HomeMy WebLinkAboutFindings and Recommendations Angoon Hydropower 1984Findings and Recommendations
Angoon Hydropower
Alaska Power Authority
December 1984
Larry D. Crawford, Executive Director
Brent N. Petrie, Acting Associate
Executive Director, Planning
Project Leader: Bob Loeffler
Project Economist
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Findings and Recommendations
Angoon Hydropower
Alaska Power Authority
December 1984
Larry D. Crawford, Executive Director
Brent N. Petrie, Acting Associate
Executive Director, Planning
Project Leader: Bob Loeffler
Project Economist
Copyright 1984 by Alaska Power Authority
ALASKA POWER AUTHORITY
MEMORANDUM
TO: Gordon Harrison s Associate Director DATE: December 13 s 1984
Division of Strategic Planning
Office of Management and Budget
Richard A. Lyons Chairman~~
Board of Directors
Alaska Power Authority
FROM:
SUBJECT: Findings and Recommendations
Angoon Hydropower
In accordance with AS 44.83.179 s this memo transmits the Alaska Power
Authority's Findings and Recommendations for Angoon Hydropower for your
review.
The Findings were approved by the Power Authority's Board of Directors
at its December 13 meeting. The Board found that the potential hydro-
electric project at Favorite Bay is economically infeasible and more
expensive than continued diesel generation. We note thats since 1979 s
the Power Authority and its consultants have studied two potential
hydroelectric sites (Thayer Creek and Favorite Bay)s studied tidal power
generation in Kootznoowoo Inlets and installed a waste heat system to
the diesel powerplant of Tlingit-Haida Regional Electric Authority.
Unfortunatelys there is no project that could lower the electricity
costs to Angoon. Efficient diesel generation with waste heat recovery
appears to be the best alternative.
BL/ald
7491/075
Chapter I.
Chapter II.
Chapter II I.
2699/231/Fl
Findings and Recommendations
Angoon Hydropower
TABLE OF CONTENTS
List of Tables
Li st of Fi gures
Findings and Recommendations Summary
Introduction
A. Background Information
B. Information Sources
C. Project Costs
D. Organization of this Report
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iii
iv
v
1
1
3
4
6
The Existing Infrastructure: Electricity, Water Supply,
and the Hatchery Proposal 8
A. Exi st-j ng El ectri c System
B. Existing Water Supply System
C. The Hatchery Proposal
Economic Feasibility of Hydropower
A. Expected Economic Return
1. Benefit/Cost Analysis
2. Cost of Power Analysis
- i -
8
11
12
14
14
15
19
Chapter IV.
Appendix
2699/231/ F1
B. Sensitivity Analysis
C. Impl ications for the Hatchery and Water Supply
Project
Public Review
A. Presentation to Angoon City Council
B. Written Comments
A. Construction Cost Estimates
B. Rough Estimate --Hatchery-sized Dam
C. Operation and Maintenance Estimates
D. Economic Calculations Benefit/Cost Analysis
20
25
27
27
30
40
45
46
48
E. Economic Calculations -~ Cost-of-Power Analysis 50
F. Economic Calculations --Sensitivity Analysis 53
G. Economic Analysis Parameters 56
Footnotes 58
- i i -
List of Tables
Table No.
1. Summary of Construction Costs
2. Cost of the Proposed Hydroelectric Project
3. Constructi on Costs of the Multi -Purpose facil i ty
4. Angoon Electric Rates
5. T-HREA's 1983 Load Projection
6. Reconnaissance Report Load Forecast Assumptions
7. Cost of the Proposed Hydroelectric Project
Page No.
v
vi
5
8
9
10
16
8. Summary of T-HREA's Displaceable Costs 17
9. Benefit/Cost for Favorite Bay Hydro 18
10. Sensitivity Analysis: Change in Construction Cost 22
11. Sensitivity Analysis: Change in Oil Price Forecast 23
12. Sensitivity Analysis: Change in Load Forecast 24
D-1. Costs Displaced by Hydropower 49
E-1. Forecast Hydropower Electricity Prices 51
E-2. Forecast Diesel Electricity Prices. 52
F-1. Sensitivity Analysis 0% Increase in Fuel Prices 54
F-2. Sensitivity Analysis -3% Increase in Fuel Prices 55
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• ~. ~ 0-____ -' • •
List of Figures
Figure No.
1. Project Location
2. Projected Electricity Prices
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Page No.
2
21
Angoon Hydropower
Findings and Recommendations
Summary
The proposed hydroelectric project on Favorite Bay Creek is not econom-
ically feasible. The 50-year life-cycle cost of the hydroproject is
significantly greater than the cost of producing the same amount of
electricity using diesel generators. This report draws no conclusions
concerning the technical or economic feasibility of the proposed water
supply system or hatchery. Other findings are listeq below.
Total Project Construction Costs
Construction costs for the hydro/hatchery/water supply facility are
given below. These costs are rough estimates (1984 dollars) and are
subject to inflation.
Table 1
Summary of Construction Costs
(Millions of 1984 $)
Power Generation System
Hatchery
Water Supply System
Access Road
Dam and Intake Structure
$ 3.3
6.4
3.1
1.6
8.2
Total: $22.6
Hydroelectric Costs
A portion of the total ptoject's construction cost is unique to the
hydroelectric proposal; that is, it would not be spent if hydropower
were not included in the multi-purpose facility. The dam and "intake
structure accounts for over one-third of the total construction cost.
Without hydropower, the hatchery and water supply projects woul d not
need an $8.2 million, 95-foot high dam. A 15-foot, $412,000 structure
would probably suffice. Therefore, the hydroelectric project is
responsible for the difference in cost: $7.8 million. The total
2699/231/Fl - v -
50-year cost of the project is summarized in Table 2. The Table's costs
are in millions of 1984 dollars discounted to 1988 the project's
possible on-line date.
Table 2
Cost of the Proposed Hydroelectric Project
Description
Construction Cost:
Power Generation System
Construction Cost:
Dam and Intake Structure
Hydro Operation and Maintenance
Lost Waste Heat Benefits
Total Life-Cycle Costs:
Benefit/Cost.
Present Value Costs
(Millions of 1984 $)
$ 3.3
$ 7.8
$ 2.8
$ 0.5
$14.4
The benefits of the hydroelectric project are the diesel costs
displaced. Depending on load forecast assumptions, these are likely to
be between $7.3 mill ion and $9.3 mill ion. The benefits are five to
seven million dollars less than the costs. The benefit/cost ratio
varies between 0.5 and 0.6 (depending on load growth assumptions).
Consequently, the project is economically infeasible.
Sensitivity Analysis.
The major variables in the economic analysis include future oil prices,
future load growth, and the construction cost estimate for hydropower.
Significant variation in each of these three assumptions does not bring
the project close to break-even feasibility. Therefore, no further
study to more closely define projections or costs are warranted.
2699/231/Fl -vi -
CHAPTER I. Introducti on
A. Background
The Alaska Power Authority is currently studying a combination hydro-
power/hatchery/water supply project on Favorite Bay Creek near Angoon.
The project was identified by individuals in Angoon and by various water
supply and energy studies. There are advantages to a combined project
because the project's components --hydropower, hatchery, and water
supply --could share joint facilities. An impoundment and a road to
the site would be necessary for anyone of the projects and all three
would cost less if these expenses could be shared.
Th is report presents the Power Authori ty' s conc 1 us ions concern i ng the
economic feasibility of the hydroelectric portion of the multi-purpose
project. It compares the 50-year 1 He-cycle cost of hydropower with the
50-year 1 He-cycle cost of the next best alternative --diesel. The
purpose is to determine if one technology is more economical, if further
study is necessary to determine the answer, or if the hydropower
alternative should be dropped without further study. This report does
not draw conclusions concerning the economic viability of either the
hatchery or the water supply projects.
The Favorite Bay site is 4.5 miles from the village of Angoon. (See
Figure 1). The hatchery would be located apprOXimately 600 feet
upstream from the mouth of Favorite Bay Creek and 1,200 feet downstream
from the proposed damsite. The powerhouse for the hydroelectric facili-
ty would be located approximately at the hatchery location. The water
supply system would take water either from the penstock (between the dam
and the turbines) or from the turbines' tailrace. Some pumping would be
necessary to lift the water to the water supply storage tank in Angoon.
The dam is expected to be 95 feet above its base elevation of 20 feet
above mean sea level.
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ADMIRALTY
ISLA ND
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FIGURE 1
Project Location
Boy
- 2 -
B. Information Sources
Most of the information in this report is taken from the Reconnaissance
Report titled A Comparative Economic Analysis of Energy Alternatives
for Angoon, Alaska, February 1984 (hereafter referred to as
"Reconnaissance Report"). That work, produced on contract to the Power
Authority, provides the consultant's assessment of the relative economic
costs of hydropower versus diesel. These Findings and Recommendations
provide the Power Authority staff's analysis. The figures in this
report are taken from that study. The conclusions, however, are much
different. The differences are due to different methods of analysis.
There are other, minor changes between this report and the consultant's
study. Figures in that report were in 1983 dollars. These have been
updated to 1984 dollars. In addition, present value figures have been
discounted to January 1, 1988--the possible on-line date of the hydro-
electric project. Other useful reports are listed below.
Angoon Hatchery Concepts, September 1980. Prepared by Tryck, Nyman &
Hayes for Angoon Aquaculture Association.
Angoon Ti da 1 Power and Comparati ve Ana lysi s. February 1981. Prepared
by International Engineering Company, Inc. for the Alaska Division of
Energy and Power Development (funded by the Alaska Power Authority).
Kootznahoo Head Water Resources Study, Angoon, Alaska. May 1981.
Jay Farmwald, P.E., Design Engineer, Environmental Health Branch, Alaska
Area Native Health Service.
Angoon Water Supply Al ternatives. July 1981. Prepared by Tryck, Nyman
& Hayes for the Alaska Power Authority.
Angoon Hatchery Final PNP Permit Application. January 15, 1982.
Prepared by Tryck, Nyman & Hayes for Angoon Aquaculture Association.
2699/231/Fl - 3 -
Angoon Cold Storage Proposal. Prepared by Peter H. Nease, Planner.
Angoon Aquaculture Association.
Tlingit and Haida Regional Electric Authority 1983 Power Requirements
Study.
C. Project Costs
The multi-purpose facil ity has five major cost components: the access
road to the site, the dam and intake structure, the power generating
system (e.g., turbines, generators, transmission line, etc), the water
supply system, and the cost of the hatchery itself. The first two
components --the dam and the access road --are joint costs; that is,
they serve all three projects. These costs should not be allocated to
only one project; rather, they should be shared among the three. In
this way, the three projects are less expensive as a group than they
would be if built individually (and each one had to build a road and a
dam) .
An estimate of the construction cost of the project is shown below.
Although construction would not occur until 1988, the cost estimates
below are in 1984 dollars to facilitate comparisons with other projects
around the State.
2699/231/Fl - 4 -
Table 3
Construction Costs of the Multi-Purpose Facility
(Millions of 1984 $)
Water
Descri~tion Hi:dro~ower Hatcheri: Su~~li:
Power Generation System $3.30
Hatchery $6.39
Water Supply System $3.11
Access Road
Dam and Intake Structure
$3.30 $6.39 $3.11
Total: $22.52 Mi 11 ion
Co IlInO n
Costs
$1.55
8.17
$9.72
The road provides other benefits besides supplying a course to the
multi-purpose facility. It provides access to currently inaccessible
lands near the town which are useful for recreation, subsistence, and
possibly for forestry. Funding for the road is a priority capital
improvement for Angoon. Most of the road is likely to be built whether
or not the total project is developed. If the entire road cost is
considered to be independent of the project, the total project cost
would decrease to $20.97 Million (1984 dollars).
The cost estimates are important. The major conclusion of this report
is that the hydroelectric project is not economically feasible; its
costs are too high for the amount of electricity it will produce. The
cost estimate is an important part of that conclusion. Therefore, the
cost estimates for the various components of the project are reproduced
in Appendix A (and updated to 1984 dollars).
Most of the hydroelectric costs appear to be shared costs. The economic
cost of hydro-generated electricity is very dependant upon the portion
of those shared costs that are attributable to the hydroproject; those
hydropower-attributable costs are portions that could be saved if the
hatchery and water supply projects were buil t without hydropower.
2699/231/F1 - 5 -
The consultant arbitrarily assumed that 75% of the joint costs should be
borne by the hatchery and only 25% by hydropower:
"75% 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% of the cost
of these items plus all parts of the project which are unique to
the generation 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 commercial fishery which will be enhanced by its existence."l
The 75-25 distribution of costs causes the hydroelectric project to
appear inexpensive and the hatchery to appear expensive.
The Power Authority rejects this arbitrary classification of costs. In
fact, we believe that most of the joint costs could be saved if a small
dam, appropriate for the hatchery, replaced the large dam required for
hydropower. This more realistic cost distribution dramatically changes
the conclusions. With this new analysis, the life-cycle cost of
hydro-generated electricity is much more expensive than diesel-
electricity. This analysis shows that the hatchery and water supply
projects would be less expensive if the hydropower portion of the
facility were not built.
D. Organization of this Report
The most important information of this report is in Chapter III--the
Economi c Feas i bi 1 ity of Hydropower. That chapter provi des the cost
benefit analysis, a preliminary comparison between the project's
expected electricity cost and the expected cost for diesel electricity,
and a sensitivity analysis that addresses the effect of changing cost
figures and assumptions on the conclusions. Chapter II briefly outlines
2699/231/Fl - 6 -
the existing electric system, the water supply system, and the hatchery
proposal. The appendices provide the basic data on which the
conclusions are built, the cost estimates, and tables of present value
calculations. The appendices should allow the interested reader to
trace the report's calculations in detail.
2699/231/Fl - 7 -
· --,-~ ... -----~.--.
CHAPTER II. Existing Infrastructure:
Electricity, Water Supply, and the Hatchery Proposal.
A. Existing Electric System
Electricity in Angoon is supplied by Tlingit-Haida Regional Electric
Authority (T-HREA), based in Juneau. Generation is from three genera-
tors rated at 400 kW, 300 kW, and 200 kW, respectively. The electricity
price schedule as of March 1984 is shown in Table 4.
NOTES:
Table 4
Angoon Electric Rates (March 1984) 1
Residential Rates
less than 300 KWH/Mo.
greater than 300 KWH/Mo. -
Small Commercial Rates
same as residential
Large Commercial Rates
less than 1,500 KWH
greater than 1,500 KWH
39.46¢1KWH
34.76¢/KWH
38. 28¢1KWH
33.59¢/KWH
Demand charge -if peak demand greater than 10 kW = $14.34/KW
Power Cost Assistance 2 16.621¢/KWH
1. Rates include a surcharge of 1.38¢/KWH but do not include the
power cost assistance subsidy. Thus, a consumer who purchased
250 KWH duri ng a month wi 11 see a pri ce of
39.46¢/KWH -16.621¢/KWH = 22.84¢/KWH
2. The Power Cost Assistance Program uses State money to subsi-
dize electricity rates to consumers and community facilities.
Consumers' electric bills are subsidized by 16.621¢/KWH for
the first 600 KWH of consumption each month. Effectively,
residential electric rates are almost cut in half.
Each community facility is entitled to the per KWH subsidy for
55 KWH's times the population of the community.
Source: Alaska Public Utilities Commission.
2699/231/Fl - 8 -
• _ ..... ~'--.... ---, ..... .!'_.
T -HREA has proj ected futu re loads for Angoon (Table 5). Accord i ng to
its projections, the existing system can accommodate Angoon's projected
loads through the end of the T-HREA planning period, 1992. The
Reconnaissance Report completed for the Power Authority modified
T-HREA's projection somewhat, subdivided the projection into low,
moderate, and hi gh-growth assumpti ons, and extended it through 2002.
These projections estimate that the installed capacity of the exi st"ing
utility can accommodate projected loads for all three forecasts --low,
moderate, and high growth --through 2002. Because of the importance of
the load forecast in the project's economics, it will be discussed
further in the economic analysis section.
Table 5
T-HREA'S 1983 Load Projection
Existing 1983 Consumers
Residential
108 residences each using
362 KWH/Mo.
Small Commercial
11 consumers each using
763 KWH/Mo.
Large Power
Two schools @ 10,417 KWH/Mo.
Public Street Lighting
Street lights @ 36,000 KWH/year
Projected 1992 Consumers
130 consumers using 380 KWH/Mo.
15 consumers using 900 KWH/Mo.
No significant growth
Any growth is offset by
installation of more energy
efficient lighting.
Public Authority (i.e. public facilities)
22 facilities each using Slight growth only
7,800 KWH/year
Generation loss -10%
Annual load factor -45%
KWH required: 1982 -1,125,000 KWH 1992 -1,222,640 KWH
Peak K~I requi red: 1982 -285 KW 1992 -338 KW
Source: Tlingit and Haida Regional Electric Authority 1983 Power
Requirements Study.
2699/231/Fl - 9 -
The Reconnaissance Report's projecti on makes some minor but different
assumptions in the number of residential consumers, but then subdivides
T-HREA's projection with the assumptions shown in Table 6.
Table 6
Reconnaissance Report Load Forecast Assumptions
High Growth Assumption:
Hatchery in operation
Cold storage operates for 10 months each year
PCAP subsidy ends*
Moderate Growth Assumption:
Hatchery in operation
Cold storage operates for 3 months each year
PCAP subsidy ends*
Low. Growth Assumption:
No Hatchery
No cold storage plant
PCAP subsidy ends*
Effect of Assumptions:
Hatchery -228 MWH/year
45 KW
Cold storage -10 months: 550 MWH/year
125 KW
* PCAP subsidy ends: This assumption decreases residential con sump-
t i on by 103 KWH/consumer/month. It has no effect on the KW re-
quirement or on other consumers. In addition, the assumption
concerning the Power Cost Assistance Program was not made as either
a prediction or a recommendation. Rather, it is a conservative
assumption with which to evaluate a hydroelectric project requiring
significant load growth to be economically feasible. Relaxing the
assumption does not change the conclusions of this report.
The Power Authority installed a waste heat recovery system at the T-HREA
generation plant. liThe heat energy recovered by that system is being
used by the sewa ge treatment plant, the grade schoo 1, the hi gh school
gym, and the teacher's 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
(del ivered), this heat is 'worth' about $28,900 per year."2 The value
2699/231/Fl -10 -
of the heat recovered each year should increase as the price of oil
increases.
B. Water Supply System
Domestic water for Angoon comes from a small reservoir across Kootznahoo
Inlet from Angoon. The reservoir, known as Stromgren Lake, is impounded
by a log-crib dam. It is supplemented by two beaver dams upstream from
the lake. Water comes to Angoon through a 7,000 foot pipeline which
includes a 1,000 foot section running under Kootznahoo Inlet. The
pipeline connects the reservoir to a 100,000 gallon storage tank. Water
treatment includes pressure sand filtration, chlorination, and
fluoridation.
The water supply system has three major problems: 1) inadequate water
quality, 2) inadequate amount of water, and 3) poor reliability of the
section of the water line running under the bay. However, there are
different opinions on the magnitude of these problems.
Because Stromgren Lake watershed includes a high proportion of muskeg
and two beaver ponds, its water has a noticeable color and odor. Though
these problems are most noticeable during times of low flow, water
quality tests carried out during those times indicate that water quality
appears to meet EPA drinking water quality standards.
A 1981 Pub 1 i c Health Servi ce study concl uded that the S_tromgren Lake
watershed contains enough water to supply the domestic needs of Angoon
through the year 2000 if little water-using industrial development
occurs. The study concludes that the watershed's existing storage is
"18% more than the projected requirement ... " and that "Based on the
driest period on record the maximum yield of this reservoir was estimat-
ed to be 120 gpm or 43% more than the design maximum daily demand."3
The report goes on to recommend improvements to the system i ncl uding
repairing the dam and possibly increasing the diameter of the pipeline.
2699/231/Fl -11 -
A July 1981 study by Tryck, Nyman, and Hayes, an Anchorage engi neeri ng
firm, came to different conclusions. It concluded that additions to the
Stromgren Lake water source are necessary. The Tryck, Nyman, and Hayes
study also comments on the reliability of the underwater .portion of the
existing pipeline system. liThe system is relatively new (built in 1965)
but reliability is low due to frequent breakdowns. Since this is the
only water supply system available to the community, it often creates an
intolerable situation when the community is left without water for
extensive periods of t·ime."4
The Tryck, Nyman, and Hayes study recommends that a new water supply
system be developed as part of a Favorite Bay Creek multi-purpose
electric power/hatchery/water supply project. If the large multi-
purpose project is not constructed, the st1Jdy recommends a run-of-the-
river system on Small Creek, a tr'ibutary to Favorite Bay Creek.
C. Hatchery
In August 1982, the Al aska Department of Fi sh and Game approved a
private non-profit hatchery permit submitted by Angoon Aquaculture
Association subject to certain stipulations. One of these stipulations
reads, liThe hatchery wi 11 not be constructed unti 1 the proposed Angoon
dam and reservoir are in'place to provide a controlled, stable, adequate
water source".5 Approved production levels are 7.5 million Pink eggs,
1.5 million Coho eggs, and 20 million Chum eggs. If the hydroelectric
portion of the facil ity were not built, the Aquaculture Association
would be required to amend its permit.'
The motivation for the hatchery is local economic development. The
hatchery could increase the catch for the local fishing fleet. Greater
catch would complement a new Cold Storage facil ity in Angoon. The
combination of increased catch and ability to use cold storage for
1 imited local processing is intended to increase local employment and
increase fishing earnings of village residents.
2699/231/Fl -12 -
The hatchery does not yet have a detailed design. Also, no application
has been made to the Fisheries Development Revolving Loan Fund (the
typical state hatchery funding source), nor is there any other firm
financial commitment. Hatchery funding is expected later in the project
development process.
2699/231/Fl -13 -
CHAPTER III. Economic Feasibility of Hydropower
A. Expected Economic Return
Because Favorite Bay Creek is a multi-purpose composite of hydropower,
hatchery, and a water supply project, the economic analysis is somewhat
complicated. The joint facilities make each project less expensive and
economically more attractive, but there still needs to be an analysis of
the individual components to insure that each is economically viable on
its own.
The most important conclusion of this section is that while the multi-
purpose facil ity as-a-whole may have positive benefits, the hydroelec-
tric portion does not. If the facility were built without the hydro-
electric component, the cost would be less and the benefits would be
greater than if the hatchery, water supply, and hydropower projects were
built together.
Determining the economic feasibility of the hydroelectric portion of the
facility requires consideration of its expected costs and benefits. At
a minimum, the hydro·s costs must include the unique hydro-related costs
(e.g., turbines, transmission lines) but also that portion of the joint
costs which are uniquely attributable to the hydroproject. The objec-
tive is to find all funds which would not have to be spent if the
hydroelectric project were dropped from the multi-purpose facility.
The Power Authority·s economic evaluation procedure is designed to
compare the real resource costs of the various projects under
consideration --in this case, hydropower and diesel. These costs
include construction, operation, maintenance, and fuel costs. The
procedure specifies that costs be forecast over the life of the longest
project under consideration: hydropower with a 50-year life. Thus, the
procedure compares total life-cycle costs of diesel over 50 years versus
the cost of 50 years of hydropower. The parameters specify a 3.5% real
2699/231/Fl -14 -
discount rate and also establish a 20-year planning period in which
future electric loads and oil prices are forecast. For Angoon, electric
and oil prices are forecast to increase through 2004 and are then held
constant. The hydroproject could be on-line "in 1988; therefore, the
life cycle analysis compares costs through 2037.
Figures in this report, unless otherwise specified, are in January 1,
1984 dollars. Thus, they can be compared with the cost of today's con-
struction projects. The present value analysis discounts all costs to
the possible on-line date of the hydroproject, 1988.
Benefit/Cost Analysis
Costs.
The hydroelectric project's costs include the construction cost of the
power generation system, construction cost of the dam and intake
structure, the 50-year operation and maintenance cost, and the "cost" of
losing the waste heat benefits from T-HREA's diesels.
The construction cost of the power generation system is relatively
straight-forward. It is the cost to construct (as shown in Appendix A)
the powerhouse, transmission line, etc.; it is $3.3 million.
Determining the hydroproject's share of the dam and intake structure is
more compl ex. The 1984 constructi on cost of the 95-foot dam and the
intake structure is $8.2 million. The dam impounds the water needed to
generate electricity, supply the hatchery, and provide a water supply.
However, if the hydro facility were not built, the hatchery would not
need a multi-million dollar 95-foot dam. Using extremely rough esti-
mates, the hatchery might need a 15-foot dam, or possibly smaller. This
smaller dam would impound enough water to guarantee that an unusually
low streamflow would not leave the hatchery dry. This smaller dam
2699/231/Fl -15 -
requires less than 2t% of the volume of the higher dam. A rough cost
for this smaller dam is $412,000. Therefore, the hydroelectric proposal
is responsible for the difference between the two costs, $7.86 million.
(Detail in Appendix B).
Estimates indicate that it will cost $121,233 per year (1984 "$) to
maintain the hydro system. (For detailed breakdown of the O&M costs,
see Appendix C.) The present value of these costs (31% real discount
rate, 50-year life) equals $2.84 million.
If the Favorite Bay hydro plant begins operation, the T-HREA diesels
would shut down and the waste heat system would be out of business.
That waste heat system provides benefits to the community. The loss of
these benefits must be counted as a cost to the project. The 50-year
net present value of the benefits are approximately $500,000.6
The 1984 present value costs attributable to the hydroelectric project
are shown in Table 7. The total life-cycle cost of the project in
present value terms (1984 dollars) is $14.4 million. That amount is the
real resource cost to construct, operate, and maintain the project
through the year 2037.
Table 7
Cost of the Proposed Hydroelectric Project
Description
Construction Cost: Power Generation System
Construction Cost: Dam and Intake Structure
Hydro Operation and Maintenance
Lost Waste Heat Benefits
Present Value
(Millions of 1984 $)
$3.3
$7.8
$2.8
$0.5
Total Life-Cycle Project Cost: $14.4
Benefits.
The benefit of the Favorite Bay hydroelectric project is the money saved
by not running the T-HREA diesel generators to produce the electricity.
2699/231/Fl -16 -
However, if T-HREA were to stop generating power altogether, it would
have on-going financial obligations to cover such items as financing of
equipment, administrative charges, maintenance of equipment and power
lines, insurance, taxes, etc. There are only a few costs which would
decrease or be eliminated with the construction of a hydroelectric plant
(or other alternative energy source) at Angoon. These are:
°Fuel ($780,475 in 1982)
°Generation Expenses ($276,615 in 1982)
°Miscellaneous Other Power Generation Expenses ($ 57,247 in 1982)
The total of these "displaceable" costs ($1,114,337) represents almost
50 percent of T-HREA's costs in Angoon. The figures are taken from the
Reconnaissance Report, Table 5, page 14. For more information, please
go to that source.
Most of these displaceable costs increase with the amount of electricity
generated. As the benefi ts of the hydropl ant are the T -HREA costs
displaced, the hydro's benefits depend on the projected electric gen-
eration. A full discussion of the T-HREA's displaceable costs and of
the projected electric generation is given in the Reconnaissance Report
(p. 13-20). However, a summary of displaceable costs is given in
Table 8.
Year
1983
1988
2000
2699/231/Fl
Table 8
Summary of T-HREA Oisplaceable Costs
(Figures in 1984 $)
Fuel
Costs
($/k~lh)
.125
.125
.178
Other
Costs
($/kWh)
.055
.055
.055
Unit
Oisplaceable
Costs
($/kWh)
.180
.180
.233
-17 -
Total Oisplaceable Cost
Moderate High
Growth Growth
Forecast Forecast
($1,000) ($1,000)
183 183
243 312
322 412
The table can be interpreted as follows. In 1988, the fuel cost for
electricity production is expected to be 12.5¢ per KWH. All of that
cost would be unnecessary if the Favorite Bay hydro begins operation
that year. In addition, T-HREA will save another 5.5¢/KWH of other
expenses for a total of 18.0¢/KWH. In the "moderate growth" load
forecast, Angoon is expected to need 1,350,000 kWh during 1988. In
1988, T-HREA will therefore save $243,000 (in 1984 dollars) if the
hydroelectric project produces Angoon's electricity. Over the 50 year
life of the project, from 1988-2037, the present value of the savings is
$7,119,000 for the moderate growth forecast, and $9,107,000 for the high
growth forecast.
Benefit/Cost Comparison.
The previous paragraphs outline the costs and benefits of the hydroelec-
tric portion of the multi -purpose hydro/hatchery/water supply project.
Table 9 compares that benefit and cost information. It shows that the
hydroelectric development at Favorite Bay is not economically feasible.
Its costs are much greater than its benefits.
Table 9
Benefit/Cost for Favorite Bay Hydro
(Present Value millions of 1984 $)
Benefits Moderate Growth
Displaced T-HREA Costs
Costs
Construction Cost: Power Generating System
Construction Cost: Dam and Intake Structure
Operation and Maintenance
Lost Waste Heat Benefits
$7.1
Total Costs
$ 3.3
7.8
2.8
0.5
$14.4
New Present Value
Benefit/Cost Ratio
$-7.3 (~1oderate)
0.5 (Moderate)
2699/231/Fl -18 -
High Growth
$9.1
$-5.3 (High)
0.6 (High)
The hydroelectric portion of the multi-purpose facility has a signifi-
cantly negative net present value {-$5.3 to -$7.3 million depending on
the load forecast}. Put another way, it has a benefit/cost ratio
significantly less than 1.0 {0.5-0.6}. In practical terms, this means
that over the 50-year life of the project, it would be less expensive to
rely on T-HREA's existing diesel generation of electricity than it would
to build the hydro project. It would be less expensive with greater
public benefits to build the hatchery and water supply projects alone,
without the hydro addition. Also, the table's calculations exclude all
joint costs, such as the access road or the lower porti on of the dam
necessary for the hatchery and water supply project. The Table only
includes the increment of additional costs that the hydro would require
if the hatchery and water supply system were already built.
The Power Authority has not analyzed and makes no conclusions concerning
the economic viabil ity of either the hatchery or the water supply
system. These systems may be feasible independent of the hydroelectric
project.
Cost of Power Analysis
The fact that the hydroelectric portion of the multi-purpose facility is
not economically viable means that the electricity it produces will be
more expensive than that generated by diesel. This can be shown by
ca 1 cu 1 at i ng e 1 ectri city pri ces expected from the hydroproject and from
continued reliance on diesel. Estimating future electricity prices
requires assumptions about electricity sales, inflation, and financing
arrangements. It is difficult enough to estimate the construction cost
without trying to guess the country's inflation rate over the next few
decades. Thus, the figures in this section are not precise predictions;
they are general estimates of the relative price of hydro-electricity
versus diesel-electricity. The figures incorporate standard Alaska
Power Authority project evaluation parameters: 6.5% inflation over the
next 20 years and 0% thereafter; 10% interest rate for funds loaned to
2699/231/F1 -19 -
the project; a financing term of 35 years; real oil-escalation rate of
0% through 1988, 3% for the following 16 years, and 0% thereafter; and
finally, load growth for 20 years only. Given these parameters, a rough
estimate of the relative electricity cost is given in figure 2.
The fi gure shows that under the moderate growth load forecast, at the
project's on-line date of 1988, diesel electricity will cost approxi-
mately 44¢/KWH, but if the hydro pri ce incl uded the full cost of the
project, it would cost $1.15/KWH. Even if the State paid 60% of the
financing costs, the electricity cost would be 64¢/KWH. In fact, if the
project absorbed its full costs, its electricity would cost more than
diesel until the loan is paid off in 2023. Conclusions are similar
under the high growth forecast; hydroelectricity would not cost
significantly less until the bonds are paid off in 2023.
B. Sensitivity Analysis
The conclusions of the economic feasibility section of this report are
based upon certain estimates: construction cost, load growth, and future
oi 1 pri ces. At thi s stage, all of the estimates are extremely rough.
It is important to test to see if change in any of the estimates would
change the conclusions. If so, further study to refine the estimate is
probably necessary. If not, the hydro facil ity should be rejected
without further study.
Construction Cost.
The intake structure, power generation system, and the hydro's portion
of the dam are estimated to cost $11.1 million. Brief review of the
cost estimate by the Power Authority indicates that $11.1 mill ion is a
low-cost estimate; that is, the structure is unl'ikely to be built for
1 ess than that amount. The estimate incl udes a contingency of 15% on
costs for the dam and 10% on costs for the power generation system.
Typically, reconnaissance level estimates include contingencies of 30%.
2699/231/Fl -20 -
FIGURE 2
ANGOON FORECAST ELECTRICITY PRICE
MODERATE GROWTH FORECAST
$1.70 ~,----------------------------------------------------------~
$1.60 ...l /111111111111111111
$1.50 l
$: .4-0 ~
$1 . .30 ~
$1.20 ~
$1.10 -i
~ 1 /' i I
~¥ ~DDDDDDooooooooOqOOOODOOOOOO~
-"",;-' / I i
,AoI.,i"r it i :
..>i<'''' I , : ~ \ j .~~ \ I ~. I' ( I
1
$1.00 -I \ I , I
\ ' :::: ' ~ $0.90 1
........ $O.BO-l .... I L 11111 11111 I! I !
$0.70 -1
$.0'
60 .J/1 • ~
$0.50 -I
$0.40 J
$0 . .30 -i
$0.20 j
$0.10
$0.00 iii iii iii Iii i
1985 1995
• i ;
o DIESEL
I
I I I ' I i I Ii' I I I Iii' I I i , I I ' iii I iii ii'
2005 2015 2025 2035
YEAR
+ HYDROELECTRIC
ANGOON FORECAST t-LECTRICITY PRIC~
HIGH GROWTH FORECAST
$1.70 ~I----------------------------------------------------------'I
$1.60 ~ I
$1.5 °1 I
$1.40 -1 1
$1 • .30 -i OOODOoOmp
$1.20 ~. I I
$1.10 -i !
~ :~:~:~ ~ I·
~ $O.BO ~ \
$0.70 -i \
$0.60 l 1 1 I 1 1 I 1 1 1 I 1 1 1 1
$0.50 -I
$0.40 ~
$0 • .30 -1
i $0.20 -I
I
$0.10 ...l :
$0.00 -:~~~~~~~~~~~I~I~I~'~I~~~~I~'-'~' ~I~~-'~I ~ITI~I~'~~~~'~I~:~I~
'985 1995 2005 2015 2025 2035
YEAR
o DIESEL + HYDROELECTRIC
2699/231/05 -21 -
Similarly, clearing was to be funded by the sale of timber. Power
Authority experience indicates that timber sale revenues are unlikely to
cover clearing costs. The construction costs are unlikely to be less
than the estimates.
It is possible, however, that the hatchery would require a larger dam
than the IS-foot structure this report expects. If so, the hydro
facility would need to absorb fewer costs. Table 10 shows the effect
that a 20% change in construction cost would have on the viability of
the project.
Table 10
S~nsitivity Analysis: Change in Construction Cost
(Present value millions of 1984 $)
Benefits
Moderate Forecast
High Forecast
Cost
--Constructi on
O&M
Waste Heat Lost
Net Present Value
Benefit/Cost Ratio
20% Decrease in 20% Increase in
Construction Cost Construction Cost
Total Cost
$7.1
$9.1
$8.9
2.8
0.5
$T2"":7
$-5.1 (Mod)
$-3.1 (High)
.6 (Mod)
.7 (High)
$7.1
$9.1
$13.3
2.8
0.5
$IO":""O
$-9. 5 (r~od)
$-7.5 (High)
.4 (Mod)
.5 (High)
The Table shows that a significant decrease in construction cost would
not change the initial conclusions. A 20% decrease in construction cost
does not bring the project close to break-even feasibility.
Oil Prices
The hydroproject's benefits are the costs saved by not running T-HREA's
diesels. The majority of those costs are fuel costs. If fuel prices
2699/231/Fl -22 -
increase, the benefits of the hydroproject increase. Current Power
Authority evaluation parameters call for stable oil prices (oil prices
fo 11 owi ng i nfl ati on) through 1988 and then a rea 1 3% increase through
the end of the planning period. In order to test the effect of a
sustained increase in oil prices, the benefits were recalculated
assuming a continuous real 3% increase in oil prices from 1983 through
the end of the planning period. The results of those calculations are
shown in Table 11. However, these higher benefits still do not make the
project feasible. For purposes of comparison, the Table also shows the
effect of assuming ,that oil prices do no more than follow inflation
(i .e., 0% real increase).
Table 11
Sensitivity Analysis: Change in Oil Price Forecast
(Present value millions of 1984 $)
3% Real Increase 0% Real Increase
In Oil Prices In Oil Prices
Benefits
Moderate Forecast $ 8.2 $5.8
High Forecast $10.5 $7.4
Costs
Construction $11.1
O&M 2.8
Waste Heat 0.5
Total Costs $1"4.4
Net Present Value $-6.2 (Mod) $-8.6 (t~od)
$-3.9 (High) $-7.0 (High)
Benefit/Cost Ratio .6 (Mod) .4 (Mod)
.7 (High) .5 (High)
Load Forecast
The benefits of hydro-generated power increase with the quantity of
electricity produced. This is because the cost of hydroelectric produc-
tion is mostly fixed, and extra production requires few extra costs. If
the load forecast used in this study underestimates future use of
electricity, this study underestimates the benefits of the hydro proj-
ect.
2699/231/Fl -23 -
The load forecast prepared for the Reconnaissance Report assumed that
sometime during the life of the hydro project the Power Cost Assistance
Program (PCAP) which subsidizes electric rates might end. The end of
the subsidy would cause a decrease in the use of electricity. To be
prudent, the Reconnaissance Report assumed that PCAP would end in 1986
and that the subsidy's end would cause a 20% decrease in residential
consumption but no change in commercial or government "consumption. This
assumption was a conservative approach to evaluating hydroproject
dependent on a large load to support it high capital cost. Recent
developments, most notably the Power Cost Equalization Program, makes
this conservative assumption less necessary than it seemed a year ago.
To test the effect of eliminating that assumption, benefits were
recalculated assuming that total electricity consumption (residential,
commercial, and government) was 25% greater than the amount assumed in
the Reconnaissance Report. The results are reported in Table 12.
Table 12
Sensitivity Analysis: Change in Load Forecast
Benefits and Costs Assuming 125% of Forecast Load.
(Present value millions of 1984 $)
Benefits
Moderate Forecast
High Forecast
Costs
Construction
O&M
Waste Heat
Net Present Value
Benefit/Cost Ratio
Total Cost
$ 8.9
$11.4
11.1
2.8
.5
14.4
$-5.5 (Mod)
$-3.0 (High)
.6 (Mod)
.8 (High)
The Table shows that an "increase in load will not br"ing the project
close to break-even feasibility.
It is also important to realize that the high forecast is actually a
2699/231/Fl -24 -
somewhat speculative estimate of future electricity use. That forecast
assumes that Angoon's cold storage plant (which has not yet begun
operation) operates 10 months each year. That level of operation
requires that a regional bottomfish industry develops and that Angoon
process a significant share of the regional catch. It also assumes the
hatchery's existence and its projected electricity consumption. If the
hatchery is not built, if a bottomfish industry does not develop, if
Angoon does not capture a significant share of the bottomfish catch, if
the cold storage plant operates for less than 10 months per year, or if
the cold storage plant produces its own electricity (they are not now
connected to the village electric grid), then the high forecast will be
an overestimate of local electric use.
The conclusion of the various sensitivity analyses is that no likely
change in cost estimates or assumptions can make the hydroproject
economically feasible. Consequently, no further study is necessary.
C. Implications for the Hatchery and Water Supply Project.
The three projects --the hatchery, the water supply system, and the
hydropower --are expected to share the cost of the dam and access road.
What happens if the hydroelectric project is dropped from the mul-
ti -purpose faci 1 ity? Without the hydroel ectri c project, the hatchery
and water supply systems will need a different design but each will be
less expensive to build. In addition, the hatchery will need to amend
its PNP permit from Fish and Game.
In the original hatchery/water supply/ hydropower proposal, the hatchery
was expected to share the cost of the dam. The Reconnaissance Report
allocated the hatchery its construction cost plus 75% of the joint
costs, $12.9 million in 1984 dollars. Such a cost would be considerably
higher than the typical hatchery cost and beyond the current limits of
the Fisheries Development Revolving Loan Fund. If the hydroelectric
project is dropped and if a 15-foot, $412,000 dam wi 11 provi de the
2699/231/Fl -25 -
hatchery enough water, then the hatchery's construction cost would be
only $6.5 million --quite a difference. This lesser amount should be
much easier to finance. However, the change in plans will require an
amendment to the hatchery's existing PNP permit. A similar situation
exists for the proposed water supply system.
2699/231/Fl -26 -
CHAPTER IV. Public Review
On August 31, 1984, the Findings and Recommendations were distributed
(without this Chapter) to interested community members in Angoon and to
state agencies. On October 16, Power Authority representatives present-
ed these findings to Angoon's City Council. This chapter contains a
summary of the City Council meeting, two letters received as comments on
these Fi ndi ngs, and the Power Authority's response to one of the 1 et-
ters. In addition, Acres American, the consultant, who completed the
original report and found the project feasible was asked for their com-
ment. Their letter is also included.
A. Presentation to Angoon City Council, October 16, 1984.
The Council meeting began at 10:30 a.m. The Mayor and all six Council
members were in attendance. There were approximately ten spectators
including Pete Nease, Angoon Aquaculture Association; Helen Castillo,
Monument Manager, Admirality Island National Monument; K. J. Metcalf,
former Monument Manager, Admirality Island National Monument; and
Gordon Williams, Planning and Zoning Commission. The local power plant
operator for T-HREA, Rocky Hunter, is on the City Council.
Brent Petrie began the meeting by introducing himself and Bob Loeffler.
He gave a short introduction that included the project's history and
Power Authority involvement with previous studies in Angoon including
wind monitoring, installation of the working waste heat facility, Thayer
Creek, and tidal power. Bob Loeffler then explained the Power Authori-
ty's conclusions.
Using bar charts, graphs, and verbal explanation, Bob Loeffler explained
that the proposed hydropower project at Favori te Bay Creek was not
economically feasible; the electricity it produced would be much more
expensive than that produced by diesel. The expected cost/cost ratio is
0.5. He also explained that even if oil prices increase much faster
2699/231/ F1 -27 -
than predicted, if load growth increases much faster than predicted, or
if construction costs were much less than predicted, the project would
still not be feasible. Under these speculative assumptions, the highest
cost/cost ratio was 0.8. The presentation was followed by a long
question and answer period. After that, Bob Loeffler explained the cost
estimates whi ch supported the ana lysi s. Thi s expl anati on was agai n
followed by a long question and answer period.
Questions came from both the City Council and the audience. The major
speakers were the Mayor, Pete Nease, and City Councilman Frank Sharp.
The Mayor's questions included three major points. (1) While economic
analysis is all well and good, it isn't realistic to compare a snapshot
of today' s energy pri ces wi th those for hydropower because everybody
knows that the price of oil will go up. (2) Eventually we will totally
run out of oil; then what will the State do? And (3) the State (Depart-
ment of Transportation) tries to give the City of Angoon an $8,000,000
airport that nobody wants and has no benefits, and then the State (APA)
comes and says that an $8,000,000 dam is economically infeasible; the
dam will at least generate power. On the first two points, Bob Loeffler
pointed out that the analysis indeed expected that the price of oil
would go up. He explained current Power Authority parameters for oil
escalation, and the sensitivity analysis that included unusually rapid
oil escalation. On point #3, the Mayor didn't expect an answer and none
was given.
Pete Nease had a number of questi ons. He menti oned that the Power
Authority had not given h-im or the Council enough time to review find-
i ngs. (The draft fi ndi ngs were sent to Pete Nease and to the City
Counci 1 on August 31.) Brent offered and the Counci 1 accepted another
month for comments. Thus, Board of Directors consideration of the
Findings was delayed until the December Board meeting. The cut-off date
for comments was November 30. The second point was that our assumptions
were not reasonable--what were our assumptions? Third, the Power
Authority was given $400,000 by the legislature to study
2699/231/ F1 -28 -
various projects in Angoon. This current study took much less than a
half million dollars. What did the Power Authority do with the
remainder? They probably wasted it. Brent Petrie mentioned that the
current appropriation is for much less than $400,000, and that there is
probably some mistake in Mr. Nease's figures, but we would find out. He
did say that we have not spent $400,000 on this study. Mr. Nease noted
that our analysis had mistakes in the cost of the road and in the cost
of the hatchery; therefore, he figured we had probably made mistakes in
the cost of hydropower. It was poi nted out that the cost of the road
and the cost of the hatchery were taken mostly from his data. And,
because they didn't infllJence the price of electricity, the costs were
not reviewed by the Power Authority. The dam and hydroelectric costs
were reviewed by Power Authority cost estimators and are, infact,
probably a low estimate of hydroelectric construction costs.
Mr. Sharp also had comments. His major comment was that the Power
Authority representatives had probably done a reasonable job on the
analysis and, if they're bringing bad news, shooting the messenger is
probably not an appropriate response. He then made some comments about
the four-dam pool. There was some discussion of those electricity
prices.
There was also a discussion of need for a long-term plan for Angoon's
power and the power in Southeast. The Power Authority's part of the
meeting closed after an hour.
After the meeting, Bob and Brent spent approximately forty~five minutes
in personal discussion with Pete Nease. In that discussion, Pete Nease
emphasized that the Power Authority's conclusions were just that -
concl us ions of the Power Authority. He was angry that we had sent our
conclusions to other people. He demanded that we send him a list of
whom we had sent letters to so that he cOlJld send a rebuttal. We agreed
to send him our distribution list.
2699/231/Fl -29 -
B. Written Comments.
This section contains written comments on the Draft Findings and Rec-
ommendations. The contents of this section are listed below.
1. Letter from Mr. Pete Nease, Tribal Planner, Angoon Aquaculture
Association.
2. Power Authority response to Mr. Nease's letter.
3. Letter from Ms. Helen Castillo, Monument Manager, Admirality
Island National Monument.
4. Letter from Jim Landman, Project Engineer, Acres American
Incorporated.
2699/231/Fl -30 -
ANGOON COMMUNITY ASSOCIATION
P.O. Box 138
Angoon, Alaska 99820
(907)-788-3411
Larry Crawford
Executive Director
Alaska Power Authority
334 West 5th Avenue
Anchorage, Alaska 99501
Dear Mr. Crawford:
October 19, 1984
Alaska Power Authority recently addressed Angoon City
Council. A.P.A. started the meeting off by changing Angoon's
Hydro-electric project from the "things to do" list to the
"removal"·list. It was pointed out that they promised to
start the core drilling for the hydro project two years ago,
as soon as they made one more study -this one was for study-
ing the long. list of previous studies. The saying that you
can study something to death is certainly true in this case.
No doubt one more study will be needed to get the project
moving again.
The State Legislature appropriated $500,000 .. 00 about six
years ago for Angoon Hydro Development, but A.P.A. represen-
tatives said they did not know what it was used for. The
search for the missing half a million was promised by the
staff of Angoon's legislative representatives.
Alaska Power Authority said they used a system of feasi-
bility analysis, that was introduced to them by the firm,
"Acres America". It was called the "Monte Carlo" analysis
and demonstrated that Angoon hydro project was feasible. The
system was apparently used by APA for their report, but this
time the dice came up "crap". No doubt, two out of three
will be required; however, an independent source should be
used. Bob Loffler, APA project leader, has said that his
environmental group was not against the project.
Your letter of October 11, 1984, states that Angoon's
study is complete, but the study is a draft. Also, there
are mistakes in the report. We also request that you remove
all reference to our hatcher~waterline and access road, as
your report condemns them by association. Your letter and
report also makefan absolute decision in regard to Angoon's
ability to fund this project, this is inappropriate, since
APA has repeatedly changed their feasibility requirements,
and do not have authority over Congress, or the State Legis-
lature, or other funding sources. Absolute condemnation is
extreme.
Your statement is inappropriate and damaging. Therefore,
your decision should be qualified within the context of the
criteria used. In addition, your decision is premature and
corrections should be made to list the entities that maintain
that this project is feasible. Also, an explanation of why
your previous decision of feasibility was changed, and why
the p~ocrastination of the co~e drilling, would be appreciated.
Angoon cannot survive without stabilized electric cost.
We have 80% unemployment, without the present subsidy, the
lights will go off. We cannot support a fish processing in-
dustry wihtout hydro power. The money spent on welfare and
expendable subsidies would pay for this hydro project quickly.
Page Three -APA
Exploitation of the Angoon people by T&HREA, to provide
them with perpetual income, is barbaric. Their incumbrances
and costs are growing every year. The people are held in
indentured servitude to never ending debt payments. It is not
the intent of Congress to create entities that will indebt the
people with impossible payments, or to incumber the people in
perpetual pseudo tax payments.
Hydro-electric power for Angoon must be based on Angoon's
needs and benefit; Angoon cannot support all of the Southeast
villages or support federally mis-managed monopolies gone wrong.
The Supreme Court prohibited the State of Maryland from certain
authority, stating the reason as, ".the power to tax is the
power to destroy". The government should not be permitted to
create government corps. or government funded and regulated
monopolies with the power to tax.
APA's report, if correct, states that T&HREA's costs in
Angoon for 1982 were: -fuel -$780,475; general expenses -
$276,615; and miscellaneous -S57,247 ---Totaling Sl,l14,337,
but also states that this represents almost 50% of T&HREA's
costs in Angoon. Obviously, if these payments were used to
pay for hydro-electric power, it would be paid off in less than
ten years.
Sincerely,
Peter H. Nease
Tribal Planner
cc: Peter Goll; State Representative
Dick Eliason; State Senator
Ziontz, Pirtle, Morisset, Ernstoff & Chestnut
Frank Nyman; Tryke, Nyman & Hayes
Senator Murkowski
Senator Stevens
Representative Young
Dave Nease
Angoon City Council
Angoon I.R.A. Council
file
~L: ~,~ .
.. '
ALASKA POWER AUTHORITY
334 WEST 5th AVENUE· ANCHORAGE, ALASKA 80801
November 26, 1984
Mr. Peter H. Nease, Tribal Planner
Angoon Community Association
P.O. Box 138
Angoon, Alaska 99820
Dear Mr. Nease:
Thank you for your letter of October 19. In that letter you asked a
number of questions. The first asked us to find what legislative
appropriations were made to the Power Authority for Angoon and what has
been spent.
There have been two appropriations. The first appropriation occurred in
1979. "rhat year, the Legislature appropriated funds for detailed
reconnaissance studies of six creeks in Southeast. $220,000 of those
dollars were earmarked for a study of Thayer Creek near Angoon. Because
the entire amount of funds were not necessary for the Thayer Creek
study, the Legislature, through its Budget and Audit CODlllittee, approved
a transfer of $120,000 to the Black Bear Lake account. The second .
appropriation occurred in 1981: $250,000 for a study of Angoon Tidal
Power. In total, after the transfer, there were $350,000 available for
the study of p'ower alternatives for Angoon. Ther~ have been six
separate studies contracted for Angoon. The appropriation spending
history is summarized in the attached table. Of the $350,000 '
appropriation, $109,500 has been.spent on various_ studies, roughly·
$210,000 is still in the accounts and the remainder was spent on project
administration, etc. The $210,000 is, by law, dedicated to planning and
feasibility studies that are finished --the vast majority to tidal
power. Unless the -legislature reassigns them, the funds must be
returned to the general fund.
There have been-other expenditures for energy in Angoon as well.
Approximately $26,000 have been spent for feasibility and design of a
waste heat facility and" $191,000 was spent to construct it. Thus, the
total funds expended for solving Angoon's energy problems have been
approximately $326,500 not including Power Cost Assistance and Power
Cost Equalization subsidies provided to the local utility.
Your letter questions why so many studies were necessary for the
Favorite Bay site, and why our draft findings disagree with previous
studies. The first engineering consideration of the Favorite Bay hydro
site was the Angoon Water Supply Alternatives Study funded by the Power
Authority. This general study recommended a multi-purpose project on
Favorite Bay Creek, but it did not include a comparison of the cost of
diesel electricity versus that of hydro generated electricity. It was
7272/317
Mr. Peter H. Nease
November 26, 1984
Page 2
felt that an economic comparison of the two systems, diesel· versus
hYdro, was necessary before beginning an expensive feasibility study or
an environmental impact statement. Without the economic comparison, it
is not clear that the expensive feasibility investigations would be a
worthwhile expenditure. The present study, A-Comparative Economic
Analysis of Electric Energy Alternatives for Angoon, is the first
detailed study of the benefits and costs of hydroelectricity at that
site. As your letter states, the consultant's analysis found the
hydroproject marginally feasible. However, that analysis was based on
assumptions that we believe are incorrect.
The consultant assumed that the entire dam was necessary for the
hatchery; that is, if the hydroproject was not built, the hatchery would
still require the full 95-foot dam. He also assumed that 75% of the
construction costs would be paid by the hatche~. We do not believe
these assumptions are correct. An explanation is given on page 5 and
pages 15 -16 of the draft Findings and Recommendations. To summarize,
however, the hatchery needs only a small impoundment to protect its
water source. The bulk of the large dam and the bulk of the costs are
directly attributable to the hydro. When we brought this information to
the Contractor, Acres American, their response was that they had not
investigated the hatche~'s requirements and that if the full 95-foot
dam was not needed without the hydropower, then our conclusions· are
correct. The present study (the consultants report and the Power
Authority's findings) is the first detailed consideration of the
Favorite Bay site; the conclusions are that a hydroelectric facility
would produce more expensive power than diesel. In addition, our
analysis shows that extensive changes in oil prices, construction costs,
or load growth would not alter the conclusions.
Your letter also asks why core drilling did not precede the economic
investigation. Core drilling is appropriately classified as feasibility
level investigations and the current procedures of the Power Authority
Board requires their review and approval of the reconnaissance study
before feasibility investigations begin. This may be different than the
policies of previous Power Authority Boards, but it is a reasonable
decision making approach.
The Power Authority remains committed to lowering energy costs through-
out Alaska. Your letter laments the high cost of electricity in Angoon,
so do we. Unfortunately, our analysis shows that the Favorite Bay
Hydroproject would raise Angoon's cost of electricity. The full cost of
electricity in the project's first year of operation would be approx-
imately $1.15 per KWH. Even if the State paid the vast proportion of
the bill, diesel would be less expensive. Unfortunately, hydro is not.
"free" energy; it is expensive to develop. The funds spent on the
Favorite Bay project would produce much cheaper electricity if spent on
a diesel system instead.
In the last few years, the Power Authority has studied two hydro sites,
tidal power, and installed a waste heat system for Angoon.
7272 317
Mr. Peter H. Nease
November 26, 1984
Page 3
Unfortunately, the update of these studies show that there is no
near-term solution to Angoon's energy problems other than an efficiently
run diesel system w;th a working waste heat project. It is unfortunate
that there is no project that could lower the electricity price to
Angoon. but our studies show that to be the case •
. I hope this information ;s useful. and if you have any further comments,
please do not hesitate tn write.
Sincerely,
d~~
Larry D. Crawford ~
Executive Director '
BL/LDC/ald
7272/317
Mr. Peter H. Nease
November 26, 1984
Page 4
-Appropriation and Spending History
Appropriation: 1979 $100,000 (after transfer)
1981 $250,000
Total $350,000
Expendi tures:
Thayer Creek Reconnaissanse (Harza)3
Angoon Tidal Power (IECO)
Angoon Water Supply Alternatives (IN&~~3
Aerial Surveying -Favorite Bay (TN&H
Economic Analysis of Energy ~lternatives (Acres)3
Streamflow Monitoring (TN&H)
Total
Funds remaining in Angoon Accounts:
Notes:
$22,000 1
$35·,000
$15,000
$10,000
$10,000 2 $17,500
$109,500
$210,000 (approx.)
1. $22,000 is approximate. The contract for the Thayer Creek study
cost $87,000, but included other creeks. .
2. The streamflow contract will not be complete until February 1985.
The contract amount listed is an estimate of total costs.
3. Contrac~ors: Harza --Harza Engineering Company
7272/317
IECO --International Engineering Company
TN&H --Tryck, Nyman & Hayes
Acres --Acres Allleri can
.,
Uni ted States
Department of·
Agriculture
Bob Loeffler
Forest
Service
Project Manager
Alaska Power Authority
334 West 5th Avenue
Anchorage, AK 99501
Dear Mr. Loeffler:
Region 10 Tongass National Forest
Admiralty Monument
P .0. Box 2097
Juneau. Alaska 99803
Reply To: 1920
Date: October 1, 1984
RECEIVED
OCT 04 1984
AwKA POWER AUTHORIlY.
Thank YOt1 for the opportunity to review t,tle rough draft of the Alaska Power
Authority's Findings and Recommendations for the proposed hydroelectric project
near Angoon. .
We have no specific comments to offer on the draft. We do ask to receive a copy
of the final report and to be notified of your meeting with concerned citizens
in Angoon.
Sincerely,
~ Cv::lu_Lo
HELEN CASTn.LO
Monument Manager It/
cc: M. Fred, Sr.
100184 1215 ANM 1920 HC
Alaska Power Authority
334 West 5th Avenue
Anchorage, Alaska 99501
Attention: Mr. Bob Loeffler
Project Manager
November 28, 1984
P6409.01.11
T368
RECEIVED
NOV 29 1984
ALASKA eowea AIJ1HORJll
Subject: Alaska Rural Village Energy Reconnaissance
Studies --Angoon
Dear Mr. Loeffler:
This is written as a follow-up to our recent telephone conversation regard-
ing APA's economic analysis of a hydroelectric plant in Angoon.
Based on information in the hatchery license application, our analysis pre-
sumed the "high" dam (approximately 100 feet) would be required for hatch-
ery operation regardless of the existence of a hydro plant. The costs
attributed to hydroelectric production were thus assumed to be only those
necessary to build and operate th~ power-producing facilities.
If, as you contend, the hatchery requires only a small impoundment and dam,
the costs of increasing the dam size to that needed for power production
should be assessed against the hydro project. We therefore concur with the
approach in your economic analysis.
If you have any questions in this matter, feel free to call.
ACRES AMERICAN INCORPORAorED
Consulting Engineers
Suite 305
, 577 C Street
Anchorage, Alaska 99501
Telephone: (907) 279-9631 Telex: 025450 (ACRES AHG)
Appendix A. Construction Cost Estimates
The construction cost estimates are taken from a 1981 report by Tryck,
Nyman, and Hayes, Angoon Water Supply Alternatives, pages 65-67. The
estimates were made in 1981 dollars; they were updated to 1983 dollars
for the Reconnaissance Report and to 1984 dollars for this report. From
the original 1981 estimates, an 8% inflation rate was used to yield 1982
dollars; 4.3% brings the estimate to 1983 dollars; and 5% to 1984 dol-
lars.
The estimates are taken unchanged from the water supply report with one
exception. The Reconnaissance Report's review of the 1981 cost estimate
found that the 1981 estimate for fill to be in error. The 1981 report
estimated $23/cu.yd. for fill. In 1983, the authors expected $37/cu.
yd. (for more detail, see the Reconnaissance Report, pages 25-26). In
the terms of the original estimate, $37/cu. yd. in 1983 dollars is
equivalent to $32.85 in 1981.
2699/231/ F1 -40 -
1. Cost Estimate -Dam and Intake Structure
Mobilization
Reservoir Clearing and Sale of Timber
Diversion & Care of Water
Dam Structure
94 1 high w/crest 300ft. long,
110,000 cu. yd. @ $23.00 =
Intake Structure
Penstock -40" 1,200 ft. @ $187.50 ft. =
Subtotal direct cost:
Contingencies 15%:
Total Direct Cost:
Engr. & Admin. -19%:
Total Construction Cost:
Adjustment for backfill price:
Total (approximately):
2699/231/Fl -41 -
$375,000
-0-
320,000
2,530,000
300,000
225,000
$3,750,000
562,500
$4,312,500
776,250
$5,088,750
$1,818,984
$6,908,000
$7,460,000
$7,782,000
$8,170,000
(1981 $)
(1981 $)
(1981 $)
(1982 $)
(1983 $)
(1984 $)
2. Cost Estimate -Power Generating System
Mobilization
Powerhouse Structure
Mechanical & Electr. Equipment
Discharge Channel -100' long
Transmission Line
Subtotal -Direct Cost:
Contingencies -10%
Total Direct Cost:
Engr. & Admin. 18%:
Total Construction Cost:
2699/231/Fl -42 -
$ 125,000
460,000
860,000
20,000
680,000
$2,145,000
214,500
$2,359,500
424,710
$2,784,210
$3,006,947
$3,136,246
$3,293,058
(1981 $)
(1982 $)
(1983 $)
(1984 $)
3. Cost Estimate -Water Supply System
Mobilization
Clearing & Grubbing
Trench Excavation & Backfill
(4 1 depth)
Furnish & Install 10" DIP
Furnish & Install 8" DIP
Furnish & Install 6" DIP
Bedding
Rock Excavation
Valves and Valve Boxes
Air Relief Valves
Compaction
Pump Station
SUr1MARY: Water Supply
Pipelines:
Treatment Plant:
Reservoir (225,000 gal.)
2699/231/F1
Lump Sum $ 50,000
7.2 acres @ $16,000 115,200
36,000 1. f. @ $ 9.00 324,000
21,650 1. f. @ $ 26.00 562,900
12,600 l.f. @ $ 23.00 289,800
2,550 1. f. @ $ 15.00 38,250
36,800 1. f. @ $ 2.00 73,600
1,960 cu. yd. @ $ 50.00 98,000
15 @ $1,100/ea. 16,500
3 @ $2,500/ea. 7,500
12,000 cu. ft. @ $ 2.00 25,200
Lump Sum 100,000
Direct Construction Cost: $1,700,950
Contingencies, 15%: 255,142
Sub-total: $1,956,092
Engineering & Admin., 19%: $352,096
TOTAL: $2,308,188
$2,308,188
150,000
170,000
$2,628,188 (1981 $)
$2,838,433 (1982 $)
$2,960,496 (1983 $)
$3,108,520 (1984 $)
-43 -
4. Cost Estimate -Access Road
Mobilization Lump Sum
Clearing & Grubbing 12.68 acres
"Typa r" Fil ter Fabri c 52,800 sq. yd.
Crushed Rock 34,609 cu. yd.
Leveling Course 6,120 cu. yd.
Subtotal: Direct Cost:
Engineering & Administration -10%
Total Construction Cost:
2699/231/ F1 -44 -
x $16,000
x $ 1.38
x $ 18.00
x $ 23.00
$ 150,000
202,880
72,864
622,962
140,760
$1,189,466
$ 118,947
$1,308,413
$1,413,086
$1,473,849
$1,547,541
(1981 $)
(1982 $)
(1983 $)
(1984 $)
Appendix B. Rough Estimate --Hatchery-Sized Dam
The estimate below is EXTREMELY rough. It is a ballpark, or-
der-of-magnitude estimate only. Because the amount of this estimate is
only 2% of the total project cost, and only 3% of the hydroelectric
life-cycle cost, an error of a few hundred thousand dollars either way
will have little effect on the economic conclusions of this report.
Fill: 3,000 cy. @ $39./cu. yd. = approximately $120,000
Other expenses (Mobilization, penstock, etc).= $160,000
$280,000
Contingency @ 30%: 82,000
Engineering & Admin. @ 18%: 50,000
Tota 1 : $412,000
2699/231/Fl -45 -
Appendix C. Operation and Maintenance Estimates
These estimates are taken from the 1981 report, Angoon Water Supply
Alternatives, page 67.
Maintenance Crew:
Wages incl. insurance, lab. tax & admin:
1 working foreman
1 1 aborer
Vehicle -$0.75ton
Tools
Total Distributable Cost:
a) Dam and Intake Structure:
Maintenance Crew -40% of $92,800
Subcontract work (larger maintenance work)
Professional inspection -$10,000/5 yr.
Utilities $50/mo.
Maint. Material (parts, paint, cement, etc.)
Total:
b) Power Generating and Transmitting System:
Maintenance Crew 50% of $92,800
Subcontracted work (larger maintenance)
Professional Inspection -$5,000 every 5 yr.
Utilities $50/mo.
Maint. Material & Misc. Parts $300/mo.
Major Repairs (turbine cavities 2 X $16,000/20 yr.
Total: .
c) Water Supply System:
Maintenance Crew -10% of $92,800
Subcontracted work
Utilities $50/mo.
Chlorine $1/1 lb.
Pump Station Power -50 KWH/day @ $0.20
Extra Pump Station Maintenance
Total:
d) Access Road:
$ Year
$50,000
35,000
6,600
1,200
$92,800
$37,000
3,000
2,000
600
2,400
$46,500
3,000
1,000
600
3,600
1,600
$9,300
1,500
600
1,500
3,650
2,000
It is assumed that the maintenance of the road will
be taken over by the Hi ghway or Vi 11 age Authority,
thus only minimum maintenance cost will be carried by
the project itself ($100/mo.):
2699/231/Fl -46 -
$45,000
$56,300
$18,550
$ 1,200
$121,050
Hydropower 0 & M =
2699/231/Fl
$ 45,000
$ 56,300
$ 1,200
$102,500 (1981 $)
$110,700 (1982 $)
$115,460 (1983 $)
$121,233 (1984 $)
The 50-year present value (at 3.5% discount rate) of
the $121,233 annual expense is $2.84 million).
-47 -
Appendix D. Economic Calculations· -Benefit/Cost Analysis
The life-cycle costs of the hydroelectric project include construction
costs (from Appendix A and B), Operation and Maintenance (from Appendix
C), and lost waste-heat (from Reconnaissance Report, p.21). The bene-
fits are T-HREA's diesel costs displaced, and these costs are shown
below. The load forecast and the 1983 displaced cost figures are taken
from the Reconnaissance Report. The cost figures are updated to 1984
dollars and the fuel costs are escallated through the year 2004 consis-
tent with Power Authority eva 1 ua t ion pa rameters. The net present va 1 ue
totals are discounted to January 1, 1988 -the possible on-line date of
the project.
2699/231/Fl -48 -
YEAR
1983
1984
198~
1986
1987
1988
1989
1990
1991
1992
1993
1994
199 ~
1996
1997
1998
1999
2000
2001
2002
2003
2004
200~
2006
2007
2008
2009
2010
2011
2012
2013
2014
201~
2016
20~7
2018
2019
2020
2021
20-22
2023
2024
202~
2026
2027
2028
2029
2030
2031
2032
2033
2034
20B
2036
2037
TABLE D-1
T-HREA Costs Displaced by Hydropower
···OISPLACEA8LE COSTS---
FUEL COST
(S/KWH)
o. 1 2 ~
0.1 2 ~
0.1 2 ~
O. 1 2 ~
O.IB
O. 1 2 ~
0.12?
0.133
O. 137
O. 141
O. 1 4 ~
0.149
0.1~4
O. 1 ~8
0.163
0.168
0.173
0.178
0.184
0.189
O. 19 ~
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
(L 201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
0.201
OTHER
(S/KWH)
O.O~~
O.O~~
O.O~~
O.O~~
O.O~~
O.OB
0.055
O.O~~
0.05~
0.0~5
C.05~
0.0~5
O.O~~
O.O~~
O.O~~
O.O~~
0.0~5
O.O~~
O.O~~
O.O~~
O.O~~
O.O~~
O.O~~
O.O~~
O.O~~
0.0~5
O.O~~
0.055
0.0~5
0.055
O.O~~
0.0~5
0.055
0.0~5
O.O~~
0.0~5
O.O~~
0.O~5
O.O~~
0.05~
0.055
O.OB
0.0~5
0.055
O.O~~
0.0~5
0.05~
0.055
0.05~
O.O~~
O.O~~
0.055
O.O~~
O.O~~
O.O~~
MODERATE FORECAST
LOAD DISPLACEABLE
FORECAST
(MWH)
1020
1028
1202
i 2 1 1
1220
13~0
13~4
13~8
1361
1364
1368
1372
137~
1378
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
t382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
-49 -
COSTS
(SI,OOO)
NPV-
243
249
25~
261
267
273
280
287
294
301
308
315
322
330
337
345
353
3B
3B
B3
353
B3
3~3
3B
353
3B
353
353
353
353
3B
3B
353
3~3
353
353
3~3
3~3
'B3
353
353
353
353
353
353
B3
353
353
353
B3
71 19
HIGH FORECAST
LOAD DISPLACEA8LE
FORECAST COSTS
(MWH) (SI,OOO)
1020
IH7
1587
1596
1605
173~
1739
1743
1746
1749
1753
1757
1746
1763
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
312
320
327
33~
342
3~0
359
364
376
)8~
394
1003
td 2
!: 2 2
1031
"41
"'~2
452
'<52
1,52
t:52
1:52
t, 5 2
t,~2
452
1052
452
4~2
4~2
452
452
4~2
452
4~2
4~2
452
452
452
4~2
452
452
452
.4~2
452
452
452
452
452
4~2
4~2
NPV-
9107
Appendix E. Economic Calculations Cost-of-Power Analysis
The two tables of this appendix calculate the expected cost of electric-
ity (exclusive of any subsidies) for diesel-and hydro-electricity. The
load forecast and base (1983) cost figures are taken from the Reconnais-
sance Report. All figures are in nominal dollars. Cost escalation from
1983 to 1984 assumes 5% inflation; from 1984 through 2004, 6.5%
inflation; and 0% after 2004. Fuel costs receive an additional
escallation of 0% through 1988, 3% through 2004, and 0% thereafter.
2699/231/Fl -50 -
YEAR
1984
198~
1986
1987
1988
1989
1990
1991
1992
1993
1994
199~
1996
1997
1998
1999
2000
2001
2002
200]
2004
200~
2006
2007
2008
2009
2010
20 II
2012
2013
2014
2016
2017
2018
20.19
2020
2021
2022
2023
2024
202~
2026
2027
2028
2029
2030
2031
2032
2033
2034
203~
2036
~3 7
IMOLt. t.-!. rUrl::!~d::'L. IIJUIUfJUWl::!1 t.11::!~L.1 1~1L.'y rr II.I::!;:'
OPERATION
CONSTRUCTION AND
COST
(SI,OOO)
11100
MAINTENANCE
( S I .000)
121.23
129. II
137. ~O
146.44
IB.96
166.10
176.89
188.39
200.64
213.68
227. ~7
242. ]6
B8.11
274.89
292.76
311.78
332.0~
332.0~
332.0~
332.0~
332.0~
332.0~
332.0~
332.0~
332. O~
332.0~
332. O~
332.0~
332.0~
332.0~
332.0~
332.0~
332.0~
332.0~
332.0~
332. O~
332. O~
332. O~
332. O~
332.0~
332.0~
332. O~
332.0~
332. O~
332.0~
332.0~
J32.0~
332.0~
~ .O~'
IF'INANCl!
COST
( S I ,000)
I, I ~ I
I , I ~ I
I, I ~ I
I , I ~ I
I, I ~ I
I , I ~ I
I, I ~ I
I , I ~ I
I, I ~ I
I , I ~ I
I , I ~ I
I , I ~ I
I , I ~ I
I , I ~ I
I , I ~ I
I , I ~ 1
I • I ~ I
I , I ~ I
I , I ~ I
1 , I ~ I
I , I ~ I
I , 1 ~ I
I , I ~ I
I , I ~ 1
I , I ~ I
I , 1 ~ 1
I , I ~ I
I , I ~ 1
I , I ~ I
I , I ~ I
1 , 1 ~ I •
I , I ~ I
I , I ~ I
I , I ~ I
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
T-HREI.
If I X lUI
COST
(SI,OOO)
21 ~
229
244
260
277
29~
314
334
3H
379
404
430
4~8
488
~20
~~4
~90
628
669
712
H8
7~8
7~8
7~8
7~8
7~8
H8
H8
H8
7~8
H8
7~8
7~8
7~8
7~8
7~8
7~8
7~8
7~8
7~8
7~8
7~8
7~8
7~8
7~8
7~8
7~8
7~8
H8
7~8
7~8
7~8
7
YEARLY
b11ll1l)!xO
COST
(11,000)
I ,~49
I , ~ 7 ~
1,603
1,632
1,663
I ,6<96
1,732
1,770
1,810
I, 8 ~J
1,898
1,947
1,999
2,O~4
2,112
2,17~
2,242
2,241
2,241
2,241
2,241
2,241
2,241
2,241
2,241
2,241
2,241
2,241
2,241
2,241
2,241
2,241
2,241
2,241
1,090
1,090
1,090
1,090
1,090
1,090
1,090
1,090
1,090
1,090
1,090
1,090
1,090
1,090
'090
MODERATE
GROWTH
FORECAST
(MWH)
1028
1202
1211
1220
13~0
13~4
13H
1361
1364
1368
1372
1375
1378
1382
1382
1]82
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
i3&2
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
HIGH
GROWTH
FORECAST
(MWH)
IH7
1~87
1~96
160~
173~
1739
1743
1746
1749
1753
17~7
1762
1763
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
iiv;
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
IH
***ELECTRICITY PRICES*··
MODERATE HIGH
GROWTH
("KWH)
I. 147
1.163
1.180
1.199
I. 219
1.240
1.262
1.287
I. 3 13
1.341
1.374
1.409
1.446
1.486
I . ~ 29
I.H4
1.622
I. 622
I. 622
1.622
1.622
1.622
1.622
1.622
1.622
1.622
1.622
i . V ££
1.622
I. 622
1.622
1.622
I. 622
1.622
1.622
0.789
0.789
0.789
0.789
0.789
0.789
0.789
0.789
0.789
0.789
0.789
0.789
0.789
0.789
89
GROWTH
($IKWH)
0.893
0.906
0.919
0.93~
0.9~1
0.968
0.986
1.004
1.027
1.049
1.074
I. 102
I. 13 I
I. 162
1.196
I .23 I
1.269
1.268
1.268
1.268
1.268
I. 268
1.268
I. 268
1.268
1.268
1.268
i .26&
1.268
1.268
I. 268
1.268
1.268
1.268
1.268
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
O.
TABLE E-2. Forecast Diesel Electricity Prices
••• 0 1 SPLACEABLE COSTS." T-HREA •••••••• MOOERATE FORECAST •••••••• ••••••••• HIGH FORECAST •••••••••
FUEL COST OTHER FIXED LOAD TOTAL ELECTRICITY LOAO TOTAL ELECTRICITY
COST FORECAST COSTS PRICE FORECAST COSTS PRICE
YEAR CS/KWH) CS/KWH) ('51.000) CMWH) (SI.000) (S/KWH) (MWH) ('51.000 ) ('5'KWH)
1963 0.1 19 0.051 20:-1020 378 0.371 1020 378 0.371
1984 Q :7.5 iJ .055 21S :n8 400 0.389 1577 499 0.31b
1985 0.1.33 0 .059 279 1202 4bO 0.38;' 1587 533 0.33b
:98b 0.142 O. Ol,2 244 1211 491 0.40b :59b S70 0.357
1987 n.151 0 .Obb 7.l.C :7.20 57.5 0 .431 lb05 b09 0.379
1988 O. 1101 0.071 277 , ~,5D 590 0 .437 1735 1.79 0.391
1989 o.ln 0 07:' 295 1354 1,3b 0 47(2 1739 733 0.421
,990 :J :94 . 080 314 !35B 68b J .505 : 743 791 a.454
199; 0.11:<' 0.08S 334 I3bl 740 0 .544 1741. 854 0.489
:992 a.233 ,., 09! :~~",b : 3(,1. 798 a. 585 1749 923 0 .528 ~
199:1 0 25:, O. 097 ]79 13l.8 B/~: 0 .63C 1753 997 a .51.9
:994 !l 280 -. UJ3 404 :172 930 0 b78 :757 1078 '1 613
199:: 0.307 u 11 C 1.3C ',175 1.004 0 . nc, 1741, 11 S9 a . I:.{'~
:996 'J ~ :~37 ] t t 7 4~Je : .!78 : .084 ., 787 :7(,3 :259 o. 714
1997 0.370 0 I:<'S 4f1e 1382 1.172 U 8H! 1767 131.7 0 .77:
,998 a.40b J.133 ':020 :382 1 • "b4 J. 915 :767 1471 0.833
1999 0.445 O. 141 551. 1382 1.3b4 0 987 1767 1590 0.900
2000 J.48fl !~ 151 590 :382 l ,472 065 :767 1718 0.972
2001 0.535 0 . llo0 l.28 1382 1.590 150 1767 18se 1. OS:
2002 D.S67 J. 171 6b9 1382 1.717 1.242 :767 2009 1.137
2003 0.b44 O. 18~ 712 1382 1.854 1.342 17b7 2172 1.229
2004 0.707 0.194 758 :382 2.003 1.449 17b7 2350 1.330
2005 0.707 0.194 758 :382 2.003 1.449 17b7 2349 1.330
200l. 0.707 ::J.194 758 1382 2.003 1.449 17b7 2349 1.330
2007 0.707 0.194 758 1382 2.003 1.449 17b7 2349 1.330
2006 0.707 !).191. 758 :362 2.003 1.449 17b7 2349 1.330
2009 0.707 0.194 758 1382 2.003 1.449 17b7 2349 1.330
2010 0.707 0.194 758 :382 2.003 1.449 171:.7 2349 1.330
2011 0.707 0.194 758 1382 2.003 1.449 171:.7 2349 1.330
2012 a.707 0.194 758 1382 2.003 1.449 17b7 2349 1.330
2013 0.707 0.194 758 1382 2.003 1.449 17b7 2349 1.330
2014 0.707 O. : 94 7S6 1382 2.003 1.449 1 7b 7 2349 1.330
2015 C.707 0,194 758 1381 2.003 1.449 17b7 2349 1.330
201b 0.707 ::J.194 756 1382 2.003 1 .449 17b7 2349 1.330
2017 0.707 0.194 758 1382 2.003 1 .449 17b7 2349 1.330
2016 0.707 0. 194 758 1382 1.003 .449 171:.7 2349 1.330
2019 0.707 0 191. 758 1381 1.003 .449 171:.7 2349 1.330
2020 0.707 D. :94 758 :382 2.003 .449 17b7 2349 1.330
2021 0.707 0.194 758 1382 2.003 .449 17b7 2349 1.330
2022 0.707 0.194 758 1382 2.003 .41.9 171:.7 2349 1.330
2023 0.707 0.194 758 1382 2.003 .449 17b7 2349 1.330
2024 0.707 0.194 758 :382 2.003 .449 171:.7 2349 1.330
2025 0.707 0.194 758 1382 2.003 .449 171:.7 2349 1.330
202b 0.707 0.194 756 :382 2.003 .449 171:.7 2349 1.330
207.7 0.707 0.194 758 1382 2.003 1.449 171:.7 2349 1.330
2028 0.707 D.194 756 1382 2.003 .449 171:.7 2349 1.330
2029 0.707 0.194 756 1382 2.003 .449 171:.7 2349 1.330
2030 0.707 0.194 758 :382 2.003 .449 171.7 2349 1.330
2031 0.707 0.194 758 1382 2.003 449 1767 2349 1.330
2032 D.7!J7 0.: 94 758 1382 2.003 .449 1767 2349 1.330
2033 ~ 70i O. :9L 758 1382 2.0C3 .449 17b7 2349 : . 33~
203/. 0.707 J. : 94 7!;8 1382 2.003 1.449 1767 2349 1.330 nns 0.707 0.194 7S8 1382 2.003 I .449 17b7 2349 1.330
2036 0.70'7 " :9/. 758 :382 2.003 1 .449 :71:.7 2349 1.330
7.037 C.7U7 ~. 191. 758 1387. 7..00] 1 .449 17b7 211.9 1.338
-52 -
-------, .. _.-.. ---•..
Appendix F. Economic Calculations --Sensitivity Analysis
The Sensitivity analysis includes changes in load growth, construction
cost, and oil prices. The first two analyses can be calculated directly
from Table 9 (Benefit/Cost for Favorite Bay Hydro); only the oil price
change needs extensive recalculation. That recalculation is in the two
tables of this appendix. The tables are in 1984 dollars. In the first
table, there is a continuous 3% real increase in fuel prices from 1985
through 2004. In the second table real oi 1 pri ces do not change from
their present levels.
2699/231/Fl -53 -
TABLE F-l
Sensitivity Analysis -0% Increase in Fuel Prices
"""""""""0"""'0,,'0""""0""0' 07. INCREASE IN FUEL COST
YEAR
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2 a 1 I
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
···DISPLACEABLE COSTS··· MODERATE FORECAST
FUEL COST oTHER LOAD DISPLACEABLE
(S/KWH)
O. 125
O. 125
0.125
0.12 S
0.125
0.125
O. 125
0.125
O. 125
0.125
O. 125
O. 125
0.125
0.125
0.125
O. 125
0.125
O. 125
O. 125
O. 125
O. 125
O. 125
O. 125
O. 125
O. 125
0.125
O. 125
0.125
O. 125
0.125
O. 125
O. 125
O. 125
O. 125
o • 1 2 5
O. 125
O. 125
O. 125
0.125
O. 125
0.125
O. 125
0.125
O. 125
0.125
O. 125
0.125
O. 125
O. 125
O. 125
0.125
O. 125
O. 125
0.125
O. 125
(S/KWH)
0.055
0.055
0.055
a .OSS
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
O. 055
0.055
0.055
0.055
FORECAST
(MWH)
1020
1028
1202
1211
1220
1350
1354
1358
1361
1364
1368
1372
1375
1378
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1381
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
-54 -
COSTS
(SI,OOO)
243
244
244
245
246
246
247
248
248
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
249
NPV-
5810
"""""""""""","""0
HIGH FORECAST
LOAD DISPLACEABL
FORECAST
(HWH)
1020
1S77
IS87
1 S96
1605
1735
1739
1743
1746
1749
1753, "
1757
1746
1763
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
COSTS
(SI,OOO)
312
313
314
314
315
316
316
314
317
318
318
318
318
318
318
]18
318
318
318
318
318
]18
)18
]18
:n8
J18
318
318
318
318
318
318
318
318
318
318
318
318
318
318
318
318
318
318
318
318
318
318
318
318
NPV-
7433
TABLE F-2
Sensitivity Analysis -3%, Increase in Fuel Prices
.",g,g""""""""""",.",."g"", 3% INCREASE IN FUEL COST
YEAR
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
***DISPLACEABLE COSTS***
FUEL COST OTHER
(S/KWH)
0.12 S
O. 125
0.129
0.133
0.137
o • 14 1
O. 145
0.149
0.154
0.158
0.163
0.168
O. 173
0.178
0.184
0.189
0.195
0.201
0.207
0.213
0.219
O,,2~6
0.226
0.226
0.226
(J.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
0.226
(S/KWH)
0.OS5
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.05S
0.055
0.055
0.055
0.055
0.055
0.055
00055
0.OS5
0.055
C.055
0.C55
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.05S
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
0.055
C.OS5
0.055
0.055
0.055
0.055
MODERATE FORECAST
LOAD
FORECAST
(MWH)
1020
1028
1202
12 1 1
1220
1350
1354
1358
1361
1364
1368
1372
1375
1378
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
1382
-!55 -
DISPLACEA8LE
COSTS
(Sl,OOO)
NPV-
264
271
277
284
291
298
306
314
321
330
337
345
353
362
370
379
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
388
8202
"""""""""""""""""1
HIGH FORECAST
LOAD
FORECAST
(MWH)
1020
1577
1587
1596
1605
1735
1739
1743
1746
1749
1753
1757
1746
1763
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
'1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
1767
DISPLACEABLE
COSTS
(Sl,OOO)
340
348
356
364
373
382
392
398
4 1 1
1,22
1,31
I, to!
452
1062
1,73
484
~96
497
497
497
497
1,97
497
497
1,97
"97
1,97
to 9 7
1,97
497
497
497
497
497
497
497
497
497
497
497
497
497
497
497
497
497
497
497
497
497
NPV-
10492
Appendix G. Economic Analysis Parameters.
The economic analysis parameters used in this analysis are outlined in
Table G-l. The parameters are consisted with those approved by the
Alaska Power Authority Board of Directors for FY 1984 and used for all
Power Authority projects. Table G-2 summarizes the sensitivity analysis
parameters.
Table G-1
Economic Analysis Parameters
Economic Analysis
Inflation Rate -0.0%
Real Discount Rate -3.5%
Real Oil Escalation Rate:
0.0% through 1988
3.0% through 2004
0.0% thereafter
Cost of Power Analysis
Inflation Rate -6.5%
Cost of Debt -10.0%
Economic Life and Financing Terms
Diesel Generation
Economic Life (Units over 300 KW) -20 years
Hydroelectric Projects
Economic Life -50 years
Terms of Financing -35 years
2699/231/Fl -56 -
Table G-2
Sensitivity Analysis Parameters
Real Oil Escalation Rate
Low Assumption -0%
High Assumption:
3% through 2004
0% thereafter
Construction Cost
Low Assumption -25% decrease over estimated cost.
High Assumption -25% increase over estimated cost.
Load Growth
High assumption -25% increase over Moderate and High load
growth scenarios.
2699/231/Fl -57 -
FOOTNOTES
1. Reconnaissance Report: A Comparative Economic Analysis of Electric
Energy Alternatives for Angoon, Alaska. February 1984. Page 30.
2. Ibid. Page 16.
3. Kootznahoo Head Water Resources Study. Page 2.
4. Angoon Water Supply Alternatives. Page 12.
5. Letter to Carolyn Nease, Angoon Aquaculture Incorporated; August 5,
1982; from Don W. Collinsworth, Deputy Commissioner, Alaska Depart-
ment of Fi sh and Game. The Letter accompani es the Angoon I s PNP
permit.
6. Reconnaissance Report. Table 9, Page 21.
2699/231/Fl -58 -