HomeMy WebLinkAboutComparative Economic Analysis of Electric Alternatives for Angoon Alaska 1984" .
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A COMPARATIVE ECONOMIC
ANALYSIS OF ELECTRIC
ENERGY ALTERNATIVES
FOR ANGOON. ALASKA
PREPARED BY FEBRUARY. 19S4
ALASKA POlMER AUTHORITV ------~
TABLE OF CONTENTS
PAGE
Sect ion A - I NTROD UCTION ••••••••••••••••••••••••••••••••••••.••••.•• 1
Section B -SUMMARY AND RECDI~I~ENDATIONS ••••••••••••••••••••••••••••• 2
Sec t ion C - F LIT UR E LOAD S •••••••••••••••••••••••••••••••••••••••••••• 7
Section D -FlITlRE CDST OF POWER PROVIDED BY 11-IREA DIESEL SYSTEM ••• 13
Section E -11-IE ECDNa-1ICS OF A FAVORITE BAY HYDROELECTRIC PLANT •••• 24
Section F -ntE THAYER mEEK HYDROELECTRI C PROJECT. •••••••••••••••• 42
Section G -OTHER ENERGY 11-IEGlNOLOGIES ••••••••••••••••••••••••.•••• 44
Section H -(l]MMENTS RECEIVED FRO'<1 REVIEw AGENCIES ••••••••••••••••• 45
APPENDIX A -BENEFIT:alST RATIO SENSITIVITY ANALYSES
APPENDIX B -ALASKA ffiWER AUfHORIlY PROJECT EVALUG.TION PROCEDLRES
page 1
A -INTRODU CTION
Thi s report is the resul t of work performed by the Anchorage office of
Acres American Incorporated in 1983 at the request of the Alaska Power
Authority.
As a resul t of a number of reconna i ssance-leve 1 and other stud i es do ne
for APA, there is a good deal of interest in the developnent of a small
hydroelectric site near Angoon. Because these earlier works 'were done
over a span of years, their cost estimates cannot be compared directly
from one report to another. Thus, an 01 d report IS estimate may not
have much relevance in light of current costs of operating the diesel
generating systsn in Angoon. It is the goal of this report to put the
cost estimates of the earl ier works on a common economic base (1983
dollars) so that the value of the hydro plant(s) proposed can be com-
pared to the costs of continued dependence upon diesel-produced
el ectri ci ty.
This report examines the economics of a salmon hatchery in concert with
the costs of the hydro facility. Since a hatchery would likely be
"required" if a hydro plant and its dam were to be built near Angoon,
this is considered to be a reasonable approach. Current Alaska Divi-
sion of Fish and Game policy seeks to protect salmon habitat where
possible, and the inclusion of a hatchery in a hydro project would
mitigate the loss of spawning habitat.
page 2
B -SUMMARY AND RECOMMENDATIONS
It is the general finding of this report that the developnent of a
small hydroelectric facility on Favorite Bay Creek may have economic
advantages for the commun i ty of Angoon when compa red to the present
system which uses diesel fuel for power generation.
In the eight months between the issuance of the draft version of this
report and the final, State agencies have had an opportunity to compi le
data on the value of salmon harvested from Southeast Alaska waters in
1983. Many of the assumptions used in the draft report regarding the
value of fish to be taken by the Angoon Aquaculture Association have
been significantly altered by using this more recent data. In contrast
to the support given to the Falls Creek project in the draft, it now
appears that such an enthusiastic endorsement should not be given with-
out further investigation of the volatility of the salmon market and
its possible future trends. The Monte Carlo techniques introduced in
Appendix A attenpt to probe the impl ications of varying salmon prices
and load growths. The reader is cautioned to interpret the results
given in Appendix A as tenative.
There is no available source of energy which can produce "cheap"
electricity for the Angoon. Electricity produced at a Favorite Bay
site' and distributed through the existing Tlingit-Haida Rural Electric
Associ ati on system wi 11 cost about $0.34 per ki lowatthour. This is
about the same as would be paid for diesel power in 1988, the first
year that a Favorite Bay hydro plant is assumed to be available. The
advantage of the hydro energy is that it will not escallate as the
price of fuel oil rises. The cost of electricity to the consumer would
be expected to remain stable at the $0.34/kWh level over the lifetime
of the project. Diesel-generated power, on the other hand could be
expected to rise to $0.37 to $0.44 per kWh (in 1983 dollars) by the end
of the 20th century (see Figure 1).
Other alternatives, including another hydroelectric site, were not
found to have any economic advantage for Angoon.
The economic advantage of the Favorite Bay hydro site disappears at low
energy use rates because of the high fixed costs involved in such a
pl ant.
If a hydro plant were to be built at Favorite Bay, it is probable that
a hatchery would be required by ADF&G to mitigate salmon habitat
losses. An appl ication has been made to ADF&G by the Angoon Aqua-
culture Associ at; on for a permit to bu-lld a sa lmon hatchery at Favori te
Bay. A pennit will not be granted without provision for an impoundment
area (dam and reservoir) to ensure adequate water suppl ies during times
of low water or during the winter when the stream is frozen.
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./ -..-
0.40 ./
(I) ..-
\ / ./ 2)
,~ 3) ./ ~ ,..,.,
r--........
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0.30 (2
0.20
0.10
o
'78 '88 '93 '98 '03
YEAR
Notes:
1. Curve (1) -(1) shows eiler9Y prices under the assumptions
given in low-growth case if THREA diesel generation is
continued.
2. Curve (2) -(2) shows energy prices under the assumptions
given in hi~h-growth case if THREA diesel generatior. is
continued.
3. Curve (3) -(3) sho\,/S energy prices with a Favorite Bay
hydrQ plant comino on-line in 1988 under the assumptions
given in the hiqh-growth case. Energy prices with low
consumption are off the top of this graph.
4. No consideration is given to any state subsidy programs.
FIGURE I -ANGOON ELECTRICITY PRICES
-
-
-
-
-
-
-
---
-
.-.,.. ..
-
page 4
This report assumes that electric utility customers would not be \'Iill-
ing to pay any more for electricity generated by a hydro plant than
they do for a diesel plant. It is further assumed that there are no
available "subsidies" and that the hydro plant and hatchery must "pay
their own 'Nay." This constraint limits the revenue generated by the
power pl ant to a level adequate to pay for those structures di rectly
associated with power generation (powerhouse, generators, transmission
line, etc.) and 25 percent of the cost of the dam and intake structure,
which is "shared" with the hatchery. Later, the report shows that
salmon harvest revenues to the Aquaculture Association may not be suf-
ficient to pay for 75 percent of the dam and intake structure costs.
Hatchery opera ti on and i ncrea sed product i on a t the Angoon co 1 d storage
plant would drive up energy use, reducing the per-unit cost of
electricity for all consumers in the village.
It should be kept in mind while reviewing this report that the intro-
duction of a hydroelectric plant and salmon hatchery at Angoon has
implications far beyond the supply of electricity at a stable price.
The improvement in the area's salmon fishery may be able to provide a
significant improvement in the general standard of living for many of
Angoo n 's res ide nt s.
Before construction can be started on a Favorite Bay hydro plant,
detailed studies are needed to verify many of the assumptions used in
this study. It is conceded that much of the work presented in this
report (and no doubt in reports by others) is rough. This report
serves to guide others to focus their attention on the Favorite Bay
hydro project, as it seems to provide the most benefits to the village
of Angoon for the forseeable future. The studies listed below are
recommended. It is the opinion of Acres' staff that they should be
commenced in the nea r future so that unforseen ci rcumstances do not
unnecessari ly del ay the compl etion of the project:
1. A continuous stream gaging station should be established in the
vicinity of the proposed dam site. Existing streamflow data are
largely synthesized from llSGS data taken at other locations and ver-
ified, where possible, by occasional measurements taken at the site.
2. Geotechnical explorations should be undertaken at the dam site
to establ ish foundation condi tions.
3. Area geology should be thoroughly explored to identify candidate
sites for quarries which would be needed for a rock-or earth-fill
dam. Quantities on the order of 100,000 to 150,000 cubic yards of
rock would be needed for a Favorite Bay dam. An Lrlknown, but less-
er, quantity of aggregate would also be needed for the construction
of the hatchery and powerhouse •
page 6
The next step in the analysis of energy economics for a small community
involves the examination of those energy resources readily available.
In the case of Angoon, that would incl ude diesel generation (as cur-
rently provided by the Tlingit & Haida Regional Electrical Authority,
or "THREA"), hydroelectric power from a proposed site on Falls Creek,
and perhaps wind energy.
Finally, the cost of supplying the forecast energy demands with the
available alternatives is studied. The life-cycle (or "present worth")
costs of the alternatives are compared to establish the most economical
means of providing energy to the community.
In the study of energy economics at Angoon, an interesting case devel-
ops as a result of the availability of the Falls Creek hydro site. If
the hydro site is not developed, it is possible that the village could
move into a future of very low energy growth. Under most ci rcum-
stances, a conservative approach to take when evaluating a hydro plant
is to assume a low energy growth rate. This makes the electricity from
such a plant considerably more expensive. However, in the case of
Angoon, such an approach is inappropriate. If a hydro plant is built,
a hatch ery mus t be bui 1 t to m i ti ga te the loss of a sa lmon spawni ng
stream. The hatchery will, by itself, provide a large increase in the
energy used in the community. The higher load forecast which results
from the existence of the hatchery will cause the economic calculations
to show less expensive electricity from the hydro site. For this
reason, the Falls Creek hydro plant will not be evaluated using the
lowest-growth forecasts.
The economics of the Falls Creek hydro facility will be evaluated under
two assumptions of energy growth: (1) The dam and hatchery will be in
place, but the cold storage plant (the other "large" load in Angoon)
wi 11 opera te only 3 months out of the yea rand (2) same as 1 except
that the cold storage plant will operate 10 months of the year as a
result of the increase in the area1s bottomfish industry.
page 7
C -FU llJ RE LOADS
A key elEment in the rost of electricity to the consumer from a partic-
ular power systEm is the amount of energy purchased from that system.
In general, the more energy consumed or purchased, the less each unit
of energy should cost.
Studies done by Harza (1979), Retherford (1981), and Tryck, Nyman &
Hayes (1981) have all based their load growth projections on forecast
work done by the Tlingit & Haida Regional Electrical Authority (THREA)
in 1979. Since that time, THREA has developed a revi sed forecast of
energy use and demand growth (1983). The new forecast anticipates less
growth of the Angoon load than did the old one. The differences are
sh ow n i n th e ta b 1 e be 1 ON :
TABLE 1 THREA ENERGY FORECASTS
ENERGY USE POWER DEMAND
OLD NEW PCT. OLD NEW PCT.
YEAR FORECAST FORECAST CHANGE FORECAST FORECAST CHANGE
1978 600 MvJh 680 MvJh 171 kW 171 kW
1983 1,200 1,050 -12.5 304 295 -3.0
1988 1,290 1,200 -7.0 327 327
1993 1,390 1,200 -13.7 353 340 -3.7
The approach used by THREA to produce their forecasts was to examine
the historic trend of energy use (and power demand) for several years
prior to the forecast. These trends were then used to develop math-
anatical descriptions of future load growth rates. This method has
been used for a number of years by uti lities which are financed by the
Rural Electrification Administration (REA).
The REA method is limited in its ability to anticipate the effect of
possible capital developnents or political actions which may cause
alterations in the trend of energy growth rates. Any "adjustment" to
the forecast must be made "by hand" by the REA investigators. To the
extent possible, THREA has made these adjustments. However, they have
not ronsidered the impact which the rold storage plant or the hatchery
woul d h ave on energy us e growth. One rea so n the co 1 d storage pl ant was
not included in THREA forecasts is that the nearest power line to the
pl ant is about three miles away. Although the construction of a new
power line to the cold storage plant may be expensive for the plant, it
is probable that, over itls lifetime, power purchased from THREA may be
less expensive than self-generated power. Additionally, the new THREA
forecasts do not take into account the effect which the el imination of
the state IS Power Cost Assi stance Program would have on energy use in
Angoon.
page 8
PCAP effectively reduces the cost of electricity to the consumer as
much as 50 percent and has greatly infl uenced recent growth of
electricity consumption in rural communities. As an example, in Angoon
during 1982 (the first full year the subsidy was available), 1,000,354
kWh were sold. This represents an increase of about 18 percent over
1981 energy sales, which were thEmselves a decrease from 1980 Angoon
sales. Even with peAP available, it is our understanding that electric
bi lls in Angoon are frequently over $100. Without PCAP, this same bi 11
(for about 700 kWh) would be about $200. Such an expenditure would
take a very significant part of a family's disposable income. It would
be likely that the discontinuance of the PCAP subsidies would lead to a
reduction in residenti al energy consumption.
Public cnnsumers (schools, community buildings, street lighting sys-
tems, etc.) also benefit from PCAP. They are el igible for PCAP support
for an amount of electricity which is dependent upon their village's
population. The elimination of PCAP would undoubtedly cause signifi-
cant hardship for many rural governments.
Presently (for fiscal year 1983, which ended July 1, 1983), the P(]I.P
subsi dy is set up to cover 95 percent of a resi denti al customer's el-
ectricity cost over 14 cents/kWh for the first 600 kWh of their con-
sumption. FlJ1ding for PCAP in fiscal year 1984 was not made available
by the 1 egi s 1 ature to the ex tent th a tis h as been in previ 0 us yea rs.
It is 1 ikely that the program's admini strator, the A laska Power Author-
ity will raise the cost ceiling from 14 cents/kWh to some higher level
(as yet unknown) to make their available funding go farther. There is
some sentiment in the legi sl ature to do away with this program enti re-
ly, something which becomes more probable as state oil revenues con-
tinue to falloff.
For purposes of this report, it will be assumed that PCAP subsidies
will be available (although is diminishing amounts) through the end of
calendar year 1986. Since the 1983 legislature has left the program
intact and 1984 is an election year, it is unlikely that the 1984
legislature will eliminate the program. This report will assume that
the 1985 legislature will tenninate PD\P altogether with funding to end
at the end of calendar year 1985 (a simplifying assumption, since funds
w"ill likely rot cnntinue past JlJ1e 1985, the end of the fiscal year).
In 1986, there will be an immediate 20 percent reduction in residential
consumption. As oil prices continue to rise, there will be little to
no growth in that sector throughout the remainder of the forecast per-
iod (1983 -2002). Public and commercial users will cnntinue to use
the same amount of energy they woul d h ave if the program had co nt i nued.
An lJ1fortunate effect of this reduced energy use is that each unit of
energy (kW h) wi 11 have to cn st the cn nsumer more to pay fo r the uti 1 i-
ties' fixed costs (equipnent capitalization, administration, fixed
maintenance, etc). This will have the effect of reducing consumption
further, driving kWh prices up more, reducing consumption, etc, etc.
-
... -
-
...
-
.. '
-
-
, ....
-
-
-
-
page 9
We wi 11 use the ll-lREA 1983 forecast as an upper 1 imit for Angoon energy
consumpti on and load (after appropri ate changes have been made to take
into account the col d-storage pl ant). The lower 1 imit forecast will
take ll-lREA's forecast and modify it to show a 40 percent reduction in
residential consumption occurring in 1986 with growth thereafter due
only to new housing units. We will assume that 2 new homes will be
bui It in Angoon each year from 1983 through 1987, 1 home per year from
1988 th rough 1997, wi th no new homes added for 1998 -2002. In 1982,
the "average" Angoon residenti al customer used about 4,370 kWh (360 kWh
per month). This will be considered to remain constant from 1983 to
1986 when the annual residential consumption will fall to 3,311 kWh
(276 kWh per month).
It is assumed that: (1) the new cold-storage facility will become fully
operational in 1985; (2) if it is used only for the salmon season, it
will only be used for three months each year; (3) if a bottornfish
industry develops in the area, the cold-storage plant could be operated
for 10 months out of the year. The new cold-storage plant load is
calculated as follows:
TABLE 2 --COLD STORAGE PLANT LOADS
Power 3 month 10 month
Load Demand Load Factor MWh/month MWh MWh
100 hp Air compr. 76 kW 0.6 33 99 330
25 hp I ce maker 20 0.3 4 12 40
15 hp Process equi p. 12 1.0 9 27 90
15 hp Refri geration 12 0.6 5 15 50
L i gh t s & Mis c • 5 1.0 4 12 40
TOTALS 125 kW 55 165 550
Note: 1 M.oJ h = 1 ,000 kWh
In addi ti on to th is co 1 d-storage pl ant, there is some po ss; bi 1 i ty of a
fish hatchery being constructed in Angoon. It will be assumed to begin
operation in 1988, with the follONing loads:
TABLE 3 --HATCHERY PLANT LOADS
Power
Load Demand Load Factor I"1Wh/month MWh/year
3 20 hp P LITIPS 40 kW 0.6 17 204
Lights & Misc. 5 0.7 2 24
TOTALS 45 kW 19 228
page 11
TABLE 4
ENERGY USE AND POWER DEMAND FORECASTS FOR ANGOON, ALASKA
1983 -2003
ACRES' FORECASTS
1979 THREA 1983 THREA HI GH-GROWTH t{)DERATE-GROWTH LOW-GROWTH
YEAR FORECAST FORECAST FORECAST FORECAST FORECAST REMARKS
kW MWh kW MWh kW MWh kW MWh kW MWh
1983 304 1,200 290 1,060 289 1,020 289 1,020 289 1,020
1984 292 1,577 292 1,028 292 1,028 2 nel'/ homes
1985 419 1,587 419 1,202 419 1,202 cold storage plant on-line; 2 new homes
1986 424 1,596 424 1,211 424 1,211 2 new homes
1987 429 1,605 429 1,220 429 1,220 last year of PCAP; 2 new homes
1988 327 1,290 330 1,200 477 1,735 477 1,350 432 1,122 hatchery/dam in moderate & high; 1 new home
1989 479 1,739 479 1,354 434 1,126 1 new home
1990 481 1,743 481 1,358 436 1,130 " " "
1991 484 1,746 484 1,361 439 1,133 " " "
1992 487 1,749 487 1,364 442 1,136 " " "
1993 353 1,390 340 1,200 489 1,753 489 1,368 444 1,140 " " "
1994 491 1,757 491 1,372 446 1,144 " " "
1995 494 1,762 494 1,375 449 1,147 " " "
1996 497 1,763 497 1,378 452 1,150 " " "
1997 499 1,767 499 1,382 454 1,154 " " "
I
1998 499 1,767 499 1,382 454 1,154 I no additional homes through study period
1999 499 1,767 499 1,382 454 1,154 I
2000 499 1,767 499 1,382 454 1,154 I
2001 499 1,767 499 1,382 454 1,154 I
2002 499 1,767 499 1,382 454 1,154 I
Notes: The differences in Acres' "Low," "Moderate," and "High" growth forecasts resu It from: (1) cold storage plant ope raged only 3
months per year, no hatchery in the "Low" forecast; (2) cold storage plant operates 3 months, hatchery in operation in the
"Moderate" forecast; (3) cold storage plant operates 10 months per year, hatchery in operati on in "H i gh" g rOl'/th forecast.
,.. 2.500..,.... _____ r-____ --r _____ -r-____ ---,-____ ----,
I
3
~ w
2 :a.ooo -+------+------+-----+-----__+-------1
D -HIGH
~ . -~--.~ ........ ~ .... --.--.--.--. .. 11 ------
II:: / ~ r--' J 1.!500 -+------1__-_--+-_+-----+------+-------+
OJ n .A MOOERATE 2 !I ___ ~-~...-jI-"'llllIP----.. ~----D 1 '\e"791~ r-.. ~! [19S3) _ Lew U . ...-! r.-~ -r ~ .,------~----.. ~----
~ 1.000 +-__ ~f1!..,....4~~-;,-+ I--+-+----t-------+-------f ~ ;I
2 w
!500-r ___ ~I--+_-~-_r_+-----+_----__+----___1
0-r-+_+~-I__+_+-~~_+-+-+~-~+_+_~_r_r __ _4~-~+-~~
'7s
SYMBOLS:
_____ ACRES'
_____ T&HREA
'S3 'SS '93 '9S '03
L YEAR
HATCHERY OPERATJON BEGINS
[EXCEPT IN LOW FORECAST)
'--PCAP SUBSIOY ENOS
'--CCLO STORAGE PLANT
COMES ON-LINE
[HIGH FORECAST: 10 MOo/YR.)
[MOO. II 3 II II)
[LOW II 0 II II)
"--FIRST FULL YEAR OF
PCAP SUBSIDY
FORECASTS
II
FIGURE 2
FORECASTS OF ENERGY
CONSUMPTION IN ANGOON
page 13
D -FUTURE COST OF POWER PROVIDED BY THREA DIESEL SYSTEM
The existing power systen at Angoon, owned by the Tlingit and Haida
Regional Electrical Authority (THREA) consists of three diesel units
ra ted at 250, 300, and 400 kW for a fi rm capaci ty of 550 kW (250 + 300
kW, assuming that the largest of the machines may be unavai lable for
service). Since the greatest load anticipated in Angoon for the next
20 years is only about 360 kW (see Part C), it can be seen that the
generating capacity will not have to be increased. This report will
assume that, when the existing units are replaced at the end of their
service lives, they will be replaced with identical units.
Because electric utilities are capital-intensive, they have very large
annual costs which are fixed. That is to say that even if THREA were
to stop generating power altogether, they would have ongoing financial
obligations to cover such itens as financing of their equip11ent, admin-
istrative charges, maintenance of equipment and power lines, insurance,
taxes, etc. In 1982, of THREA's expenditures of $2.25 million, just
less than half (about $1.1 mill ion) were fixed expenses. Because of
these high fixed charges, utility systems which sell relatively small
amounts of energy (such as THREA) have cost structures which are sensi-
tive to changes in sales levels: the more energy which is sold, the
less its per-kWh price becomes. Conversely, if less energy is sold,
each unit of energy must be sold at a higher price.
Using information obtained from THREA's 1982 Annual Report to the
Alaska Public Uti lities commission, Acres has broken expense data into
categories of fixed and variable costs. These are summarized on Table
5 on the following page.
Total fixed costs for the system in 1982 were $1,108,704; variable
costs were $1,140,107. Since not a 11 of the fixed costs can be reason-
ably charged to anyone of the five THREA vi llages, they have been al-
loca ted on a per-customer basi s. In 1982, THREA reported that they had
a tota 1 of 779 customers, with 144 in Angoon. Therefore, the fixed
costs allocated to Angoon for 1982 were:
$1,108,704 x (144 t 779) = $204,946
Variable costs were allocated equally thro~ghout the system on a per-
kWh basis. These variable cost rate was calculated to be:
$1,140,107 t 6,562,000 kWh = $0.1737/kWh
Part of these variable costs are due to fuel ($780,475 in 1982, or
68.46 percent of the total variable costs), the renainder are due to
maintenance and bad debt expenses ($333,862 and $25,770 respectively).
The per-kWh cost of fuel can be expected to escallate in real terms
(1983 dollars) at a rate greater than general inflation. Calculations
wh i ch fo 11 ow assume that fuel pri ces will i ncrea se 2.5 percent faster
(on an annual basis) than general inflation. All other costs are
assumed to renain constant relative to the general inflation rate.
page 14
TABLE 5
ALLOCATION OF FIXED AND VARIABLE COSTS IN THE THREA SYSTEM
(Based upon data taken fran THREA's 1982 Annual Report to APtI:)
VARIABLE COSTS
Item
** * F ue 1 • • • • • • • • • • • • • • • •
* Generation Expenses .•.••.•••
* Mi sce 11 aneous 0 ther Power Genera ti on
Uncollectible Accounts •...••.
Expenses.
.$
Amount
780 ,475
276,615
57 ,247
25,770
TOTAL VA RIABLE CO STS: $1,140,107
FIXED COSTS
Item
Operation Supervi sion and Engi neering. . . . . • .. • .$
R en t s .. • • .. . .. • • .. • • • . • .. • • . . . . . .. ..
Mai ntenance Supervi sion and Engi neeri ng (Generation)
Maintenance of Structures ••••..••.••....
Maintenance of Generating and Electric Plant. . . .. ••
Maintenance of Miscellaneous Other Power Generation Plant. .
Operation Supervision and Engineering .•...•.
Overhead Line Expenses. . • • • • . . . .. • ••.•
Street Lighting and Signal System Expenses •....•
Meter Expenses • • . . . • . • • • • . . • . . . . • •
Miscellaneous Distribution Expenses ...••...••.
Maintenance Supervision and Engineering (Distribution) .
M ai ntenance of 0 verhead Lines. • • . . . • . . • .
r~ai ntenance of Underground Lines .••••.•...•••.
Maintenance of Street Lighting and Signal Systems ••.
Maintenance of Meters .....•.
Supervision (Custaner Accounts) ••
Meter Reading Expenses •••..•.•••
Custaner Records and Collection Expenses •.••.
Actninistrative and General Salaries •.
Offi ce S uppl i es and Ex penses . .
Outside Services Employed •..
Property Insurance .••.•..•.•••
Injuries and Damages ••••••
Employee Pensions and Benefits •.•••
Franchise Requirements .•••
Regulatory Commission Expenses ••
(conti nued on
Amount
22
29,876
5,729
1 ,039
150,111
773
1,247
25,116
132
7 ,360
18,817
1 ,303
7 ,746
75
1 ,558
357
7 ,120
5,144
60 ,389
129,099
50,908
17 ,559
13 ,592
32,265
110 ,326
45,156
9,913
nex t page)
*Cost of these items may be el iminated by al ternati ve energy sources.
**Cost of fuel is expected to rise relative to inflation.
FIXED COSTS (continued)
Item
Genera 1 Adverti si ng Expenses.
Miscell aneous Genera 1 Expenses
Depreci ati 0 n . . . . . • .
Tax es. . . . . . . . . . . .
Interest on Long-Term Debt.
Interest and Dividend Income
. $
page 15
Amount
19,872
27,826
206,436
9,793
126 ,926
(14,881)
TOTAL FIX ED CO STS: $1,108,704
It is important to keep in mind that under varying circumstances, many
of the costs called "fixed" or "variable" here may SNitch categories.
Di fferent uti 1 i ti es have developed thei r OlIn method of di fferent i ati ng
between fixed and variable costs.
It is also important to note that the fixed costs are "fixed" only over
a rel ati vely narrow range of energy production and power demand. The
retention of the allocation of fixed and variable costs in the manner
discussed here is done for simplification of the report calculations.
page 16
There are only a few of these costs which woul d be decreased or el imin-
ated with the construction of a hydroelectric plant (or other alterna-
tive energy source) at Angoon. These are:
• Fuel
• Generation Expenses
• Miscellaneous Other Power Generation Expenses
($700,475 in 1982)
($276,615 in 1982)
($ 57,247 in 1982)
The total of these "displaceable" costs ($1,114,337) represents almost
50 percent of THREA's costs which we have allocated to Angoon.
The "benchmark" against which other alternatives must be compared is
the existing THREA diesel system. Throughout this report, this bench-
mark system is called the "base case" plan. The costs associated with
operating this system on into the future are calculated for each year
of the study. In this case, our study must extend for the enti re 50
year 1 ife of the proposed hydroel ectri c pl ant which will be assumed to
be put "on-line" in 1988. Therefore, the study period will be 1983 -
2037. Load growth and fuel price escallation are both assumed to stop
after 2002. The "net present worth" of all of the future years' is
calculated using a 3.5 percent annual rate.
The calculations used to produce the net present worth of the Angoon
are shown on Tables 6 and 7. Note that the "Approximate Energy Sales
Price" shown does not include any subsidy discounts.
The construction of a waste heat recovery system on the THREA generat-
ors by the Alaska Power Authority complicates the calculation of utili-
ty system economics in Angoon. The heat energy recovered by that sys-
tem is being used by the sewage treatment plant, the grade school, the
high school gym, and the teachers' quarters. It is estimated that this
recovered waste heat eliminates the need for about 14,600 gallons of
heating oil in these buildings each year. At current prices of $1.98
per gallon (delivered), this heat is "worth" about $28,900 per year.
The A laska Power Authori ty has no pl ans to charge for the heat, so the
affected building owners realize a combined "benefit" of $28,900 each
year. This is treated as a savings against the annual cost of power
production in Angoon, even though the village residents will never see
a recduction in their electric bills as a result of the waste heat sys-
tem installation. The installation and annual maintenance costs must
be added to the system costs as well. These calculations are shown
separately, on Table 8 so that the energy costs shown on Tables 6 and 7
will not be distorted by the economics of the waste heat system.
Present worth calculations of the system operation for the years 1983
through 2037 (50 years after the assumed on-line date for a Favori te
Bay hydro plant) assuming an interest rate of 3.5 percent shows a
lOHgrowth plan to have a present worth of $11,657,000. Similarly, the
high-growth plan has a present worth of $15,049,000. When the benefits
of the waste heat system are considered (which will reduce each of
page 17
these costs by $604,000) , we reach net present worths of:
L (}J -ffi OW 111 BA SE CA SE :
HI (}l -ffi OW 111 BA SE CA SE :
The "ne t present worth" 0 f a pl an is the
have to be invested in January of 1983 to
that plan while earning a particular rate
annually) .
$11 ,053 ,000
$14,445 ,000
amount of money which woul d
cover all future expenses of
of return (in this case 3.5%
page 18
TABLE 6
COSTS OF BASE CASE PLAN FOR ANGOON UNDER LOW-GROWTH FORECAST
1983 -2037
VARIABLE COSTS I FIXED COSTS TOTAl I APPROX. I PRESENT
DI SPLACEABLE I NON-DISPLACEABLE I TOTAL SYSTEM I ENERGY I WORTH
LOW-GROWTH ESCALATING NON-ESC ALA TI NG I NON-ESC ALA TI NG I VARIABLE COSTS I SALES I OF TOTAL
FORECAST ( Fuel) (O&M, etc.) '(UncoIl. Accts.) , COSTS TOTAL I PRICE I SYSTEM COSTS
YEAR (MWh) ($/kWh) ($/kWh) , ($/kWh) I ($1 1 000) ($1 1 000) ($1 1 000) I ($/kWh) , ($1 1 000) , I , ,
1983 1,020 0.119 O.OSl , D.004 , 177 2DS 382 I .37S , 369
1984 1,028 0.122 O.OSl , D.004 I 182 20S 387 I .376 , 361
1985 1,202 D.12S O.OSl I 0.004 , 216 2DS 421 I .3S1 , 38D
1986 1,211 0.128 O.DSI , D.004 , 222 2DS 427 I .3S2 , 372
1987 1,220 0.131 O. DSI 0.004 , 227 2DS 432 I .3S4 364 , I
1988 1,122 O.13S O.OSl D.004 , 213 2DS 418 , .373 34D
1989 1,126 0.138 O.OSl D.004 I 217 2DS 422 , .37S 332
199D 1,130 0.141 O. DSI D.004 , 221 2DS 426 I .377 324
1991 1,133 D.14S O.OSl D.004 227 20S 432 , .381 317
1992 1,136 D.149 O.OSl D.004 232 20S 437 , .384 31D ,
1993 1,140 0.lS2 O.DSI 0.004 236 2DS 441 , .387 302
1994 1,144 0.156 0.D51 0.004 241 20S 446 I .39D 29S
1995 1,147 0.160 O.OSl D.004 247 2DS 4S2 , .394 289
1996 1,lSD 0.164 O. DSI 0.004 2S2 2DS 4S7 I .397 282
1997 1,lS4 0.168 O.DSI 0.004 2S7 2DS 462 I .401 276
I
1998 1,lS4 D.l72 O.DSI D.004 262 2DS 467 , .4OS 269
1999 1,lS4 0.176 O.DSI D.004 267 2DS 472 , .4D9 263
2000 1,lS4 D.181 O.OSl 0.004 272 2DS 477 , .414 2S7
2001 1,154 D.186 O.DSI 0.004 278 2DS 483 I .419 2S1
2D02 1,lS4 0.190 O.OSl D.004 283 2DS 488 I .423 24S
'D3 -'37 1,lS4 D.19O O.OSl 0.004 283 2DS 488 .423 4,669
TOT AL: ID ,867
page 19
TABLE 7
COSTS OF BASE CASE PLAN FOR ANGOON UNDER MODERATE-GROWTH FORECAST
1983 -2037
I VARIABLE COSTS I FIXED COSTS TOTAl I APPROX. PRESENT
MJDERATE I DI SPL ACEABLE I NON-DISPLACEABLE I TOTAL SYSTEM I ENERGY WORTH
GROWTH I ESCALATING NON-ESCALATING I NON-ESCALAT I NG I VARIABLE COSTS I SALES OF TOTAL
FORECAST I (Fuel) (O&M, etc.) I (Ureal!. Accts.) I COSTS TOTAL I PRICE SYSTEM COSTS
YEAR (MWh) I ($/kWh) ($/kWh) I ($/kWh) 1($1 1 000) ($1 1 000) ($1 1 000) I ($/kWh) ($1 1 000)
I I I I
1983 1,020 I 0.119 0.051 I 0.004 I 177 205 382 I .375 369
1984 1,028 I 0.122 O.OSl I 0.004 I 182 20S 387 I .376 361
1985 1,202 I 0.12S 0.051 I 0.004 I 216 20S 421 I .3S1 380
1986 1,211 I 0.128 O.OSl I 0.004 I 222 20S 427 I .3S2 372
1987 1,220 I 0.131 0.051 I 0.004 227 20S 432 I .3S4 364
I I I
1988 1,350 I O.13S O.OSl I 0.004 2S7 20S 462 I .342 376
1989 1,3S4 I 0.138 0.051 I 0.004 261 20S 466 I .344 366
1990 1,3S8 I 0.141 O.OSl I 0.004 266 20S 471 I .347 3S8
1991 1,361 I 0.14S O.OSl I 0.004 272 20S 477 I .3S1 3S0
1992 1,364 I 0.149 O.OSl I 0.004 278 20S 483 I .3S4 342
I I
1993 1,368 I 0.lS2 0.051 0.004 283 20S 488 I .3S7 334
1994 1,372 I 0.1S6 0.051 0.004 289 20S 494 I .360 327
1995 1,375 I 0.160 0.051 0.004 296 20S SOl I .364 320
1996 1,378 I 0.164 O.OSl 0.004 302 20S S07 I .368 313
1997 1,382 I 0.168 0.051 0.004 308 20S S13 I .371 306
I I
1998 1,382 I 0.172 O.OSl 0.004 314 20S S19 I .37S 299
1999 1,382 I 0.176 O.OSl 0.004 319 20S S24 I .379 292
2000 1,382 I 0.181 O.OSl 0.004 326 20S S31 I .384 286
2001 1,382 I 0.186 O.OSl 0.004 333 20S S38 I .389 280
2002 1,382 I 0.190 0.051 0.004 339 20S S44 I .393 273
'03 -'37 1,382 0.190 O.OSl 0.004 339 20S S44 .393 5,204
TOTAL: 11 ,872
page 20
TABLE 8
COSTS OF BASE CASE PLAN FOR ANGOON UNDER HIGH-GROWTH FORECAST
1983 -2037
I VARIABLE COSTS 1 rr XED COSTS TOTAl 1 APPROX. PRESENT
1 HIGH I DISPLACEABLE 1 NON-DISPLACEABLE I TOTAL SYSTEH I ENERGY WORTH
I GROWTH I ESC ALA TI NG NON-ESCALAT I NG I NON-ESCALATING I VARIABLE COSTS I SALES OF TOTAL
1 FORECAST I (Fuel) (O&M, etc.) 1 (U~oll. Accts.) 1 COSTS TOTAL I PRICE SYSTEM COSTS
YEAR I (MWh) I ($!kWh) ($!kWh) I ($!kWh) 1 ($1 ,000) ($1 1 000) ($1 1 000) I ($!kWh) ($1 1 000)
I 1 1 1 1
1983 I 1,020 I 0.119 0.051 1 0.004 I 177 205 382 I .375 369
1984 I 1,577 I 0.122 0.051 1 0.004 ·1 279 205 484 1 .307 452
1985 I 1,587 I 0.125 0.051 I 0.004 I 286 205 491 I .309 443
1986 I 1,596 I 0.128 0.051 I 0.004 I 292 205 497 I .311 433
1987 I 1,605 I 0.131 0.051 1 0.004 299 205 504 I .314 424
I 1 1
1988 I 1,735 0.135 0.051 I 0.004 330 205 535 I .308 435
1989 1 1,739 0.138 0.051 1 0.004 336 205 541 I .311 425
1990 I 1,743 0.141 0.051 1 0.004 342 205 547 I .314 415
1991 I 1,746 0.145 0.051 I 0.004 349 205 554 I .317 406
1992 I 1,749 0.149 0.051 1 0.004 357 205 562 I .321 398
I 1 1
1993 1 1,753 0.152 0.051 1 0.004 363 205 568 1 .324 389
1994 1 1,757 0.156 0.051 1 0.004 371 205 576 I .328 381
1995 I 1,742 0.160 0.051 1 0.004 375 205 580 I .333 371
1996 I 1,763 0.164 0.051 I 0.004 386 205 591 I .335 365
1997 1 1,767 0.168 0.051 I 0.004 394 205 599 1 .339 358
I I 1
1998 1 1,767 0.172 0.051 I 0.004 401 205 606 1 .343 349
1999 I 1,767 0.176 0.051 1 0.004 408 205 613 I .347 342
2000 I 1,767 0.181 0.051 1 0.004 417 205 622 1 .352 335
2001 I 1,767 0.186 0.051 I 0.004 426 205 631 1 .357 328
2002 1 1,767 0.190 0.051 1 0.004 433 205 638 1 .361 321
'03 -'37 1,767 0.190 0.051 0.004 433 205 638 .361 6,104
TOTAL: $ 13 1 843
page 21
TABLE 9 ----
VALUE OF HEAT DELI VERED BY ANGOON WASTE HEAT RECOVERY SYSTEM
VAL UE OF PRESENT
CAPITAL COSTS DISPLACED WORTH OF
($185,000 at 3.5 pet MAINTENANCE HEATING OIL NET NE T
fa r 15 yrs) COSTS (ese1. ® 2.5% ) BENEFITS BENEFITS
YEAR ($1,000) ($1,000) ($1,000) ($1,000) ($1,000)
1983 16.1 2.6 29.0 10.3 10.0
1984 16.1 2.6 29.7 11. 0 10.3
1985 16.1 2.6 30.5 11.8 10.6
1986 16.1 2.6 31. 2 12.5 10.9
1987 16.1 2.6 32.0 13. 3 11. 2
1988 16.1 2.6 32.8 14.1 11. 5
1989 16.1 2.6 33.6 14.9 11. 7
1990 16.1 2.6 34.5 15.8 12.0
1991 16.1 2.6 35.3 16.6 12. 2
1992 16.1 2.6 36.2 17.5 12.4
1993 16.1 2.6 37.1 18.4 12.6
1994 16.1 2.6 38.0 19.3 12.8
1995 16.1 2.6 39.0 20.3 13.0
1996 16.1 2.6 40.0 21. 3 13.2
1997 16.1 2.6 41.0 22.3 13.3
1998 16.1 2.6 42.0 23.3 13.4
1999 16.1 2.6 43.0 24.3 13. 5
2000 16.1 2.6 44.1 25.4 13. 7
2001 16. 1 2.6 45.2 26.5 13.8
2002 16. 1 2.6 46.3 27.6 13.9
'03-'37 16.1 2.6 46.3 27.6 264.0
NET PRESENT WORTH OF HEA T: $ 510.0
page 22
Sinc2 not 3.11 of the costs of the TI1REA syst811 would "go away" with the
introduction of an alternative source of power (such as a Favorite Bay
hydro plant), it is important to determine just how much money would be
saved if all possible costs were el"iminated. Table 10 shows the calcu-
lations of the annual "displaceable" costs of the TI1REA syst811 in
Angoon.
The calculations given show the savings which would result from a shut-
down of the TI1REA diesels compl etely for both the low-and the high-
growth plans. In 1990, for example, $217,000 would be saved in the
low-growth instance; $335,000 in the high-growth case. The present
worths of these annual savings are summed for the years 1983 -2037
wi th a resul ti ng sa vi ngs of $5,880,000, $6,870,000, and $8,807,000 for
the low, moderate, and high energy growth rates.
If the Falls Creek hydro plant is put into operation and the THREA
diesels were shut down, the waste heat system would be "out of
business." The loss of the heating system's benefits are counted as an
added cost to the hydro project. The present worth of the waste heat
system benefits for the years 1988 through 1997 must be added to the
present worth of the hydro proj ect co s ts. Note th at the ent ire
$510,000 of benefits from the waste heat system is not added. This is
because the benefit from the waste heat system over the period 1983
through 1987 is subtracted from the present worth of the TI1REA systen.
From the above discussion, it can be seen that the net present worth of
the Falls Creek hydro plant (or any similar alternative investigated
for Angoon) must have a net present worth of no more than about $6.4
million if our "moderate" growth rate is assumed or $8.3 million if a
higher forecast is used.
Of course, it is entirely possible that a particular alternative to the
THREA diesel system would not completely eliminate the fuel use. There
may be times in the future when the alternative could not produce suf-
ficient power to meet Angoon's needs (for exanple, if a generator were
down for maintenance). The numbers given above are general guidel ines
by which a particular alternative may be measured.
YEAR
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
'03-'37
I I DISPLACEABLE COST ITEMS
I ESCALATING NON-ESCALATING
I (Fuel) (O&M, etc.)
($/kWh) ($/kWh)
0.119
0.122
0.125
0.128
0.131
0.135
0.138
0.141
0.145
0.149
0.152
0.156
0.160
0.164
0.168
0.172
0.176
0.181
0.186
0.190
0.190
0.051
0.051
0.051
0.051
0.051
0.051
0.051
0.051
0.051
0.051
0.051
0.051
0:051
0.051
0.051
0.051
0.051
0.051
0.051
0.051
0.051
TABLE 10
CALCULATION OF PRESENT WORTH OF DISPLACEABLE COSTS FOR BASE CASE PLAN
1983 -2037
I I TOTAL
LOW-GROWTH I DISPL.
FORECAST I COSTS
( MWh ) I ($1, 000 )
I
1,020 I 173
1,028 178
1,202 212
1,211 217
1,220 222
1,122 209
1,126 213
1,130 217
1,133 222
1,136 227
1,140
1,144
1,147
1,150
1,154
1,154
1,154
1,154
1,154
1,154
1,154
231
237
242
247
253
257
262
268
273
278
278
I PRESENT
I WORTH OF
I DISPLACEABLE
I COSTS
I ($1,000)
I I 167
I 166
I 191
I 189
I 187
I I 170
I 167
I 165
I 163
I 161
I
158
157
155
153
151
148
146
144
142
140
2,660
MODERATE I
GROWTH I
FORECAST I
(MWh) I
I
1,020 I
1,028 I
1,202 I
1,211 I
1,220
1,350
1,354
1,358
1,361
1,364
1,368
1,372
1,375
1,378
1,382
1,382
1,382
1,382
1,382
1,382
1,382
TOTAL
DISPL.
COSTS
($1,000)
173
178
212
217
222
251
256
261
267
273
278
284
290
296
303
308
314
321
328
333
333
PRESENT
WORTH OF
DISPLACEABLE HIGH-GROWTH
COSTS FORECAST
($1,000) (MWh)
167 1,020
166 1,577
191 1,587
189 1,596
187 1,605
204 1,735
201 1,739
198 1,743
196 1,746
194 1,749
190
188
185
183
181
178
175
173
171
167
3,186
1,753
1,757
1,742
1,763
1,767
1,767
1,767
1,767
1,767
1,767
1,767
TOTAL
($1,000)
173
273
279
286
292
323
329
335
342
350
356
364
368
379
387
394
401
page 23
I PRESENT
I WORTH OF
I DISPLACEABLE
I COSTS
I ($1,000)
I I 167
I 255
I 252
I 249
I 246
263
259
254
251
248
244
241
235
234
231
410 I
419 'II
426
227
223
221
218
214
426
I
I 4,075
LOW-GROWTH TOTAL: $ 5,880.0 MODERATE-GROWTH TOTAL: $ 6,870.0 HIGH-GROWTH TOTAL: $ 8,807.0
page 24
E -THE ECONOMICS OF A FAVORITE BAY HYDROELECTRIC PLANT
The resign (at a conceptual level) of a small hydroelectric plant on an
unnamed creek (Favorite Bay Creek?) about 4 miles south of the village
has been under study by the Anchorage firm of Tryck, Nyman, and Hayes
(TN&H) since 1980. The major thrust of their work has been in the
direction of the developnent of a fish hatchery to provide a renewable
income-producing resource. The operation of a fish hatchery on Favor-
ite Bay Creek would necessitate the construction of a water impoundment
so that fresh water would be available year-round, even when the creek
was frozen, as it normally does in the winter months.
The availability of the head developed behind an impoundment dam would
provide an attractive hydroelectric resource. Any dam would be an ex-
pensive proposition, but the incremental cost associated with building
a dam large enough to provide q water supply adequate for both the
hatchery and a hydroelectric plant could be fairly 10fJ. It may well be
that if ah""atchery and its dam were constructed, it wouldn It make sense
not to incl ude a hydro pl ant to make use of the energy stored beh ind
the dam before the water was released for hatchery use. Naturally,
some minimum streamflOfJ would have to be maintained at all times.
From the standpoint of hydroel ectri c developnent at Angoon, the con-
struction of a hatchery is practically a given condition. If Favorite
Bay Creek were to be developed, a dam would be necessary. Favorite Bay
Creek is a salmon spawning creek (although a fairly poor one) and the
Alaska Department of Fish and Gamels (ADF&G) prevailing stance is that
salmon habitat must be protected. If a dam were built on the stream,
it would destroy the existing habitat. In such a case, ADF&G would
likely require some mitigative measure such as a hatchery to make up
for the loss of the salmon.
This study will eX<111ine the economics of the hatchery/hydro plant sys-
tem at th ree 1 eve 1 s :
l. First, an investigation is made of the hydro plant in isolation
from the hatchery and its costs and revenues.
This approach assumes that the hydro plant pays for all costs which
are identified as being unique to that faci lity; the hatchery funding
"pays" for 75 percent of the dam, access road, and intake structure.
The ratio of the benefits (savings in displaceable costs) to the
costs of operating the "base case" diesels is calculated for the mod-
erate and high growth energy forecasts. It is not considered appro-
priate to carry out this calculation for the 10fJ-growth forecast,
because one of the load components of the two higher forecasts is the
ha tch ery.
page 25
2. An investigation is made of the hydro plant plus the hatchery.
This will examine the impact to the benefit:cost ratio of the reve-
nues and costs due to the hatchery operation and salmon harvests.
3. The final investigation carried out is identical to that performed
under "2" above, except that the extra revenues which are realized by
the local fishing fleet as a result of the hatchery's operation are
incl uded.
In 1982 the Angoon Aquaculture Associ ation filed an appl ication with
ADF&G to be granted a permit to construct a fish hatchery at a site
along F avo rite Bay Creek. Thei r perm it appl i ca ti on descri bes a
" ... newly created reservoir of 4,500 acre feet. .. behind a one hundred
foot dam." This dam is also featured in a TI~&H report done in 1981 to
explore various options available to Angoon for a new water supply.
That report explored the dam as a mul ti -use faci 1 i ty, provi di ng the
village with drinking water, hydroelectric power, and water for their
ha tch ery.
In their 1981 report describing the multi-purpose facility (hatchery/
hydro/water supply), TN&H gave cost estimates for the various faci lity
components as foll OIlS:
Dam and I ntake Structure
PONer Generating System
Water Supply System
Access Road
TOTAL:
$ 5,088,750
2,784,210
2,628,188
1,308,413
$11 ,809,561
Using an 8 percent escallation rate to yield 1982 dollars and another
4.3 percent to give current costs, this estimate is revised to $13.3
million in 1983 dollars. It is Acres I opinion that, for the most part,
estimates provided by TN&H are quite reasonable for the level of detail
required at this stage of project evaluation.
There are a muple of changes to this cost estimate which will be made
before proceeding.
The most significant of these changes is in the cost of the dam itself.
Acres carried out calculations based on an earth-or rock-filled dam.
At a dam vo 1 ume of 132,000 cubi c yards, with a pri ce of $ 37 per cubi c
yard, Acres calculates a dam cost of $4.9 million ($ 1983) compared to
the $2.5 million ($2.85 million in $ 1983) given by TN&H. Their work
was based upon a dam volume of 110,000 cubic yards of rock with a price
of $23 per cubic yard. Acres does not believe that rock fill will be
available in Angoon for that price.
We do believe that suitable rock will be available in Angoon for the
$ 37 per cubi c yard ment i oned abo ve. Rock and ea rth pl aced at Tyee
ranged from $8 per cubic yard for "Common Backfill" to $48 per cubic
page 26
yard for "Select Bedding and Backfill". In that bid, the fairly coarse
rock "Riprap" was priced at $20 per cubic yard. While rot identifying
riprap as a bid item, the Swan Lake 10v'J bid priced "Compacted Backfill,
Type A" at $15 per cubic yard and "Compacted Backfill, Type B" at $25
per yard (not including some special purpose Type B backfill priced at
$310 per yard for a small quanti ty). A Tryck, Nyman, and Hayes staff
member told Acres personnel that rock fill in the Craig/Klawock/ Hyda-
burg area was presently costing about $25 per ton (or about $37 per
cubic yard).
This adjustment would mean that the line item "Darn and Intake Struc-
ture" would be $7,782,278 (in 1983 dollars), an increase of about $2
million over the TN&H estimate of $5,088,750 ($5.73 million in 1983
do 11 ars ) .
The second adjustment to be made in Acres I analysis is the "r61l0val" of
the msts associated with the water supply system. The existing water
supply for Angoon is in such disrepair that it is likely that the con-
struction of a new source will be of such priority that it will be con-
structed before the hatchery/dam is begun. This change will decrease
the project mst estimate by $2,960,496 (1983 dollars).
Thirdly, in their cost estimate for the hatchery (total cost $6.09 mil-
lion in 1983 dollars), TN&H had allocated $392,370 (1982 dollars) for
the mnstruction of an access road. This estimate was based upon the
idea that the hatchery would share the cost of an access road built to
serve the hatchery, the dam, and the water supply system. The prelim-
ina ry co st of the mmpl ete road was $1,473,849 in 1983 do 11 ars. Si nce
it is likely that most (perhaps as much as 2/3) of this road will be
built to serve the new water supply before a Falls Creek hydro site is
built, only one third of its cost, or $491,283, needs to be allocated
to the hydro plant/hatchery.
Thus, the mst estimate used in this report (expressed in 1983 dollars)
is as follONS:
Dam and Intake Structure
PON er Genera ti ng System
Water Supply System
Access Road
$ 7,782,278
3,136,246
-0-
491,283
TOTAL: $11,409,807
The first eX(fJlination of the Favorite Bay hydro plant economics assumes
that the hatchery will pay for 75 percent of the dam and intake struc-
ture (and 75 percent of the access road). This makes the increnental
cost of the hydro plant:
Dam and I ntake Structure (0.25 x $7.782 1"1)
PONer Genera ti ng System
Water S upp 1 y System
Access Road (0.25 x $0.491 M)
TOTAL:
$1,946 ,000
3,136 ,000
-0-
123,000
$ 5,205,000
page 27
Since this report assumes an on-line date of 1988 (Year 6 of the econ-
anic analysis), this dam capital cost has a present worth of $4,234,000
(w h en ca 1 c u 1 ate d at 3.5 %) •
The 1981 cost estimate for maintaining a Favorite Bay hydro plant was
$102,500 per year (not counting the cost of maintaining the water sup-
ply). This represents an annual cost of $115,460 in today's dollars.
The present worth of 50 years of this O&M (calculated at 3-1/2%, assum-
ing an on-line date of 1988) is $2,203,000. Therefore, the total
present worth of a Favorite Bay hydro plant is $6.437 M.
As discussed in Part 0 of this report, some components of the THREA
system will continue to cost Angoon custaners money even though THREA
may not be generating any pJwer. Items such as the diesel generators
(whi ch woul d be mai nta i ned to act as backups to the hydro pl ant) and
the power distribution lines must be kept in good working order; the
cost of the REA loans used to finance the THREA equipment must be paid
off; THREA administrative work will continue and must be financed.
Again referring to Part 0, it may be rananbered that there was some
discussion of "displaceable" costs associated with the THREA system.
Those were costs which would no longe,r be realized if some other gener-
ation facility came along which could replace the energy produced by
THREA's diesels. The "displaceable" costs are used in determining the
economic impact of a Favorite Bay hydroelectric project on the Angoon
power system.
TABLE 11 -PRESENT WORTH OF POWER SYSTEM WITH FAVORITE BAY PLANT
(Moderate -Growth Forecasts)
1. Present worth of THREA system opera ti on
(10.01 -growth forecast, 55 years, 3.5%) $11,872,000
2. Present worth of "displaceable" THREA costs
(l~ -growth forecast, Year 6 -55,3.5%) 6,870,000
3. Savings due to operation of APA waste heat system
from 1983 through 1987 53,000
4. Potenti al savings from waste heat system which
are lost due to the sh utdown of the system from
1988 through 2037 457,000
5. Present worth of Favori te Bay hydro pl ant 6,437,000
TOTAL (1 - 2 - 3 + 4 + 5) $11 ,843 ,000
This total should be compared to the present worth of the continued
operation of the existing THREA system which is $11,872,000. The dif-
ference, $29,000 in 1983 dollars shows that if the Angoon load growth
follONS the moderate forecast, the system with the dam would be about
the same price as continued operation of THREA's diesel system.
page 28
In tenns of increnental benefit:cost ratios, we can easily take the
cost data from the previous page and develop the following:
BENEFITS
1. "Displaceable" THREA msts $ 6.87 million
COSTS
1. Favori te Bay hydro pl ant $ 6.78 mill ion
2. Lost benefi ts from APA waste hea t system .46 mi 11 ion
TOTAL COSTS $ 6.89 mill io n
Benefit:Cost Ratio 0.997 = 6.87 + 6.89
It should be n~ted that these first calculations were done using the
moderate-growth scenario. Bela", are the same calculations carried out
using the high growth forecasts.
TABLE 12 -PRESENT WORTH OF THREA -FAVORITE BAY HYDRO SYSTEM
(H igh -Growth Forecasts)
1. Present worth of THREA systen operation
( high -grow th foreca st s, 55 yea rs, 3.5 %)
2. Present worth of "displaceable" THREA costs
(high-growth forecasts, Year 6 -55, 3%)
$13 ,843 ,000
8,807,000
3. Savings due to operation of APA waste heat system
from 1983 through 1987 53,000
4. Potential savings fran waste heat system which
are lost due to the shutdown of the system from
1988 th ro ugh 2037 457 ,000
5. Present worth of Favori te Bay hydro pl ant
(see calculations above) 6,780,000
TOTAL (1 - 2 - 3 + 4 + 5) $ 12 ,220,000
Under this load assumption, it can be seen that the THREA-Favorite Bay
Hydro system is about $1.6 million (11%) less expensive (present worth)
than the di esel-fuel ed THREA system.
The increnental benefit:cost ratio of the Favorite Bay hydro plant
under this set of assumptions is:
Benefit: Cost Rati 0 1.22 = 8.81 + 7.24
This is significantly different from the 0.99 B:C ratio which was calc-
ulated using the moderate-growth assumptions.
page 29
It is not so obvious what effect the hydro plant will have on individu-
al consumers' electric bills. This is the next topic to be explored.
The incremental capital costs of the Favorite Bay hydro plant were
calculated to be $5,205,000. By APA project evaluation rules, the
period over which these hydro plants are financed is 35 years. At an
interest rate of 3.5%, the annual costs associated with the dam
construction are $260,250. Again, the O&M costs are $102,500. Thus,
the total annual cost of the hydro plant is about $363,000. These
costs are fixed and will not change over the 35 years of the dam
financing period.
Additionally, there are costs associated with the THREA system whic~
are rot eliminated with the operation of the hydro plant and must be
considered. As has been shown on Table 5 and discussed in Part D,
ll-IREA incurs fixed costs of about $205,000 per year. These costs do
not dlange with energy use. There are also some "non-displaceable"
costs which vary with energy use, but these are so small that they may
be ignored in this analysis (these costs were estimated at $0.004 per
kW h) •
Thus, the total annual dlarges associated with operating a power sytem
which makes use of the existing THREA distribution system and a new
Favorite Bay hydro plant are:
$ 36 3,000 + $ 205 ,000 = $568,000
At the highest energy uses anticipated, this works out to a per kilo-
watt hour charge of about $0.32, which is currently a "typical" price
level for a diesel-powered system in the bush. For the later years of
the modera te foreca st, the energy pri ce from such a system woul d be
about $0.41/kWh, an lJ1reasonably high price for electricity.
Calculations performed in Part D (Tables 7 and 8) showed THREA prices
of $0.38 and $0.34 per ki lONatthour for the moderate and high growth
cases, respectively in 1998. A comparison of projected electricity
prices both with and without a Favorite Bay site in operation are shown
be la'll:
TABLE 13
MODERATE GROWTH HIGH GROWTH
YEAR NO HYDRO WITH HYDRO NO HYDRO WITH HYDRO
1988 $ 0.34 $ 0.42 $ 0.31 $ 0.33
19~ 0.35 0.42 0.31 0.33
1992 0.35 0.42 0.32 0.32
1994 0.36 0.41 0.33 0.32
1996 0.37 0.41 0.34 0.32
1998 0.38 0.41 0.34 0.32
2000 0.38 0.41 0.35 0.32
2002 0.39 0.41 o .36 0.32
page 30
The "catch" to all of these calculations is that 75 percent of the cost
of the dam, intake structure, and that part of the access road not
built as part of the water supply are allocated to the hatchery. The
hydro plant then is charged with 25 percent of the cost of these items
pl us all pa rts of the proj ect whi ch are un i q ue to the ge nera ti on and
transmission of electricity.
This rather arbitrary split in costs was made because it is felt that
the major beneficiary of the project will be the hatchery and the com-
mercial fishery which will be enhanced by its existence. It is only a
coincidence that the energy prices realized in the high-growth forecast
are as competitive with the TI1REA system as they are.
Recent experience in Southeast Alaska has shown that utility custaners
are a lmost un i versa lly oppo sed to the purch ase of energy from a hydro
project which is more expensive than that available from their existing
diesel system. In order to make the Falls Creek hydro system attract-
ive, it may be necessary to allocate an even greater fraction of the
project costs to the hatchery.
Sane calculations regarding the economics of the hatchery operation are
now in order.
Tryck, Nyman, and Hayes has carried out an economic analysis of the
hatchery's operation which shows that it would be able to turn a profit
once its design production levels were reached and the full potential
of the returning fish runs was realized. [It should be kept in mind
that the hatchery's operator, the Angoon Aquaculture Association is
organized as a nonprofit corporation.] The TN&H calculations, assume
that "someone else" would provide the dam and its impoundment. Under
the calculations just presented, we assumed that the Angoon Aquaculture
Associ ation woul d pay for 75 percent of the dam and intake structure
and access road. Thi s woul d add another $6.02 M to the capi ta 1 co st of
thei r project (0.75 x $8.27 M).
The TN&H report gave a
mil 1 ion ( a s ex p 1 a i ne d
Applying an escallation
1983 dollars, we get an
cost estimate for the fish hatchery of $5.84
in a supplemental letter) in 1982 dollars.
rate of 4.3 percent to bring this to January
"updated" cost estimate of $6.09 million.
Adding the $6.02 M to the $6.09 M derived above, the capital cost of
the hatchery and its 75 percent share of the dam is $12.11 million.
The terms of the loan by which the Angoon Aquaculture Associ ation pl ans
to finance this project require no payback of the loan's principal for
six to ten years. At the end of that period, the loan is repaid over a
page 31
ten-year period. For the purposes of this study, we will make the fol-
10r'ling assumptions regarding the intial financing of the dam and
hatchery:
Initial hatchery mst. ... .
Loan deferra 1 peri od ..... .
Interest rate (net of inflation)
Loa n payback per i od. . . . . .
Annual payment (yea r 11-20). .
.. $ 12.11 million
. 10 yea rs
3.5 perce nt
. 10 yea rs
. $ 1 .46 mil 1 ion
Additionally, for the calculation of present worths, we will treat the
total investment as occurring in Year 1 of the project's existence,
which is assumed to be 1988. The life of the hatchery will be assumed
to be 20 years, after which the analysis will presume that a second
hatchery is "built", and a third 20 years after the second one. These
"replacement" hatcheries, cost-ing $6.09 million, will be financed with
20-year loans at 3.5 percent, for an annual cost of $428,000.
The dam will be assumed to have a lifetime of 50 years and will only be
" b u i 1 t" 0 n ce .
The last hatchery will rut be replaced at the end of the economic life
of the dam. Since it will then be in the middle of a "lifetime" it
will be credited with a salvage value of 50 perecent ($3,045,000).
Tryck, Nyman, and Hayes has estimated the operating costs of the hatch-
ery to be on the order of $428,000 per year (1982 dollars). In terms
of 1983 dollars, this figure is $446,400.
In response to ADF&G requests for supplenental infonnation on the
hatchery permit, TN&H provided details of their assumptions regarding
the economic viability of a hatchery at Angoon. In their permit appli-
cation and in their supplemental letter, they provided data regarding
the number of salmon to be rel eased from the hatchery and the number
expected to return to the area to mmpl ete thei r 1 ife cycl e.
The Angoon hatch ery is des i gned to opera te at max imum egg prod !Jct ion
level s of :
Coho Sa lmon 1.5 million green eggs
Pink Salmon 7 .5 " " "
Chum Salmon 50.0 " " "
In their revenue assumptions, TN&H "operated" the mum salmon portion
of the hatchery at a 20 million egg level, which is consistent with the
terms of their existing permit. A surrmary of the hatchery release and
return levels (as stated by TN&H) is given on the next page.
TABLE 14 -ECONOMICS OF HATCHERY OPERATION
(Based on Data from Tryck, Nyman, and Hayes)
HATCHERY PRODUCTION
1. COHO SAlJw10N (see note 1)
page 32
a.
b.
Hatchery rel ease •••••••••
Returning fish (assuming that
1 ,000 ,000 per yea r
c.
d.
e.
f.
5 percent survive in the ocean).
Catch by local fl eet (70 percent).
Fish returned to hatchery (b c).
Fi sh used for brood stock ••
Fish rEmaining for sale by
Aquaculture Association (d e).
2. PINK SAlJw10N (see note 1)
a.
b.
c.
d.
e.
f.
Hatchery rel ease •••.•••••
Returning fi sh (assuming that
2 percent survive in the ocean).
Catch by local fleet (40 percent).
Fish returned to hatchery (b c).
Fi sh used for brood stock. •
Fish rEmaining for sale by
Aquaculture Association (d e).
3. Q-i UM SAlJw10N (see note 2)
a. Hatch ery rel ea se • • • • • • • • •
b. Returni ng fi sh (assumi ng that
2 percent survive in the ocean).
c. Catch by local fleet (40 percent).
d. Fish returned to hatchery (b c).
e. Fi sh used for brood stock. •
f. Fish rEmaining for sale by
Aquaculture Associ ation (d e).
Notes:
50 ,000 "
35 , 000 "
15,000 "
1 ,072 "
13,928 "
"
"
"
"
"
6 ,000 ,000 per yea r
.120,000 II
48, 000 "
72,000 "
8,824 "
63,176 "
16,000 ,000 per
.320 ,000 "
.128,000 "
.192,000 "
20 , 000 " .
.172 ,000 "
"
"
"
"
"
yea r
"
"
"
"
"
1. Rel ease data taken from permit appl ication •
2. Rel ease taken fran suppl Emental letter." Hatchery was appar-
ently expanded from the conceptual design in the permit ap-
plication to make this chum production possible.
page 33
The Alaska Department of Fish and Game (Limited Entry Permit Section)
has provided data giving preliminary 1983 catch price levels for the
various fish species by gear type in the Juneau area (whia includes
Angoon). These figures are as follONS:
ADF&G has
speci es.
TABLE 15--SALlY10N PRICES BY GEAR TYPE (FROM 1983 DATA)
SPECIES TROLL
Pink
Ch urn
Coho
a 1 so
These
Salmon $ 0.35/1b
Salmon 0.55
Salmon 0.75
provi ded da ta on
are:
SPECIES
Pink Salmon
Chum Salmon
Coho Salmon
the
GEAR TYPE
PlRSE
SEINE
$ 0.23/1b
0.30
0.40
II average II
AVG. WEIGHT
4 lb
10
7
rnIFT
NET
$ 0.26/1 b
0.41
0.55
wei gh t of the various
Because the troll harvest is rel ati vely small, this report will use the
drift net price for each species as the "average" price paid the fish-
ermen for their catch. Given the average weights as listed above, we
can calculate a per-fish value of $1.04 for pink salmon; $4.10 for chum
salmon; and $3.85 for coho. These figures contrast greatly with the
per-fish values assumed by Tryck, Nyman, and Hayes in their economic
assessment of the hatchery operation. Thei r work, which used data from
earlier years, assumed the follONing per-fish values: $1.36 for pink
salmon; $6.90 for chum; and $10.50 for coho salmon.
From the discussion on pages 30 and 31 regarding the terms of the Aqua-
culture Association's loan, it can be seen that the annual costs asso-
ciated with loan repayment will be $1.46 million (assuming that the
complete hatchery/dam package can be financed under the same terms).
Added to this is the $0.446 million in annual operating costs for a
total of $1.90 million per year during those years when the hatchery
loan will mme due.
From the catch data given in Table 14, and the per-fish values as
developed above, we can see that the hatchery revenue of all three
species is about $824,000 per year. This assumes a maximum production
of mho and pink salmon and a 40 percent (a) million green eggs -: 50
million green eggs) production level of churn salmon.
page 34
The logical question would be "Can increased chum production make up
the $1.08 million shortfall in revenues?" To determine the chum egg
levels needed to bring the hatchery an extra $1.08 million these simp-
lifying assumptions will be made:
1. Of each million chum salmon eggs produced, 8,600 adult fish will
return to be harvested by the Aquacul ture Associ ati on.
2. The allocation of variable costs will be based upon the number of
eggs produced of each species, with coho being charged more
(since they cost more to raise)
Coho Vari able Costs = $ 44,900
= $ 29,200 per million eggs
Pink Variable Costs = $109,700
= $ 14,600 per million eggs
Chum Variable Costs = $292~00
= $ 14,600 per mill ion eggs
3. Returning chum salmon will be worth $4.10 per fish to the Aqua-
cul ture A sso ci ati on
A simple calculation is all that is necessary to determin2 the chulTl
production level needed to make the hatchery break even:
$ 1,000 ,000 = $4.10 x (8,600 n) -$14,600 x (n)
52.3 = n
where "n" is in millions of additional chum salmon eggs
needed to make up the shortfall
This represents a mum salmon production level of about 72 million
eggs, or about 22 million eggs (44 percent) beyond the design level.
Given recent salmon prices, we can see that if the Aquaculture Associ-
ation were required to pay for 75 percent of the dam costs, it would be
unable to adjust production levels to cover all costs. Further analy-
sis in this report will presume that mum egg production will be raised
to 50 million, the hatchery's maximum design level.
These results are in stark contrast to those presented in the draft
version of this report. There, using per-fish values developed by
TN&H (as shown on the previous page), it was found that the hatchery
could generate sufficient revenue to cover both its operating costs and
the capital costs of 75 percent of the dam by raising chum production
to 32 million green eggs. It is obvious that the economics of the
Falls Creek hatchery and hydro plant are influenced by salmon prices
which are much more volatile than were previously recognized.
page 35
The economic analyses presented in the draft edition of this report
showed that the Favorite Bay hatchery's production could easily be
adujsted to make up for the funding shortfall realized when operating
under those circumstances. It now appears that there may be times ' . ."hen
salmon prices are depressed to the point where the proJ))sed hatchery
cannot produce eno~gh fish to generate revenue sufficient to meet all
needs. Raisi ng the pri ce of el ectri ci ty from a Falls Creek hydro pl ant
to generate additional revenue is not an available alternative. This
is because diesel J))wer is alreayd available to Angoon residents.
Earlier analysis work assumed that the selling price of Falls Creek
energy would be set to rover just the "displaceable" costs of THREA
diesel generation. Any increase in Falls Creek energy prices beyond
this level would prompt a shift back to diesel generation.
Although it appears that the economics of the hatchery are unattractive
at recent salmon prices, this study will proceed to develop Benefit:
Cost ra ti ons for its opera ti on.
Table 14 on page 32 gave production and harvest levels for the three
species of salmon to be raised at the Favorite Bay hatchery. On the
previous page, we "adjusted" the mum salmon production in an attempt
to enable the Aquaculture Association to pay for 75 percent of the dam.
This resulted in a chum salmon production of 50 million green eggs,
whi ch is the desi gn producti on max irnum. Even so, the Aquaculture
Association revenue was inadequate to support the hatchery operation
and the loan payback for the ro nstruct i on of the dam.
TABLE 16 -ASSUMPTIONS REGARDING HATCHERY OPERATION
1. mHO SALMON
a.
b.
c.
d.
Hatch ery re 1 ea se . . . • • . . . . . .
Ca tch by 1 oca 1 fl eet (70 % of return) .
Fish available for sale by Aquaculture Assn.
Aquaculture Assn. revenue ($3.85 per fish)
2. PI NK SALMON
a.
b.
c.
d.
Hatch ery rel ea se •..•......•...
Catch by local fleet (40% of return) ••••
Fish available for sale by Aquaculture Assn.
Aquacul ture Assn. revenue ($1.04 per fi sh) •
1 ,ODD ,ODD
35,000
13,928
$ 53,623
6,000 ,ODD
48,000
63,176
$ 65,703
per yea r
II II
II II
II II
per yea r
II II
II II
II II
TABLE 16 (cont'd)
3. (}i UM SALMON
a.
b.
c.
d.
Hatch ery re 1 ea se • • • • • • . . • • • • • .40,000 ,000
Catch by local fleet (40% of return) . • •• 320,000
Fish available for sale by Aquaculture Assn. 430,000
Aquaculture Assn. revenue ($4.10 per fish) $1,763,000
pa ge 36
II II
II II
II II
II II
It is not expected that hatchery production will begin at the levels
shown above. Data taken from the hatchery permit appl ication and later
verified in conversations with TN&H personnel yield the follOtling
production schedule:
YEAR OF HATOHRY HA TOHRY REL EA SE BY SP E CI ES
OPERA TI ON (percent of ul t i rn ate prod uct ion)
(Year 1 -1988) COHO PINK CHUM
1 -0 -0--0-
2 10 7 3
3 33 27 12
4 33 34 31
5 100 ·60 63
6 and 1 a ter 100 100 100
There is a delay between the time when the salmon are released and the
time they return. Again, based upon data from Tryck, Nyman, and Hayes,
we have derived the follOtling fish return schedule from which annual
revenue levels may be computed:
TABLE 17 -SALMON RE1URNS AND AQUACUL1URE ASSOCIATION REVENUES
YEAR OF
f1ll. TQ-I ERY
OPERATION
1
2
3
4
5
6
7
8 and 1 ater
SALMON RE1URNS BY SPECIES
(perce nt
COHO -0-
o
o
o
10
33
33
100
of ultimate
PINK -0-
o
o
7
27
34
60
100
returns)
CHUM -0-
o
o
3
12
31
63
100
COHO -0-
o
o
o
5.4
17.7
17.7
53.6
(Year 1 = 1988, revenues shown are in $1,000)
REVENU ES
PINK CHUM -0---0-
o 0 o 0
4.6 52.9
17.7 211.6
22.3 546.5
39.4 1110.7
65.7 1763.0
TOTAL
o o
o
57.5
234.7
5 ffi .5
1167.8
1882.3
The total revenues, if rontinued for 50 years, can be shown to have a
total present worth (1983 dollars, calculated at 3.5%) of $28.2
million.
page 37
As discussed before, the share of the dam and intake structure allocat-
ed to the Aquaculture Association (75 percent of the total) had a cost
of $6.02 million (1983 dollars, spent in 1988). This would have a
present worth of $5.05 million. The hatchery capital cost of $6.09
million, plus "rebuilding" in years 21 and 41 and a 50 percent salvage
i n y ea r 5 0 have a to tal pres e nt w 0 r tho f $ 8 • 3 mil 1 ion.
The annual operating costs to the Aquaculture Association are $884,000
(including an extra $438,000 due to the expanded chum salmon produc-
tion). Over 50 years beginning in 1988, these expenditures would have
a present worth of $16.9 million.
Thus, the total costs of the hatchery are $30.2 million, the total rev-
enues (benefits) are $28.2 million, for a benefit:cost ratio of 0.93
over the term of the proj ect.
When considering the hydro plant/hatchery "system" as a whole, the fol-
lowing increnental benefit:cost calculations may be made:
BENEFITS
1. Displ aceable TI-lREA costs
2. Hatch ery Reve nue
COSTS
1. F avo ri te Bay Hydro Plant
2. Hatchery (capital pl us O&M costs)
3. Lost Benefits from APA Waste Hea t System
$ 8.8 M
28.2
TOTAL $ 37.0 M
$ 6.8 M
30.2
0.5
TOTAL $ 37.5 M
Benefit: Cost Rati 0 0.99 = 37.0 of-37.5
Thi s number may be compa red to the B: C ra ti 0 of 1 .22 ca 1 cul ated for the
TI-lREA -Favori te Bay IX>wer system standing on thei r own. The reader IS
attention is directed to our use in this case of the displaceable bene-
fits from the high-growth case. This approach is believed to be cor-
rect because the hatchery was incl uded in the high-and moderate-growth
forecasts, but not in the lCM-growth forecast. Additionally, the
increased salmon production which would accompany the hatchery operat-
ion would 1 ikely increase the ice consumption (therefore the energy
use) of the Angoon cold storage pl ant. That increased demand was also
a high-forecast component. Under the moderate-growth forecast, the B:C
ra t i 0 i sO. 94 •
page 38
With regard to both of these calculations, it is appropriate to empha-
size that the Angoon Aquaculture Associ ation is chartered as a non-
profit organization. It very well may be that they would "schedule"
their salmon production levels to meet cash flON requiranents of future
years so that they would have small annual surpluses. If this '",ere the
case, the B:C ratios for both high and low forecasts would be much
closer to uni ty.
The sensitivity of the system's B:C ratio to changes in the capital
costs of the hydro pl ant or the msts of the THREA system is dimini shed
by the overwhelming infl uence of the hatchery costs and revenues. The
B:C ratio is considerably more sensitive to the perfonnance of the
Angoon Aquaculture Association's fishery.
This completes the second of our three analyses, showing in this case
that a Favorite Bay hydroelectric plant may not be an economically
so un d ve nt ure.
The final approach taken in the analysi s of the economics of the Favor-
ite Bay hydro plant is to include the benefits realized by the local
fishing fleet as a result of the hatchery operation.
In thei r revenue estimates, Tryck, Nyman, and Hayes assumed that the
operators of the local fishing -fleet would catch 70 percent of the
returning coho salmon and 40 percent of both pink and chum salmon.
Referring to Table 13, this amounts to 35,000 coho, 48,000 pink, and
320,000 chum salmon annually if the hatchery has reached its maximum
assumed production levels. In tenns of revenue, these catch levels
represent $135,000 for coho, $50,000 for pink, and $1.31 million for
chum salmon. For purposes of this study, it will be assumed that no
capital additions (e.g. boats) will be required to harvest these extra
fish. HONever, we will assume that 25 percent of the revenue will be
used to purchase extra fuel needed to capture the fish. This will make
the ultimate net revenues $101 ,000 of mho, $37,500 for pink, and $0.98
mi 11 ion for ch um sa lmon.
The 1 oca 1 fi sh i ng fl eet will be faced with the same sch edul e of return-
ing fish as is the Aquaculture Association. As shown in Table 18, we
have derived the follONing fish return schedule showing revenues to the
1 oca 1 fl eet:
page 39
TABLE 18 -SALMON RETURNS AND LOCAL FISHING FLEET REVENU ES
YffiR OF SALMON RETURNS BY SPECIES REVENU ES
HA T01 ERY (percent of ul timate returns)
OPERATION COHO PINK CHUM COHO PINK CHUM TOTAL
1 -0--0--0--0--0--0--0-
2 0 0 0 0 0 0 0
3 0 0 0 0 0 0 0
4 0 7 3 0 2.6 29.4 32.0
5 10 27 12 10.1 10.1 117.6 127.7
6 33 34 31 33.3 12.8 303.8 316.6
7 33 60 63 33.3 22.5 617.4 639.9
8 and 1 a ter 100 100 100 101 .0 37 .5 980.0 1118.5
(Yearl = 1988, revenues shown are in $1,000 )
The total revenues, if continued for 50 years, can be shown to have a
total present worth (l983 dollars, calculated at 3.5%) of $16.5
million.
Now considering the benefit:cost ratio of the hydro plant/Aquaculture
Association/local fishing fleet "system" we see:
BENEFITS
1. Displaceable THREA costs
2. Hatchery Revenue
3. Local Fish ing Fleet Revenues
COSTS
1. Favori te Bay Hydro Plant
2. Hatchery (capital plus O&M costs)
3. Lost Benefi ts from APA Waste Hea t System
Benefit: Cost Ratio 1.43 = 53.5 t 37.7
$ 8.8 M
28.2
16.5
TOTAL: $53.5 I...,
$ 6.8 M
30.2
0.5
TOTAL: $37.7 M
When considered as a complete "system", the construction of an impound-
ment dam and its attendant hatchery at Favorite Bay, becomes a more
at t r act i ve pro po sit ion.
There are a number of other benefits which can be ascribed to this
system. Sane of these have measurable economic benefits to the system.
These "extra" benefits have not been included in any of the above
analyses because of their some:.what esoteric nature. They are consider-
ed here and left for each reader to draw thei r own concl usions as to
the appropriateness of their inclusion in the analyses.
page 40
There is a oon-trivial market for salmon eggs, considered a delicacy in
Japan and gaining popularity in the lD. The harvesting and processing
of salmon eggs is done by special teams of Japanese "technicians" who
travel from fishing village to fishing village throughout the salmon
season to package then to meet the exacting standards of Japanese
consumers. Data gathered by TN&H personnel on the economics of the
salmon egg market yields the follONing information:
1. Salmon egg pri ces are oow at a very depressed 1 evel, thei r lON-
est in many years. Coho eggs sell for $5.80 per pound wholesale;
pi nk for $4.00; and ch um for $4.50.
2. The cost of the Japanese technicians to carry out the processing
work at the village is about $0.75 per pound of eggs regardless of
species of fish. This does not include travel expenses to the vil-
lage oor housing expenses in the village.
3. About 7 percent of the body weight of a fenale salmon is eggs.
Roughly 50 percent of the returning salmon are fenales. The average
weight of the harvested fish by species are: coho 7 pounds; pink 4
pounds; chum salmon 10 pounds.
Since it is very important to the Japanese to have their salmon eggs
harvested from the females as soon after they are taken from the water
as possible, our analysis will mncentrate on the fish harvested by the
Aquacul ture Associ ation.
Referri ng to Tabl e 16, the ul timate harvest by the Aquacul ture
Association is assumed to be: 13,928 coho, 63,176 pink, and 430,000
chum salmon. This means that there will ultimately be 6,964 female
coho, 31,588 femal e pi nk, and 215,000 femal e mho sa lmon harvested by
the Aquaculture Association. This harvest will yield 3,400 pounds of
coho eggs; 8,800 /Xlunds of pink eggs; 150,000 pounds of chum salmon
eggs. By species, these eggs would bring the follONing revenues (Lllder
present de pressed pri ces ) :
Coho: $17,170 = 3,400 lb x ($5.80/lb -$0.75/lb)
Pink: $28,600 = 8,800 lb x ($4.00/lb -$0.75/lb)
Chum: $562,500 = 150,000 lb x ($4.50/"lb -$0.75/lb)
This total revenue of $339,000 per year would be reached follCMing much
the same schedule as the harvest of the salmon thenselves. Table 19 on
the foll CMing page was prepa red to show the developnent of the egg rev-
enues to the Aq uacul ture A sso ci ati on:
TABLE 19--AQUACULnJRE ASSOCIATION EGG REVENUES
YEAR OF
HA TO-l ERY
OPERATION
1
2
3
4
5
6
7
8 and 1 a ter
SALMON REnJRNS BY SPECIES
(perce nt
COHO -0-
o
o
o
10
33
33
100
of ul timate
PINK -0-
o
o
7
27
34
60
100
returns)
CHUM -0-
o
o
3
12
31
63
100
COHO -0-
o
o
o
1.7
5.7
5.7
17.2
(Year 1 = 1988, revenues shown are in $1,000)
REVENU ES
PINK CHU M -0---0-
o 0
o 0
2.0 16.9
7.7 67.5
9.7 174.4
17.2 354.4
28.6 562.5
page 41
TOTAL
o
o
o
18.9
76.9
189.8
377 .3
608.3
These revenues, if mntinued for 50 years, can be shown to have a total
present worth (1983 dollars, calculated at 3.5%) of $9.0 million.
Another benefit whim may be attributed to the existence of an impound-
ment behind a Favorite Bay dam is that the Angoon cold storage plant
would not have to mnstruct a water filtration plant. The existing
water supply to the v-rllage of Angoon produces water whic'1 is yellowish
in color and has a definite taste and odor. Buyers would almost cer-
tainly object to fish whim were sold packed in ice made from untreated
Angoon water. The water from Favorite Bay Creek however, is very clear
with no objectionable taste or odor. Without the dam, the cold storage
plant would be forced to build a filtration plant capable of removing
the minerals or organic matter responsible for the taste, odor, and
color now in the water. While no finn data for the msts of such a
plant are available (without knowing specifically what contaminants
must be removed, it is not possible to develop meaningful estimates),
it is conceivable that they could run to the hundreds of thousands of
dollars over the 50 year economic analysis period of this study. The
water from an impoundment would only need to be chlorinated to make it
acceptable for use at the mld storage plant.
Other benefits, whim are difficult or impossible to quantify, but
whiCh would nonetheless exist if an impoundment were available, include
a larger and more reliable water supply for the village (important from
a fire fighting viewpoint); the possiblility of the developnent of an
improved sport fi shery above the dam (dolly varden, trout, landlocked
salmon, etc); the possibility of local 6TIployment in the mnstruction
trades (during dam and hatchery mnstruction) and in the local fishery;
and an increase in tourism revenues due to the plentiful salmon run
which would result from the hatchery operation.
page 42
F -THE THAYER CREEK HYDROELECTRIC PROJECT
At first glance, the developnent of a hydroelectric plant on Thayer
Creek (6 miles north of Angoon) se61lS to be an ideal opportunity. The
sites which have been investigated by at least two earlier reports are
simply ideal places to put dams. The creek has sufficient flONS (mean
annual flONS on the order of 400 cubic feet per second) to generate all
the energy Angoon muld possibly use; the lONer end of the creek passes
through a gJrge no wider than 100 feet in some places, with solid rock
walls on either side (although some shales and slates are present in
places); the creek is regulated by Thayer Lake; and salmon do not
migrate above the falls which mark a pro~sed damsite.
In their 1979 report, the Harza Engineering Company estimated the cost
of a Thayer Creek hydro project (complete with access roads and trans-
mission lines) to be $9.4 million. To escallate this price to 1983
dollars, we apply increases of 10.7 percent for the periods 1979-1980,
10.5 percent for 1980-1981, 8 percent for 1981-1982, and 4.3 percent
for 1982-1983, a total of 37.8 percent. This yields a 1983 capital
cost estimate for the project of $13.0 million. With an assumption
that Year 1 of the project is 1988, such an expenditure would have a
present value of $10.8 million.
Harza provided a cost estimate of $40,000 per year in operation and
maintenance costs ($55,100 per year in 1983 dollars). Over a 50 year
period (Year 1 = 1988) this would represent a net worth of $1.2 million
in 1983 dollars. Note that this annual 0&1"1 mst is less than half that
given by Tryck, Nyman, and Hayes (and used in our analysis) for the
Favori te Bay pl ant.
Together, the capital mst and the 0&1"1 costs have a present worth of
$12.0 million. This value exceeds by more than $2 million (22 per-
cent) the fuel and O&M msts of the THREA system which would be saved
by the operation of a hydro plant, even under the assumption of the
hi gh ene rgy foreca st.
The lON-forecast benefit:cost ratio for this project under the above
assumptions is 0.44. Using the high energy use forecast, the ratio
becomes 0.69.
Another disadvantage of the Thayer Creek site is that it would not be
practical to develop as a multi-use facility. The site is too innac-
cessable to construct a hatchery; it is too far from the village to run
water lines for a new water source. Further, the transmission line to
the village would be run through Adniralty Island National Monument
land for virtually its entire distance. It is likely that the environ-
mentalist malition would work against allONing such a line's con-
struction. The Favorite Bay site, by mntrast is located such that its
transmission lines are routed through village lands for most or all of
th ei r di stance.
pa ge 43
It is the opinon of Acres' staff that the developnent of a Thayer Creek
site is inappropriate at this time. Further consideration may be given
to the site in the event that Angoon's energy needs grow beyond the
capaci ty of a Favori te Bay developnent. By the forecasts developed in
this report, there is little possibility that this could happen at any
time in the 20th century.
page 44
G -OTHER ENERGY TECHNOLOGIES
Previous reports1 ,2 discussed in varying detail other technologies
whi ch were fel t to be worthy of study for Angoon. For the most pa rt
these technologies were believed to be too expensive or to experimental
in nature. Ideas for power generation which were excmined and then
discarded included solar, wind, wood waste, interconnection to other
power systems, other hydro projects (Hassel borg Creek, Jim's Creek,
Kathl een Creek), and coa 1. It is the opi nion of Acres' staff that the
earlier reports were correct in dismissing those technologies from
detailed consideration.
One report 2 put forth the idea of constructing a tidal /Xlwer plant
at Angoon which would make use of the relatively high tidal velocities
in Kootznahoo Inlet. It is the opinion of Acres' staff that the
assumptions used in that report to arrive at the favorible analysis of
tidal power at Angoon are basically flawed. It is beyond the scope of
this document to provide a detailed analysi s of the tidal /Xlwer scheme
as it was proposed, but we do not believe that proper consideration was
given to many of the problens associated with such a scheme. Areas
such as anchoring of the units, maintenance, /Xlwer transmission, cor-
rosion protection, protection of the units from rocks moved by the
tides, and environmental effects are dismissed with what appears to be
1 i ttl e seri ous co nsi dera ti on.
Due to the prototypical nature of such a tidal power unit, any serious
consideration of its implenentation at Angoon is considered inappropri-
a te a t th i s tim e.
1. "Thayer Creek Project, A Reconnaissance. Report," by Harza Engineer-
ing Co., Chicag), for the Alaska Power Authority, 1979.
2. "Angoon Tidal Power and Comparative Analysis, Angoon, Alaska" by
Robert W. Retherford Div., IECO, for the Alaska Division of Energy and
Power Developnent, 1981.
PART H
COMMENTS RECEIVED FROM
REVIEW AGENCIES
comments were recei ved from:
A laska Department of Fish & Game
US Amy Corps of Engineers
LD Fish & Wildlife Service
--
11·K2LH
• ,I
,
.. ', ~..J l
, :
DEPARTMENT OF FISH AND GAME
Habitat Division
November 7, 1983
L c/.? /l-X" 1'--
~1r. Bob -baftler
Project Manager
Alaska Power Authority
334 West 5th Avenue
Anchorage, Alaska 99501
RE: Angoon Energy Alternatives
Dear Mr. Leftler:
Bill Sheffield, Governor
230 S. Franklin Street
Room 307
Juneau, Alaska 99801
Phone: (907) 465-4290
Rt-"CEIVED
'i()V 1 0 1983
AlAS •• I h(lRITY
The Department of Fish and Game has reviewed the report prepared by
Acres American entitled "A Comparative Economic Analysis of Electric
Energy Alternatives for Angoon, Alaska." First of all, we wish to
express our appreciation for your extension of the response time. We do
feel that our comments will help to correct some deficiencies in the
report.
Page 2, paragraph 5: It is stated that "an application has been made to
ADF&G by the Angoon Aquaculture Association for a permit to build a
sa 1 mon hatchery at Favori te Bay. II Actually, the permit was issued on
August 15, 1982.
Page 21, paragraph 1: Again, the hatchery permit has been issued for a
hatchery capacity of 7.5 million pink salmon eggs, 20 million chum
salmon eggs, and 1.5 million coho salmon eggs.
Page 26, paragraph 3: It is our understanding that if the Angoon
Aquaculture Association plans to finance the project with loans from the
Aquaculture Loan Fund, (1) they probably would be limited to 1 million
dollars, or 6 million if they received the official approval of the
Northern Southeast Regional Aquaculture Association and (2) the
provisions of these State loans call for payback after 6-10 years with
interest, rather than 10 years and interest-free, as stated in the
report.
paae 26, 7aragraph 5: The estimated operating costs of the hatchery
($ 46,000 year) appear rather high considering other PNP hatcheries of
similar size in the region. A more appropriate range might be $200,000
-250,OOO/year. However, we cannot completely evaluate the total costs,
as no breakdown of operational costs is included.
Mr. Bob Leftler -2-November 7, 1983
Page 27, Table 12: Prices listed for fish appear to be considerably
higher than the current (1982 Juneau area purse seine) prices of
$0.84/lb for coho; $0.20/lb. for pinks; and $0.47/lb for chums. The
1983 prices may be even lower.
Page 30, Table 14:
capacity, that the
in excess of brood
Table 14 indicates
Our estimates indicate, assuming a 32 million egg
hatchery would not have excess chum returns for sale
stock needs until the sixth year of production.
excess production in the fourth year.
Page 33, ~aragraph 7: The average weight for coho is listed as 12
pounds, t is is more likely to be 7-9 pounds. Average weights for
Southeast Alaska based upon catch statistics are 7.0 lb (coho), 3.8 lb
(pink) and 9.9 lb (chum).
Thank you for the opportunity to review the report. While we realize
our corrections primarily related to the facility as permitted, we feel
the most current information should be used.
If you have any questions please feel free to contact us.
S-incerely,
-:;<?~K~
Richard Reed
Regional Supervisor
cc: D. Hardy
page 48
ACRES RESPONSE TO LETTER FROM ALASKA DEPARTMENT OF FISH & GAME
1. Commen t:
Acre s '
Response:
2. Comment:
Acre s '
Res po nse:
3. Comment:
" ... the hatchery permit has been issued for a hatchery
capacity of 7.5 million pink salmon eggs, 20 million chum
sa lmon eggs, and 1.5 mi 11 ion coho sa lmon eggs."
The hatchery is designed to operate at production levels
of up to 50 million chum salmon green eggs in addition to
the 7.5 million pink and 1.5 million coho eggs as noted.
This "reserve" was included by the hatchery's designers in
order that the Aquaculture Association could adjust salmon
production as needed to meet their financial requirements.
No change in the text is needed.
" . if the Angoon Aquacul ture Associ ati on pl ans to
fi nance the project wi th loans from the Aquacul ture Loan
Fund, ... they are probably limited to ... 6 million
do 11 a rs. "
As a study exercise, this analysis is not required to
study the intricacies of loan programs available to the
Aquaculture Association. Any loan available to the Asso-
ciation would, because of the long lead time involved in
bri ngi ng the hatchery "on-1 i ne," defer repayment for some
time into the future. Whether this deferral is 10 years
or some other time is of 1 ittl e si gni fi cance to the out-
come of th is study. It is assumed that fundi ng needed
beyond that available from the Aquaculture Loan Fund w-lll
be provided with similar terms. What is important is the
study of the project without outright grants from the
s ta teo Such an approach tests the abi 1 i ty of a proj ect to
"stand on its own." No change in the text is needed.
" ... the provi si ons of these Sta te loans ca 1 for payback
after 6-10 years with interest, rather than 10 years and
interest-free. "
Acres' The text will be changed as required to show a payment
Response: deferral for 10 years and a 10-year payback period, with
interest calculated at 3.5 percent.
4. Comment:
Acres'
Res po nse:
"Prices listed for fish appear to be considerably higher
than the current (1982 Juneau area purse seine) prices of
$0.84/1b for coho; $0.20/"lb. for pi nks; and $0.47/1b for
chums. The 1983 prices may be even lower."
The draft report used salmon prices from the 1980 or 1981
seasons. The final report uses prices from 1983, which as
suggested by the comment, are considerably less than they
were in 1982. 1983 Juneau purse seine prices were as
5. COOlment:
Acres'
Res ponse:
6. COOlment:
page 49
follows: pink salmon $O.23/1b; chum salmon $O.30/1b; coho
salmon $O.40/1b. These data were given by Elaine Dinne-
ford of the Limited Entry Section of ADF&G in Juneau.
The pri ce of sa lmon has a tremendo us impact on the econ-
OOlics of the Falls Creek project. As the report shows,
the hatchery is called upon to "subsidize" the hydro
pl ant. Since Angoon residents have an alternative to
electricity generated by the Falls Creek plant (namely
THREA's diesels), they would be disinclined to purchase
electricity at anything but the lowest available price.
Thus, in orde r to make any sa 1 es of energy from Fall s
Creek, the pri ce of that energy must be such that the bi 11
to the consumers does not rise above the levels experienc-
ed if all the energy was suppl ied by THREA.
The text has been changed to make use of 1983 Juneau-area
ca tch pri ces.
II .a 32 million egg. hatchery would not have
excess chum returns for sale in excess of brood stock
needs unti 1 the sixth year of production. Table 14 indi-
cates excess production in the fourth year."
The return schedule was developed with the assistance of
the designers of the hatchery. If there is any error in
this assumption, its impact on the economic analyses will
be minimal because of the small numbers of fish harvested
in the early years of hatchery operation. No change in
the text is needed.
"The average weight for coho is listed as 12 pounds, this
is more likely to be 7-9 pounds. Average weights for
Southeast Alaska based upon catch statistics are 7.0 lb
( co h 0), 3.8 1 b (p ink ), an d 9. 9 1 b (ch um) . "
Acres' These numbers will be incorporated in the final version of
Response: the report.
'. t I
DEPARTMENT OF THE ARMY
ALASKA DISTRICT. CORPS OF ENGINEERS
POUCH 898
A N8 H 0 RAG E A LAS K A 99506
C to be r 27, 1983
"'I:~ ... y TO
ATT.NTION 0"':
Hydropower and Comprehensive
Planning Section
Mr. Raymond J. Benish
Alaska Power Authority
334 West Fifth Avenue
Anchorage, Alaska 99501
Dear Mr. Benish:
RECEIVED
OCT 3 1 1983
Thank you for the opportunity to review your draft report
"A Comparative Economic Analysis of Electric Energy
A 1 tern at i ves for Angoon, Alaska." In genera 1, we found the
report both interest i ng and i nformat i ve. ACRES appeared to be
quite resourceful, although somewhat arbitrary, in their
proposed cost sharing plan with the Angoon Aquaculture
Association.
Several rational cost allocation methods are available for
use on multipurpose projects such as Angoon. It is important
to separate these costs in a consistent manner to ascertai~ if
each use is in fact "paying its way." This prevents feasible
projects from carrying infeasible ones. We suggest use of the
separable costs remaining benefits method of cost allocation
for the Angoon project.
The "simple calculation" pg. 28, which increases the
hatchery's chum production by 11.2 million to cover the
additional $8.59 million in dam, intake, and access road costs
assigned to the hatchery by ACRES appears to be rather
simplistic. However, without the benefit of reviewing the
Aquaculture Association's report, it is difficult to determine
if the assumptions made regarding expansion, profit, etc. are
reasonable.
We did find the Monte Carlo approach to the sensitivity
analysis refreshing. This approach should aid you in decision
making. It may be useful to expand the possible salmon price
and catch variations in the program to more realistically
reflect possible changes in this very volatile industry.
-2-
If you have any questions regarding our comments please
contact Mr. Loran Baxter of our Hydropower and Comprehens i ve
Planning Section, at 552-3461.
Sincerely,
l/6!:tj!Jr(_~
Chief, Engineering Divfsion
page 52
ACRES RESPONSE TO LETTER FROM US ARMY CORPS OF ENGINEERS
1. Comment: "Acres appeared to be somewhat arbitrary, in their
proposed cost sharing plan with the Angoon Aquaculture
Association."
Acres' The 25 :75 cost spl it between the hydro pl ant and the
Response: hatchery for "common" faci lities (access road, dam, intake
structure, etc) was indeed arbitrary.
2. Canment:
Acre s '
Res ponse:
It will not likely be possible to sell electricity to
Angoon consumers at a cost higher than it is presently
sold by TI-lREA. With this constraint, it works out that
the hydro plant can absorb just about 25 percent of the
"common" project costs and all of the "hydro pl ant only"
costs (power house, turbines and generators, transmission
line, and O&M).
To a point, the hatchery can adjust its production levels
to meet varying fiscal needs. The initial operating plan
calls for the hatchery to operate at green-egg levels of
1.5 million coho eggs; 7.5 million pink eggs; and 20 mil-
lion chum salmon eggs. These figures represent the maxi-
mum design levels for coho and pink salmon eggs, but the
hatchery is designed to be operated at as many as 50 mil-
lion chum salmon eggs.
With this arrangement, it is understood that the hatchery
will be "subsidizing" the hydroelectric plant. Ho.vever,
as the final version of the report shows, with salmon
prices as low as they were in 1983, it is unlikely that
the hatchery/hydro pl ant wi 11 be abl e to generate adequate
levels of revenue.
"The 'simple calculation' pg. 28, which increases the
hatchery's chum producti on by 11.2 mi 11 ion to cover the
additional $8.59 million in dam, intake, and access road
costs assigned to the hatchery by ACRES appears to be
rather simplistic. However, without the benefit of
reviewing the Aquaculture Association's report, it is dif-
ficult to detennine if the assumptions made regarding
expansi on, profit, etc. are reasonable."
The calculations are indeed simplistic. They are intended
to be so. The objective of this report is to exanine the
potential at Angoon for the development of a hydroelectric
plant which can provide economic benefits for the
community. Until feasibility-level work is done, more
sophisticated analysis techniques will be unable to pro-
vide "better" results.
page 53
3. Comment: "We did find the Monte Carlo approach to the sensitivity
analysis refreshing ... It may be useful to expand the
possible salmon price and catch variations in the program
to more realistically reflect possible changes in this
very volatile industry."
Acres' The compliment on the use of the Monte Carlo technique is
Response: very much appreciated.
In the final version of the report, the range is expanded
considerably. As the main body of the text indicates,
there is a significant probability that the B:C ratio of
the hydro plant/hatchery could be less than unity.
T \ _l
RECEIVED
United States Department of the Interior OCT 3 1 1983
IN REPL Y REFER TO:
Mr. Ray Benish
Acting Executive Director
Alaska Power Authority
334 West 5th Avenue
Anchorage, Alaska 99501
Dear Mr. Benish:
FISH AND WILDLIFE SERVICE
P. O. Box 1287
Juneau, Alaska 99802
ALASK" ?Ql.AJ~R II.UTHORITY
October 26, 1983
Re: Favorite Bay Creek
Hydro Project
We have reviewed the subject draft report and offer the following comments:
General Comments
Our review of pertinent fisheries related sections of the report suggests that
more work would be required to fully assess the proposed hatchery operation.
We are particularly disturbed with the statement on
page 2 indicating that many assumptions used in this study need verification.
The validity of conclusions in the report, therefore, seems unclear.
Although the project is still in its early planning stage, it should be
recognized that a hatchery does not mitigate all project impacts. A range of
project impacts can be expected. We, therefore, recommend that an
environmental analysis be initiated in coordination with resource agencies.
Specific Comments
Page 4. Summary and Recommendations. A stream survey should be conducted to
update escapement counts (pink, chum and coho salmon).
Page 25, seventh paragraph. The Economics of a Favorite Bay Hydroelectric
Plant. This paragraph should be expanded to discuss the basis for assuming
that the Angoon Aquaculture Association would pay for 75 percent of the dam,
intake structure and access road.
Page 26, last paragraph, same section. The basis for various assumptions used
in deriving the economics of the hatchery operation should be discussed. We
further suggest that the economics of the proposed hatchery be compared with
existing hatchery operations in southeast Alaska.
Page 30, second paragraph, same section. Since the hatchery operation would
displace a major part of the existing salmon runs, loss of the natural run
should be subtracted from the hatchery revenue.
Thank you for the opportunity to comment.
Sincerely yours,
Jt/~ t!(/~
Field Supervisor
page 56
ACRES RESPONSE TO LETTER FROM US FISH AND WILDLIFE SERVICE
1. Comment:
Acre s'
Res ponse:
2. Comment:
Acres'
Response:
"We are particularly disturbed with the stat8l1ent on page
2 indicating that many of this study need verification.
The validity of conclusions in the report, therefore,
seem s un c 1 ear. "
The report is valid within constraints imposed by the lack
of detai led data on project costs and operati ons. The
prudent reader should not be "disturbed" by the report's
recommendation that assumptions used in the analyses be
verified by futher study. Indeed, a prudent reader should
be more disturbed by works which profess no flaws.
The scope of the report was to establish the economic via-
bi 1 ity of the proposed Falls Creek project before detai led
studies \vere commenced. Taken in this 1 ight, it is our
opinion that the validity of the report is quite clear.
" ... an environmental analysis [should] be initiated in
coordination with resource agencies."
It is entirely likely that the construetion of a dam at
the Falls Creek site would require the completion of an
Envi ronmenta 1 Impact Sta tement. Under federa 1 1 aw, an EI S
must be included " ... in every recommendation or report
on proposals for ... major Federal actions significantly
affecting the quality of the human environment."
A project at Falls Creek would require a "major Federal
acti on" in the form of the permits needed to back water up
into the Admiralty Island National Monument. The project
would also "significantly affect the human environment."
In addi ti on to the EI S, it is 1 ikely that a FERC 1 icense
woul d be requi red if the dam were used to generate power.
3. Comment: "A stream survey should be conducted to update escapement
co un ts. . ."
Acres' No doubt such a survey would be one of the undertakings
Res ponse: necessa ry to produce an Envi ronmenta 1 Impact Sta t8l1ent
(see Comment No.2).
4. Comment:" .di scuss the basi s for assuming that the Angoon Aqua-
cul ture Associ ati on woul d pay for 75 percent of the dam,
intake structure and access road."
Acres' See response to US Anny Corps of Engineers Comment No.1
Response: on page 52.
APPENDI X A
BENEFIT: COST RATIO SENSITIVITY ANALYSES
page a-I
APPENDIX A -BENEFIT:COST SENSITIVITY ANALYSES
Throughout the study of the economics of the Favori te Bay hydro project
and the Aquaculture Association's hatchery, no consideration was given
to the range over which project cost components could vary.
It is sometimes easy to lose sight of the point that all of the costs
put forth in a report of this type are estimates. These estimates may
be very carefully thought out, but the fact remains that it is not pos-
sible for a forecaster to dictate future energy growth rates, costs, or
revenues.
There are a number of approaches available to give the reader some idea
of the range over which the economics of a project may vary. A common
method is to identify the lowest and highest costs (or revenues) which
a particular project component could achieve. All of the the low-cost
(or low-revenue) values are then added up. This yields the absolute
lowest cost (or revenue) for the project. Summing the high-cost values
similarly yields the upper bound for project costs (or revenues).
In real life, it is rare that all components of a project will come in
at their lowest (or highest) possible cost. Thus, the upper and lower
boundaries established by the technique described above are normally of
very limited value to decision makers. Cost estimates could be made
more useful if some means were at hand to allow the individual cost
components to vary independently (and randomly) over their available
ranges. To carry out such a task by hand with more than a very small
number of cost components is virtually impossible. The wide availabil-
ity of computers makes a technique known as Monte Carlo analysis
attractive in this type of work.
Simply put, a Monte Carlo program makes random choices of cost (or rev-
enue) values for each of the components of the project under study.
These values are then sUlllTled to produce the total project cost. One
"pa ss" th rough such a procedure woul d provi de no more i nsi gh t into the
project cost than to show one possible cost. Thus, it is standard
practice to repeat the process a great number of times to generate a
"cost distribution" which is representative of the project.
When investigating a system which is to be studied over a number of
years (such as our power system), it is reasonable to allow each cost
component to vary through its range in each year of the study. An
appropriate discount rate is applied to the total costs incurred in
future years to provide a "real dollar" value for that year's cost.
The individual years' costs are summed to provide a net present 'North
of the project over its lifetime. The program runs through a large
number of "lifetimes" to develop a cost distribution for the project.
The approach taken in the sensi ti vi ty ana lysi s of the F avo ri te Bay pro-
ject paralells that taken in the original economic analysis. That is,
page a-2
the project was first eXc1T1ined on its own merits, with no consideration
gi ven to the costs or revenues attri buted-to the hatchery. A second
ana lysi s was carried out which tested the B: C rati 0 of the hydro pl ant
plus the hatchery costs and revenues. Thirdly, the B:C ratio of the
hydro plant, the hatchery, and the local fishing fleet (which would
catch fish released by the hatchery) was ex iIllined.
The base values assumed and the ranges over which they were allowed to
vary are given for each case on Tables A-I through A-3. These base
values are the same as those developed in the text of this report. The
ranges over which individual parameters are allowed to vary were
determined in cooperation with staff of Tryck, Nyman & Hayes (for fish
catch and price data) and the Alaska Power Authority (all other data).
Following Table A-3 is a rudimentary flow diagram of the computational
process used in the l"1onte Carlo run. Space 1 imitations prevent the
inclusion of significant detail. The diagram is included only to pro-
vide the reader with a graphic representation of the process involved.
The program "SPSS" mentioned in that figure is a widelyavailable pack-
age of stastical routines which is installed on most large computer
systems. All computations carried out for this project were done on
CDC equi pnent owned by Boei ng Computer Servi ces.
Follow i ng the flow ch art is a gra ph i c repre senta ti on of the out put of
the SPSS work. The cumulative probabilities of a Favorite Bay project
having lifetime B:C ratios below particular values are given for each
of our three analysis approaches. A broad pen was used deliberately to
give the reader the idea that these plots were to be used as represent-
ative values only.
It is interesting and instructive to compare the results of the Monte
Carlo program with the manual calculations presented in the text (Part
E of the report).
In the first analysis (Favorite Bay's B:C ratio calculated in isola-
tion), the manual calculations gave B:C ratios of 0.997 and 1.22 when
using the moderate-and high-growth forecasts, repspectively. The
Monte Carlo routine gives B:C ratios ranging from 0.82 to 1.45, with a
mean ratio of about 1.11. Fifty percent of the B:C ratios calculated
by the Monte Carlo routine were below 1.13. This would imply some
sensitivity to load, since this was virtually the only variable in the
manual approach to this analysis.
The second analysis (Favorite Bay plus the Angoon Aquaculture hatchery)
manual methods produced B:C ratios of 0.94 and 0.99 for the moderate-
and high-growth cases. The Monte Carlo routine developed B:C ratios
ranging from 0.95 to 1.47, with a mean ratio of 1.17. This "improve-
ment" in the ratios is due in most part to the variation in price which
was available to the salmon prices.
page a-3
The third analysis (similar to the second, but including the revenues
of the local fleet due to hatchery-produced salmon) yielded a high-
growth B:C ratio of 1.43. No moderate-growth ratio was calculated
manually as it was believed the load growth due to income earned by the
local fleet operators would push energy use to at least high-growth
levels. The Monte Carlo analysis for this scenario produced B:C ratios
rangi ng from 1.66 to 2.56, with a mean of about 2.07.
We can see that as the economic impact of the hatchery production is
given greater consideration, the sensitivity of the B:C ratio to energy
use is reduced. While such a result may be expected intuitively, it is
always comforting to be able to see some confinnation of one's
ex pecta t ions.
TABLE A-I --PARAMATERS USED FOR B:C SENSITIVITY ANALYSIS
(Case 1: Favorite Bay Hydro Plant)
page a-4
PARAMETER RANGE OF VARIABILITY
Energy Use
Fuel Cost
Generation-
Dependent O&M
Hydro Plant
Capital Costs
Hydro Plant O&M
Number of
Iterations
Discount rate
40 percent probabili ty of using the Acres low-growth projection; 40 percent probabili ty of using Acres I high-growth projection;
20 percent probability of using 110% of Acres' high growth projection. Energy use choices are assumed to remain constant
after 20 years into the study.
Fuel is assumed to cost $0.119 per kWh in 1993, with escallation rates of 2.0m., 2.25%, 2.50%, 2.75% and 3.0m. available each
year. Each escallation rate is assumed to be equally likely (20 percent probability each). Fuel price is assumed to remain
constant after 20 years into the study.
Base cost assumed to be $0.051 per kWh, with equally probable costs at -10, -5, + 5, and +10 percent. No escallation is
involved in this cost.
Base cost assumed to be $5,205,000, with equally probable costs of -10, -5, +10 and +20 percent. This expenditure is assumed
to occur in Year 6 (1999) of the study.
Base cost assumed to be $115,000 per year. Equally probable costs of -10, -5, +5, and +10 percent are avajlable each year.
This cost is not subject to escallation.
10,000
3.5 percent
PARAMETER
Energy Use
Fuel Cost
Generation-
Dependent O&M
Hydro Plant
Capi tal Costs
Hydro Plant O&M
Hatchery Cepital
Costs
Hatchery O&M
Number of Coho
Caught by AAA
Price of Coho
Number of Pinks
Caught by AAA
Price of Pinks
Number of Chum
Caught by AAA
Price of Chum
Iterations
Discount rate
See Case 1
See Case 1
See Case 1
TABLE A - 2 --PARAMATERS USED FOR B:C SENSITIVITY ANALYSIS
(Case 2: Favorite Bay Hydro Plant Plus Hatchery)
RANGE OF VARIABILITY
page a-5
Base cost assumed to be $11,410,000, with equally probable costs of -10, -5, +10, and +20 percent. This expenditure is assumed
to occur in year 6 (1988) of the study.
See Case 1
Base cost assumed to be $6,090,000, with equally probable costs of -10, -5, +7.5, and +15 percent. This expenditure is assumed
to occur in Years 6, 26, and 46 (1988, 2008, and 2028) of the study. Hatchery salvalge of 50 percent in Year 55 (2037).
Base cost assumed to be $824,000, with equally probable costs of -10, -5, +5, and +10 percent. These costs are not subject to
escallation
Base number assumed to be as shown in text discussion of hatchery economics. Equally probable catch level variations of -10,
-5, +5, and +10 percent are available to the program.
Base price assumed to be $3.85 per fish. Price variations of -25, -10, +100, and +200 percent were avaHable. These prices are
not subject to escallation.
Set in a manner similar to that used for coho.
Base price assumed to be $1.04 per fish. Price variations of -25, -10, +50, and +100 percent were available. These prices are
not subject to escallation.
Set in a manner similar to that used for coho and pinks.
Base price assumed to be $4.10 per fish. Price variations of -25, -10, +50, and +100 percent were available. These prices are
not subject to escallation.
10,000
3.5 percent
PARAMETER
Energy Use
Fuel Cost
Generation-
Dependent O&M
Hydro Plant
Capital Costs
Hydro Plant O&M
Hatchery C~i tal
Costs
Hatchery O&M
Number of Coho
Caught by AAA
Number of Coho
Caught by LFF
Price of Coho
Number of Pinks
Caught by AAA
Number of Pinks
Caught by LFF
Price of Pinks
Number of Chum
Caught by AAA
Number of Chum
Caught by LFF
P ri ce of Chum
Iterations
Discount Rate
page a-6
TABLE A - 3 --PARAMATERS USED FOR B:C SENSITIVITY ANALYSIS
(Case 3: Favorite Bay Hydro Plant Plus Hatchery and Local Fishing Fleet)
RANGE OF VARIABILITY
See Cases I and 2
See Cases 1 and 2
See Cases 1 and 2
See Cases I and 2
See Cases 1 and 2
See Cases 1 and 2
See Case 2
See Case 2
LFF catch calculated as discussed in text. Catch variations were assumed to be the same as AAA catch.
See Case 2
See Case 2
LFF pink catch set in the same manner as its coho catch.
See Case 2
See Case 2
LFF chum catch set in the same manner as its coho and pink catches.
See Case 2
10.000
3.5 percent
-> w a:
N
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o z
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[Ii]
~
Q
o
-J
~ f-
Calculations
SUBJECT:
a
o
~
I
•
•
•
't
B= AM.JCl..l
'Bene:~i-6
C. = A "1"\c.J<ll
c..osi-~
I
t
LB
B:C. Ka.t;o '::. ~ (,
(wrl~eJ'l 0 .. -1-10 ~j~ k)
I
" .
JOB NUMBER P.C2~"9., Oi
FILE NUMBER
SHEET OF
BY J bAIil)l!:l.4::~ DATE q-3-8~
APP DATE
In each year of the study, each cost
(and benefit) parameter (energy use,
maintenance costs, dam capital
costs, fish revenues etc.), is al-
lowed to select one value from among
five choices.
randomly and
The selection is made
independently from one
parameter to another.
The fuel price for each year is cal-
culat~d from the price of the previ-
ous year multiplied by a randomly
selected escalation rate.
At the end of each study year, the
cost and benefit parameters are sum-
med independently and the total
costs and benefits are added to
those calculated in previous years.
a.-7
At the end of the 55-year study period,
the present worth of the plan's ben-
efits are divided by the PW of the
plan's costs. This yields a B:C
ratio for that particular "lifetime".
Each lifetime B:C ratio is written
out to a storage file for future
processing. The program then re-
peats the calculation of the life-
time B:C ratio, a process that is
repeated 50,000 times.
When all 50,000 lifetime B:C ratios
have been calculated, the program
"SPSS" is used to provide a statis-
tical analysis of the resultsL This
analysis includes an identification
of the maximum and minimum B:C
ratios identified, the mean of the
population generated, and the number
of times each B:C ratio was encoun-
tered. These data were used to plot
the graphs provided on the following
page.
>
lJ.J
0:
ci z
:;::;
0: o u.
a e a-8
•
JOB NUMBER
Calculations FILE NUMBER
SUBJECT: SHEET OF
BY . I< I DATE Z-1.7-84 ..J
APP DATE
.
<S w a:-
LL
l.IJ
~,....
r:-": c::r'-'
..J
~
~
::> v
1 0 0
so
~o
'to 3
"lO
0
0.4-1.0 C.O z.'8
'B:( ~ATID
Curve 1: Benefit:Cost Ratio of Favorite Bay Hydro Plant vs. THREA Diesel
System
Curve 2: Benefit:Cost Ratio of Favorite Bay Hydro Plant and Angoon
Aquaculture Association Hatchery vs. THREA Dieser-System.
Curve 3: Benefit:Cost Ratio of Favorite Bay Hydro Plant and Angoon
Aquaculture Association Hatchery ~ Revenues to the Local
Fishing Fleet Operators
APPENDI X B
ALASKA Po..JER AUTI-iORIlY PROJECT EV,LlLUATION PROCEDURES
ALASKA POWER AUTHORITY
PROJECT EVALUATION PROCEDURE
I . Tl..('-Y 8.",
~'-"('>N' \, ... 1 211 T Ie,{
The Power Authority IS proj ect eva 1 uati on procedure refl ects the
organization's purpose and phi 1 osophy. The Power Authority was
established as an instrument of the State to intervene for the purpose
of bringing to. fruition worthy projects that would otherwise be excluded
from development by the constraints of financial markets. Most, if not
all, Alaskan capital intensive power projects would be precluded from
conventional financing due to the perception of added risk inherent in
building projects in small, isolated Alaska communities.
Thus, the Authority's approach to project evaluation does not
consist, as some have recommended, of using market financial parameters
to determine the ability of the project to generate sufficient sales to
cover revenue requi rements. Instead, the approach entai 1 s fi rst
assessing a project's "worthiness" apart from the constraints of
financial markets, and, second, determining if there is the ability and
political will to intervene to establish financing arrangements and
terms that permit the project to be financed. To reiterate, the
Authority's purpose is to intervene in financial markets to permit
worthy projects to be developed. A project evaluation procedure that
requires a project to pass a financing test using market conditions
would preclude the Authority from acting in keeping with its purpose.
The means that the Authority has adopted to assess a project IS
worthiness are consistent with traditional federal evaluation methods
for. public water resource projects. The goal is to maximize net
economic benefits from the state's perspective, tempered by
environmental, socioeconomic and public preference constraints. The
method attempts to identify the real economic resource costs of all
options under study; the magnitude of these costs are independent of the
entity that finances and implements the options.
The Authority's project evaluation procedure has evolved since 1979
and continues to undergo refinement. Some desired characteristics of
the procedures are:
1. Consistency from one study and market area to another.
2. Equity in the treatment of alternatives.
3. Practicality, given data limitations.
4. Responsiveness to statutory direction.
In general terms, the procedure entails (1) forecasting end use
requirements on the basis of assumptions regarding economic activity and
energy cost trends; (2) formulating various alternative plans to satisfy
the forecasted requirements; (3) estimating the capital, operation,
maintenance and fuel costs of each plan over its life cycle;
(4) discounting the cost of each plan to a common point in time;
(5) comparing the total discounted costs of each plan and determining
Project Evaluation Procedure
Page 2
the preferred plan; (6) evaluating the preferred.plan's cost of power
under a variety of financing arrangements in relation to anticipated
power costs without the plan; and (7) identifying those financing
arrangements which result in acceptable power costs.
Forecasting Future Requirements.
A planning period ;s first adopted to define the period of time
over which forecasts are developed and energy plans are formulated. The
length of the planning period is limited by the practical difficulties
of forecasting far into the future. A period of 20 years from the
present is normally adopted. End use requirements (space heating, water
heating, lights and appliances, and industrial processes) are forecast
over the planning period for each of three sectors (residential,
corrmercial/government, and manufacturing). The end use requirement
forecasts are initially developed irrespective of the form of energy
being used to energize the end use. The forecast for each end use
reflects a range of economic activity/population forecasts and a range
of overa 11 energy pri ces. Wi th respect to the fo nne r , economi c base
analysis founded on discreet developmental events is used as the basis
of forecasting rather than simple trend projections, whenever possible.
With regard to the latter, the end use forecasts reflect situations both
where energy prices, overall, rise faster than general prices and where
energy prices, overall, rise at a rate in keeping with general price
1 eve 1 s. (It can be expected that the actual energy costs of the
preferred plan will eventually be shown to fall within that range.) An
intermediate forecast is used as the basis for the initial planning
steps ... For each end use where more than one energy form is available to
energize that end use, a mode split analysis is performed. This is
accomp1 ished in the course of the following initial screening of
alternatives:
1. All reasonable alternative means of providing each end use are
identified.
2. The per unit cost of energy ;s detennined for each alternative
using the Power Authority's economic evaluation parameters.
3. The amount of energy (or the amount of energy savings) that
can be provided by each alternative is estimated.
4. For each end use, cost curves are developed showing relative
cost, over time, of providing the end use by each of the
reasonable alternatives.
5. The lowest cost means, or combination of means of providing
each end use is identified. This determines the mode split
after due consideration of the existing mode split and lag
time for substitution of energy fonns. The results also serve
as a tool for formulating energy plans, which is the next step
in the analysis.
Project Evaluation Procedure
Page 3
The forecasts address both ener~y and peak load requirements.
Plan Formulation.
The first stpp in formulating energy plans is identifying and
screening all reasonable energy supply and conservation options. These
include structural and non-structural alternatives and alternatives that
provide intermittent as well as firm energy. This is accomplished in
the course of the previous step in the analysis.
Existing energy generation facil ities and conservation practices
are also evaluated for their performance, operation and maintenance
costs, condition and remaining economic life.
Given the menu of options available, the relative cost and mode
split information developed in the course of forecasting energy
requirements, and any additional comparative analysis of the options,
two or more energy plans are formulated. Each plan must, with a
consistent level of reliability, meet the forecasted energy and peak
load requirements over the planning period.
Whether plans are formulated to meet electrical energy requirements
only, or both electrical and thermal requirements, depends upon the
results of the mode split analysis. If it is shown that thermal needs
should be met to a significant extent by electrical energy, then plans
are formulated to meet both thermal and electrical reauirements. If it
is shown, on the other hand, that electricity should not play a
significant part in providing thermal needs, then the bounds of the
study are_limited to electrical energy requirements only.
One plan is termed the "base case plan"; this plan is developed
assuming a continuation of existing practice in the study area and is
used as a common yard stick for comparison of the other plans.
If opportunities exist, a plan is formulated to improve the base
case plan by increasing its efficiency or by other means.
One or more additional plans are formulated incorporating various
combinations of options with the objective of identifying the lowest
cost plan that is environmentally and socially acceptable .
. The sequence and timing of plan components are optimized as an
integral part of plan formulation. This is accomplished by a systematic.
testing of different sequences and project timing in search of the
sequence and timing that results in the lowest present value of plan
costs.
Project Evaluation Procedure
Page 4
Discussion:
1. The Authority initially confined the forecasting to electrical
energy requirements only. There are two problems with this
approach. First, electrical energy supply plans often have
associated with them certain amounts of waste heat suitable
for space, water or process heati ng. In such cases, a
forecast of thermal energy requirements is needed to determine
the possibility of effectively utilizing this heat.
Second, in forecasting electrical energy alone, the analyst is
either explicitly or implicitly assuming a certain mode split
in those end uses where more than just electrical energy can
provide that end use. It is necessary to make the analysis of
mode split explicit, and to do so requires a forecast of end
use requirements rather than simply electrical energy needs.
2. In amplification of the procedure for mode split
determination, the goal is to determine, based on full
economic cost of alternatives and rational economic behavior,
the lowest cost way of providing the end-use.
Estimating Project Costs.
All costs for all projects are estimated with reference to a base
year and -in tenns of the base year price levels. Costs incurred in
future ye-ars reflect relative price changes only. Capital cost
estimates are "overnight" estimates.
Capital costs (in the year they are incurred) are added to annual
operation and maintenance costs and any fuel costs to give the total
yearly cost of a plan. The series of yearly costs is discounted to a
common point in time, typically the first year of the planning period.
Discussion:
1. A constant dollar approach has been adopted in the economic
analysis to keep from having to forecast a long tenn inflation
rate that would always serve as source of dispute, and to ease
the computational burden. As reported by the Water and Energy
Task Force of the U.S. Water Resources Council in their
December 1981 report entitled "Evaluating Hydropower
Benefits," the critical element in an analytical approach is
the "use of consistent assumptions about interest rates and
future prices." The Task Force endorses either IIlife-cycle
analysis" (which includes inflation) or lIinflation free
analysis". The Power Authority's approach is specifically
cited by the Task Force as an example of the latter.
Project Evaluation Procedure
Page 5
2. Life cycle analysis dictates, state statute requires, and the
long term planning horizon of a state government suggests that
the relative plan costs be compared over the economic life of
the projects under consideration. When hydroel ectri c and
steam plant projects are being addressed, the economic
evaluation period exceeds the 20 (or sometimes 30) year
planning horizon. Yet, it is inappropriate to forecast load
growth or escalation trends beyond the limits of the planning
period. Also, project economic lives differ for varying types
of facilities. These problems are handled by addressing costs
throughout the economic evaluation period, but by assuming no
load growth or cost escalation beyond the planning period.
Facilities are replaced throughout the economic analysis
period as dictated by their economic lives. Salvage values
are included in the final year of the period as necessary.
The economic evaluation period extends to the year that the
longest lived project (that is added during the planning
peri od) reaches the end of its economi c 1 i fe. For instance,
if a hydroelectric project with a 50-year economic life is
added in the tenth year of the planning period, the economic
evaluation period would be 60 years in duration.
Plan Comparison.
Plans are compared in terms of total net benefits. Net benefits
are equal to the gross benefits associated with a plan, less plan cost.
The benefits are defined as the discounted total cost of the base case
plan; sup~lemented by any subsidiary benefits of a particular plan (see
discussion).
The plan offering the greatest net benefits is the preferred plan
from an economic perspective. A benefit/cost ratio can also be used as
an indicator of a plan's cost effectiveness.
Discussion:
1. In the event a plan provides a beneficial output other than
that specifically being addressed in the study, incremental
costs required to realize that benefit are subtracted from the
benefit in each year, and these annual subsidiary net benefits
are discounted to the common base date.
2. Consider the following hypothetical example: All cost and
benefit figures are the sum of annual amounts discounted to
the base date.
Project Evaluation Procedure
Page 6
Plan Cost
Base Case 100
Pl an A 120
Pl an B 90
Base Case Evaluation -
benefits: 100
cost: 100
net benefits: 0
benefit/cost ratio: 1
Plan A Evaluation -
benefits: 100 + 10 = 110
cost: 120
net benefits: 110 -120 = -10
benefit/cost ratio: 110/120 = 0.92
Plan B Evaluation -
benefits: 100 + 15 = 115
cost: 90
net benefits: 115 -90 = 25
benefit/cost ratio: 115/90 = 1.28
Subsidiary
Net Benefit
10
15
SUMMARY OF RECOMMENDATIONS
Analysis Parameters for the 1983 Fiscal Year
Economic Analysis
Inflation Rate -0%
Real Discount Rate -3.5%
Real Oil Distillate Escalation Rate
2.5% -First 20 years
0% -Thereafter
Cost of Power Analysis
Inflation Rate -7.0%
Project Debt to Equity Ratio -1:0
Cost of Debt -12.0%
Economic Life and Term of Financing
Gasification Equipment
Waste Heat Recapture Equipment
-Under 5 MW
Over 5 MW
Solar: Wind Turbines, Geothermal and
Organic Rankine Cycle Turbines
Diesel Generation*
Units under 300 KW
Units over 300 KW
Gas Turbines
Combined Cycle Turbines
Steam Turbines (Including Coal
and Wood-fired Boilers)
Under 10 MW
Over 10 MW
Hydroelectric Projects
Economic Life
Term of Financing
Transmission Systems
Transmission Lines wI Wood Poles
Transmission Lines wI Steel Towers
Submarine Cables
Oi 1 Fi 11 ed
Solid Dielectric
10 years
10 years
20 years
15 years
10 years
20 years
20 years
30 years.
20 years
30 years
50 years
35 years
30 years
40 years
30 years
20 years
*Diesel Reserve Units will have longer life depending on use. Also this
economic life is by unit and not total plant capacity.
Inflation Rate
For the purpose of the economic analysis there is assumed to be no
inflation.
Recommendation: The inflation rate should therefore remain at 0%.
Discount Rate
As previously indicated in the Analysis Parameters of FY 82 the historic
inflation free cost of money to the utility industry appears to be
approximately 3.0%. Currently national and local economists and
financial experts estimate the overall real discount rate to be in the
range of 3% to 4% with a likelihood that the real cost of money for
utilities is increasing slightly due to the increasing size and cost of
electric generation projects currently being undertaken. It is also
acknowledged that historically the real cost of money in Alaska contains
an "Alaska factor" and is therefore somewhat higher than in the rest of
the nation. However, the discount rate is also intended reflect the
state opportunity cost of money and reflect long term trends.
Recommendation: In regards to the above analysis and review, the
Discount Rate should be set at 3.5%.
Escalation Rate
Based upon-a composite research of Energy Consulting Companies, national
and local economists, and Investment Brokerage Firms, the forecast of
distillate fuels (diesel and fuel oil) are expected to increase at an
average real rate of 2.5% per annum for the period from 1982 to 2001.
Beyond the year 2001 further increases in fuel are assumed to be zero.
This assumption ;s based upon the belief that although additional
increases are expected they are too speculative to quantify • .
Recommendation: The escalation rate for diesel and fuel oil be set at
2.5% per annum for the first 20 years of the economic analysis.
Thereafter, further increases in the rate are assumed to be zero.
Inflation Rate
For the 1983 Fiscal Year, national and local economists along with
Financial Institutions and Energy consulting Firms forecast the National
inflation rate between 6 and 8 percent.
Recommendation: The inflation rate should be set at 7% per year.
Debt to Equity Ratio
At the present time and under legislation currently in effect it is
difficult to estimate the extent of debt financing for future Power
Authority projects. It is also common utility practice to debt finance
capital intensive projects.
Recommendation: In spite of the Power Authority's legislation, the debt
to equity ratio for power project financing should remain at 1:0.
Cost of Debt
Cost of Debt is largely determined by the interest rate identified by
statute for loans from the Power Project Loan fund. That interest
rate is equal to the average weekly yield of municipal revenue bonds for
the previous 12 month period as determined from the Weekly Bond Buyers
30 year index of revenue bonds. This average is currently approximately
13%. It is anticipated that the average will decrease only slowly
during the-1983 fiscal year.
Recommendation: Because of the anticipated slow decrease in the weekly
revenue bond index it is recommended that the cost of debt be set at 12%
to reflect current long term tax exempt rates with a decreasing
participation of the Rural Electrification Administration in providing
federal low interest financing.
Economic Life and Term of Loan
Although in certain instances economic lives of up to 100 years may be
warranted for hydroelectric projects, both the State Oivision of Budget
and Management and F.E.R.C. recommend the use of 50 year economic lives
for new hydroelectric projects. As a result the economic life of a new
hydroelectric project is set at 50 years and the term of financing at 35
years. For all other alternative generation sources, the economic life
and the term for which financing can be obtained is assumed to be the
same even though they vary for each alternative. The following economic
lives and loan terms should be used for various power project
alternatives.
Economic Life and Term of Financing
Gasification Equipment
Waste Heat Recapture Equipment
Under 5 MW
Over 5 MW
Solar, Win~ Turbines, Geothermal and
Organic Rankine Cycle Turbines
Diesel Generation*
Units under 300 KW
Units over 300 KW
Gas Turbi nes
Combined Cycle Turbines
Ste~m Turbines (Including Coal
. and Wood-fired Boilers)
Onder 10 MW
Over 10 MW
Hydroelectric Projects
Economic Life
Term of Financing
Transmission Systems
Transmission Lines wi Wood Poles
Transmission Lines wi Steel Towers
Submarine Cables
Oil Filled
Solid Dielectric
10 yea rs
10 yea rs
20 years
15 years
10 years
20 years
20 years
30 years
20 years
30 years
50 years
35 years
30 years.
40 years
30 years
20 years
*Oiesel Reserve Units will have longer life depending on use. Also this
economic life is by unit and not total plant capacity.
Inflation Rate
Or. Scott Goldsmith
r.S.E.R. 6.0%
Or. David Reaume
Economic Consultant 7.0%
Lehman Brothers,
Kohn Loeb ~.O -6.0%
Or. Bradford Tuck
University of Alaska 6.0%
Donald MacFayden
Salomon Brothers 6 -8%
Peter W. Sugg
URS/Cloverdale &
Colpitts-6.0 -7.0%
Gary Anderson,
Stanford Research
Institute 7.0%
Or. Mike Scott
Battelle Pacific
N.W. Lab. 5.0 -7.0%
Mr. Thomas 'Lhurber
Data Resources, Inc. 6~··5.%
Victor A. Perry III
Bechtel Corp. 5.0%
William L. Randall
The First Baston
Co rp . 7 . 0 -8. 0%
',.1m. Micheal'McHugh
Applied Economics
Associates 7.0 -8.0%
Fredric J. Prager
Smith, Barney, Harris
Upnam & Company 5.0 -6.0%
John De 1 roca 1 i
Whartan Econometric
Fat-casting Asso.
Micn~el G. Maroney
Peat, Marwick &
Mitchell, rnc.
Cvu __ r __ _
7.0%
6.5%
REFERENCE
Discount Rate Fuel Escalation Rate
3.0% 2.3%
3.0% 2.6%
3.0 -3.5%
3.5% 2.65%
4.0% 3.0 -4.0%
4.0t% 4.0%
4.0 -4.0t% 3.0%
3.0% 2.7%
3.0% 2.0%
3.0% 2.5%
3.5% 3.0 -3.5%
3.5% 3.0 -3.5%
4.0% 2.5%
2.3~
3.0% 2.5%