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PLANNING MEMORINJ'Jt.M
st.ts~~ e •. 02 .
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PREFACE
This Planning· Memo;-andum. is an i~terim report to describe the prelinti.nar)t
ana~yses carl:'ied out m1der Subtaak e •. o2, ••Electric System s.-~adi~~". In
view of the 1.mcertainty of a num:ber of system paranxet.ers 1 some sweeping
assumptions had to be made to be able . to carry out this prelilni.nary
anal.y$iS ..
One important item which is still undecided at. the time of this writing
is the interconnection /configuration of the Sus.itna transmission with the
utillties in t.t'le Anchorage area. The tecfJilical ana.~yses, including
transmission line enerqizil'lg, load flew and transi~nt stability studies,
were performed assuming two major swi tchinq and transformer stations in
----~·-
Anchorage, witbout·knowledge of their, locations, as shown in.the system
diagrams in Figures 3.1 and 3.,2. Due to later information, it was
proposed to ba$e the economic comparison of the various trattsmission
-
·· a~~~aticv~,on a single switching station at the western terminal. of a
' 230-kv cable crossing of Knik'=-'A.m. · The costs of the cable crossing-.~
being common to all alternatives, were excluded from the comparison.
The final common cQnfiguration will. have to be determined, as will a
ntmber of other paramp.ters, before the technical: and economic analyses
can be. completed. The capital and operating costs of all components of
the SUSitna transmission .system will then ha'Ve to be included· i.n the
economic comparison of alte.rnati.ves • It is expected that the co:nc.l.usi:ons
drawn from this study will not be significant~y affected by th~ .:r:e.au1ti.itg
changes in system parameters.
_T.Al;LE OF COWl:ENTS
2 ...... SIJMMABX· ----------~---·---·-----·----""'--'""·-·~---~----------
3 -DESCRIPTION AND RESULTS OF STUPXES ---------.... ------------
3.1
3.2
3.3
--Planning C~iteria .---~-------------~~---------.. ~----~~-~ ..... -:Existing Systeiii. Data ___ ...;_.,. ______ ,.. ______ ._ ... ___________ _
;, ' ---. -Syst~ .:.toad Jrorecast ----...,.,;:~ .... ------........ _;;;..,. • .,; ... ___ .., ____ _
;I . .. :
3e 3e 1 -I:o-adi/Levels _...'-,.,..~-------~------•:-. ........ .__ ..... _•••••..-•--•----•---
:·~ .
3 -~ 3. 2 Load{! Distri:bution----.. ,~-------o.t>i---...;------·---~-------
3. 3.3 -I..Oad POwer: Factors --~~---------·-~"'""'""--;.-... ----------,, ,
3. 4 .... System cOnfiguration --At~ 1U ternati ve$ . ---"11~-~--------
3. 4.1· Susitna,. Ci:lnfi.guration :...~ .. "':"--------.u.-oi(o-•-e!i!~-----------·
3:•46)2 SW'itcbing at Wil.l.ow ----· .. -----·-------;.. .... ______ .;. __ _
3 •. 4•3 .. Switching at~ Healy -----------~~-~-~---... -------~-~~---------
3.4.4 -·Anchorage Configuration--------:-·--·----~-----------3 .• 4 .• 5 • Fairbanks Configuration ----... _ ... ___ '"" _______________ _
3.-'S --Al.ternating Current Altel:natives Analyzed ------------
3.5.1 -Sus.itna to Anchorage Transmission Alternati:ves -----
3-.5.2 -Susitna to Fairbanks Transmission Alternatives ----
3.5p3 Total. System Alte;-natives --~---.... --""'--:..----·----·-
:~'6 -.... Electric ·system Studies -----------·o:---------------!'io--
3-.0$1, --.Pc)wer 'f:r,ansfeJ; --~--------~-------~----------_,.-..... _,--~.:. .. _...,_
3.6.2 -Conductor Sizes ----.... ------------------------------
.3 a 6.3 l:J.n_e :Exle~~--~;lnq -------~-ae---.-.-~.o-------------~--------Cd'le--~
3.6.·4 -.Load Flow stl.).dies ---------------------~~,;..: .... _..,.._ ___ _ 3e6.5·-... Trans;ent Stability ______ ,.. ___ .,.. _________ _. _________ _
3a7·-Economic -Studies --·----------------------.... ----•----
3 .• 7.1
3.7.2
3.8 ...
.. Cost .Esti-m.ates ._ ___ __. .. ,.._ .. __ ~-~-:t-~~--------fiiD-------~-----
WJ ~"tfe•Cyc:le ·coSts ---.... .u-•--tll!--~------1111!~--·--~ca••-----
~ ~cinsm.is.Sion ---'11!11-lillllkll!t-•--·---..--..----------~-----............... .. -~ -'·
3.8.1 -·General ~--~-~---~-~-~-~~----~~-------~-~--~~-----~ 3.8.-2 -Canparati'Q'e Transmission System,s ____ .;.. ... o:..-----------
3 • S. 3. -Comparat'i ve:-··costs ._ ... __ .,....., .. ...,_._ ..... _________ ;-·--------
APPENDIX' A -~:;MISSION PLANNING CRn'SlUA
APPENDIX B ... EXIS1'ING TRANSMISSION stSTEM DATA
'APP~D.IX · C -· ECONCJf.tl:C CONDUcrt'OR SIZ:~s
APPENDIX D-COS'rESTIMAr:rES
Al?PENDIXC E-RVDC.TRANE!(~SSION
2-
3 -1
.3 -1
3 ... .2
3 -2
3 --2
3 --3
3 -3'
3 -4
3 ---4
3 -5
3 ..... 5:
3 -5
3 -7
3 --7
,J -8
3 ·-9
3 ... , 9
3 . .... 10
3 -10
3 11
3 --12
3 -12
3 -14
3 -15
3 -16
3'•-'17
3 -17
3 -17 ·--
3 ..... 18
3: -· 19
'4 -1
5 -1
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NUmber
'3 ... 1
3.2
3•3
3.4
3.7
3.9--
3.10
3.11
3.12
3.13
3.16
Title
Ra.ilbelt Region Peak and Energy Demand Forecasts Used for
Generation Planning Studies
Staging of the Susitna Develo~ent
Maximum Power to .be ':tranSmitted to All.Chor-age and Fairbanks
for Each stage of the sus.itna Pevel:opment
Line Losses Under Maximum Power T.r'ansntission
Transmission Line Energizi:nq -Transmission nternati.ve 1 \
Transmission Line Energizing·"" Transmission Alternative 2
Transmission Line Energizing -Transmission_ Al:tex:native 5
Ratings o.f Reactive Compensation Required
T.ransmissicn and Substation Unit costs
~"!!:.';;>:-!::.~= -.;
I4,£e Cycle Costs -·'l':ransmission Alternative 1
Life Cycle Costs -'~' fJ.'ransmission' lUternative 2
T.aife Cycle Costs -Transmission Al.:ternative 3
Life cycJ.-g·~sts -Transmission Alternative 4
Life Cycle Costs .... TranSitti.ssion Al.ternative 5
summary of Life CJ~le Costs
~u:nnnary of Comparative COsts -ac .Versus de Transmission
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LI:ST OF FIGURES
Number
3 .• 2
3.3
3.6
3.8
3.9
Title
Tx:ansmission System Configuration -Alternative 1
Transmission. .System Configuration -Alternative 2
Peak Demand Flow -Alternative ~-85 Percent Load at
Anchorage
Peak Demand Flow -Alternative 1 -25 Percent load at
Fairbanks
Peak Demand Flow -Alte1.:native 2 -85 Per cent Load at
Anchorage
Pealt Demand Flow -Alternativoe 2 -25 Percent Load at -
Fairbanks
T.ran·sient Stabi.li.ty Snng curves -Altex-native 1 -85 Percent
Load at Anchorage
T.ransient Stability swing curves -Alt~n~tiv'e
Load at 'Fairbanks.
, ..... -'
Transient Stability Swing Curves -Alternat.,:ve 2 -85 Pax-cent.
Load at Anchorage
Transient Stabil.ity Swing Curves ... Alternative 2 -25 Percant
Load at Fairbank~
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1 -IN?l'RODUCTJ:ON
The Plan of Study (POS) for the Susitna, hydroeleotri.c P.,'\:."Ojec.t, which is
currently l;leing undertaken for the Alas~a Power Authority {.APA) by Acres
Au,erican lncorporated includes studies of the required transmission
system under Task S•
Su.btask 8.0.2 of Task 8 is entitled., :E:lectric System St:ud,i.es. The·
objective of this subtask, a\s define~~ in the February 1980 PQS is as
follows.
"To ensure that the electrical aspects of the project design are
integrated wit.lt. the existing P.atilbelt ar;~~ power s~{stems and to design an
electrieal po\~er system Which is reliable and economic."
The transmission system for the susitna project, as currentl.y envisaged~
will ulti~ately invo1ve lines £rom the Watana and Devil canyon sites to
both Fairbanks. and Anchorage. The sys.tem is to be de~igl.'led in such a way
that the proposed intertie between Anchorage and Fairbank~t., which is
~esently under study for APA by Commonwealth Associates, ~~1 event~lly
become part of the Susitna transmission system.
Work on Subtask 8.02 commenced in June 1990 and is scheduled tc.' be
complete by March 1982. The purpose of this P1anning Memarand~ is to
present the results. of the preliminary analysis completed under;
Subtask 8a02 through June 15, 1981.
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2 -SUMMARY
The studies are best summarized by outlining the scope of the work to be
performed. c
a
The scope of work incl. udes
-develop·transmission system planning criteria
. -assemble all data .d~scribing exis.ting Railbelt power systems
-study the present and projected load distribution to Anchorage and
Fairbanks
""' determine delivery points .for Susitna power into local util:tt:y systEml.s
_,
-determine line .load:lngs for the Susitna transmissiC4 system -propose
alternative preliminary system configurations
prepare. preliminary cost estimates for alternative system
configurations -o
-perform preliminary screening of various alternatives
.. recol'l'llUend transmission system configuration, voltage and conductor
.sizeso
Based on the results obtained from the above activities a transntission
alternative is recommended which best satisfies the techri.ical. planning
criteria at am economical cost.. The recommended option., called
Alternative 2 in this study, has the fo~lowing major characteristics.
2-1
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Tra.nsmission l'Ane
·Dfavil Canyon -Willow
Wil~ow ""' Anchorage
Devil can)tc>n --Fair-banks
. . ,· . . . L . . . I.·: .
.' l .. ' • •
Length
(mi)
2.7
90
so
189
Numbet.·
Cirouts
2.
3
3
2
2 - 2
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7.' •• -. •
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. ~~. . .
of Cc;m.ductor
Y9lta~e Size
{kV) (kcmil)
3.45 ? ... X 954
345 2 X 954
-345 2 X 954
3415 2 X 795
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3 ~ DESCRIPTION AND RESULTS
OF STUDI:SS
3.1 -Planning Criteria
., c
The planning criteria were. developed to ensure the design of a reliable·
and economic electri:cal power system, wi.th components which are rated to
allow a smooth transition through early p:roj ect $tages to the ultimatel.y
fully developed potential.
System, pl.anning criteria were suhtt1itted to APA in August 1980 and
subsequently accepted without comment. As a result of the. better
understanding of the SUsitn·a transmission system, gained from the
preliminary analyses carx:-ied out to date, revised criteria were proposed
as outlined in Appendix A· In the revision, some of the criteria were
modified to all.ow for larger variations :in perfox;mance parameter~ during
:early stages of proj ect developnent. Strict application of optintumf
lon9"""term-criteria would require the_ installation of equipment with
ratings larger than necessary and at excessive cost,. In the interest of
economy and -l.ong-term system per.formance, these criteria were temporarUy
relaxed during early development stages of .the project.
While. allowing for satisfactory operation during early system
de.velopment, final system parameters must be based on the ul·timate _
Sus.i tna potential.
The criteria are based on the desirability to main:tain rated power fl..ow
to Anchorage and Fairbanks during the outage of any single line or
transformer element. The essential features of the criteria are
-total ;power output of Susitna to be del.ivered to one or two stations at
0
Anchorage and one at F{Lirb.anks
jl
-''breaker-and-a-hal£1i s\~itch,ing station arrangements.
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dynCllD.ic overvoltages during line ·energizing not to exceed specified
limi:ts·
-system voltages to be within established limits during normal
operation
power delivered to the loads to be maintained and system voltages to be
kept within established limits for .system operation under emergency
conditions
-transient stability during a 3-phase line fault cleared by breaker
action with no reclosing
-where performance lintits are exceeded, the most cost effective
corrective measures are to be takeno
3. 2 -Existinq System Data
T.he data on the existing power systems in the. Railbelt area were·
assembled by R. W. Retherford Associates. These data have be.en compil,ed.
in a drai!t report by Commonwealth Associates Inc., dated November 198() .. ','
and entitled _"Anchorage-Fairbanks Transmission Intertie -Transmission
System Data". This report is included, with minor 1:ev.isions, as
J\ppendix l3. -Other. system data were obtained in the form of single-line
diagrams from the various utilities.
3.3 -System Load Forecast
3.3.1 -Load Levels
Energy and peak demand fo.recasts were prepared for the Alaska
Railbelt region by the Ins.titute for Social and. Economic Research,
University of Alaska (ISJ!;R} .~· These were modified to account for
3 -2
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self-supplied industrial and military generation as well as
expected results of load management an:d conservation ~fforts. The
resulting low, ntedi:um ana high forecasts of peak and energy demand,
as shown in Tabl.e. 3~ 1, were used. in the generation p~anning
ana~yses of Subtask 6.36.
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3o3e2 -Load Distribution
At present, t.lJ.e total Railbelt system load is shared approximate1y
80 percent by Anchorage and 20 percent by Fairb~nks. While the.
projections of various load forecasts vary somewhat around these
figures, the predicted changes are small. To account for the
·-
uncertainty in future developmen;t ~ the transmission system was -~
designed to ·allow for this load shcu::ing: to vary from a maximum of
85 percent of Susitna generating capacity at Anchorage to a maxim'UlU
of 25 percent at Fairbanks.
3·. 3 • 3 -Load Power Factors
Loads. were represented in the electric system: studies at the
highest subtransmission l~vel at each load center transformer
station, genera:Lly 1.38 -kv. Subtransmissi.on at 138 kV from the.
point of delivery o:f Susi tna power was considered to be the
responsibility of individual utilities. As such it was not
included in the system -sintulatio:-.'1.. Load power factors were assumed
to be corrected to O.o 95. Conditions of low voltages were corrected
with the help of additional static var generation at the EHV/138•kV
transformer station. During detaiJ. design stages, it may prove
advantageous to carry ou.t most of this power factor correction at
lower vo~tages in the distribution network. This method is
expected to be more cost effective in equipment costs and resul·t; in
. operational.~ advantages as well.
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3.4. -System CoJ.lfiguration. -
AC Alternatives
Alternative co,nfigttrations for the proposed transmission system were
deve1oped afber re·(Tiewing the existing system configurations at both
Anchorage ancl Faubanks as well as the possibilities and developnent
plans ~n the~ Susi.. tna, Anchorage, Fairbanks, Willow and Heal.y areas.
3.4.1 -§]Sitna C~nfiguration
Prf'~liminary development plans indicate that the first project to be
constructed would be Watana with an initial installed capacity of
400 Mvl to be increased -,to approximately 800 M.W in the second
developnent stage. The next project, and the ·last to be considered
in "chis stud,y, is Devil Canyon with an installed capacity of 40(} Mvl
to 6.00 MW.
Devil canyon and Gold Creek were considered as the ·sites for a
major switching station to collect all of the Susitna. generat1ctn
for transmission to Anchorage and Fairbanks. Switching at Gold
Creek would involve the . construction and operating co.st of onta
additi.onal station.· It would require a larger number of circ.:tlit
breaker::; but would reduce the number of transmission circui.t.s in
the cany~'.l• Uncertainty about detail line ro~~ing and, access,
requirements make a switching station at Gold Creek l.ess desirable.
A cost comparison between the two alternative configurations pro·tied
that a switching ~tation at Devil Canyon is more econanical than. at
Gold ___ qre~:k· In the light of all these factors, it is ~considerecL
advantageous to base present studies on a switching._ station located
at Devil Canyon with transmission directly from ~ere to ~cbor:ag:eL
and Fairbanks.
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3. 4. 2 -Swi tchinc;r at Willo.w
'Transmission from Susit:na· to Anchorage is facilitated by tl:te
introduction of an intermediate switching station. This has the
effect of .reducing line energizing QVervoltages and. reducing tile
impact of line outages on system stability. Willow is a suitable
location for this intermediate sw-itching station. and in -addition it
would make it possible to supply l¢.cal 1.oad when this is justif.ied
by developnent in the area. This local load is expected to be. l.e:s.s
than 10 percent of the total Railbelt a:rea system ~oad, but the
availability of an EHV line tap would defin~tel~ facilitate future
powe:r supply.
3.4.3 -Switching ~t Healy
A switching station at Healy was consider$d early in the analysis~
but was found not to be necessary to satisfy the planning criteria~
The predicted load at Healy is small enough to be supplied by th~
local generation and the exis.ting 138-kv transmission from
Fa~bar.Jcs.
3.4.4 -Anchorage Configuration
In its 1975 report on the Upper Susitna River Hydroelectric
Studies, the United States Department of the Interi~ Corps of
. ~..g:ine~s favored a transmission route terminating at Point
MacKenzie.
";>
The 1979 .Economic 1=-easib.i.lity Study Report for the Anohox;~ge
Fairbanks Intertie by International Engineering Compan~ Inc.
( IECo ) recommends one circuit from Susi tna termina t1.;.nq at Point
MacKenzie and another passing· through Palmer and Eklutna
substations to Anchorage alox:tg the eastern siaa of Knik Arm.
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.At the begi<'nning of the studies, it was assumed that Susitna power
would he deliv,ered to Anchorage through tw ntajor transformel:
stations. Initially, it was thouqht that orie of these ttdght be
near Palmer and the other "elsewhel.~e" with.out detailed knowledge of
its location.
Analysis of system configuration, distribution of loads and
developnent in the Anchorage area :reveals that a transformer
s.tation near Palmer would be of little-benefit,;) Most of. the major
loads. are concentrated in and around the urban Anchorage area at
the mouth of Knik Arm.. In order to red.uce the length of
subtranSID.ission feeders, the transformer stations should be located
as close to Anchorage as possible.
The routing of transmission in-co Anchorage' may be .. ~liosen from thx'ee·
possible alternatives ..
(a) Submarine cable crossing from Point MacKenzie to Point
Woronzof. This would require transmi.ssion thiough a very
heavily developed area o It would a1so expose the cables to
damage by ship's anchors, as has i)een experienced with'
existing cables, thus resu1 ting in ques·tionable tran.smissiQll
x-eliability.
(.b) Overland route north of Knik Arm via Palmer. This is likel.?
(c)
,~,,
most economical in terms of capital cost in spite of the long·
distance involved • However, approval for this route is.
unlikely .since overhead transmission through this ·de,! eloped
area is considered environmentally unacceptable. A longer
overland route around the developed area is considered
unacdeptable because of the mountainous terrain •
. Submarine cable crossing or Knik Arm, in the area of ·Lake
Lorraine and ·Six Mile Creek, approximately paral.lel to the new
230-kVcable under construction for ChUgach Electric
------· . ------------" ': -.:.':1.
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Association (CEA). This opt:i,.on, ~eluding sotne 3 to 4 miles·
of submarine cabl2, requ.ires a high capital cost. ~e.ing
upstre~'nl from the shipping lanes to the por.t of Anchorage it
would result in a reliable tranSl'llission link, and one that
would not have to cross environmentally sensitive conservation
areas.
The load flow and stability studies were carried out assuming t'W:O
major switching and. transformer stat:i,.ons, wi.thout knowledge of
-··------~---~----~-·--·----.---·-·-·----·---~--.--------;-------::--";:,~.:--.-~ ' -.--~-o;-·-----·
their locations, as shown in the system diagrams in Figures 3.1 and
3e2. Later information from th:e field indicated that Sus.itna power
would likely be. delivered to a single 345/230-kV station at the
western terminal of the cable crossing outlined in option (c)
above. The, cost of the cable crossing (a.t 230 kV) 1i~Ould be comm.on
to all transmission alternatives under this option. This cost ~m.s
thus excl.uded from the economic analysis comparing the five
alternatives in this planning m~orandum:. !!'he final analysis wUJ.
benefit from more definitive knowledge regarding the most likely
transmission routing and locations of Anchorage transformer
;;)
stations. The costs of .cable c:J:ossings and ter.mina1 stations for
the EHV system will then be included in the final economic
comparisons between the various transmission alternatives.
3 .. 4.5 -Fairbanks Configuration
Susi tna. power for the Fair banks aJ:,ea is recommended to be delivered
to a single EHV/138-kV transformer station located at Ester.
34!5 '!"! ~..l.ter.nating Current
Alternatives Analyzed
•
Because of the geographic location of the various centers, transmissio~
from Susitna to Anchorage and Fairbanks will result in a. radial syst~
conf.iguration. Thi.s fact allows significant freedom in the choice of
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transmission voltages, conductors, and other parameters for the two line
sections wi.tlt only limited dependence between them. In the en.d, the
advantages of standardization for the entire system will have to be
compared to the benefits of optimizing each section on its own merits.
T.ransmission a1 ternatives were deve.loped, for each of the two system areas
including voltage l.evels, number of circuits :t;equired1 and other.
parameters, to satisfy the necessary transmission requirement$ of each
area.
Having established the peak power to be delivered and the distances over
which it is to be transmitted, transmi.ssion voltages and number of
circuits required were determined. To maintain. a consistency with
standard ANSI voltages used in other p,arts of the USA, the following
voltages were considered for SUsitna transmission.
Watana to Devil canyon or Gold
Creek and on to Anchorage
-Devil Canyon or Gold Creek to
:E'airbanks
500 kV or 345 kV
345 kV or 230 kV
3.5.1 -Susitna to Anchorage
Transmission Al ternati.ves
Transmission at either of two different voltage levels could
(i
reasop.ably provide the necesr.;ary power transfer capability over t:he.
distance of approximately 140 miles between Devil canyon and
Anchorage. These are 345 }{V and 500 kV. The ·required transfer
capabil.ity is 85 percent of the Ultimate generating capacity of
1sr400 MW (1,190 MW). At 500 kV, two circuits would provide more
than adequate capability. At 345 kV either three cil:cuits
uncompensated, or two circuits With seri.es c0mpensation are
l:'equired to provide the necessary reliability .for the single
contingency outage criterion. At lower voltages, an excessive
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number of parallel circUits woulcl be rE!quired while above 500 kV
two circuits are still need~d to provide service in the event of a ·
line outage~
3e5.2 -SUsitna to Fairbanks
Transmission Alternatives
Using the same reasoning as for the choice of transmission,
alternatives to Anchorage, two cj,rcuits of e:i.ther 230 kV or 345 kV
'were chosen for the section from Devil Canyon to Fairbanks., The
230-kV alternative requires series compensation to satisfy the
planning criteria in ease of a line outage.
3.5.3 ~ Total System Alternatives
The above-mentioned transmission sectiofl alternatives were combined
into five realistic total s_ystam altet'nativesa Three of the five
. alternatives have different voltages for the two sections. The
principal parameters of the five transmission system alternatives
to be analyzed in detail are as follows.
Alternative
1
2
3
4
5
Susitna to
Anchorage
Number of
Circuits
2
3
2
3
2
*Denotes series compensation.
Voltage
(kV)
345*
345
345*
345
.sao
3 - 9
Susitna to
Fairbanks
Number of
Circuits
2
2
2
2
2
Voltas:!:
(kV)
345
345
.230*
230~
230*
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Single-line diagrcuns explaining: the details of the two most
promising system config~ations, ~~t-ernatives 1 and 2., are shown in
Figures. 3~ 1 and 3. 2.
3.6 -Electric System Studies
Early in. the system studies, it was realized that 345 kV was the one
voltage whi.ch showed greatest promise for transmission from Susit:n.a to
both An.chorage and Fairbanks. A 500-kV system has higher transmission
capahilities but at significantl.y higher costs. Transmission at 230 kV
is insUfficient for the section from Susitna to Anchorage, and all dual
voltage systems have increased complications and decreased reliability at
little or no economic advantage. For these reasons, 500-kV and 230-kV
system. alternatives were only analyzed-sufficiently to determine their
equi.~ent ratings so that cc..1st estimates could be prepared.
3 o 6 .. 1 -Power Transfer
After stud.ying various reports and obtaining preliminary
information on the staging of Susitna from SUbtask 6.36, Generation
Planning, the electric system studies were able to proceed in
December 1980. Table 3.2 shows the preliminary staging schedule
for the Susitna develo];lii.ent. The. maximum power to be transmitte.d
. to Anchorage and Fairbanks for each stage of development, based on
the 85 percent and 25 percent limits is given in Table 3 •. 3.~ , The
load power fao.tor .is assumed to be 0.95 and the power factdr rating
of the Susitna generators is assumed to be 0.90.
Following determination of the system power transfer requirements
for each stage of St!.sitna development; alternative systeJn
configu.r:ati.ons were developed taking into account the following
3-10.
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-initial SUSitna development a~ the Watana site
.... a major std. tching station at Devil Canyon. or near Gol.d Creek ..
-possible intermediate switching at Willow and Healy.
Preliminary line lengths for the s.ystem conf iguratiorts under study
were obtained from Subtask 8. 03, Transmission Line Route.
Selection.
3.6.2 -Canductor Sizes -
Based on the transmission and. power transfer requirements at the
various stages of Su.sitna development, economic conductor si~es are
determined. The methodology used to obtain the economic conductor
size and the results obtained are outlined in Appendix C, Econom:ic
Conductor Sizes~ Also included in Appendix C are the capital~zed
costs of transmission line losses. The costs of these losses are
taken into account in comparing the overall costs of al.ternative
transmission schemes.
When determining appropriate conductor size, the economic conductor
is checked for radio interference ( RI) and co.:r;ona ~rformance. If
RI and. corona performance are witi-Iin acceptable limits, then t..l:te
economic conductor size is used. However, where the RI and corona
performance are found to be limiting, the condttcto.r selection is
based on these requirements.
Total 1ine losses for the proposed conductor size for each of the
different line voltages being considered are given in Table 3,4.
These losses are for the· alternatives where a IP.ajor switching
station is located at Devil Canyona The losses given are the total
line losses for transmission from Devil Canyon to Anchorage and
from Devil canyon to Fairbanks. The line fr.om Devil Canyon to
Anchorage is 155 miles long. The losses were calculated for the
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maximum expected power transfer to Anchorag~ an.d to Ja'airbanks for·
each of the stages of the Susitna development as given in
~able 3.3. ~
3.6.3 -Line Energizi~
Transmission line energizing studies were carried out to determine
the need for and ratings of reactive shunt compensation at the
receiv-ing ends of transmission line sections at the various
voltages. This compensation is required to limit overvol tages
during line energizing to acceptable levels,. Shunt reactors are
required at Willow and Anchorage for the 500-kV transmission
alternative and at Fairbanks for 345-kV transmission. ~ese
reactors are switched with EHV breakers directly to the respective
transmission lines in order to be connected prior to energizing of
the line sections. The breakers are :required to disconnect ~e
reactors at times-of heavy line fiows, and especially during line
outage -e.onditionso This arrangement reduces the need for
capacitive var generation to compensate for the reactors. The
-results of the line energizing analysis. are shown in Tables 3. 5 to
3. 7. Included in the tables are values which fall outside the
proposed planning critera and m1.1st be corrected. with shunt reactors
as indicatede
3.6.4 -Load F1ow Studies
Load flow studies confirmed satisfactory system performance und~
both normal and emergency condi tiqns for all. transmission
alternatives. Emergency conditions tested include outages of any
single 345-kV transmission eircuit fo~ ~~e 345-kV alternatives as
we'll as the critical outages of a 500-kV circuit betr,.""een Devil
canyon and Willow and a 230-kV circuit between Devil canyon and
Fairbanks for the 500-kV and 230-kV alternatives.
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Voltages on the 138-kV and 230-kV load buses range from 0.99 to
1.02 per unit for normal operation and from 0.93 to 1.02 per unit
under emergency outage conditions. Vol ta(]e ranges on the EHV
systems were Oe95--to 1.04 and 0.90 to 1.04 for no:rmal and emergency
conditions, respectively.
Load conditions __ were assumed to be at peak demand with SU.si.tna
generation fully utilized and-Onlyl!linintal other generation
available on the system. This situation is expected to result in
the most critical operating conditions. fJ:-,:...tal locui is 1,600 MW at
a power factor of 0.95. Systell\ load di.stribution was simulated at
a maximum of 85 percent of the total lflad for Anchorage and a
maximum of 25 percent for Fairbanks. Generation assumed for the
above 1oad conditions includes SUsitna -capability fully utilized
{Watana 800 M.W, Dev.Ll canyon 600 MW} plus 300 MW of coal-fired
generation at Beluga. and 100 MW of gas turbines at each of
Anchora9e and Fairbanks. All of the tJ.'lermal units are assumed to
be running .. at approximately half load .in order to provide 250 MW of
-spinning rese~ve.
Load flow diagrams showing normal system operation at peak demand
for 85/15 percent and 75/25 percent lo~d sharing for transmission
Alternative.s 1 and 2 are included as Figures 3.3 to .3.6. !Jlle load
flow diagrams show a s.ystem configuratio~ containing ·two terminal.
stations in lmchorage with a subtransmission voltage of 138 kV.
Transmissi9n fromJ3eluga is represented as a. 345-kV infeed. In the
final analysis the transmission between Willow and Anchorage wi~l
include approximately four miles of submarine cable for the Knik
Arm crossing, but this is not represented in the initial studies.
Switching of the 345-kV shunt reactors at Fairbanks is not shown in
the diagrams , but these will be discolll'lected for _peak demand and
1ine outage coi idi tions as required. While these changes have
significant effects on transmission system equipment costs, they do
not significantly affect system operation. For this reason, they
were included i.n the latest cost estimates but riot in the electric
3 -13
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system studies to a~oid repeated updating of system parameters.
System ~formance was found to be critical for line outages
betwgen Devil canyon and Wi11ow and between Devil Canyon and
Fairbanks• Consequently,· it was these line qutage£J which
de.termi.ned the ratings of static var s.o:urces and series
compensation.
The required ratings of compensation equipment for the five
transmission alternatives are listed in Table 3.8.
3•6c5 -~ransient Stability
Detailed transient stability studies were carried out only for the
. 345-kV transmission Alternatives 1 and. 2.
Before the studies bad advanced to the stage of stability analys2sr
alternatives containing SOO .... kV or 230-kV transJ.Uission had been
recognized to be noncompeti.ti.ve with the rem.a.ining 345-kV
alternatives, on either economic or technical grounds. A 500-kV
transmission to Anchorage would have sufficient surplus capability
to ~nsure stable operation. On the other hand, should 230-kV
transmission to Fairbanks ever have to be reconsidered., transient
stabilitywould still need to be confirmed.
As outlined'-'in--'the planning criteria., the design faul.t for
transient stability analysis is a 3-phase fault. In the
preliminary studies, the faul.t was cleared in 4. 8 cycles at both
ends of the faulted line section, rather than in 4 .• 8 and 6 cycles
at the near and remote ends, respec.tively, as stipulated in the
planning criteria. A test run for the most critical system
condition confirmed.that.the additional delay does not
significantly affect system performance.
Transient stability vms analyzed for a 3-phase fault on the 345-kV
line from Dev i1 Canyon to Willow (with as perc5ent of the system
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load at Anchorage) and similarly on the line from Devil Canyon to
Fairbanks (with 2,5 percent of system load at Fairbanks). To
simulate worst conditions, the faUlt was assumed to be near Devil
Canyon in both cases. The fault was cleared in 4118 cycles without
reclosw:,-e. System transient behavi.or was observed for a period of
1 second after the fault. Exciter and governor response in the
transient interval was ignored. The dynamic voltage regulating
capabili~es of ~he static var sources at ~~chorage and Fairbanks
were ignored as well. For the· fi!lal analysis a .revised comput~
model (with representation of dynamically v.ariable stat.ic var
sources) will be available .•
.The attached swing curves, Figures 3. 7 to 3.10, .show the rotor
angles of all generators relative to the rotor angles at Watana .•
Al.1 generators recover from the first and second swings for both
transmission alternatives. 'l'he actions of exciters and governors
should ensure that these swings are damped out and return the
system to a new equilibrium after each d'isturbance. System
transient behavior seems to be. quite sensitive to the generation
on-line at both Anchorage and Fairbanks at the time ,of a fault.
Detailed analysis. at the design stages will have to determine the
minimum spinning reserve required at both Anchorage and Fairbanks
to ensure system stability in the event of a major fault. The
transient stud4-es are considered. adequate to confirm the stability
of the system configuration and the primary equipment parameters
needed to ensure satisfactory operation.
3.7-Economic Studies
Economic studies were carried out to determine the capital and operating
11
costs and to compare the total life cycle costs of the various
transmission alternatives. The economic studies exclude the costs of the
Knik Arm: crossing and terminal stations in Anchorage. These were
considered common to all alterr1ati ves (for a 230-kV crossing) • They will
have to be in0'11ldedl·in the final analysis •
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3. 7 11 1 -Cost Estimates
The transm.tssion cost. estimates inc~ude all costs for transmissi.on
lines anii substations. All estimates include the costs of land
acquisition and cl.earing" Included. in the substation cost
estimates are site preparation and all equipment costs for circuit
breakers, transformers, shunt reactors, static var sources and
transmission line series capacitors. Cost estimates of major ___ _
equipment include the costs-of all ancillaries such as disconnect
-~·
switches, potential transformers~ current transformers, controls,
instrtnnentation, etc. At the generating stations all EHV circuit
breakers are inc~uded, but generator transformers and low-voltage
breakers are excluded. These are included in the powerhouse
estimates. Similarly at the load centers all EHV breakers are
included as well as the necessary cix'cuit entries at the
subtransmission voltage (230 kV or -·rJa kV] for each transformer
bank.. The remainder of the low~ voltage station is common to al.l
alternatives and therefore excluded from the comparison. At
~·· --
Anchorage, transformation to 230 kV is assumed on the west side of
Knik Arm impl.ying cable crossings at .230 kV. The cable crossings
and other 230-kV equipment are considered. common to all ac
transmission alternatives for Susitna and their costs have been
excluded from this comparison. They must be included for
comparison of schemes with different Knik Arm crossing
configurations such as HVDC transmission from Susitna.
The unit costs and assumptions in the cost estimates are shown in
Table 3. 9.-
All details on which the cost estimates are .based are given i!).
detail in Appendix D.
3 -16
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3.7.2-Life-cvcle Costs
,.Life-cyc~e co-sts £or---ea-ch transmissi-on alternative were calcul.ated
by discounting all cost components over a SO-year lifetime from
1993 to 2043 to a common present worth datum of 1981. The
calcul.ations and results of total present-worth costs are shown in
Tables 3.10 to 3.14. Included in the life-cycle costs are capitcU
(including engineering, contingencies, land acquisition and
. clearing and bond commissi-on) c Also in.cl uQ.ed are the capitalized
annual costs of operation and maintenance, insurance,. inter.im
replacement, contribution in lieu of taxes, and transmission
losses. A summary of ~esent-worth life-cycl~ system costs for all
five transmission alternatives is shown in Table 3.15.
3.8 -HVDC Transmission
In order to determine the. relative economics of HVDC as compared to the
preferred ac transmission alternative an economic screening was carried
out. The details of this analysis are given in Appendix E, and the
results and significant features are summarized ha.re.
3.8.1 -General-
A HVDC transmission system linking Susitna generation with the
Anchorage and Fairbanks load areas woul.d need to be either one
3-terminal system or two 2-terminal systems. Another alternative
would be a combined scheme using ac transmission from Susitna to
one load center and de transmission to the other. In order to
ensure that no possible economic colllbination is overlooked,
transmission to Anchorage and Fairbanks are considered separately.
3 -17
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3~8.2 -Comparative Transmission
Systems
The ac and HVDC transmission systems whose costs are comp;~red are
essentially comparable in terms of :-;ecurity of supply. Each
alternative is planned to maintain rated transfer capability with
the sinqle contingency outage of any element in the transmission
system. a
{a) Ac Transmission
The ac transmission syst~ ·which is considered as the base
case utilizes 345 kV _with 3; circuits ultimately to Anchorage
and 2 circuits to Fairbanks. Transmission to the load centers
originates at a switching station at Devil Canyon with Watana
generation brought in at 345 kV.
Transmission to Fairbanks is direct to a 345-kV/138-kV
terminal station at the load center.
Transmission to Anchorage involves aY' lntermediate swi tchi.'lg
station at Willow and proceeds tc~ a .345-kV/230-kV station on
the west side on Xni.k Arma At this point transmission ~
continues via a 230-kV submarine cable* to the east side of
Kni.k· Arm and into a termina1 station from which l.ocal
distribution circuits would radiate.
*Transformati.on to 230 kV and use of 230-kV submarine cable is not
necessarily the optimum arrangement, but it is considered adequate for
the ac versus HVOC economic screening.
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(b) B.VDC Transmission
The HVDC converter terminals are assumed to be located at
Devil Canyon with local ac transmission at 230 kV between
Watana and Devil Canyon.
Transmis~ion to Fairba~ks is via a single bipo!~ HVDC line
operat.ing at ±_250 kV, with an inverter terminal an.d 138-kV
circui.t entries at the load end.* .. .
Transmission to Anchorage is also at .±,250 kV but would require
2 bipolar HVDC eircu:i..ts to meet the security constraints.
~--'These circUits would proceed directly to Anchorage, utilizing
HVDC submarine cables across Knik Arm and into an inverter
station on the east side of Knik Arm. The inverter output is
via 230-kV circuit entries which would supply local
distribution identical to the ac alternative.. The cost of a
separate 230-kv ac supply from Point McKenzie to Willow is
allowed for 6 ;;;-o that both ac and de a1 ternati ves would be
functionally equivalent.
3.8.3 -£omparative Costs
•The details. of equipment ratings and unit costs are given in
Appendix E i the results are summarized in Table 3.16o
Individual costs are given for line and termil:niL facilities in
order to illustrate the basic relationships ·between ac and HVDC
transmission costs 6 All_ capital costs are for the ul:titm1_~e
installation with no discounting of staged componertts. The
*During the single contingency ou.tage of one pole of the line or terptinal
facilities, earth return. would be utilized to maintain rated ,POwer flow
to FC!~;Y;J:lanks • ·
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capitalizatioit_of annual charges s.uch as operating costs' and the
cost of l.osses .is at 3 percent discount rate over the 50-yr life of
facilities.
As the comparative costs.show there is·no obvious cost advan'fage
favor in<] HVDC over ac transmission either to Anchorag~ or to
. Fairbanks. This iz particularly true in the case of Anchorage
where HVDC is over 20 percent more costly than ac transmission.
The margin favori.ng ac is only 8 peX'cent in the case; 'f
tra.Yismission to Fairbanks, and although this mi~tht be . ·aduced by
further study, it is unlikely the savings would be sufficient to
justify the operating complexity of combined ao .and HVDC systems.
on the basis .of this economic screening it is conc~uded that ac is
an appropriate choice for transmission from s'usitna to the load
centers at Anchorage.and Fairbanks ..
3 -20
----
TABLE 3.1: P'-~ILBELT REGION PEAK AND ENERGY DEMAND FORECASTS
~USED FOR GENERATION PLANNING STUDIES
LOAD CASE
Low Plus Load ~
Management and
Conservation 1 Low Medium 3 High. . 4 · (LES--GLAdjusted) (LES-GL)2 (MES-GM) (HES-GH)
Load Load Load
Year MW GWh Factor M'"w GWh Factor MW GWh Factor MW GWh -
1980 510 2790 62.5 510 2790 62.4 510 2790 62.4 510 2790
1985 560 3090 62 .• 8 580 3160 62.4 650 3570 62.6 695 3860
1990 620 3430 63.,2 640 3505 62.4 735 4030 62 .. 6 920 5090
1995 685 3810 63.5 795 4350 62.3 945 5170 62.5 1295 7120
2000 755 4240 63.8 950 5210 62.3 1175 6430 62.4 1670 9170
2005 835 4690 64.1 1045 5700 62.2 1380 7530 62 .. 3 2285 12540
2010 920 5200 64.4 1140 6220 62.2 1635 8940 62.4" 2900 15930
Notes:
1 LES-GL; Low economic growth/low goverQment expenditure with 1oad·management and conservation.
2 .. LES-GL.:
3 MES-GM:
4 HES-GH:
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Low econoll!ic gr9~1th/low government expenditure.
Medium economic growth/moderate government expenditure.
High economic growth/high government expenditure.
Load
FactQJt-
62.4
63.4,
63 .. 1
62.8
62.6
62.6.
62.7
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1993
1996
2000
TABLE 3.2: STAGING OF THE SUSITNA DEVELOPMENT
Susi tna Capacity -MW
Watana
Increments
400
400
Total
400
800
Devil Canyon
Increments Total
Susitna
Total
•. _. 2000 (optional)
400
200
400
600
400
800
1,200
1,400
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Total Susitna
Capacity
(MW)
400
800
l.;t2-00
1.,400
TABLE 3. 3;, MAXIMUM POWER TO BE 'rru.utSMITTEO TO ~..NCHORAGE
AND FAIRBANKS FOR EACH STAGE OF SUSITNA DEVELOPMENT
Maximum Power Transmission
To Ar.,chorage To Fairbanks
{tvlW) (~i)
340
680
1,020
1,190
100
200
300
350
Note: For sy.stem planning purposes a maximum of 85 percent of 5usitna
generation is assumed to be transmitted to Anchorage and a maximum
-· · "'vf 25 percent to Fairbanks.
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TABLE J il 4 :· LIN'"E LOSSES UNDER MAXIMUM POWER TRANSMISSION
Devi1·can1:on· to Anchora2e (155 mi)
Susitna Power. 500 kV 345 kV 345 kV
CaEacit:z Transmitted 2 Circuits 2 Circuits 3 Circuits
(MW) (MW) {MW) {MW) (MW)
400 340 1.5 3.2 2 •. 9
800 680 6.2 12.8 11 .. 2
1,200 1,.020 13.8 28.8 25 .. 5
1,400 1,190 18.8 39.2 35.3
Devil can2:on to Fairbanks (189 ~)
Susitna Power 345 kV 230 kV
Ca;E!acit!( Transmitted 2 Circuits 2 Circuits
(M'"w) (t.fi-1} {MW) (MW)
400. 100 0.5 1.5
800 200 2.0 6.1
1,200 300 4.6 13:7
1,400 350 6.3 18 .. 6
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TABLE 3.5: TRANS~ISSION LINE ENERGIZING
Transmission Alternative 1
Line "' Senc:Un~ End
Reactors No. of No. and Short
(receiving Circuits Size of Watana Circuit Initial Final Voltage L.ine
Line Section Len2th end) at 345 kV Conductors Genera tio•!. Level Volta2e Volta51e Rise Plow
(mi} (!WAR} (kcmil) (MW) (MVA) (per unit) (per unit) (per unit) (MVAR)
Devil. canyon -189 0 2 2 X 795 200 541 0 .• 900 1..1892 ~.2892 229
Fairbanks
Devil C~yon -189 15 2 2 X 795 200 541 0.900 1.025. 0.125 as
Fairbanks
Devil Canyon -.189 75 2 2x 795 400 1006 0.9SU 1.025 o.o"'ls 85
Fairbanks
Devil Canyon -189 75 .~. 2 X 795 800 1768 1.000 1.048 0.048 89 lli
I:' air banks
Devil ~anyon -90 0 2 2 X 12721 200 541 0.900 1. .. 017 0.117 eo
Willow3
Devil Canyon -.90 0 2 2 X 1272 1 400 1006 0.950 1.021 0.071 80
Wil.low3
De.vil Canyqn ·-90 0 2 2 X. 12721 800 1768 1..000 1.046 0.046 84
Wi1low3
Willow -651 0 2 2 X 1272 1 200 436 0.950 1.073 0.123 64
Anchoragel
• Willow -651 0 2. 2 X ~272 1 400 696 0.950 lo024 0.074 58
Anchor agel
Willow -651 0 2 2 X 12721 800 992 0.950 l.OOQ 0.050 55
Aiichor:agel
Notes: 1~he di.stattce froll Willow to Anchorage and conductor .size from Susitna to Anchorage wil.l be revised for the· final analysis ..
2 $hunt rel\,,t,t\)J:'S are requlred •t Fairbanks to satisfy volt:agfl rise criteria.
3 . . .· . . ·. . -ttesults fc1r the line sections Devil canyon -Willow -Anchorage are also valirl for 'l.'ranlllUiasion Altern.:at.ive l.
Re~g
End
Vol.:t~_
{per limit)
1.2&l;~
l .. O_i.$!
1 .. 02.,~
l.QSl,
1 .. 0:3S
1.()~
l.Q&l
l.OSl
l .. Q~l
1.®9
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·DBLE 3.6: TRANSMISSION L'INE ENERGIZING
' ~--~ .. ----·-"
~ransaission Alternative 2
Line Sending:.End
Reactors No. of No. and Short ~ving
(receiving Circuits size of ~atana Circuit !niti.al Final Voltage Line En.a
t.ine Section Length end} at 345 k.V Conductors · Generation Level Vol.ta9:e Vol.ta:1e Rise Flow V().\.~ge
(rnU (MVAlt) . (kcmil) (MW) (MVA) (per unit) (per unit) (per unit) (MVAR) ~\mit)
Devil Canyon -189 0 2 2 X 795 200 541 0.900 1.1892 o.2a92 229 ~ l .... ~ ,_ ' --.. .,.
Fairbanks
Devil canyon -189 75 .2 2 X 795 200 541. 0.900 1..025 0.125 85 l. ... ~$
Fairban"ks
"
Devil Canyon -189 75 2 2 X 795 400 1006 0.950 1.025 0.075 as ::t"'~'S
Fairbanks
Devil Canyon -189 '15 2 2 X 795 BOO 1768 1..000 1.048 0.048 89 ~,~l.
Fairbanks
Devil Canyon -90 0 3 2 X 954 200 541. 0.900 1. .. 013 0.113 76 1;,.,;~0
W!llow3
Devil-canyon -90 0 3 2 X 954 400. 1006 0.950 1.018 0.068 77 l ... ~
Willow3
Devil Canyon -· 90 0 3 2 X 954 800 17.68 1.000 1.044 0.044 81. ~ ... ~~
Will owl
Willow-651 0 3 2 X 954 200 433 0.950 1.069 0.119 61 l .. ~na
Anchor agel
Willow -651 0 3 2 X 954 400 688 0.950 1 .. 022 0 • .072 56 t._.())l.
Anchoraqel
Willow -651 .0 3 2 X 954 aoo 976 .0.950 0.999 c .. o4~ 53 1, ... oon
Anchoragel
Notes: 1The distance from Willow to Anchorage wil.l ·be revised for the final analysis.
2shunt rt1actors. are required at Fairbanks to gati'sfy -voltage rise criteria ..
3aesults for the. line sections Devil Canyon -Willow -A."1chorage are also valid for Transnussion Alte:rnative 4.
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TABLE 3. 7: TRANSMISSION LINE ENERGIZING
Transmission Alternatlve 5
-Line Sendin2: End
Reactors No. of No. and Short Re.~'«ing (recei vil'lg Circuits Size of Watana Cir~uit Initial Final Voltage. Line ~ Line Section Length end) at 500 kv Conductors Generation Le\\iel Volta2e Vol. taste Rise Flow Vol<~~ {mi) (MVAR) .. (kcmil) (MW) (MVA)-(per unit) (per unit} (par unit) (MVAR) (~,liZ' tunit)
Devil canyon -· 90 0 2 3 X 795 200 564 0.900 1.1842 0 .. 2842 234 l .. ~Q$-2 Willow
Devil Canyon -so 75 . 2 3 .X 795 200 564 0.900 1.035 0.135 97 l~Q~7J Willow
Devil canyon -90 75 2 3 X 795 400 1091 0 .. 950 1.021 0.077 96 1~~ Willow
Devi! ~~yon 9Q 75 2 3 X 795 800
Willow 2044 1.000 1...046 0.046 99 1.~
Willow -501 0 ~ 3. X 795 200 506 0~950 1.1372 0.1872 119 1 .. 1o~ ...
Anchorage
Willow -so1 50 2 3 X 795 200 506 o.sso 1.027 o.on 44 l .. Q~ Anchorage
Willow -so 1 so 2 3 X 79S 400 892 1.000 1.049 0.049 46 1.0., Anchorase
tiillow -so 1 50 2 3 X 79S 800
Ancho:t;"age
1443 1.000 1.030 Q.030 44 1~.0~-
Uotes: 1 . . . . -. The distance from Willow to Anchorage will be revised for the final analysis.
2 . . . .
Shunt reactors art! required. at Willow and Anchorage to aat:i.sty voltage rise criteria. 3 . .
Shunt eo~apensation is. not required for 230-kV lines Devil Canyon to Fairbanks, Alternatives 3, 4 and 5.
--'----··-
TABLE 3.8: RATINGS OF REACTIVE COMPENSATION REQUIRED
Fairbanks Anchorag:e Willow
Transmission Static VAR Shunt s~ries Static VAR Shunt Series Static VAR Shunt Series·
Alternative Source Reactor Capacitor Source Reactor Capacitor Source Reactor <Capacitor
(MVAR) {l.WAR) (MVAR) (MVAR) (MVAR) (MVAR) (MVAR) (MVAR) ~MVAR)
1 100 2 X 75 400 430 773
2 100 2 X 75 400
. -
3 200 430. 400 -430 -773
4 200 430 40.0 .... -
5 200 430 200 2 X 50 2 X 75 -
.• --... -
' ·.
-.·.;;····
~1:-',
I
I
I
I
I
I'
··a:
I
I
~ABLE 3, 9: TRANBMISS!ON AND StTBSTAT.ION UNIT CCtSTS
~ransnrl.ssion
Line Costs
-Voltage
(kV)
Conductor
\K"clliil1 ·-·-
230 "1, X 954
230 1 X 1272
230 -1 X 1351
345
345
345
500
2 X. 795
2 X 954
2 X· -.l-3&J.c-.. ·-·"·'·,--
3 X 795
Bas.e Cost
$/Circuit Mile
120,000
136,000
140,000
190,000
207,000
-= ---~,25-1 ,-eeo
326,000
Land Acquisition and Clearing
Voltage
(kV)
230
345
345
500
No .• of Circuits
2
2
3
2
$/Mile
70,000
75,000
96 fooo _
80,300
,_,
Final Cost1
$/Circuit Mile
162,000
1841000
l$9,000
256,000
279,000
339,000
440$000
'}
...•. · .-~-
I
I
I
I
••
I
I
I
I
I
.I
I
I
·I.· . ..
I
Table 3.9
Transmission and Substation Unit Costs - 2
Substations -------·-------
Vo1tage
{kV}
138
230
345
500
Station Base Cost2 Circuit Brea.lcer Position
($ .Million) ($ r.Iillion}
1.000
1.500
2.000
2.500
0.400
0.700
1.000
1 .. 600
Autotransformers {including 15 kV ter1:_iary}
Voltage
{kV)
230/1.38
345/138
500/1.38
345/230
500/230
Generator Transformers
Voltage
(kV}
345
500
75 MVA
($ Million)
0.500
0.700
$/kVA
4.20
5.00
150 MVA
($ Million)
0.800
0.,900
1.200
0.900
1·.200
250 MVA
($ Million)
1.100
1.300
1.600
1.300
1.600
I
I
••
I
I
I
I
I
I
I
I
.lr.
I
I
I
'I
Transtnis .. sion and Substation Unit Costs - 3
Shunt Reactors
vo~tage
(kV) -
345
500
50 MVARS
($/kVAR).
24.60
Series Compensation (all volta,ges)
$14.00/kVAR
Statio VAR Squrces (tertiary . voltage)
$30.00/kVU -
Notes:
c
75 WlARS
($/kVAR)
1.11
17.20
1 Final transmission line ·costs (Sheet 1) include 20 percent contingencyR
plus 5 percent -engineering, 5 percent construction management, and
2. 5 percent owner's _cost.
2• . -Substation base cost (Sheet .2) includes land acquisitions, site
preparation, foundations 1 etc.
,;.,... --·
. ii
.. -· !
------
TABLE 3 .. 10: LIFE CYCLE COSTS
Transmission Alternative 1
Susitna to Anchorage - 2 x 345 kV 1 2 x 1351 kcmil, 50 percent series compensation.
Susitna to Fairbanks - 2 x 345· kV, 2 x 795 kcmil, no series compens~tion.
1993 Costs 2000 Costs
Current $ x 106 1981 P .. W. current $.x 106 1981 P.W ..
Line Capital
Line Capital Cost
1.5 percent Bond Commission
Total Line Cost
Land Acquisition
Capitalized Anr:,ual Charges
Capitalized Lir~e Losses ,'->·
Station Capital
Station Capital Cost
1.5 percent Bond Conunission
Total Station Cost
Capitalized Annual Charges
19Sl .Present Worths
Total Lile Cycle cost
220.12
3.30
223.42
26.70
181.5(:)
75.66
123.88
1.86
125.74
135.46
156.70
18 .. 73
12.7. 34
53.07
88.19
95.01
539.04
44.74
0.67
45.41
45 .. 60 26 .• 01
51~91
Tot a~
·1981 ~ ... w~
156 .. 7Q,
18 .. 7~
127.3~
53 .. 01!
114 .. 09
12l.Ol
590.9$
--------
TABLE 3.11: LIFE CYCLE COSTS
Transmission Alternative 2
Susitna to Anchorage -3 x 345 kV, 2 x 954 kcmil, no series compensation ..
susitna to Fairbanks - 2 x 345 kV, 2 X 795 kcmil, no series compensation.
1993 Costs 2000 costs
--·--
Total..
Current $ x 10(5 · 1981 P.W. Current $ x 106 1981 P.W. 1981. P-.W.
Line Capital
Line Capital Costs
1.5 percent Bond commission
Total Line Cost
Land Acquisition
Capitalized Annual Charges
Capitalized Line Losses
Station Capi.tal
Station Capital Cost
1.5 percent Bond pommission
Total Station Cost
Capi taliz_ed Annual Charges
1981 Present vlorths
Total Life Cycle Cost
192.25
2.88
195.13
29.64
160.76
77.70
123 .. 88
1 .. 86
125.74
135.46
136.86
20 .. 79' --.. --~-~---~ -·-----:.'
112.75
54 .. 50
"
88.19
95.01
509 .. 10
39~12
0.59
39.71
30.49
31.47
0 .. 47
31 .. 94
32.07
22.65
17.39
18 .. 21
18.29
76.54
'·i
159 .. 51.
20 .. 19t
130 .. :14
54.,$Q
106 .. 40-
113.3()
584.64
;-. .. ..... IIJ• :------------
TABLE 3.12 ~ LIFE CYCLE COSTS
Transmission Alternative 3 .· \
. ---~--------------------~----~~----~~----~----~--~~~----------~~~--~--------
Susitna to Anchorage -2 x 345 kV, 2 x 1351 kcmil 1 50 percent series compensation.
Susitna to Fail::-banks - 2 x 230 kV, 1, x 1272 kcmil, 50 p~rcent series compensation.
1993 Costs 2000 Costs
Current $ · ;( 106 .. 1981 P. w. current $ x 106 . 1981 P .w.
Line Capital
Line Capital Cost
1 .. 5 percent B()nd Co1Ilmission
Total Line Co:;t
Land Acquif;ition
Capitalized Annual Charges
Capitalized Line Losses
Station capital
Sta~ion Capital Cost
1.5 percent Bond Commission
Total Station Cost
Capitalized Annual Charges
1981 Present Worths
Total Life Cycle Cost
188.18
2.H2
191 .. 00
25.76
153.,17
91."97
135.95
2 .. 04
137.99
148.66
133. 96·
18.07
107.43
64.51 ..
96.78
104,.27
525.02
i
54.48
. 0 .. 82
55,.30
55.53.
31.54
31.67
63 .. 21
Total
1981-P .. ,'W/..,
133 .• 96.
18.,.0#
107.43;
64.51
128.32
135.94
(I
-
I
j
-~-
' -----------· '-
TABLE 3.13: LIFE CYCLE COSTS
Transmission Alternative 4
Susitna to Anchorage -3 x 345 kV, 2 x 954 kcmil, j/lO series compensation.
Susitna to Fairbanks -?. x 230 kV, 1. x 1272 kcmi1,, 50 percent series compensation.
2000 Costs 1993 Costs
Current $ x 106 1981 P.W. current $ x 106 1981 P.W.
Line Capital
Linfa Capital Cost
1,.5 percent Bond Commissi,on
Tot:al ·Line Cost
Land Acquisition
Capitalized Annual Charges
Capitalized Line Losses
Station Cavital
Station Capital Cost
1.5 per.cent .Bond Commission
Total $,tation Cost
Capi,tal.izt:ld Annual Charges
1981 Present Worths
Total Life Cycle Cost
166.16
2.49
168..65
28.70
136.08.
93.85
135.9~
.2 .. 04
137.99
148 .. 66
118 .. 29
20.13
or.:-44 ~..,:::> •.
65.82
96.78
104.27.
500.73
39 .. 1.2
0.59
39 .. 71
30.49
41.21 .
0.62
41.83
42.00
22 .. 65
17~39
23 .. 86
23 ... 95
87.85
Total
1981 P .. W..,.
140 .. 94
20.ll
112.83
65.82:
120.64
128 .. 2a
- - - - ----- - - - -·-
TABJ:.E 3 .14 : LIFE CYCLE COSTS
Transmission Alternative 5
Susitna to Anchorage 2 x 500 kV, 3 x 795 kcmil, no series compensation.
Susitna to Fairbanks - 2 x 230 kV,. 1 x 1272 kcmil, 50 percent series compensation.
1993 Costs 2000 Costs
CUrrent $ x 106 1981 P.,W. ----··-_ _;...,.~ Current $ x 106 1981 J?.W.
Line Capital
Line Cap! tal Cos.t
1.5 percent Bond Commission
Total Line Cost
Land Acquisition
Capitalized Annual Charges
Capitali~ed Line Losses
Station Capital
Station Capital Cost
1.5 percent Bond Commission
-Total Station Cost
Capitalized Annual Charges
1981 Present Worths
Total Life Cycle Cost
223.72
3.36
227.08
26.59
180,95
61.05
185.06
2.,78
187.84
202 .. 36
159.27
18.65
126.91
42.82
131.75 .
141.93
621.33
39 .. 73
0.60
40.33
40.49
23.00
23 .. 09
46.09
To tall
1981. li!>~W.
159.~1/
18.6-.$
126.~]1
42 .. &~
154.?5
165.0l'
- - - - - -·----- - ---
Transmission Alternative.
Transmission Lines
Capital
Land· Acquisition
capitalized Annual Charges
-·capitalized Line Losses
_ · To·tal Transn1ission Line Cost
TABLE 3 .. 15: SUMMARY OF LIFE CYCLE COSTS
1981 $ X 106
1 2 3 4
156.70 159.51 133.96 140.94
18.73 20 .. 79 18 .. 07 20.13
127.34 130.14 107 .43' 112.83
.53.07 54.50 6.4.51 65.B2
355.84 364.94 323.97 339 .. 72
----~ ·~!~
'•
5
159.27
18.65
126.91
42.82
347 .. 65
i
. l
----.. ----·--
TABLE 3.16: SUMMARY OF . COMPARATIVE COSTS AC VERSUS DC -TRANSMISSION
Comparative Costs -$ Million
Transmission to Anchorage Transmission to Fairbanlks
Cost CoinponeJl1:.S
Line·Cost 1 ~line capital 1 line capi~a~i~ed O&M 3 land acqul.s~t:t.on (R.O.W.)
Station Costs 1 station cap~tal. ___ 2 station cap:Ltal:t.zed u&M
4 Capitalized Cost o~ Losses
Total costs
AC DC
198.18
165.72
13 .. 44
99 .. 38
108.67
83.87
669.26
125.40
104.86
8.40
239.59
262.00
74.94
815 .. 19
1 Line and station'-capi.tal costs are developed in Appendix E •
AC DC
96.77
80.92
14.18.
35.32
39.62
13.72
279.53
3}".._90
:n~:Gl
q\.,.56
1~"10
l'l$.,..46
Jt(-) .. ~3
3.03 .. 3.6
. 2Cc:tp:it_a1ized O&M charges include O&M, insurance,. interim replacement and contributions in lieu of taxes. ~hese
-.. annual charges total 3.25 percent of transmission capital and 4 .. 25 percent of station capital, and they a~
capitalized. over 50 years at 3 percent.
3Land acquisition (R.O.W.) costs are estimated at $96,000/mile and $75,000/mile for 345 kV, 3 cct and 2 cct
tran$mlssion respectively, and $60,000/mile and $40,000/mile for ±250 kV de 2-circuit and single circuit,
. respectively.
4 .
Losses are va:lued at _3.5¢/kW·h,_ e1:nd they are capitaliz~d over the 50-year line life. at 3 percent ..
I
I
ANCHORAGE ll
-·------
200 ~WAR-
. ANCHORAGE T
®··.
I
3X250MVA
3X250MYA
··· ··~_-....... •_;. _· __ 150/i$00 MVt _···_· · cu.·.
. .
. .-----
•
. BELUGA
I
50 MILES I
15 MILES
--+----......--.. ·~---1 -~,
J
3 3X75 3 MVA
90MlLES
1 •
27 MILES
I
I
I I
I
~
189 MILES
GOOMW ·
75 t
MVAFi~
75
MVAfil
DEVIL CANYON
_...._....,..--..... 3£)1) WATANA
TRANSMlSS!ON . SYSTEM CONFlGURAriON
ALTERNATIVE l-
' 1:._
50/IOOMW
100 MVAR
.
I
I . •
1
LEGEND
GENERAl lOIIi
~LOAD
ED STAT1C VAR SOURCE
@ BUS NUMBER·
REAL POWER FLOW { MW )
REACTIVE POWER FLOW {MVAR)
-II-:.:··
SERIES COMPENSATION
TRANSFORMER
. WITH TERTIARY
SHUNT REACTOR
L03 BUS VOLTAGE MAGNITUDE (PER UNIT)
jt5.5 BUS VOLTAGE PHASE ANGLE (DEGr.EES)
TRANSMISSION LINES
---345l<V
----l3"a KV OR LOWER
NOTE : EQU1PMENT RATINGS INIJTCATED ARE FOR
ULTIMATE INSTALLATION (YEAR ZOOO}
FIGUREE 3.1
BELUGA
ANCHORAGE IT
• 0
50 MILES .. 3 .
Hl---t--~"'--..... """'(3 3x250
. MVA
200MVAR
15 MILES
ANCHORAGE I
_SO MILES
)..-..+-..;......+-----< 3X25Q
·-MVA
200 MVAR
-•oo· ....
,
--~ ;~~':_:;-.:::>".
•
50/JOOMW
27 MILES-
189 MILES
15
MVAR
•
i.
'
) ,;c .
. Jr ----··""· ---------..,r-e-t 4Kl50 +-......_~"'-------'+--<:
· MVA. , .. 100 MVAR
~)
GOOMW
75
MVAR
DEVIL CANYON
-.--,......-.--@) WATANA
!Rj.\NSMISSION· SYSTEM CONFIGURATiON
AL1"ERNt%rtVE 2
•. "
LEG.END
GtNERAilQN
LOAD
STATIC VAR SOURCE
@ . BUS NUMBER
'-il-
. _L_---_~----~ ...
1.03
~-¥·
REAl. POWER FLOW { MW) .
REACTIVE POWER FLOW (MVAR)
SERIES COMPENSATION
IRANSFORMER
WliH TERTIARY
SHUNT REACTOR
--. -;:-_--, --------
BUS VOLTAGE MAGNITUDE (PER UNIT}
" <\t5.5. BUS VOlTAGE PHASE ANGLE (DEGREE$)
TRANSMISSION LINES
---·-345 KV
.
13'8 J<V OR l.OWER
~OTE.' E.QUIPM~NT R;i!.ilNGS INDICA TEO ARE FOR
, . ULTIMATE INSiAL.LAT!ON (YEAR 2000)
I
. ·:1
I
I
I
I'
I
I
'' >
.. -.
ANCHORAGE II ($::>
' . !.00 1-0.1
sao ..... ;---
225 .. t-
200 MVAR
ANCHORAGE I
1.0110.0
f?O/JOO MW ~..=:::
200MVAR
•
1.03Jl0.4
0.9915.9 ---.... t"'"· ·:...~""1""--< __ BELUGA
61 150
150•0111!---
t3G,. ·I
·,
WILLOW
ll
41 45
(03 ....... '-----+!-
1.031 18-.6
0.98!4.6
_...::., --.. -. --~---;:co--,-,----~------
7;
!;03!30.2
....
'
--190 l
76
-+----l.-..1!7 8
1.01113.5
t 19t2 ..
125 . DEVIL CANYON
1.03127.3
GOOMW
WATANA
PEAK DEMAND FLOW-ALTERNATIVE l
85% LOAD AT ANCHORAGE /!
• {I
,._. --
.·FAIRBANKS
1.02 l!L3
\ r
f
! l
!
50/lOOMW
IOOMVAR
. LEGEND
e
-------4
··.er
GENERATION
LOAD
STATIC VAR SOURCE
· ® BUS NUMaER
.. \
-II--
REAL POWER FLOW ( MW}.
REACTIV.E POWER FLOW (MVAR)
· SERIES COMPENSATION
TRANSFORMER
WITH TERTIARY
SHUNT REACTOR.
1.03 BUS VOLTAGE MAGNITUDE (PER UNIT)
'
po.5 BUS VOLTAGE PHASE ANGLE (DEGREES)
TRANSMISSION LINES
345 KV
13"3 KV OR LOWER
,-.-.-=-o_-.
.,
•
'
FIGURE 3.31•1
I
I
I
I ,
I.
a··
I
.I
I
I
I
I
I
.. ,~ ---~·
.
-_.::.,:':;---~----
' 60();---
2.00 4: t.
>-+:-:--:-::.-:::+------'-~-<· 3x250 ~48 MVA
200MVAR
1.00!4.2.
•
ANCHORAGE I
50/100 MW ]llo 38 .
I ll> 77
soo . .---
2oo.r 1
33x250 }-.f-1~.,.:-::::57:1------< MVA
tso ..... ,.._,..._
114 -.c . I
200MVAR 0.99L4.0
··., .
1.01 19.6
.: ---· ··• ·~ n. "·· ~--'-'f" ..
•.
BELUGA
·WILLOW
102.4.-----
72. ...... ,__--11-·
' • . .
---FAIRBANKS
1.00 i2.! ..
so-..
t
74 •400
-+ .. !50
-~--
57 ... I
~. j.
..-------------....,.-t· 4xl50 -+--:-"4is:r::;t=:j:\:~ tiNA .J t ......... IOOMVAR
74 I T t T
1.04115.8 ....,.jL.:.--...:..-t-t:----+.;;84.;...-....:...a.---"T"'---(
. 797 ~-
·t
35 I
.
DEVIL CANYON
. . ' 65
t soo SOOMW -~42""""ro .... t....__·, ~ WATANA
1.03{ 27.3
80 800
·-='~
PEAK DEMAND FLOW-. ALTERN~1.lVE t
25°/o LOAD At F4lRBANKS.
E9 GENERATION
~LOAD
EO STAT1C VAR SOURCE
@ . BUS NUMBER
REAL POWE~ FLOW ( MW)
• REACTIVE POWER fLOW {MVAR)
-11--...
SERIES COMPENSATION
TRANSFORMER
WITH TERTJARY
SHUNT REACTOR
L03 BUS VOLTAGE MAGNITUDE (PER UNIT)
BUS VOLTAGE PHASE ANGLE (DEGREE;$.}
TRANSMISSION LlNES
---M5l<V
---13"9 KV OR LOWER
'
.I.·
I
·I
I
I
I
·I
I
.. J ...
I L·.,.-\~1
.
;; .. -
.-!).
ANCHORAGE II
1.00 (~0.9.
-,----·--·----.
680 ... '"'""'"· -
2la5 .... 1
3x250 r-t-l-l!O_l_4_,5t----~. ' .. rMVA----~ ·
200 MVAR
1.03 l~o.s
73t f
l,03l9.6 . . . i 150
l.00[5.1.,.. .. ·---. .... t"!"· · ....... -.. "'!"J.,·r---""' BELUGA
59. 150
150 ..... """. --
. 134.,. . 1 . -~·-·
0.'~8l.1d_ . t 122 0
15 1
ANCHORAGE. I t .'~2-
25 t
50/IOOMW at,. I·
. ·.;. ..
EiSOr ... -.~-,--1 ..
225""" I 1:oo 1.1z.o
. -~ --------· '---·
76 1204
•
:-~
----,--.,· 190 t
76
.FAIRBANKS
'
1.02 1!4.8
?; ·-
' ' . '
5 ~.: , E9 50/IOOMW 4~-:"' I . · . ,, . ,-. -· ~ .
' . '
J, ~ 0
•tel · j I ·· ...--------------r-1. 4•150 J---··11
,j7:7:;f .. ==i=J \1 . ·. r .. ·· .. ··. f.···.·. · MVA · .,) . ~ _·l.Oltl7.1
75[
IOOMVAR
3x250.
>-~-r~· ..,~114:+-----< MVA 1.•.·.· t T I . 123
1.0312.2; t ' ~~--.L.--+---11-----...... --"T---<. t .... · ... · .. · . 796 ..._
r•
200 MVAR '@.
0.?!'D.o
. 801 .
. .· .
.. '···-
. ·_;.,.
... ·t·· •·.. l.oa 130.9 -orr.--~----
. ,_ -
ao I 75 600
600MW
WATANA
.--.r . ·':-
PEAK DEMANDFLOW~ AlTERNATiVE Z
· 85°/o LOAD. AT ANCHORAGE,, ·
1---
;
•
.•.. ·
·' UtGt;::NO
. t-
i i.OAO ·
STATIC. VA.R SOU~CF
® . 1:!\JS NUM!:lF.~
.. I
-il-
. . .
(
-l
L03
jl5,~
REAl. POWER FLOW I MW }
REAC:TlVE ~'OWER FLOW {MVAR)
SERlES COM?ENSATIO!Il
T-RANSFORMER
WITH TE:RT.IAR~
. ~\-.
SHUNT ~EI\CTOR
BUS VOLTAGE MAGNITUDE: {PER UNIT) ...
· BUS VOLTAGE PHASE ANGLE (DEGREES)
TRI\NSMISS!ON LINES
---345 li:V
13'8 KV OR LOWf:R
' {} -
·····1· .•. .· ·'
•' ·I··.
I
·I
I
I
I·
,.
<.·
ANCHORAGE li
600, .... f-.·-........
·;J
3x250 ·}-J--~J----'-~~ MVA
1.00 14.1 ---.... t-·······.""· ........... "l"t"'i·· ..... -"'"""{"'--=~
53' ISO
BELUGA ..
150 ....... --'--
l30 ...
WILLOW
0.9813;6
ANCHORAGE I
. 1.01 !0.0
50/100 MW
soo ... -.t-L'-~
200-c ·I
'
,,
' ---~ .
. .-~,
FAIRBANKS
; .
. !.0,1 (5.4 •
. 50 ..
59 ... 0.t--l-
··:::
.. ~400
i ·-..
I 1.•.1.30
. :f:('r t
..... -----~--------,..... .... 4x!50 i ',.
MVA · ·68• l
.JQOMVAR. t.•. Y.··• · + ~ 0:99J9.6
73h .
l
3x250 ,_·+t--.-... -ss+---.---...'""""-< MVA
200MVAR
0;9814.1
t.02 'I.Q.Q.. .,
3f 10t40 l 35tG .
-J-!.+--1-:.· ~---+.:.:1S.;:;........,i·;.....Ji.--..,...---< 'DEVIL CANYON
. 1,051 19.0 ·t. '. 1 ....._.,....
3[ r :· _ _;
. ' <-?
' . .,,-·.---,-~--
SOOMW
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.· f PEAKDEMAND FLOW...., ALTERNATJVE 2 · ..
. 25o/; LOAD AT fAiRBANKS. . . .
. '
GtNERATJOr~
. . ;-:. . '
' !
I U.>AD
STATIC VAR SOURCE::
·. @§) bUS NUMBER
'.'. -<,;;
REAL POWER FLOW { MW }
-. . ' tl
REACTIVE POWER FLOW {MVAR}
SERtE!;: ·';'JMPENSAT!Otll
TflJ).NSfORMER
WlTH TERTiAR'r
--rt-·
L-jl.· .. ·· ... ) ' ., .. . .,,, .
SHUt-.T REACTOR
1.03 BUS VOLTAGE MAGNITUDE· ( PtR UNIT) '
l 155 SUS VOLTAGE PtlASE ANGLE {OEGREltS)··
TRANSMISSION· !,.lNE:S
..
L'\c'B KV OR l.OWER
. .
-;-;-;:.,':-·;=c~--,.c---_-•c;c=----=.-·~""--''"-'·"'
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10~--------~~----~--------~~---------------------
0::: . tB -eot-----""--+--......._.._: :--~-.-~---'
0
~
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~ I z -30 ~---~----+----64-!-----..:.f.~...;.._-~---+~-----t--,__ __ ~
<t
a: g
~ ~·~~~~--+--+--~~~--------~~~----~~----~~ 0::: ~ \
a:: \ LLJ
·~ -50~--~,--~~--_,~~-+---------4--~~~--~~~~~
-\
/
1
-70•-~~----~------------~------~--------~--------~ 0 0.2 Oo.4 0.6 0.8 1.0
TIME (SECONDS) .
NOTE
-01 STURBANCE IS 3 .. PHASE FAULT AT DEVIL CANYON CLEARED JN 0.08 SECONDS
BY3·PHASE TRIPPINGOFOEYiL CANYON-WILLOW LlNE WtTHOUT RECL.OSURE
-ROTOR ANGULAR DISPLACEMENT PLOTTED IS THAT OF AL.L GENERATORS
RELATIVE TO WATANA
TRANSIENT STA __ ~:LITY s_ .. w_ JN. G CURVE. S.-ALTERNATIVE I ~D~ ..
85 Yo LOAO--AT ANCHORAGE FfGURE 3 .. 7 HUO!Il
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-iOr---~----~--------~--------~----------~--------~
,..._...__ ...... ---.. ., ----
•
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I ~0~--------~-----T--~----~--~------~~~----,_~
• I •
•
. .:_./ ._/
-70~------~~--------~~------~----------~~----~ 0 0.2 0.4 0.6 0.8
TIME (SECONDS}
NOTE
-DISTURSANCE 15 3·PHASE FAULT AT DEVIL CANYON CLEARED lN 0.08 SECONDS
SY 3-PHASE TRlPPINGOF DEVIL CANYON-FAIRBANKS LINE WIThOUT RECLOSURE
-ROTOR ANGULAR DISPLACEMENT PLOTTED IS THAT OF ALL GENERATORS
RELA"flVE TO WATANA
1.0
TRANSI!;NT S"f ABIUTY SWING CURVES-ALTERNATIVE l t IOD_ ~.I
25°/o LOAD ATFAIRBANKS -FlGURE s.a 808£11
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-(J) ; / ... ~
(.!)• ~ -20~--~----~------~-+--,~--~~----------~~-1'~--~
UJ _J
~ -30~~------~--~~--~~~-~~~~--------~~--~~
<!
et:
f2
0
~ -~~--~~--~·~~---++r--------_,--~~~~~----~~ a:
~ <t n:
LU
~ -50~~~~~~-----~~-r--------~~~~----r---~+-~
(!)
' \ J
-70..____~_.....______.___~-0 o.4 o.s o.s -t.o
TIME (SECONDS}
NOTE
,.
-DIStURBANCE IS 3· PHASE FAULT AT DEVIL CANYON CLEARED IN C.OS SECONDS
BY 3-PHASE TRIPPING OF DEVIL CANYON-WlLLOW LINE WITHOUT REClOSURE
-ROTOR ANGULAR DISPLACEMENT PLOTTED IS THAT OF ALL GENERATORS
RELATIVE TO WATANA
·;
. .
TRANSIENi STABILITY SWING CURVES-ALiERNAFJ ..
1
.
6
JV.u·· .RE.E2"--g~~Pll[Q1.
85o/o LOAD AT ANCHORAGE · w. HUDlO
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P-------------~-~c ~------~------------~--~----~-------·-------~-
-
1
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10~--------~----~----~---~----~----~----~-------~
.. _....-., .... ~ ... __ .......,_
-··~---
-10~----~--~--------~--------~----~----r-----~--~-
-ro~--------~--~~~------------------------------~ o o.z. 0.4 o.s o.e t.o
TIME (SECONDS}
NOTE
-DISTURBANCE IS 3·PHASE FAULT AT DEVIL CANYON CLEARED IN 0.08 SECONDS
BY 3-PHASE TRIPPING OF OEVll CANYON -FAIR SANKS LINE WITHOUT RECLOSURE
-.ROTOR ANGULAR DISPLACEMENT PLOTTED JS THAT OF ALL GENERATORS
RELATIVE TO WATANA
TRANSIENT STABI~IT_Y s_. WING CURVES-ALTERNATIVE-2 .. janamj
_ . 25 Yo LOAD AT FAIRBANKS FIGURE 3.10 1108[1} ·
4 -CONCLUSIONS
Al~ fJ.ve transmission al1t:.ernatives which were developed and tested would
be capable of transmitting Susitna power to .Anchorage and Fairbanks with
acceptab~e levels of reliability. Al.l, excep·;:, Alternative 5, h&ve v~y
similar present worth life cycle costs.
"' .
Tl'lere-are., ho~ver,. other differences between these alternatives which
have not been quantified in the above analyses. T'n;ese differences, as
outlined below, result in making some of the alternatives more desirable
than others._
500-kV transmission to. AnchorCl,ge has a higher ultimate capability than
any other uternative, but at a. significantly higher cost. .
Furthermore, this added capability is not required with presently
£oreseen installation at susitna. This alternative also implies a dual
voltage system with_ less possibility of standardization and reduced.
reliability because of the additional transformation required at Dev.il:
Ca!J.yoli.
230~kv transmission to Fairbanks would need. to be combined with ·a
higher voltage tran$Iltission to Anchorage. with-the resultant
disadvantag;es of a dual voltage systemo Furthermore, it includes
series compensation with additional complexity in protection and
operation. fts reduced transfer capability offers no economic
advantage-.
-Of the 345-kV alternatives, the three-circuit configt'lt'.ation to
Anchorage has the greatest reliability and simplici~y by not requ±ring
s.eries compensation. l:t also has -~ higher ultimate transfer capabil~ity
' and a higher capability with single contingency outage·, thus allowing
for greater flexibility of capacity _.planhl.iig-~for susitna. l:t al.so has
partial transfe.r capability in the case of the double contingency
outage of parallel c.irctdt elem~nts.
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1.
-On the other hand, the three-circuit configuration results in a
slight1y greater visual impact than the two-circuit alternative ..
Considering the overall balance of economy, reliability, tl:'ansfer
capability anq opera~ional complexity, the three-ci~cUit configUration of
Alternative 2 is seen to offer the bes.t combination of ·advantages.
It i:s recognized that; in view of the uncertainties regarding some of the
system parameters, seve:r;:-al sweeping assumptions had to be made to be able
to carry:.out this preliminary analysis. The most obvious of these
uncerts±nties involves the interconnection configuration between the
Susitna transmission and the high-voltage transmission system in the
Anchorage area. Installed capt,icities and generating unit sizes, as well
as other technical characte~isti:cs of the Suaitna project, are likely to
be revised as well. However, it is expected that the conclusions drawn
from both the technical and economic analyses will not be significantly
affected by the resulting changes in system parameters.
4 - 2
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5 -RECOMMENDATIONS
The folloWing recommenqations result from the preceding analysis.
(a) Recommended transmission alternative
-Watana to Devil Canyon
-2 circuits at 345 kV with 2x954 kcmil
conductors
-Devil Canyon to Anchorage -3 circuits at 345 kV with 2x954 kcmil
conductors
-De·vil Canyon to Fairbanks - 2 circuits at 345 kV With 2x795 kcmil
conductors
All without series compensation.
{b) Before ~oceeding W-ith the final feasib~lity analysis, it is
recommended to await revisions and more definitive decisio~s and
values for the following parameters.
(i) Ultimate installed capacity at Susitna •
(ii)
(iii)
(iv)
Generating unit s~zes at Susitna.
Number and location of points of delivery for Susitna power
to the-Anchorage area.
Details of generation planning, resUlting in thermal
development at Beluga or elsewhere.
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·.: : . . . ·.· .... : -. . :-~ ..
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)\
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(co) At a future date, it is recommended to analyze the possible
advantag.e o£ sta:ndardization by constructing all of the Susitn~
~ansmission to Fairbanks with 2n954 kcmil conductors(j The first
eucuit is expected tc be built with this conductor between Willow·
and. Healy as part of the 1\nchoraqe-Fairbanks transmission int·erti.e.
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APPENDIX A
TRANSMISSION PLANNING CRITERIA
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APPEtiDIX .A
TRANSMISSION PLANNING. CRJ:TERIA.
In general., transmission facilities are planned so that the single
conti.ngency outage o£ any ~ine or trans£ormer element will not x-esult :in
restrictions in the rated power transfer, although voltages may be
temporarily outside of nt>rntal limits. t;rhe proposed guidelines concerning
power transfer .capability, stability, system _performance limits, and
thermal overloads are detailed below.,
(a} Transmission System
Transfer CaJ?ability
The transmi:Ssion system will be designed to be capable of
transmi.tting the maximum generat:ing capability of the Susitna
Hydroelectric Project with the single contingency outage of an¥ l.~ne
or transformer element. The shau:ing of load between the Anchorage
and Fairbank.s areas is approximcttely 80 and 20 perpent respectively.
To account for the uncertainty :Ln future deve.lopment, the
,
transmission system shall allow for this load sharing to vary from: a
maximum of 85 _percent at Anchorage to a ma~iln~"f?~ 25 pet;"cent at
Fairbanks.
(b) Stability
The transmission system will. be checked for transient stability at
critical stages of developnra:nt. The system is to be designed fol:;'
high speed r~closing follottring single-pha~e faults that ~e cl.ecu:-ed.
by single-pole switching. In the case of multiphase faults, delayed
reclosing ~s assumed.
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The design fault for transient stability analysis will be a 3-phase
fault clearea in 80 ms (4o8 cycles)" by the local breaker and 100 In$
( 6c 0 cycles.) by the remote breaker, with no reclosing.
(Note: At later stages of Q.es ign it may be uaef ul to check dynamic
stability for· unsuccessful reclosure of an SLG fault cleand
eventually by 3-phase trip and lock-out following initial.
single-pole trip. For the present, a 3-phase design fault
is .considered to be equivalent in terms of severity.)
(c) ~Istem Energizi~~
Line energizing initially and as part of routine .switching
operations will generate s01Ue d}"llamic overvoltages. . System design
shoUld be arranged to keep these overvo~tages within the following
limits ..
Line open-end voltages at the remote end should not exceed
1.10 per unit Ofi line energizing.
Following line energizing, switching of transformer.s and var
control. devi<.~es at the receiving end shoUld bring the vol.tage dawn
to 1.05 per unit or lower.
Initia~ voltages at the energizing end should not be reduced below
o. 90 per unit.
-Final voltages' at the energizing end should not exceed 1. 05 per
unite
The step change in voltage at the energizing end of the line
should not exceed the following values
,' A-2
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(d)
(i) 15 percent with only one generating unit operating at
watana (to repre$ent a temporary condition during the early
stage of commissioning $1_f: :t;.ne Susitna project}
(ii) _ 10 percent with two units operating at Watana (to represent
a slightly longer-term condition early in the developnent
of susitna)
(iii) 5 percemt with 800 MW of generating capacity operating at
SUsitna.
Load Flow
System load fJ.ows will l:)e checked at critical stages o·f develop11ent
to ensure that the system configuration and component ratings are
adequate for normal and emergency operating conditions. ).1b.e load
levels· to be checked-will include peak load and minimum load
(assumed 50 percent of peak) to ensure that system flows and
voltages are within the limits specified belo1>1.
-Normal system flows must be within all. normal thermal. limits for
transformers and lines, and shoul.d give bu:s.voltages on the EHV
system within +5 percent, -10 percent, and at subtransmission
buses within +5 percent, -5 percent .•
-Emergency sy~1tem flows with the loss of one system e-lement Iml$t be
within emergency thermal limits for lines and transformers
(20 percent 0/IJ). aus-vol'tages on the ES.V system should be within
+5 percent, -10 percent, and at subtransmission buses within
+5 percent1 -10 p~rc.ent.
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• • • •.t • • •
(e)
{f)
Corrective Measures
,.
Where limiting performance criteria are exceeded., system design
modifications will be applied that are considered to be most cost
effective~ Where conditione of low voltage are encountered, for
.example, power factor improvement would be tried. Where voltage
variations ex_ceed th.e range of normal corrective transform&" tap
change, .supplementary var generation and control would be applied-.
Where circuit and transformer thermal limits are about to be
exceeded, additional elements would be scheduled.
Power Delivery Points
For study .p~-poses, it will be assumed that when susitna gene1;ation
is full.y developed (i.e. to appro}(ilnately 1,500 MW~c the total. output
will be ·delivered to terminal stations as follows.
-Fairbanks -one station at Gold }{ill with transformation from EHV
to 138 kv.
-Anchorage one or two stations with transformation froni EHV to
230 kV or 138 kV.
The provision of intermediate switching stations along the route. may
prove to he economic and essential for stability and operating
flexibility. Utilization o:f these switching stations for the supply
of local load will be examined, but security of supply to Anchorag-e
and Fairbanks will be given priority considerat;ion.
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APPENDIX B
EXISTI1'1G TRANSMISSION SYSTEM 0-A!I.'A
·-
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TABLE OF CONTENTS
Page·
LIST OF TABLES -------·-----------------------------------------B -i LIST OF FIGURES --------------·-----....... -............ ..,. _____ . ____________ ...,...,...,. B -.iv
B1 -ANCHORAGE MUNICIPAL LIGH'l' AND PCMER -----------------------B -1
B2. -CHUG..2\CH ELECTRIC ASSOCIATION, INC" ------------------------B -7
B3 -FAIRBANKS 14UNICIPAL UTILITY SYSTPM -------------------------B -14
B4 -GOLDEN ~.LLEY ELSCTRIC ASSOCIATION, ntc. --------~-,...-------B .... 19
BS -UNIVERSITY OF ALASI<A, FAIREANI<S •-----------..:. ... _____________ B -28
B6 .;,.. MILITARY INSTALLATIONS, FAIRBANKS AREA ----.--------------B -30
B7 --MATANUSKA ELEC'l'RIC ASSOCIATION AND ALASl\A l?CMER
AlliiiNISTRA.TJ:ON--------... -----------:...------------------------B -32
l
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LJ:ST OF TABLES
Number
B1.2
B1..3
B1.4
B1.5
B1.6
B2.1
B2 •. 2
B2.5
B3.1
B3.3
Title
Anchorage Muni.cipal Light and Power
EXistin<; Generating Capacity
Anchorage. Munici!:-~~.1 Light and Power
Generator Dat_a_
Anc~orage Municipal Light and Power
Transmission Line Data
Existin~ and. Planned Facilities
Anchorage Municipal. Light and Power
Transformer Data
Anchorage Municipal Light and Power
Distribution Substation Data
Existing and Planned Facilities
Anchorage Municipal Light and Power
Historical. System Peak Demands .
Chugach Electric Association, Inc.
Existing and Planne.d Generating Capacity
Chugach Electri.c Association, Inc.
Generator t>ata
Chugach Electric Association, Inc.
Transmission Line Data
Existing and Planned Facilities
Chugach Electric Association, Inc.
Transformer Data
Existing and Planned Facilities
Chugach ~lectric Association, Inc.
Distribution Substation Data.
Existing System
Fairbanks Mtinicipal Utility System
Existing Generating Capacity
Fairbanks Municipal Utility System
Generator Data
Fairbanks Municipa~ Utility System
Transmission Line Data
EXisting_and Planned Facilities
B--i
• '• ... -• ". " • ". •• • • • • .. • • • ~ • 4 ,.."J•••
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Idst of Tables -2
Number
B3.5
B4.1
B4-.;2.
B4.3
J34.4
B4.5
B4.6
B4.7
B4.8
B5.1
B5.2
1'36.1
Title
FaiJ:banks Htu~\icipal Utility System
'l'ransforme?: rata
Existing an.·:! Planned Facilities
Fairba.."lks Municipal Utility System
Historical Load Data
Golden Valley Electric Association, Inc.
Existing Generating Capacity
Golden Val.ley Electric Association, Inc~
Generator Data
Golden Val.ley Electric Association, Inc.
Transmissi.on Line Data
Existing System
Golden Valley Electric Association, Inc.
Transmission ·Line Data
Planned Facilities
Golden Val.ley Electric Association, Inc.
Transformer Data
Existing System
Golden Valley Electric Association, Inc.
Transformer Data
Planned Facilities
Golden Vall.ey Electric Association, Inc.
Distribution Substation Data
Existing System
Golden Valley Electric Association;·· Inc.
Distribution Substation Data.
Planned FaciJities
University of Alaska., Fairbanks
Generating Capacity and Data
University of Alaska, Fairbanks
Transformer.Data
Military Installations, Fairbanks Area
Generating Capacity and Data
B-ii
. . . .. ' ... . . . . ~ . . . . . . ~ .
I. ~st . o,L~ab:Les ,. 3 -;---·;':..-c:-,:.:"':;;:~___::...::.: :;.~ ·-----·--~~:-;;_:-. '--::_ .. ~--·~-..:.: •.. -,--"~" ~-------·--·-••
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B6.2
B7.1
B7.2
B.7~3
Title_
Military Installati.ons, Fux-banks Area
Transformer Data
Mata.nuska Electric Association and
Alaska. Powez: Administration
Existing Generating Capacity
Matanuska Electric Association and
Alaska Power Administration
Generator i:!~4-Transformer -Silt-a
Matanu.ska Electric Association and
Alaska Power Administration
Transmission Line Data
Existi.ng System
Matanuska Electric Association and
-Alaska Power Administration
Distribution Substation Data
Exi$ting System
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L:IST OF F.IGURES
Number
B.l
Bc;2
B.3
Title
1\..ncP,oraqe-Fairbanks Railbel t Area Map
Anchorage Area, One-Line Diagram -1984 System
Fairbanks Area 1 One-Li.ne Diagram -1984 System
B-iv
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TABLE. 81. 1: }WjJ-PRAGf MUNICIPAL LIGiT AND R:>WER
EXISTING-GENERATING CAPACITY
Unit -
Statton l -Un.i't 1
Statton 1 -Unit 2
Stat ron 1 -Unlt 3
Statlon l -Un ii' 4
StaTion 1 -01
STation 1 ... 05
Statton 2 -Unit 5
Statlori 2 -Unit 6
Station 2 -Unit 7
Total avai I ab fe capacity·
-ll?eak rating a-t 0°F.
Year of
I nsta lla'ti on
Abbrev fat ions: GT -G!!s Turb i ne
ST -Steam Turbine
GT
sr
GT
GT
DfeseJ
Diesel : }
B --·1
Capac I' tY.*
(MW) a
10.25
16(l-25
19.50
37.50
t.to
l. 10
138.~
230.60
Remarks
Naturai gas
Natural gas
Natural gas
Natu~al gas
Stack start units
Sf ack start units.
Natural gas,
combined cycJe, base
load
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I TABLE. 61.2: ANCHORAGE. MUN!CIPAL Lla-tT AND POWER
GENERATOR DATA
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UniT -
Sta1'1on l -Unit 1
Siatlon 1 -Unit 2
sntlon 1 -UniT 3
S:tatlon 1 -Unit 4
Station l -01
Station 1 -05
Statton 2 -Un tt 5
Siatlon ·z -UniT 6
S-tation 2 -Untt 7
Power
Voltage Ra-ting Factor
(kV) (MVA}
t3.8 15.6 .as
13.8 15.6 .as
13.8 19.2 .85
13.8 31.765 •. 85
t. 1 ·• i\ ·~'"'
1~ 1 1.0
13.8 39.2
13.8 38.8
13.2 110e 5
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* lmpedance in per unit on 100 wm base.
**tnertta constant in per-uniT on 100 MVA base.
Generator ltneedance*
xd X'd xnd Xz --
11.54 2.44 i.60 1.60
11.54 2.44 1.60 1.60
14.43 2.43 1.60 1.61
5.68 •. 12. .41 .41
104.55 29.09 20.00 21.82.'
104.55 29.09 20.00 21.82
5.22 .70 .41
4.12 .57 .28
2.25 .34 .24
B-2
Inertia
X 0
Constant**
1.64
1.64
1.94
• 14 z.~t\9
3.88
1.63
8.40
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TABLE Bl.3: ANCHORAGE MUNICIPAL LIGHT AND POWER
TRANSMISSION LINE DATA
EX J STING AND PLANNED FACILITIES
Pos Seq
l mfl!danc:;e* Transmission Cfr<;ult -VolTage
From Bus -To Bus Lengt-h \:ond.uctor
(ml}
R X
Susceptance**
.. Jro
Sta-tion 1 -Station 2.115 kV
<vta Ft. Riehanison...£lflleildorf -AFB>t
Stat fon 1 ... Station 2
Statlon 2 ~ APA Tap 115 kV
Stat ion 2 -APA Tap .6
Station. 1 .... Ancmrage (APAt 115 kV
(Approximate i n-sarv ice date 1982) tt
Station l -Station 6 1.7
Station 6 -Stat ion 11 Tap 1 .8
Stai"lon 11 Tap -Stai"ion 16 .8
Statton 16 .... Sta"tlon 15 3.1
Stat loo l5 -Anchorage (APA> .1
Totaf 7.5
Stat ion 11 -Sta-tion 1 t Tap 3.0
S-tation I -Station 2 CAPA) 1 lS -k¥
(Approximate i ~service date 1982)tt
Stat ton 1 ... S-tat ion 14
Stat ion 14 -Stat ion 17 Tap
Sta'tfon 17 Tap -Station 2
Total Statlon t -Statton 2
. . . .. ttt Stat ion 17 Tap ""' Stat 1on 17
Station 11 -Ancl:nraga (APA)
Total
1.6
~9
3o0 -5.5
1.0
.. a -1.8
?B1 ACSR (26/7) .. 01134 .. 03087 o00456
397 ACSR (26n> .00124 .00338 .00050
397 ACSR <26/7) .00356 .00973 .. 00144
397 ACSR (26/7) \J00377 .01030 .00152
· 39 7 ACSR (2.6/7} .. 00156 .00427 .,00063
397 ACSR (26/7) .00634 .01733 ... 00256
397 ACSR (26/7) .00025 .00068-.. 00010
?B1 ACSR (26/7) .00613 .01680 .00248
397 ACSR (26/7) .00336 &00918 .00135
397 ACSR (26/7) o00187 .. 00512 .00076
397 ACSR (26/7) .00630 .01712 .00253
397 ACSR (26/7> .00210 .00574 .. 00085
397 ACSR (26/7> •. 00165 .00450 .00066
* Posttlve sequence impedance in per unit on 100 MYA base.
** Total 11 ne charging susceptance tn per unit on 100 MVA base.
***Zero sequenca tm~dance ln per uniT on 100 MVA base .•
t Normally no power ·exchange to military system.
tt Rebuttd and CQnverslon of existirg 34·5-kV cf.rcuit' to 115 kV ..
tt+station 17 is scbaduled for installation fn 1985. Sntlon 17 -Statton 17 Tap
wt II be operated nonnally open.
B - 3
Zero Seq
I mpedanca***
Ro Xo
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I
:.1
I
.-~1
I
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·I"
'I
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Substation-Transformer
TwO: WTndi ngTransformers
Station l -1
Statton 1 - 2
S.'ta'tlon 1 -GSU
St~'tlon 1 -GSU 2
St~'tion 1 -GSU 3
Stai"lon 1 -GSU4
Sta-tton 1 -GSU Diesel
Statton 2 -GSU 5
S:tation 2 -GSU 6
StaTion 2 -GSU 7
TABLE 81.4: At-CHORAGE MUNICIPAL UGHT AND POWER
TRANSFORMER DATA
Voltage Ratlns Tap SetTing Tap Range . .. ' <kvr·---(MVA>
115/34.5 28/37/46
l15/34.5 28/37/46
13.8/34e5 12
13.8/34.5 12
13.8/34.5 12
13.8/34o.5 21/25/28
2.4/33 3.75
13.6/115 30/40/50
1.3~ 8/115 30/40/50
13.2/115 44/.?9/74
*~ransformer reactance in per uglt on tOO MVA base.
B-4
Reactance*
.2893
.2893
•. 5833
.5833
.5000
.2810
2 .. 0373
---.2£33
.2267
.1528
I --
-1
I
I
I
I
I-
I
I
Subs-tation
Central buslne~s district*
12 kV substations**
Total
TABLE 81.5; A!'CrPRAGE t·1UNIC1PAL LiGHT AND POWER
'D!STRfSUTIOO SUBSTATJOO DATA
EX l STING AND PLANNED FAC I Ll Tl ES
Volta.S!
(k.V)
34~5/4.2
l t5/12.5
-
-Load***
(percent>
31
69
100
* The centra I bust ness d i si"r i ct J s supp I i ed fran gener'Clt i ng Station
34.5-kV bus via a number of 34.5/4.2-kV -substations.
** Sta'tions 6, 11, 14, 15, 1.5 and 17 are 115/12, 5-KV substations.
Substatton 17 ls scheduled for instatfatJo·a in 1985. The 12-kV load
ls equally divided among the 12-kV sub$tations.
***The percentage oi I oad supp I t ed at 34., 5 and 12. 5 kV 1 s expected to
r~nain constant.
B-5
"···
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;I
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1974/19TJ
1975/1976
1976/1977
1977/1978
1978/1979
1979/1980
TABLE BT.6; ANJiiORAGE '1UNICIPAL liGHT AND POWER
HISTORICAL SYSTEM PEAK .DE~OS ..::0
Peak Demand
(MW)
82.8
89.,5
93a4
101.5
109.0
111.5
B-6 ..
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,, •.
I
TABLE _82.1.: .. ~H~ACH ELECTRIC .ASSCCIATION, t~ ..
EXIST!NG AN& PLANNED GENERATI.NG CAPAClTY
Year of
Unlt Installation Oaeacit~
Beluga -Unit 1
Beluga-UniT 2
Beluga -UniT 3
Beluga -Uni"t 4
Beluga -Unit' 5
Beluga -Unit 6
. Be I uga ... Unit 7
Be I uga -Un r t 8
Bernlce Lake-Uni+ 1
Bernice Lake -Un ii" 2
Bernice Lake -Un.i 't 3
Cooper lake -Unl"t 1
COoper Lake-Unit 2
· tnterna'tional -Unit 1
InternaTional -UniT 2.
lnterna"tionai -Unit 3
Knl k Arm -TGS
Kni k Arm -TG6
Knlk Arm -TG7
Knt k Ann -TGS
Total available capacity
1982
Abbrev i at ions: GT -Gas Turb f ne
ST -Steam Turbine
GT
GT
GT
GT
GT
GT
GT
ST
GT
GT
GT
Hydro
Hydro
GT
GT
GT
ST
ST
ST
ST
J5 .... 7
CMW)
16.5
16.5
54 .. 6
9 .. 3
6.5.5
67.8 } 68.0
62.0
8~85
18.95
29.60
7.5
7.5
14.0
14.0
18.58
3 .. 0
3.0
3.0
s.o
493.18
Base load
Base loa<l
Base load
Je't e~(ne
Base toGd
Combln.eq eycle-
base loat
Base load
•••
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••
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TABLE 82.2: CHUGACH ELECTRIC ASSOO IATION~ 1-tc.
Uitit
Be.tuga -Uni-t 1
Beluga -UniT 2
Beluga ,_ Unit' 3
Sal uga -Unit 4
Beluga -Uni.i" 5
Be[uga -Unit 6
Beluga -UniT 7
Beluga -UniT 8
Bernice Lake-UniT l
Bernice Lake -UniT 2
Bernice Lake ... UniT 3
'
Cooper lake -~niT 1
Cooper Lake -Un i 1" 2
International -Unit 1
Interna-tional -Unit 2
InTernational -UniT 3
Knlk Ann-TG5
Kntk Arm -TG6
Knlk Arm -TG7
Knik Arm -TG8
••
VolTage
CkV}
13.8
13.8
13.8
13.8
13.5
13.8
13.8
13.8
24.9
13.8
13.8
39.8'
39.8
13.8
13.8
13.8
4.2
4 •. 2
4.2 0
4 •. 2
Rating
<MVA)
18.824
18.824
57.0
10.0
68.889
as.o
85.0
68.889
9.375
20.65
29 .. 60
8.33
8.33
n. 647
17.647
19.200
3, 1'5
3. 75
3.75
6.25
*. lmpedance tn per uniT on tOO MVA base.
GENEP.ATOR DATA
Power
Factor
.90
.90
.95
.90
.95
.so
.so
.90
.95
.90
t.oo
.90
.90
.so
.so
.95
.. so
.so
.so
.ao
Generator lmoedance*
Xd X'd X"~ Xz -
1.59 .58
1.59 .58
2.87 .28 .18
2.87 e28 • 19
2.54 .33 .21
2.54 .33 s21
2.44 .23 .16
16.00 3.73 2.13
8.96 _.,82 .53
6.31 .65 .43
3. t 1 2.16
3. 11 2.16
10.65 1.02 • 71
10.65 1.02 • 71
S•74 1. 74 1.24
6.00
6.00
6.00
3.40
** 1 nert fa consnmt" i n per uniT on too MVA base.
B-8
tnertla
Constant**
.34
t .. a6
2.l9
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·_ .•
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TABLE 82.3: CHUGAQi ELECTRIC ASSC.ClATlON, HC.
Tran$mlssfon Circuit -VolTage
From Bus -To Bus
Beluga --Pt MacKenzie 230 k.V
Beluga·-Pt MacKenzie Ckt 1t
B~~uga -Pt MacKenzie Ckt 2t
Beluga -Pt MacKenzie Ckt 3tt
Length
(mi)
..E!J:!'ad<enzie -University 230 kvttt
Pt MacKenzie -West Termi.nal
Submarine cable
East-Tennt nal -Untvers iTy
Totals
International -University 138 kV
I nternaTlonal -Un ivef'$ i-t-y
l nternat f ona I -. Pt Woronzot 13~
I nterna1t ional -Pt Woronzof Ckt I
I nterna'tfona I -Pt Woronzof Ckt 2
Pt MacKenzie -Teeland 138 kV
Pt MacKenzie -Teeland
Pt MacKen:z I e -Pt Woronzof 138 kV -
Cables 1 to 4
Cable 5
Cable 6
Cables 7 to 10
Bernice Lake -Soldotna (HEA> 115 kV
Bernlce Lake -Soldotna
TRANSMISSION Lf.NE DATA
EXISTING AND PLANNED FACILITIES ·
Conductor
795 ACSR
795 ACSR
79? ACSR
954 and 795 ACSR
1,000 Kanll-Cu
954 and 795 ACSR
795 ACSR
B-9
Pos Seq
lm~dance*
R X
Susceptance**
BC
.0094 .0627 •. 1216
.0094 .0627 .. 1216
.0094 .,06Z7 .12i6
•
.0016 .otoa o0220
.ooto .0056 .0004
.0037 .0266 .0536
.0063 .0430 .0760
.0048 .0189 .0054
.0038 .015i .0538
.0038 .0151 .0538
.,
.0176 .1066 .0264
.0030 o0041 .0562
.0035 .0045 .1034
.. 0035 .0045 .1034
.0086 .0034 .2800
.0310 .1390 .0156
Zero Seq
impedance***
Ro Xo
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I
Table 82.3: Chugach Electric Association, lnc.
Transmission Line Data
Exisi"tng and Planned Faci l fJl ..... es;;;,.-..... ':"..-2 __ _
Transmission Circuit'-Voltage
Fran Bus -To Bus'
Soldotna -Quartz Creek 115 kV
So I dotna -Quartz Creek
Quartz Creek -U n i ver_!i;~ ty 115 kV
Quartz Creek -Daves Creek
Daves Creek • Hope
Hope -Por-tage
Portage-Girdwood
Gi.rdwood -Indian
Indian-University
Length Conductor
(mi)
Bernlce Lake -Soldotna <HEAl 69 kV
Bernice Lake -Kenai
Kena~ -Soldotna <HEA>
Cooper Lake -Quartz Creek 69 kV
Cooper Lake -Quartz Creek
Hom9r {HEAl -Soldotna CHEAl 69 kV
Homer CHEAl -Kasi I of (HEAl
Kasilof CHEAl -SoldoTna (HEA)
Soldotna CHEAl -Quartz Creek 69 kV
Soldotna CHEA) -Quartz Creek
* Posit'ive sequence l_mpedance i'n per unit on 100 MVA base.
Pos SSq
f rneedance* Susceptance**
BC R X
• 0684 0 • .3070 •) 0371
.0184
.0215
.0250
.0140
.0136
.0210
.2300
.. 0133
.0218
.6350
.0827 .Q108
.0964 .0125
.1124 ~0146
.0627 .0082
.0610 .0079
.0941 .0122
.3250 .• 0051
.1040 .0016
.0863 .0015
.8980 .0129
** Total It ne charging-susceptance in per un 11" on 100 MVA base.
***Zero sequence impedance In per uniT on 100 ~fVA base.
t Existing 138-k.V clrcutts are being relnsulated to permit operation aT 230 kV ..
approximate -in-service date-1981.
tt A thfrd 230-kV circuit bet ng addeh approximate i n-servfce date-1981.
tttApproxlmate in-service date ... 1982.
Abbreviation; HEA -Haner Electr.ic Assoeratlon
B -10
Zero Seq
Impedance***
Ro Xo
"
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I
TABLE 82 •. 4: CHUGACH ELECTRIC ASSOO JATIO~., It-e.
TRANSFORMER DATA:
EXISTING AND PLANNED FACILITIES ___ ...;;;;..;.;.,o;;.;..;.;;.;,;;....;..:;.;-....;..;;;;;..;.;.;,;~....,.;..;..;;;;.;..;;;..;..;~----.•
Substation -Transformer Voltage Ratln9
(kV) (MVA)
.Be I uga-1 ** 230/138 180.1240/300
Befuga-2** 230/138 180/240/.300
Pi" MaeKenzie-1** 230/138 180/240/300
?t ~1acKenzi e-2** 230/138 180/240/300
Uni ver~sfty** 230/138 180/240/300
Tea lard 138/115 45/oons
Untversity-1 138/115/34. 5 45/60/75
University-2 138/115/34.5 45/60175
lnternational-1 138/34.5 12.5
lnternational-2 138/.54.5 125
Bernice Lake t 15/69 33.6/44.8/56
Soldotna (HEA) 115/69 32.6
Quartz Cteek 1-lS/69 12/15
Beluga-GSU t 13.8/138 16
Se1uga~U 2 13.8/138 16
Be. I uga-GSU .3 13.8\/138 48.8/65/8 t. 3
Bel uga ... GSU 4 13.8/138 12/16
Beluga-GSU 5 13.6/138 45/6ons
Beluga-GSU 6 13.8/138 48.8/65/81.3
Se.l uga-GSU 7 13.8/138 45/64/80
Beluga-GSU 8 13.8/138
Bernt ce La ke-GSU 1 24.9/69 5
Bern i ca La ke-GSU 2 1.3.8/69 23
Bernice Lake•GSU 3 13.8/69 20.4/27..,2/34
Cooper Laka-GSIJ 39.8/69 20
lnternationai-GSU t 13.8/34.5 12/16
I nterna'tt•-,na 1-GSU 2 i 3.8/34.5 11.25/15
1 nternat1onal-GSU 3 13.8;34.5 12/16/20
Knik Arm-l 4.2/34.5 5
f<nik Arm-2 4.2/34.5 5
Knlk Arm-GSU 8 4.2/34.5 6 •. 25
·'*'Transformer 'lmpadance ln per unt·t on 100 MVA base •.
**ApproxImate f ,..service date 1981 to 1982.
Abbreviations: HEA -Homer El e\:trlc Association
B -11
l meedC!Ince*
Tae settfM Jae Range R X
o0020 .0222
.0020 .0222
.0020 .0222
.0020 .0222
.0020 .0222
(V1805
(ZH=-j.0245., ZL =j.2045. Zr=j. 1712)
<Z.tt'j.0276~ Zt_ =-J.0036~ Zr=j.l194)
.0073 .0880
.0073 .0880
.2972
.1333
.3420
.. 0450 .6780
.0440 .6640
.ouo .1600
.0450 .6780
.Ol40 .2040
._"Ol4Q .1650
•. 009 1.3600
.043 .5170
.3889
•. 0310 .4600
.5000
.5510
.5000
1.2200
t. 2200
.9600
I
I
I
I
I
I
I
I
I
·.··.1'
. f
',,•'
I
I
• : • • • ••• • • <> : • • • ·: •• : .: ~ < -:-';.. _ ... · ... - . . _: . ' . . ' . . ' . : ' ..
Substat-ion
Anchorage Area
Supp.l led vfa tnternationai
Substation aT 34.5 kV
Arctic
Blueberry
Campbell
Jewel Lake
Klatt
Sand Lake_
Spa nard
Tudor
Tur-nagain
Wood I and Park
International Subtotal
Suppl i ed via Un iverslty
Substation at-34.5 kV
Bon trace
DeBarr
Fa I rv lew
Huffman
Mt Vtew
0 'Malley
Unlverslty Subtotal
TABLE 82.5~ CHLGACH ELECTRIC ASS~ IATlON$ It-e.
0 ISTRIBUTlON St.BSiATHJN DATA
EXI-STING SYSTEM
Transformer
Vof'taae
(kV)
341) 5/12.5
34.5/12.5
34. S/12. 5
34*5/12.5
34.5/12 .. 5
34.5/12.5
34.5/12.5
34.5/12.5
34.5/12.5
34.5/12..5
34.5/12.5
34.5/12.5
34. 5/i2.S
34.5/12.5
34.5/1A5
34.5/12.5
Rating
(MVA>
14.0
14.0
14.0
tT.2
14.0
14.0
io.o
14.0
5.0
21.0*
131.2
14.0
25.2'*
3.8
17.8*
12.0*
i4.0
86 •. 8
Percent
of Total
46
30
Suppl ted via Beluga Substation
· Tyonek
Tyonek Timber
Beluga Subtotal
24.9/12.5
24.9/12.5
3.8
8.4
12.2
B -12
4
0
I
:1
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:1
I
:1
I
I
. I
I
Substation
Kenai Peninsula
Daves Creek
Girdwood
Homer
ibpe
Indian
Kasilof
Kenai
Portage
Soldotna
Kenai PenInsula Subtotal
TOTALS
Tabla B2.S: Chugach Electric Association, Inc.
D f str I but I on Substation D~ta
Existing System-2
Transformer Percent
Voltage Ratfna of Total
(kV) CMVA>
115/24.9 14.0
115/24.9 11.2
69/24.9/12.5 3o8
115/24.9 3.8
115/24.9 ·2.3
69/24.9 3.8
69/33 1.5
115/12.5 2.8
69/24.9 7.5
56.7 20 -
286.9 tOO
*T~iaJ MVA capacity of two transformers •
B -13
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I'
I
I
.~-
1
I
'I
I
Unft -
Chena 1
Chena 2
Chana 3
Dfesel Dt
Diesel D2
Diesel 03
Gas Turbine 4
Chana 5
Chana 6
TABLE B.3el: .FAIRBANKS MUNICIPAL UT JLJTY SYSTEM
EXISTING GENERATJNG CAPACITY
Year of
Installation
1954
1952
1952
1967
1968
1968
1963
1970
c
1976
ST
ST
ST
Diesel
Dtesef
Diesel
Gr
ST
GT
Nameplate
Capacftt_
( f.t.i)
5,.00
2.00
1.50
2.75
2.75
2. 75
5;.25
20.00
23.10
Total Avaf fable C!pacity 65. 10
..
B ... 14
Coal
Coal
Coal
Oi I
Coa I -Base I oad and
di str Jet haathg
Oi f
I
I
I
Unit
Chena 1
Chena 2
Chena 3
Diesel 1
Diesel 2
Diesel 3
Gas turbine 4
Chana 5
Chena 6
TABLE 83.2: FAIRBANKS .\1UNICIPAL UTILITY SYSTEM
GENERATOR DATA
Voltage
CkV}
4.2
4.2
4.2
12.5
12..5
12.5
12.5
12.5
12.5
Rat' I ng
CMVA)
6.25
2.40
1.80
3.44
3 •. 44
3.44
6.25
25.10
29.00
Power
Factor
.85
.as
o85
.so
.so
.so
.so
.as
.as
Generator Impedance*
-
23.,36 2.50 i.47
55 .. 00 7.aa 4.13
75.00 12.33. 6.39
6.63 4.,54
6.63 4.54
s. 6.3 4.54
6.24 3.68
1.08 .66
.73
* Impedance in per uni-t on 100 MVA base.
**I nertta constant In per uniT on 100 MVA base~
B -15
lnert-ta
Constant'**
I
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:··1
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tABLE 83.3: FAIRBANKS MUNICIPAL UTILITY SYSTEM
TRANSMISSION Lt NE DATA
TranSlllfssion Circui-t-Voltage
Frcrn Bus -To Bus
Chana -Zehnder CGVEA)
69 kV t nterconnectlont
EXISTING AND PLANNED FACILITIES
Length
CmO
Conductor
Pos Seq
I rnpedance*
R X
S uscep"tance**
BC
Chena -Zehnder .a 336 ACSR (26/7) .0047 .0120 .0002
Chen a -SouTh FaIrbanks 69 kV
<Approximate In-service dafe 19aztt
Chana -South Fairbanks 3.0 336 ACSR (26/7 l • 0175 • 9451 • 0006
* Positive sequence Impedance t n per un ii" on 100 MVA base.
** Total trne charging susceptance In per uni-t on 100 MVA base.
***Zero sequence Impedance fn per unit on 100 MVA base •.. -,.-Metered~ at Zehnder.
tt Esi"Tmated da1·e.
B-16 -
Zero Seq
I mpedc:ince***
Ro Xo
.0095 • 0472
.0355 .1no.
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I
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I
I~
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I
.I
I
I
I
••
I
I
••
TABLE 83.4: FAIRBANKS MJClPAt. UTJLJTY SYSTEM
TRANSFORMER DATA
EXl STING AND PLANNED FAC I LIT 1 ES
Substatlon -Transformer Volta92 Rating*
(kV) CMVA)
Two Winding Transformer
Chena-• 69/12.47 12/16/20 I
C!lena - 2 (1982)*** 69/12.47 12/16/20
South Fairbanks <1982>*** 69/12.47 12/16/20
* ConTinuous ful f load rating at 65"C rise.
** Transfonner reactance fn per unlf' on 100 MVA base •
***Approximate i n""'serv ice date.
Abbreviatfon: LTC -Load Tap Changing
B -17
Tae Setting
LTC
L'TC
LTC
Tae Rance Reactance**
.6250
.6250
.6250
lc
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I
--·-·
TABLE 83.5: FAIRBANKS MUNiCIPAL liT ILITY SYSTEM
HISTORICAL LOAD DATA
Historical Peak Demands <MW)* . . Substation _!ol tage
CkV}
1975 1976 1977 1978 ---
Chena 12.47 and 4.16 27"2
*Historical load power factor-• 95
**f980 maximum demand through June 1980.
25~0 27.6
B -18
1979
25.3
1980**
~
25.2.
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I
'TABLE 84.1: GOLDEN VALLEY ELECTRIC ASSOOIATION, H'4C.
EXISTING GENERATING CAPAC·JTY
Healy -51
Healy -01
NQrth Pole -GTl
North Po I e -Gr2
Zehnder -Grl
Zehnder -GT2
Zehrrler -GT3
Z-ehnder -GT 4 ·
Zehnder-0
Zehnder -0
Zehnder -4 units
Year of
t nstal Jation
1967
1976
1977.
1971
1972
1975
1975
Total Av.al (able Capacity
* Capacity ;:-t" t:s1"fmated power factor -,.eo.
**Carib i ned capacity of 4 units.
Abbreviations: ST-S-team Turbine
GT -Gas Turb f ne
ST
DLasal
GT
GT
GT
GT
GT
Diesel
Diesel
Diesel.
B --19
Capacit'L_
(MWl
25.00
2. 75
60.50
60.50
18.40
18.40
2.80*
2.80*
2;28*
2.28*
10.64**
206.35
Remarks
Coal base Joat uni-t
Peaklng unit
Peaki ~ uni-ts
' . ..i. '•-.. . : • . -. . ~ .~ &~ -."' : ' ... ' ... , ...... -• • 1 .
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TABLE 84.2: GOLDEN VALLEY ELECTRIC ASSOOlATION, INC.
GENERATOR DATA
UniT Voltage
( kV)
Power
Factor
Generator I m,eede1l,.ce*
Healy -S 1 13.8
Healy -Dl 2.4
North Pole -GT1 13.8
North Po 1 e -GT2 13 .. 8
Zehnder -GT 1 13.8
Zehnder -GT2 13.'8
Zehnder -GT3 4.2
Zehbde r -GT4 4.2
Zehnder -0 4.2
Zehrder-D 4.2
Zehnder -4 Units 4.2
Rai"Jng
CMVA)
29.4
3.5
71.9
71.9
20.7
20.7
3.5
3.5
2.9
2.9
3.3
~as
~80
.90
.90
.85
.85
.ao
.so
.so
.so
.so
* lmpedance fn psr unit on tOO MVA base.
**Inertia constant tn per unit on 100 MVA base.
6.086 • 731 5.10
23.190 8.700 5.220
2.866 "285 .185
2.932 .284 .185
8 .. 959 ·•823 .533
8.959 .823 .S33
32.86 4.29 2~86
32.86 4.29 2.$6
63.86 16.84 11.23
63.86 16.84 11.23
24.02 9.00 5.40
B -2o
,510
5.507
.177
• 172
.484
.484
3. 71
3.71
8.42
8.42
5. 70
.170
1.449
• t07
.104
.315
.315
1. 14
1. 14
4 •. 21
4.21
1.50
Inertia
ConsTant**
.sa
5.62
$.62
1.86
1.86
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TABLE 64.3; GOLDEN VALLEY ELECTRIC ASSOCIATION, JtC,.
Transm i S$icn Circuit ..;; Vo!,tage
TRANSMISSION LINE DATA
EXISTING SYSTEM
Pos Seq·
Impedance*
;l.ero ~q
Susceptanc~** J_mpedance***
From Bus -To ars Length Conductor R · X .EC i=t0 X0
Healy-Gold HlU 138 kV
Gold Hi II -Nenana
Nenana -Hea!y
Total
(mil
47.0
56.2
103.2
North Pol,e -For-t Wainwright' 138 k.V
Fort Wainwright -North Pole 12.3
North Pole -Hishway Park 69 kV
Highway Park-North Pole 2.3
Zehnder -Fort Wainwright 69 kV
fort Wainwright -Ham i I ton Acres 2. 9
Zehnder-:~Fox 69 kV
fox -Steese. 5. 7
Steese -Zehnder 2.4
Total 8.1
Zehnder -Gold Hill Double Ci rcult-
69 kV CZ mutual = .0060 + j.0431
peo mile)
Gold Hill -Musk Ox Tap .8
r.bsk Ox Ta.p -U of Ak 3.5
University of AK -University Ave· .3
University Av.e -Zehnder . 2.6
Totaf
· Musk Ox -Musk Ox Tap
Got d Hi l f ... Chena Pf..iil1l Tap
Chena Pump Tap -Airport Tap
Alrpert 'TaiJ "" Zehnder
Total .
7.2
2.!
1.5
3.6 -
556 ACSR (2Gn>
556 ACSR (26fl)
195 ACSR (26/7)
.0415 • 1963
.0496 .2349
..0075 .0489
-
.0475
.0569
.0130
4/0 ACSR (6/1) .0269 .0478 .. 0008
336 ACSR (26!7) .• 0330 .0826 ... 0016
336 ACSR (26/7) .0141 .0352 .0007
336 ACSR (26/7)
336 ACSR (26n>
336 ACSR (26/7)
336 ACSR (26/7)
336 ACSR f2.6nl
3~5 ACSR C26/7)
336 ACS.{i .. C2o/7)
3)6 ACSR {26/7)
B """ 21
.. 0046
.0203
.0018
.01.53
.0309
.0121
.0091
.0208
•. QU<J . .-0002.
.0510 .0010
• 0044 =.0001
.0384 ,0008
.0798
.0303
.0227
.0522
.0015
.. 0006
.0004
.0010
.1120
• 134 t
.0259
.6311
.1552
.1650
.0195 .1331
.0442 .1743
.0669 .3381
.0285 ~1442
.0092
• 0412
.0036
.OJctO
.0628
.0245·
.0184
.0422
.0466
.2080
.0179
.1566
• '1237
.0926
•. 2128
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Table B4. 3: Go. I den Val I ey Electric Assoeratlon, Inc.
Transrrifssion. Une Data
Existing Sys'tem -_2
Transmission Cireuft -Vol'tage
Fran Bus -To Bus Length.
(mil
Conductor
Pos Seq
l!!t..aadance*
R X
Susceptance**
EC
Zero Seq
Impedance***
Ro Xa -
Chana Pump -Cnena Pump Tap .4 336 ACSR. (26fl) .002'. .006.1 .0001
! nterna'tfonal Ai.rporf -Airport 1.5 336 ACSR (26/7} .ooaa .-0226 .0004 tap
For't Wa l nwr i·ghi" ..: H i'ghway Park 69 kV
Fori' Waf nwr ight -Fori" W ~n .5 4/0 ACSR (6/l) .0047 "'0083 .0001 Fort W Gen -Badger Tap 6o7 4/0 ACSR <ollJ .0622 .tl03 .0018 Badger .Tap -Broclanan Tap 2.3 4/0 ACSR (6/l) .02JJ :•.9378 .0006 Badger Tap -Highway Park 3.0 4/0 ACSR (6/1.) .0280 ,.0497 .ooo8 ~·
Total 12.5
Badger Road ,. Badger Tap 1. 0 4/0 ACSR (6/l J
:. :;.:..-·." .0093 .0164 .0003
Stockman -Broc[qnan Tap 336 ACSR (26/7) .0368 .0.948 .0012
Fori' Wajnwrlgh"t-Pager Road 69. kV
For"t Wainwright-.;;._ S Fairbanks
S Fairbanks -Peger Road
Total
1.2
3.2 -
4.4
Highway Park -Jarvis Creek 69 kV
Highway Park -Newby Road 4. o
Cfuture>
Newby RQad (future)--Etelson AFB 9.,4
S:i el son AFB -Johnson Road 9.5
Johnson Road ... Carney (future) 6. 5
Carney .(future) -Ja~vis '~tt 52.6 -
Total 82.0
336 ACSR (26/7) .0070
336 ACSR (26/7) .0185
4/0 ACSR (6/t l .0374
4/0 ACSR (6/1) .• 0874
4/0 ACSR (6/1) .ossa
336 ACSR (26/7) .0380
556 ACSR (26/7) .. 1856
* Posit Iva sequence Impedance in per un 11" on 100 MVA base. ** To-tal It ne charging. suSc&ptance. fn per unit on-.100 MV~ base.
***Zero sequence impada·nce in per un tt on 100 MYA base.
f ESTimated data.
-:t-t-ca-rney < ft.ittre)-Jarvls Creek rs constructed to 138-kV standards •
. tttca rney ( future)-Jar\. is Creek fs converted to T 3'8-k V ope taT ion.
.OlSl
.0476
.0563
.1551
.1575
.0978
.8624
.0003
.. 0009
.0011
.0025
.0026
.0018
.• 0136
.0178
~" .0077
IIi 1()21
.0350
.0451
.Qt52
.0145
.Qt42
.0374
.. 0614
.1436
.1459
.0770
.sot a
.Q23.4
.osss
.-03o3
·4024
.uao
.. 1815
.0708
.1864
.2420
.5658
.5749
.3834
2.8579
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••••
. .
I
• • • , ', •• 1' f. • . -
/ /
/ i
TABLE 84.4: GOLDEN VALLEY ELECTRIC ASSOC1AT10N; HC.
Transm.ission CircuiT ... Voltage
TRANSMISSHi,,~ LINE DATA
PLANNED FACILlTIESt
Pos Seq
l~eeaanca*
From Sus -To Bus length Conduct-or R X
(mi)
Peger Road -Interna-tional Alrport" 69 kV
{~~pproxirna"te 1 neservice date-1981)
,
InternaTional Airport-Pgger 3
Road
North Pole-Gold Hi II 138 k.V
.,mperoximate i'n-service date -1984)
Go.l:d Hi It -North Pole-OH 21
..UG .J..
Total 22
North Pole-Jarvis Creek 138 kV
<Approximate ln-servrce date-1984)
. -
· North Po J e -Garney
Carney -Jarvis. cKttt
Total
Ben-t! y -Fort Wainwright 138 kV
72.6
, <Approximate in-service date -1992)
Sentry -Fort Wainwright 16c.2
senti)t-Gold Hi I l 1:38 kV
(ApproxHr.ate i n-servfce date -l992l
Bently .,. Gold HilI 9 • .5
336 ACSR (26fl) . -
556 ACSR (26fl l .0192 .0902
556 ACSR C26n) • 017.5 !t 0820
556 ACSR {26fi) .0464 .2156
795 ACSR (26/7)
795 ACSR (26fl l
* PosiTive sequence impedance fn per unl"t on 100-MVA base. ** To'ta! I Ina chargJ ng sysceptance ln per unfT on 100-MVA base.
~**Zero sequence impedance in per uniT on 100-MVA base.
t Estimated data •
tt Carney ( futura)-Jarvls Creek is constructed. to l3&-kV standards.
tttaarney ( future)-Jarvis Creek is converted to 138-kV operation.
B-23
Zero Seq
Susceptance** 1 mpedance***
8C R0 X0
.0326
.0206
.054.2 • 1254 • 7145
·.
'·
I?
I
•• ..
I ,,
••
I
I
I
·'.1·" .. ·· ' -~
I
I
TAB~ 84.5: GOLDEN VALLEY E;lECTRIC ASSOO!AtlON, ftC.
· TRANSFOIV-1ER DATA·
EXl ST J NG SYSTeM,
Substation-Transformer VoltaS! .8.'!!1.!19.* rae Settt.'!S,
CkVJ <MVA)
Autotransformers
.
Fort Wain"--'right-FWSt380T1 138/69 60/80/100 138 ·ooo
Gold Hl ~ l-t~l380Tl 138/6~ 18/24/30 i34 550
Go.ld Hi I J-GHS0090T2 69/34 .. 5. 1. 725 69 000
Two Winding Transformers
...: ;:~.~~· ·-·. ~
Hea I y-HLP1380T l 138/13.2 18/i4/30 134 550
Healy HLS138drt 138/24.94 10/12.5 138 000
Healy 24~912.4 5 24 900
North Aola-NPS1380Tt 138/13.2 45/60fl5 138 ooo
North Po I e-NPS' J80T3 138/13 .. 2 4SJoons 1.38 000
North Poie-NFSQ690T2 69/13.2 36/48/60 69 000
Zehnder-T4 \GSU-GTl) 69/13.8 12/16/20 69 000
Zehoder-T3 (GSU-GT2l 69/13.8 t~/16/20 69 000
Zehnder-T6 69/4.16 7.5/9~4 69 000
Zehnder-T5 69/4.16 7.5/9.4 69 000
* Cont 1 nuous fu I I . load :rat i ng a~ 65 OC rise.
**Transformer rE)actanee in per uni-t on 100-MVA .b~s~.
~~ap range:. 144 900, 141 450, 138 000., 134 59'0, 131 100.
t Tap range: 12 450~ 70 12;, 69 ooo, 67 275., 55 sso.
tt Adjus-ted 1'o base of 13.8 kV frc::m nainepl ate base of 13.2 kVo
Tae RaP$
***
*** t
***
***
*** ***
t
Reactance**
.080()
.2194
~ .. 1933
.3802tt
c·..a.~J:~-=~.o;.~.··
1.0940
.l484tt
• l4841t
.2o941"t
.5760
.6780
.9470
.9810
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. '
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TAB(..E 84.6: GOLDEN VALLEY ELEC1RlC ASSOO IATIONp HC.
Substation-Transformer Vol'tase
(kY)
Autotransformers
Carney-l984t 138/69
Bentley-1992t 138/69
* Estimated data ..
TRANSFORMER DATA
PLANNED FACILITIES* .
Rat1 ng** Tae SeTting
CMVA)
30/40/50 138 {)00
138 000
** Coni"tnuous ful t load rating at 65°C .rlsao·
***Transfonner reactclnce.,_cJn per unit ort 100-MVA base.
· t Approxlmate in-seNica date. ,
tt Tap range: 144 900, 141. 450,. 1:'S8 ,ooo, 134 550, 131 too.
B -2.5
(•.
Tae Ran!!!
tt
tt
Reactance***
.1500
11
~:·
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I
I
I -., ....
. .
. .s ..~..: .,~.. .. •
XABLE 84.7: OOLOEN VALLEY ELECTRIC ASSOCIATION, lte.
DrSTRIBUTION SlBSTATHl4 PATA
EXJ ST 1 NG SYSTEM
TnJnsfo~r!!-_ Noncoincldent Substaitlon Peak Demand Readinss <~>
Substation Voltage Rat ins** 1975 1976 1977' . ]9.7~ -~--~-· _ l97~_,_~----f98QX
CkV) {MVA>
Bagger 69/12.47 13~44 2.98 5.65
Brop!man 69/24.94 7.oo NIS N!S .
Chana Pump o9/t2.47 22.40 NIS NIS
Energy Company 13.8 *** NIS N.IS
Fox ------69/34.5 8.40 2.57 3.11
Gold Hirt++ 34.5 t ,.67 .81
HOOl i I ton Acres 69/12.47 22.40 NIS NIS
Healy 24 •. 94 tt na 1.15
Highway Park 69/12.47 14.00 6.45 7.33
I ntarnatlonaf 69/12.47 n.2o 12 •. 65 13.02
Airport
•'! ,,
Jarvis Cr!ii!ak+++-69x138/24. 94 22.40 NIS NJS
Johnson Road 69/24.94 8.40 4.64 6 .. 43
Mu.sk ox 69/12.47 14.00 NJS NlS
Nenana 138/24.94 3~12 Z21 2.00
Peger 69/12.47 13.44 . 6. fil Oe91
South Fairbanks 69/12 •. 47 u.zo n.o1 6.53
Steese 69/12.47 8.40 7.43 -7.67
Unfversfi'y Ave 69/12.47 7.azttt 8.76 9.1.6
Zehnder 69/12.47 11 •. 20 11.35 11.36
77 •. 45 81.13
Q
-·-----* l.oad tap changing 'transformer unless otherwlse noted .•
** t-1aximum naneplate continuous full load rattng at 65-°C :rtse.
***Supplied fr.an North Po.le 13.8-kV bus.
t Suppl led fran Gold Hi II 34.5-kV bus.
tt Supp( fed from Healy 24e94-kV bus.
tttMax imum rating of iwo transfonners l n para I I $! • *"
x 1980 maximum demand through July 1980
xx 3 months data.
xxx-5 months data.
+ 4 months data.
..
5.52 3.-84 4.80
NlS t.:soxx lo62
NtS 3. tzxxx -4.94
2.3s+ 2.05 2.23
2.06 2.61 2.72
.84 • 91 o.82
NIS 4.80 4.26
1.56 na 4.20
9 •. 22 6.71 . 5•40
10.68 9. 19 5.69
NIS NIS 6.48
8e~64 7.02 2.48
4.39 4.90 3.31
2.05 1.;34 1.80
5.28 4.60 5.28
7.30 --6.16 6.91
7.49 6. 19 4.90
7.39 5.69 4.25
13.18 1.2.53 7.63
88.55 83.16 --79.70
+t· Includes a demand of approximately 300 1<W at Murphy Dome supplied by Eielson AFB.
+++tncfudes a denan9 of approximate.ly 2.600 kW at Fort Greal.y suppf i~ fran Fort Wainwright.
Abbrevlatlons: "na ... rb data available.
NlS ~Not in service.
4.74
1.76
l-.72
2 •. 10
3..85
• .sz
3o.36
:s.as
5.66
5.42
6,.24
2.57
2.84
~'e94
5.16,
-~51
.:4_. 72.
4.25
6.98 -75.80
:Z''
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I .,
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=•
I
Substatfon
Newby Road
* :Est t mated data.
TABLE 84.8: OOLDEN VALLEY ELECTRIC Assm IATlOO$ ff.C.
D tSTR IBUTlOO St.BSTATI·Ct.f DATA
PLANNED FACILITiES*
. Transformer**
Voltage . Ra'ti f!a***
fkV> CMVIO
69/12.47 t2 CApproxfmate l n-servrce date-t984J
** load tap changIng Transfor~m~r un I ess othe~ise noted.
***Maximum nameplate continuous full load rating at 6.500 rise.
l3-27
cl 0
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I
.. :-:1'
I
Generatr no Untt
UnJvers ity of AI aska-Sl
University of Af aska-S2
Vnlverstty of AI asks=S3 c.
· University of Af aska-O 1
Un iversf1)i ot AI as ka-D2
Total Ava i I ab I e Capac lt"y
TASLE 85. 1_: UN IVERS lTY CF ALASK/\
6
FAIRBANKS
GENERATl.NG CAPACtTY AND DATA
Year of
Instal fation ~
ST
-------~-ST
SY
Diesel
Dtesat
Capacity-
(MW>
1.50.
~oo~--•=·cc:~· -:-• 1~.
f(4()(}
2.75
2.75
18.50
Unit -Voltage
{k\')
Rating
CMVA)
Power _Generator Impedance*
Factor xd X'd X"d Xz
..._._. ~
University .of Alaska.-S t 4.2 1.875 .eo 61.33 s.oo 5.33 6 .. 93 University of AJaska-SZ 4.2 1.875 .so 61.33 a.oa 5.,33 6.93 University of AI aska~,s3 4.2 12.50 .so 13 .. 80 1.,77 i.02 1 •. 02 University of Afasr~-Dl 4.2 3.438 _ .ao 23.27 8.73 .5.24 5.53 Un tversi ty of .Ai aska-D2 4.2. 3.438 .so 23.27 a. 73 5.24 5.53
--.--------;--~
0
I
I
I
I
* lnipedance in per unit on 100-MVA base.
**fner-tfa ccnstant in per unit on lOO.-MVA base.
'· :::'·c
I.
I
Abbrev fat.fon; Si -Steam Turb t ne
-
B-.2S
X 0 -
2.13
z. t3
0.34
'1.4!i
1.45
Remarks
Coal
Coal
Coal
, Inertia
Cons'tant**
1:,·
·-,
I
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'I
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I
••• • "
. '
I
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I·
.-.'
TAaL£ 85.2: . UNI VERSlTY Cf' ALASKA~ FAIRBANKS
TRANSFORt.'ER DATA
SubsTa.tlon-Transformer-
Two W l nd t ng Tra.nsf.ormsr
Un i~er~lty of Alas~-t
Voltage
CkVl
69/4.16
Ecrtine*
O.tVA)
7.5
* Cont'in Jus full load rai"ing at·ss-c dse •
**Tronsfonner-reactar.ce .in per unJT on 100-MVA base.
Abbrev l atlon:. LTC .. Load tap changing
Tap Setting Iay Range
LTC
Reactance.**
.893,3
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> ;;::;,'
TABLE 66., 1; Ml LITARY. INSTALLATIONS~ ~AeRBANKS J\.REA
GENERATING CAPACirr AND DAiA
Generat'lng Unlt'
EJ ef son Ar6-=S 1, 52
EJ el son AFB-53, 54
Fort Greely..O 1, 02, 03
Fori" Greet y-o4, 05
fort Walnwrlght-Sl, S2, S3, 54
To'tal AvaHable Capacity
··unit Voltage -CkV)
Eiel.son AFB-51, sz 7.2
Ei el son AFf3-S3,. S4 7o2
F9r't Greef y-o 1, 02, 03 4.2
fort Greely..U4, 05 4.2
Fort Wa i nwr lght-12.4
Sl, 52, 53, 54
Tyee
ST
ST
Diesel
Diesel
ST
Rating
CMVA)
3.124
6.250
1.250
' 1.563
6.25
* impedance ill per unit on. 100-MVA base •.
Power
·Factor
.a
1.0
.a
.a
.s.
Untt
Capae:lty ·
\MW)
2 • .50
6.25
1.00
1.25
s.o
Total
Caeacity
(MW)
5.0
t2. 5
3.0
z.s
20.0 -
43.0
Gener~tor Impedance*
39.3t5 5.44 2.86 2.88
18.41.) 2.40 .. 1.60 -2.08
64.00 24.00 ·14. 40 15.20
51.1.8 19.20 11.52 12.16
18.·40. 2.40 1 •. 60 2•08
**I nertla· coo~tant tn par unit on 100 MVA base.
Abbreviation: ST -Steam TuPbltte
··-~
:s -30
., '
•
lnertta
. X0 . Constan't**
0.96
0.64
4.00
3.20
0.64
..
I•··
I·
01
I
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I
:1.
I
~··
·.·;·
I
I
I
')
TABU: :86•2: Mlt.tTARY INSTALLATIONS, FAIRBANKS AREA
TRANSFORfER OATA
S ubstaT ton -Transformer
Two WInding Transformers
Eiel son AFB
ForT Greely
Fort' Wainwright
.Y,pltage
(kV)
69/1.2
24.9/2.4
69/12.~4
RaTil'ig*
tMVA).
5.6
,~:5
a.4
*Continuous full load raTing at 65t rise.
**Transfonner reactance ls per untt on 100-MVA .base~
Abbreviation: LTC ... Load tap eha.ng ing
Jae S~fting
LTC'
LTC
B ... 31
Reactance**
lo518
2.372
0.983
::::
• •••••
. -
,·
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I
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I
I
.: •.
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UniT -
Ekl ut'na -1 (APA)
Ek I utna -2 {.APA)
',; .
TABLE 87. 1: MATANUSKA E:LECTRlC ASSOCIATION ANO
ALASKA POdER AI:MJNlSTRATlON-
Year of·
I nstaf I ati on
EXISTING GENERATING CAPACITY-
Hydro
Hydro
,capacity
CMW>
15
15 --
Total Ava.i I able Capaci-ty .30
B-32
...
Remarks
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TABLE B7• 2: MATANUSKA ELECTRIC AS SOC IATl ON AND
ALASKA POWER ACMt NISTAATICN
GENERATOR AND TRANSFORMER DATA
Power Generator I meedance*
Unf't Voltage Ra-ting Fa.ctor xd X'd X"d --CkV) <MVA)
Ekiutna -1 {1\PA) 6.9 16.667 .9 6.12 1.65 1. 16
Ekl ui'na -·z <APA> 6.9 16.6.67 .9 6. 12 1.65 1. 16
Tap
Transfoi:'mer Voltage Rating Settlng,
(kV) CMVA)
Eklutna-·t (APA) 115/6.9
Ekl utna -2 (APA) 115/6.9 ...
?
* Impedance in per uni.t on 100-t·WA base.
**lnertla constant In per unit' on 100-t·\VA base.
lnert'ia
x2 Xo Constant'~*
1.41 • 78
1.41 .78
0
Tap
Ran9,!. Reac'tance*
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TABLE B7.3: MATANUSKA ELECTRIC ASSCCIATlON AM)
ALASKA PCMER ADMIN !STRATI ON
TRANSMISSION UNE DATA
EXJSTJNG SYSTEM
Pos Seq
Impedance* Transmission Circui 't-Voltage
FrQn Bus -To· B.r.s Length Conductor R X
(mi)
Anchorage {APA) -Ekl U'tna (AP'-l ns J<vt .
Anchorage CPPAJ -Briggs Tap (MEA)
Briggs Tap (MEA) -Pippel CMEA)
Pi ppel (MEA) -Parks <MEA>
Parks CMEA> -Reed CM:A)
Reed (MEA) -Ekl utna CAPA)
Total
Br fggs <MEA} ·-Briggs Tap CMEA)
Eklutna (APA) -Shaw {fJEA) 115 ~t
Ekl utna CAPA> -Do!.\' Tap (MEA>
Dow Tap CMEA) -Lucas CMEAJ
Lucas ( tJ£A > -LaZe I I e Tap C MEA)
LaZe I I e Tap-01EA) -Shaw <MEA)
Total
Dow (MEA} -Dow Tap (MEA)
laZe II e -LaZe I fe Tap
Shaw CM:Al -Teeland CCEA> 115 kV
Shaw CMEA> • Herning C!-1EA >
Herni ng (MEA> -Teela:rd CGEA)
Total
8.8
5.0
6$4
6.0
7.2 -
33.4
6.3
8.6
5.1
4.3
4.3 -
22.3
1. 2
3.9
4.8
7.8 -
12.6
Douglas CM:A~}: o""'! Tee I and CCEA) 115 kV
Doug I as (MEA) -And erso111 Tap (MEA) 19.0
Anderson Tap CMEA) -Tet!lani CCEA) .. 6.5 -
Total 25.5
397 ACSR (26/7) .0156 .0528
397 ACSR (26/7) .0089 .0300
397 ACSR (26fl) .0113 .0384
39~/ ACSR (26/7) .0107 .0360
397 ACSR (26/7) .ot5a .0433
397 ACSR (26/7) .0112 ".0375
397 ACSR <26/7) .0106 .0502
397 ACSR (26/7) .0090 .0311
397 ACSR & MC .0076 .0255
397 ACSR (26/7) .0076 .0229
4/0 ACSR .0032 .0066
397 ACSR (26/7) .0066 .0215
397 ACSR (26/7} .0085 .0259
397 ACSR (26/7) .0139 .0422
555 ACSR (26/7} .0241 • Jill
4/0 ACSR (6/0) -.0219 .0423
B-34
Susca?tance**
ac
.0061
.. 0035
.0045
.0042
.0050
.0045
e~0060
.0036
.0030
,t0033
.. oooa ·
.0030
.0037
.0060
-· -
.Of39
.0048
Zero Seq
Impedance***
Ro · Xo -
·.0347 .2023
.Qt97 ,. 1150
.0253 .1471
.0237 .1380
• 0284 .1656
.0246 • 1440
.0339 .1977
.0203 .1171
• {}168 • 0977
.0167 .1026
.0054 .0242
.Ol6t .• 0933
.0190 .. 1161
.0309 .1891
.0653 .4339
.0365 .1574
• • • ' 0 •• " • ~ .-..... -•• t -. ; •• -: '"· ;,·, • ~ • • • : • • .. • t.., !•: . . ·.
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Tab J e B7e.3: Matanuska Electric Associ at ion and
Alaska Power Adminis'tratlon
Transnlssion Line Data
Transmission Clrcui t -Vol tag<a ·
Fran ats -To Bus Length
Cmf)
'E xl st f ng System .... 2
Conductor
Pos Seq
Impedance*
R X
· Su~ceptance**
8C
Anderson (MEA) -Anderson Tap (MEA) 3. 5 4/0 ACSR (6/0 l • Oll8 • 0228. • 0026 •
* Posit!ve sequence Impedance in per unit on 100-MVA base.
** Total I tne chargt ng su5cep-tance in per unit on 100-MVA base.
***Zero sequence Impedance tn per unit on 100-MVA base.
t Ekl utna-Anchorage and Ekl utna-Lucas 115-kV circuits owned by APA.
Abbreviations: APA .. Alaska Power Admlnfstratlon
MEA -t-~tanusl<a cl ec:tric Association
CEA -Chugach Electric Associatton, Inc.
B-35
Zero Seq
. l mpedance***
Ro Xo
.• 0194 .0870
.. • • • f\t • • ~ '
. • • I • . ~· "' ' • . -• . : • • "• ; • -.' • ~ r • ,. .. ..... ·, : j .,
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TABLE B7.4: MATANUSKA ELECTRIC ASSOCIATION AJ.D.. 9
ALASKA PG'IER ADMINISTRATION
DISTRlBUf ION SUBSTATION DATA
EXISTING SYSTEWC
T ransfonner• Noncofnci dent Substat'lon Peak Demand Read l ngs
Substation
Anderson
Campttt
Douglas
Dow
Herni rg
LaZe I J e
Lucas
Parks
Pippel
Reed
Settlers Bay
Shaw
Sit"e Bay
Vol-tage
CkV}
115/l2o 47
115/24
l t 5/12.47
115/12.47
115/12'.97
115/12.47
115/12.47
115/12.47
115/12.47
34. S/12.47
115/12.A7
34.5/12.47
Rating** 1975 -CMVA)
12/16/20 2. 74
1.37
12/16/20 NIS
5 l. 98
22126/30*** 4.99
12/16120 NIS
tst 7.82
10 5.81
2ott 8c06
5 na
2.5 NIS
12/16/20 NJS
1.5 4.17
36.94
* Load tap changing .. transformer un J ass otherwise noted.
1976 -
3.9a·
1. 12
NIS
1.94
6 • .34
NIS
9.31
3 • .79
10.44
1 •. 97
NIS
NIS
4.22
43.11
** Maxtmi.Jn nanepJate continuous full load ra-ting at 55°C rise.
***Two transformers in para I I ef, one 10 MVA and one 12/16/20 MVA.
t Two transformers ln para11 el; one 5 MVA and one 10 MVA.
tt Two transfo.nners in para II el, each 10 MVA.
tttsuppl ied at EkJ utna.
x All distribution facJI itles are tEA.
Abbrev I at ions: na ... t-b data ava il c=b I e.
NIS -Not ih service.
B-36
1977 1978 1979 --
6. 19 3.94 4.;6
2.07 .98 .63
MIS 2.69 3,.07
2.45 3o24 2.99
1 t.04 i2.96 13.32
NIS NlS 3.26
12.72 14.98 11 •. 38
·4.42 4 •. 32. 4 .. 22
9.22 10.51 9.50
. 2.59 2.98 2.98
.65 .76 .so
NIS 4,.13 3.84
4.65 3.48 1.78
56.00 64.97 62.03
(f.MJ
1980 -
na
na
na
na
na
na
na
na
na
na
na
na
na -
na
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1·. ·_ --
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G
E
D
c
B
fD·•
ALASKAN
RAILROAD
LEGE' NO ---o-HIGHWAY
-H-H-t++-RAILROAD
(TO DELTA JUNCTION)
138 KV.
ALASKA RANGE
-.
-• ...._ PRr: -~.~f!O SUSITNA UN£
EA, . "~. J TRANSMISSIOI'fUNE'
SUB~ STATtON -
\
1
\
\
MT. McKINLEY \---. ·.·
'NATlONAL PARK
\
\
\
\
\
\
\
\
WATJ.\NA ALASi<AN-RAILROAD
~ "
TALKEETi,A MOUNTAlNS
•
UNDER. ~· \.-~---
CONSTRUCTiON -. --.
{ TO BELUGA _PO_W __ -__ ER PLANT 1 -~-__ -__ . · __ --._ ..
230 KV '•. ·
----~-
. r-;;l-
FtGHRE -Ett 1m1·
----
------=------------::.-------=--------:.--d---------1
-~· i!llr~ . I . . I -. . I
-I ----~;,-----~---r-~---------;uOH6RAG£uuHicwAL------,
-nn,_, "' UGHT ' POWER ... 11
a a .
nttv
, .. i
trl. u
. UA. I su. l I
Sl£. ••
Sll. I n-.n
__ J
•rcc;s UATANUSKA ELECTRIC
ASSOCIATION
PSI'ftl. rws ...--
l. ... ------!1!..!!__!?!:..!!._-f _........_.._ ~t£ J
"· 1Dllll2i:f' L... ---------------------~---~-r----... ·-------. i
I~IM I
I
CUUGACU ElECTRIC ASSOClATIOfl I
-------------j
-
ANCHORAGE A'REA ONE-LINE. OIAGRAM·--'-'1984-SYSTEM fiGURE BJ~
. . -. . . . • I • --.---
• . .
~ . . . . . -
--·-- - -<--·-.. - - -
~-~~-~--~--~------~----~~--~--~-~~-------~--~-~~-~-~------~~-~----~-----~--~--~-~~~~~------~----~~-
l'iOI
llll
1111\0Sill
(//ALUlA
I
Allli'Ctlf _._.,....:..._
Ill
GOlDEN VALLEY
ElECTRIC ASSOCIATION
Ulll\'£1SIIl A 'I[.-
fAIRBANKS--1
UUNICIPAL l"'
UTiliTY "' ----,
SYSTEU I
·CII(Jtl I
~~:~ ___ ___j
S. JAIIiW«S
-----·· ... -----------------------............... _____ ~....., ........ ,
~1-----1
I lilY I
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-.. 11 ... . ~-crux a ~--------------~~--~-------:::~------------~~------------J
FAIRBANKS AREA ONE-LINE DIAGRAM...:I984 SYSTEM . . fiGURE
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APPENDIX C
ECON01IC CONDUCTOR SIZES
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~---·· ..
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TABLE OF CONTENTS
Page
C1 .... INTRODUCTION .... -_.. ________________ _..._,...,..._-____________ ~_,_._. .... ~ ........ _ .. _ _._. C . =--1
C2 -.LINE CAPITAL COST . __________ qa ......... :-. __ .._ ____________ ~}l .. .__._______________ c. .. 1
·c3-CAPJ:TALIZED.COST OF LOSS----------""' ______ .., __________ ... _..,.. ____ 'C.-2
LIST OF TABLES
Number
C3.1
C3.2
Title
Transmission Line to Anchorage
Develo];inent' of Capitalized Cost of I.oss
Tran$fttission Line to Fairbanks
oevelopnent of Capitalized Cost of I.oss
Summary of ~onomic Factors and
Proposed Conductor Sizes
LIST OF-FIGURES
Number
C3.1
Title
Transmission -To.tal. Cost per Mile as a Function o£
Conductor Area
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APPENDIX C
ECONOMIC CONDUCTOR SIZES
C1 INTRODUCTION
In EHV. transmission, l.in.e conductors and conductor bundles musit:. be sized
to minimize corona, RI and audible noise effects. An addition·al factor
that needs to be quantified is the economic incentive to increase the ·
conductor s.ection still further to achieve savings in the future cost of
line loss.
This appendix deals with the economic aspects of conductor sizing, and
since both line costs and line losses are proportional to line length,
the analysis is carried out on the basis of costs pez circuit-mile.
C2 -LINE CAPITAL COST
fJ!ransmission costs are genera:Lly a function of the transmission voltage
and :conductor size, modified :by local considerations such as
meteorological factors, access, transport costs and local labor costs ..
At a partic'U4-ar voltage, the variation in line cost as a function of
conductor area is normally oi' the form.
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On the basis of line cost estimates for AiasK.a: "values'~ of *'X1 "
1
"~" and •a• have been determined.J. These are approximate
1
hut
they describe the relationship between line cost and conductor si~e
sufficiently well to be USed ~~· a guide in determining the economic size
of line conduQtor. The equations are shown below.
230 kV: $/mile=' 110 000 + 16 (kcmi1)1.18
345 kV; $/mile~ 160 000 + 1.6 (kcmil.)1.18
500 kV: $/mile. ·Cf 285 000 + 16 (kcmil)1.18
C3 -CAPITALIZED COST OF LOSS
Line loss varies directly as the square of the line loading and inversely
as the conductor c:ross•sectional. area$ Since the line loading varies in
a daily pattern and also throughout the life of the facility~ thes..a
variations must be taken into account.
Transmission line loading over the llfe of the facility can only. be
estimated at this time. According to generation planning studies, each
time a block of 400 MW of generation is commissioned (in years -1993,
1996 and 2000}, this capability is fully absorbed by the system. It i.s
further assumed that all of the average energy capability at Susi tna "
would be utilized at each development stage, resulting i.n load factors
(LF) and loss load factors (LLF) as indicate.d in the table below.
In this table no generation additions are included after year 2000 as the
~~
contribution to loss energy from any additional peaking capacity is
assumed to be negligible.
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Line Loadin2:s (MW}
Susitna To To Period Ca12acit:t Ener91: LF' LLF* !Ulchoras:~ Fairbanks-(MW) (GW•h)
1993 to 1996 400 2 990 o •. as 0.786 320 80
1996 to 2000 800. 3 252 0.46 0.336 640 160
--
2000 to 2043 1 200 6 227. 0.59 0.469 960 240
0
Expressing .line loading and line1 resistance in per unit on surge
impedance loading (SIL} and sur(a-e impedan·ce (Zc) base leads to
the following expressions •
· Line resist·ance
1oo· 1 = · · x -per unit per mile kc:mil Zc
I£ line ~oading = s .Per unit on SIL. base
Then line loss per mile S 2 100 1 -. •t = x --x -per u::t...'t. kcwd.~ Zc -
and since SIL
Line loss per mile S 2 . 100 1 kV2 {,..31-.1 ) = X .k· .....,...;, ·-l X ·-.X -1::.rt UU. e -zczc ~
Annual loss energy/mile 2 100 kV2 . ..
lL S X k .1 X -2 X 8. 76 X LLF
cm1 Zc (GW•h/mile)
And if the cost of loss energy = c $/kW•h
= c $ million/GW•h
Then annual coat of loss 2 100 kV2 . . . = S X·kcmil X 2 X 8.76 X LLF XC
Zc ( $ milllon/Jnile)
LF 2 + LF *Loss load factor (LLF) is estimated as LLF = ----
--~---,c .. -.. 2
c-3
,,
-·
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A typica~ value of C for .Susitna is $0.035/kW•h. This energy
cost is an average figure derived in the OGP-5 planning studies based
G
on zero inflation and 3 perc.ent net cost of money.
• • .Aunllal. cost of loss • 3!1.66 s2 k~::. ..r.F ($ Jliil1ion/JIIlle)
kcmil zc.
In Tables C3.1 and C3~ 2. the· capftalized cost of loss per mile is derived
for transmission to Anchorage rmd Fairbanks, respectively, as a function
of conductor size and for the line voltages that are being considered ..
The capitalized coot of loss is derived in three components, representing
the three stages of develop:nent of the project. In all cases two
circuits are assumed from the outset. for secln"ity .reasons. In t".:he case
where three eir5=ui,ts a,..e used for the ultimate line loading, it. is
assumed that the third circuit is added at t.l].e final (1,200 MW) stage of
develo~ent.
In '!'able C3. 3 the line capital cos·t and capi.tali~~d cost of loss (as
#
developed in Tables C3.1 and C3.2) are shown. as a function of conductor
area for ~each voltage and transmission alternative. The indicated
optimum conductor areas are also given .in the table and these were
derived as follows.
-rf line capital cost
lC
and capitalized cost of ~oss = k~l $ million/mile
K
Total. cost per Dli.l.e = x 1 + K2 (kcmilJa + k~l $ million/mil.e
c .... 4
t
,.
:··
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.. , Differentiating with respect to kcmil and equating to zero for
minimum total cost per mile.
K d coat . (k--.tl) a•1 _ ......... 3--._ -·-.::= a •tc \.OAL&. -d kcai:i. 2 . 2 (kcmil)
X
3 = .... : ·-~
(kemi~)2
X
(kaa.il)a+1 = ... ~
a.· 2
and ket'Ail
-0
In two eases, namsly 500-kV transmission to Anchorage and 345 kV to
Fairbanks, line losses are relatively low and lead to indicated econcmic
conduct~l.:" areas that are below the acceptable limit from an ru: and Corona
_point of view. The proposed conductor sizes which are sbowil at the
bottom of Table 3 have been adjusted, where necessary, to provide
acceptable Corona and RI performance.
The relationship between line capital cost and total ~ost (including
capitalized cost of loss) is shown graphia~lly as a function of conductor
ar.ea in Figure C3. 1. The cases illustrated ar.e for 345 kV to Jmchorage
and 23 0 kV t6 Fairban1ts, the two cases where cost of loss was a fat.-:tor i:n
· the proposed conductor arrangement.
. . . . . . . ' .· .; . . . . ' .. ·~ . .. ... . : . ..
--------
'rlUlLE Cl.lz 'l'RAliSMXSSIOH L'INE '1'0. AHCUORAGR DEVEE.Oft.£.'fr OF CAPI'ttlLIZED COST OP LOSS
Loading per 2 Circuit Annual.
'l'Obil No.,. of on SIL cost of
Period Load Circuits Basel E:!. Loss
. (MW) {iii) (S-pu) ($M•kcmi1)
cct•mile
1993-1996 320 2 160 l 0.386 0.786 5.195
1996-2000 640 2 32.0 0.771 0.336 8.861
2000 -2(1.43 960 2 480 1.157 0.469 :n.BS4
1993 -1995 320 2 160 ~.396 0.786 5.195
1996. -2000 640 2 320 ~I 0.711. 0.336 8.861
2000 .. 2043 960 3 320 0.1'11. 0.469 12.368
1993 -1996 320 2 160 -o.r1a 0.786 2.474
1996-2000 640 2 320
:> ;!( 0.356 0._336 4.230
0
0
2000 ... 2043 960 2 480 &0 0.533 0.469 13.236
1stL base valua• are 415 MW (345 kV) .and 900 MW (500 lV} •
21mnual cost of less "' l0.66 s2•kV2 ~ J.JE/zc2 based on losoeu valued at S0.035/kW·h·.
3n a duration of loa~ period
~.=offset from present worth datum.
5 . 1~ 1 ~ 1 Present worth .factor • I 1 -. · · x --.-, annual discount ,;at'C (1} • 3 percent,
i'-(Hi)'!_ (l+i)lll
3 4: n II
"(y";f {yr) .
3. 0
4 3
43 7
T-otal Ate :!#-kV
3 0
4" 3
43 7
'l'O.tal. 3t 345 kV
3 0
4 3
43 7
'l'ot.al at 500 kV
-·-·
Preaent5 capitilllzed
~rth Cost of
Factor Loss
(Sll.!·k~il.)
cct•DU.le.
2.8286 14 •. 695
3.4017 30.1~2
19.4995 543.139
(2 clltcuits) • 587.976
2.8286 14.6.95
3,4017 30.142
19.4995 241.179
(3 circuits) • 286.016
2.8286 6.998
l.4017 14.369
19.4995 258,095
(2 circuits) • 219.482
. . . . . . . . . . . . . ~
: ·, -:·· . ' . . . . .. .' . . : : . . . . .· . .. -. . .' . ---.. -
TABLE C3.2i TRANSMISSION LINE TO, FAIRBANKS DEVELOPMENT OP CAPI'l'ALXZBD COst OF LOSS
.LOading per
Annua12
Circuit
'lotal No. of on SIL cost of
~ Load circuits Basel LLF Lo!ls -1iiWf -(~tW) (S-pu) ($M•kcmi1)
cct·mile
1993 -1996 80 2 40
;\
0.292 0.786 o .. 729:i
1996 -2000 160 2 eo O.SB4 0.336 1.2466
lOOO-2043 240 2 120 0.876 0.469 3.9151 .
1993 -1996 80 2 40 ~I 0.100 o. 796 0,3240
J,996 -2000 160 2 80 o.2oo 0.336 o.ss39
2000 -2(1.43 240 2 120 (.,,300 0.469 1,1397
1siL base value!S are 13.7 MW {230 k'\f} nnd ,.SQ:O .t.ftf (34~ kVl. .
2 . 2 2 2 . Annual cost of loss • 30.66 S •k.V • U2/'Zc basr.d on. losses valued at $0 .. 035/kW•h.
3 .
n =duration of load peri~.
4m-offset fr~present vorth datUM.
5 Present WOJ:"tli factor • ~ ·_fi -1 ::1 x 1
Q an••~l ;_.lacount xate (1) • "' percent,. L tl+tl ~ (l+i)&' .;
Pt:osent.5 Capit:aliaod
3 .4
WO!:th Cost of
n Factor LOSS --(yr) (yr) ($M•kcmil)
~ct•mile
3 0 2.8286 2.0620
4 3 3.4017 4.2¢~
43 7 19 •. 4995 76~3425
Total ~t 230 .kV (2 circuits) -Ill 82.64.51
3 0 2.8286 . 0.9165
4 3 3.4017 1.8842
43 7 19.4995 33.9233
Total at 345 kV (2 cil:cuit:a) ... l6.124Q
-
TABI:E C3. 3: SUMMARY OF ECONOMIC !"ACTORS AND PROPOSED CONDUCTOR SIZES
Capital cost of line
($M/mile)
caeitalized cost of loss*
($M/mile}
oetimum conductor area**
(MCM}
f!:_pZOSed conductors
Transmiss~on to Anchorage
500 kV .~~4-S~kV._. ______________ ~---------
2" Circuits 3 Circuits 2 Circuits
279.482
kcmil
1,946
3x795***
0.16 + 166 kcmill.lS
10
286.106
kclidl
1,967
2K954
0.16 + ~· kcmill.lB
10°
597.976
kcmll
2,737
2x1,351
*Capitalized cost of loss expressions are derived in tables 1 and 2.
. 1
·uaptimum conductor area == {~apitalized cost of lossj ~.18 kcmil per phase.
\l.6xl.,lS ·
Transmission to Fairbanks
345 kV
o.1n + 166 kcmJ.·11.18
10
36.,-7240
kcmil.
767
2x795'**
230 kV
. l.& 1 18 0.11 + ::t lkaa:il • ·.
l.!J)
82.6451
kcrnil
1,113
lxl.272
***The economic conductor areas for 500 kV to Anchorage and 345 kV to Fai~banks are smaller than the minimum needed for ai and Corona performance.
Hence, RI considerations will dictate conductor size.
- - --· - - - - - -
---------·-
-(I) z
0 -...J
...J -~
J:
~ -
lU -~ -l
::2
1--:::>
0
0::
0
0:: w
0..
!-
(/)
0
0
OAr. . I . I
. SUSITNA TO FAlRBANKS AT 230 KV . t
TOTAL COST lNCLUOlNG CAPITALIZED
0.3 COST OF LOSS (TWO GlRCUtTS)
I
0.2
I
-UNE CAPITAL COST
(/;f
0~--------~--------~------~
500 1000 1500 2000
TOTAL CONDUCTOR AREA (kcmil)
PER PHASE
-CJ) z:
Q
_J
-' -·~
0.71
0.6
I I
SUSITNA TO ANCHORAGE AT 345 l<V
--r-
TOT.AL COST tNCLUOJNG CAPJTAUZEO
COST OF LOSS (TWO CIRCUITS)
~ 0.5
w
...J --:E
t-
::>
0
0: ·-(.)
0:: w a..
t-
(/)
8
0.4
0.3
TOTAL COST INCLUDING CAPITALIZED
COST dF LOSS (THREE ClRCtJlT.S)
LINE CAPITAL COST
0.2 L-------~"--'--------~-------------~..----_....i
1500 2000 2500 3000
TOTAL CONDUCTOR AREA (kcmil)
PER PHASE
TRANSMISSION-TOTAL COSTS PER MILE AS A FUNCTION OF CONDUCTOR AREA I.J•Ii ].·· .. '
FIGURE C3.1 II
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APPENDIX D
COST ESTIMATES
"
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LIST OF TABLES -----·-"
Number
D.1
0.2
D.3
0.4
D.S
Title
Transmi~$iOn and Substation Unit Costs
Transmission Line Capital Costs
Substation Capital Costs
Transmission and Substation Annual Charges
Tra.ns:tission Line Land Acquisition Costs
Capitalized Transmission Ldne Losses
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APPENDIX D
COST ESTIMATES
T.he economic analysis for the Susitna transmission system was Ciarried
.out using cost estimates based on 1981 unit costs, without escalation,
for all equipment and services. The unit costs for all transmission
and substation equipment. are given in Table o. 1. The principal para-
meters of the five transmission alternatives analyzed in detail are as
-
follows.
Susitna to Anchorage Susitna to Fairbanks
{ 140 Miles) ( 189 Miles)
Number of Number of
Alternative Circui.ts Voltag:e Conductors Circuits ·'7."'~"1 ............ ""'-~ ~~CL::;!~ Conductors
(k\T) (kcmil) (kV) (kcmil)
1 2 345* 2 X 1 351 2 345 2 X 79oS
2 3 345 2 X. 954 2 345 2 X 795
3 .2 345* 2 X 1 351 2. 230* 1 :2C_j_ 272
4 3 345 2 X 954 2 230* 1 X 1 272
5 2 500 3 X 795 2 2302 1 X 1 272
The t:cansmission line capital cost estimates for the fi;re transmission
alternatives are shown .in Table o. 2. The 1993 line costs include ah
adjustment for the use of a larger conductor than required by the
intertie, 9 years.before the construction of the Susitna transmission
system. '!his adjustment accounts foz: inter tie construction with con~
ductors ultiinatel.y required for Susitna transmission.. The adjustment
consists of the. difference in line costs mul.tiplied by the length of '
the line section in question and the. factor to account f~r t"he
*Denotes series compensation•
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accummulated interest for the incremental conducto,r cost. It is
calculated as· follows.
Adjustment= 1ength•[(1.00+i)n .... 1.00J•(ca-Ci)
-length • [( 1. 03) S -1. 00 ]• ( cs-Ci)
-length • o .. 304,8 • ( Cs-Ci)
where
i = discount rate (3.0 percent)
n = time period ( 9 years)
Cs -cost of Susi tna conductor in $f:1/mile
Ci = cost of conductor required for intertie in $M/mile.
The substation -capital cost estimates are shown in Table 0.3 and
include a base cost plus costs Zor major components at each station.
The base cost includes land acquisition, site preparation, found~tions,.
etc. Cost estimates of major equipment, such as circuit breakers,
transformers, etc, include the costs of all ·ancillaries StLOh as
disconnect switches 1 potential and current transformers, controls~
instrumentation, etc. At the generating stations all EHV circuit
breakers are included, but generator transformers and low-voltage
breakers are excluded. These are i..'l').cl uded in the powerhouse estimates,.
Similarly at the load centers all EHV breakers are incl.uded as well. as
the necessary circuit entries at the subtransmission "t_rol tage { 23 0 kV or
13S kV) for each trans forllter bank. The remainder' of the lower voltage
station is common to all alternatives end therefore excluded from. the.
economic canparison. At &··u;horage, trans formation to 23 0 kV is assumed
on the west side of Knik Arm implying cable crossings at 230 kV. The
cable crossings and other 230-k\1' equipment are considered cOIUlX)n to all
ac transmission alternatives for Susitna and their costs have been
excluded frem thi~ est±~tae 1'hey mu.st be included for ccmpa.rison of
schemes 'With different Knik Ar1li crossing configurations such as HVDC
transmission from: Susitna ..
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'rhe calculations of annual ~~harges for transmission lines and
substatlons are shown in Table D.4. Annual charges ;include the.
following companents.
:rtem.
Operating and maintenance
Insurance ..
interim. replacement
contribution in lieu
of taxes
TOTALS
Percent of
Transmission
Capital Per
Year
0.10
0.15
2.00
3.25
Percent of
Substation
Capital Per
Year
2.00
0.10
0.15
2.00
4.25
At a discount rate of 3. 0 percent and for a 50-yr peric.ld of anaLysis
<
from 1993 to ~043 the capitalized annual charges are. calculated as
follo~ ..
For equipment commissioned in 1993
Transm.is~ion .lines: 3.25 'Percent
0.03
!11.03)50-1.00] c: { 1. 03 ) 50 J
Substations:
-83.62 percent of 1993 transmission
line capital cost
4. 25 ,£ercent -n 1 • 03) so -hQ..til.·
o.o3 [ [1.03)50 ~ J
-109.35 percent of 1993 substation capital cos·t
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For equipment commissioned in 2000
Transmission lin~s: 3 .o 25 Percent
0.03
f]1.03)43 -1. ool
[ ( 1. 03)43 J
= 77.94 percent of 2000 transmission line
·capital cost
Substattons: ~ ~-25 percent
_0. 03
11_1.03)43-1.oQ1
[ ( 1. 03)43 J
= 101.92 percent of 201)0 substation capital cost
Costs of land acquisition and clearing for transmission lines are
. calculated in !!'able D. 5. :tt is assumed that all right-of-way
requirements wi.ll be acquired in 1993 ~ This includes the" land
a«:quisition costs for aJ.l additional circuits to 'be constructed in the
year 20(/0.
Costs 1bf ce4pi talized transmj_ssion line losses are calculated in
Table D. 6. Unit costs per mile for capitalized transmission losses
have been derived from the costs a£ leas developed in Appendix C,
"Economic Conductor Sizes". In the case of the line section from
watana to Devil canyon the. unit costs have been adjusted to take into
ac~ount the loading that will apply during the various stages of
proje~t development.
D•4
• • ' • • • • C> ~ • ' ., • • ·._. • ..,. ~ ' • .. • • t~-· :-. .. 1o • • ~ ~-,. :: --., . ~ ., '.· _. . : < . --.:: . ·. . -~ . . . ' ' ·, ... . ',; . . ·. __ . ~ . . .
. . : • • •. ·[ . . . .• • .tzr ..• ~. . ~ . . . ' -., .. . . . . . .
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TABLE 0.1: TRANSMISSION AND SUBSTATION UNIT COSTS
Transm~ssJon
Llne Costs
.Voli'aa,e Conductor Base Cost
(kV} {kcmfl) ($/circuit mile)
230 l X. 954 l20,000
230 l X 272 136,000
230 i X l 351 140,000
345 2x 195 190,000
34$ 2x 954 207,000
345 2x l 351 251,000
500 3. X 795 326,000
land Acquisition and Clearing
Vo1-tase
<kV>
345
345
500
Substa'tions
Voltage
(kV)
1~8
230
345
500
Number of Clrcuii"s
2
2
3
2
Station Base Cost**
( $ M.il lion)
1.000
t .:soo
2.500
Fina I Cost*
C$/cfrc"'it mile-)
162,000
184,000
189,000 Q
256,000
219,000.
339,000
440,000
$/Mt te
75,000
96,000
80,000
Circult
Breaker PosltJon
($ Mi 1 f fonl
0.400
0.700
1.000
1.600
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Tabh1 D. 1
Transmission and Substation Unit Costs-2
Autotransf~rmers_ ( tnc I udl ng 15-kV tart iart!.
,Yoltage
(kV)
2.30/138
345/138
500/138
3451230
500/.230
Voltage S/kVA
CkVl
345 4.20
500 s.oo
Shunt Reactors ---
V]~Jta~.~
{kV)
345
500
75 MIA
( $ Mit f ion)
0.500
0.700
50 MVAAS
($/kVAR>
24.60
Series Compensation (all voltages)
$14oOO/kVAR
Static VAR Sources (tertiary voltage>
$30.00/kVAR
150 MIA
C$ Mf Ilion)
o. 800'
0$900
·t. 200
0.900
1.200
75 WAR,§_
($/kiJ!1R)
1. 11
17.20
250 WA -· C $ Mf I J ion)
1.100
1.300
1.600
1.~00
t. 6CJv
*Final transmission line costs (page 1 of table) tnclude 20 percent contingency, plus
· 5 percent engineerf ng, 5 percent" constr.uctlon management and 2. 5 percent ownerJs cost.
**Substation base cost (page 1 of table) includes land acqulsitfon_, site preparation,
foundationst etc.
- ---- - - - - - - - -... ----
TABLE D.o2: TRANSMISSION LINE CAPITAL COSTS
Transmission Alternative
.,.
'·--1 "2 3 4 5 Year 19.93Transmlsslon Circuit Circuit CircuiT Cir'wit Ciradit line Costs Unit Cost .Miles .SM Mfles $M Miles .SM Mites !!! MiJes. SN UM/mn
Watana to Oev! i Canyon (27 mi) ,.
Voltage CoQductor
.345 kV 2 X 954 kcmi I 0.207 54 11.18 54 11.18 --345 kV 2x 1,351 kcmil 0.251 54. 13.55 54 13.55 500 kV 3 X 795 kcmi I 0.326 54 11.60
~vll Canyon to Anc.horage ( 140 mi)
345 kV 2)7. 954 kcmi I 0.207 "280 57.96 ,_ 28C 57' ... 96 345 kV 2 X 1,351 kcmll 0.251 260 70.28. 280 70.28 500 kV··-3 X 795 kcmlt 0.326 --280 9lo28
.Oevi I Canyon to Fairbanks ( 189 mi)
230-k.V 1 X 1,272 kcmll 0.136 293 39~95 .378 51.41 378 Sl.4t 230 kV 1 X 1,351 kcmil 0.140 85 11.90 345 kV 2 X_ 795 kcmi I 0.190 293 55.67 293. 55.67
345 kV 2x 954 kcmll 0.207 85 17.60
345 kV 2 X 1,351 kcmt a 0.251 85 21.34
Sub-total 1993 llne costs 160.84 142o41 i35.(k 120.55 160.29 Contingency (20 percent) 32.,1"/ 28.48 . 27., 14 24.11 32.00 Subtota• 193.01 170.89 162.82 144.66 ..
192.35 Engineerlng and Management 24.13 21.36 20.35 18.08 24.04 (12.5 percent)*
TOTAL 1993 Transmission Llne Costs 217.13 192.25 J..83 .. 17 162.74 216 .. 39
Adjustment For Advanced lntertle
Construction With. Larger Conductor** .SM/mi $M $M/mi $M $M/ml .$M SM/mi SM .SM/ml ~ -
Willow to Gold creek (80 mJ) (0.251-0.20'1) 1.07 (0.207-0.207) 0 (0.251-G.120) 3,19 (0.207-Q.120) 2,12 ( 0.326-o. t 20) 5.02 Gold Creek to Healy (85 mi) (0.251-0.207) 1.14 (0.,207-0e207) 0 <0.1.40..0. 120) 0.52 (0.136-0.120) 0.41 (0.136·0.120) ,0.41
Subtotal· tntertle adjustmenT 2.21 0 3.7t 2.53 5.43 Contlngency, englneering, ~tc 0.77 0 1.30 0.89 l.90 Totar adjustment 2.98 0 5.01 3.42 7.33 -TOTAl Adjusted 1993 Transmission Line Costs 220.12 192.25 tea. uf 166.16 223.72
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Table D.2: TransmJsslo.n Line Capital Costs.-2
Transmission Alternative
1 ~2~·--~-------etrettit Circuit-Year .2000 Transmission ·
Lfne Costs.
.:;:-, -----
1
Unit Cost Miles $M Mi l~e:s $M
($Wmi)
Dev i I Caft100 to Anchorage C 140 m t ).
Vol~£Jil Conducfur
345 kV 2 x 954 kcmi I 0;207
Contfngency (20 percenT}
Sub'total
Engineerfng ard Management
{12 •. 5 percent>*
TOTAL 2000.Tr.:ansmJsston Ur.a
. Cap J tat Costs
* Engineering and Management rnciudes
.... Eng i neert ng · ?• 0 percent
-Construction Manayement 5. 0 percent
140
-Owner's Cost _£!5 percent ~
26.98
5.80
34.78
4.35
39.12 --
3
Circuit
Miles
-Total 12.5 percent
**lntertJe cdjusiment accoun·rs for ·construction wl_th a larger .conductor than required by the fntertle
9 years_ beforE! construction of Susttna transmlssion system.
$M -
4
Clr:cufi"
tUfas
140
11:!.
2S.S6
5.ao
34.78
4.35
39.12
5
Clr~umt
Mtles., 1M.
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TABLE 0.3: ~\UBSTATION CAPITAL COSTS
Transmi~,si-nn Alternative
1 2 3 4 5 --Year 1993 Substation Costs Unit Cos-T· · Quant_ity $M Quantlt:t .lli 2uanfif:t $M Quantrt~ $M Quanf;ilitw $M
CSM>
Anchorage
Base cost -345 kV 2.00 1 2.00 1 2.00 •• 2.00 1 2.:00 -500 kV 2.50 1 2.50
Circuit breakers -230 kV 0.70 6 4 .. 20 6 4.20 6 4.20 6. 4.2() 6 4.20"
... 345 kV t.oo 9 9.00 9 9.00 9 9.00 9 9.00
-500 kV lt.6.0 l t 17.60
Transformers -345/230 kV,. 250 MVA 1.30 4 5.20 4 5.20 4 5.20 4 5.20
-500/230 .kV ~ 250 MVA 1 .. 60 4 6#-40.
Shunt reactors-500 kV. 50 MVIIR 1.23 2. 2.46
Static VAR sources (MVAR) 0.03 400 12.00 400 12.00 400 12.00 400 ~2.00 200 6.00
Subtotal 32.40 32.40 32.40 32 .. 40 39.16
Contingency < 20 percent) 6.46 6 .. 48 6.48 6.48 7.83
Subtotal 38 •. 88 38.88 38.86 38.88 46.99
Engineering and management 02 .. 5 percent>* 4.86 4 .. 86 4.86 4o86 !i~87
TOTAL 1993 Anchor~ Station Cost 43.74 4~•ill. 43 .. 74 43.74 52.87
Wtf low ~t·'"
Base cost-345 kV 2.00 1 2 .. 00 1 2.0'0 ·~~~~:i~-:-:z;fO(l --·-· ··r"-" 2.00
.... 500 kV 2.50 ___ ... _-...
~=~-·=~":;..;.~-~~=-"'"';;.;..~.;:_:-.:.:_:_.· -:---~ .. -~~:~t.50
Circuit breakers-138 kV 0.40 3 1.20 3. 1.20 3 1.20 3 1.20 3 1.20 -345 kV 1.00 9 9.00 9 9.00 9 9.00 9 9.00 -500 kV 1.60 11 17.60
Trans fanners -345/138 kV• 75 MVA 0~50 2 loOO 2 t.oo 2 1.00 2 1..00 -500/138 kV, 75 MVA 0.10 2 1.40
Shunt reactors-500 kV, 75 MVAR 1.29 2 2 •. 58
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Subtotal 13.20 13.20 13.20 13.20 25.28
···---.-·-
':-\--;~·::::-
-' ·--·--·-·-- --·
~ble 0.3: Substation Cap ita I Costs -l.
~ TransmissIon A lternatt ve. ·< ~
-1 2 3 4 5
Year 1993 Su~tlon.Costs Unit Cost QuantiTl SM Quantity .!! Quantlt;t $M :ouantft~ 1M. Quarrtit)' SM
($M)
Con"tl ngency OW percent) ,,... .. -.~·-...... -"
2.64 2.64 2.64 2.64 :5.06
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Subtotal 15.84 15.84 15.84 15.84. 30.34
Engl neer i ng antt managament ( 12. 5 percent)* 1.98 1.98 1.98 1.98 3.19
TOTAL 1993 WIt tow StaTion Cost 17.82 17.82 17.82 17.82 34.13
Devil Canvon
Basa. cost -230 k V 1 .. 50 1 . 1.50 1 1.50 l 1.sa
-345 kV 2~00 1 2.00 1 2.00 1 z...·oo 1 2.00
-500 kV 2.50 t 2.50
Circuit breakers-230 kV 0.70 8 5.60 8 5.60 8 5.60
-345 kV 1.00 12 12.00 12 12.00 15 15.()0 15 15.00
-500 kV 1.60 15 24"100
Transformers -345/230 kV. 150.MVA 0.90 3 2.70 3 2•70
-500/230 kV. 150 MVA 1.20 3 3.60
Generator ··•"ansformer 1 ncr:ernE:mta l. cost-. 220 MVA 0.176** 3 0.53
Subtotal 14.00 14.00 26 .. 80 26.80 37.73
Contingency (20 percent} 2.80 2.80 5.36 5.36 1.55
Subtotal 16.80 16.80 32.16 32.16 45.28
Engineer J ng and management < t2.5 percent)* 2.10 2.10 4.02 4.02 5.66
TOTAL 1993 Devil Canyon StaTion Cbst I 18 ... 90 18.90 36.18 364018 50.94
Watana
Base cost :... 345 kV 2 .. 00 1 2,.00 . 1 2.00 l 2.00 1 2~oo
-500kV 2.50 1 2.50
Circuft brea~ers-345 kV. 1.00 9 9.00 9 9.o00. 9 9.00 9 9 •. 00
-500 kV 1'.60 9 14.,_40
Generator transfo.rmer Incremental cost, 22.0 MVA (}.176** 4 0.70
Subtotal t l$00 lhOO . n.oo ll.OO 17 .. 60
... q • • . • • , • ' •" • . • .. • '* .• . ... ""
Tal:ile 0.3: SubstaTion Capital Costs .. 3
Tr~nsmission Alternative
l 2 3 _4 5
Year 1993 Substat-ion COsts Unit Cost Quan'tit~ 1M. Q!;!antJtl SM Quantity $M QUant it}! $M Quant"i!tttf ... ;$M
t$t.U
Contingency (20 percent> 2,.20 2.20 2.20 2.20 3.52
-Subtotal· 13.20 13.20 13.20 13.20 21.1-2
Engineering and management ( 12.5 percen-t)* 1 .. 65 1.65 . 1.65 ... 1:.65
If""":" ... -
2.64
"TOTAL 1993 Watana Station Cost 14.85 14.85 14.85 i~·$,135 23.76
fairbanks
Base cosf ;. . ZSO. ltV 1.50: :1 h50 1 1.50 l 1.~0
-345 kV 2.00 1 2.00 1 2.00 ~
Clrcult breakers.-138 kV 0.40 4.5 1.80 4.5 1.80 4.5 1.80 4.5 1.80 4.~ 1.80
-230 kV 0.70· 8 5.60 6 5.60 8 5.60
-345 kV l.OO 10 10'.00 10 10.00
Transformers ... 230/138 k'l, 15G MVA o.ao 3 2 •. 40 3 2.40 ·~ 2.40 ~
-345/138 kV, 150 MVA .. 0.90 .3 2.70 3 2.70
Shunt reactors -34~ k.V, 75 MVAA 0.83 2 1.66 2 1.66
Static V-M sources {MVNU 0.03 tOO 3 •. 00 100 3.00 200 6.00 200 6.00 200 6.00
Subtotal 21.16 21 .. 16 17.30 17.30 17.30
_Contingency (20 percent) 4 .. 23 4.23 3.46 3.46 3.46
Subtotal 25.39 25.39 20.76 20 .. 76 20.76;,
Eng I neetlng and management t 12.5 percen-t>* -3~ 17 3 .. 17 2.60 2.60 2.60 ..
TOTAl 1993 Fa 1rban.ks Stat.lon Cost 28.57 ~8.57 23.36 23.36 . 23.36
TOTAL 199> Substation Capital Cost 123.88 123.88 '135.95 135.9.5 185.06
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"' . ' ----------'_"::: --------
Table 0.3: SubstaTion Cae ita I Costs -5_
, ··----·· .,
Transmission AlternatTve
l 2 3 4 } :
Year 2000 Substation Costs
Unlt" Cost Quantity $M 2uanti!Y. "SM .Q!!ani"lty: SM. :quantity $M, .,2!!antty $M ----
{$M)
Devil Canyon
Cl.rcult breakers-230 kV 0.70
1 04/70 1 o.7o t {).70
_. 34.5 kV 1.00 3 3.a00 5 5.0{} 3 3•00 5 5.,00
-500 kV "1.60
3 -1.00 '
Transformers -345/230 kV. 150 MVA 0.90
1 -0.90 l o.so
-500/230 k v, 150 MVA 1.20
l 1"20: -
subtotal
3.00 5.00 . 4.60 6.60 '6.70
Cont l ngency {20 pei -...~otl
0.60 1.00 0.92 -1.32 1.34.
Subtotal
3.60 6.00 5.52 7.92 S.04
Engineering and managema11t 02.5 percent")*
0.45 0.15 0.,69 0.99 t.Ol
4 ... 05 6.75 6.21 6.91 9.05
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TOT At:. 2000 Devil Canyon station Costs -:-::-:--
fairbanks "'
Circuit breakers-t38 kV 0.40 1.5 0.60 1 .. 5 0 .. 60 }.5 o.oo 1.-5 0.60 1.~ Oo.60
-230 kV 0.70
1 0.70 l 0.70 1 0.70
-345 kV 1 .. 00 1 t .. OO 1 1.00
1 o.ao 1 0.80 1 -o .. ao
Transformers -230/l38 I(V, 150 MVA 0.8()
-345/138 kV, 150 MVJ\ 0.90 1 0.90 l 0.90
430 6.02 A~ 6 .. 02 "' 430 6.02 __,.._.._.... ··~·
Series compensation (t-1VAR> o.ot4 ----
Subtotal
2.50 2~~ 8.12 8.12 '8,.12
Contingency (20 percent)
0.50 0 ... 50 .1 .. 62 1.62 1.62 -
Subt()tal
3.00 3.00 9~74 9" 74 '9. 74
Eng t nearing and management (12. 5 percent>*
-().,38 0.38 1.22 1.22 1.22
3 .. 38 3.38 10.96 10.96 '10.96
TOTAL. 2000 Fairbanks station O:>sts
44.74 31.·47 54.48 41.21 39.13
TOTAL 2000 Substation Capi-tal ,Costs
*Engineering and management includes ... cenglneering 5 .. 0 percent · · , -construction man,~gement 5. 0 percent
-owner-s cosT ... 2.5 percent
. . . _ .. .. Total ~percent
**C'A>st of generator transfomners for 345-kV transmlsslon ls-lncll.lded · ln powerhouse· cost "'sthnates.
Al terll(ltlve 5 requl res adjustment for i.ncrerrt'ental cost of 500-kV transforrners.
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TABL~£t.ii: TRANSMISSION AND SUBSTATlON A~UAL C!fARGES
Transmission Alternative
1 .z·· 3 4 5
Percent of capt"tall·zed .-. Capitalized Capital. l zed Capl ta I i zed ~pi-tali zed
Capital Capital Annual' Capital Annual Gaprtal Annual Capital Annual Caplta.li ~·
Cost* Cos-t Charges CosT Charges Cost Charges Cost Ctta~s:s CosT ~t:t.arges
{$M) UMl CSMl ($M) ($t.0 ($M) ,($M} ($M) _($M) UN')·
a.
l993 Cap lta t 1 zed Annual Una 83.62 217.13 181.56 192.25 160.76 183.17 153..17 162.74 136.08 -210..39 lS0.95
~
Charges
2000 Cap I t~l i'.zed Annuai U~Ye 11.'94 39.12 30.49 -39.12 30•49 -
Charges
1993 Capital h:ad Annual ~ta-t ion 109.35 123 ... 88 135.46 123.88 135.46 135.95 148• 66-135.95 1.48.66 185 •. ()6, 2.02.36"_
Cllarges
2000 Capltallz:ed Annual Statton tot. 92 44.74 45 .. 60 31.47 32.07 54.48 55.53 4l.~! 42.00 :$9.7$ 40.49
Charges
*Capital U.ed aJtnual charg$ per<:entages are devol oped tn. the text on page D-3.
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TABLEDo5:. lRI\NSMiSSION UNE LAND ACQUlSrrtON COSTS
Transmission Aiterna1:"ive ·
t 2 3
'Transmission ll ne Uni.t Cost Len 9th .$M length ~ Length $M
{$M/~t) "-(miles) (mi fes) (miles)
-""' Nmiber of
Voltage Clr.cults
189 13.2~
230 kV 2 0.070
-345 kV 2 D.075 356 26r10 216 1.6 ... 20 167 12.53
345 kV 3 0,.096 140 13.44 -
-~ ----.,;;--~ ----.,.......-:~-·-"':::""' --··---··-·-
500 k.V 2 o.oso
1993 Land Acqulsltlon Cosi"s
26.70 29.64 /;5.76
~-
=
4
1..eng!h $M -·.-:
(miles)
189 13.23
27 2.03
140 13.44
28.70
5
Length
(mHasl
189
---
167
-
$P4
13.23
:-
13.36
26 .. 59'
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TABLE 0.,6: CAPitAUZEO TRANSMISSION LINE LOSSES
Transmlssion Alternative
l
....
2 3 4 5
Capitall~ed _Una losse~ Unit Cost Miles. SM M£1es $M Mfles 1M. Miles $M Miles $M
. ·" {iMimn
Wt:rt~u~ to Oav n Canyon C27 mll
Z X 345 k.V,. 2 x. 1 ,35t kcmif 0 .. 2517 27 6.80 27 6.80.
2 ~345 kV, 2x 954 kanil 0.3565 27 9.62 -27 9.62
2 X 500 k.V• 3 x 795 kcmll 0.1358 27 3.67
Devll Canyon ~to Anchorage 040 mD
2 X 345 kV, 2 X 1.351 kcmll 0.4352 -·140 ., 60.93 140 60.93
3 X 345 kV, 2x 954 kcml t 0.4262* 140 59.67 --140 59.67
2 X 500 kV, 3 X 795 .kcmH 0.2344 140 32.82:
Devil Canyon-to fa:ir6a~~s 089 mil
t x ~Q kV, \ X 1 1 212 kd\.\i.l <tr06497 293 19.04 376 "24.56 378 24.56
1 X 230 kV,. l X 1,351 kani·~ 0,.06117 85 5.20 ..,
1 X 345 kV, 2 X 195 kcm.il 0.02310 293 6.77 293 6.77 -
1 X 345 kV. 2 X 954 kctnll 0.01925 85 1.64 -
l X 345 kV;. 2 X 1,351 kcmtt 0.01359 85 1.16 --
TOTAL 1993 Capttalt zed Ltne losses 75.66 77a70 . 91.97 93.85 61 .. 05
*lnctudes tosses on two circults fran 1993.-t99.9 and three circuits frQIIl 2000 -2042 rnclustve.
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APPENDIX E
Hvtc TRANSoiiSSION
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TABLE OF CONTENTS
Page
~1 -GENERAL -~-------~-~~~--~--~~~~--~--~~-~~~~--~-------~-~~--~~-E-1
E2 -·ECONOMIC SCREENING· ~-~---------~~~~-·---~-~~~---~~~~~---~~~~ E~2-
E2 .• 1 ---Bas·i.e: Schem.es ----~--------.... ---.... ---.. -------CD .... _....,. ..... _., ___ ...... E .. 2
E2o 2 -Comparative Costs ---------.-·------------------------E-4
E2.3 -Resul.ts -----------~---------------~----------------E•7
LIST OF TABLES
Number
E2.2
E2.3
E2.4
Title
A.c Transmission to .Anchorage
Development of Capital Costs
HVDC Transmission to Anchorage.
Development of Capital Costs
Ac Tra..'lsmission to Fairbanks
Development of Capital Costs
HVDC Transmdssion to Fairbanks
Dev·eJ.opment of Capital Costs
Summary of Comparative Cbsts
Ac Versus De Transmission
LIST OF FIGURES
Number
E2.1
E2.2
Titl.e
Comparison of HVDC Versus Ac
Transmission to Anchorage
Comparison of HVDC Versus Ac
Transmission to Fairbanks
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APPENDIX E
HVDC TRANSMISSION
E1 -GENERAL
Traditionally, HVDC has found economic app.lication. for long-distance
overhead l.ine {point-to-point) transmission or where ~-;i.gnificant
lengths of submarine cable were involved. In either ca:ee, the savings
resulting from the avoc·line or cable ~s compared to the ccst of ac
lines or caoles need to be sufficient to offset the additional. cost of
de tetmina.t facilities.
other characteristics of HVDC transmission that have been significant
in its application are
-its asynchronous nature and hence the elimination of a transient or
dynamic stability problem
-its ucontroll.ability" may be an advantage to limit steady-state
circalating power flow in system interconnections, or to introduce
damping to limit or control system dynamic oscil.lations
-its ability to limit short-ci.rcuit contribt'\tions.:~
In the case of Susi tna transmission, ayoc is not an obv.ious contender Q
No technical difficulties are anticipated in an ac transmission scheme.
and the transmission distances ( 140 miles to Anchorage and 189 miles to
Fairbanks) are well within the normal economic liltits of ac transmis-
sion. ldso, the transmission involves three terminals leading to some
complication of the de control and adding to the cost of some of the
primary ci:rcu.it elements as well.. However, in the Anchorage area some
submarine cable :O'ii.tcuits may be involved in delivering Susitna power
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to the load center. Hence,. ;i.t is appro.priate to carry .put a screening
anal.ysis to detexmine whether or not the de alternati·Q-e merits further
study.
E2 -.ECONOMIC SCREENING
E2.1 -Basic Schemes
Sinca a number of variations are possible in the HVDC basic arrange-
ment, and also in combinations of ac and HVDC transl'l\iaaion, each
transmission link (from ~usitna to ~ohorage and Susitna to Fairbanks)
will he examined separatel-y. In "Uhis base comparison, separate
point-to-point de schemes are implied.
In order to take into account possible savings associated with HVDC
cable circuits in the Anchorage area, the transmission costs to
Anchorage include sul::marine cable circuits as needed to bring the power
to the metropolitan load center.
All transmission from Susitna to Anchorage and Fairbanks is assumed to
start at a Devil Canyon switching station and terminate at an appro-
pr.i.ate voltage in each load center. Ac transmission circuits and
switching facilities between Devil Canyon and Watana are assumed to be
common to both ac and de alternatives# and their costs are excluded
fran the analysis.
Dynamic vat' generating equipment is needed at the load centers for both
ac and de alternatives. The necessary var capability for ac transmis-
sion was determined in load flow studies of critical line outage condi.:-
tions. In th'~ case of th~ de alterna,tive some vars will be generated
by the ac filters. The balance~ as needed to .meet the total var demand
of the load and the inverters thems.elves, is estin:lated. and charged to
the de alternative. All of the required va.r gener.ation is assumed to
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be located on transformer tertiary .windings. Necessa~y switching is
inc-J. uded in the unit var cost.
The .alter.native HVDC transmission systems are planned to· be capable of
handling full rated power under conditions of single contin~ 1cy
outages. In the de terminals, this rnea.n.s that one val.ve group module
could be out of service and the remaining valve groups should be able
to handle the rated load. Similarly, on the transmission line, one
pole may be out of servrice and the remaining pole(s) should be capab1e
of handling the load w1ithout interruption.
For the transmission t.0 Anchorage (rated 1,190 MW) a ±250-kV bipolar
scheme is envisaged, with four valve groups per terminal. Under normal.
conditions one bipolar transmission line to Anchorage would be
adequate • , However, the loss of one line pole would result in a
temporary power reductioil, aw £u]l.,power cculd,-,f>e res.umed only after
te~al S'Witchi.ng4 and an earth return current would flow throughout
the total duration of the pole ·outage. For this reasoh·, and to provide
a system more comparable to the ac al:ternati ve in case of a tower
fail.ure, twa bipolar transmission lines are provided for transmission
to Anchorage.
In the case of ac transm.ission to Anchorage, an intermediate switching
station and transfoxmation to 138 kV is pro'lided at WilJ.ow. This is an
integral part of the ac al.terrtative. For the de;; alternativa, an eqld-
valent power supply to Willow is provided by adding two 230-kV ac
circuits from Point Mackenzie to Willow.. The cost of thes·e circuits
plus a 230-kV bus and transformation to 138 kV at Willow is .included as
part of the cost of de transmission to Anchorage, so that both scheme>cs
would be functionally equivalent.
The. t.ransrnis.sion to FairbCL&"lks is rated 350 MW and at this load level it
is di.ffieult to justify more than a single bipalar transmission line.
Los$ of one pol.e wou1d restilt in an earth :return current and1 if a
power interruption is to be avoided., the terminal equipment on each
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pole .must be ca,Pable of handling the full 350 MW. This results in
tOO· percent reserve capacity,· but it is still more economic than the
building of a second bipolar transmission line •
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The ac and de comparative systems are shown in single line diagrams in
Figure 22.1 for transmission to Anchorage and in Figure E2.2 for trans-
m.issd.on _ -Go Fairbanks.
E2.2 -Comparative Costs
. -.. capital costs associated with the varj,ous ~o an'd de transmission
alternatives .are deve1oped in a series of tables as follows •.
Tables -
E2.1
E2.2
E2.3
E2.4
Transmission Alternative
ac to Anchort.\ge
de to Anchora~re
ac to Fairbanki.;
de to Fairbanks
The costs developed in these tables are all for the ultimate installa-
tion as the effect cf staging is expected to be similar for both ac and
de alternatives.
In all ac transmission alternatives, the unit costs for station equip-
ment and. transmission lines are those used in Section 3.7 of this
planning memorandU1ll. The costs used for ac cable circuits are based on
quot.ed estimates for 23 O-kv· cables. Where station buses are existing
or would be common_ to both ac and de al.ternati ves 1 no base c.ost is
charged.
Al~ HVPC te:rminal equipment ·is estimated at $44/kW per terminal, based
on manufacturers* recent estimates. . .
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'I'he necest,;a.ry ac awitchyard circuit ent~:les are estimated additional to
the base HVDC te:rlninal cos.ts. Var .generation over aftd -above thG.t
provided-by the H"IDC filter circui ta is. estimated, based on the var
demand of the converters and the load, and the cost is .al.lowed for in
the receiving terminals •. ~.At the HVDC sending. end, no additional charge
is ma~ to ensure that generating equipment can tolerate the var demand
and harmonic currents of the converters. Some added costs would be
incurred, but these are expect.ed to have onl.y a secondary effect on the
cost comparison.
HVDC transmission line costs are estimated as foJ .. lo"AS for +250 ... kV
bipolar transmission lines.
Conductor Area
Der Pole
(kcmil)
2 X 1,780
2 X 1 1 272
. . -
Estimated Cost
12er Mile
($)
250,.-000
200,000
In the case of the HVDC cable circuits, these are estimated at 2 0 times
the cost of equivalent overhead line, or $5 million per mile. This is
consistent with the estimate used for ac cable c~rouits and it i:s
considered.to be. sufficiently c~ose for this type of cost comparison.
Comparative costs for ac and de transndss.ion alternatives are
summarized in Tab1e E2.5. Here the line and station capital costs
developed in Tables E2. 1 to E2o.4 are combined with cost of right ... of-way
and capitalized annual operating costs to give capitalized total costs
th~t may then be compared. Included in the annual operating costs are
a number of misce~laneous charges Which cont~ibute to totals for
transmission and s~t.ions as follows •.
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Oper~tinq_~n.g. ~i11tenanca
Insurance
Interim replacement
Contribution in lieu of
taxes
Total annual operating
Aru'lual Operating Charges
{Percent of £_apital Cost} .
Transmissior1 Substation
1.00
0.10
0.15
2.00
.3. 2_5
2o00
0.10
0.15
2.00
The annual~ operating charges shown in Table E2. 5 have been capitalized -at ~ 3 percent interest rate over the 50-yr life of the transmission
system. lJ!he same annual charge rate$. have been used fo.r both ac and de
transmission on the a.ssumption that differences in operating costs due
to differences in canpletity will be adequately reflect,ed in the ..
diffex-ences in capital investment for a¢ and de plant.
capict.al.ized costs of losses for ac transmission lines were developed as
part of the exercise to determine econoMic conductor sizes. Loss
energy was valued at 3.5 cent/kW•h,. based on the results of the
generation planning exercise for the period under study. The capita-
lized total cost of loss for ac· transmission was derived by adding
transformer losses at o. S percent pet: terminal to the line losses. In
the case of HVDC transmission,. total terminal losses .were calculated at
1.25 percent and added to line losses to derive the capitalized cost of
losses shown for the de alternatives.
LaLli acquisition costs are-estimated for the line right-of-way only .• . ,
Land requirements at terminal J.ocati.ons are assumed to be similar for
both ac and de alternatives •
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E2. 3 -Result-!! •
Com,Parati ve costs of a<: and de transmission alternatives as shown in
Table E2.5 confinn that ac is. an appropriate choice for transmission
from Susi tna to load centers at .Anchorage and Fairbanks. The concl u-
sion i.s based on separate assessments of transmission costs to each of
~
the t"\110 load centers, and this implies the use of two 2-terminal de
transmission systems. Some de economies might. be achieved with an
alterna~a 3-terminal de arrangement, but any savings are unlikely to
overcome the indicated 15 per~~t margin favoring .ac transntission.
The economic conclusions are consistent with the res.Ults of other
studies for the load levels and transmission distances involved, and
they are considered adequate to support the selection of ac
transmission over HVDC for the Susitna project.
E. ..., 7
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TABLE E2 .1: AC TRANSMISSION TO ANCHORAGE DEVELOPMENT OF CAPITAL COSTS
Location . Details
.Devil Canyon breakers 345 kV
Cost Components
Unit
Quantity Cost
($M)
1.00
Overhead Transmission 3 cct, 345 ·kv, 2x954 kcmil
conductor -140 IDi route 420 0.279
Willow Terminal
West Terminal
Cables
· Anchorage Terminal
Terminal Sub't.otal
base
breakers
breakers
transformers
base
·breakers
breakers
transformers
VAR generation
345 kV
345 kV
138 kV
75 MVA
345 kV
345 kV
230 kV
250 ~
400 MVAR
4 cct, 230 kV, 3.7 mi
breakers .. 230 kV
Indirect costs (at 32 .. 5 percent)
Total Costs
..
1
14
5
3
1
14
15
6.
4
6
2.00
1.00
0.40
0.50
2.00
1.00
0.70
1.30
0.03
20.25
0.70
Station Cost
Component Total
($M) ($M)
5 •. 00
2~.00
14.00
2.00
1.50
2.00
14.00
10.50
7 .. 80
12.00
4.20
s.oo
19.50
46.30
4.20
75.00
24.38
99-.38
Line Costs
(.$M)
117.18
81.00
198.18
Total. Costs
($Ml!
-
-.... _ --
--
--
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297.5'6
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·: . . .. -: . . . . . -. . .. . :. . . .· . ··. . . ' . . . . .. . . -. . .. ' . . . : : :·· . . .
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TABLE E2. 2: HVDC TRANSMISSION TO ANCHORAGE DEVELOPMENT OF CAPITAL COSTS
.Location
Devil canyon
HVDC Transmission
overhead
Details
breakers 230 kV
Hvnc· 1, ·saG. 1 MW
2 bipolar circuits ±250 kV
2x1,780 kcmil conductor
Cost Components
Unit
Quantity Cost
, ($M)
0.70
0.044
140 mi route 280 0.250
Cable
Anchorage
AC Supply to.
Willow
Po·int Mckenzie
Transmission
Willow
Terminal Subtotal
. 2 bipolar circuits
3 .. 7 mi route
HVDC 1,586. 7 MW
breakers 230 kV
VAR generation 670 MVAR
breakers 2.30 kV
230 kV, 2 circuits
1,272 kcmil conductor
50 mi route
base 230 kV
breakers 230 kV
.breakers 138 k\1
transformers 75 MVA
Indirect Costs (at 32.5 percent)
. Total Costs
2
6
3
100
1
8
5
3
JB.50
0.044
0 •. 7
0.03
0.70
0.184
1.,50
0.70
0.40
o .. so
Station Costs
Component Total
($M) ($M}
4.20
69.81
69.81
4.20
21,10
2.10
1.50
5,60
2 .. 00
1.50
74.01
94.11
12.70
180.82
58.77
Line Costs
(.$M)
-
70.00
37.00
18.40
239,50 125.40
Total ~sts
($M)
-
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--·-
364.99
-------------'-----~ .
TABLE E2. 3! AC TRANSMISSION TO FAIRBANKS DEVELOPMENT OF CAPITAL _COSTS
Details
Devil Canyon bra akers 345 kV
2 cct, 345 kV, 2x795·kcmil overhead
Transmission conductor, 189 mi .route
base 345 kV
breakers 345 kV
Fairbanks Terminal
breakers 138 kV
tJ;ansformers 250 .MVA
reactors 75 MVAR
VAR generation 100 MVAR
Terminal Subtotal.
Indirect Costs (at 32.5 percent)
Total Costs
Cost Components
Unit
·Quanti t,y cost
($M)
3 1.00
378 0.256
1 2.00
11 1.00
6 0.40
4 0.90
2 0.83
0.03
Station costs
Component Total
($M) ($M)
3.00
2.000
11.00
2.40
3.60
1.66
3.00
3.00
23.66
26.66
8.66
35.32
Line Costs
($M}
96.77
96.77
Total C:asts
($M)
....
1.32.09 .. I
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TABLE E2 • 4 ~ HVDC TRANSMISSION TO FAIRBANKS DEVELOPMENT OF CAPITAL COSTS
Location .
Devil Canyon
HVDC Transmission
Details
breakers
HVDC
230 kV
700 MW
1 bipolar circuit
±250 kV, 2xl,272 kcmil
conductor
Fairbanks Terminal HV])C
breakers
700 MW
138 kV
VAR generation 245 MVAR
Te~~inal Subtotal
Indirect Costs (at 32.5 percent)
Cost Components
Unit
Quantity Cost
6
189
6
($M)
Oe700
0.044
0,200
0.044 ..
0.400
0.030
Station Costs
component Total
($M) ($M}
4.20
30.80
30.80
2.40
7.35
35.00
40.55
75.55
24.55
Line Costs
{$M)
37.80
Total Costs· 100.10 37.80
Tota11. Cos.ts
($M}.i
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0
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TABLE -E2.5: SUMMARY OF COMPARATIVE COSTS AC VERSUS DC TRANSMISSION
eomparative Costs - $ Million
Transmission to Anchorage -----------------------=-Transmission to Fairbanks
Cost-Components AC DC AC DC
Line Costs 1 line capital 1 line capi~a~i7ed O&M 3 land acqu1s1t1on {R.O.W.)
Station Costs _ 1 stat~on cap~tal_ 2 stat~on cap1talized O&M
Capitalized Cost of Losses 4
Tota.l Costs
198.18
165.72
13.44
99.38
108.67
83.87
669.26
-
125.40 -96.77 37""~n
104 .. 86 80.92 3l.~b1.
8.40 14.18 i:~S6
239.59 35.32 100 lo ··'. ~
262 .. 00 38.62 109,4.6
74.94 13.12 16.,1()3
815.19 279.53 303,16
~Lin: an~ station capital_ costs are de:rel.oped in :able~ E2 .1 to E2. 4. . . _
Cap.1tetlJ.zed -O&M charges 1nclude O&M, 1nsurance, 1nterun replacement and contr1but1ons in lieu of taxe;s. Th~se
annual charges total 3.25 percent of transmission capital and 4.25 percent of station capital1 and they at"G
3 capitaliz7d .o:rer 5~ years at 3 percent~. _ _ _ _ . __ _ .. _
Land acqu1s1.t~on (R.~O .. W.) costs are est~m~tedat $96,000/m1le and $75,000/mJ..le for 345 kV, 3 cct and 2 'cct trans-
misS:iOll respectively, and $60,000/mi1e and $40,000/mile for ±250 kV de 2-circuit and single circuit,
4 respectively.
Losses are valued at 3.5¢/kW·h, and they are capital.i~ed. over the 50-year line life at 3 percent.
"!.
.. · .· ... · ·.· . ·-·~· .. ·· · .. · ..... ·· · .. ···.·. . ' ;~ '·. '. "·~-. . . ~~ . ) ·_ · .. -. : . ~ . . <
., . :_ . -~ . ' ·.
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.. -.:_,c~~~-==~· ==~·,, -~z~t\ v. --~ .. ·:--c-: . -~--~=· 230 KV
~ t<NtK
-·--==--"""'= -·~~,~-·-·:.-~.C~'--"'-·. r-...:2 -~ --·-~-----------
,.ANCHORAGE
345 KV AC ALTERNATIVE · -
4X397 MW
230 i<V
,.
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G X250 MVA ·
WEST TERMINAL -WU .. LOW
230 KV
POINT MACKENZIE WILLOW
~~~~~~----~~~~~~----~~~------------------/
KNlK
{BIPOLAR 2. X 1780 KCMIL ·
2.-CtRClUTS )
670 MVAR··· ·· ARM
ANCHORAGE-
±250 KV HVDC ALTERNATIVE
>~~ .
'DEVIL CANYON
230KV I
DEVIL CANYON .
.-,_, -:
. " . •. .~;;;.:.~-: :. •-,: . :;::-_: ·-~::...-:-:::.::::;-; ·--~--. ~ ;;-...o.=..-.-. ..• .
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DEVIL CANYON
. 345 t<V .AC ALTERNATIVE
230 KV
DEVIL CANYON
. ± 250 KV HVDC. ALTERNATIVE
0 '
( 3 tJ -.2 X -195 KCMIL
2 ... ClRCUITS ) .
,;
.. ·75 MVAR
. 75 MVAR
( BIPOLAR 2 X 1272. KCMIL. ·
ONE ClRCU IT ')
. , ..
. CQM:PAR.ISON OF'· HVOC VERSUS >AC T
. '
FAI~BANKS
; .
r· . t
. t -.
' '138 KV ~
. ~-
t3·8 ):kV .
I,·-.
. . .. . " -·~ --~t
. '$.'
JJr;:
~t~~ ~-
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