 3410 50.0
For the medium and high load growth the transmission interconnection~is
assumed to come on line in 1989 and 1986 respectiveTy~the same years as for
case:.2_In the low load growth scenario the interconnection comes on Tine in
1991 rather-than 1994.This earlier cempl etion date wiTl anow the Watana dam
construction site to besuppTied with power from either the Anchorage-Cook
Inlet area or the Fairbanks-Tanana Valley area.
The power output of the two dams is divided between the two load centers
in proportion to the;r relative energy consumption in 1994.This resul ts in
the percentage divisions shown below.
30
!,Load Growth
,Scenario
Anchorage-
Cook Inl et
Fairbanks-
Tanana Valley
Low
Medium
High
80%'
81%
84%
20%
19%
16%
3.4 RESULTS OF LOAD/RESOURCE ANALYSES
An additional generating capacity beyond utility plans assumed to be
coal-fired steam turbines including a transmission interconnection.
An additional generating capacity beyond utility plans assumed to
be coal-fired steam turbines without a transmission interconnection
between the Anchorage-Cook fnlet area and the Fairbanks-Tanana Valley .
.area load centers.
Case 1
Case 2
Using the methodology outlined in Section 3.1 and the assumptions
explained tnSection 3.2,a series of load/resource analyses were
As poi.nted out earlier,three basic cases were evaluated:
Case 3 All additional generating capacity beyond util ity plans assumed to be
coal-fired steam turbines but including the Upper'Susitna project
(in:1uding a transmission intertie)coming on line in 1994.
For each ",f these three cases.Three load growth scenarios (low,medium
and high)are evaluated resulting in a total of nine load/resource.analyses.
The assumptions discussed in this chapter are incorporated in a computer
model called AEPMOD.The output of AEPMOD for Case 3 assuming the medium load
growth scenario is presented in Table 3.10.The results of an nine cases,are.
presented in Appendix c~The AEPMOD computer code is presented in Appendix B
and the data base necessary to make the runs is presented in Appendix A.
The capacity additions called up in the various cases are presented in
Tables 3.11,3.12 and.3.13 .
.The results of the runs are summarized in Figures 3.6 through 3.11.
"""-I
31
'-
PEAK --PEAK LOAO/G£N£~ATIM~CAPACITY ~tYUIR~~ENTS(MEGA~ATTS)
Io'f'llF --MAX1l'~UM PLA>j1 liT LLIZATlON FACTOR
"'!"til'-ACTuAL PLA;~l \JTLLLZATlOIII fACTOtj
ENERGY --GEN~~~TION/.N~U.L EWEKGY KEQUI~tMENTS{MILLI0N~OF KILu~ATT-HUU~~)
32
'TABLE 3.10 •
...tA:~.I"~.I"'S
FAl~8ANA5 C~Se:2 --~EaIUM LOAO GROWTH
Wre.~11t n.R:1'1"0.
NOfES:UtC.o.191~~I U.5.-I~'.'
(contd)
C R 1 rIC A l.~ERII)D
1 1"'>l-1'I7"i 1 1 '17'1-1 '..Iv 1 1~~~-1"81
1 "F.A~MPUF M'uF E~.ERG(1 "€U ,",puF APuF ENERGY 1 f';:AK '""uF A"uF Ei\;Etlb(
1------·._-.---.1------------.-1------_.------
---------------/1 I
i-:E\:iiLlrJ.it~~N rs I 11:1'1.80/;.I 1'l7.!Ie2.I 20'l.'He.
---------------1 ....I I
"'1:~nu ..CF.5 /I.I
f:11;,r 1'.(0 I I I
"Yul<ll 1 o..50 .50 O.I O..511 .50 U.1 O..50 .50 0_.
:;rl:.A',,/ELEC I 110.,1'5 •co 033.I 110..7~.72 b'l~.I 1\0 •.7':>.1 ~7c!3.
Cu·Mo.rl'~o [i..E.I 209.•50 .10 l!l~.I .:!09 •..~O •10 \llS_I 20'1 •.50 .11 207 •
UllO~El.I Qa_.10 .00 il.I Qo..10 .uo U.I II;'..111 .110 <I.•
//I
TIl r AI-I 305.II 1"•.I 305.<175.I 31>5.'l3u.
1 I I
AlJUITI'1.'.S I I I
';(UII'j I I I
.'Hi·M/Ft.£C I I I
c.(J.;~..TtlRoINE I I I
:;n.SEL I I I
I I I
HET l"ii~'f:'.TS I I I
t'l'fi,iRi,J I I I
::'IL":~/r:LEr::I I I
co ...,TIl"'';H.F f I I
llIE::.EL I I I
f I I
---------------/I I
10 ..05:;fiE 5fJ,jWC E 5 I 30':\•.all>.I 305.,il7'S .'I 30'.:l.930 •.
I I I
CA;.o "ts."Al<.GIrU o.'l>lJ I O.Ii'.:l2 I Q.1QII
r'"I I I
';E:iE"lJ€.RE').I QQ.I 1I'l.I 52.
I I I
L[j:'S~.::'I ".12.I 10.I j •.I 10.1 ~.
I I I
"Ei kJ;:SDUl'lCE5 I .HlI.80tl./301<•BoO!.I 302.91b.
I I I
i ;I.·.~FE"EO I u.I O.I O.
I I I
I I ,
SUwPL.uS I 12b.ll.I 10'1_O.I 93.O.
PEAl<Pf:"",LO"U/GEN~tlAr!I;G CAPAC t TT ~E~UlwEMENT5(MEGA~ArTS)
,~II'tIF MAllMUM i'L.ANr UTlLHATIUN FACTUR
AI-UF ACTUAl."'LANT lJ IILl ZA HUN FAcrojoj
ENERGY --GEN~~ATION/.NNUAI.EI~EFtGY kEuuIHEHENT5(MILLIDNS OF l(IL.0 1'1 A TT -HOURS)
33
TABLE 3.10.(contd)
Af<f":Ar.C"O"A ..e:
ANr."nf<Af.1'c ..:n:<I --"EIJ!I)'"LOA{J GIlII"T"~
I'.rEII r I~TE ..II :1'1'10.I
"OTES:D~C.b,1'176 ,0 U.~.-l'j'l'l.
C >l I T I C A L.?..>l I 1.1 lj---------------_._--------------------------------------------'--.._------------------_._----
/ICJ ..l-l'18~/l'Itl~-lCJa3 I 1.'1<13-1 CJllol
/PEA~,"'PuF APuF E....€>lG·Y /PEA ..."'''tJF A..uF EfoC:>lGY I PEAK ,"PUF A"UF ENF.>lGJ/--------'------/--------._----1---------------------------1 /I
"EIJU.J.lE ~.i.T3 /741 •3~81./7'15.3'>cl./lISO..311l1 •
---------------1 //
itE~Ou~CES /.//
Exr:>Tl(;',///
';Y;.I>10 /'53..~O •50 20il •/5~..50 .50 cOli.I 53..50 .50 20"•
STii"IIEI.EC I Sl..7'3 •75 ~32 •/51..•75 .75 H2.I 251..TS .4<'123.
CUH~.rll""lN€/7~'1..:'/l •jCJ a71 "•/1l07..50 •.sc aasu./1l'l1..50 .J5 cD';I.~
UI!:.SEL I lr..15 .00 (I./17..1'>.00 0./l'5..15 .00 O.
///
TorA\.I '110.3251./Q28.2/85./1210.31117.
///
100111'"),,5 I I /
"YIJI",///
SH.',~/fL~C I /200..7'>.<21l 350.I
C'lhd.rU>I';I PI!;:/1tl..50 .50 19./tOo..50 .5.0 438./
,vll:SEI.I //....///
"E T I III:"E III TS ///
rl'rtJIoit)///
~TI:A"'/i:.l.EC ///
co ....~.rUjo("INt://15..00 .00 O./6..00 .DO O.
ulESEL //2..00 .00 O./•///\---------------///
(.~lJs!>;;EsnUHCEs,(928.3~311./1210."35H./1<202.31111.
///
CAP "1::5.:-IARG l:i/1j.25~/0.523 /0.41'1
///
...€:.Ei<VE·...E.u./~H~./19'1./au •
///
I..IJ5St.S I '3.1.4'1./411.51./41.1)0.
///
'.fl PlE.SOUl/eE5 I TO.,.leU./972.35e1../'147.,S7bl.
///
TRAfoSFE",Eli I -~I Q.I O.
///
J //
5 .....,.I..U~1 -3';.O./117 •O./'II.II.
~EAK PEAK 1..0AU/G~NE~ATING CAPACITY iolE~u!We.~e.NTS(MEGA"ATTS]
kPIiF MAXIMuM P1....NT UT!LIZAIIOI'l FACillW
APlJf ACTUAl."LANf U1ILlZATtiJI'<FACTU",
EHER!;"--GU"""A TIUIIlIANNUAl.,.U;EWGY kEIJUIREHl;:N fS (~II,I.IU;'lS OF K lLO.....TT-...OUw$)
34
PEAK Pl:.u LOALl/GEN,,;:U Tl~G-C-APAC-{I f -io/""UIWl:.;~i:IH:;.(...eGA .....-r TSJ-
M~VF MAX!~UM P~A~T ~rIL1ZATION FACTO>!
A~uF ACTuiL PLANT UTILIZATION FACTOio/
Ek£wGY --GtNt~ATION/ANi'UAL £~tftGl ~EUU!>!lMtNI5(MILL10~S OF KILowATT-~uu~~J
35
-------------------,-------'------~
TABLE 3.10.(contd)
.~<:~:""CHOI/AGE I~."c"o".,,<:CA[>l:.:a --"""luM L.IJAU G~UWTH
I,'dEIH H.tf..tR:I 'I'll).
/iOTES:OfC.b.1'176 "I U.5.-19'l4.
C II I T I C A L.P E Ij I 0 [)
--------.------------------------~-------------.-----------------------------------------I 19<14-19015 I l'la~-1'l8b I 1'ld&-I 'ill 11PEA,(HPuF APuF EN£~i;y I PEAK H"UF'APuF EN£IIGY I PE4K H'-Ill"AI'uF E"~EIlr,y
1-------_._-_.--1------.------1--------.-----
---------------1 I I
"f'lIJ l~t."E,.rs I '10".4001.I Hb.4329.I 10'1<1.IIb57.
---------------1 I I
~E,;("J ..CE S I I I
tq::'II'li.I I I
Ii v lJ'ct}I 'i$.•~O .50 i!1I11.I 5~•.:;11 .~o 204.I 13li..5U .50 510.
~TEA"tEl,.E C I ~.';I ••/5 .53'11104.I a',H..75 •1>4 I"U5 •t '1';<:1..75 .:;0 22':1'1 •
CO;·l"•.TllHI;tr.E I ~I>j.•~o •.)'1 21>15.1 ~Hlt,..51l .28 2111,.I e5';..511 .~&1956 •
t11~5EI.t 1'5..15 .1)0 I).I IS..15 •()(I I).I 5..IS .110 I)•
I I I
10rAI.I 12Q2.~,*1l2.I 1205.37211.I lli52.'1721.
I I I
Avli IT!0,,1 I I I
HYLJkl!I I !II..~o •50 307 •t
STl:.AM/fLl::C I I 201.•75 .20 31>3 •I
co",,.:rulIt!WE I 1>1..';0 ,.50 79.I I
D H SEl.I I I
I I t
~t.T PIE','€;"r S t I I
I1YU"O I I t
:.J Ii:Aj:,.L/E.LiC I I t
CO"'~.ru~"rr'E t 15..00 .1I0 II.I 31..110 .QO 1I.t
uIESEL.I t 10..00 .00 O.t
//I
---------------///
(olIOS;,"'e;S!lU~l:fSI 12GS.40&1.I 1452'_4394./l'lsa.4127.
t /I
CAl'"e:s •.~ARG 11<1 0.353 I O.lI811 /G.3as
I I /
~ESF."w€.j.(E:~./22b.I 2l14./2b2.
//I
LOSSeS t ll~.b/J •I ~q.&5.I 52.10.
///~,I.e i "e.SOuI{CES /'Hli.lI00t./11 Sq.4329./lljd.4b51.
I I /
iR ..hSFEREil I 1>.I G'.,I Il.
I //
I I 1
SuRFLuS I 30.o.I 183.Q./90.II.
PEAK PI:A"L.O.O/GENERA [lNGC"PAC I TV ~El.IlJl11E"'€fj·TS (I<'E'GA'"TT::l1
MPllF MAlllMu~PLAi.,UIILIZAOt.N FACiUII
..PIIF ACTUAL I'I.ANf uTIL.HAnONh"fi;'f~·
ENl:RGY --GENEiUTlON/4"HUAL ENERGYllEOUlilE1'ti'.NTS{Mll.LIONS OF ~ILo ....n-I1IlU~_
36
TABLE 3.10.(contd)
I"'E A;F A I"IlAtjl<~
FAIk01Ar."S CASt:.2 --1'lEDIUM 1.0AD GRl".TM
INTEr/TIE rEA":!940.
NiJH.S:OfC.o.197il "I U.S.-19'l1l.
C R I 'T'1 C A L ~E "I U 0----_..._---.------------...---------------------------------------------~-------------------
I 1'1<l4-1'1!l~I I 'H'~-I'l<l"J 1"~t>-1'I,,1
I PEAl<MPUF APuF fNEiH,Y I P!;.AK "PUI'AI'I;F ENERGy I 1'£101<1'110'1;1'"APuF c;''''f~~'f
1-------------1------.--.-...--J-------------
---------------1 I J
"i::o;UI"'t:."fAfS I 258.1132.I 272.11'13.J 2<1&.12,4.
---------------1 I I
"'E~;Jd~CES.I I I
L<l~r PH.//I
Hr"iolu J u..~O .~o u.I (I..5~.5Q 0.I u..:.u .:'0 0.
:>leA'~/EI.EC I llO..75 ./5·72!..I HO..7S •75 123.I 21u •.7S .55 101<1.
CO'-d.TufllHNE I 2~4..50 .24 "20.I 2(,4..50 •teo 313.I 20"..50 .1 ~c'H.
li1fSe.1.I 46..10 .00 O.I :.!l.• I \I .00 0.I <12..10 .tlO U.
I I I
IflTAI.I 300.114'1.I 330 •.1030.I 43&.1273.
I I I
l!JUI r 10,'5 /I I
nYu":,I I I
:'ltA ./ELEC /I 100..7~•.20 17.,•I
CU-·Ui.fUf.l1-i I HE I I I
DIESEl.I I I
I I I
,,£11kE"'I:...r5 I I I
rifl"jt:C'tj 1 I 1
STEAHELEC /I I
.:0'.01.ruiolu I:,E I I 1
UH.;;"1.I 2'1..00 .00 0.-.I I
/I I
---------------1 I I
~RO~~IoIE:>OU"CE~/.531>•.11<19.I''131>•.1211./'130.l.e1J.
/I I
ColI'wE:;..URI;lit/(J.300 I o ./Jv l I v.523r'./I I
'lESERVE MErl •.I "5.I bil.I 72.
/I I
,-OSSES I l.5.17.I 1'1.1 ~./14.I II.
I I /
"'€T So:ESillJi<CES /~58.1132.I 35'1.11 'i3./350.1<1511.
I I I
.OUt·I:>F€"t:1J /0 •.I U.I O.
I I I
I I 1
SURPl.US I u.0.I Si!.0.I bll.tI.
PEAK
Mll>uF
~I'UI'
E:.fItGY
P~AK LOAO/GEN£~.lTl~G C~PACITY ItEQuIHE~INTS{MES.lhATTS)
M.~IMUM PLANT UTILIZArIUN FACTO~
ACTUAL ~L.NT uTILIZArlUN FAC1U~
--G~NtRATlaN/AHNUAL ENEHGY HEQUIHI~~NT5(~lLLIONS OF KtLu~ATT-"OUHSl
37
TABLE 3.10.
~~EA:A.C~OkA'E·
ANC~*~bl CAS~:~--MEUIUM LUAU G~owTH
I~TEHTIE YEAR:l'l~U.
WUTES:otC.b.197~~I U.S.-19'l'l.
(contd)
C k 1 rIC ...L P E fj 100
----------------------_...---------------------------------------------------------------
I 19i:l7-1'l88 1'.188-1989 1 j'ld'i-I'lq"
1 I'~A~""til'A~U"ENEItGl 1041"1)1'APIlF "NlOlitH J ?\:.h MPUF ...iOUF C.'l~"t,;Y1------"--------_.-------.---1--------------
---------------1 /
"t.'JlH~E"ENrS I I 1.i!1k.'1985.1l9c!.~.H 3./1.i!1I1i.5"41 •.
-------------/I
,IlE;;Ou.cCE5 I I
E~1::1 II.;'""/.
"·YOl<,,,,I~I1.1311.:.~'}.sa SlQ.J 13'1..~()
::iJtA"t/i:l.EC F 45/1 •.&43.•7~.~8 32S".I ,,43 •.75/'C Q',.loi·.1"11 ..os £lIE /"S'='.855.·.Su·.23 1,,28.{791..':lu,.".U:S£!;../-5'.5.,·.15 .00·II.I ~'-.15
I I
lOU,-I 53'B.I 1573.,I
~ul>1T 1Uus I 1
rtTr..I1G '1 I
:>TI:.A:~/I:L£C,I I
ell.....II Il<K ltl£./r
I1f':'S!1-.I I
I I
;/0.Tll<E;'1Erlt:;I r
t't't1J'ciJ I I
STc:....,/EUC I 15..,,0'.00'.0.,.I
CO"';.Tll""INE I &4_.00 .00 0 •.I
uH.St~,J
/.J---------------1 I
;r,IlUS.,>lESIJIlItCES/Ibn.5QbO'••1573.,53'13.1 1573.
//
CAP I<e5.,i'lA;,GINI CJ ...loc-0.320 I 0.245
/I
,<ei:lE"'o'e '''Et.•.I 26 4'._.298 ••1 253.
I I
.LO:iSfS I S&.7S.,bU •.50 •.I b3.~.,.
I I
,jET "IEsouIolCES I 1301.ll'leS.,.121b.53U.1 12~7.5&'11.
//
TR ...,,:;FERf.:J I 0'_ll •.I 7.
/I
I I
SUi/PLUS /1~1..:I •.2".G•/Q.G.
PEAK P~A~LOAO/GENE>lAT!NG CAPACITY liE~oIREME~TS(MeGAwArT51
MPUF --MAXIMuM PLAWT UTILIZATION FACTOR
...PIlF --A'TUAL Pl.ANT UTILllAT10Jli FACTul<
(l'j(ltGY --Gc."~R·ArzO"'/ANr.UAL.E"Ehin ~eQuIHEMENTS(M11.1.!ONS OF KILOwArT-ttOUi/SI
&$
38
TABLE 3.10.(contd)
AHEA~FAr-<IlAN"S
FAtHR"J><"S CASE:2 --MEDIUM LO"O GROOilTW •
r,~TE.1oI1 II:TEA~:1'1'10 •.
~uTES:O~C.c.1~/b ~I U.5.-l9'/4.
C R I TIC A L.?E Il 100
o.
ENEioI(il
l'H19-l99il
",PuF VuF
I
ENEIlGl 1 PEA'"--------1------
I
1.UI>.I
I
I".'"/
J
I
/
/.
1312 •.•I
I
I
I'
I
I
I
I·
I
I
II.I
I
0 •.I,.
I
1397..I .'4 \'h..
I
I 1I •.!1T
I
I b&.·
I
21 •.I lb •.
I
U7b.I .D7.
J
I -1."...
I
I
Q ..I .!..
.OQ.:.00
19l:ld-l9l:l'l
MPuF APIJi'
0 ..
ttl,.
325.
o.
1$35 •.
1315 •.
I
EUER~f I POI<--------1------
I
1315.I 31'1.
I
I':.
I
I
I
lqb~.F
0 •.•/
I
U35~I'
19c7-l'1/l/l
",PuF "put"
75 ...·
I).:
21u.
iOQ ..
22 •.
5Ui<i'l.tlS
RefIll!:"1E'n S.·
"-''':;J~i).
S !~A'~/EI..EC·
CUMil.!IJi<rl INE
II TESE\.;
L.OSSES
I
I PEAl<1---------------------1~~U~l~!~E~rS I 300.-------·_------1
"e:StJ"ilCE$·I
e:U~n.NG-I'
;:ii~~~~/rL"c ~
Cn~.!1·.,.njHbI NE I
Oll:.SE:1..r
r
I '13 .....
I
It/flH rONS.I
·.,,,v""Q.·.I
.$,Tb'""'/EJ..U;.I
c.o;o.,.b--..rU"~rNE.,r
Ulr5E\.;I
I'
I
I
I
J'.
I
I---------------1("llilSS-..<e::,uUiiCESI '131:1.
I
/""""'.eJ.;>~t:S·..I4A~GH.I O.'1':lo!
I
I
I'
J
I
NE T ~FSOljIiCES.I
I
I
I
I
I
PEAK --PEAK LOAD/GENEi<ATING CAPACITY i<EQUIIlEMeNTS(MEG"~ArTs)
,",PUF·--MAXIMU,.Pl.Al\IT UTILIZ"TION FACTO"
A"UF .-.ACTUAl.PLUIT UT ILIlAflUr.FAI.TO>l
E"'E~Gf --GeNt:.kA TiONI ANNUAL EhErlGY REf.ll.lREMENTS (11 11.1.IONS OF I<Il.OIIIA fl-HQuOlSI
39
~\
TABLE 3.10.(contd)
~",EA:'••C110><~"f
~"ie110RAGE C~~"":2 --!olED tUM LUAU GRU"TH
P<TE~TIl:.YE~R:1'1"0.
"uT~s:or;;c.b,1'I7~"I U.5.-I'/';'1.
c ..I T I C A L.P E R I 0 0-------------------.._-----------_._--------------------------------~------------~--------I 1 '1'10-1'1'll /1"'1I-I'1'1~/19'i2-1'i'U
/PE~""'l"uF ."UF E;~EI<GY /PEAK MPuF A?UF ENE>lGY /PEAK /,\puF APUF ENERGY/----------_..-/--------------/------.-----......
---------------//I
nt:·uld~e:M€~.r$/1351.bye3./1115Y.o"d~.I 15'13."'l07.
---------------//I
kE~OoJ"CE5 ,//
EJI:.iTING I //
1"t11JktJ I 13'1..50 •50 Sill •/134..50 •50 '310.I 13<1 •.:'0 •50 510 •
SIEA·.,EL£C I bll~..15 •71 3'1<1b_/8'13 •.1'5 .&5 4'55~./10'15.•15 .5b 51110 •
efJ"'....TU><flINF:I 7'11..50 •1'1 1 'SO!!.I 1'11 ••50 .il,10'15.,773 •.50 •10 b3U1 •
ull:.Z:lEI./5.•15 •nll o•/5 •.15 .00 O./3..15 •00 Q•
I I /
TO TAI../157.5_5804./17n.0157./1"1';5.&311l •.
//,
AI)OlTliJ"S ///
H'I'Uj.;'(;///
STc.A"',ELEC I ~O".•75 •.2U 350 •I .2'13 • •75 •.20 4.25./400 ••75 •.20 101 •co.".TU""I',E /I /
Ult-SEL ///
I //
;jETll'l ..·.Eo;TS I I I
JotYUHi]I I I
~Ti."'/FLtC I /'II..oa .00 Il.I
(.[J'H••lu"!'II'!,//II:!..00 •00 II.I ':ill •.00 .YQ 0.
DIE::>EL /I 2._.00 .CiO fl./
/I I ~---------------/I /
GRClS ..><ESOUWCE:;I 1773.&154.I 195'5.&5il2./230b.7011 ..
///
CAP',;ES~MAIIl;UU fl.JU7 /0.349 I ~.~94
///
"'::~E,,\I~REa.I 271.I .290./30'1.
I I /
"(J:lsc:s /b ...'11./73.97./77.1 \/'1.
I //
~.E:r "<.50IJ",C£::'I 143'1.&Ob3.I 1593.0'18'5.I l'12U.b907.
///
r;IAN:lFEH'E~/~./-<'I.I -d...
I I I
I /I
SUI<PLUS /77.,O.I 114.O.I 211'1.0 ..
'tA~'i.~LOAO/GiNERATINi CA'.CITY kEQUIR£~ENTS(MEGA~ATTS)
l.lilllF 'U~I"'lJH PLAiH UTIL.ILHION .~CTUI<
Ali'UF ACTUAL p~,~r uTIL.IlATIUN F~CTU~
ENERGY --GENlRATIO~/'~hUAI..E~fRGY REaUIREHENTS(MI~~IONS 01"KI~O~ArT-HOUWSJ
TABLE 3.10.
A~E":FAp"HAN~S
FAIwH4NKS CASt:2 --~EOIUM LOAD GROWTH
IhTERTIE IEIW:1990.
NUTES:UEC.b.1976 N/U.S.-199Q.
(contd)
C ..I T rCA L f'E R I cl 0
.50 •50 O•
.7'5 •bB lcll3.
•511 .IB 313 •
•111 .00 \/.
1591.
.5v .50 {I.
.1':1 .71 1359 •
.50 .23 327.
.10 .VO (I •
I !lee.
/19"0-IQQl /
/I'EAI'\....PUF ..PuF E;,,,1<6l /I'EAlI/------------J---------------------//
I<E\'Ur~E·~ENlS /343.1505./358.
---------------//
,><E ;;()UPCES //
eI.I~rl'lI.//
>HUI<U /IJ..50 .:i0 ,O.,o.
SlEA"i/t:":L,EC /21b.•/5 ./3 11701 •,211>.
CO"'o •.TtJR6Ii,E·/20 ....•50 .17 300.,204 •
(l1l:SEL•./IJ.•iO .DD D•./D.
//
TOUL /41"1.1472./419.
/,
lUll r 111Jr.3 //
"YoJ)/O I I
~It ".'IIELEC I 3<!..15 .20 51>•./
t.'j;-'>I.1IJIIH INf:I /
I.:ItS€L I I
I I
1<t r IIH.MI:.N I 3 I I
hV()i><1 I I
::.rE"'~If LEe /32..00 .00 O.I
CU.1Fi.TlJi'lIl1 TN£.I /
~lI:SEL I I
I
::--------------1 ,
",HUSS.·"IESlJUI(CESI Q 1 <~•.15~!f•.I 41q ._
I I
.'-'p...l<E:i."'''RlOIN'u.222 I 0.1.10
I I
:iESf"ve:..Ea.I 69.I 72.
I I
kOSSE:;I 1 7 •23.I 18.
I I
'J!::T ,.jESOiJIICES I 333.1505.I 330.
I I
1.10 41.,:,1<f.III:U I ).,I 29.
I I
/I
S'JIlPLUS·/-Iu •.O./O.
19'11-1992 /
~PUF APuF ENE"GY I PEAlI--------,;.-----
I
1573.I 374.
I
I
I
I O.
I 2U••
I 0204.
I O.
I
I 419.
I
I
I
I
/
I
/
I
I
I
/4(1.
I
I
I
15'H./H'I.
I
I 110013
I
I 1'5.
/
24./19.
/
1'513.I 286.
/
I ~'1.
I
I
O.I u.
lqq2-19q3
""uF A?UF
_I,IU .uo
1;'41.
\/.
v.
PEAIl,--PEA ..L.OAU/GEI>;.iRA n-.lO CAPACITY i«Eill)IiiE~,EI'iTS(MEGA ..ATT S ~
M~UF --~~xrMUM t>LANT UIILIZATIUN FAcrUN
APUF --ACTuA~,PLANr UTILLZATION 'ACTuN
E!.EPiGf --GENl:.K.l.T IONI AtlkUAI.ENERGY HEQUIREMEJli-lS lMILUOIiS iJ,i'"KILOI'lA TT-huUI<lSl
41
_~"'l~~=--,-------.---------------------------------------------
~I
TABLE 3.10.(cantd)
A~EA:A~'CMOl<A6E
A,;C ...fH~A&E CASt.:a --r~EOIUH LOAD GHuVI!H
I ..rE~rh TE .,1:1'l~U.
NuTE5:IJc.C.b,1918 "'J U.S.-199<1.
C H I T I C "L.P E H·1 0 D-----------------------------------------------------------------------------------------
J 1'193-19'14 J 19'14-1995 J 19'1S-19'lb
1 PEA",",PUF APlJl'EI;E"'liT 1 PEAK "PilI'"PilI'ENElilir I P~AK "'>'uF ""UF t.NEl<Gr
1-----------~--1------·--------1-.;------------
---------------1 I I
l'CE.i.i1f1~e.'_1~~f3 I 11>3:,.132'1.J 1129.1151.I 1,,'5<1.831 1.
---------------1 J I
~E ~Ou"1CE5 I 1 J
E~I::.TI·;t>I J J
..ru"fJ I 13<1..~Q .~O ~l<I.I 13<1..511 .50 '510.J 7"'lc.•';iQ .50 jOl':>•
"reA·.../f"LC.C J IIl<l')..1'5 .~II j,j4j.I 14"5..75 .34 Q~oa.I 14<1~.•75 .3&"''''1'''•C;J'lB.iURS IhE 1 12"..5G .10 'Soo •.I bo'!.•50 .10 5Bb.I £Obit ••50 .10 417 •
!I rE·~"L J 3..15 •0"o./:)..15 .00 o•1 3.•1'5 •till o•
I J 1
TOTAL I 23Gb.7"j'l.I 2251.531>Z.I a'HI9.·l>10b.
I J I
AvvLTI11I-l5 1 I J
l"'I'ftJk(J J.I 1>51>..~tI .':10 a5i1~.I 6o..50 ,':III .!z~.
STt,A;.</ELEC I I I
cu><".rU""'INE I I J
IIH:.S!:.1.r I'I
J I I
~ET1"E'1E.NT3 I J I
",Yu-..u·I 1 J
;;H....·I/E\.£C J J J
Cll';;".Tu ><"IN£I 55..uO .00 u..I J lZS •..00 .011 u_
II I~:;l:.1.1 I 1
I I I
--------.------J r I .~
"..os~~ES'lURCESI U'H.7439'~I Zq09·.IIH.]•J aIHI.8~~1>..
I I I
CAi'fte.s.lol.kGINI 0.37&J 0.682 I 0.548
J.:I 1
kE:>E",VE "El.i •.I 321_I jAb •..I 371_
J J I
l.iJS;;;t:s I l\Z.l1p.J Bb.Ill>.I 93.1;:5.
1 1 J
1<e T ;,tl:;:;OuRCES J 11\4~.73;:~.·J a41&.1751_J Z41l1.il311.
J 1 I
'l<Ari::'FE~E!J I -107.I o.J tI.
J I 1
J I I
SUi/PI.US J 9'1.o.J 747 •.G.J 553.Il.
PEAK P~AK I.UAO/GENEHATINli CA~ACl'Y HeQU1~EMt.Nli{~E~A"ArrS)
HP~F H.XIMUM PLANT UI~1.12ArIUN FACTUR
AIo'IIF ACTUA~Pl.A..oI'UT,IL.1ZATtUN FACTtlH
ENl:WG't --Go.Nl:.IoI ...TION/...NNUAI.EI'<El<IH ..€I1Ullil:;I'I!:....rs (I4ILI.10I'<S UF K II.OIOA rT-HHUHlIl
42
.,
TABLE 3.10.
_AREA:F~l"'flalllt:t
FAI~~.N~S CAS~:~--Mfulu~LUAU GNO~TH
I1HElilli:.H ••lt:1~'lQ.
NOTES:OeC.b,1~7&~I U.S.-l~~4.
(contd)
--------.---------------------------------------------------------------~--~-----~-------
I 19'13-19'1<1 ,199"-1~9'5 I 1995-199&
I P!:ArI ·'''UF A"'Ur EHEIIGr I PEAK /4P'jF Al'j,F Er.li.RIiT /P:'AK MPUF .?(jF ENt"1liY
1-------------,------...-------/--------------
---------------,I /
Hf.!-HJ 1 (,fe ....j:,,'~I ~,.S!l'l.17~'1 •I 'lOS.1771./".?3.Ib~'1.
---------------~I I
"E~uv ..CF.S 1 I 1
EJl::.IlV.1 //
"1l;;lfJ /11..5".SO 0.I (J..•'50 .50 tI.I l:il..50 .50 ~7~.
:;'';:.:1/I:LEC 1 21b.•15 .73 1371./21b..75 .sa llH:lb./21&•.7'5 .bJ IIJ'53,
CO.,;.TU'l!>It.E /104..~o •25 357.,H,"..50 •10 145./1&"•.~o .10 1 '13 •.
ul ..Sli.t..1 o..1U t.Q.Q tI./.fJ'..10 ..00 O.1 o..10 .UO u.
I 1 /
TOlAL "37'1.1735_',.379.122'1_,'530.17H.
I //
"Oli 1 rlU"'z:,i.1 //
H"rvR.U .1 .;,lSI..50 •50 '57'1./19 •.5l1 .50 7'1.
;'T1.A"l/cLeC""'//,2':>..7'5 •211 43 •
CIIM".T'J';11 [r'e /1 /
01r.:;':L //I
I I /
;1l:.TIRE:.,l:.N IS 1 ,1
,,1lJRO 1 I I
::.TU""ELEC I /I <1.5..ou .uO u.
CO",H.flllol.;Ttllr./-.I I -[H ..~Et.//;
I ,/
---------------,I I
iilolUS:>>IF.~IIlJ"CE:;'.H~.1735•.I 530_1804.I ':i"9.1ll1l7.
1 I I
,"'-~.lP "'ES~....R&1·N/-II.02&/0.306 I o.a~1l
I -I 1
"l:...t:r<VE I<EY./7~."lit.I ~"".
1 /I
1.0"S£.S I 19.20.I aQ.2T.I cl.2/l.
///
;,E t '1E:;UI/IolCES 1 2R2.1709.1 42':1.1777 •I ~".s.1·1l:>'l.
I /I
T""""'I:.IIEil J 10'•I o.I o.
I I /,I 1
SUo/PLUS I o.O.I all.o.I ao.u.
PE.l1<PUrl L.O.U,GENEIUTIN&C.lp:.cnr ~Etwl"EI'\ENTS(!'lE&,t,..ATTS)
HPuF ....XIMUM PLA~T UTI~lZ,t,TION FACTUR
.lPUF ACTu"LPL.l~T UI1LIZAT10N "CTuw
E.....E~GY --Gl:.Nl:.R.lf1UI'l/.lNi\iUAL.ENE~GT k£OUlIiEMENTS{M1LLIOIf5 OF I\I!..U".lIl-l'Iuvo<:»
4-3
TABLE 3.10.(contd)
AI,EA:A.'jC ....O..A~E
ANCHU~A~E CA~~:2 --MEU!UM LOAD GkO~r"
!~rER1I~YEA~:1990.
NIJTE:S:UEC.<0,1'l711 'Il1.U.S.-199'1.
c ~I lIe A I.PER[OD
o•
15u.
o.
7b1l8.
9991.
33114.
..\12,:>•
a 111 •
u•
1 g I "I •
•so .50
•SIl .50
•75 .32
•so .10
•15 .00
.00 .UO
1998-1999
M>'uF APUF
O.
/:iTS.
[445.
335 •
o.
33411 •
S'-"311 •
29'1 •
O•
I
ENE"GY 1 P\:.A~
--------1------I
'1'1$1.I 2a2~.
I
I
1
I
I
I
1
I
9512.I 205'l.
I
I
I o5~.
I
1
I
1
I
1
I
I
I
I
I
9S72~'1 ~i!~!I.
I
I li.lI7<J
1
I "'lb.
1
1 4 1.I 111.
I
9'131.I 2131:i.
1
I
I
I
o.1 510.
•541 .50
.75 .47
•'50 .•10
•15 .00
19'17-1998
M>,UF APUF
I 1 'l':l6-1 'l'i-7 I
I I'i:.AK MI'<.JF ....1.1"ar.E I;Ii V 1 POll
1--------------1------
---------------1 1
ioIEUUlioI("'I:.'H:I 1 1979.U71.I 2103.
---------------1 1
R£::;OuRC£S I 1
EXl;>II,H;1 I
rifl"RO I 1:178..::'0 .~O 3344.I a711.
:>1i:.Ar./ELEC I 1~4'i.•75 .'"5.:16 ....I l Q 'I5.
(0;-,,,.Tuol"[;1£I '5<15.•50 .10 294.I 335.
ull:.SE.L I 3..15 .00 O.I U.
I I
IOrAL.I Z81l •.9111l"•I 265'1.
I 1
Ae,,:;I r 1'J"::;I I
"rviolO I 1
5fEA~/F.Le:C I I
(;()....;.lu ..l:IINE I 1
iJH.St.t.I 1
1 1
IlEfl~O::"ENl S I I
I1lUl<O 1 I
~ri:.."/ELEC I 1
COM~.TIJIl:HI<E:I 211]•.uo .00 O.1
01t.~i:.L 1 ~..•uo .00 O.I
I I
---------------1 I
(;$«,S::;~t,::;UlliolCe::;1 2b5".'1004 •.I 2b'i'l.
I'I
CAP ,;e:S.,O1AilGHl1 o•3!~3 I O~2b4
1 I
ioIt,SEkVE kEQ.1 396.I 1121.
I I
l,OSS"S I '19.13J •.I 105.
1 1
:.£1 ioIESOuwCES I 21"'"8/:171.I 2133 •.
1 I'
'HAI'SFEREU I -27.I O.
I I
I I
SuHP1..US I l'5d.II.I 30.
I'EA~peA~LDAO/GENE~ArING CAPACITY HEuulkEHENTS(MEGAWAITSJ
HPUF MAXIMUM ?LA~r UTILIZAl10N 'ACTUR
A~W ACTUAl.PLANT urILIZArIO~FACTUH
'~~EHG1 --G~N~~ATIO~/AN~UAL ~NE~Gl NEQUIH~ME~lS(HILLIOM~UF ~ll,O~Arl-"OUHSl
,.~,
A •
,~,TABLE 3.10.(contd)
Ali'EA:FAI~fI"N ...S
FAlkUAN":;CAS ..:~-.'.fu lUM L.UAU Gl/llwrM
I"lIEIIiIl>TEA!<;1"~O.
1,(jIES:OfC....\9711 "ill U.S.-19'14.
C !<I T 1 C A L.I'E ~I II 0-----------------------.---------------.---------------.-----------,----.-----------------
I I q~l>.1 ~''17 1 l"q7-1~911 I 1991l-1'l9q
I PEAK "'''UF Ar'I,F EI.E!<GT /I'EA~MPlJF APllf Er,fNGT /I'EAI\1-1~\IF ....!.IF EI"....GT1-··-·--------/._--..--------/----_.---------------··---·--1 I 1
ilE"U!REME·'1IS I "4.!.I ~'ll •I <ll>I.21123./"ao.211J':!....-..--.-...../I I
RESOIJ;/CES /I I
<:llIllIItJG 1 I /
rt¥u;,!1 /170..50 .50 &48./170..5ll .SO &48.I 1711..~O .50 oa~..
S H.AI<·/i:.i..EC I 21&../'5 .,,11 IctOO.I 210..7').105 la~o.I 31b..15 .35 9"~.
C1/"".luI/clUE /16t.1...'i0 •10 123 •/Illu..50 .10 O./o..'ii).10 II •
<LJ!:'lll:.l./o..10 .00 O.I v..10 .00 II./O.•11).0'0 o.
///
TOTAi.../549.l'HO.I 52&.U7a.I 'lab.1/>11.
I I I
ADD 1 T t OtiS.I I I
"TuRl)I '"/I \38..51>.511 5025.
i:lHA'./t:L"C I I 1110..75 .cO 17';./
CO"II'.Til"'''tNE I //
oIESEL I //
///
Ht:Tt,,;;:t~I:.rlTS-I I I
"T!J~I)///
ST€A;~/ELEC I //
t u"".r"~!:l HiE I c4..00 •00 O•/1110..00 •00 O•I
:l1ESEL I I I
I I I"'--..--.....---/I /
511\153.~ESl)lIilCESI ')C".l'HU •.I 'llla •.20S.5./cell.2137 •,//1
~~P "ES •.'~ARGl'u 0.16'1 /~.G~3 /O.e'l'1
//I
Nf::'E""f wEu./~'"./'12.I 910.
//I
LoOS3c.S I 22.2'1./23.3Q.I 2'1.32.
I I I
,.£T i<f50uRCES /'11~.1'Ill 1 •.I 370.2023./SO".2105.
I I I
II<'A'~5F£Rf.O I 27./U.I G.
I I I
///
SuRPl.US /o.U.I ·'11.O.I 211.II.
PEAK Pf~K L.aAO/GE~ERATING C~PACI1'NEQUI~f~EkTS(MEGA~ArT5)
~puf MA~lMvM PLANT UTILIZATION FACTOI<'
APUF A'JUALo I'i..ANT uT1L~lAT~ON FACTOH
ENEHGT ••G..NfRA.rIUN/ANNUAL ENf.HGT xEuUI"EMEfflS(MILLIONS OF KIL.U~Arl·HOUHSl
45
TABLE 3•11].
A"EA:"NC,lIl"Al.E
A,<l:HU,O"1'CAS ..:2 --IolEuluM L.UAU GHIJwTH
IHTE"TIE YEA":I~~Q.
NoTES:OeC.b.1'111;..,iJ.3.-1994.
(contd)
Cf<ITICAL.~E RIO 0-----------------------------.-------------------------------------------------._--------/19"'1-2\10u /2000-2001 /2uOl-21l02
I PEA~,",PUF U'UF EJ\lEIo/G1 /Pl:.AII MI'U~APUF ENEIoIG1 /PEAII l'lI'UF Ai'U;cNl;1ol1>1
1-------------1-----..---------/------.-.-.---
---------------1 //
"E"'Ul ...E'~E:no.I 2j53.10:)51~/2'121.1 U8bj./2'1'lu.11115.
---------------1 //
K(:;Oul<CES //I
EU:>II"l.///
IHU ..O /I'iH..~O .:)0 San./Ib17..50 •50 blbU •I Ib17 ••50 .50 121120 •:.HAH/EL.EC /1'145.•15 •34 4343 •I 1445 •.1~•J7 'H47 •/1'1"~..75 .411 50(10 •.
COMS.fUR;'WE /317..50 .10 200.'I 23&..50 .10 119./136..511 •10 103 •
ClI ..SEI./o..15 .00 G.I 0.-.15 .00 O.I o..15 .00 D.
/I /
TOTAL I 32'15 •.10.38&./32'18.11 02/:1./31'16.11343.
//IA\JO!T10.":;//I
H'tlIiU /85.•50 .50 323 •/I
S T~A""El.fC I //
CO.1e!.TUI/b IUE I I I
lJ (ESEL I /I
//I
lit:Tt .."...t:i.TS /I I
111'iJitO //I
S P:A",cL.EC /I /
cn.....11110/"INf /62 •.•110 .ao o.I 100 •.00 .00 D•.I 10..1111 .00 U.Ull:.SEL ///
/I /
---------------///~";"OSS flESO,jHCES/3291:1.10709.../31'18.11112 ...I 3180.11.3"3.·
//I
CAP WES.1'<...1'11011.1 0 •./102 /0~321 /0.277
I I /icESE><VE REy.I 1171./4184.I 498.
I I /
I.OSSES /II'.1'311.I 121.11>3./T2'5.1123.
//I
"ET OlEo.OuRCE5 /211"•1 0::'5 1.I 2593.108l>3./2'558.1111'S..//I
TI'IAI'~"ERED /o.I o.I -b./I I
I /I
S'JRPI.US /351.ii •.I 172.o./101.o.
PEA~--PEA~L.OAU/G~NERATLNG CAPACIT'~EyUIKEM£NTS(HEGAftATTS)
MPUF --MAXIMuM PLA~T UTILIZATIuN FACTUR
",PUF --ACTUAl.PLA~r UTILIZArION FAcrn~
ENE~GT --G~N~HATION/ANNUAI.E~E~~T icfYUIWEMENTS(MILI.IONS uF KII.O~ATT-~uU~51
,~,
"'
46
TABLE 3.10.(contd)
~~tA:,~1l<6At'KS
FI>HIA~lj~S CAS..:2 --.-1EOIU"l.OAD GRuwTH
I"'TEUTl~YE~il :19'10.
IIOTE.:;:lJE.C.,.,1916 /jl U.S.-1'19Q.
C II 1 T 1 C ~l.I't I(1 U 0-----------------------------------------_.._-----------------------.---------------------
I 191j9-200a I 2000-2001 I 2001-2002
I PEAK MP!JI'APUF ENERGY I PEAK Ml'uF ,4Pt.:r EJ\lERlOl I PEAK MPUF A"OF ENEilGl
1--------------1--------------1-------------
---------------1 I I
fcEuIlIllU'~lnS I 499.2187 &.I 508.2a29.I 518.2270.
---------------1 I I
"I:.SUI.Ii<CES I I I
E~l:'Tl'.iO I I I
'1 <1.11<,}I 308 •..~o •50 1173 •I 32&..50 .50 lallY.I 32l>..50 .50 124O.
:.TEA"/ELEC I jl&..7'5 •.3'3 980.I 316..75 .37 1022.I 31b..7'3 .36 lUb".
cu"'&.T\JioId U.£I u..50 •.10 O•I O..50 .10 O.I o..50 .10 u.
o IESli.L-I oJ..10 •00 O•I O..10 .00 O.I O..10 .00 O.
I I I
TOIA~I &24·•.21'33.I &41.·2202.I &'11.,!JOe •.
I I I
AOO IT lor.s I I I
~'I"t.",;;j!fJ I la..50 .50 i:J7.I I
STE",,·l/El.EC I I I
CO'<ll.Tu'"'''INE.I I I
01 tSli.L I I I
I I I
J;lli.T 1I'lE"'ErHS I I I
'HUIIl;1 I I
ST ..,l.rIlEl.tC I I I
C[."'~.Tu"'''lI.C:.I I I
DIE:>E.l.I I I
I I I
--~------------I I I
'"uSS.fcESijuiolCESI bill.2220.I &111.22b2.I &41.2304.
I I I
Ct.,,·I<f.:l."AIU.n.1 0.21l5 I O.2bC!I O.C!.3l!
I I I
i<E;i£i<vt:KEli.I 10u~I I (l2~I lOll •
I I I
~OSSES I 25.~3.I 25.33 •.I 2b.311.
I I I
;,£T "'E:iUlI;lCES I 51b.alt17 •I SIll.222".I SIC!.2270.
I I I
TRAU.:oFEREO I u.I O.I b.
I I I
I I I
SIJICPLUS I 1 T.O.I b.o.I (I.O.
PEA~PtAK ~OAO/GENERATI~~CAPACITY "'~~UIHE~ENTS(MEG.~ATTSI
"I'UF MAXH1W1 1'1.ANT Urrl.lLATlON FACTup
APlIF ACTu~t..~l.ANT UTILlLHION F~CTlJk
tNf....Gy --GtN~R~T1[)I\I/"'N,"U~l.EJ~EI<GY JlEIJUIKErll1'l I S (Mll.l.IOI~::S 01'I<11.011.."TT-l1UUK:l1
47
TABLE 3.10.(contd)
A"I:.&:A.\C"O,a",e
A~C"O~AbE CASe:2 --MEDIUM ~OAO GROWI~
I~TERrlt YE.R:19iO.
~~II:.S:OEC.ti,1978 ./U.S.-199<1.
CR 161 I C A ~10 ER I a 0--------------.--------------------------------------------------------------------------
o.
o.
12111.
1~111.
.51)•50 blbl)•
.75 •J&0133 •
.50 .10 u •
•15 .liO O•
Ic293.
20,)/1-2\)1)5
MpuF APUF
.00 •i,l0
U.
lel.
1&11.
184,:>•
10.
O.
/
1 "E..AK1------
/
/2119".
I
I
I
/
1
I
/
/
1 5480.
I
/
/
I
I
/
/
1
1
/
/
I
1
/
I 3402.
/
I O.ae",
I
/539.
I
I 1.5').
I
1 .Hai.
I
1
I
I
U./
177.
ENERGY
.so .511 bl&O.
•1~.3&51l01.
.so •10 1'3.
.15 .01)O.
1197".
2U05-2uO'l
MpuF APUF
I).
Il.17 •
lall~.
Ill •.
O.
olbU •
/1103.
IS.
O•
I,
E,~EKGY ..;/PEAK
--------1------I
11487.1 2l.2l..
1
/
J
/
/
I
I
/
10959.I 3480.
I
/
/
701.I
/
/
/
I
/
I
u.1
/
/
I
11l.59./3"80.
/
/O.32~
I
1 525.
/
17o!.I 131.
I
11487./282".
I
/
1
1
O./I'HI.
./5 .CO
•~U-'.50
•r-!.38
,.su .1 U
•15 •(10
cO"2-i!\JQ3
..i'UF A?UF
o.
11>17.
1445.
Ud.
a.'
TOUt.'
Al!ull ral,:.
,",ft-wI';'
So r"A""~LEC.
ClJ,~".TU~ij HIE
CIE.::>E.L
;j~.T lW;:'HEN rs
"r,).:10
5T<'.:HELfC
tl)"1~..lLJHt]10i:,
uI~SE.L
,-U:;5..5
/,
/PEA"/--------------------/~EQuIREM~NrS /2~~~.
---------------1..£:'0 ').:1CE5 , /
EAISTIt,r,/
"'uRU /
STU"'/ELEC /
CfJ"~.Ttl""IM,/
1i11:.5U./
/
/,51&').
1
/
/
/'UIU.
/
/
/
/
/
/
/lDU.
J
1
-------.-------/bRQ5~~€5nllRCE5J 34~U_
1
CAP RES.MANGlh/U.3~1
1
/')12.
/
I 12/>.
I
NET ~ESUURCES I 2841.
I
/
/
/
/i!/l5.
PEl~--PEAK ~UAu/GEN~RATING CA~ACITY ~£QUl~E~£NTS(HEGAwATTS)
"IOU'--MAXIMUM PLANT Ul1~IZATrON FICTO~
.>'tlF .-ACTUAl.PLA,"T UII~lZ"'T1(;N f4<:.II1~
E~e~GY --GE.Ne~Al1U~/ANNUAL ENERGY ~EUUlwE~ENTSlMILLlaNS Of KILU~AT1-MUU~~J
48
TABLE 3.10.(contd)
J,iotE,A.:,f Po !l"I'dANI\S
FAIR~~~~S'CAS~:2.--MEOIU~~OAO G~O~T~
'I"rEIHlc.YfAIl:1~90.
MuTeS'OEC.1:>.\91ij ~I U.5.-19~~.
C 1/I TIC Ai.,__I'E 1/I lJ 0
.------~---------------------------------------------------------------------------------
o.
.sa.
.50 •50 li!'lO •
.15 ..35 1191.
•511 .10 o •
.10 •00 O•
2431.
~OO"-,NO~
MPUF APUF ENERGY
o.
27.
1240.
1146 •
O.
O•
I
ENERGY J PEAl<.--------1------
/
2353.1 '.:i4/:>.
/
I
1
/
1
I
I
/
23118.I 71&.
I
I
I
1
I
I
I
I
I
I
-'I
I
1
1
23118.I Hb.
I
I 0 •.:51 1
1
I 109.
I
.lS./
I
2353.I sao.
I
/
/
I
O.I
.50 .50
•7~.34
.~o .10
• 1 It ..00
c003-i!OOQ
MPl;F APuF
1 20u2-2003 1
1 PEA<.,PUF ,Ai'UF t:f'~fk\3Y 1 PEA~
1--------------/------
---------------/I
kE:uUlkE"Elojl::i I '')27.2312.,/537.
---------------/,/
i<E:SOLlHCE::i I /c.X I::;r II,../,
"YuHI)I 32.....5f!.50 1.24U./321>.
::;TU'''/~LEC /311>../5 .37 "H.I 3'H.co;.a.TUi/a INE:I q..~O .10 0.,1 0.,
ul~Se:L /u..10 .uO,O./O.
//
TOTAL 'I ...'It •c17l.I 711:>•
I /
AO!J 1 TIO,.S I'/
riYUtolO /I
STLAM/€LEC /1011.•75 .20 17'5 •/
Cu'.!'.r'J~b INE./I
!111:..~..t..I I
I /
RE:rlPEME.'1TS I /
,,'1'i.J~O /I
::;ro,"nt.."c /2:>..UO .00 U./
COHlS.rURti INE //
~.::t.Se:L 1 /
I I
---------------1 I
....(;:;;;;I<E:WUkCI:.l>1 71".c3qJ •/7IIl.
I I
.~CA~"I:.~.MAI/GINI o•.3~~I 0;333'
/I
i/ESE"VE,.l<t:Q./10"./107.
/I
L.O::;Sc5 /2".15./.,21.
I /
r.E T "E SI)URCE 5 /50"•2312.I 502.
//
TII .....::;I'EI/"O /O./O.
1 I
//
SUI;PLUS /57.O./,,').
PEA~PEA~~OAD/GENEI/ATING CAPACI1Y ~F.~UI~EMENTS(MEGA~ATTS)
HPUF MAXIMUM p~A~r UTIL.ILATIUN FACTUII
A~UF ACTUAL PLANT VTILIl ...rrUN fACTvK
ENE~GY --GENc.R"'110'~IAN;,jUAL ENE~IOY REQul;;El'lENTSlMlLt..IOfliS OF KII.OilATI-"uURS)
49
Pe~~Pf~~~OAu/G€NcHATING CA~ACITY ~EQulk€~ENT~(MEG.~.TTSJ
~PUF ~A~lMU~PLANT ~rlLIZArluN FACTUH
APUF aCTUAL ~LA~r uTILIZATIO~FaCTD~
E~E~GY --GtNcHArION/AN~U.L ENckGV ~EYUIHEMtNrSfMILLIONS uF ~!Lu~ATT-~~U~8J
50
~..
,
TABLE 3.10.(contd)
''''EA:FAI~"AN"S
f.llollhN.S CAS~:2 --MEl.lIUM L.OAO GRO"'l"
Ir,TE"11!:'YEArO 1""0.
~IO IES :Or.c.h.1918 "',U.S.-I""'!.
C R I T I C A I."E il I a 0-----------------------------------------------------------------------------------------/~Qu5-cuOh ,cOO,,-cu()1 /2uu7-coOl!
/PEAK 1'Il'uF AI'UF EiIE"lGT 1 PEAK ,.PUF APur Eh£IolGl /PEAK IoIPUF AP\JF ENEi/Gl/----------.---/-------------1-----------------------------1 //
wH,uIRElo';::r.T S /55<..2437./5&5.2418./515.25211.
-~------------I //
''''E~UiJ''(;£S ///
HI:>r lW~·/.//
"Yuila I 321>..':>0 .5D 12'10.I 3Olb..50 •50 12'Hl.I 32&..50 .so 12'!0 •
~n.A"/ELEc I j"l../5 •So 12.34./.511 •..1">.j9 1<17,:>.1 .511..15 ."1 [jIll.
CO"'".TI.o«/l I1.IE /Q...,:>0 .1i>O./O..50 •10 O./0..50 .10 Ii •
lIIr.::'U./O..10 .00 Q./0..10 .00 I).I D..HI .ilO 0.
///
rOUL /710.2'114_..i b9b •.251S_/&9b_2550.
///
.laO IT IO!'<S ///
ri'iJf'l.f)///
sreA"'/l:LEC ///
CUM'!.TU.<fI tr.E //I
i[.o IE5EI..///
/I I
~E TI;'E"r.I~r::i·/,/
;l"'tYL:~J ,//
,:,H A t'£I.EC /211..01).00 O.//
1 CO"...Tu~"11.£I I /
OU~"L.///
,/I /---------------///
\oiHjlz:...l::~OuRtE~/·o'Jo.2 'n'l./&'110.2'515./&90.i!ssa.
I //
t~~"..s ...,.:lGII./11.252 1 O.23Ol /o.all
///
..E5~"\iE liEU./111./113.I 115.,//.
..OliSl~I 20.37./21'1.:51./2~.311.
//I
'iE,l'lESOll"CES /'3'57.2437./55S.2<1711./552.Ol5OlO.
I //
li"....SF EIolElJ /0·•./10./23.
I //
/I 1
SuR9L.US I 1 •.O./O.O./O.II.
PEAK PEA~LOIO/~E~f~ATIH~CA~ACIIT j.{EYUIRE~ENTS1HEbA~ATTS)
H~UF ~AX1MU~PLANr UIILIlATIUN 'ACTuR
A"IJF 11;TI:1-L.I'LA"r UI1LIZAII0N F.l.CTUI'i
E~EwGl --GEN~R1-rl0~jANNuaL ENERGY RECUI~EMENTS(MIL.LIONSOF KILowaTT-MOURSJ
5-1
TABLE 3.10.
~kEA:~"CHOkA"E
A,.ChUilAloE CA::it.:2 --i~EOluM LOAu GllO,HH
I~TEN1I~TEAk:1~90.
~UT~S:~~C.h.1~7d ~I U.S~-lq~~.
(contd)
C I'(I TIC A L P E Ii I iJ LJ
---------------------~-------------------------------------------------------------------1 2Du<l-c!110q I 2~Uq-20Iu I 2'H Q-2Ull
I PEA,(",PuF Ar'IlF ENE~~Y I PEAX MPI;F A;>uF ENEiiGY I PEAl(MPUF APuF ENEliGT
1--------.-----1--------------1--------------
---------------1 I I
-NEA,J~~..-<!:.I'IS I Zql>d.13350;.1 3030.13..71.I 310'1.13'Il;3.
-------_·------1 I I
j(E·~{;l.J ...~1.~I "f 1
EO"II'H'I 1 1
i1Tu..-a /1"'11.•50 •50 01&0./I t I 7•.50 .50 &1&0.I 1 b 1/•.5\1 .50 01 ..11.
iiTU>i/ELEC /22'1~..75 .38 1<100./2245.-.75 •3CJ Ip".I 22'15 •.75 .37 n3c!.
ca"'B.Tllw ..II-!€1 ~.•50 ~lQ O.1 o•.50 .10 O./O..50 .111 u.
~.;'liIc.;ofL I 1*._.IS-.I>il o./(J..1:;.1>0 .O.I u..1 ':>..1.10 U.
I I 1
TIITAL 1 3M''?1355~.I 31lb2.1:5<170.I 30b2.IJ'ICJ2.
I I I
",,0 I no',s /I I
tt1u~{J I .I I /
::.n.A,HU.EC I I /400..75 .2\1 1 \t I •.
CO><Il.TUlltllNE I I I
l)lt.~tL I I I
I I I
"I':.T!REJlEflT:I I I I
Hl'l,)~i1 I //
S lE...-./tLEC I //
cr."'i.Tllna U.E 1 /I
UIt:SEI.1 /I
I I I .~---------------/I /
'-~U~.;i Ii/cSH'-l",CESI Jabi!.t3o:.59.I 38b2.1387&./'1e62.1'11'13.
I /I
'41'><£5."Ali'G Ira 0 •.301 /0.212 I 0.373
J I I
~E~E"vE.;(£0.I 5q·~•I bUl./021.
/I I
Lrl.'>~E;;;1 14d.e\)il.I 152 •.20'>.1 155.2111.
J I I
NET flESOIl"CES 1 3120.1335".1 3103.13611./34<1 ...13'1113.
1 //
Hi.lH:>FERED /-3.:.4.I -4"./-Sa.
I I /
//I
5 u..-Pl..uS /1 t,s.O./21.O./3 ..5.0.''
PEA~PE~~LU~UJGENE~.lrI~~C.lPAClTY REoulkE~ENTS(MEGAwATTS)
MPUF MAXI~~M ~~A~l UTILIZATIUN FACTUk
A"OF ACTuAl.PI.A,H UTlLlZATION FACUJ"-
EN~kGY --GaN~RAT!UN/AN"UAI..eNERGY REQUIk(MENTS(MILLIONS uF KILUWArT-~UURS)
TABLE 3.10.(contd)
A,;fA:FA!"'bANKS
F~IH8AN~S CASE:2 --MEOIuM LUAD GRO~TH
INTF.Rllc YfAH~Iq'1U.
NU1<.S:U£C.~.l~'~#1 u.~.-I~~4.
CRITIC'>..PER r (J 0
.50 .50 12'10 •
.7'].'1'14'1'5.
.~O .1 \1 u.
.10 .00 o •
C'~('\.'3.,
0 •.
2QIO-2ull
MPUF ~PUF E"E~G'
.50 •50 12'10.
.7'5 .43 140c.
.'50 •10 o•
•1ll .OU O.
2e.4.L!.
2009-2010 I
MPuF APuF EI.ERGY /PEA,.;_._-----/------
/
ZbO-i.I b03.
I
/
/
/32i>.
/371.
I O.
/O.
/
;Q'''h••
/
/
/
/
/
I
/
/
/
1
/
/
f
/
21042./b'Ur.
1
/0.154
I
1 121.
1
39.1 30.
/
2~03.1 '5'1';.
/
/58.
/
/
II./O.
.~O .50 1240.
.75,.~2 1359.
•50 .:0 o •
•10 .00 O•
2599.
~Ov~-2UOq /
MPuF "PUF ENEwGY /PEAK
-----~--1------
/
2501./59'1.
/
/
/
/32b.
/371.
I o.
/O.
/
//091>.
/
/
/
/
/
/
I
/
/
I
/
/
I
I
2599.I ~9~•.
I
/0.172
/
/11'1'.,
I
38./30 •.
I
25..1./548.
/
I 46.
I
I
0 .•I II.u.
32b.,
371.
O.
<I.
SUi/PLUS
TIl rAL
AUOI T!Ot~S
"YUR"
~1<''''''/ELEC
co,"".TUi'lrlII.E
O!",SEL
"f'r H<E>oii?:NT S
"'ffHiII
5H/.·~/fU.C
CQ"'b.Tu"'"WE
O!ESEl-
1
1 PEU/---------------------/~!UUJkt~~H1S I 5A~.
_._------------/i<Esu\ii<CES 1
EU:;TTrIG 1
t<,jJ~iJ /
:iTEA"'/ELEC /
COl<8.TURtllNE /
lJH.SEL../
/
1 ,,"h.
/
/
/
1
/
/
/
/
/
/
/
/
/
---------------1G~OS~~ESaURCES/..q~.
/
CU'"'E3.,",."tHNI (}.l'1Z./
RESErI'Il::REil./117.
1
/
/
~ET ",fIOUrlCES I S~U.
/
/
f
/
1
P~A~~EA~~OAO/GENERArlNG CA~AC!T'~EQurREMENT5(MEGA~ATTSl
~~UF MAXIMUM ?LA~r urr ..llAfIDN FAC1UN
Al'llF ACTUAL.PLANr ulILllAT.l:ON FACTON
ENEWGl --G~N~RATI0N/ANNUA~ENENGT REgUIRfMENT~(MrLLION$OF KILUwATT~HOURS)
53
TABLE 3.11.(contd)
Scheduled Combustion Turbines
Scheduled Combustion Turbines +400 MW S.T.
Anchorage 400 MW Coal-Fired Units Could be Replaced with Staged 800 MW
Capacity Units
Scheduled Combustion Turbine +200 MW S.T.
Bradley Lake (70 MW)x 1.15 for Peaking +7 ~~W S.T.National Defense
Bradley Lake/(70 MW)x 1.15 for Peaking +200 MW S.T.+7 MW S.T.National
Defense
Na ti ona 1 Defense
200 MW S.T.+43 MW S.T.National Defense
400 MW S.T.+43 MW S.T.National Defense
55
TABLE 3.12.(contd)
*Interconnection Installed
(1)Scheduled Combustion Turbine Additions
(2)100 MW Scheduled Combustion Turbine +400 MW S.T.
(3)100 MW Scheduled Combustion Turbine +200 MW S.T.
(4)Bradley Lake (70 MW)x 1.15 for Peaking +7 MW S.T.National Defense
(5)Bradley Lake (70 r4W)x 1.15 for Peaking +200 MW S.T.+7 MW S.T.National
Defense
(6)18 ~1W Scheduled Combustion Turbine +200 MIN S.T.
(7)Anchorage.400 r~w Coal-Fired Units Could be Replaced with Staged 800 ~4W
Units
(8)National Defense
(9)200 ~1W S.T.+43 MIN S.T.National Defense
(10)100 MW S.T.+25 M~~S.T.National Defense
(11)400 MW S.T.+43 MW S.T.National Defense
57
TABLE 3.13.(contd)
*Interconnection Installed
(1)Scheduled Combustion Turbine Additions
(2)Scheduled 100 MW Combustion Turbine +400 MW S.T.
(3)Share of WatanaCapacity x 1.15 for Peaking
(4)Share of Devil Canyon Capacity x 1.15 for Peaking
(5)Scheduled 100 MW Combustion Turbine +200 MW S.T.
(6)Bradley Lake (70 MW)x 1.15 for Peaking + 7 MW S.T.National Defense
(7)Bradley Lake (70 MW)x.1.15 for Peaking +200 ~~W S.T.+MW S.T.National
Defense
(8)Scheduled 18MW Combustion Turbine +200 MW S.T.
/
(9)Anchorage 400 MW Coa l-Fi red-Units Cou1 d be Repl aced wi th Staged 800 MW
Units
(10)National Defense
(11.)Share of Watana Capacity x 1.15 for Peaking +25 ~,\~S.T.National Defense
(12)200 MW S.T.+43 MW S.T.National Defense
(13)Share of Watana Capacity x 1.15 for Peaking +25 MW S.T.National Defense
(14J 400 MW S.T.+43 MW S.T.National Defense
59
__________-r-----~_w ---__"---=----------
7000
r".
6000 ~'
~
-b3:5000:E-0
~
..J
~4000<1.1.1
~
0z I "'"'<
V1 I
1.1.1 3000u
0::
;::)
0
V1
1.1.1
0:::
I-20001.1.1 J-------Z I ~,
I
1000
o
80 85 90 95
YEAR
2000 2005 2010
FIGURE 3.6.Load/Resource Analysis for Anchorage-Cook Inlet Area
Without Interconnection and-Without Susitna Project
(Case 1).Low~Medium.and High Load Growth Scenarios
60
7CXXJ
/
/
6COO t
I-ls:
~5000c 7«0
....J
~<W
0..400Jc:z<
c.n
L.LJ
U
Q:3000:::l
0en
1.1.1
0::
l-
l.U:z 2000
;..........
I ------
1000
OL....-__~__......J....__---Ji--__...J..-__--'-__--l ..l-----J
80 85 90 95
YEAR
2000 2005 2010
FIGURE 3.7.Load/Resource Analysis for Anchorage-Cook Inlet Area
With Interconnection but Without Upper Susitna Project
(Case 2).Low,Medium,and High Load GroIJ/th Scenarios
61
-7000r--~-----------------------,
.6000
;:5000
~
o
~
--l
.~4000.<c..
LLJ
C-
o
Z
<C
~3000u0::
~o
V')
LLJ0::2000
I-
LLJ
Z
1000
Ol...-__--L .L-__--l-...I--__-J...-"--__-J...-----:
80 85 90 95 2000 2005 2010
YEAR
FIGURE 3.8.Load/Resource Ana1ysis for Anchorage-Cook In1et Area
With Interconnection and.With Upper Susitna Project
Coming On Line in 1994 (Case 3).Low,Medium,and
Hi gh Load.Growth Scenarios
62
~,
1200
t"....--I
I
1050 J
r,/
'-J-~
~
Q 900
~I....J
~I«~IQ.750c Iz«/,"
In I~u
J....~10::
::J 6000 IIn
~
10::
I-
1.1.1z
450
'--._-'_.-..._--
300
150
o
80 85 90 95
YEAR
2000 2005 2010
FIGURE 3;9.Load/Resource Analysis for Fairbanks-Tanana Valley Area
Without Interconnection and Without Upper Susitna Project
(Case 1).Low,Medium,and High Load Growth Scenario
63
1200 r-----------------------------,~.
,.
1050 I'-
I
I
900 I
-3:
:E-0
<:7500
....l
~<:
UJ
C-
o 600'z«
V')
UJ
U -----.-c::
::>
0 450Vl
UJc::~,
I-
u.J:z
300
150
a
80 85 90 95
YEAR
2000 2005 2010
FIGURE 3.10.Load/Resource Analysis for Fairbanks-Tanana Valley Area
With Interconnection but Without Upper Susitna Project
(Case 2).Low,Medium,and High Load Growth Scenari
64
1200 ,.....--------------------------.,
1050
,I
/.
I-,
J \_'
I \I
I \1
300
900-3:
~
o
C§750
-J
~
isa.
~600<
en
u.J
Uc::
~
S;450
l.I.I.0::
l-
I.1.J
Z
150
o
80 85 90 95
YEAR
2000 2005 2010
FIGURE 3.11.Load/Resource Analysis for Fairbanks-Tanana Valley Area
With Interconnection and With Upper Susitna Project
Coming On Line in 1994 (Case 3).Low,Medium,and High
Load Growth Scenarios
65
--I
4.0 SYSTEM POWER COST ANALYSES
This chapter describes the methodology used to evaluate the annual
cost of power from individual generating facilities (or groups of similar
generating facilities),the method of computing the average system-wide
power costs,and presents.the results of the system power cost analyses.
The first section briefly discusses the factors which determine the cost
of power.The second section describes the computational method used to
compute the annual cost of power.This method is incorporated into a
computer model titled ECOST4.A listing of the computer code is given in
.Append i x D.
The third section of this chapter contains a discussion of how the
system-wide power costs are computed given the power costs for the'indi-
vidual facilities.The results are presented in the last part of the
chapter.
4.1 FACTORS DETERMINING THE COST OF POWER
Three cost'categories are evaluated in this report:1)interest and
amortization charges (capital cost);2)fuel ~osts;and 3)operating,
maintenance and replacement costs.Of course,there are other cost items
included in the cost of power to the consumer,such as taxes,insurance,
distribution and billing charges,but these costs are not evaluated in
this report since they typically do not vary among the three cases
evaluated.
.'
These components of the cost of power are shown in Figure 4.1.The
annual plant capital expenses are fixed by the initial financing and are
typically constant over the life of the plant.Operation,maintenance,
and replacement fuel costs typically increase overtime as affected by
inflation and real price increases.As a result,the total annual cost
of power progressively increases over time.
4.1.1 Capital Cos ts
The capital costs represent the total cost of constructing a gene-
rating facility.ihe capital cost estimates used in this analysis include
66
TOTAL
ANNUAL COST
\
COST OF
ELECTRICITY
(MILLS/KWH)
TIME (YEARS)
FIGL'Ru..J....Components of the Total Annual Cost of Power
67
interest and escalation during construction.It is assumed that the capital
costs are repaid in equal annual payments over the payback period of the
plant.The capital cost estimates used are in terms of constant October
1978 do 11 ars..
The total investment cost for the coal-fired and hydroelectric
generating facilities are shown below.
Total Investment Cost
100 MW Coal Steam Turbine
200 MW Coal.Steam Turbine
400 MW Coal Steam Turbine
Watana Dam (795 MW)
Devil Canyon Dam (778 MW)
(mi 11 ion $)
245.4
372.0
646.8
.2501.2
834.0
($/kW)
2454
1860
1617
3146
1071.9
SOURCE:Alaska Power Administration,August 1978.
Transmission facility costs are presented in Table 3.7.
4.1.2 Heat Rate
The heat rate is the ratio of the Btu·s going into the plant as fuel
to the kWhls of electricity produced by the plant.The heat rate is
assumed to remain constant for all plant utilization factors over the
lifetime of the plant.The heat rate for new coal-fired stearn electric
plants is assumed to be 10,500 BtU/kWh.
4.1.3 Operation,Maintenance,and Replacement Costs
The operating,maintenance,and replacement (OM&R)costs include the
administrative and general expenses as well as the interim replacement
costs.All estimates are expressed in terms of Oct.ober 1978 dollars.
They are escalated at a rate equal to the rate of general inflation.
The 0~1&R costs for coal-fired steam electric and hydroelectric
generating facilities and transmission facilities are shown below.
68
.~.
100 MW Coal Steam Turbine
200 M",!Coa 1 Steam Turbi ne
400 MW Coal Steam Turbine
Watana Dam (795 MW)
Devil Canyon Dam (778 MW)
New transmission facilities
OM&R
(million $)
3.76
5.7
9.8
0.74
0.73
Costs
($/k~J/yr)
37.6
28.5
24.5
0.94
0.94
2.0
SOURCE:Alaska Power Administration,August 1978.
4.1.4 Financing Discount Rate
The financing discount rate represents the cost of capital to
utility.A rate of 7.0%is assumed in this report.This is assumed to
be an average of all types of financing available.
4.1.5 Payback Period
The length of time over which the plant is fi~anced is the payback
period.This is assumed to be equal to the plant lifetime except for
hydro projects where a 50-year payback period is assumed versus at least
a lOO-year plant lifetime (see Section 3.2.6).
4.1.6 Annual Plant Utilization Factor
The plant utilization factor (PUF)is the ratio of the actual power
production during a year to the theoretical maximum if the plant was to
run 8760 hours at lOO~capacity during the year.
The annual plant utilization factor is highly variable depending upon
many factors (e.g.,forced outage rate,cost of power from alternative
sources,and power production requirements).Because of this,it is
necessary to explicitly consider the effects of the PUFon the cost or
power over the 1ifetime of a pl ant.As pointed out earl ier,the PUFs
used in the report are determined by the load/resource analyses (see
Section 3.2.6).
4.1 ..7 Unit Fuel Costs
Fuel costs for thermal generation pl ants are expected to increase
over times following paths shown in Figures 4.2 through 4.4 for natural
69
10 ~----------':"----------r-'7'
BELUGA &HEALY
•
201090.200080
0.1 '-----J-__.l....-_---J.__--l-__.....
FIGURE 4.2.Estimates of Future Coal Prices -
2%and 7%Escalation
SOURCE:Alaska Power Administration,August 1978.
70
_________________________w'
10.0
ANCHORAGE -KENA ILO
BELUGA
0.1
70 80 -90 00 10 20
FIGURE 4.3.Estimates of Future Natural Gas Prices -
2%and 7%Escalation
SOURCE:Alaska Power Administration,August 1978
71
FAIRBANKS
~/j
II 7'/0
II
II
IIII.
IIIIII
il
/1
II
ANCHORAGE':KENAI PENINSULA
00 10 20
FIGURE 4.4.Estimates of Future Fuel Oil and Diesel
Pri ces -2%and 7%Escalation
SOURCE:Alaska Power Administration~August 1978.
i2
gas (Cook Inlet areas),coal and distillable o{l.Although natural gas
is likely to become available in the Fairbanks region in the early to mid
1980·s,Federal policies are expected to preclude its use for ~ower gen-
eration except for probing and the cost is indeterment at the present
time.
4.1.8 General Inflation Rate
Because of the uncertainty involved in estimating the future rate of
inflation,two alternative cases are evaluated.A constant dollar case
(0%inflation),and a 5%inflation case.
4.1.9 Construction Escalation Rate
In this analysis,construction costs are assumed to escalate at the
same rate as the rate of general inflation.
4.1.10 Fuel Escalation Rate
The fuel escalation rate is set to equal the general inflation rate
plus 2%.
4.2.METHOD OF COMPUTING THE ANNUAL COST OF POWER FROM INDIVIDUAL
GENERATING FACILITIES·
During any year the electrical power production is computed thus:
*EPPF;i=(ICAP *PUF;*HPY)/1000
where :"
ICAP =Installed capacity (MW)
PUF i =Plat utilization factor in year (fraction)
HPY =Hours per year (8760 hours/year)
*Parameters with the subscript i are assumed to vary each year over the
i ifetime of the pi ant.Parameters without the subscript are assumed to
be constant over the lifetime of the plant.
73
The total annual costs (TAG)are composed of two elements:variable costs
and fixed costs.In equation form:
TAC.=VARC.+FIXC.111
where:
VARC i =Variable costs in year i ($/Year)
FIXC i =Fixed costs in year;($/Year)
The variable costs consist only of the fuel costs.
VARe.=FUELC.1 1
where:
FUELC;=Fuel costs in year i ($/Year).
In turn,fuel costs are computed:
FUELC;=HEATR *EPPRO i *UFUELC i
where:
HEATR =Heat rate (Btu/kWh)~,
EPPRO i =Electrical power production in year i (MMk~Jh)
UFUELC i =Unit fuel costs in year i ($/MMBtu)
The fixed costs consist of two factors.These factors can be writ-
ten in the following equation form:
FIxe i =INTAM +OMRC i
where:
INTAM =Interest and amortization (capital recovery)charges (S/Year)
OMRC i =Operations,maintenance and replacement costs in ye~r;($/Year).
The interest and amortization charges (INTAM)represent the annual debt
service payments.
74
INTAM =CRF *TINVC
where:
CRf =Capital Recovery Factor
TINVC :Total Investment Costs ($)
The capital recovery factor is used to compute a future series of equal
end-of-year payments that will just recover a present sum p over n periods
at compound interest (IR).It is computed thus:(l,p.26)
,CRF :JR(l +IR)PBP
.(l +IR)PBP_l
where:
PBP :Payback period (years)
The methodology described in this section is incorporated into a
computer model called ECOST4.
4.3 METHOD OF COMPUTING AVERAGE SYSTEM POWER COST
Once the costs of producing power from the various individual gen-
erating facilities in a system are known,a method of comparing the total
cost of Hwer from the three alternative system configurations evaluated
in this report is needed.
To compare the overall cost of power produced'by these alternatives
a relatively straightforward method is used.The costs of producing and
transmitting power for each of the generation and transmission facilities
are added tl1gether for each year during the period 1978-2010.In equation
form:
TAC.
J
where:
n:l:
i=l
AG ..lJ
TAG,:total annual cost of power production for the system in
J
year j ($)
75
.'AC ..=annual cost of prOd~cii1g...or ~t:~ansmitting power for faci 1i ty~\lJ
i during year j ($)
n =number of generation and"transmission facilities in system.
Likewise the amount of power produced by each facility during each
year is summed to give a system-wide total.
TAPP j
where :
n
=2:PP ..
i =1 lJ
TAPP j =total annual power production for the system in year j (kWhs)
PP ..=power 'produced by ead+generating faci1 ity i during year jlJ
(KWHs)
n =number of generating facilities in system
By dividing the total cost by the total generation an average cost of power
for the system is obtained for each year.
EPCOST j =
where:
TAC.
J
TAPP j
EPCOST j =average system-wide cost of power for year j ($/kWh)
By comparing the costs of power,the system producing the lowest cost of
power can be selected.
4.4 RESULTS OF SYSTEM CASH FLOVJ AND POWER COST CALCULATIONS
The results of the
sented in this section.
evaluated:
system cash flow and power cost calculations are pre-
As pointed out earlier in the report three cases were
Case 1.All additional generating capacity assumed to be coal-fired
steam turbines without a transmission interconnection between
the Anchorage-Cook Inlet area and the Fairbanks-Tanana
Valley load centers.
76
Case 2.All additional generating assumed to be coal-fired steam
turbines including a transmission irterconnection.
Case 3.Additional capacity to include the Upper Susitna project
(including transmission interconnection)plus additional
coal as needed.Upper Susitna assumed to come on line in
1994.
Tables 4.1 through 4.36 present the cash flow and power cost calculated
for the 3 cases.The contents of these tables are summarized below:
07177777"'__I
TABLE 4.1.Anchorage-Cook Inlet Area,Low Load Growth Scenario,Case 1,0%Infl a ti on-----
New Hydroelectric TranslIli 55 t on
Total Cost _J~COil L£!r~d CaedC!!y'_Costs _~_IS __10tal Total Total System
of Existing Investment OM&R Coa1 Investment OM&R Investment OM&R Investment System Consumption.Average Power
Year Capad ty ~osts_.Cos ts CosiL-_~.t>__~sts ~~!L.-~Costs costs.$Mt1t:~IH Costs.¢n~H
78-79 33.1 ---------------0.6 0.4 ---34.1 2376 1.4
79-BO 42.2 ------.--------0.6 0.4 ---43.2 2568 1.7
80-81 48.2 ---------------0.6 0.4 .-.49.2 2706 1.8
81-82 52.8 ---.-----------0.6 n.4 ---63.8 2050 1.9
82-B3 61.1 ------3.1 ------0.6 0.4 ---65.3 .299\2.2
83-84 62.0 _.....---3.3 ------0.6 0.4 ._-66.3 3132 2.1
84-85 66.7 ------3.3 ------0.6 0.4 ---71.1 3273 2.2
85-86 66.7 1.3 0.2 3.6 10.9 0.4 0.6 0.4 12.8 84.1 3433 2.4
8b-;i7 67.2 1.3 0.2 3.7 10.9 0.4 0.6 0.4 12.8 84.8 3594 2.3
87-08 66.4 30.0 5.9 6.7 10.9 0.4 17.1 3.6 58.0 141.0 3754 3.7
83-S~1 59.0 30.0 5.9 9.6 10.9 0.4 17.1 3.6 58.0 136.6 39\5 3.5
89-90 .54.5 58.7 11.6 16.6 10.9 0.4 17 .1 3.6 86.7 173.4 4075 4.2
90-91 50.2 58.7 11.6 22.5 10.9 0.4 17.1 3.6 86.7 175.0 4285 .4.1
91-92 47.1 66.8 13.2 26.6 10.9 0.4 17.1 3.6 94.8 165.7 4495 4.1
"co 92-gJ 42.4 95.5 HI.9 34.5 10.9 .0.4 17.1 3.6 123.5 223.3 4705 4.7
93-94 38.9 95.6 18.9 41.9 10.9 0.4 17.1 3.6 123.5 227.2 4915 4.6
94-95 ,39.4 124.2 24.6 50.7 10.9 0.4 17.1 3.6 152.2 270.9 5125 5.3
%-96 34.5 152.9 30.3 56.9 10.9 0.4 17.1 3.6 180.9 306.6 5385 5.7
96-97 &8.3 202.8 40.1 64.1 10.9 0.4 17.1 3.6 230.8 ~67.3 5645 6.5
97-96 25.4 202.6 40.1 69.1 10.9 0.4 17.1 3.6 230.8 369.4 5904 6.3
98-99 27.4 202.8 40.1 74.1 10.9 0.4 17.1 3.6 230.8 376.4 6164 6.1
99-2000 22.6 252.7 49.9 80.4 10.9 0.4 3.3.5 6.8 297.1 457.2 6424 7.1
00-01 12.2 252.7 49.9 83.B 10.9 0.4 33.5 6.8 297.1 450.2 6'189 6.9
01-02 11.0 252.7 49.9 86.9 10.9 0.4 33.5 6.8 297.1 452.1 6555 6.9
02·03 4.8 252.7 49.9 90.4 10.9 0.4 33.5 6.8 297.\449.4 6620 6.8
~
03-04 4.B 252.7 49.9 93.3 10.9 0.4 33.5 6.8 297.1 452.3 6686 6.8
04·05 3,6 252.7 49.9 96.6 10.9 0.4 33.5 6.8 297.1 454.4 6751 6.7
05-06 3.6 302.6 59.7 99.6 10.9 0.4 33.5 6.8 347.0 517.1 6CJl 7 7.6
06-07 3.6 302.6 59.7 102.7 10.9 0.4 33.5 6.8 347.0 520.2 6882 7.5
07-08 3.6 302.6 59.7 105.8 10.9 0.4 33.5 6.8 347.0 523.3 6948 7.5
08-09 3.6 302.6 59.7 108.9 10.9 0.4 33.5 6.8 347.0 526.4 7013 7.5
09-10 3.6 302.6 59.7 112.1 10.9 0.4 33.5 6.8 347.0 529.6 7079 7.5
lO-1l 3.6 302.6 59.7 115.4 10.9 0.4 33.5 6.8 3117.0 532.9 7\44 7.5
)))
'))
TABLE---i:l.Anchorage-Cook Inlet Area.Low Load Growth Scenario.Case 1,5%Inflation
New Ilydroelectric Transmission
Total.cost _~~.J:oallJ!:£.iLCapac!!L_Costs __._2Ystems Total Total lota 1 Sys tem
of Existing Investment OH&R Coal lnves tmentOM&R Investment OM&R Investment System Consumption,Average Power
_Year _~~illL Costs Cos~Costs ~Costs._.D!ili _.fo sts__Costs Costs fasts,$I-lMKWH Costs.C/KWH
78-79 29.7 ---"'-----------0.7 0.4 ---30.8 2376 1.3
79-80 39.1 ------------0.7 0.4 -.-40.1 2568 1.6
1
80-81 45.7 ---_..----------0.7 0.4 ---46.8 2706 1.7
81-62 47.9 ---------------0.7 0.5 --.49.1 2650 1.7
62-63 59.5 ------3.1 ------0.7 0.5 ---63.9 2991 2.1
63-84 63.6 ------3.3 ------0.7 0.5 ---68.1 3132 2.2
j
ll4-65 68.7 _.----3.3 ------0.7 0.5 ---73.3 3273 2.2
85-86 68.9 2.0 0.4 3.6 14.6 0.6 0.7 0.5 17.5 90.8 3433 2.6
I 66-87 69.8 2.0 0.4 3.9 14.8 0.6 0.7 0.5 17 .5 92,7 3594 ~.6
87-98 67.1 46.6 9.2"7.3 14.0 •0.6 24.1 5.4 65.5 175.2 3754 4.7
86-89 60.6 46.6 9.7 11.1 14.6 0.6 24.1 5.7 65.5 173.2 3915 4.4
89-90 56.4 95.7 19.9 20.1 14.6 0.7 24.1 6.0 134.6 237.8 4075 5.8
90-91 52.5 95.7 20.9 28.6 14.8 0.7 24.1 6.3 134.6 243.6 4285 5.7
91-92 49.6 111.1 24.0 35.2 14.0 0.7 24.1 6.6 150.0 267.2 4495 5.9
"-J
'-D 92-93 47.4 168.0 37.4 48.4 14.6 0.6 2U 6.9 206.9 347.8 4705 7.4.
61.3 24.1 362.0 491593-94 46.5 168.0 39.2 14.8 0.1:1 7.3 206.9 7.4
94-95 46.5 230.7 51.6 77.9 14.8 0.9 24.1 7.7 269.6 456.2 5125 6.9
95-96 43.8 296.5 67.3 92.2 14.8 0.9 24.1 8.1 335.4 547.7 5385 10.2
96-97 36.3 416.7 94.3 108.6 14.8 0.9 24.1 8.5 455.6 704.2 564f.12.5
97-98 37.7 416.7 99.0 122.6 14.8 1.0 24.1 8.0 455.6 724.8 5904 12.3
S8-99 37.5 416,7 103.9 138.4 lUI 1.0 24.1 9.3 455.6 ·745.7 6164 12.1
99-2000 31.7 555.8 136.4 ,156.6 14.8 1.1 68.3 18.4 638.9 983.1 6424 15.3
00·01 16.7 555.8 143.3 172.0 14.8 1,1 68.3 19.3 638.9 991.3 6498 15.3
01-02 15.3 555.8 lSO.4 186.5 14.8 1.2 60.3 20.3 636.9 1012.6 6555 15.4
02-03 5.4 555.8 157.9 204.8 H.ll 1.3 6B.3 21.3 638.9 1029.6 6620 15.5
03·04 5.5 555.0 165.0 221.6 14.8 1.3 68.3 22.4 636.9 1055.5 6686 15.8
04-05 3.6 555.8 174.1 240.4 14.8 1.4 68.3 23.5 638.9 1081.9 6751 16.0
05-06 3.7 742.3 219.4 259.11 14.8 1.5 68.3 24.6 825.4 1334.4 6817 19.6
06-07 3..9 742.3 230.4 280.8 14.8 1.5 66.3 25.9 825.4 1367.9 6882 19.9
07-08 4.0 742.3 241.9 303.6 14.8 1.6 68.3 27.2 825.4 1403.7 6948 20.2
08-09 4.1 742.3 254.0 '328.2 14.6 1.7 68.3 211.5 825.4 1441.9 7013 20.6
09-1O 4.2 472.3 266.7 354.6 14.8 1.8 68.3 30.0 825.4 1462.7 7079 20.9
10-11 4.4 742.3 200.1 382.9 14.8 1.9 68.3 31.5 825.4 1526.2 7144 21.4
LABlE U·Anchorage-Cook Inlet Area.Low Load Growth Scenario.Case 2.0%Inflation
New Ilydroelectrlc Transmission
Total \fast New Coal f1 red Ca~1 ty Costs ~ems Total Total Total System
of Existing Investment 'OM&R-COar-ro~ve5tmenr-OH&JC tnvestment--OFi&R Investment System Consumption.Average Power
Year _Capacity ~~Costs Costs__foSll_fQ.Ul Costs fQili..Costs Costs,$MNKIJIi Costs,¢/KWlj
76-79 33.1 ...--------------0.6 0.4 ---34.1 2376 1.4
79-80 42.2 ---------------0.6 0.4 ---43.2 2568 1.7
80-81 48.2 ---------------0.6 0.4 ---49.2 2706 1.8
81-82 52.8 --------- ------0.6 0.4 ---53.8 2850 1.9
82-83 61.1 ------3.1 .-----0.6 0.4 ---65.3 2991 2.2
83-B4 62.0 _.----3.3 ------0.6 0.4 -.-.66.3 3132 2.1
84-85 66.7 ------3.3 ------0.6 0.4 ---71.1 3273 2.2
85-86 66.7 1.3 0.2 3.6 10.9 0.4 0.6 0.4 12.8 84.1 3433 2.4
86-87 67.2 \.3 0.2 3.7 10.9 0.4 0.6 .0.4 12.8 84.8 3594 2.3
81-B8 66.4 30.0 5.9 6.7 10.9 0.4 17.1 3.6 58.0 141.0 3754 3.7
8£1-89 59.0 30.0 5.9 9,6 10.9 0.4 17.1 3.6 58.0 136.6 3915 3.5
89-90 54.5 58.7 11.6 16.6 10.9 0.4 17.1 3.6 86.7 173.4 4075 4.2
90-91 50.2 58.7 11.6 22.5 10.9 0.4 17.1 3.6 86.7 175.0 4285 4.1
91-92 41.1 66.8 13.2 26.6.10.9 0.4 17.1 3.6 94.8 185.7 4495 4.1
OJ
0 92-93 42.4 95.5 18.9 34.5 10.9 0.4 17 .1 3.6 123.5 223.3 4705 4.7
93-94 38.9 95.5 IB.9 41.9 10.9 0.4 17:1 3.6 123.5 227.2 4915 4.6
94-95 39.4 95.5 18.9 46.3 10.9 0.4 35.9 5.6 142.3 252.4 5125 4.9
95-96 34.5 124.2 24.6 55.3 10.9 0.4 35.9 5.6 171.0 290.9 5305 5.4
96-97 28.3 152.9 30.3 64.1 10.9 0.4 35.9 5.6 199.7 :127 .9 5645 5.8
97-98 25.4 202.8 40.1 69.2 10.9 0.4 35.9 5.6 249.6 389.8 5904 6.6
98-99 27.4 202.8 40.1 74.1 10.9 0.4 35.9 5.6 249.6 396.7 6164 6.4
9'1-2000 22.6 202.5 40.1 flO.4 10.9 0.4 35.9 5.6 249.6 397.9 6424 6.2
00-01 12.2 252.7 49.9 83.8 10.9 0.4 52.4 8.8 316.0 470.6 6489 7.2
01·02 11.0 252.7 49.9 86.9 10.9 0.4 52.4 8.8 316.0 412.5 6555 7.2
02-03 4.8 525.1 49.9 90.4 10.9 0.4 52.4 8.8 Ji6 ..0 469.8 6620 7.1
OJ-04 4.8 252.7 49.9 93.4 10.9 0.4 52.4 8.8 316.0 412.8 •6686 7.1
04-05 3.6 252.7 49.9 96.6 10.9 0.4 52.4 8.8 316.0 474.8 6751 7.0
05-06 3.6 525.7 49.9 99.6 10.9 0.4 52.4 8.8 J16.0 477 .9 6017 7.0
06-07 3.6 252.7 49.9 99.6 10.9 0.4 52.4 8.8 316.0 480.9 6882 7.0
01-08 3.6 252.7 49.9 105.7 10.9 0.4 52.4 8.8 316.0 484.0 6948 7.0
08-09 3.6 252.7 49 ..9 108.9 10.9 0.4 52.4 8.8 316.0 487.1 7013 6.9
09-10 3.6 252.7 49.9 112.1 10.9 0.4 52.4 8.8 316.0 490.3 7079 6.9
10-11 3.6 252.7 49.9 115.4 10.9 0.4 52.4 8:8 316.0 493.6 7144 6.9
))).,
')))
TABLE_4.4.Anchorage-Cook Inlet Area,Low Load Growth Scenario,Case 2,5%Inflation
New IlYdroe1ectrtc Transm!5S ton
Total Cost New Coal ft'ml capac~'!y'Costs ~s Total Total Total System
of Existing Tii'ilestmenr--OJ;oa~lovestment-OM11C Trlvestment -liJf&R Investment System Consumption.Average Power
-!lli-Capact ty Costs £2sts Cos~_Cost_s~f.~_C!lS~Costs COsts Cos 15 •$-'1':!~Costs,¢/K"'~
78-79 29.7 ---------------0.7 0.4 ---30.8 2376 1.3
79·80 39.1 ------------0.7 0.4 ---40.1 2566 1.6
80·81 45.7 ------------_..0.1 0.4 ---46.8 2706 1.7
81-82 47.9 ---------------0.7 0.5 ---49.1 2850 1.7
82-83 59.5 ------3.1 ------0.7 0.5 ---63.9 2991 2.1
83-84 63.6 ------3.3 ------0.7 0.5 ---68.1 3132 2.2
84-65 68.7 ------3.3 -----.0.7 0.5 ---73.3 3273 2.2
65-86 68.9 2.0 0.4 3.6 14.8 0.6 0.7 0.5 17.5 90.8 3433 2.6
86-87 69.8 2.0 0.4 )(14.8 0.6 0.7 0.5 17 .5 92.7 3~94 2.f>
81-88 6'7'.1 46.6 9.2 7.J 14.8 0.6 24.1 5.4 85.5 175.2 3754 4:7
88-69 60.6 46.6 9.7 11.1 14.6 0.6 ,24.1 5.7 85.5 '173.2 3915 4.4
89-90 56.4 95.7 19.9 20.1 14.8 0.7 24.1 6.0 134.6 237.8 4075 5.8
90·91 52.5 95.7 20.9 23.6 14.6 0.7 24.1 6.3 134.6 243.6 4285 5.7
91-92 49.8 111.1 24.8 35.2 14.6 0.7 24.1 6.6 150.0 267.2 4495 5.9
CO 92-')3 47.4 Hi8.0 37.4 43.4 14.8 0.8 24.1 6.9 206.9 347.8 4705 7.4......
93-94 46.5 166.0 39.2 61.3 14.8 0.8 24.1 7.3 206.9 362.0 4915 7.4
94-95 48.5 168.0 39.3 71.2 14.8 0.9 63.6 9.7 246.4 416.0 5125 8.1
95-96 43.8 233.C1 54.4 89.5 14.8 0.9 63.6 10.3 312.2 511.1 5385 9.5
96-97 36.3 302.9 70.8 108.6 14.8 0.9 63.6 10.8 381.3 603.7 5645 10.8
97-98 37.7 429.1 99.1 122.6 14.8 1.0 63.6 11.3 507.5 779.2 5904.13.2
93-99 37.5 429.1 104.1 138.4 14.8 1.0 63.6 11.9 507.5 800.4 6164,13.0
99-2000 31.1 429.1 109.3 156.6 14.8 1.1 63.6 12.5 501.5 818.7 '6424 12.7
00-01 16.7 575.2 143.4 172.0 14.8 1.1 110.0 22.1 700.0 1055.3 6489 16.3
01-02 15.3 575.2 150.6 106.4 14.8 1.2 110.0 23.2 700.0 1076.7 6555 16.4
02-03 5.4 575.2 158.1 204.9 14.8 1.3 110.0 24.4 700.0 1094.1 6620 16.5
03-04 5.5 575.2 166.1 221.6 ,14.{j 1.3 110.0 25.6 700.0 1120.1 6666 16.7
04·05 3.6 575.2 174.4 240.4 1Ul 1.4 110.0 26.9 700.0 1146.7 6751 17.0
OS-Of!3.7 575.2 183.1 259.8 14.8 1.5 110.0 28.2 700.0 1176.3 6817 17 .2
06·07 3.9 575.2 192.2 280.8 14.8 1.5 110.0 29.6 700.0 1208.0 6882 17.5
07-08 4.0 575.2 201.8 303.6 14.0 1.6 110.0 31.1 700.0 1242.1 6948 17.9
08-09 4.1 575.2 211.9 320.2 14.8 1.7 110.0 32.7 700.0 1278.6 7013 18.2
09-10 4.2 575.2 222.5 354.6 14.0 1.8 110.0 34.3 700.0 1317 .4 7079 10.6
10-11 4.4 575.2 233.7 302.9 14.8 1.9 110.0 36.0 700.0 1358.9 7144 19.0
TABLE 4.5.Anchorage-Cook Inlet Area,Low Load Growth Scenario,Case 3,0%Inflation
New lIydroelectrlc Transmission
Total Cost ~'1....r;Q!!l!..!!ed QQ!!f.!!Y__Costs _~stems Total Total Total System
of Existing Investl/lent OM&R Coa 1 Inves tment-~OM&1f-Investment OM&R Investment System Consumption.Average Power
..J!!!.L..Capac!ty Costs Costs ~~CostL._£Qrti ~!.L..~Costs Costs,$_~.!:!!L_Costs~
78-79 33.1 ---------------0.6 0.4 ---34.1 2316 1.4
79-80 42.2 ---------------0.6 0.4 ---43.2 2568 1.7
80-81 48.2 --------.------0.6 .0.4 ---49.2 2706 1.8
81-132 52.8 ----.----------0.6 0.4 ---53.6 .2850 1.9
82-83 61.1 -.----3.1 ---.--0.6 0.4 ---65.3 2991 2.2
83-84 62.0 ------J.3 ------0.6 0.4 ---66.3 3132 2.1
84·65 66.7 -----.3.3 ---,--0.6 0.4 ---71.1 3273 2.2
85-86 66.7 1.3 0.2 3.6 10.9 0.4 0.6 0.4 12.8 84.1 3433 2.4
86-87 67.2 1.3 0.2 3.7 10.9 0.4 0.6 0.4 12.8 84.8 3594 2.3
87-88 66.4 30.0 5.9 6.7 10.9 0.4 17 .1 3.6 58.0 141.0 3754 3.7
89-89 59.0 30.0 5.9 9.6 10.9 0.4 17 .1 3.6 58.0 136.6 3915 3.5
89-90 54.5 58.7 11.6 16.6 10.9 0.4 17.1 3.6 86.7 173.4 4075 4.2
90-91 50.2 58.7 11.6 22.5 10.9 0.4 17 .1 3.6 86.7 175.0 4285 4.1
CO 91-92 47.1 66.8 13.2 26.6 10.9 0.4 35.9 5.6 113.6 206.0 4495 4.6
N 92-93 42.4 66.8 13.2 30.3 10.9 0.4 35.9 5.6 113.6 205.0 4705 4.4
93-94 38.9 95.5 HI.9 38.9 10.9 0.4 35.9 5.6 142.3 244.5 4915 5.0
94-95 39.4 95.5 13.9 20.6 155.9 1.0 35.9 5.6 287.3 372.3 5125 7.3
95-96 34.5 95.5 111.9 21.6 155.9 1.0 35.9 •5.6 287.3 368.4 5385 6.8
96-97 28.3 95.5 18.9 27.9 155.9 1.0 35.9 5.6 207.3 368.5 5645 6.5
97-98 25.4 .95.5 111.9 32.2 155.9 1.0 35.9 5.6 287.3 369.9 5904 6.3
98-~9 27.4 95.5 18.9 26.4 155.9 1.0 35.9 5.6 287.3 376.1 6164 6.1
99-2000 22.6 95.5 18.9 7.9 204.2 1.6 35.9 5.6 335.6 391.7 6424 6.1
llO-Ol 12.2 95.5 18.9 B.O 204.2 1.6 35.9 5.6 335.6 3B1.4 6489 5.9
01-02 11.0 95.5 18.9 IJ.1 204.2 1.6 35.9 5.6 335.6 380.3 6555 5.6
02-03 4.8 95.5 111.9 9.3 204.2 1.6 35.9 5.6 335.6 375.3 6620 5.7
03·04 4.8 95.5 18.9 10.6 204.2 1.6 35.9 5.6 335.6 376.6 6686 5.6
0~-05 3.6 95.5 10.9 12.0 204.2 1.6 35.9 5.6 335.6 376.6 6751 5.6
05-06 3.6 95.5 18.9 13.2 204.2 1.6 35.9 5.6 335.6 378.0 6817 5.5
G6·07 3.6 95.5 IM.9 14.6 204.2 1.6 35.9 5.6 335.6 379.4 6692 5.5
07-06 3.6 95.5 18.9 16.0 204.2 1.6 35.9 5.6 335.6 380.8 6948 5.5
08·09 3.6 95.5 18.9 17 .4 204.2 1.6 35.9 5.6 335.6 382.2 7013 5.4
09-10 3.6 95.5 18.9 18.9 204.2 1.6 35.9 5.6 335.6 383.7 7079 5.4
10-11 3.6 95.5 18.9 20.4 204.2 1.6 35.9 5.6 335.6 385.2 7144 5.4
»
-)
TABLE 4.6.Anchorage-Cook Inlet Area;Low Load Growth Scenario.Case 3;5%Inflation
New Hydroelectric·Transmfssion
Total Cost New Coal FlredCapacftir--Costs S.1s tems Total Total Total System
of Existing TilvestmeiitoM&R COa Tnves tmentoM&R Investment OM&R·Inves tillent System Consumption.Average Power
~Capacity Costs Costs Costs Costs Costs
Costs _Costs Costs Costs,$MMKWH Costs.II/KWH-.-
78-79 29.7 ---------------0.7 0.4 ---30.8 2376 1.3
79-80 39.1 ---------0_---0.7 0.4 ---40.1 2568 1.6
80-81 45.7 ---------------0.7 0.4 ---46.8 2706 1.7
81-82 47.9 ----~!I'---------0.7 0.5 -_.-49.1 2850 1.7
82-83 59.5 ----..3.1 ------0.7 0.5 ---63.9 2991 2.1
83-84 63.6 ------3.3 ------0.7 0.5 ---6B.l 3132 2.2
84-85 68.7 .......----3.3 ------0.7 0.5 ---73.3 3273 2.2.
85-86 6B.9 2.0 0.4 3.6 14.B 0.6 0.7 0.5 17 .5 90.8 3433 2.6
86-87 69.3 2.0 iJ.4 3.9 14.8 0.6 0.7 0.5 17 .5 92.7 3594 2.6
B7-8e 67.1 46.6 9.2 7.3 14 ..8 0.6 24.1 5.4 85.5 175.2 3754 4.7
88-89 60.6 46.6 9.7 11.1 14.a 0.6 24.1 5.7 85.5 173.2 3915 4.4
89-90 56.4 95.7 19.9 20.1 14.8 0.7 24.1 6.0 134.6 237.8 407S 5.B
90-91 52.5 95.7 20.9 28.6 14.8 0.7 24.1 6.3 134.6 243.6 4285 5.7
91-92 49.8 111.1 24.8 35.3 14.8 0.7 58.2 8.4 184.1 303.1 4495 6.7
COw 92-93 47.4 111.1 26.1 42.5 14.8 0.8 58.2 8.8 184.1 309.7 4705 6.6
93-94 46.5 170.a 29.2 56.9 14.8 0.8 58.2 9.3 243.8 396.5 4915 8.1
94-95 48.5 170.8 41.1 31.7 319.9 2.1 58.2 9.7 548:9 682.0 5125 13.J
9S-96 43.8 110.8 43.2 35.0 319.9 2.2 50.2 10.2 548.9 633.3 5385 12.7
96-97 3&.3 170.8 45.4 47.4 319.9 2.3 56.2 10.7 54B.9 691.0 5645 12.2
97-96 37.7 170.8 47.6 56.9 319.9 2.4 5n.2 11.3 54B.9 704.8 5904 11.9
98-99 37.5 170.8 ~O.O 68.1 319.9 2.5 68.2 11.8 548.9 718.8 6164 11.7
99-2000 31.7 170.8 52.5 15.4 449.7 4.2 58.2 12.4 67B.7 794.9 6424 12.4
00-01 16.7 170.8 55.0 16.3 449.7 4.5 58.2 13.5 678.7 784.8 5489 12.1
01-02 IS.3 170.8 57.9 17.4 449.7 4.7 5fU 13.7 678.7 787.7 6555 12.0
02-03 5.4 170.6 60.8 21.2 449.7 4.9 S8.2 14.4 678.7 765.4 6620 11.9
03-04 5.5 170.8 63.8 25.1 449.7 5.2 511.2 15.1 6711.7 793.4 6666 11.9
04-05 3.6 170.8 67.0 29.9 449.7 5.4 58.2 15.9 670.7 BOO.5 6751 11.9
05-06 3.7 17Q.a 70.4 34.3 449.7 5.7 56.2 16.7 670.7 809.5 6816 11.9
06·07 3.9 170.6 73.9 40.0 449.7 6.0 58.2 17.5 678.7 B20.0 6882 11.9
07-08 4.0 170.8 77 .6 45.9 449.7 6.3 5f!.2 16.4 678.7 830.9 6948 11.9
08-09 4.1 170.8 81.5 52.4 449.7 6.6 5i1.2 19.3 678.7 842.6 7013 12.0
09-10 4.2 170.8 8li.5 59.7·449.7 6.9 58.2 20.2 676.7 1155.2 7079 12.1
10-11 4.4 170.8 89.8 67.~449.7 7.3 58.2 21.3 676.7 669.0 7144 12.2
TABLE 4.7.Anchorage-Cook Inlet Area.Medium Load Growth Scenario,Case 1.0%Inflation
New IIydroelectrfc Transm1 ss 10n
Total Cost _New Coa.t.f.!red cupac1_~_Costs Systems Total Total Total System
of Ex1stfng 1nvestment OM&R Coa Investment OM&R lilves tment OM&R Investment System Consumption.Average Power
-.!lli.-CapacHy Costs CosU Costs Cosls f~Cosh Costs Costs Costs,$MMKWH Costs.¢/KWH
7B-79 33.1 ---------------.6 .4 ---34.1 2531 1.3
79-BO 42.2 ---------------.6 .4
_.-.43.2 2801 1.5
80-Bl 48.2 ---------'_..----.6 .4 ---49.2 3041 1.6
81-82 52.8 ---------.-----.6 .4 ---53.8 3281 1.6
82-83 61.1 28.1 5.7 6.5 ------.6 .4 29.3 103.0 3521 2.9
83-84 62.0 28.1 5.1 9.2 ------.6 .4 29.3 106.6 3761 2.8
04-85 66.7 28.7 5.7 11.8 ------.6 .4 29.3 114.0 4001 2.8
85-06 66.7 58.7 11'.6 10.5 10.9 .4 17.1 3.6 06.7 107.6 4329 4.3
86-87 67.2 58.7 11.6 24.19 10.9 ..4 17.1 3.6 fJ6.7 193.7 4657 4.2
87-0B"66.4 87.4 17 .3 29.9 10.9 0.4 17 .1 3.6 .115.4 233.0 4985 4.7
88-89 59.0 87.4 17.3 36.2 10.9 0.4 17 .1 3.6 115.4 231.9 5313 4.4
89-90 54.5 116.1 23.0 46.4 10.9 0.4 17.1 3.6 144.1 272.0 5641 4.B
90-91 50.2 116.1 23.0 52.9 10.9 0.4 17.1 3.6 144.1 274.2 6063 4.5
91-92 47.1 152.9 30.3 61.9 10.9 0.4 17.1 3.6 100.9 324.2 6485 5.0
CO 92-93 42.4 202.8 40.1 70.2 10.9 0.4 17.1 3.6 230.8 387.5 6907 5.6-Po
93-94 38.9 202.8 40.1 77 .9 10.9 0.4 17.1 3.6 230.8 391.7 7329 5.3
94-95 39.4 202.8 40.1 114.6 10.9 0.4 17.1 3.6 230.8 39fJ.9 1751 5.1
95-96 34.5 252.7 49.9 g.,6 10.9 0.4 17.1 3.6 2fJO.7 463.7 8311 5.6
96-97 28.3 302.6 59.7 106.8 10.9 0.4 33.5 6.8 341.0 549.0 llll71 6.2
97-9B 25.4 352.5 69.5 116.9 10.')0.4 33.5 6.fJ 396.9 615.9 9431 6.5
98-99 27.4 J53.5 69.5 126.7 10.9 0.4 33.5 6.8 396.9 627.7 9991 6.3
99-2000 22.6 402.4 79.3 130.5 10.9 0.4 33.5 6.6 446.8 694.4 10551 6.6
00-01 12.2 402.4 79.3 146.3 .10.9 0.4 33.5 6.8 446.ll 691.8 10863 6.4
01-02 11.0 402.4 79.3 IS·!.3 10.9 0.4 33.5 6.8 446.8 698.6 11175 6.3
02·03 4.8 452.3 B9.1 162.5 10.9 0.4 33.5 6.8 496.7 760.3 114117 6.6
03-04 4.8 452.3 89.1 170.7 10.9 0.4 33.5 6.8 496.7 767.9 11799 6.5
04-05 3.6 452.3 89.1 179.4 10.9 0.4 33.5 6.8 496.7 716.0 12111 6.4
05-06 3.6 502.2 9£\.9 108.0 10.9 0.4 50.0 10.0 563.1 864.0 12423 6.9
06-07 3.6 502.2 90.9 196.0 10.9 0.4 50.0 .10.0 563.1 072.8 12735 6.8
07-08 3.6 502.2 9ll.9 205.9 10.9 0.4 50.0 10.0 563.1 fJ81.9 13047 6.8
08-09 3.6 502.2 9ll.9 215.1 10.9 0.4 50.0 10.0 563.1 B91.1 13359 6.7
09·]0 3.6 502.2 98.9 224.6 10.9 0.4 50.0 10.0 563.1 901.6 13671 6.6
10-11 3.6 552.1 106.7 234.2 10.9 0.-1 50.0 10.0 613.0 969.9 139B3 6.9
))J
)
TJ\BLE 4.8.Anchorage-Cook Inlet Area,Medium Load Growth Scenario.Case 1,5%Inflation
----~"
Total Cost
New Hydroelectric Transml ss Ion
New Coa 1 !'Ired Capacl ty Costs Systems 0 Total Total Total System
of Existing Jnvestment oiiiR-Coa'--Investment OHIR "Investment ""MAR Investment Systetn Consumption,Average Power
~"~~Costs ~~ll.Costs ~~illL-.Costs ~tL-£!im Costs Costs l $I'J~KWH Costs l UI(WH
78-79 29:7 ---------------0.7 0.4 ---30.8 2531 1.2
79-80 39.1 ---------...~"---0.7 0.4 ---40.2 2801 1.4
80-81 45.7 ---------------0.7 0.4 ---46.8 3041 1.5
81-82 47.9 ---------------0.7 0.5 ---49.1 3281 1.5
62-63 59.5 34.9 6.9 6.5 ------0.7 0.5 35.6 109.1 3521 3.1
83-84 63.6 34.9 7.2 9.2 -----0.7 0.5 35.6 116.1 3761 3.1
84-85 68.7 34.9 7.6 11.8 ._----0.7 0.5 35.6 124.3 4001 3.1
85-86 68.9 77.3 16.4 18.1 14.6 0.6 23.0 4.9 115.1 .224.0 4329 5.2
86-87 69.8 77.3 17.2 25.3 14.0 0.6 23.0 5.1 115.1 233.2 4657 5.0
87-88 67.1 121.9 26.8 32.7 14.8 0.6 23.0 5.4 159.7 292.3 4985.5.9
60.6 121.9 211.2 14.8 23.0 5.7 159.7 296.5
.
68-89 41.6 0.6 5313 5.6
89-'90 56.4 171.0 39.3 56.3 14.8 0.7 23.0 6.0 208.8 367.5 5641 6.5
90-91 52.5 171.0 41.3 67.3 14.8 0.7 23.0 6.3 20B.8 376.9 6063 6.2
91-92 49.8 240.6 56.9 82.2 14.0 0.7 23.0 6.6 278.4 474.6 6485 7.3
OJ 47.4 339.5 90.60192-93 79.2 •14.8 0.8 23.0 6.9 377 .3 608.6 6907 8.8
93·94 46.5 339.5 83.2 1'13.9 14.8 0.3 23.0 7.2 377 .3 628.9 7329 8.6
94~95 48.5 339.5 87.3 130.1 14.8 0.9 23.0 7.6 377 .3 659.3 7751 8.5
95-96 43.8 454.0 114.2 153.3 14.8 0.9 23.0 8.0 491.8 B12.0 6311 9.7
96-97 36.3 574.2 143.5 160.8 14.8 0.9 63.0 16.0 652.0 1029.5 6871 11.6
97-98 37.7 700.4 175.5 207.2 14.8 1.0 63.0 16.6 778.2 1216.2 9431 12.9
98-99 37.5 700.4 184.2 236.7 14.8 1.0 63.0 17.4 778.2 1255.0 9991 12.6
99-2GOO 31.8 839.5 220.8 269.7 14.8 1.1 63.0 18.3 917.3 1459.0 10551 113 .8
00-01 16.7 839.5 231.8 300.2 14.11 1.1 63.0 19.2 917.3 1486.3 10863 '13.7
01-02 15.3 839.5 243.4 331.2 14.8 1.2 63.0 20.2 917.3 1528.6 11175 13.?
02-03 5.4 1000.6 207.2 368.3 14.8 1.3 63.0 21.2 1078.4 1761.B 11487 15.3
5.5 1000.6 .301.5 405.2 14.8 1.3 63.0 22.2 1078.4 1814.1 11799 15.403-04
04-05 3.6 1000.6 316.6 446.6 14.8 1.4 63.0 23.3 1070.4 1069.9 12111 15.4
05-06 3.7 1107.1 369.0 490.4 14.8 1.5 116.7 34.9 1319.6 2218.1 12423 17 .8
06-07 3.9 1187.1 387.5 53(\.4 14.0 1.5 116.7 36.6 1318.6 2286.5 12735 17 .9
07-08 4.0 1187.1 406.8 590.9 14.0 1.6 116.7 3a.5 1318.6 2360.4 13047 18.1
08 ..09 4.1 1181.1 427.2 648.1 14.8 1.7 116.7 40.4 1318.6 2440.1 13359 18.3
09-10 .4.2 1181.1 448.5 71 0.1 14.8 1.8 116.7 42.4 1318.6 2525.6 13671 18.5
10-11 4.4 1425.1 517.7 777.3 14.8 1.9 116.7 44.6 1556.6 2902.5 13983 20.7
TABLE 4.9.Anchorage-Cook Inlet Area.Medium Load Growth Scenario,Case 2,0%Inflation
----~
Total C~st :.;New f1ydroe1ectrlc TransmissIon
New Coal fired Capa~1tl---Costs Systems Total Total Total System
of Existin9 Investment Or~&R Coal Investment OM&R Investment OM&R Investment System ConsumptIon.Average Power
~Capacity Costs fQill Costs Costs fllil Costs_Costs ~-Costs I $MMKWIt Costs I ¢/KWtJ
78-79 33.1 ------.0._0-._-0.6 0.4 ---34.1 2531 1.3
H-BO 42.2 ---------------0.6 0.4 ---43.2 2801 1.5
60-81 48.2 .-.------------0.6 0.4 ---49.2 3041 1.6
81-B2 52.3 ---------._----0.6 0.4 ---53.8 3281 1.6
82-133 61.1 28.7 5,7 6.5 ------0.6 0.4 29.3 103.0 3521.2.9
83-84 62.0 28.7 5.7 9.2 ------0.6 0.4 29.3 106.6 3761 2.8
lJ4-85 66.7 28.7 5.7 11.8 ---._.0.6 0.4 29.3 114.0 4001 2.8
85-86 66.7 50.7 11.6 18.5 10.9 0.4 17 .\3.6 1J6.7 187.6 4329 4.3
86-87 67.2 58.7 11.6 24.19 10.9 0.4 17 .1 3.6 86.7 193.7 4657 4.2
87-88 66.4 87.4 17.3 29.9 10.9 0.4 17 .1 3.6 115.4 233.0 4985 4.7
IlS-89 59.0 87.4 17.3 36.2 10.9 0.4 17 .1 3.6 115.4 231.9 5313 4.4
89-90 54.5 87.4 17.3 42.5 10.9 0.4 35.9 5.6 134.2 254.5 5641 4.5
90-91 50.2 116.1 24.6 50.1 10.9 0.4 35.9 5.6 162.9 293.8 6063 4.8
91-92 47.1 152.9 31.9 59.1 10.9 0.4 35.9 5.6 199.7 343.8 .6485 5.3
co
0)92-93 42.4 202.8 41.7 70.2 10.9 0.4 35 ..9 5.6 249.6 409.9 6907 5.9
93-94 38.9 202.8 4].7 77.9 10.9 0.4 35.9 5.6 249.6 414.1 7329 5.6
94-95 39.4 202.6 41.7 84.6 10.9 0.4 35.9 5.6 249.6 421.3 7751 5.4
95-96 34.5 252.7 51.5 94.6 10.9 0.4 35.9 5.6 299.5 486.1 6311 5.0
96-97 28.3 302.6 61.3 106.8 10.9 0.4 52.4 8.8 365.9 571.5 8U7l 6.4
97-98 25.4 302.6 61.3 116.9 10.9 0.4 52.4 8.8 365.9 578.7 9431 6.1
98-99 27.4 352.5 71.1 126.7 10.9 0.4 52.4 6.8 415.0 650.2 9991 6.5
99~2000 22.6 352.5 71.1 138.5 10.9 0.4 52.4 8.8 415.8 657.2 10551 6.2
00-01 12.2 402.4 80.9 146.3 10.9 0.4 52.4 8.8 465.7 714.3 10863 6.6
01-02 11.0 402.4 00.9 154.3 10.9 0.4 52.4 0.0 465.7 721.1 11175 6.4
02-03 4.8 402.4 00.9 162.5 10.9 0.4 52.4 ·8.8 465.7 723.1 11487 6.3 .
03-0~3.6 452.3 90.1 110.7 10.9 0.4 52.4 0.8 515.6 789.8 11799 6.7
04-05 3.6 452.3 90.7 179.4 10.9 0.4 52.4 8.8 515.6 798.5 12111 .6.6
05-06 3.6 452.3 90.7 lB8.0 10.9 0;4 52.4 8.6 515.6 Il07.I 12423 6.5
06-07 3.6 452.3 90.1 196.8 10.9 0.4 52.4 6.6 515.6 815.9 12735 6.4
07-08 3.6 502.2 100.5 205.9 10.9 0.4 66.9 12.0 582.0 904.4 13047 6.9
08-09 3.6 502.2 100.5 Z15.1 10.9 0.4 68.9 12.0 582.0 913.6 13359 6.8
09-10 3.6 502.2 100.5 224.6 10.9 0.4 68.9 12.0 Sill.0 923.1'13671 6.7
10-11 3.6 &02.2 100.5 234.2 10.9 0.4 68.9 12.0 51l2.a 932.7 13903 6.7
c.))
i;.
))
TABLE 4.10.Anchorage-Cook Inlet Area,Medium Load Growth Scenario,Case 2,5%Inflation--------
New Ilydroe 1ectrl c Transmission
Total Cost New Coal fired caeac~ty Costs ~stems Total Total Total System
of Existing InvesTmeiituFlm-oar lnVes tmentUJ1&r Tilves tmeii-t-OOll Investment System ConsumptIon,Average Power
.1lli-Capac1 t.y Cos ts Cost~CostL_Costs -,~Costs Costs Costs Costs,$~--Costs,¢/KIIII_
78-79 29.7 ---------------0.7 0:4 ---30.8 2531 1.2
79-80 39.1 ------------0.7 0.4 ---40.2 2801 1.4
80-81 45.7 -------_.-------0.7 0.4 ---46.8 3041 1.5
81-82 47.9 ---------""",-,".---..0.7 0.5 ---49.1.3281 1.5
B~-83 59.5 34.9 6.9 6.5 ------0.1 0.5 35.6 109.1 3521 3.1
83-84 63.6 34.9 7.2 9.2 -----0.7 0.5 35.6 116.1 3761 3.1
84-85 68.7 34.9 7.6 11.8 ------0.7 0.5
35.6 124.3 4001 3.1
85-86 68.9 77.3 16.4 18.1 14.3 0.6 23.0 4.9 115.1 224.0 4329 5.2
B6-ill 69.8 77.3 l7.2 25.3 14.8 0.6 23.0 5.1 115.1 233.2 4657 5.0
87-6!!67.1 H1.9 26.8 32.7 14.8 0.6 23.0 5.4 159.7 292.3 4985'5.9
8tl-89 60.6 121.9 28.2 41.6 14.8 0.6 23.0 5.7 159.7 296.5 5313 5.6
89-90 56.4 121.9 29.6 51.5 14.8 0.7 ,53.9 9.3 190.6 333.1 5641 6.0
90-9)52.5 173.5 41.3 63.7 14.8 0.7 53.9 9.7 242.2 410.1 6063 6.8
(Xl 91-92 49.8 243.1 56.9 70.3 14.8 0.7 53.9 10.2 311.8 507.8 6485 7.8
--.J 92-93 47.4 342.0 79.2 98.5 '14.8 0.8 53.9 10.7 410.7 647,4 6907 9.4
93-94 46.5 342.0 83.2 113.8 14.8 0.8 53.9 11.3 410 .-7 666.4 1329 9.1
94-95 48.5 342.0 87.3 130.1 14.0 0.9 53.9 11.8 410.7 689.3 7151 8.9
95-96 43.8 465.5 .114.2 153.3 14.8 0.9 53.9 12.4 534.2 858.8 8311 10.3
96-97 36.5 576.7 143.5 180.8 14.8 0.9 93.9 20.9 685.4 1067.8 8871 12.0
97-98 37.7 576.7 150.6 207.1 14.8 1.0 93.9 21.9 685.4 1103.8 9431 11.7
98-99 37.5 709.2 184.2 236.6 14.8 1.0 93.9 23.0 817 .9 1300.3 9991 13.0
99·2000 31.7 709.2 193.4 269.7 14.0 1.1 93.9 24.2 017.9 1338.1 10551 12.7
00-01 16.7 055.3 23\.7 300.2 14.8 1.1 93,9 25.4 964.0 1539.1 10063 14.2
01-02 15.3 855.3 243.3 331.2 lUI 1.2 93.9 26.7 964.0 1581.7 11175 14.1 '
02-03 5.4 955.3 225.5 3u8.3 14.8 1.3 93.9 28.0 964.0 1592.5 11407 13.9
03-04 5.5 1024.4 301.5 405.2 14.8 1.3 93.9 29.4 1133.1 1876.0 11799 15.9
04-05 3.6 1024.4 316.6 446.6 14.8 1.4 93.9 30.9 1133.1 1932.2 12111 15.9
05-06 3.7 102~.4 332.4 490.4 14.8 1.5 93.9 32.4 1133.1 1993.5 12423 16.0
06-07 3.9 1024.4 3·19.0 538.4 14.0 1.5 93.9 34.0 1133.1 2059.9 12735 16.2
07-08 4.0 1230.0 406.8 590.9 14.8 1.6 •140.9 46.1 1393.7 2443.7 13047 18.7
08-09 4.1 1230.0 427.1 646.1 14.0 1.7 148.9 49.0 1393.7 2523.7 13359 18.9
09-10 4.2 1230.0 44&.4 710.1 14.8 1.8 148.9 51.5 1393.7 2609.7 13671 19.1
10-11 4.4 1230.0 470.8 777.3 14.8 1.9 143.9 54.1 1393.7 2702.2 13963 19.3
TABLE 4.11.Anchorage-Cook Inlet Area,Medium Load Growth Scenario,Case 3,0%Inflation-------
NIl\j Itydroelectr1c lransmission
Total Cost _~llew C~red Capacuy_Costs _----.il'.stems Total Total Total Sys tern
of Existing Investment OM&R Coal Investment OM&R Investment OM&R Investment System Consumptioll,Average Power
~Capacity _~1._Cos.!i Cost_s__Costs _Costs Costs Costs Costs Costs.~---"Y1kIlH__Cost~•.c/K\lH
78-79 33.1 ---------1.0 ------------34.1 2531
79-80 42.2 ---------1.0 ------------Lf3.2 2801
80-81 78.2 --- ------1.0 ------------49.2 3041
81-B2 52.8 ---------l.0 ------------53.8 3281
82-83 61.1 28.7 5.7 6.5 l.0 ---------29.3 103,0 3521
83-84 62.0 28.7 5.7 9.2 1.0 ---------29.3 106.6 3761
84-85 66.6 2(1.7 5.7 11.8 20.7 ---------29,3 114.0 4001
85-86 66.7 58.7 11.6 18.4 20.7 ---------86.7 187.6 4329
dfi-87 67.1 58.7 11.6 24.1 20.7 --- ---
---86.7 193.7 4657
87-88 66.3 87.4 17.3 30.1 20.7 ------.-.115,4 233.0 4985
U8-89 59.0 87.4 17 .3 36.2 10.9 0.4 17.1 3.6 115.4 231.9 5313 4.4
89-90 54.5 81.4 17 .3 "42.5 10.9 0.4 35.9 5.6 134.2 254.5 5641 4.5
90-91 50.2 116.1 24.6 50.1 10.9 0.4 35.9 5.6 162.9 293.8 6063 4.8
co 91-92 47.1 152.9 31.9 59.1 10.9 0.4 35.9 5.6 199.7 343.8 6485 5.3
CO 92-93 42.4 202.8 41.7 70.2 10.9 0.4 35.9 5.6 249.6 409.9 6907 5.9
93-94 38.9 202.8 41.7 77.9 10.9 0.4 35.9 5.6 21 9•6 414.1 7329 5.6
!l4-95 39.4 202.0 41.7 53.3 157.7 1.1 35.9 5.6 396.4 537.5 7751 6.9
95-96 3~.5 202.8 41.7 58.6 157.7 1.1 35.9 5.6 396.4 537.9 8311 6.5
96-97 28.3 202.8 41.7 69.9 157.7 1.1 35.9 5.6 396.4 543.0 8871 6.1
97-98 25.4 202.8 41.7 79.1 157.7 1.1 35.9 5.6 39ti.4 549.3 9431 5.0
98-99 27 .4 202.8 41.7 54.5 206.6 1.8 35.9 5.6 445.3 576.3 9991 5.8
99-2000 22.6 202.0 41.7 60.2 206.6 1.8 35.9 5.6 445.3 577 .2 10,551 5.5
00-01 12.2 202.8 41.7 66.8 206.6 1.8 35.9 5.6 445.3 573.4 10.863 5.3
01-02 11.0 202.8 41.7 73.1 206.6 1.8 35.9 5.6 445.3 578.5·11 ,175 5.2
02-03 4.8·252.7 51.5 80.0 206.6 1.8 52.4 8.8 511.7 650.6 11 ,487 5.7
03-04 4.0 252.7 51.5 86.5 206.6 1.8 52.4 8.8 511.7 665.1 11 ,.799 5.6
04-05 3.6 252.7 51.5 93.4 206.6 1.8 52.4 8.8 511.7 670:0 12,lll 5.5
05-06 3.6 252.1 51.5 100.2 206.6 l.8 52.4 8.8 511.7 677.6 12,423 5.4
06-07 3.6 302.6 61.3 107.3 206.6 l.8 52.4 8.8 561.6 744.4 12,735 .5.8
07-08 3.6 302.6 61.3 114.5 206.6 1.8 52.4 B.£!561.6 751.6 13,047 5.B
Otl-09 3.6 302.6 61.3 121.9 206.6 1.8 52.4 8.8 561.6 759.0 13,359 5.7
09-10 3.6 302.6 61.3 129.6 206.6 1.8 52.4 B.8 56l.6 766.7 13,671 5.6
10-11 3.6 352.5 71.1 137.5 206.6 1.8 52.4 0.8 611.5 .834.3 13,983 5.9.
'J ))
..~
;
I ))
"
')
TABLE 4.12.Anchorage-Cook Inlet Area t Medium Load Grow~h Scenario,Case 3,5%Inflation
New Ilydroe 1ectri c Transmission
Tota 1 Cost New Coal Fired Capacity Costs Systems Total Total Total System
of Existing InVestment 6M&R Coal Investment OM&R Investment OM&R Investment System Consumption,Average Power
~Capacity Costs Costs ~!_S _Costs ~OSh Costs fQlli.Costs Costs',$MHKWIl Cos ts,¢/KWH
78-79 29.7 ---------------0.7 0.4 ---30.8 2531 1.2
79-80 39.1 --.---------0.7 0.4 ---40.2 2801 1.4
80-81 45.7 ---------'-~----0.7 0.4 ---46.8 3041 1.5
81·82 47.9 ---------------0.7 0.5 .1..49.1 3281 l.S
62-83 59.5 34.9 6.9 6.5 ------0.7 0.5 35.6 109.1 3521 3.1
63-84 63.6 34.9 7.2 9.2 -----0.7 0.5 35.6 116.1 3761 3.1
84-85 68.7 34.9 7.6 11.8 ------0.7 0.5 35.6 124.3 4001 3.1
8~-c36 6<3.9 77.3 16.4 18.1 14.3 0.6 23.0 4.9 115.1 224.0 4329 5.2
86-67 69.8 77 .3 17 .2 25.3 14.8 0.6 23.0 5.1 115.1 233.2 4657 5.0
81-1.18 67.1 121.9 26.8 32.7 14.8 0.6 23.0 5.4 159.7 .292.3 49B5 5.9
88-B9 60.6 121.9 28.2 41.6 14.8 0.6 23.0 5.7 159.7 296.5 5313 5.6
69-90 56.4 121.9 29.6 51.5 14.8 0.7 53.9 9.3 190.6 330.1 5641 6.0
90-91 52.5 173.5 41.3 63.7 14.8 0.7 53.9 9.7 242.2 410.1 6063 .6.8
91-92 49.8 243.1 56.9 78.3 14.8 0.7 53.9 10.2 311.6 507.8 6485 7.6
(Xl
47.4 342.0 79.2 9B.5 14.8 0.8 53.9 10.7 410.7 647.4 9.4~92-93 6907
93-94 46.5 342.0 83.2 113.B 14.8 0.8 53:9 11.3 410.7 666.4 7329 9.1
9~·95 48.5 342.0 1.17.4 82.1 323.7 2.4 53.9 11.13 119.6 951.8 7751 12.3
95-96 43.8 342.0 91.7 94.9 323.7 2.5 53.9 12.4 719.6 964.9 8311 11.6
96-97 36.3 342.0 96.3 118.3 323.7 2.7 53.9 13.0 719.6 986.2 8871 11.1
97-9B 37.7 342.0 101.1 140.2 323.7 2.0 53.9 13.7 719.6 1015.1 9431 10.8
98-99 37.5 342.0 106.2 1Ol.13 448.8 4.4 53.9 14.3 844.7 1109.0 9991 11.1
99-2000 31.7 342.0 111.5 .117.2 440.8 4.6 53.9 15.1 644.7 1124.8 10,551 10.7
00-01 16.7 342.0 117.1 137.1 448.8 4.9 53.9 15.8 844.7 1136.3 10,863 10.5
01-02 15.3 342.0 122.9 156.8 448.8 5.1 53.9 16.6 844.7 1161.4 11,175 10.4
02-03 5.4 503.1 160.7 181.4 44B.8 5.4 104.9 26.9 1056.8 1436.6 11,487 12.5
03·04 5.5 503.1 160.'1 205.3 448.8 5.6 104.9 28.2 1056.8 1470.1 11 ,799 12.4
04·05 3.6 503.1 1'17.1 232.5 448.8 5.9 104.9 29.6 1056.8 1505.5 12,111 12.4
05-06 3.7 503.1 105.9 261.4 4413.8 6.2 104.9 31.1 1056.8 1545.1 12,423 12.4
06-07 3.9 690.9 233.7 293.5 4Q8.8 6.5 104.9 32.7 1252.6 1822.9 12,735 14.3
07·08 4.0 698.9 245.4 328.7 448.8 6.8 104.9 34.3 1252.6 1071.8 13,047 14.3
08-09 4.1 69£\.9 257.6 ~367.5 448.8 7.2 104.9 36.0 1252.6 1925.0 13 ,359 14..4..
09-10 4.2 698.9 270.5 409.9 44£\.8 7.5 104.9 37.8 1252.6 1982.2 13 ,671 14.5
10-11 4.4 936.9 330.7 456.3 448.8 7.9 104.9 39.7 1490.6 2329.6 13,983 16.7
TABLE 4.13.Anchorage-Cook Inlet Area,High Load Growth Scenario,Case 1,0%Inflation
.Transml ss i on
lotal Cost
New Hydroelectric
New Coal Fired capac~Costs ~stems Total Total Total System
of Existing TRVestment OM&~oa rnvestme~nvestmen~M~--Investment System Consumption,Average Power
-lm-Capacity ~t_s_Costs Costs J~~Costs fosts Cost_s__Costs,S MMKIJIl Costs ,¢/KIJH_..--
78-79 33.1 ---------------0.6 0.4 ......-34.1 2680 1.3
19-80 42.2 ---------------0.6 0.4 ---43.2 3025 1.4
80-81 48.2 --- ------------0.6 0.4 ---49.2 3688 1.3
81-82 52.6 ---------------0.6 0.4 ---53.6 4352 1.2
82-63 61.1 57.4 11.4 9.8 ------17 .1 3.6 74.5 160.5 5015 3.2
83-84 62.0 66.1 17.1 18.6 ------17 .1 3.6 103.2 204.5 5679 3.6
84-85 66.7 114.8 22.8 29.9 ------17 .1 3.6 131.9 254.9 6342 4.0
85-86 66.7 144.8 28.7 44.8 10.9 0.4 17.1 3.6 142.8 317.0 6849 4.6
86-87 67.2 164.7 38.5 66.2 10.9 0.4 17.1 3.6 192.7 368.6 7357 5.0
87-88 66.4 164.7 38.5 73.4 10.9 0.4 17.1 3.6 192.7 375.0 78M 4.8
8S·09 59.0 214.6 48.3 81.2 10.9 0.4 33.6 6.8 259.1 454.8 8372 5.4
89-90 54.5 214.6 48.3 88.6 10.9 0.4.33.6 6.8 259.1 457.7 8879 5.1
90-91 50.2 214.6 40.3 98.5 10.9 0.4 33.6 6.8 259.1 463.3 9589 4.8
1.0 91-92 47.1 272.6 59.7 109.9 10.9 0.4 33.6 6.8 317.1 541.0 10,29a 5.2
0 92-93 42.4 322.5 69.5 120.1 10.9 0.4 33.6 6.8 367.0 606.2 11,008 5.5
93-94 38.9 322.5 69.5 132.6 10.9 0.4 33.6 6.8 367.Q 615.2 11,717 5.3
94-95 39.4 372.4 79.3 143.9 10.9 0.4 33.6 6.8 416.9 686.7 12,427 5.5
95-96 34.5 422.3 89.1 161.3 10.9 0.4 50.1 10.0 483.3 778.6 13,477 5.8
96-97 28.3 472.2 98.9 181.5 10.9 0.4 50.1 10.0 533.2 852.3 14,526 5.9
97-98 25.4 522.1 lOll.7 200.I 10.9 0.4 50.1 10.0 583.1 927.7 15,576 6.0
98-99 27.4 572.0 118.5 217.9 10.9 0.4 50.1 10.0 633.0 1008.2 16,625 6.1
99-2000 22.6 621.9 128.3 238.7 10.9 0.4 66.6 13.2 699.4 1102.6 17 ,675 6.2
00-01 12.2 671.8 138.1 256.6 10.9 0.4 66.6 13.2 749.3 1169.8 18,584 6.3
01-02 11.0 671.8 138.1 275.8 10.9 0.4 66.6 13.2 749.3 1187.8 19.493 6.1
02-03 4.8 721.7 147.9 294.6 10.9 0.4 66.6 13.2 799.2 1260.1 20,402 6.2
03-04 4.8 771.6 157.7 314.7 10.9 0.4 66.6 13.2 849.1 1339.9 21,311 6.3
04-05 3.6 771.6 157.7 335.6 10.9 0.4 66.6 13.2 849.1 1359.6 22,220 6.1
05-06 3.6 821.6 167.5 356.9 19.9 0.4 83.1 16.4 915.5 1460.3 23,129 6.3
06·07 3.6 871.4 177.3 378.8 10.9 0.4 83.1 16.4 965.4 1541.9 24,038 6.4
07·08 3.6 871.4 177 .3 401.2 10.9 0.4 83.1 16.4 965.4 1564.3 24,947 6.3
08-09 3.6 921.3 187.1 42'1.2 10.9 0.4 83.1 16.4 1015.3 1647.0 25,1156 6.4
09-10 3.6 971.2 196.9 447.a 10.9 0.4 83.1 16.4 1065.2 1730.3 26,765 6.5
10-11 3.6 971.2 196.9 472.0 10.9 0.4 83.1 16.4 1065.2 1754.5 27,674 6.3
)))
".I
)))
TAI3LE 4.14 .Anchorage-Cook Inlet Area.High Load Growth Scenario.Case 1.5%Inflation--------
New Hydroelectric Transmission
Total Cost New Coal Fired CaRac~Costs Systems Total Total Total System
of Existing Investment OM&R oar--'lnves tmcnt OMlR Investment OOR Investment System Consumption,Average Power
Year _Capacity Costs Costs !1J!~_Costs Costs Costs ~Costs Costs,$MMKWH Costs,t/K!lH
78-79 29.7 ---------------0.7 0.4 ---30.8 2680 .1.1
79-80 39.1 ---------...---0.7 0.4 ---40.2 3025 1.3
80-81 45.7 ------------...--0.7 0.4 ---46.8 3688 1.3
81-82 47.9 --------- ------0.7 0.5 ---49.1 4352 1.1
82-83 59.5 69.8 13.8 9.9 ------21.0 4.4 90.8 \78.4 5015 3.6
83-84 63.6 106.4 21.8 18.6 ...---21.0 4.6 127.4 2;)6.0 5679 4.2
84-85 68.7 144.9 30.5 29.9 ------21.0 4.9 165.9 299.9 6342 4.7
85-86 68.9 187.3 38.9 44.8 14.8 0.6 21.0 5.1 223.1 381.4 6849 5.6
86-87 69.8 261.1 49.2 69.4 14.8 0.6 21.0 5.4 296.9 491.3 ,356 6.7
87-88 67.I 261.1 51.7 80.5 14.8 0.6 21.0 5.6 296.9 502.4 7864 6.4
3<1-89 60.6 342.5 70.2 93.4 14.0 0..6 48.1 11 ,2 405.4 641.4 8372 7.7
8~-90 56.4 342.5 73.7 107.4 14.8 0.7 46.1 11.7 405.4 655.3 8870 1'.4
90-91 52.5 342,5 77.4 125.4 14.0 0.7 48.1 12.3 405.4 673.7 9569 7.0
lO 91-92 49.8 452.1 102.6 145.9 14.8 0.7 46.1 12.9 515.0 826.9 10,298.8.0
--'92-9)47.4 551.0 127.2 168.5 14.8 0.8 48.1 13.6 613.9 971.4 11.000 8.8
93-94 46.5 551.0 133.5 193.8 14.8 0.0 48.1 14.3 613.9 1002.8 11,717 8.6
94-95 48.5 660.0 161.6 221.3 14.8 0.9 48.1 15.0 722.9 1)70.2 12,427 9.4
95-96 43.8 774,5 192.2 261.2 14.8 0.9 07.1 22.7 876.4 1397.2 13,471 10.4
96·97 36.3 894.7 225.4 307.4 14.8 0.9 87.1 23.9 996.6 1590,5 14,526 10.9
97-98 37.7 1020.9 261.5 354.5 14.8 1.0 87.1 25,1 1122.8 1002.6 15,576 11.6
98-99 37.5 1153.4 300.5 407.1 14.8 1.0 87.1 26.3 1255.3 2027.7 16,675 12.2
9~-2000 31.7 12&2.6 342.8 464.8 14.8 1.1 131.3 36.2 1438.7 2315.3 17,675 13.1
00·01 16.7 H3il.7 380.7 526.5 14.8 1.1 131.3 37.9 1584.8 2555.7 18,5B4 13.8
01-02 15.3 1436.7 4011.1 592.6 14.8 1.2 131.3 39.9 1564.8 2641.9 19.493 13.6
02-03 5.4 1599.6 460.1 667.5 14.8 1.3 131.3 41.9 1745.9 2922.1 20,402 14.3
03-04 5.5 1769.0 516,3 746.8 14.8 1.3 131.3 43.9 1915.1 3220.9 21,311 15.1
04-05 3.6 1769.0 542.2 835.5 14.8 1.4 131.3 46.1 1915.1 3343.9 22.220 15.0
05-06 3.7 1955.5 605.9 930.8 14.8 1.5 184.3 58.4 2154.6 3754.9 23,129 16.2
06·07 3.9 2151.3 674.6 1035.9 14.8 1.5 Hl4.3 61.3 2350.4 4127.6 24.038 17 .2
07·08 4.0 2151.3 708.3 1151.5 14.8 1.6 184.3 64 .4 2350.4 4280.2 24,947 17 .2
.08-09 4.1 2367.2 7B6.1 1270.1 14.8 1.7 184.3 67.6 2566.3 4703.9 25,856 18.2
09-10 4.2 2593.9 869.9 1416.3 14.8 1.8 134.3 70.9 2793.0 5156.1 26,765 19.3
10-11 4.4 2593.9 913.4 1566.6 14.8 1.9 184.3 74.5 2793.0 5353.8 27,674 19.3
TABLE 4.15.Anchorage-Cook Inlet Area.High Load Growth Scenario,Case 2,0%Inflation
New Hydroelectric Transmission
Total Cost,New Coal fired Capa!Oiy__"Costs Systems Total Total Total System
of £Kisting Investment OM&R Coal Investment OM&"R Investment OMloR Investment 'System Consumption.Average Power
~Capacity Costs Costs Costs Costs ~!!sts Costs Costs Costs Costs.S MMKWH Cos!!.L.YKWH
7B-79 33.1 .-------------.0.6 0.4 ---34.1 26BO 1.3
79-80 42.2 -------.-------0.6 0.4 ._-43.2 3025 1.4
BO-Bl 48.2 ---------_.----0.6 0.4 ---49.2 3688 1.3
1ll-82 52.8 ---------------0.6 0.4 .--53.8 4352 1.2.
82-83 61.1 57.4 11.4 9.8 ------17.1 3.6 74.5 160.5
5015 3.2
83-84 62.0 66.\17 .\18.6 ---_.-\7.1 3.6 103.2 204.5 .5679 3.6
84-85 66.7 114.8 22.8 29.9 ----_.17.1 3.6 131.9 254.9 6342 4.0
85-86 66.7 144.8 28.7 44.8 10.9 0.4 17.I 3.6 142.8 317.0 6849 4.6
86-87 67.2 144.8 28.'58.7 10.9 0.4 35.9 5.6 191.6 352.2 7357 4.8
61-88 66.4 194.7 33.5 73.4 10.9 0.4 35.9 5.6 '241.5 420.8 7664 5.3
88·89 59.0 194.7 38.5 .til.2 10.9 0.4 35.9 5.6 241.5 .426.2 il372 5.I
89-9il 54.5 244.6 48.~68.6 10.9 0.4 52.4 8.8 307.9 506.5 6679 5.7
90-91 50.2 244.6 48.3 98.5 10.9 0.4 52.4 8.B 307.9 514.1 9589 5.4
~91-92 41.I 302.6 59.7 109.9 10.9 0.4 52.4 8.8 365.9 591.8 10,296 5.7
N 92-93 42.4 302.6 59.7 120.I 10.9 0.4 52.4 8.8 365.9 5~1.3 11,008 5.4
93·9~31),9 352.5 69.5 132.6 10.9 0.4 52.4 8.8 415.8 666.0 11.717 5.7
94-95 39.4 352.5 69.7 143.9 10.9 0.4 52.4 B.8 415.8 678.0 12.427 !j.5
95-96 34.5 402.4 79.3 161.3 10.9 0.4 52.4 8.8 465.7 750.0 13.477 5.6
96-97 28.3 452.3 89.1 I III .5 10.9 0.4 60.9 12.0 532.1 843.4 14.526 5.8
97-98 25.4 502.2 90.9 200.1 10.9 0.4 68.9 12.0 582.0 918.8 15.576 5.9
98-99 27.4 5!i2.1 108.7 217.9 10.9 0.4 68.9 12.0 631.9 998.3 16,625 6.0
99·2000 22.6 602.0 118.5 238.7 10.9 0.4 68.9 12.0 6111.8 107'4.0 17,675 6.1
00-01 12.2 651.9 128.3 256.5 10.9 0.4 85.4 15.2 740.2 1160.8 18.564 6.2
01-02 11.0 701.0 138.1 215.0 10.9 0.4 85.4 15.2 798.1 123ll.6 19,493 6.3
02·03 4.8 751.7 147.9 294.6 10.9 0.4 85.4 15.2 648.0 1310.9 20,402 6.4
03-04 4.8 751.7 147.9 314.7 10.9 0.4 85.4 15.2 848.0 1331.0 21,311 6.2
04-05 3.6 151.7 147.9 335.6 10.9 0.4 85.4 15.2 848.0 1350.7 .22,220 6.1
05·06 3.6 801.6 157.7 356.9 lO.9 0.4 85.4 15.2 897.9 1431.7 23,129 6.2
06-01 >.6 851.5 161.5.378.8 10.9 0.4 85.4 15.2 947.11 1513.3 24.038 6.3
07-08 3.6 901.4 177 .3 401.2 10.9 0.4 101.9 18.4 1014.2 1615.1 24.947 6.5
08-09 3.6 901.4 171.3 424.2 10.9 0.4 101.9 16.4 1014.2 1638.1 25.856 6.3
09·10 3.6 951.3 W7.1 447.11 10.9 0.4 101.9 18.4 1064.1 1721.4 26.765 6.4
10-11 3.6 1001.2 1fl6.9 472.0 10.9 0.4 101.9 16.4 11l4.0 1801.7 27,674 6.5
)
~,,?)
'\),
TABLE 4.16.Anchorage-Cook Inlet Area,High Load Growth Scenario,Case 2,5%Inflation
New l/ydroe1cctrfc ...,frlll)sJ!1isslon
Totill Cost New Coal Fired CaJ!.<!.£.ity Cos ts .~tems Totll1 Total Total System
of Existing tnvestiilen-r-oM&R~Coal lnves tmenC-CM1T 1nves'tme·ii'tliMXR-Investment System Cons umptf on,Average Power
~Capad ty Costs ~Costs~Costs Costs
Costs Costs Costs ~osts,S MMKWH Costs,¢/KWH
76-79 29.7 ---------~"~----0.7 0.4 .--30.8 2660 1.1
]g-80 39.1 -------------_.0.7 0.4 ---40.2 3025 1.3
80-81 45.7 ---------------0.1 0.4 ---46.6 3688 1.3
111-82 47.9 ---------------0.7 0.5 ---49.1 4352 1.1
62-83 S9.5 69~'8'13.8 9.9 -------".21.0",·4.4 90.8 1.78.4 5015 3.6
83-84 63.6 10604 21.8 18.6 ------21.0'4.6 127.4 236.0 S679 4.2
84-85 68.7 144.9 30.S 29.9 ---......-21.0 4.9 165.9 299.9 6342 4.7
65-66 68.9 187.3 38.9 44.8 14.8 0.6 21.0 S.l 223.1 301.4 6849 5.6
86-87 69.0 167.3 40.8 61.5 14.8 0.6 47.7 8.1 249.8 430.6 4357 5.8
87-88 67.1 264.6 58.0 BO.5 14.8 0.6 47.1 8.6 327.3'542.1 786'4 6.9
68-89 60.6 264.8 60.9 93.4 14.8 0.6 47.7 9.0 327 .3 551.8 8372 6.6
89-90 56.4 350.2 80.8 107.4 14.8 0.7 74.8 14.7 439.6 699.8 8879 7.9
90-91 52,5 350.2 64.8 125.4 14.6 0.7 74.8 15.4 439.8 718.6 9589 7.5
lD 91-92 49.8 459.8 110.5 145.9 14.6 0,1 14.8 16.2 549.4 872.5 •10.298 8.5
Lv 92-93 47.4 459.6 115.9 166.5 14.11 0.8 74.8 17 .0 549.2 899.0 11.008 8.2
93-94 46.5 563.6 142.2 193.9 14.6 0.8 74.8 17 .9 653.2 1054.5 11,717 9.0
94-\15 48.5 563.6 149.3 221.3 14.8 0.9 74.8 18.8 563.2 1092.0 12.421 8.8
95-96 43.8 67il.l 179.2 261.2 14.8 0.9 74.8 19.7 767.1 1272..5 .13.477 9.4
96-97 36.3 798.3 211.8 307.4 14.8 0.9 113.8 27.7 926.9 1511.0 14 ,526 10.4
97-98 37.1 924.5 241.2 354.5 H.8 1.0 113.8 29.1 1053.1'1722.6 15,576 11.1
96-99 37.5 1057.0 285.5 407.1 14.6 1.0 113.8 .30.5 1185.6 1947.2 16,625 11.7
99-2000 31.7 1196.2 327.1 464.8 14.6 1.1 113.8 32.0 1324.8 2181.5 17.675 12.3
00-01 16.7 1342.3 372.2 526.5 lUI 1.1 160.2 42.6 1517.3 2476.4 18.564 13.3
01·02 15.3 1495.7 420.9 591.£I 14.6 1.2 160.2 44.7 1670.7 2744.6 19.493 14 .1
02-03 5.4 1656.£1 473.t."667.5 14.8 1.3 160.2 46.9 1831.8 3026.4 20.402 14 .8
03-04 5.5 1656.8 497.2 746.8 14.B 1.3 160.2 49.3 lB31.B 3131.9 21,311 14.7
04-05 3.6 1656.8 522.1 835.5 14.£1 1.4 160.2 51.8 1831.8 3246.2 22.220 14.6
05-06 3.7 1843.3 .584.8 930.8 14.0 1.5 160.2 54.4 2018.3 3593.5 23,129 15.5
06-07 3.9 2039.1 652.4 1035.9 14.8 1.5 160.2 57.1 2214.i 3964.9 24,038 16.5
07-08 4.0 2244.7 725:3 1151.5 14.6 1.6 215.2 70.9 2474.7 44211.0 24,947 17.7
08-09 4.1 2244.7 761.6 1278.1 14.8 1.7 215.2 74.5 2474.7 4594.7 25,856 17 .8
09-10 4.2 2471.4 844.2 1416.3 14.0 1.8 215.2 78.2 2701.4 5046.1 26.765 18.8
10-11 4.4 2709.4 933.1 1566.6 14.8 1.9 215.2 £12.1 2939.4 5521.5 27,674 19.9
TABLE 4.17.Anchorage-Cook Inlet Area,High Load Growth Scenario,Case 3,0%Inflation
Total Cost
New Hydroelectric Transm1sliton
_New Coal Fired Capacity Costs Systems Total Total Total System
of Existing Investment OM&R Coal loves tment-(jf4&R-Investment OM&~Investment System Cons (jmp ti on •Average Power
~Capacity Costs ~Costs Costs Cost~~~-Costs ..f2ill..--Costs.$MMKWII Costs,¢m/ll
78-79 33.1 ---------------0.6 0.4 ---34.1 2680 1.3
79-80 42.2 ---_.----.------0.6 0.4 ---43.2 3025 1.4
80-Bl 48.2 ---,....----------0.6 0.4 ---49.2 3688 1.3
81-82 52.8 ---------------0.6 0.4 ---53.8 4352 1.2
82-83 61.1 57.4 11.4 9.8 ------17.1 3.6 74.5 160.5 5015 3.2
83-34 62.0 86.1 17.1 18.6 ------17.1 3.6 103.2 204.5 5679 3.6
64-85 66.7 114.8 22.8 29.9 ------17.1 3.6 \31.9 254.9 6342 4.0
85-86 66.7 144.8 28.7 44.8 10.9 0.4 17.1 3.6 142.8 317.0 6849 4.6
86-87 67.2 144.8 28.7 58.7 10.9 0.4 35.9 5.6 191.6 352.2 7357 4.8
87-88 66.4 194.7 33.5 73.4 10.9 0.4 35.9 5.6 241.5 420.8 78M 5.3
88-69 59.0 194.7 38.5 81.2 10.9 0.4 35.9 5.6 241.5 426.2 8372 5.1
89-90 54.5 244.6 48.3 86.6 10.9 0.4 52.4 8.B 307.9 508.5 8879 5.7
90-91 50.2 244.6 48.3 90.5 10.9 0.4 52.4 8.0 307.9 514.1 9589 5.4
w !H-92 47.\302.6 59.7 109.9 10.9 0.4 52.4 8.B 365.9 591.B 10.298 5.7
.po.92-93 42.4 302.6 59.7 120.1 10.9 0.4 52.4 8.8 365.9 597.3 11,008 SA
93-94 38.9 352.5 69.5 132.6 10.9 0.4 52.4 8.B 415.8 666.0 11.717 5.7
94-95 39.4 352.5 69.5 111.7 163.1 1.1 52.4 8.B 568.0 798.5 12.427 6.4
95-96 34.5 352.5 69.5 124.2 163.1 1.1 52.4 0.8 568.0 806.1 13.477 6.0
96-97 28.3 402.4 79.3 143.5 163.1 1.1 68.9 12.0 634.4 898.6 14.526 6.2
97-98 25.4 452.3 89.1 161.2 163.1 1.1 68.9 12.0 684.3 973.1 15,576 6.2
98-99 27.4 452.3 89.1 143.9 213.8 1.7 68.9 12.0 684.3 1009.1 16.625 6.1
99-2000 22.6 452.3 89.1 158.5 213.8 1.7 68.9 12.0 684.3 1018.9 17,675 5.8
00-01 12.2 452.3 89.1 175.1 213.8 1.7 68.9 12.0 684.3 '1025.1 18.5ll4 5.5
01-02 11.0 502.5 98.9 192.5 213.8 1.7 68.9 12.0 785.2 1101.3 19.493 5.6
02-03 4.8 552.1 108.7 210.1 213.8 1.7 68.9 12.0 834.8 1172.1 20,402 5.7
03-04 4.8 552.1 •109.7 228.4 213,8 1.7 68.9 12.0 834.8 1190.4 21.311 5.6
M-05 3.6 602.,(1 118.5 247.;;·213.8 1.7 85.4 15.2 901.2 1287.1 22.220 5.8
05-06 3.6 651.9 128.3 266.9 213.8 1.7 85.4 15.2 951.1 1366.8 23.129 5.9
06-07 3.6 651.9 128.3 286.9 213.8 1.7 85.4 15.2 951.1 1386.8 24.038 5.8
07-08 3.6 70\.8 13B.l 307.6 213.8 1.7 85.4 15.2 1001.0 1467.2 24.947 5.9
OB-09 3.6 11.1.7 147.9 328.8 213.8 1.7 85.4 15.2 1050.9 1548.1 25.856 6.0
09-10 3.6 751.7 147.9 350.6 213.8 1.7 B5.4 15.2 1050.9 1569.9 26.765 5.9
10-11 3.6 DOl.r.157.7 372.9 213.8 1.7 101.9 18.4 1117.3 1671.6 27.674 6.0
,)
it ,
Inlet Area,)i9h
.)TABLE 4.18.I\nchoruge-Cook Load Growth Scenario,Case 3,5%Inflation
New l~droolectric Transmission
Total Cost r--.l!.~~~i-().!!U~r~!..(-~l.cj!:j',_.Costs rr_.s.Y.~t.~rns -0'.---Total Total Total System
of Existing nv~s tillent ~1"R Coal liivcStiilcrll-o:Hrr-nvestment ,·11.R Investnlent S.ys tern Consurnption,Average Power
Year _.~1~c i l y_.~~J:.L__to~0~.t~_Costs ,(:os ts _S9~ls_Costs Costs SJ2.-~.J fll~K\JIl Co s ~_Wb'!!.------_._---~---
78 -79 29.7 ----,........-------0.7 0.4 ---30.8 2680 1.1
79-80 39.1 ---------------0.7 0.4 ---40.2 3025 1.3
80-81 45.7 -_.~---.."'..---.--0.7 0.4
-_...46.8 36118 1.3
81-82 47.9 ...-".-----------0.7 0.5 ---49.1 4352 1.1
82-83 59.5 69.8 13.8 9.9 ------21.0 4.4 90.8 175.4 5015 3.6
83-84 63.6 106.4 21.B 18.6 ..-----21.0 4.6 127 .4 236.0 5679 4.2
84-85 68.7 144.9 30.5 29.9 ------21.0 4.9 165.9 299.9 6342 4.7.
85-86 68.9 187.3 38.9 44.8 14.8 0.6 21.0 5.1 223.1 381.4 6849 5.6
86-87 69.8 HJ7.3 40.8 61.5 14.8 0.6 47.7 8.1 249.8 430.6 4357 5.B
81-88 67.1 264.0 58.0 80.5 14.8 0.6 47.7 8.6 327.3 542.1 7864 6.9
813-89 60.5 264.8 60,9 93.4 14.8 0.6 47.7 9.0 327 .3 551.8 8372 6.6
89-90 56.4 3S0.2 8D.B 107.4 14.8 0.7 74.8 14.7 439.8 699.8 8e79 7.9
90-9)52.5 350.2 84.8 125.4 14.8 0.7 74.B 15.4 439.13 718.6 9589 7.5
~o 91-92 49.13 459.8 110.5 145.9 14.8 0;7 7Ui 16.2 549.4 e72.5 10,298 8.5
c..n 92-93 47.4 4~i9 .8 115.9 168.5 14.8 0.8 74.8 17.0 549.2 899.0 11 ,008 0.2
93 ·9·1 46.5 563.6 142.2 193.9 14.8 0.8 74.8 17.9 653.2 1054.5 11 ,717 9.0
94-95 48.5 563.6 149.3 171.3 335.2 2.2 74.8 18.8 973.6 1364.2 12.427
10.9
95-96 43.8 563.6 156.!1 2DI.2 335.2 2.3 74.8 19.7 973.6 1397.4 13.477 10.4
96-97 35.3 683.8 lOB.2 243.1 335.2 2.4 llUI 27.7 1133.8 1595.2 14,525 10.9
97-98 37.7 810.0 222.4 2nS.6 33S.2 2.5 114.8 29.1 1260.0 1837.3 1'j ,576 11.8
98-99 37.5 010.0 7.33.5 2611.9 464.9 4.2 114.8 30.5 1389.7 1954.3 16,625 11.8
99·7000 31.7.nl0.0 245.2 308.5 464.9 4.4 114.8 32.0 13U9.7 2011.5 17,675 .~11 .4
00-01 16.7 810.0 257.5 359.3 464.9 4.6 114.8 33.6 1389.7 2061.4 18.584 11.1
01-02 15.3 963.4 300.5 413.1 464.9 4.8 114.8 35.3 1543.1 2312.1 19,493 11.9,
02-03 5.4 1124.5 347.1 476.1 464.9 5.1 114.8 37.1 1704.2 2575.0 20,402 12.6
03-04 5.5 1174.5 364.4 5'11 .9 464.9 5.3 114.8 38.9 1704.7.2660.2 21,311 12.5
04·05 3.6 1302.I 417.5 616.1 464.9 5.6 168.5 51.9 1935.5 3030.2 22 ,220 13.6
.05·06 3.7 1488.6 474.9 696.2 454.9 5.9 168.5 54.5 ·2122.0 3357.2 23,129 14.5
06-07 3.9 1488.6 49l1.7 784;9 4.64.9 6.2 168.5 57.2 2122.0 3472.9 24,038 14.4
07-08 4.0 1694.2 563.9 882.8 464.9 6.5 168.5 60.1 2327.6 3844.9 24,947 15.4
08-09 4.1 191 D.I 634.5 990.5 464.9 6.B 168.5 63.1 2543.5 4238.4 25.856 16.4
09-10 4.2 1910.1 665.3 110B.7 464.9 7.1 168.5 66.2 2543.5 4396.0 26,765 16.4
10-J1 4.4 2148.1 746.3 1237.8 46Q.9 7.5 222.0 81.5 2835.0 4912.5 27,674 17.7
..
TABLE 4.19.Fa i rbanks -Ta nana Valley Area,Low Growth Scenario,Case 1,0%Inflation
New Hydroelectric Transmission
Total Cost New Coal Ff rid Capacf ty Costs ~tellls Total Total
Total System
of Exlstfng Investmf:~O;'l R --Coa1-lnves'fijienrOM&T 1nves tmeriT-OM&R Investment System Consumptfon,Average Power
~Capacfty Costs Costs Costs ~li.._fQ.ili..~~Costs Costs Costs,$MMKWH Costs,t/KIIH
78-79 33.8 ----.----0.3 0.2 ---34.3 778 4.4
79-80 36.6 ---_.----0.3 0.2 ---37.1 823 4.5
80·B}39.4 ._-------0.3 0.2 ---39.9 855 4.7
61-82 41.6 ----_.---0.3 0.2 ---42.1 887 4.7
82-83 35.6 ._----6.9 0.3 0.2 ---43.1 919 4.7
83-84 33.1 ------7.2 0.3 0.2 ---40.8 951 4.3
84-85 30.3 ------7.3 0.3 0.2 ---38.2 9113 3.9
.85-86 28.2 ------7.5 0.3 0.2 ---36.6 1015 3.6
86-87 26.1 ------7.7 0.3 0.2 ---34.3 1047 3.3
87-88 24.0 ------7.8 0.3 0.2 ---32.4 1079 3.0
88-89 22.9 2.6 0.5 7.7 0.3 0.2 2.9 34.2 1111 3.1
89·90 23.1 21.5 4.3 10.0 3.5 1.0 25.0 63.4 lH4 5.6
90-91 20.9 27.6 5.5 10.0 3.5 1.0 31.4 68.5 1176 5.8
1.0 91-92 21.1 27.6 5.5 12.4 3.5 1.0 31.7 71.1 1208 5.9
Ol
92-93 18.2 27.6 5.5 13.3 3.5 1.0 31.1 69.2 1240 5.6
93-94 18.4 27.6 5.5 14.\3.5 1.0 31.1 70.1 1272 5.5
94-95 18.5 46.5 9.3 14.7 3.5 1.0 50.0 93.5 1305 7.1
95-96 16.9 51.2 10.2 15.4 3.5 1.0 54.7 98.2 1337 7.3
96-97 14.3 51.2 10.2 16.4 3.5 1.0 54.7 97.1 1369 7.1
97-98 3.8 70.1 14.0 lB.9 3.5 1.0 73.6 111.2 1401 7.9,
9.8-99 3.8 69.0 17.8 19.6 3.5 1.0 92.5 134.7 \433 9.4
99-2000 3.8 89.0 17.8 20.6 3.5 1.0 92.5 135.7 1466 9.2
00-01 3.8 89.0 17.8 20.9 3.~1.0 92.5 136.0 1470 9.3
01-02 3.8 89.0 17.8 21.5 3.5 1.0 92.5 136.6 1474 9.3
02-03 1.5 89.0 17.8 21.9 3.5 1.0 92.5 134.7 1478 9.1
03-04 1.5 89.0 17.8 22.4 3.5 1.0 92.5 135.2 1482 9.1
04-05 1.5 89.0 17.8 22.9 3.5 1.0 92.5 135.7 1437 9.1
05-06 ---89.0 17.8 23.5 3.5 1.0 92.5 134.8 1491 9.0
06-07 ---89.0 \7.8 24.\3.5 1.0 92.5 135.4 1495 9.0
07-08 ~~-89.0 17.8 24.6 3.5 1.0 92.5 135.9 1499 9.1
08-09 ---89.0 17.8 24.7 3.5 1.0 92.5 136.0 1503 9.0
09-10 ---89.0 17.8 25.7 3.5 1.0 92.5 137.0 1507 9.1
10-Jl ---89.0 \7.8 26.2 3.5 1.0 92.5 137.5 1511 9.1
)).)
)
TABLE 4.21.Fairbanks-Tanana Valley Area.Low Growth Scenario,Case 2,0%Inflation
New Hydroelectric Transmh s 1on
Total Cost New Coal Fir-cd (apacllY Costs Systems Total Total'Total System
of ExistIng lnves tme;;t--oM&R .-Coa-l-.Inves tmertr-OM&1C Investment OM&R,Investment System Consumptfon.Average Power
~Capacity ..-1!!.ill-f£sts Costs _~tL-_Costs Costs 0ili.Costs Costs J $_MHKl-Ifi_._Costs.C!KWH
70-79 33.0 ---------0.3 0.2 ---34.3 778 4.4
79-80 36.6 .--------0;3 0.2 ---37.1 823 4.5
80-81 39,4 ---------0.3 0.2 ---39.9 855 4.7
81-82 41.6 ---_......---0.3 0.2 ---42.1 887 4.7
82-83 35.6 ------.6.9 0.3 0.2 ---43.1 919 4.7
83-84 33.1 ------7.2 0.3 0.2 ---40.0 951 4.3
84-85 30.3 ------7.3 0.3 0.2 ---38.2 983 3.9
85-86 28.2 ------7.5 0.3 0.2 ---36.6 1015 3.6
86-87 26.1 ------7.7 0.3 0.2 ---34.3 1047 3.3
87-08 24.0 ------7.0 0.3 0.2 ---32.4 .1079 3.0
88-09 22.9 2.6 0.5 7.7 0.3 0.2 2.9 34.2 1111 3.1
89-90 23.1 21.5 4.3 10.0 3.5 1.0 25.0 63.4 1144 5.6
90-91 20.9 27.6 5.5 10.0 3.5 1.0 31.4 68.5 1176 5.8
\.0 91-92 2].1 27.6 5.5 12.4 3.5 1.0 31.7 71.1 1208 5.9
CO .
92-93 18.2 27.6 5.5 13.3 3.5 1.0 31.1 69.2 1240 5.6
93-94 .18.4 27.6 5.5 14.1 3~5 1.0 31.1 70.1 1272 5.5
94-95 HI.5 27.6 5.5 14.7 16.6 2.0 46.4 87.2 1305 6.7
95-96 16.9 32.3 6.4 15.4 18.8 2.0 51.1 91.8 1337 6.9
96-97 14.3 51.2 10.2 16.4 18.8 2.0 70.0 113.1 1369 8.3
97-98 3.7 70.1 14.0 18.9
10.8 2.0 88.9 127.6 1401 9.1
98-99 3.7 70.1 14.0 19.6 10.8 2.0 8tl.9 128.4 1433 8.9
99-2000 3.7 70.1 14 .0 20.6 18.0 2.0 80.9 129.3 1466 8.8
00-01 3.8 70.1 14.0 20.9 10.8 2.0 88.9 129.6 1470 8.8
01-02 3.8 70.1 14.0 21.5 10.0 2.0 08.9 130.2 1474 8.8
02-03 1.5 70.1 14.0 21.8 18.8 2.0 88.9 128.3 1478 0.7
0)-04 1.5 70.1 14.0 22.4 HI.8 2.0 88.9 128.0 1482 6.7
04-05 1.5 70.1 14.0 22.9 18,8 2.0 68.9 129.3 1487 8.7
05-06 ---70.1 H.O 23.5 '18.8 2.0 88.9 128.4 1491 8.6
06-07 ---89.0 17.8 24.0 18.0 2.0 107.8 151.7 1495 10.1
07-00 ---89.0 lI.B 24.5 18.8 2.0 107.8 152.2 1499 10.1
08-09 ---89.0 17.0 25.1 10.8 2.0 107.8 152.8 1503 10.1
09-10 ---89.0 17.8 25.7 18.8 2.0 107.8 153.3 1507 10.2
10-11 ---89.0 17.8 26.2 18.8 2.0 107.8 153.9 1511 10.2.
)))
,_....;.~..,.
-",,--.
')
TABLE 4.22.Fairbanks-Tanana Valley Area,Low Growth Scenario,ease 2,5%Inflation
New Hydroelectdc Tran~mjssjon
lata 1 Cos t New Coal Fired Capacity Costs ~stems .Total Total Total System
of Existing liivestment-OM&R Coa1-rnvestment ilMllC wves tlnent -----oHlR Investment System Consumption,Average Power
~L _Capadty Costs Costs Costs Costs -fQ.ili.Costs Costs Costs Costs I $MMKWH Costs ,UKWH
76-79 30.57 ---------0.2 0.2 ---30.9 776 4.0
79-80 33.9 ---------0.2 0.2 ---34.2 823 4.2
80-81 37.4 ---------0.2 0.2 ---37.8 .855 4.4
81-82 40.7 ---------0.2 0.2 ---41.0 887 4.6
82-83 36.6 ------6.9 0.2 0.2 ---43.9 919 4.8
83-84 35.6 ------7.2 0.2 0.2 ---43.2 951 4.5
84-85 33.5 --- ---
7.3 0.2 0.2 ---41.3 983 4.2
8~-86 32.3 ------7.5 0.2 0.2 ---40.3 1015 4.0
86-87 30.4 ------6.1 0.2 0.3 ---38.9 1047 3.7
87-68 28.1 ------8.6 0.2 0.3 ---37.8 1079 3.5
88-89 27.9 4.2 0.7 8.9 0.2 0.3 4.4 42.4 1111 3.B
89-90 29.3 36.6 7.0 12.1 4.5 1.7 41.1 91.3 1144 7.9
90-91 28.4 48.0 7.4 12.7 4.5 I.B 52.5 102.B 1176 B.7
to 91-92 30.1 48.0 7.4 16.5 4.5 1.9 52.5 108.2 1208 8.9
'-0 .8.692-93 26.7 48.0 7.4 lB.7 4.5 2.0 52.5 107.0 1240
93-94 28.1 48.0 7.8 20.6 4.5 2.1 52.5 ]10.8 1272 8.7
94-95 29.5 48.0 11.9 22.6 36.8 4.0 84.8 153.0 1305 11.7
95-96 2B.8 58.1\14.6 24.9 36.8 4.2 95.6 168.1 1337 12.6
96-91 27.1 105.4 24.4 27.9 36.8 4.4 142.2 226.6 1369 16.5
97-9B 6.1 153.3 35.2 33.5 36.8 4.6 190.1 269.6 1401 19.2
98-99 6.4 153.3 36.9 36.7 36.8 4.8 190.1 275.0 1433 19.2
99-2000 6.6 153.3 38.7 40.1 36.8 5.1 190.1 280.6 1466 19.1
00-01 7.0 153.3 40.7 43.0
36.8 5.3 190.1 266.2 1470 19.4
01-02 7.3 153.3 42.7 46.1 36.6 5.6 190.1 291.9 1474 19.8
02-03 2.7 153.3 44.9 49.6 36.8 5.9 1'.J0.l 293.2 1478 19.8
03·04 2.8 153.3 47.1 53.2 36.8 6.2 190.1 299.4 1482 20.2
04-05 2.9 153.3 49.5 57.1 36.6 6.5 190.1 306.2 1487 20.6
05·06 .--153.3 51.9 61.3 36.8 6.8 190.1 310.1 1491 20.8
06-07 ---227.6 69.2 65.7 36.8 7.2 264.4 406.6 1495 27.2
07-0B ---227.6 72.6 70.5 36.8 7.5 264.4 415.1 1499 27.7
66-09 ---221.6 76.3 75.7 36.3 7.9 264.4 424.4 1503 28.2
09-10 ---227.6 80.1 81.2 36.8 B.3 264.4 434.1 1507 28.8
10-11 ---227.6 84.1 87.1 36.3 8.7 264.4 443.3 15H 29.4
TABLE 4.23.Fairbanks-Tanana Valley Area.Low Growth Scenario,Case 3,0%Inflation-----
Hew Hydroa 1ec tri c Transmission
Total Cost New Coal Fired Capacl!y Casts _~I])L __Total Total Total System
of Existing II\~estniellt -011&[Coal-Inves tment OM&R III~es tlllen t OM&R Investment System COllsumlltfon.Average Power
~Capad ty Costs ~Cos~Costs "_Costs .Costs_f2ili Costs Costs.$MMKWU Costs,¢/KliH
78-79 33.8 .......------------0.3 0.2 ---34.3 776 4.4
79-60 36.6 ---------------0.3 0.2 ---37.1 823 4.5
80-81 39.4 ._-------------0.3 0.2 ---39.9 855 4.7
81-82 41.6 ---------------0.3 0.2 ---42.1 887 4.7
82-83 35.6 ------6.9 ---.-.0.3 0.2 ---43.1 919 4.7
83-84 33.1 ------7.2 --- ---
0.3 0.2 ---40.8 951 4.3
84-85 30.3 ...---7.3 ------0.3 0.2 ._-38.2 983 3.9
85-86 26.2 -.----1.5 ------0.3 0.2 ---36.6 1015 3.6
85-87 26.1 ------7.1 --..--0.3 0.2 ---34.3 1047 3.3
87-88 24.0 _..---7.8 ------0.3 0.2 ..-32.4 1019 3.0
88-89 22.9 2.6 0.5 1.7 ------0.3 0.2 2.9 34.2 1111 3.1
89-90 23.1 21.5 4.3 10.0 ------3.5 1.0 25.0 63.4 1144 5.6
90-91 20.9 27.6 5.5 10.0 ---.--3.5 1.0 31.4 68.5 1176 5.8
......91-92 21.1 21.6 5.5 12.4 ------18.8 2.0 46.4 61.4 1208 7.2
0
0 92-93 18.2 21.6 5.5 13.3 ------18.8 2.0 46.4 85.5 1240 f.9
93-94 18.4 27.6 5.5 14.I ------18.8 2.0 46.4 1l6.4 1272 6.6
94-95 18.5 21.6 5.5 6.9 36.2 0.1 18.8 2.0 C2.6 115.6 1305 8.8
95-96 16.9 32.3 6.4 6.5 36.2 0.1 18.8 2.0 B2.6 119.2 1337 B.9
96-97 14.3 32.3 6.4 1.3 36.2 0.1 18.8 2.0 82.6 117.5 1369 8.6
97-98 3.8 32.3 6.4 9.6 36.2 0.1 18.8 2.0 82.6 10!U 1401 7.11
98-99 3.8 32.3 6.4 10.1 36.2 0.1 16.8 2.0 82.6 109.1 1433 7.6
99-2000 3.6 32.3 6.4 3.1 411.3 0.2 10.11 2.0 99.4 114.9 1466 1.8
00-01 3.8 32.3 6.4 2.7 41L3 0.2 H\.8 2.0 99.4 114.5 1470 1.8
01-02 3.B 32.3 6.4 2.1 48.3 0.2 16.6 2.0 99.4 114.5 1474 1.7
02-03"1.5 32.3 6.4 2.4 46.3 0.2 18·a 2.0 99.4 111.9 1478 7.6
03-04 1.5 32.3 6.4 2.5 48.3 0.2 IB.8 2.0 99.4 112.0 1482 7.6
04-05 1.5 32.3 6.4 2.6 4B.3 0.2 10.8 2.0 99.4 112.1 14B7 7.5
05-06 ---32.3 6.4 2.7 48.3 0.2 18.8 2.0 99.4 110.7 1491 7.4
06-07 .-.32.3 6.4 2.8 48.3 0.2 18.8 2.0 99.4 110.8 1495 7.4
07-08 ---32.3 6.4 2.9 48.3 0.2 IB.B 2.0 99.4 110.9 1499 7.4
08-09 --.32.3 6.4 3.1 48.3 0.2 18.8 2.0 99.4 111.1 1503 1.4
09-10 ---32.3 6.4 3.2 48.3 0.2 18.8 2.8 99.4 111.2 1507 7.4
IO-IJ ---32.3 6.4 3.4 411.3 0.2 lIJ.B 2.0 99.4 111.4 1511 1.4
)))
)
TABLE 4.24.Fairbanks-Tanana Valley Area.Low Growth Scenario.Case 3.5%Inflation
New f1ydroelectr1c Transm1ss 10n
Total Cost New Coal Fired Capacity Costs Systems Tobl Totlll Total System
of Ex1stlng Investment OM&R Coal Inves-tment OM&R 1.J1ves tment OM&R Investment System Consumpt10n.Averagl;!Power
~Capacity .Costs__Costs CostL-Costs Costs .Cost_s_Costs Costs Costs.S MMKWfI Costs.t/KWH
78-79 30.5 ---------------0.2 0.2 -'--30.9 778 4.0
79·80 33.9 -.-------._----0.2 0.2 ---34.2 823 4.2
80-Bl 37.4 ---------------0.2 0.2 ---31.a-855 4.4
81-82 '40.7 ---------------0.2 0.2 ---4].0 887 4.6
82-83 36.6 -.----6.9 ------0.2 0.2 ---43.9 919 4.8
83-84 35.6 ------7.2 ------0.2 0.2 ---43.2 951 4.5
84-85 33.5 -,.....---7.3 -.----0.2 0.2 .--41.3 983 4.2
85-86 32.3 ------7.5 ------0.2 0.2 ---40.3 1015 4.0
86-87 30.4 ------B.l ------0.2 0.3 ---3B.9 1047 3.1
87-88 28.7 c-.....---8.6 ------0.2 0.3 ---37.8 1019 3.5
88-89 27.9 4.2 0.7 8.9 ------0.2 0.3 4.4 42.4 111l 3.8
B~·90 29.3 36.6 7.0 12.1 ------4.5 1.7 41.1 91.3 1144 7.9
90-91 28.4 4B.0 1.4 12.7 ------4.5 I.B 52.5 102.8 1176 8.7
--'91-92 30.1 48.0 10.3 16.4 .-----32.4 3.5 80.4 140.1 1208 11.6a
--'92-93 26.7 48.0 10.8 lB.7 ------32.4 3.6 60.4 140.3 1240 11.3
93·94 26.1 48.0 11.4 20.6 ------32.4 3.8 80.4 144.3 1272 11.3
94·95 29.5 46.0 11.9 10.1 76.2 0.3 32.4 4.0 156.6 213.1 1305 16.3
95-96 2B.B 58.8 14.6 10.5 16.2 0.3 32.4 4.2 167.4 225.8 1331 .16.9
96-97 21.1 58.8 15.3 12.4 76.2 0.3 32.4 4.4 167.4 221.5 1369 16.6
97-98 6.1 58.8 16.1 16.9 76.2 0.4 32.4 4.6 167.4 211.5 1401 15.1
98-99 6.4 58.B 16.9 10.9 16.2 0.4 32.4 4.8 167.4 214.8 1433 15.0
99-2000 6.6 58.8 17.7 5.9 IOB.6 0.8 32.4 5.1 199.8 .l36.0 1466 16.1
00·01 7.0 511.8 Ill.6 5.4 108.6 0.8 32.4 5.3 199.8 236.9 1470 •16.1
01·02 7.3 58.8 19.6 5.8 1Oil.6 0.9 32.4 5.6 199.8 239.0 1474 16.2 .
02-03 2.7 58.8 20.5 5.5 10B.6 0.9 32.4 5.9 199.8 235.3 1478 15.9
03-04 2.8 5B.B 21.6 5.9 108.6 1.0 32.4 6.2 199.8 237.3 1462 16.0
04-05 2.9 58.8 22.6 6.5 108.6 1.0 32.4 6.5 199.8 239.3 1487 16.1
05-06 -_.58.8 23.1 7.1 108.6 1.1 32.4 6.6 199.6 238.5 1491 16.0
06·07 -.-58.8 24.9 7.8 106.6 1.1 32.4 7.2 199.8 240.8 1495 16.1
07-0B ---58.8 26.2 8.5 106.6 1.2 32.4 7.5 199.8 243.2 1499 16.2
08-09 ---58.8 27.5 9.3 10B.6 1.2 32.4 7.9 199.6 245.7 1503 16.3
09-10 ---58.8 28.9 10.2 lOB.6 1.3 32.4 B.3 199.8 248.5 1507 16.5
10·11 ---56.6 30.3 11.1 108.6 1.4 32.4 B.7 199.8 251.3 1511 16.6
))
Il\]lE 4.26.Fairbanks-Tanana Valley Area.Medium Growth Scenario.Case 1*5%Inflation
New Hydroelectric Transm15s Ian
Total Cost New Coal Fired Capdclty Costs S.Y~tt'JlS Total Total Total System
of Existing TiiVestment OM&R (oa"-TriVes tment -OM&R"""nves tmen OM&R Investment System Consumption.Average POlo/er
~~a£ll.L...Costs fasts Costs ~!.L.-Costs Costs CoSh Costs Costs I $MMKWH Costs,t!I<WtI
78-79 30.5 -.-------0.2 0.2 .--30.9 604 3.8
79-80 33.9 ---------0.2 0.2 ---34.2 862 4.0
80-81 37.4 ---------0.2 0.2 ---37.8 916 4.1
81-82 40.7 ---------0.2 0.2 ---41.0 970 4.2
82-83 36.6 ------6.9 0.2 0.2 ---43.9 1024 4.3
83-84 35.6 ------7.2 0.2 0.2 ---43.2 1078 4.0
84-85 33.5 ------7.3 0.2 0.2 ---41.3 \132 3.6
85-136 32.3 26.6 5.3 9.4 4.4 1.2 31.0 79.2 1193 6.6
86··67 30.4 26.6 5.5 11.4 4.4 1.3 31.0 79.6 1254 6.3
87-88 28.7 26.6 5.8 13.6 4.4 1.4 31.0 80.5 1315 .6.1
83-89 27.9 30.8 7.0 15.4 4.4 1.5 35.2 87.0 1376 6.3
89-90 29.3 63.2 13.6 17.6 4.4 1.5 67.6 129.7 1437 9.0
90-91 28.4 74.6 16.4 19.3 4.4 1.6 79.0 145.3 1505 9.6
-~91-92 30.1 74.6 16.4 22.3 4.4 1.7 79.0 149.5 1573 9.5
0 92-93 26.1 112.1 23.8 25.5 4.4 1.8 116.5 194.4 1641 11.8W
93-94 28.1 112.1 25.0 28.5 4.4 1.9 116.5 200.1 1709 11.7
94-95 29.5 112.1 26.2 31.fl 4.4 2.0 116.5 206.1 1777 11.6
95-96 28.8 122.9 29.7 35.13 4.4 2.2 121.3 223.8 1859 12.0
96-97 21.1 169.5 40.1 40.7 8.5 2.3 178.0 288.8 1941 14.9
97-98 6.1 217.4 51.7 48.5 8.5 2.4 225.9 334.6 2023 16.!)
98-99 6.4 267.7 64.1 54.0 8.5 2.6 276.2 403.4 2105 19.2
99-2000 6.6 267.7 67.3 59.9 8.5 2.7 276.2 412.7 2187 18.9
00-01 7.0 267.7 70.7 65.3 8.5 2.8 276.2 422.0 2229 111.9
01-02 7.3 267.7 74.3 71.1 8.5 3.0 276.2 431.9 2270 19.0
02-03 2.7 267.7 77.9 17.6 0.5 3.2 276.2 437.6 2312 18.9
03-04 2.8 365.0 77.9 77.6 8.5 3.4 373.5 561.5 2353 23.9
04-05 2.9 365.0 102.1 92:1 8.5 3.6 373.5 574\2 2395 24.0
05-06 --365.0 107,2 100.3 8.5 3.7 373.5 584.7 2437 24.0
06-07 ---365.0 112.6 109.1.a.5 3.8 373.5 599.0 2478 24.2
07-08 ---365.0 1l!l.2 llB.7 8.5 4.2 373.5 614.4 2520 24.4
08-09 ---365.0 124.1 129.1 8.5 4.2 373.5 630.9 2561 2·1.6
09-10 ---365.0 130.3 140.4 8.5 4.4 373.5 648.6 2603 24.9
10-11 ---365.0 136.8 152.5 8.5 4.5 373.5 667.3 2645 25.2
TABLE 4.27.Fairbanks-Tanana Valley Area,Medium Growth Scenario~Case 2~0%Inflation
New I/ydroe 1ectrl c Transmission
Total Cost New Coal Fired Ca~ac~!y Costs Systems Total Total Tota 1 System
of Existing Investment nM&R ·Coar--1nves tmentOM&rr TiiVestment OM&R Investment System Consumption.Average Power
.J.lli-CapacHy Costs Costs Costs Costs Costs Costs ~Costs CO$ts.S M~IK~JH Costs.¢/KWH
78-19 33.8 ---------0.3 0.2 ---34.2 804 4.3
19-80 36.6 ---------0.3 0.2 ---37.0 862 4.3
80-81 39.4 ---------0.3·0.2 ---39.8 916 4.3
81·82 41.6 ------._-0.3 0.2 ---42.1 970 4.3
82-83 35.6 ------6.9 0.3 0.2 ---43.0 1024 4.2
83-64 33.1 ------7.2 0.3 0.2 ---40.8 1078 3.8
84-85 30.3 ------7.3 0.3 0.2 ---36.1 1132 3.4
85-86 2e.2 18.9 3.8 9.4 3.5 1.0 22.4 64.9 1193 5.4
86-81 26.1 18.9 3.6 10.9 3.5 1.0 22.4 64.2 1254 5.1
87-88 24.0 18.9 3.8 12.4 3.5 1.0 22.4 63.7 1315 4.8
8il-89 22.9 21.5 4.3 13.3 3.5 1.0 25.0 66.6 1376 4.8
89-90 23.1 21.5 4.3 14.5 18.8 2.0 40.3 64.2 1437 5.8
90-91 20.9 27.6 6.5 19.1 18.8 2.0 46.4 89.0 1505 5.9
91-92 21.1 21.6 5.5 15.2 18.8 2.0 46.4 90.2 1573 5.7
C)92-93 18.2 27.6 5.5 16.0 18.8 2.0 26.4 80.2 1641 5.4,f;:.
93-94 13.4 27.6 5.5 16.9 10.0 2.0 46.4 09.2 1709 5.2
94-95 18.5 46.5 9.2 19.8 18.8 2.0 65.3 .114.9 1777 6.5
95-96 16.9 70.1 13.8 22.1 1ll.B.2.0 06.9 143.7 1859 7.7
96-91 14.3 70.1 13.8 24.0 18.8 2.0 08.9 143.2 1941 7.4
97-9/1 3.76 69.0 17 .5 27.3 111.8 2.0 101.8 158.5 2023 7.-8
98-99 3.1 10].9 21.2 23.9 13.3 2.0 126.7 182.6 2105 8.7
99-2000 3.7 107.9 21.2 30.7 18.n 2.0 126.7 184.5 21B7 6.4
GO·Ol 3.B 107.9 21.2 31.8 18.8·2.0 126.7 185.5 2229 8.3
01-02 3.8 107.9 21.2 33.1 18.8 2.0 126.7 186·.8 2270 8.2
02-03 1.5 126.8 24.9 34.2 18.8 2.0 145.6 208.2 2312 9.0
03-04 1.5 126.8 24.9 35.6 18.8 2.0 145.6 209.6 2353 8.9
04-05 1.5 126.8 24.9 37.0 18.8 2.0 145.6 211.0 2395 8.6
05-06 ---126.8 24.9 3B.44 18.3 2.0 145.6 210.9.2437 8.6
06-07 ---126.8 24.9 39.6 18.8 -2.0 145.6 212.3 2478 8.6
07-08 ...126.8 24.9 41.3 11l.8 2.0 145.6 213.8 2520 8.5
08-09 ---126.8 24.9 42.8 lB.8 2.0 145.6 215.3 2561 8.4
09-10 ._-126.0 24.9 44.3 18.3 2.0 145.6 216.9 2603 8.3
10-11 ---126.8 24.9 45.9 18.8 2.0 145.6 218.4 2645 8.2
)c,)
I..
'\
J
TABLE 4.28.Fairbanks-Tanana Valley Area.Medium Growth Scenario.Case 2.5%Inflation-------
New Hydroelectr1c Transm1ss1on
Tohl Cost New Coal F1red capac~!y Costs Systems Total ,Total Total System
of Exist1ng lnvostment---TIM&--R--',oal---,Investment of.l&R-·1nves tmen t OM&R Investment System Consumpt1on.Average Power
~!r-Capacity Costs Costs Costs CostL_fosts Costs Costs Costs Costs,S ~_'H__~-Li/K"'H
78-79 30.5 ---------0.2 0.2 ---30.9 804 3.8
79-80 33.9 ---------0.2 0.2 ---34.2 862 4.0
80-81 37.4 -.-------0.2 0.2 ---37.8 916 4.1
81-82 40.7 ---------0.2 0.2 ---41.0 970 4.2
82-83 36.6 ------6.9 0.2 0.2 ---43.9 1024 4.3
83-84 35.6 ------7.2 0.2 0.2 ---43.2 1078 4.0
84-85 33.5 ---7.3 0.2 0.2 ---41.3 1132 3.6
85-86 32.3 26.6 5.3 9.4 4.4 1.2 31.0 79.2 1193 6.6
86-117 30.4 26.6 5.5 11.4 4.4 1.3 31.0 79.6 1254 6.3
87-88 28.7 26.6 5.6 13.6 4.4 1.4 31.0 80.5 1315 6.1
68-89 27.9 30.8 7.0 15.4 4.4 1.5 35.2 87.0 ,1376 6.,3
89-90 29.3 30.9 7.3 17.6 29.7 3.2 60.6 118.1 1437 8.2
90-91 26.4 42.3 9.8 16.0 29.7 3.4 72.0 131.8 1505 6.7
.....91-92 30.1 42.3 10.3 20.2 29.7 3.5 72.0 136.1 1573 8.6
0 .
U1 92-93 26.7 42.3 10.8 22.4 29.7 3.7 72.0 135.7 1641 8.3
93-94 28.1 42.3 11.4 24.7 29.7 3.9 72.0 140.1 1709 8.2
94-95 29.5 83.7 20.2 30.5 29.7 4.1 113.4 197.8 1777 11.1
95-96 28.8 137.9 31.'}35.8 2').7 4.3 167.6 268.5 1859 14.4
96-97 27.7 137.9 33.5 40.7 29.7 4.5 167.6 274.0 1941 14.1
97-98 6.1 165.8 44.7 48.5 29.7 4.7 215.5 319.5 2023 15.8
98-99 6.4 236.1 56.6 54.0 '29.7 5.0 265.8 388.1 2105 18.4
99-2000 6.6 236.1 59.6 59.9 29.7 5.2 265.8 397.1 2187 18.2
00-01 7.0 236.1 62.6 65.3 29.7 5.5 265.8 406.2 2229 18.2
01-02 7.3 236.1 65.7 71.1 29.7 5.7 265.8 415.6 2270 10.3
02-03 2.7 291.2 81.1 77 .5 29.7 6.0 326.9 494.3 2312 21.4
03-04 2.8 297.2 05.2 84.4 29.7 6.3 326.9 505.7 235.3 21.5
04-05 2.9 297.2 89.5 92.1 29.7 6.7 326.9 518.2 2395 21.6
05-06 ---~97.2 93.9 100.2 29.7 7.0 326.9 528.1 2437 21.7-06·07 ---297.2 90.6 109.1 29.7 7.3 326.9 541.9 2470 21.9
07-08 ---297.2 103.6 118.7 29.7 7.7 326.9 556.9 2520 22.1
03-09 -_.297.2 108.7 129.1 29.7 8.1 326.9 572.8 2561 22.4
09-10 ---297.2 114.2 140.3 29.7 8.5 326.9 590.0 2603 22.7
10-11 ---297.2 119.9 1~2.5 29.7 0.9 326.9 606.2 2645 23.0
TABLE 4.29.Fairbanks-Tanana Valley Area.Medium Growth Scenario.Case 3.0%Inflation
New Hydroclectdc Transm15sion
Total Cost New Coal fired capacity Costs Systems Total Total Tota 1 Sys tem
of Existing Investment OM&R Coal Investnlent OM&R Investment OM&R Investment System Consumption,Average Power
..1ru:-.Capacity Costs fQill Costs ~2_H1_fQ.ill..~lliL....Costs Costs Costs.$HHKl-IlI Cost5,t/KWIi
7B-79 33.B·---------------0.3 0.2 ---34.2 B04 4.3.
79-80 36.6 ----...---- ---
---0.3 0.2 37.0 862 4.3
80-81 39.4 0.3 .0.2 39.8 •916 4.3------------------
81-82 41.6 ---------------0.3 0.2 ---42.1 970 4.3
82-83 35.6 ------6.9 ------0.3 0.2 ---43.0 1024 4.2
83·84 33.1 ------7;2 ------0.3 0.2 ---40.11 1078 3.8
114-65 30.3 ----.-7.3 ------0.3 0.2 ---3B.l 1132 3.4
65-86 28.2 18.9 3.8 9.4 ------3.5 1.0 22.4 64.9 1193 5.4
06-87 26.1 18.9 3.8 10.9 ------3.5 1.0 22.4 64.2 lZ54 5.1
87-88 24.0 18.9 3.8 12.4 ------3.5 1:0 22.4 63.7 1315 4.8
88-89 22.9 21.5 4.3 13.3 ------3.5 1.0 25.0 66.6 1376 4.8
89-90 23.1 <'1.5 4.3 14.5 ------18.8 2.0 40.3 84.2 1437 5.8
90-91 20.9 27.6 5.5 19.1 ------18.11 2.0 46.4 89.0 1505 5.9
91-92 21.1 27.6 5.5"15.2 ------18.8 2.0 46.4 90.2 1573 5.7
0 92·93 18.2 27.6 5.5 16.0 18.8 2.0 26.4 88.2 1641 5.40'\------
93-94 13.4 27.6 5.5 16.9 ------18.0 2.0 46.4 89.2 1709 5.2
:H-95 18.5 27.6 .5.5 13.6 34.4 0.1 ·18.8 2.0 80.8 .120.5 1777 6.8
9S-'J6 16.9 32.3 6.4 13.9 34.4 0.1 18.0 2.0 85.5 124.8 .1859 6.7
96-97 14.3 32.3 6.4 15.6 34.4 Q.l 18.8 2.0 85.4 124.0 1941 6.4
97-38 3.7 51.2 10.2 10.7 34.4 0.1 1ll.O 2.0 104.4 139.2 20ll 6.9
98-99 3.7 51.2 10.2 13.0 45.9 0.2 18.8 2.0 115.9 145.1 2105 6.9
99-2000 3.7 51.2 10.2 13.6 45.9 0.2 10.8 2.0 115.9 145.7 21117 6.7
00-01 3.8 51.2 10.2 14.4 45.9 0.2 18.8 2.0 115.9 146.5 2229 6.6
01-02 3.8 51.2 10.2 15.3 45.9 0.2 18.8 2.0 115.9 147.4 2270 6.5
02-03 1.5 70.1 14.0 16.1 45.9 0.2 18.8 2.0 134.8 168.6 2312 7.3
03·04 1.5 70.1 14.0 17 .1 45.9 0.2 18.8 2.0 134.8 169.6 2353 7.2
04-05 1.5 70.1 14.0 10.1 45.9 0.2 18.0 2.0 134.8 170.6 2395 7.1
05-06 ---70.1 14.0 19.2 45.9 0.2 18.8 2.0 134.8 110.2 2437 7.0
06-07 --.70.1 14.0 20.2 45.9 0.2 18.8 2.0 134.8 171.2 2478 6.9
07-08 ---70.1 14.0 21.3 45.9 0.2 18.8 2.0 134.6 172.3
2520 6.6
08-09 ---70.1 14.0 22.4 45.9 0.2 10.8 2.0 134.8 173.4 2561 6.8
09-10 --.70.1 14.0 23.6 45.9 0.2 18.6 2.0 134.6 174.6 2603 6.7
lO-n ---70.1 14.0 24.7 45.9 0.2 16.6 2.0 134.6 175.7 2645 6.6
)))
I )
I
TABLE 4.30.Fairbanks-Tanana Valley Area,Medium Growth Scenario.Case 3,5%Inflation
New Hydroelectric Tr\lnSRlisSion
Total Cost New COdl Fired Capacit~Costs --.Jlltems Total Total Total ~ystem
of Existing Investment OM&R COdl Investment OM&R Investment OM&R Investment System Consumption.Average Power
~Capacity Costs Costs Costs __C(lsts_fQ.ili.-..f.2!!_s_Costs Costs Costs.S tJ.MKWH Costs.aKWH
78-79 30.5 ---------------0.2 0.2 ---30.9 804 3.6
79-80 33.9 ----.----._----0.2 0.2 ---34.2 662 4.0
60-81 37.4 ---------------0.2 0.2 ---37.8 916 4.1
61-82 40.7 -------.-------0.2 0.2 ---41.0 970 4.2
82-63 36.6 --.._-6.9 ----.-0.2 .0.2 -..43.9 1024 4.3
63-64 35.6 ------7.2 -_.---0.2 0.2 ---43.2 1078 4.0
84-85 33.5 ---.--7.3 ------0.2 0.2 ---41.3 1132 3.6
65-66 32.3 26.6 5.3 9.4 ------4.4 1.2 31.0 79.2 1193 6.6
66-87 30.4 26.6 5.5 11.4 ------4.4 1.3 31.0 79.6 1254 6.3
87-88 28.7 26.6 6.8 13.6 ------4.4 1.4 31.0 60.5 1315 6.1
88-69 27.9 30.8 7.0 15.4 ------4.4 1.5 35.2 67.0 1376 6.3
89-90 29.3 30.9 7.3 17.6 ------29.7 3.2 60.6 .116.1 1437 8.2
90-91 28.4 42.3 9.8 18.0 ------29.7 3.4 72.0 131.8 1505 6.7
--'91-92 30.1 42.3 10.3 20.2 ---29.7 3.5 72.0 136.1 1573 8.6
0 .
""-I 'J2-9J 26.7 42.3 10.8 22.4 ------29.7 3.7 72.0 135.7 1641 8.3
93-94 28.1 42.3 11.4 24.7 -.----29.7 3.9 72.0 140.1 1709 B.2
94-95 29.5 42.2 11.9 20.9 72.5 0.2 29.7 4.1 144.4 211.2 1777 11.8
95-96 28.8 53.0 14.7 22.6 72.5 0.3 29.7 4.3 155.2 .225.9 1859 12.1
96-97 27.7 53.0 15.4 26.5 72.5 0.3 29.7 4.5 155.2 229.6 1941 11.8
97-98 6.15 100.9 25.7 33.2 72.5 0.3 29.7 4.7 203.1 273.1 2023 13.5
98-99 6.4 100.9 26.9 24.4 101.8 0.7 29.7 4.9 232.4 295.7 2105 14.0
99-2000 6.6 100.9 28.3 26.4 101.8 0.7 29.7 5.2 232.4 299.6 2187 13.7
00-01 7.0 100.9 29.7 29.5 101.0 0.8 29.7 5.5 232.4 305.1 2229 13.7
01-02 7.3 100.9 31.2 32.0 101.0 0.8 29.7 5.7 232.4 310.2 2270 13.7
02-03 2.7 162~0 44.9 36.6 101.8 0.9 29.7 6.1 293.5 3B4.7 2312 16.6
03·04 2.B 162.0 47.1 40.6 101.6 0.9 29.7 6.4 293.5 391.3 2353 16.6
04-05 2.9 162.0 49.5 45.1 101.8 1.0 29.7 6.7 293.5 398.7 2395 16.6
05-06 ---162.0 51.9 50.0 101.8 1.0 29.7 7.0 293.5 403.4 2437 16.6
06-07 ---162.0 54.6 55.3 101.8 1.1 29.7 7.3 293.5 411.8 2478 16.6
07-08 ---162.0 57.3 61.2 10).8 1.1 29.7 7.7 293.5 420.8 2520 16.7
08-09 -.-162.0 60.2 67.5 101.8 1.2 29.7 8.7 293.5 430.5 2561 16.8
09-10 -.-162.0 63.2 74.5 101.8 1.2 29.7 8.5 293.5 440.9 2603 16.9
10-11 ---162.0 66.4 1I2.1 101.8 1.3 29.7 8.9 293.5 452.2 2645 17 .1
TABLE 4.31.Fairbanks-Tanana Valley Area.High Growth Scenario.Case 1,0%Inflation
New lIydroelectric Trdn~mls~ion
Total Cost f!!!~LfJ!ed Callilc~Costs Systems Total Total Tota 1 System
of Existing TriVestment OM&R Coa Investme~&R Invl'!s tPil'nt OM&R Investment System Consumption,Average Power
~Capacity CMU Costs Costs Cost~fosts Costs Cos!!.Costs Costs.$Ml4KWH Cos ts t't/KWH
78-79 38.8 -------.-0.3 0.2 ---34.2 032 4.1
79-80 '36.6 ---------0.3 0.2 --.37.0 903 4.1
80-81 39.4 ---------0.3 0.2 ---39.8 931 4.1
81-82 41.1 ---------0.3 0.2 ---42.1 1059 4.0
82-83 35.7 ---_...-6.9 0.3 0.2 ---43.0 1137 3.8
83-84 33.2 ------7.2 0.3 0.2 ---40.8 1215 3.4
94·85 30.4 13.9 3.8 9.1 3.5 1.0 22.4 66.7 1294 5.2
85-86 2lJ.3 18.0 3.8 10.6 3.5 1.0 22.4 66.2 1396 4.7
86-87 26.1 37.8 7.6 12.1 3.5 1.0 41.3 88.2 1498 5.9
87-88 24.1 37-11 7.6 15.6 3.5 1.0 41.3 89.7 1600 5.6
88-89 22.9 40.4 8.1 17.2 3.5 1.0 43.9 93.1 1702 5.5
89-90 23.1 59.3 11.9 lB.7 3.5 1.0 62.8 117.6 1805 6.5
90-91 20.9 65.4 13.1 20.5 3.5 1.0 68.9 124.4 1927 6.5
--I 91-92 21.1 65.4 13.1 22.5 3.5 1.0 60.9 126.7 2049 6.20
CO 92-93 18.3 84.3 16.9 24.6 3.5 1.0 87.8 148.7 2172 6.8
93-94 18.4 84.3 16.9 26.8 3.5 1.0 07.8 150.9 2294 6.6
94-95 18.5 103.2 20.7 28.8 5.3 1.8 108.5 178.3 2417 7.4
95-96 16.9 107.9 21.6 31.5 5.3 1.8 113.2 85.0 2585 7.2
96-97 14.4 126.8 25.4 34.8 5.3 1.8 132.1 200.5 2i54 7.6
97-98 3.8 155;5 31.1 39.5 5.3 1.8 160.8 237.0 2922 0".1
98-99 3.8 184.2 36.0 42.4 5.3 1.8 189.5 274.4 3091 •8.9
99-2000 3.8 \8·1.2 36.8 45.0 5.3 1.8 189.5 286.7 3260 8.8
00-01 3.8 184.2 36.8 48.5 5.3 1,8 189.5 200.4 3396 8.3
01-02 3.8 184.2 36.8 51.5 5.3 1.8 189.5 283.4 3531 "8.0
02-03 1.5 184.2 36.0 51.3 5.3 1.8 189.5 2!l3.9 3667 7.7
03-04 1.5 212.9 42.5 .57.6 5.3 1.0 218.2 321.6 3003 8.5
01-05 1.5 212.9 42.5 60.9 5.3 1.8 218.2 324.9 3939 8.2
05-06 .-212.9 42.5 6<1.3 5.3 1.8 218.2 326.8 4074 8.0
06-07 ---212.9 42.5 67.7 5.3 1.8 218.2 330.2 4210 7.8
07-0B ---241.6 48.2 71.3 7.1 2.6 240.7 370.8 4346 8.5
00-09 ---241.6 48.2 74.9 7.1 2.6 248.7 374.4 4481 8.4
09-10 ---241.6 48.2 78.7 7.1 2.6 248.7 .378.2 4617 8.2
10-11 ---241.6 40.2 82.6 7.1 2.6 248.7 382.1 4753 8.0
J 0 ))
-;"
)
TABLE 4.32.Fairbanks-Tanana Valley Area.High Growth Scenario.Case 1,5%Inflation------
New Hydroelectrlc Transmiss ton
Total Cost New Coal Fired Call!£~Costs ~tems Total Total Total System
of Existing TiiVestment OMllf-oal lilves tment-OOll nvestmenr---oM~Investment System Consumption.Average Power
.1£!L..-Capacity Costs Costs Cos~Costs ~Costs ~Costs Costs.S MMKl>iH Cos ts.j/KIIH
70-79 30.6 ---------0.2 0.2 ---30.9 832 3.7
79-80 33.9 ---_......---0.2 0.2 ---34.2 903 3.8
80-81 37.5 ---------0.2.0.2 ---37.8 081 3.9
81-82 40.1 ---------0.2 0.2 ---41.0 1059 3.9
82-83 36.7 ------6.9 0.2 0.2 _.-43.9 1131 3.9
83-84 35.6 ------7.2 0.2 0.2 ---43.2 1215 3.6
84-85 33.6 25.4 5.0 9.1 4.4 1.2 29.8 78.a 1294 6.1
85-86 32.4 25.4 5.2 10.6 4.4 1.3 29.8 19.4 1396 5.7
85-87 30.4 43.3 11.0 12.7 4.4 1'.3 57.1 113.2 1498 7.6
87-88 28.7 53.3 II .5 17.1 4.4 1.4 57.7 lI6.5 1600 1.3
88'-89 21.9 57.5 13.0 19.8 4.4 1.5 61.9 124.1 1702 1.3
89-90 29.4 69.9 20.1 22.7 4.4 1.6 94.3 16B.l 1805 9.3
90-91 28.5 10).3 23.2 26.1 4.4 1.1 105.1 185.3 1927 9.6
91-92 :iO.l 101.3 24.3 29.9 4.4 1.1 105.7 191.1 2049 9.4
0 92-93 26.8 138.8 32.9 34.6
4.4 1.8 143.2 239.3 2172 11.0to
93-94 28.1 138.8 34.6 39.2 4.4 1.9 143.2 247.0 2294 10.8
94-95 29.6 180.2 44.5 44.3 8.4 3.6 188.6 310.7 2417 12.8
95-96 28.8 191.0 48.9 51.0 8.4 3.1l 199.4 331.9 2585.12.8
96-91 25.1 237.6 57.9 58.9 8.4 4.0 246.0 392.5 2754 14.2
97-98 6.2 310.2 75.2 70.0 8.4 4.3 318.6 474.3 2922 16.2
98·99 6.4 386.4 94.0 19.3 8.4 4.6 394.8 ,579.2 3091 lB.7
99-2000 6.7 386.4 98.7 1l9.3 8.4 4.8 394.8 594.3 3260 18.2
00-01 7.0 386.4 103.7 99.5 8.4 5.1 394.8 610.1 3396 11.9
01-02 1.3 386.4 108.8 lIO.7 .8.4 5.3 394.8 626.9 3531 17 .1
02-03 2.1 386.4 114.3 123.1 B.4 5.6 394.8 640.5 .3667 11.5
03-04 2.8 483.1 139.3 136.6 8.4 5.8 492.1 776.6 3803 20.4
04-05 2.9 433.7 146.3 151.5 8.4 6.0 492.1 798.8 3939 20.3
05-06 -.-433.1 153.6 161.6 8.4 6.3 492.1 819.6 4074 20.1
06-07 483.1 161.2 185.3 8.4 6.7 492.1 845.3 4210 20.1
07-08 ---602.0 192.8 204.7 16.5 10.2 618.5 1026.2 4346 23.6
08-09 !""--602.0 202.5 225.9 16.5 10.5 610.5 1057.4 4431 23.6
09-10 ---602.0 212.6 248.9 16.5 10.9 618.5 1090.9 4617 23.6
10-11 ---602.0 223.2 274.0 16.5 11.4 618.5 1121.1 4153 23.1
TA BL l3·33.Fairbanks-Tanana Valley Area,High Growth Scenario.Case 2,0%Inflation
New Ilydroelectrlc Transml ss Ion
Total COst ·New Coal Fired Capacity Costs Systems Total Total Tlltal System
of Existin9 Investment OM&R Coal inves tlnent OM&R Investment OM&R Investment System Consumption,Average Power
~Capacity Costs Costs Costs Costs Costs Costs ~sts Costs Cos.!h-1 MHK',lfI Costs,tlKIiH
78-79 33.8 ---------0.3 0.2 ---34.2 832 4.1
79-80 36.6 ---_.----0.3 0.2 ---.37.0 903 4.1
60-81 39.4 --.------0.3 0.2 ---39.8 981 4.1
01-62 41.7 ---------n.3 0.2 ---42..1 1059 4.0
B2-83 35.7 ------6.9 0.3 0.2 _.......43.0 1137 3.8
83-64 33.2 ------7.2 0.3 0.2 ---40.8 1215 3.4
84-85 30.4 13.9 3.8 9.1 3.5 1.0 22.4 66.7 1294 5.2
85-86 28.3 16.0 3.8 10.6 3.5 1.0 22.4 6U 1396 4.7
86-87 26.1 lB.9 3.8 12.1 18.8 2.0 37.7 01.6 1490 5.5
87-88 24.0 18.9 3.8 13.7 .18.8 2.0 37.7 81.3 1600'5.1
88-69 22.9 21.5 4.3 15.0 18.8 2.0 40.3 84.6 1702 5.0
b9-90 23.1 21.5 4.3 15.4 18.8 2.0 40.3 85.2 1805 4.7
90-91 20.9 27.6 5.5 14.1 18.8 2.0 46.4 89.0 1927 4.6
-I 91-92.21.1 27.6 5.5 15.2 18.8 2.0 46.4 90.2 2049 4.4
-I 92··93 18.2 65.4 13.1 20.2 .18.a 2.0 84.2 137.8 2172 6.3'='
93-94 18.4 84.3 16.9 26.3 18.8 2.0 .103.1 166.8 2294 7.3
94-95 18.5 34.3 16.9 28.8 18.8 2.0 103.1 .169.4 2417 7.0
95-96 16.9 107.9 21.6 31.5 20.6 2.8 128.5 201.3 2585 7.8
96-97 14.3 126.8 25.4 34.8 20.6 2.8 147.4 224.8 2754 8.2
97-98 3.7 155.5 31.1 39.5 20.6 2.8 176.1 253.4 2922 8.7
98-99 3.7 155.5 31.1 42.4 20.6 2.8 176.1 256.3 3091 8.3
99-2000 3.7 155.5 31.1 45.8 20.6 2.8 176.1 259.7 3260 8.0
00-01 3.8 155.5 31.1 41J.4 -20.6 2.8 176.1 262,3 3396 7.7
01-02 3.8 155.5 31.1 51.5 20.6 2.£1 176.1 265.3 3531 7.5
02-03 1.5 155.5 31.1 54.3 20.6 2.8 176.1 265.8 3667 7.2
03-04 1.5 164.2 36.0 57.5 20.6 2.3 204.8 303.5 3303 8.0
04-05 1.5 212.9 42.5 60.8 20.6 2.0 233.5 341.2 3939 8.7
05-06 ---212.9 42.5 '64.2 20.6 2.8 233.5 343.1 4074 8.4
06-07 ---212.9 42.5 67.7 20.6 2.8 233.5 346.5 4210 ,8.2
07·08 -.-212.9 42.5 71.3 20.6 2.8 233.5 350.1 4346 8.1
08-09 ---212.9 42..5 74.9 20.6 2.8 233.5 353.7 4481 7.9
09-10 ---212.9 42.5 78.7 20.6 2.8 233.5 357.5 4617 7.7
10-11 --.212.9 42..5 1l2.5 20.6 2.8 233.5 361.4 4753 7.6
),.J
').)-)
TABLE 4.34.Fairbanks-Tanana Valley Area,High Growth Scenario,Case 2,5%Inflation
New Hydroelectric TranslRiss ion
Total Cost Ne\'l Coal Fired CaJl.!f..i!t Costs Systems Total Total Totol System
of Exf~tin9 I"vest~OM~{oal Investment o"MlR Investment OM&R Investmer,t System Consumption,Average Power
..lli!:-Capacity _-J;~Costs Cos~Costs_~Costs Costs Costs ,'.Costs,$MMKWH Costs.UK\~H
7:1!~79 30.6 ---0,2 0.2 ---30.9 832,3.1
ej,1~6!')"13:9"",,'-_.,-a:z:0.2 ---34.2 903 3.8
·:fti,';'i!",rt,','~ll:'''S,~':',''1}80"61.,,0.2 0.2 ---37.8 1 981 3.9
8:176'2\11(,'it~Wr 0.2 Q.2 ---41.0 1059 3.9'~"'{;-~1~~;':')"<
~t0:'~'36.7 '6.9 0.2 0.2 ---43.9 1137 3.9
"35.6 ------7.2 0.2 0.2 ---43.2 1215 3.6
84-85 33.6 25.4 5.0 9.1 4.4 1.2 29.8 78.8 1294 6.1
8S-86 32.4 25.4 5.2 10.6 4.4 1.3 29.6 79.4 1396 5.7
86-87 30.4 25.4 5.5 12.7 26.3 2.8 51.7 103.3 149B--6.9
87-88 28.7 25.4 5.8 14.9 26.3 2.9 51.7 104.1 1600 6.5
88-89 27.9 29.6 7.0 17.2 26.3 3.1 55.9 111.2 1702 6.5
89-90 29.3 29.6 7.3 18.7 26.3 3.2 55.9 114.6 1005 6.3
90-91 28.4 41.0 9.B 18.0 26.3 3.4 67.3 127.I 1927 6.6
--'91-92 30.1 41.0 10.3 20.2 26.3 3.6 67.3 131.5 2049 6A
-'
--'92-93 26.7 116.0 25.6 20.3 26.-3 3.7 142.3 226.8 2172 10.4
93-94 28.1 155.4 34.7 3B.4 26.3 3.9 1Ill.7 206.9 2294 17..5
94-95 29.5 155.4 36.4 44.3 26.3 4.1 161.7 2"96.2 2417 12.3
95-96 28.8 209.6 48.9 51.0 30.4 6.0 240.0 374.8 2565 14.5
96-97 27.7 256.2 60.3 58.9 30.4 6.3 266.6 439.8 2754 16.0
97-96 6.1 328.6 77.7 70.7 30.4 6.6 359.2 519.7 2922 17.8
98-99 6.4 328.0 01.6 79.3 30.4 6.9 359.2 533.5 3091 17 .3
99-2000 6.6 328.8 85.7 89.2 30.4 7.3 359.2 548.1 3260 16.8
00-01 7.0 328.8 89.9 99.5 30.4 7.7 359.2 563.3 3396 16.6
01-02 7.3 328.8 94.5 110.6 30.4 6.1 359.2 579.7 3531 16.4
02-03 2.7 328.8 99.2 123.1 30.4 8.5 359.2 592.7 3667 16.2
03-04 2.6 426.1 123.4 136.6 30.4 8.9 456.5 '728.2 3803 19.2
04-05 2.9 528.3 149.9 151.5 30.4 9.3 558.7 em.3 3939 22.1
05-06 ---520.3 157.4 167.6 30.4 9.6 550.7 893.5 4074 21.9
06-07 -_.520.3 165.3 185.3 30.4 10.3 558.7 919.6 4210 21.8
07-01l ._-528.3 173.5 204.7 30.4 10.8 558.7 947.7 4346 21.6
"08-09 ---5211.3 182.2 225.11 30.4 11.4 558.7 970.1 4481 21.8
09-10 ---528.3 191.3 248.9 30.4 11.9 558.7 1010.8 4617 21.9
10-11 ---528.3 200.9 274.0 30.4 12.5 550.7 1046.1 4753 22.0
TABLE 4.35.Fairbanks-Tanana Valley Area,High Growth Scena ri 0,Case 3,0%Infl ation
New Iiyd.'oelectrtc TranslR Iss j on
Tota 1 Cos t _~~.£i!~~Il~.£i!i'..__Costs 2tstems Total Total Total System
of hhtln9 Inves tment OHIIR·Coa 1 Inves tllleii-t-of·i&R-Inves tijJent OH&R -Investment System Consumptlon.Average Power
-1ill.-...Capacity Costs ~P6fs Costs _Costs _Q>sts Costs -Costs Costs Costs,$MMKWH £25tS.tlK1i1l
78-79 38,8 ---------------0.3 0.2 ---34.2 832 4.1
79-ll0 36.6 _.----------.--0.3 0.2 ---37.0 903 4.1
80-81 39.4 ------------.--0.3 0.2 ---39.8 931 4.1
81-82 41.7 --.------.--_.-0.3 0.2 ---42.1 1059 4.0
82-83 35.7 ------6.9 ------0.3 0.2 ---43.0 1137 .3.8
83-84 33.2 ------7.2 ------0.3 0.2 ---40.8 1215 3.4.
84-(15 30.4 13.9 3.8 9.1 -----..3.5 1.0 22.4 66.7 1294 5.2
85-85 28.3 18.0 3.8 10.6 ---.--3.5 1.0 22.4 66.2 1396 4.7
86-87 26.1 18.9 3.8 12.1 ---._.lB.B 2.0 37.7 81.8 1498 5.5
87-88 24.0 18.9 3.8 13.7 ------16.8 2.0 37.7 8t.3 1600'5.1
88-89 22.9 21.5 4.3 15.0 ------10.8 2.0 40.3 84.6 1702 5.0
89-90 23.1 21.5 4.3 15.4 ---'---18.8 2.0 40.3 85.2 1805 4.7
90-91 20.9 27.6 5.5 14.1 .--._-lB.8 2.0 46.4 89.0 1927 4.6
91-92 21.1 27.6 5.5 15 ..2 ------1£1.8 2.0 4[;.4 90.2 2049 4.4
92-93 18.2 65.4 13.1 20.2 --- ---
10.6 2.0 84.2 137.8 2172 6.3
N
93-94 16.4 84.3 16.9 26.3 ---__a 18.8 2.0 103.1 166.8 2294 7.3
94-95 18.5 84.3 16.9 22.6 29.0 0.1 18.8 2.0 132.1 192.2 2417 7.9
95-96 16.9 89.0 17.B 24.4 29.0 0.1 18.8 2.0 136.8 198.0 2505 7.7
96-97 14.4 119.0 17.8 27.4 29.0 0.1 18.8 2.0 136.8 190.5 2754 7.2
97-98 3.8 fi9.0 17.8 32.0 29.0 0.1 HI.a 2.0 136.8 192.5 2922 6.6
98~99 3.8 89.0 11.8 20.4 38.7 0.2 20.6 2.8 148.3 201.3 3091 6.5
99-2000 3.8 89.0 17.0 30.6 28.7 0.2 20.6 2.8 148.3 203.5 3260 6.2
00-01 3.8 107.9 21.6 33.0 38.7 0.2 20.6 2.8 167.2 220.6 .3396 6.7
01-02 3.6 126.8 25.4 35.7 38.7 0.2 20.6 2.8 lil6.1 254.0 3531 7.2
02-03 1.5 126.8 25.4 38.3 30.7 0.2 20.6 2.11 106.1 254.3 3667 6.9
03·04 1.5 155.5 31.1 41.2 38.7 0.2 2U.6 2.6 214.8 291.6 3003 7.7
04-05 1.5 155.5 31.1 45.6 38.7 0.2 20.6 2.8 214.8 296.0 3939 7.5
05-06 ---155.5 31.1 47.2 38.1 0.2 20.6 2.8 214.0 296.1 4074 7.:1
06-07 .-.155.5 31.1 50.3 38.7 0.2 20.6 2.8 214.6 299.2 4210 7.1
07-08 ---155.5 31.1 53.5 30.7 0.2 20.6 2.8 214.8 302.4 4346 7.0
06-09 ---155.5 31.1 56.8 38.7 0.2 20.6 2.8 214.0 305.7 4481 6.8
09·10 ---184.2 36.0 60.2 38.7 0.2 20.6 2.8 243.5 343.5 4617 7.4
10-11 --.104.2 36.8 63.7 3B.7 0.2 20.6 2.B .243.5 347.0 4753 7.3
))
Ii',
)
TABLE 4.36.Fairbanks-Tanana Valley Area.High Growth Scenario.Case 3.5%Inflation,
New Hydroelectric Transmission
Total Cost New Coal Fi red Capa£itr Costs __-2Y.stems To til 1 -JoUl Total System
of Existing Investment 0l4&R Coa 1 Investment OM&r Investment OM&R Investment System -Consumption.Average Power
~Capacity Costs !&s ts,C05ts_Costs f~!Costs Costs Costs Cos ts I $MMKllfI''CoHs,¢/Klltl
78-79 30.6 --------- ------0.2 0.2 ---30.9 832 3.7
79-80 33.9 --------------0.2 0.2 ---34.2 903 3.8
80-81 37.5 ---------------0.2 0.2 ---37.8 981 3.9
81-82 40.7 --'!"------------0.2 0.2 ---41.0 1059 3.9
82-83 36.7 ------..6.9 ------0.2 0.2 ---43.9 1137 3.9
63-84 35.6 ------7.2 ------0.2 0.2 ---43.2 1215 3.6
84-85 33.6 25.4 5.0 9.1 ------4.4 1.2 29.8 78.6 1294 6.1
85-86 32.4 25.4 5.2 10.6 ------•4.4 1.3 29.8 79.4 1396 5.7
86-87 30.4 25.4 5.5 12.7 ------26.3 2.8 51.7 103.3 149B 6.9
87-88 28.7 25.4 5.8 14.9 ------26.3 2.9 51.7 104.1 1600 6.5
88-89 27.9 29.6 7.0 17.2 ------26.3 3.1 55.9 m.2 1702 6.5
89·90 29.3 29.6 7.3 10.7 ....,..----26.3 3.2 55.9 114.6 1605 6.3
90-91 28.4 41.0 9.B 10.0 _._.---26.3 3.4 67.3 127.1 1927 6.6
--'91-92 30.1 41.0 10.3 20.2 ------26.3 3.6 67.3 131.5 2049 6.4
--'92-93 26.7 116.0 25.6 20.3 26.3 3.7 142.3 226.8 2n2 10.4w------
93-94 28.1 155.4 34.7 38.4 ------26.3 3.9 161.7 266.9 2294 12.5
94-95 29.6 155.4 36.4 34.0 61.0 0.3 26.3 4.1 242.7 347.9 2417 14 .4
95-96 28.8 166.2 40.3 39.5 61.0 0.3 26.3 4.3 253.5 366.7 25B5 14.2
96-97 27.7 166.2 42.3 46.4 61.0 0.3 26.3 4.5 253.5 374.7 2754 13.6
97-98 6.2 166.2 44.5 56.7 61.0 0.3 26.3 4.7 253.5 365.9 2922 12.5
9B-99 6.4 166.2 46.7 53.1 85.7 0.7 30.5 6.8 202.4 396.1 3091 12.8
99-2000 6.7 166.2 49.I 59.6 85.7 0.7 30.5 7.1 282.4 405.6 3260 12.4
00-01 7.0 224.4 62.4 67.8 85.7 0.8 30.5 7.5 340.6 486.1 3396 14 .3
01-02 7.3 2B2.6 77.0 76.7 05.7 0.8 30.5 7.8 398.8 568.4 3531 16.1
02-03 U 282.6 00.9 86.7 85.7 0.6 30.5 8.2 398.8 578.1 3667 15.8
03-04 2.8 380.0 104.2 97.7 85.7 0.9 30.5 8.6 496.2 710.4 3803 18.7
04-05 2.9 380.0 109.5 113.6 85.7 0.9 30.5 9.1 496.2 732.2 3939 18.6
05-06 ---380.0 114.9 123.0 05.7 1.0 30.5 9.5 496.2 744.6 4074 18.3
06-07 ---3nO.0 120.7 137.6 1J5.7 1.0 '30.5 10.0 496.2 765.5 4210 18.2
07-08 ---300.0 126.7 153.7 05.7 1.1 30.5 10.5 496.2 788.2 4346 18.1
03-09 ---380.0 133.0 171.3 85.7 1.1 30.5 11.0 496.2 812.6 4481 1B.1 ......
09-10 ---510.4 165.5 190.5 05.7 l.2 30.5 11.6 626.6 995.4 4617 21.6
10-11 ---5HU 173.7 211.5 85.7 1.3 30.5 12.2 ~626.4 1025.3 4753 21.6
All entries in the tables are in millions of dollars unless noted.The first
column is the total cost of the existing capacity.This includes investment,
OM&R,and fuel costs except coal costs after 1982-1983 as noted below.This
column includes the cost ~f the combustion turbine units planned through 1984
in the Anchorage area.The cost of existing capacity is assumed to be the
same for all load growth scenarios and system configurations.This assumption
is warrented in this case for two reasons.First,an examination of the load
resource analyses for the alternative load growth scenarios and cases reveals
relatively little variation in the plant utilization factors among the various
scenarios and cases.Second,the.cost of operating the existing capacity is a
relatively small part of the overall system costs in the 1990-2010 time period
which i~of primary interest in this report.
The next three columns present the costs for the new coal-fired capacity.
The investment cost is the total of all the individual plant investments.The
OM&R costs are the sum of all the OM&R costs of the individual plants.Entries
in these two columns begin the same year as the first coal-fired plant comes
on line.The coal costs include the coal costs of the new coal-fired capacity.
In addition,the coal costs of the existing capacity are included in this
column after 1982-1983.(It is subtracted out of the existing capacity after
1982-1983.)
The next two columns present the costs for any new hydroelectric capacity
that is added.These are the Bradley Lake project,the Watana dam and the
Devil Canyon dam.As painted out earlier the Watana.and Devil Canyon costs
are divided between the Anchorage-Cook Inlet area and the Fairbanks-Tanana
area in proportion to their relative energy consumption in 1994.
The transmission system costs are shown in the next two columns.These
columns contain the investment and OM&Rcosts for all the transmission lines
required.The total investment cost column represents the sum of the new coal-
fired capacity investment costs,the hydroelectric capacity investment costs,
and the transmission system investment costs.
The total system cost is the sum of all the costs (not including the new
investment cost column).The total system consumption figures are the same as
114
.~.
_------------------0'dL.
,,-u_m •_
:....'....'.:•...~_,...~-..'..···!'I
f 'I
}~
--CASE 1
---CASE 2
.••.........•CASE 3
1985 1990 1995 2000 2005 2010
FIGURE 4.5.Power Costs for Anchorage Low Load Growth Scenario
116
£2
CASE ':{
v\;.'(~c'~
.f :;.""
'<...••---~------.----_.---------------
CASE 1
---CASE 2
............CASE 3
/
......
.......
......
~~........."..
.......'.'........./......~..;.......
/./
..;I
.I'
30
28
26
24
22
..c:20
s
~-18Vl--c:
Q)
oS 16V')
l-
V)
0 14u
cc
w..J 12s
0
0-
lD
8
6
4
2
1985 1990 1995 2000 2005 2010
FIGURE 4.7.Power Costs for Anchorage High Load Growth Scenario
118
;~;
Power Costs for Fairbanks Low Load Growth Scenario
2010
--CASE1
---CASE 2
...••.......CASE 3
200520001995
/
/
./
(/
1
I
1
I
1
I
.........J.f·,-..
::I '.........
!I.
f J:/t······:1...
1990
30
28
26
24
22
.c 20
.S
~18VI...
Ccu
~1:6V')
t-
V')
0 14u
0::::
w.J 12s
0
Cl-
IO
8
6
4
2
1985
FIGURE 4.8.
119
"'------.........----.........-,-~----------~~-----------
,,"
-.."....--
--CASE 1
---CASE2
.•••.•.•..-CASE 3
,....:-
.
..................:
30
28
26
24
22
..r:::.20
$
.¥-18VI-C
~
~16V')
l-
V')
0 14u
0:::
U-l:s:120 J0-
ro J
I
8 ./-"'-'
6
4
2
1985 1990 1995 2000 2005 2010
FIGURE 4.9.Power Costs for Fairbanks t~ediurn Load Gro\'~th Scenario
120
CASE 1
---CASE 2
............CA SE3
...----:::::..
.
I::..·•••·•·••.••....."'••;.
li......P---../:'......:
.~.......~.....:
/
I
'/
:-'7/.'...
.....I
i-t
30
28
26
24
22
20.c:
S
~-18In-c:
QJu 16--(/')
I-
U"l
0 14u
e::::
w.J 12:s:
0
~""'a...
10
8
6
4
2
1985 1990 1995 2000 2005 2010
FIGURE 4.10.Power Costs for Fairbanks High Load Growth Scenario
121
--_..--...._......---,----,-----~--~._--------------
where:
PW =n:L APC.*----:-
i =n 1 (l +r)i
PW =Present worth of the cost of power
APe i =Average power cost in year}
r =Discount rate
n =Total number of years.
Using this formula the total investment cost and the average power cost over a
period of years can be more easily compared~A 7%discount rate is used in
these analyses.
The results for each of the load growth scenarios for both of the load
centers are briefly discussed below.
Anchorage-Cook Inlet -Low Load Growth
The present worth of the total investment and the present worth of average
power costs are shown below.
Reference P.W.Total P.W.Average
Case Table No.Investment ($)Power Costs (<tikWh)
1 2 2329 78
2 4 2251 76
3 6 2504 70
Case 3 results 1n the lowest cost of power followed by Case 2 and Case 1.
Case 2 gives the lowest overall investment costs while Case 3 results in the
hi ghest-investment costs.
122
,I""""Anchorage-Cook Inlet -Medium load Growth
Reference P.\~.Total P.W.Average
Case Table No.Investment ($)Power Costs (i/kWh)
1 8 3920 83
2 10 3930 83
3 12 3920 77
The present worth of the total investment is almost identical for all
three cases.The present worth of the cost of power is the same for Cases
and 2,.while the present worth power cost for Case 3 is lowest.
Anchorage-Cook Inlet -High load Growth
Case
1
2
3
Reference
Table No.
14
16
18
P.W.Total
Investment ($)
7053
6837
7084
P.W.Average
Power Costs (t/kWh)
86
85
83
Again Case 3 results in the lowest present worth for the CDst of power.
For this scenario Case 2 results in the lowest present worth .investment with
Cases 1 and 3 slightly higher.
Fairbanks-Tanana Valley -Low Load Growth
Reference P.W.Tota 1 P.W.Average
Case Table No.Investment ($)Power Costs (¢!kWh)
1 20 666 110
2 22 699 113
3 24 742 104
Case 3 gives the lowest cost of power while Case 1 gives the lowest
investment cost.Case 3 results in the highest present worth investment cost.
123
Fairbanks-Tanana Valley -Medium Load Growth
Case
1
2
3
Reference
Table No.
26
28
30
P.w.Total
Investment ($)
1128
1042
S70
P.~~.Average
Power Costs (¢/kWh)
117
111
99
Again Case 3 results in the lowest present worth cost of power.In this
scenario however,Case 3 also gives the lowest present worth total investment
costs.
Fairbanks-Tanana Valley -High Load Growth
Case
1
2
3
Reference
Table No.
32
34
36
P.w.Total
Investment ($)
1642
1587
1527
P.W.Average
Power Costs (¢/kWh)
115
110
103
!,..",;
Again Case 3 results in the lowest present worth cost of power and the
lowest present worth total investment.
124
i~REFERENCES -CHAPTER 4
1.Taylor,G.A.,Managerial and Engineering Economy,O.van Nostrand-
Company,Inc.,Princeton,I~J,1964.
125
-
i~.
f;.;,:.CrFl~~J ENERGY REGULATORY COMMISSION
Ii ,;-'0,:41 1,p,laSr,Q REGIONAL OFFICE\j .~_.•1·.-......-
555 BATTERY STREET,ROOM 415-"'"33","n IM.O -::1 in L:'SAN FRANCISCO,CA 941 t 1:.~~"']~hn u
March 6,1979
Mr.Robert J.Cross
Administrator
Department of Energy
Alaska Power Administration
p.O.Box 50
Juneau,Alaska 99802
Dear Mr.Cross:
This will respond to your letter of February 2,1979,requesting our
informal review and comments on your Upper Susitna Project Power
Market Draf~Report.
Although we were unable to make an in-depth review of the draft report
due to time and staffing limitations,we do wish to make the following
comments:
Page g',second paragraph,third sentence.FERC estimated costs are as
of Jul)1,1978,not October 1978 as stated.
Page 95,seccnd paragraph,last sentence.The San Francisco Regional
Office of FERC did include cost adjustments for Alaska conditions in
its power value study as it routinely does for all studies in Alaska.
Page 95,last paragraph,last sentence.The investment cost estimates
of the Fairbanks plant are $1475/kW (@ 5.7570 financing)and $1510/kW
(@ 6.875%financing).Cost estimates of the Anchorage-Kenai area
plant are $1240/kW (@ 7.94%financing)and $1220/kW (@ 6.875%financing).
Page 96,Oil and Natural Gas.Our thoughts on this subject were stated
in our October 31,1978,letter to the District Engineer,Alaska District,
Corps of Engineers.In that letter we stated that oil~fired combined
cycle and regenerative combustion turbine plants were significantly
less costly than alternative coal-fired plants for the Upper Susitna
River Basin.We are not able to state,however,which alternative is
the more probable source.The determining factors would be the Alaska
fuel situation and the interpretation of the Fuel Use Act.
..'
~~~.-:.:..__...,_..~.:_.,~,,:.,._,..,;.~._~,~~,_+,,.'._~__~_.•,.'..,·_~.L _•.•~,..,__,_._.~,_••
Mr.Robert J.Cross - 2 -
March 6,1979
While the Fuel Use Act prohibits the use of oil or natural gas as
primary fuel for electrical generation,the Department of Energy,
Economic Regulatory Administration (ERA),is promulgating regulations
which will provide for various exemptions.The regulations are ex-
pected to be issued in May.We suggest that you contact ERA on this
matter.
Page 105,item 5.The retirement schedule for combustion turbine is
.stated .to be 20 years.Most studies in the Continental United States
use 30 years.
Pages 159 and 160,Assessment of Feasibility.A cost estimate bf
Copper Valley Electric Association1s purchase of Upper Susitna power
would be useful to this discussion.
Appendix,page 21,3.2.4,Transmission Losses.The 1.5%for energy
loss appears to be lowo
We appreciate the opportunity to review and comment on your draft
report.
Sincerely,
~.-e~
Eugene Neblett
Regional Engineer
February 27,1979
Mr.Robert Cross
Department of Energy
Alaska Power Administration
P.O.Box 50
Juneau,AK 99802
Dear Mr.Cross:
R f:-{"\r.-1\./r:-0t~'l,"-v ,_j"tt 1-
I I ,..-,-..,~r f
\,:..'!'':'C1U,;"asxa
lCI~"",,\,..."!J ~Danelle,~j r:..L1 30 r~.-».
i I :~i=-"',"C'C':-',,-_.,Pacific Northwest Laboratories;:Xi\S;{~\F;:O,v='n~tgtrP,O.Box 999
,"Richland,Washington 99352
Telephone (509)942-4745
Telex 32,6345
Thank you for the opportunity to comment on your Draft Power Market Analysis.
Both Ward Swift and I read it over and came up with only a few minor comments.
The primary focus of our review was the consistency between the body of the
report and our background analysis presented in Appendix 3.
1.Page 4,2nd paragraph -The alternative on-line dates of 1990, 1992,
and 1994 seem to refer to the interconnection on-line dates for high,
medium,and low load growth cases respectively.I believe those dates
should be 1986,1989,and 1991.This would be consistent with the
dates given in the last line on page 109.
2.Page 8,"ble at bottom -It appears that the costs of power 1isted
for Case should be the same numbers listed for the Case 1 of the
combi ned sys "tS,1 in the table at the top of page 111.(i.e.,the cos ts .
of power should be 6.6,6.9,and 7.5t/KWh rather than 7.0,7.0 and
6.6¢jKWh for the high,medium,and low load growths respectively).
3.P-age 17,Installed name plate capacities -As pointed out on page 19
the totals differ from those used by us in Appendix 3.Most of the
differences are relatively minor.The only major difference seems to
be the capacity listed for the Chugach Electric Association.As you
indicate these differences are due to recent changes in plans to
install new capacity.The difference would have a minor impact on the
1978 through 1985 results and practically no impact on the results
after 1985.
Mr.Robert Cross
February 27,1979
Page 2
4.Pages 52, 59,80,and Appendix 3 page 8 -Annual Load Factors -On
page 42 and Appendix 3,pa~e 8,both reports are generally in agree-
ment that the annual load factor is presently between 46-52%.In
Appendix 3 we go on to say that it appears the annual load factor
will remain in the 50-52%range du5ring the time horizon of the re-
port.On page 80 it is stated that for planning purposes it is
assumed that the-annual system load factor will be in the range of
55-60%by the latter part of the century.
If the load factor is defined as:
ALF
where:
=GEN
CAP *8.760
ALF =Annual load factor (fraction)
GEN =Generation (MW)
CAP =Capacity (GWH)
and use data for the year 2000,low load growth as presented on page 59 we
compute an annual load factor of 51%.
i.e.
i~.
A 6424 =LF .=1448 *8.760 .51
This is lower than the 55-60%mentioned on page 80.
5.Page 95,Healy II plant costs -It would be good to poiot out tha~the
GVEA estimate is probably in terms of 1985$..
6.Page 101-102,Conclusions - I think your summary of the alternatives
available to Alaska is good.
Mr.Robert Cross
February 27,1979
Page 3
7.Cover Sheet,Appendix 3 -Enclosed are different cover pages for our
report presented in Appendix 3 and the Appendices to our report.
Please replace the cover pages you presently have.
Thank you for the opportunity to comment on the report.
Sincerely,
.~c71 (;heoj,JGJ
J.Jay Jacobsen
Energy Assessment Unit
Energy Systems Department
JJJ:tw
Enclosures
''''''-I''''""'R"Zf"'"1lfII;lI1!"r ------........,..,.,-._
~I
REPLY TO
ATTENTION OF:
NPAEN-PL-R
DEP~R~Mg~~9FTHEARMYALA~~A~'$I'f~I,cf::~RPs OF ENGINEERS
u,.,,"'"L,'f?CF'Ei'&.o:S002
,1.~.\;N'~OR~GE.AL!,?;KA 99510
..~...,•,.l~\i.-;{"j.,j I --../~
>-:·::-;~l---l:""-~
"'<,,,.$--.-.li.-.;,.-;:J
12 ~AR '919
Mr.Robert J.Cross
,Admi ni strator
Alaska Power Administration
P.O.Box 50
Juneau,Alaska 99802
Dear Mr.Cross:
I am writing to advise you of actions taken in response to your comments
on the draft Susitna Supplemental Feasibility Report and also to comment
on your draft Power Market Analysis.
Your letter of 26 January 1979 transmitting your comments on our draft
report lrrived during the final report printing.Any delay at that
point Vi 'ld have caused us to miss our deadline which I was unwilling
to perml~except under extreme circumstances.On the verbal assurance
from your staff that there was nothing of such gravity that the integ-
rity of the report would be jeopardized.the decision was made to pro-
ceed with the printing as scheduled.
I regret that your written comments did not arrive sooner,because the
report would have benefited from their incorporation.I am especially
sensitive to your contention that insufficient credit was given where
APA materials were used.In the future,my staff will be more careful
in this regard.
Our review of your excellent draft Power Market Analysis has resulted
in only one comment.On page 4 you note that the more costly gravity
structure for Devil Canyon is "currently proposed ll by the Corps.This
is inaccurate in that the gravity structure was presented to insure that
estimated costs were sufficient to cover a range of possible foundation
conditions at the Devil Canyon site.With appropriate word changes to
correct this matter,we find nothing else requiring alteration.
Since the Main Report and Appendix Part 1 are already in Washington,please
transmit 20 copies of the final Appendix Part 2 to HQDA (DAEN-CWP-W).
NPAEN-PL-R
Mr.Robert J.Cross 19 MAR 197~
Washington D.C.20314;2 copies to Division Engineer,North Pacific
Corps of Engineers,210 Custom House,Portland,Oregon 97209,ATTN;
NPDPL;and the remaining 138 copies to the Alaska District,ATTN:
NPAEN-US.
If you have any questions,Mr.Chuck Bickley at (907)752-5135 can pro-
vide assistance.
~ce;;s.~_.._
LI~LE T.S~
LtColOne1,Corps of Engineers
Acting District Engineer
2
.~.
...=-.11'IIi!3
DEPARTMENT OF THE ARMY
ALASKA DISTRICT,CORFS OF ENGINEERS
P,O.BOX 7002
ANCHORAGE,ALASK/'!l95'l,
REPLY TO
ATT£"lTJON OF:
NPAEN-Pl-R
i 9 MAR 1979
Mr.Robert J.Cross
Administrator'
Alaska Power Administration
P.O.Box 50
Juneau~Alaska 99802
Dear Mr.t>"oss:
1 am writing to advise you of actions taken in response to you'r comments
on the draft Susitna Supplemental Feasibility Report and also to comment
on your draft Power Market Analysis.
Your letter of 26 January 1979 transmitting your comments on our draft
repc~t lrrived during the final report printingo Any delay at that
point would have caused us to miss our dead1ine which I was unwilling
to per it except under extreme circumstances.On the verbal assurance
from 'JI 'staff that there \'ias ooth;ng of such gravity that the integ-
rity of ~.le report would be jeopardized.the decision was trade to pro-
ceed with~k;r.''''inting as scheduled~
I regret that your written comments did not arrive sonnert because the
report would have benefited frOl')1 their incorporation.I am especially
sensitive to your contention that insufficient credit was given where
APA materials ware used.In the future~my staff will be more careful
1n this regard.~...
OUr review of your excellent draft Power Market Analysis has resulted
in only one C01ill'Ilent.On page 4-you note that the more costly gravity
structure for Devil canyon is IUcurrently proposed"by the Corps.This
is inaccurate in that the gravity structure was presented to insure that
estimated costs were sufficient to cover a ra.nge of possible foundation
conditions at the Devil Canyon site.Hi,ttCappropriate word changes to
correct this matter,we find nothing ~lse r~quiring alteration.
\'<"<";~:~~C
Since the Main Report and Appendix ?a~t 1 a~already in Washington~~~~&
transmit 20 copies of the final Appendi~",p,~'H~t 2 to HQDA (DAEN-04P-¥,~\
o ~
~:z~~
;',&....:f.
7;>76_191'0
NI'AEN-Pl-R
Hr.Robert J'.Cross I9 M'.~1W~
Uashington DwC.20314;2 copies to Div1s1on £ng1neer*rlorth Pacific
Corps of Engineers)210 Custom House,Portland.Oregon 97209.iHTN;~~PDPL;and the remaining 138 copies to the !\iaska District,Allil:
NPA8{-US..
If you have any questions,Mr.Chuck Bickley at (907)752-5135 can pro-
vide assistance.
Sincerely yours,
:./LTC.Vemelle T.Sroith
VERNELLE T.SMITH
Lt Colonel.Corps of Engineers
Acting District Enginegr
2
.""":&-------------------------------------------,C'
~""?'e...,~4l~tit1r1:1 ~C 1,..."",
iVL Su (ivan
A1avo r
March 1,1979
Robert J.Cross,Administrator
Department of Energy
Alaska Power Administration
P.o.Box 50
Juneau,Alaska 99802
Dear Mr.Cross:
'l'h is letter responds to your letter of February 2,1979,which
requested informal comments on the draft Power Market Analyses
of the Upper Susitna River Project.
Mr.Stahr is out of town and I am writing without knowledge of his
personal opinion and comments.The Municipal Light and Power's
staff comments appear in the two attached memorandums.Mr.Stahr
may forward more comments upon his return.
Thank you for the opportunity to review the draft.If you have
any questioLs or want more comments please do not hesitate to con-
t.act us.
Very truly 'lrs ,
~~r:J~-
Max Foster
Revenue Requirements Supervisor
MF:bw
Enclosure
PROVIDE FOR TOMORROW SAVE ENERGY TODA Y.
.-.
j
,...,.:.~,...":-,';F'"n~~~~~:",IDJm:lRw~~~
March 23,197)
Mr.Jim Cheatham
U.S.Department of Energy
Alaska Power Administration
P.O.Box 50
Juneau,AI<99801
JAY 5.HAMMOND
GOVERNOR
_--...--"'T""'----'POUCH AD-JUNEAU 99811 COOE.INn l'l);'lt t
PHONE 465-3577
Subject:Power Market Analysis -Draft on the Upper Susitna River
Project
State I.D.No.79020902
Dear Mr.Cheatham:
,~The Alaska State Clearinghouse has completed review on the subject
project.
The State Clearinghouse has no comment on this project.
This letter wL satisfy the review requirements of the office of
Management and L~dget's Circular A-95.
J1'1/cz
~~:~
..S·tate,-Federal
-------------------------)'----~-------------------------
"1 ..;
Municipality of Ari.cl\orage
MEM0.RANDUM
L."I"E:February 15,1979
TO:Thomas R.Stahr,General Manager
FROM:H.C.Purcell,Assistant Chief Engineer
SUBJECT:DOE APA UPPER SUSITNA RIVER PROJECT POWER MARKET ANALYSES
I have reviewed the January 1979 draft of this report and find nothing controver-
sial in it.There is an error,and there are a few points I will comment on,
none of which,hmvever,affect the conclusions reached.
/'
I~/,l.r
r~,.~
On page 33,Table 5 shows AML&P generation in 1965 as 156.2 GWH.This results in
area growth 1964-1965 of 34.4%and 1965-1966 growth of -0.6%.AML&P generation
in 1965 was actually 101.5 GWH.This changes the area total in 1965 to 407.0 GWH,
1964-1965 growth to 18.5%and 1965-1966 growth to 12.7%.
nn pages 37 and 38,the report states ".,.correlations with weather ...seem-
ed indeterminable or of little significance,"and "Energy use and weather com-
parisons were incc ..clusive."This does not agree with my work or with plain common
sense.Growth between 1973 and 1977 is used to forecast energy requi rements.In
three of these four years,1974,1976 and 1977,the weather was warmer than normal.
Ignoring the influence of weather depresses the growth rate.However,this does
~not affect the report materially,since it winds up using three different growth
{rates (low,medium and high)in its market analyses..
It is interbti ig that the situation hasn't changed in twenty years.Page 98 lists
six major hydr(projects with much better economics than the Upper Susitna.But
they all remail tied up by "major environmental and land use problems."
On pages 100-102 the report brushes off exotic energy sources as "not realistic
plilnning alternatives ..,"I applaud this,but suspect that much more work will
have to be done to convince the vocal proponents of "natural energy."
On page 104 the report specifies "System reserve capacity of 25 percent for non-in-
terconnected load centers and 20 percent for interconnected systems." I checked
these numbers against the PROBS runs I made in connection with DOE regulations on
trans iti ana 1 facil ities.For the Anchorage area at present,PROBS showed a loss
of load probability of 0.2 days per year with a peak load of 466.3 MW.On the
same basis,25%reserve capacity would correspond to.a peak load of 468.8 MW.25%
reserve capacity would result in LOLP only slightly over 0.2 days per year.With
-the larger interconnected system ten or twelve years in the future,20%reserve
capacity will probably provide reasonable LOLP.
Page 34 of the Battelle Informal Report schedules a 200 MW steam plant to be on
line in 1982,three years hence.Yet Battelle page 22 says "the 5 to 6 year sche-
du'ling period [from final site selection to commercial operation]appears reason-
ab'le."Either eEA is about to break ground for its coal-fired steam plant or .
Battellels dates are inconsistent.Again,however,it doesn1t really matter.The
r-~elative economics of Susitna vs.coal-fired steam would not be affected.
'.
.I.,
Municipality 01 Anchorage
MEMORANDUM
DATE:
TO:
FROM:
March 1,1979
Thomas R.Stahr,General Manager,ML&P
Max Foster,Revenue Requirements Supervisor,HL&P
SUBJECT:DOE-APA Upper Susitna River Project
Power Market Analyses
This memo comments on the Alaska Power Administration's Upper
Susitna River Project Power Market Analysis draft dated January
19790 My impression is that the demand projections for the
Anchorage area are conservative.I also think that the installed
cost of coal plants is conservative.The Susitna project costs are
probably the mosJ:reliable cost estimates appearing in the report.
I am not happy with the methodology developing the cost of coal..I
think coal could actually cost much more than $1.00 to $1.50 per
million BTU.The inflation rates used in the analysis (0%and 5~)
seem low in light of recent trends.
Significantly,despite the conservative assumptions contained within
~qe report,the Susitna project represented the least cost option in,
"er.y case~
My page by page review of the report elicited the following
comments':
,J
Page 37 -'he lack of correlation to weather and price disburbs
me~It may indicate improper equation specification caused by
omitting important variable or failing to insert dummy
variables in the regression equations to correct for cyclical
abnormalities.Additionally.,it seems to me demand projections ...~QY rate cl~ss 'would_be more statistical,ly pigniiicant.C0f"?-/c(-((,~""t,...f
WC!-I{-fi-...o.r I.J'S'T?C"\.:'1 O"l a.;v'/o'l"f'!-1 f y )C'1c/!CQ!h-q.J/.J bk~rl<)"'t"o,,,,p(~(:1.117,
Pase 77 -The shape of the Anchorage Area load duration curve
suggests that a heavy proportion of generation for the area
could be large base load increments.This is very favorable
for hydroelectric development.
Page 94 - I don't like the treatment of 0 &M costs.How does
this relate to prosent actual Anchorage labor costs and trends?
I think the prices should be measured directly,not arbitrarily
increased.
Page 150 -The pipline terminal's 37.5 ~M generation plant is
not interconnected wi th CVEA.It is not a cogenera t ione;_-
fa c i litY•-r;,-r-c«e >1 er9 )"-FO C //1 '1':.0,/;/'c:1..-f1~c r---f J.c O--t-l,)
I,'.
Memo to Thomas R.Stahr,General Manager
Harch 1,1979
Page 2
Appendix 3,Pages 66 to 75-Where is the present worth or
annualized cost of power computed?This is a major change from
the earlier ECOST2 model.I think the present worth analysis
is an impo~tant part of any power cost analysis.
In general,the analysis seemS complete.The conclusions echo those
of previous studies.From an economic prospective,the Susitna
Project is unquestionably justified.Its time to stop revising
,!easibili ty analyses and get on with l'iCens l.ng and ,::onstruction../J't'/1 e
HF:bw
:',_.-----------~
SECTION H
TRJl.NSMISSION SYSTEM
None of the OMS comments were directed at the
engineering aspects of the transmission system.
There are therefore no changes made to this
section.Costs of tra~smission have been up-
da ted and appea r inSect;on B,Proj ect Descript ion
and .Cost Estimates.The economic justification
for the transmission intertie is discussed in
Section G.Marketability Analysis.
SECTION 1
ENVIRONMENTAL ASSESSMENT FOR
-TRANSMISSION SYSTEMS
This section has not been supplemented becausE;
no changes were made to the transmission plan~
"
SECTION H
TRANSMISSION SYSTEM
None of the OMB comments were directed at the
engineering aspects of the transmission system.
There are therefore no changes made to this
section.Costs of transmiss;nn have been up-
dated and appear in Section B Project Description
and Cost Estimates.The economic justification
for the transmission intertie is discussed in
Section t Marketability Analysis.
SECTION I
ENVIRONMENTAL ASSESSMENT FOR
TRANSMISSION SYSTEMS
This section has not been supplemented because
no changes were made to the transmission plan.