HomeMy WebLinkAboutFinancial Analysis for Scammon Bay Hydroelectric Project 1984SCA
004
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Alaska Power Authority
LIBRARY COPY
Financial Analysis for
SCAMMON BAY
HYDROELE~TRIC PROJECT
Submitted by
DOWL ENGINEERS
ANCHORAGE, ALASKA
In Association with
TUDOR ENGINEERING COMPANY
SAN FRANCISCO, CALIFORNIA
DRYDEN & LARUE
ANCHORAGE, ALASKA
SEPTEMBER 1984
r
L-..-.-ALASiiA POWER AUTHORITY _ _____.
SCA
004
DATE ISSUED TO
·,
HIGHSMITH 42·225 PIINTEDINu.&A.
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TABLE OF CONTENTS
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ALASKA POWER AUTHORITY
SCAMMON BAY HYDROELECTRIC PROJECT
FINANCIAL ANALYSIS
TABLE OF CONTENTS
Section Page
SUMMARY. • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • ;
I. INTRODUCTION............................................. I-1
A. GENERAL............................................. I-1
B. DESCRIPTION AND BACKGROUND.......................... I-1
C. OVERVIEW............................................ I-2
D. REPORT FORMAT ••••••••••••••••••••••• -................ I-3
II. GENERAL CRITERIA......................................... II-1
A. GENERAL............................................. II-1
B. FINANCIAL CRITERIA.................................. II-1
C. ENERGY DEMAND AND SUPPLY............................ II-2
D. DIESEL COSTS........................................ II-4
E. HYDROELECTRIC COSTS................................. II-5
F. OPERATION AND MAINTENANCE COSTS..................... II-6
G. CANNERY............................................. I I-7
III. FINANCIAL ALTERNATIVES
A. GENERAL............................................. . I I I-1
B. BASE CASE. . • • . • • • • . • • • . • . • • • . • . • • • . • • . . • . . . . . • . • • • • . I I I -1
C. SUPPLEMENTAL DIESEL................................. III-2
0. CANNERY ••.•••••••••••••••••.••.•••••••• ~............ III-2
E. FINANCIAL PLANS..................................... III-3
1. ALTERNATIVE I-A: 100% REVENUE BONOS........... III-4
2. ALTERNATIVE I-B: 100% REVENUE BONDS WITH
GRADUATED PAYMENTS........................... III-5
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3. ALTERNATIVE II-A: 50% REVENUE BONDS/
50% STATE GRANT ....••••...•••......•....•..•. II I-5
4. ALTERNATIVE II-B: 40% REVENUE BONDS/
60% STATE GRANT ..........•................... II I-5
5. ALTERNATIVE II-C: 43.1% REVENUE BONDS/
56.9% STATE GRANT .••.•..•.••.•...•.•..•.•...• III-6
6. ALTERNATIVE I II-A: STATE LOAN .•....•.••.••••.• III-6
7. ALTERNATIVE II I -B: STATE LOAN WITH
DEFERRED PAYMENT •.......••....•.••..•...••.•• III-6
8. ALTERNATIVE IV: STATE EQUITY FINANCING ..••..•. I II-7
F. DISCUSSION OF ANALYSIS .•.••...••••••..•..•.•.••••••• II I-7
APPENDIX A: EBASCO COST ESTIMATE
APPENDIX B: APA ANALYSIS PARAMETERS
APPENDIX C: ECONOMIC ANALYSIS UPDATE
APPENDIX D: DIESEL ANALYSES
APPENDIX E: HYDROELECTRIC ANALYSES
APPENDIX F: CANNERY ANALYSES
APPENDIX G: FINANCIAL SUMMARIES WITHOUT REAL FUEL ESCALATION
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SU144ARY
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SUfittARY
This report presents the results of an analysis of various alternative
possible methods of financing the Scammon Bay Hydroelectric Project
(Project). A feasibility report for the project was prepared by the Alaska
District of the U.S. Army Corps of Engineers in March 1982. This report
showed the project to be economically feasible and a recent economic analysis,
updated using newer costs and energy consumption data, has indicated that the
project is still economically viable.
Various methods considered for financing the project include tax-exempt
revenue bonds, state grants, state loans at five percent interest, and a state
equity investment yielding a five percent annual return. The alternatives are
addressed in detail in Section III of this report. The average cost of energy
to consumers was calculated on an annual basis for each alternative.
The cost of power to the users will vary depending on the type of financ-
ing chosen, which could include various uses of state grants, loans, or equity
financing. The actual cost of power may be slightly greater or less than the
costs presented in this report. Variables that may influence the cost of
power include a conservative, and therefore potentially high, cost estimate;
potentially low initial energy sales; and potentially high load growth. The
APA estimate of the actual cost of power is slightly less than the cost of
power presented in this report.
No attempt will be made here to select the best method of financing the
Project, as this is a policy decision and as such is beyond the scope of this
report. The intent of this report is to present data and the resu 1 ts of the
various analyses so that the information is available for the policy and
decision making processes.
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PROJECT DESCRIPTION
The recommended hydroelectric project would have an installed capacity of
100 kW and would be located on a small unnamed creek immediately south of the
village of Scammon Bay. The project would be a run-of-the-river type consist-
ing of a low diversion weir, less than 10 feet high, which would divert the
stream into a 12-inch penstock. The length of the penstock would be about
3,500 feet. The powerhouse would be 488 feet lower than the diversion, and
would contain a single 100 kW turbine. The diverted flows would then be
returned to the creek. No significant environmental impact, including damage
to fisheries, is expected. The village of Scammon Bay currently relies
totally on diesel generation to meet electrical needs. This hydroelectric
project would be capable of supplying approximately 86 percent of the elec-
tri ca 1 needs of Scammon Bay in 1986 and 59 percent in 2005. The ba 1 ance of
the village electrical needs would be supplied by supplemental diesel genera-
tion. Surplus hydroelectric energy could be sold to some other purpose, such
as space heating.
STUDY METHODOLOGY
The general methodology of the study consisted of first establishing the
financial cost of the ''base-case 11 alternative for Scammon Bay and then com-
paring this cost to the cost of the hydroelectric project using eight speci-
fied financial alternatives. The purpose of this comparison of the base case
to the financial alternatives was to demonstrate how each of the financial
alternative plans studied compared with the actual avoided financial cost of
the base case.
STUDY ASSUMPTIONS
The planning period for the project begins with January 1986 and extends
20 years, including 1986 and 2005. The hydroelectric project was assumed to
be on-line by January 1986 and the overall analysis extends 50 years beyond
this time (1983-2035). The years 1983 through 1985 were included in the
analysis for information only. The analysis was conducted assuming a general
inflation rate of 6.5 percent for all costs for the 20-year planning period
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and a zero inflation rate thereafter. Since most economists predict a long-
term additional escalation in the cost of fuel above the general inflation
rate, the analysis was also conducted both with and without an additional fuel
escalation of 3.0 percent applied over the period 1989-2005.
The proposed hydroelectric project will sometimes produce more power than
Scammon Bay can use and the financial impact on the unit energy cost to Scam-
mon Bay of selling this excess energy to some other use, such as space
heating, at several alternative selling prices was also analyzed.
FINANCIAL ALTERNATIVES
As specified by the APA, four basic alternative methods of financing the
project were considered. These were ( 1) 10 percent tax-exempt revenue bonds
alone, (2) state grants in conjunction with 10 percent tax-exempt revenue
bonds, (3) direct state financing at 5 percent interest and (4) state equity
financing with a 5 percent annual return.
bonds and state loans would be 35 years.
The repayment peri ad of revenue
Two different repayment schedules
were considered for the tax-exempt revenue bonds alone, three different
combinations of the state grants in conjunction with the tax-exempt revenue
bonds were considered, and two different payback schemes for the direct state
financing were considered. This resulted in a total of eight different
alternative plans, each of which was analyzed both with three percent real
fuel escalation and without real fuel escalation. The results of the analysis
are shown in the summary Tables S-1 (with fuel escalation) and S-2 (without
fuel escalation). A summary description of the plans is presented below.
1. Alternative I-A. Tax-exempt Revenue Bonds with a levelized repay-
ment schedule.
2. A 1 ternat i ve 1-B. Tax-Exempt Revenue Bonds with a graduated repay-
ment schedule. This plan allows initial annual payments that result
in an overall average unit energy cost equal to the base case for
the first year of hydro generation and then calls for increases in
annual payments at a maximum rate of 9.5 percent until a levelized
payment can be made by fully amortizing the outstanding principal
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over the remainder of the 35-year financing period without exceeding
the maximum rate of increase.
3. Alternative II-A. 50 percent tax-exempt revenue bonds and 50 per-
cent state grant.
4. Alternative II-B. 40 percent tax-exempt revenue bonds and 60 per-
cent state grant.
5. Alternative II-C. 35 percent tax-exempt revenue bonds and 65 per-
cent state grant. For this plan the tax-exempt revenue bond portion
was established by solving for the amount of debt service that would
yield an average unit cost of energy equal to the base-case unit
cost of energy in 1986.
6. Alternative III-A. State loan for 35 years at five percent.
7. Alternative III-B. State loan at five percent with principal and
interest payments deferred for 10 years. Payments for the first
10 years would be O&M only, and the principal and deferred interest
of the loan would be fully amortized over the remaining 25 years of
the 35-year financing period.
8. Alternative IV. State equity financing with return to the state on
investment equal to five percent of capital cost. The operation and
maintenance expenses of the hydroelectric project would be paid from
the return to the state.
DISCUSSION OF RESULTS
Summary results of the financial analyses in terms of the unit cost of
energy in cents per kilowatt hour are presented in Table S-1 (three percent
real fuel escalation) and Table S-2 (no real fuel escalation). Comparison of
the two base-case costs indicate the marked effect of fuel escalation on the
cost of the avoided diesel system. Figure S-1 shows a general comparison of
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the cost of two hydro financial alternatives with the base case. More details
are presented in the body of the report.
The most realistic basis for evaluation of the various alternatives
studied to finance the Scammon Bay Hydroelectric Project is a comparison of
the energy costs of the base case with the total costs system including the
hydroelectric project, using the alternative financial plans studied. The use
of excess hydroelectric power for space heating was also considered. A range
of sales prices were considered to test the sensitivity to this sale.
For use in this comparative analysis, developing the cost of the base
case was given careful attention. Through cooperative efforts of local Alaska
consultants and APA personnel, representative existing diesel electricity
costs were estimated for the first year of analysis, 1986, and projected
through the 50 year life of the hydroe 1 ectri c project extending from 1986
through 2035. Growth and price escalation were limited to the 20 year period
of 1986 through 2005, after which both factors were assumed to be zero until
the end of the period of study in 2035.
If the summary Table S-1 of 24 possible combinations (i.e. eight basic
alternatives with three space alternatives for each} is condensed to some of
the most significant findings for several selected financial alternatives, the
following table can be derived. Also, Figure S-1 presents the same data
graphically for the base case, and hydro alternatives 1-A and III-A. As can
be noted, alternatives II-A and III-A are very similar and II-A was therefore
not included.
With 50% Avoided Cost SQace Heating Credit
II I-A: 100% State Equity
I-A: 100% Tax II-A: 50-50 State Loan with 5%
Base Case Exemp., Level Tax Ex./Grant @ 5% Int. , Level Return
Year (¢/kWh) (¢/kWh) (¢/kWh} (¢/kWh) (¢/kWh)
1986 37 60 42 42 37
1990 49 64 47 48 42
1995 66 70 54 54 49
2005 150 114 101 102 95
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made:
In analyzing these results, the following general observations can be
1. With 100 percent tax-exempt financing and level ized payments (I-A)
it would take about 12 years before local interests would be able to
take advantage of savings created by the hydro project.
2. The plan reflecting a 50/50 tax-exempt financing/state grant (II-A),
and the plan with a 100 percent state loan at 5 percent interest and
levelized payments (III-A) would both produce essentially the same
cost of power. These plans would result in savings in electricity
costs in the sixth year and increase significantly over 15 years
because of the inflation-proofing provided by hydro.
3. Other apparent observations from an analysis of the summary
Table S-1 indicate:
a. Financial alternatives II-A, II-8, II-C, III-A and IV have very
similar results.
b. The graduated payment approach applied to the 100 percent tax-
exempt financing (I-B) would provide only minor increases in
early years followed by substantial savings after 17 years.
c. There is very little difference between the 40/60 tax-
exempt/State grant financing (II-B), and the financial plan
that derives the 35/65 percent combination that will just equal
the base case diesel costs (II-C).
d. The five percent State equity plan (IV) increases the savings a
small percentage over the two plans discussed in c. above.
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e. The 10-year deferral on the State loan (III-B) produces savings
of 35 percent when compared to the base case in 1986, but
increases in the 11th year to about 300 percent of the starting
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TABL[ S-1
SCAI+tON BAY tiYDROHECTRIC PROJECT
SlM4ARY Of ALL FINANCIAL PLANs!!
(With Real Fuel Escalation)
Combinations ot Tax-Exempt
!OOJ Tax-Exempt Bonds~/ Bonds and State Grants State Loans 21
-A 1-8 I 1-A 11-B I 1-C I II-A I 11-8
Base Level Graduated 50/50~1 40/60~1 35/6sZ1 Level Deferred
CaseY 31 41 Payments~/ Payments~/ Hydro Payments-Payments-
Year Year ( f/KWh) iflKWh) (f/KWh) <fiKWh) <f/KWh} if/KWh) if/KWh) <f!KWh)
1986 37,26 61 ,47 37,26 42,86 39,13 37.26 43,43 24,24
5 1990 48,61 65,41 50.17 48.22 44,78 43,04 48,75 31,02
10 1995 66,42 70.84 69.19 55.26 52.15 50,57 55,74 39,68
20 2005 150,52 115,74 132.73 102,96 100,40 99,11 103,35 11 5.11
50 2035 149.69 89.35 89,35 89,35 89,35 89,35 89,3':> 89,35
1 See Table D-1, Cost ot continued existing diesel system, with real fuel escalation,
21 Costs of financial plans are the sum of supplemental diesel and hydroelectric costs,
3! See Table E-1,
4/ See Table E-2,
6/
71
8/
9/
See -able E-3,
See Table
See Table
See Table
See Table
See Table
E-4,
E-5.
E -6,
E -7,
E-8,
l 1/ See Table F-1,
Sf 1fB·.AD1 :4-S-1
Potential Pr1ce
. 10121 State Equ1ty--Reduction from Space Heatin~l..!/~1
IV 25J 50J lOOJ
Avoided Avoided Avoided
Cost Cost Cost
if/KWh) <f!KWh) if/KWh) (f/KWI1)
37,76 0,49 0,98 1 ,48
43,08 0,55 1,09 1,64
49,97 0,64 1,29 1 ,93
96,90 0,76 1 ,51 2,27
96,0., o. 76 1 ,51 2.27
TABLE S-2
SCAMMON BAY HYDROELECTRIC PROJECT
SUt+tARY OF All FINANCIAL PLANs.!/
(Without Real Fuel Escalation)
1001 Tax-Exempt Bonds~/
Combinations of Tax-Exempt
Bonds and State Grants ~/ State Loans 2/
1-A 1-B II-A 11-B 11-C ill-A 111-B
Base Level Graduated 50/50~1 40/60~1 35/6521 Level Deterred
CaseY 3/ 4/ 8/ 91 Hydro Payments-Payments-Payments-Payments-
Year Year (~/KWh) (~/KWh) (~/KWh) jj/KWh) (f/KWh) (~/KWh) (f/KWh) (f/KWh)
1986 37.26 61 .41 37.26 42.86 39. J 3 37.26 4 3.43 24.24
5 1990 47.25 64.78 49.54 47.59 44.15 42.41 48.12 30.39
0 1995 59.44 67.52 65.87 51 .94 48.83 47.26 52.42 36.37
20 2005 113.71 97.21 114.20 84.43 81 .87 80.58 84.82 96.58
50 2035 112.88 70.82 70.82 70.82 70.82 70.82 70.82 70.82
!1 See Table 0-2. Cost of continued existing diesel system, without real fuel escalation.
~I Costs of financial plans are the sum of supplemental diesel and hydroelectric costs.
3/ See Table G-1.
4/ See Table G-2.
5/ See Table G-3.
6/ See Table G-4.
See Table G-5.
8/ See Table G-6.
9/ See Table G-7.
10/ See Table G-8.
1/ See Table F-2.
SF: IEB:A01: 4-S-2
Potential Price
' 10/2/ State Egu1ty---Reduction from Space Heat i n:1l!J~/
IV 25% 50% 100%
Avoided Avoided Avoided
Cost Cost-Cost
(f/KWh) (f/KWh) (f/KWh) Ji!KWh)
37.76 .49 .98 1.48
42.45 .52 1.03 1. 55
46.65 .53 1.06 1.59
78.37 .47 .94 1.42
77.54 .47 .94 1.42
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YEAR
1. Costs include general inflation and real fuel escalation.
2. Hydro alternatives include cost of supplemental diesel.
3. Hydro alternatives include adjustment for energy sold to cannery.
4. Hydro Alternative I-A is 100% tax-exempt revenue bonds, 35 years @ 10%.
5. Hydro Alternative III-A is State loan, 35 years @ 5%.
ALASKA POWER AUTHORITY
SCAMMON BAY HYDROELECTRIC PROJECT
W/ FUEL ESCALATION,W/ SPACE HEATING
HEATING CREDIT 8 50Y. AVOIDED COST
FIGURE
S-I
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SECTION I
INTRODUCTION
A. GENERAL
SECTION I
INTRODUCTION
The Alaska Power Authority (APA) is considering a hydroelectric
development at the village of Scammon Bay. Previous studies have shown the
project to be economically feasible and the purpose of this report is to
present alternative methods of financing the project.
B. DESCRIPTION AND BACKGROUND
Scammon Bay is a small village located in the Yukon-Kuskokwim delta
region of southwestern Alaska. The proposed hydroelectric project site is on
a small unnamed creek immediately south of the town. The project would
include a low diversion weir, a 12-inch diameter and 3,500-foot-long penstock,
and a 100 kW powerhouse which would produce 0.41 GWh of electrical energy in
an average year. The tot a 1 construction cost for the project at 1985 price
levels would be approximately $1,500,000. The project was studied by the U.S.
Army Corps of Engineers and was found to be technically and economically
feasible in a report dated March 1982.
The economic analysis for the project was updated in June 1984, using
current cost and energy consumption data. A copy of the letter describing
this economic analysis is included as Appendix C.
Using the standard APA economic criteria with an inflation-free discount
rate of 3.5 percent, a benefit/cost ratio of 1.3 was derived. This analysis
included the space heating benefits expressed in terms of savings in diesel
heating fuel as a benefit to the hydro project. These benefits were assumed
to be the avoided cost of the fuel oil, assuming that 28.3 kWh of electricity
used for space heating is equivalent to burning one gallon of fuel oil.
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C. OVERVIEW
The main objective of an economic analysis is to determine the inherent
economic viability; that is, how do the economic benefits of the project
compare to the economic costs. This comparison is independent of the method
of financing, taxes, and any other costs that may be peculiar to the
enterprise owning the project. As mentioned above, the economic analyses have
indicated that this project is viable.
The objective of a financial analysis, which is the subject of this
report, is to determine how the costs associated with a project will be paid,
and the cash flows that would result from various alternative courses of
action. Interest rates, amortization payment periods, inflation, and taxes
are factors that must be considered by a financial analysis that are often not
considered in an economic analysis. The financial analyses for this project
were conducted according to the general criteria set forth by the APA,
11 Analysis Parameters for the 1984 Fiscal Year.11 A copy of these criteria is
included as Appendix B. The alternative financial plans studied are described
in Section III of this report. In addition to the alternative financial
analyses, a financial analysis for the base case has also been included for
comparison purposes. The base case is an estimate of the configuration and
costs that would occur in Scammon Bay if the existing diesel generator system
continues and is expanded as necessary to meet the projected demand over the
study period.
The costs associated with the proposed project include both hydroelectric
costs and supplemental diesel costs. Even with the hydroelectric project, it
would be necessary to maintain sufficient diesel capacity at Scammon Bay to
meet maximum demands because the hydroelectric project would not meet the full
Scammon Bay demands. The electrical demand satisfied by the system would
include the village electrical demand, and the use of excess electricity for
space heating. Benefits possible from waste heat recovery were not
included. This analysis describes the forecasted unit cost of power for the
base case and the hydroelectric project for the various financial alternatives
studied.
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In allocating excess energy, it was assumed that the village electrical
needs would be met first, and, if excess hydroelectric energy remained and
sufficient space heating demand existed, then the excess electricity would be
sold for space heating use. The space heating energy demand that could be
satisfied by the hydroelectric project was included as supplemental revenues
from the sale of this power at alternative sales prices. This supplemental
revenue was then be applied to decrease the cost of power for Scammon Bay.
0. REPORT FORMAT
The report is presented with a summary, three chapters of text with
figures and selected tables, and seven appendices. An effort has been made to
make the report more readable by including only key tables with the report
text and placing the majority of the tables for the diesel analyses, hydro-
electric analyses, and space heating analyses in the respective appendices.
Two summary tables for each alternative financial plan studied (one for
with fuel escalation and one for without fuel escalation) were prepared and
the eight with fuel escalation tables (considered to represent the most
realistic case) were included with Section III. The eight without fuel esca-
lation summaries were placed in Appendix G.
Appendix A, 11 EBASCO Cost Estimate,11 Appendix 8, 11 APA Analysis Para-
meters11, and Appendix C, 11 Economic Analysis Update,11 were included to provide
background material and criteria.
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SECTION II
GENERAL CRITERIA
A. GENERAL
SECTION II
GENERAL CRITERIA
The Scammon Bay Hydroelectric Project was assessed in order to determine
the cost of power production for alternative energy supply systems and alter-
native methods of financing. The financial alternatives studied were speci-
fied by the APA and are described in Section III of this report. The alter-
native energy systems considered include diesel generation alone (Base Case)
and hydroelectric generation supplemented GY diesel generation (Hydroelectric
Case). Both the Base Case and Hydroelectric Case were formulated to meet the
same energy needs for Scammon Bay, as projected over the study period.
B. FINANCIAL CRITERIA
The assumptions that form the basis for this analysis are founded to as
great an extent as possible on the APA standard criteria. Additional criteria
utilized are described below.
In accordance with APA criteria, the planning period for the project is
20 years and begins in January 1986 and extends through 2005. The hydroelec-
tric project was assumed to be on-line by January 1986, and the analysis
extends 50 years beyond this time through 2035. The years 1983 through 1985
are also presented for information only, resulting in a total period of eval-
uation of 53 years. Assumptions for energy demand projections together with
general inflation and real fuel escalation were applied over the 20 year plan-
ning period and were then assumed as level over the remaining 30 years of the
study period.
The analyses for the study were conducted both with and without real fuel
escalation. As per APA criteria, a general inflation rate of 6.5 percent was
assumed for all costs. The prices of fuel oil and lubrication oil were
increased at the general 6.5 percent inflation rate from January 1983 through
the end of 1988. These prices were then escalated at an annual rate of
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SF:IEB:AD1:4-II
9.5 percent for the with real fuel escalation case from January 1989 to the
end of the planning period in order to reflect a real fuel cost escalation of
three percent annually. For the without real fuel escalation case the infla-
tion rate used was 6.5 percent as for all other costs. All costs for both the
with and without real fuel escalation cases were then assumed to remain con-
stant after the last cost escalation occurs in 2005, the last year of the
planning period. The costs were then held constant at the 2005 value for the
remainder of the period of economic evaluation through 2035.
The interest rate for bond sales and sinking funds was assumed to be
10 percent, representing an average for current market rates. The interest
rate for state loans was assumed to be five percent.
The economic life of the hydroelectric project facilities was assumed to
be 50 years. The economic project life for diesel engines was assumed to be
from 10 to 20 years, depending on the size of the machines.
All costs, including operation, maintenance costs and capital costs were
assigned to the year in which they would occur. Capital costs were assumed to
be equa 1 to the sum of the construction costs and interest during construc-
tion, financing charges, and reserve funds, as applicable. The first debt
service payment was shown in the year following the capital cost. Replacement
costs were handled by the use of a sinking fund and were assumed to occur over
the project study period.
C. ENERGY DEMAND AND SUPPLY
The energy demand and supply for the village of Scammon Bay were deter-
mined from AVEC records. This determination was made by the consultants in
cooperation with APA. The historical generation records for January 1987
through December 1983 were used as a base period to determine the pattern of
monthly demands as percentages of annua 1 demand. The annua 1 energy demands
are shown on Table II-1. The village demands were escalated at 2.0 percent
annually over the 20 year planning period and then assumed to remain level.
II-2
The annual supply and distribution of energy over the study period to
meet these demands is also shown on Table II-1, indicating the hydroelectric
and diesel requirements of the village system and the amount of excess hydro-
electric energy available for space heating. This data is also presented
graphically on a monthly basis in Figure II-1 for 1986, the first year of
hydroelectric generation and for 2005, the last year of the 20-year planning
period. These figures illustrate that as the village demand increases over
time, less excess energy is available for space heating and that the need for
supplemental diesel increases
D. DIESEL COSTS
The costs of diesel generation were taken from the AVEC records and were
estimated in cooperation with APA. The costs of diesel generation were
assumed to include debt service, various operating costs, and fuel oil.
The cost of the existing system was based on AVEC records and was assumed
to be the sum of depreciation and interest on the existing debt. Interest was
assumed as two percent annually on the outstanding principal of a 35 year
loan. The outstanding principal for 1984 was $270,738. Depreciation was
assumed as six percent of the original plant cost of $301,252 annually. This
information was furnished in a letter from APA to OOWL dated May 15, 1984.
The cost and schedule of diesel replacements was also supplied by APA. A
175 kW unit would be installed in 1986, followed by another 175 kW unit in
1988. These units would be replaced every 10 years in perpetuity. A 300 kW
unit would be installed in 1998 and replaced every 15 years in perpetuity.
The existing units would all be retired by 1992. The 175 kW units would cost
$60,000, and the 300 kW unit would cost $100,000, both at 1984 price levels.
Fuel tanks would be added in 1986 at a cost of $50,000 and 1998 at a cost of
$150,000, again at 1984 price levels. Additions and replacements were assumed
to be financed by tax-exempt revenue bonds bearing an interest rate of 10 per-
cent.
The existing system at Scammon Bay consists of one 75 kW, one 110 kW, and
one 105 kW units yielding a firm capacity of 180 kW. An additional 175 kW
unit would be installed in 1986, followed by a 175 kW unit in 1988 and a
II-3
SF:IEB:A01:4-II
300 kW unit in 1998. The 175 kW units would be replaced every 10 years in
perpetuity and the 300 kW unit would be replaced every 15 years in perpe--=
tuity. The existing units would all be retired by 1992.
No added life was assumed for the diesel engines for the hydroelectric
case. The machines would operate for significantly less time under the with
hydro case and should have longer lives; however, because of the uncertainty
associated with the availability of parts and maintenance, this credit was not
considered.
The variable operating cost was assumed to be 8.5 cents/kWh for 1984.
This is the AVEC system average variable operating cost and includes the costs
of lubrication oil, operation, miscellaneous consumables, ordinary maintenance
and extraordinary maintenance.
The cost of oil was supplied by APA and was $1.56/gallon for 1984. The
rate of consumption was assumed as 9.6 kWh of generated electricity per gallon
of fuel oil. The cost of fuel oil was escalated at 6.5 percent annually
through 1988 and then at 9.5 percent through 2005 for the with fuel escalation
case and at 6.5 percent for the without fuel escalation case.
E. HYDROELECTRIC COSTS
The total construction cost of the hydroelectric project was supplied by
APA in a letter to OOWL dated May 15, 1984. The total construction cost
includes construction, engineering, construction management, and legal and
administrative costs. The total project cost at January 1985 price levels is
$1,500,000. This cost is based on a cost estimate prepared EBASCO Services
Inc. dated June 23, 1982. The cost were carried forward to January 1985
without escalation as indicated by the APA letter. The EBASCO estimate is
included as Appendix A.
Two replacement costs were considered for the hydroelectric project: the
cost of replacing the turbine runner after 25 years of operation, and the cost
of replacing the transmission line that would tie the plant to the village
distribution system every 30 years. The 30-year economic life of the trans-
II-4
SF:IEB:AD1:4-II
mission lines is based on observation of existing lines. The cost of
replacing the runner was estimated as $26,000 at January 1983 price levels,_..,.
and the cost of replacing the lines was estimated as $62,000 at January 1983
price levels.
F. OPERATION AND MAINTENANCE COSTS
The operation and maintenance (O&M) costs for the existing diesel system
was assumed as 8.5 cents/kWh for 1984. The value represents the average O&M
cost for the entire AVEC system and includes the costs of lubrication oil,
operation, miscellaneous consumables, ordinary plant maintenance, and extra-
ordinary plant maintenance.
The operation of the hydroelectric facilities would be conducted by the
same personnel as the diesel plant. An additional $5,000 per year was allowed
for extra expenses attributable to the hydroelectric project.
The O&M costs for both the base case and hydroelectric project case were
allowed to inflate at 6.5 percent per year over the planning period of 1986
through 2005.
G. SPACE HEATING
The proposed hydroelectric project will produce significantly more elec-
trical energy than can be used in the village. This energy ~auld be sold for
use by electrical space heaters and the revenue could be used to offset the
cost of energy to the village. This space heating cost reduction was con-
sidered for a range of prices and for both the cases of with real fuel escala-
tion and without real fuel escalation.
II-5
SF:IEB:A01:4-II
YEAR
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2035
TABLE II-1
ALASKA POWER AUTHORITY
SCAMMON BAY HYDROELECTRIC PROJECT
ANNUAL ENERGY SUPPLY AND DE~AND
JUNE 1984
TOTAL
VILLAGE
ELECTRICAL
DEMAND
(MWh>
(1)
449.88
458.88
468.06
477.42
486.97
496.71
506.64
516.78
527. 11
537.65
548.41
559.38
570.56
581.97
593.61
605.49
617.60
629.95
642.55
655.40
668.51
681.88
695.51
695.51
TOTAL
HYDRO
SUPPLY
<MWh>
(2)
0.00
0.00
0.00
408.90
408.90
408.90
408.90
408.90
408.90
408.90
408.90
408.90
408.90
408.90
408.90
408.90
408.90
408.90
408,90
408.90
408.90
408.90
408.90
408.90
VILLAGE
ELECTRICAL
DEMAND
MET BY
HYDRO
(MWh)
(3)
0.00
0.00
0.00
258.55
262.88
267.29
271.79
276.37
281.05
285.83
290.69
294.97
299.12
303.34
307.65
312.05
316.53
321. 11
325.78
330.53
335.39
340.34
345.39
345.39
VILLAGE
ELECTRICAL
DE~AND
MET BY
DIESEL
<Miolh)
(4)
449.88
458.88
468.06
218.87
224.09
229.42
234.86
240.40
246.06
251.83
257.71
264.40
271.45
278.63
285.96
293.44
301.06
308.84
316.77
324.86
333.12
341.53
350. 12
350.12
HYDRO
SUPPLY
AVAILABLE
FOR SPACE
HEATING
<MWh>
(5)
0.00
0.00
0.00
150.35
146.02
141.61
137. 11
132.53
127.85
123.07
118.21
113.93
109.78
105.56
1 e 1. 25
96.85
92.37
87.79
83.12
78.37
73.51
68.56
63.51
63.51
<1>Energy consumption for 1983=449.840 MWh from APA letter dated May 15,1984.
Escalated at 2.0~ annually through 2005 according to APA letter to DOWL
dated May 15,1984
(2)Hydro energy production from Corps of Engineers Feasibility Report.
(3)Annual village electrical demand met by hydro.
(4)Annua1 village electrical demand met by supplemental diesel
(5)Excess hydro generation available for use for space heating.
>-...J a. a.
::l
Ul
t:l z a:
t:l z a:
~ w
t:l
>-(!)
~ w z w
2a I
I ter--r~+-~--~--~~--+--+--4---~~~ I
I
I
I e~~==~~~~~L_-L--~~--~--Li_L__J
J'RN F'EB l'tAR APR HAY J'UN Jl.L RUG SEP OCT NOV DEC
MONTH
1. Village demand includes residential, commercial, and school
demands for 1986.
2. Supplemental diesel is portion of village demand in excess of
availalbe hydro generation.
3. Values shown are for 1986.
ALASKA POWER AUTHORITY
SCAMMON BAY HYDROELECTRIC PROJECT
ENERGY DEMAND AND SUPPLY FOR 1986
FIGURE
II-1
>-
_J
c.. c..
::J
U)
1=1 z a:
0 z a:
l: w
0
>-
CI
0:: w z w
108 ~---T---~-r·-~---T--/-v~LAG/n~~ -r ;----l
saL;---~--f---j--~---~-~----~---;-\---~
sa ~--~-~R~-s~~~~; .. --; --·' . -r-, ·./~·-
1 I _j_ I I \
72 r----~ __y/:~~~ >-1--~.::-, . -_._ --' ! // . -~
~ /' ;1'._: \. .
\ I I I ' I \I / i
I 1 \, _/-.. I sa~-'v-'--~ __ r. . . _ --r--· ·;;r, --~ ....
• I \ <\ ~ /' ,
I \ y· ,-\ I , , , .--·r ----_,\_ ·;. ,/· . ·\ -·--·---
1 v " ' \
I "-~
"" L-------· · ~-··· -1 ---i --~
II , 1\ I HYDRO TO SPACE HERTING
30 ~-~-r ---f· ---· · • ____ : · .. : ·---· -~ ·--\ ~ ._..~..:..l;_SUPPLEM[N'!RL DIESEL \
' I ! /. • ' I 20 -. -·T--: · ·t: -· -•---r---.. -----.. --".-·· --. . -+-.. I
' I I I ' I ~
i I I I ;II : I ' , '
52~-· --1
I I : I ' I ··rr +rcr I --, -i r . -y : -~
e · _L -· L .. -L .. .l __ L __ _l __ l . ___ I_J-_j
JAN F"EB MAR APR HAY JUN JUL RUG SEP OCT NOV DEC
MONTH
1. Village demand includes residential, commercial, and school
demands for 2005.
2. Supplemental diesel is portion of village demand in excess of
available hydro generation.
3. Values shown are for 2005.
ALASKA POWER AUTHORITY
SCAMMON BAY HYDROELECTRIC PROJECT
ENERGY DEMAND AND SUPPLY FOR 2005
FIGURE
II-2
SF:IEB:AD1:4-C
SECTION III
FINANCIAL ALTERNATIVES .-..-
A. GENERAL
SECTION III
FINANCIAL ALTERNATIVES
The financial alternatives analyzed for the the Scammon Bay Hydroelectric
Project include revenue bonds, state loans~ state equity financing, and combi-
nations of revenue bonds and state grants. These alternatives apply only to
the financing of the hydroelectric facilities and not to the supplemental
diesel. The financing of the supplemental diesel and the base case costs was
considered separately, considering both the current cost of power and the APA
recommended analysis parameters for 1984. In addition to the various schemes
for financing the hydroelectric project, a base case alternative was consid-
ered to provide a comparison to the existing situation. The base case,
supplemental diesel, and hydroelectric financial alternatives and analysis
results are presented below.
B. BASE CASE
The base case analysis assumes that the hydroelectric project would not be
built and that the existing diesel system, expanded for future demand as
necessary, would continue to serve as the sole source of electrical energy.
The existing system consists of one 75 kW, one 100 kW, and one 105 kW units.
All these units would be retired by 1992. A 175 kW unit would be added in
1986 and another 175 kW unit would be added in 1988. A 300 kW unit would be
added in 1998, resulting in a final firm capacity of 350 kW (firm capacity is
the system capacity with the 1 argest unit not operable). The schedu 1 e of
investments for the diesel system is presented as Table III-11.
The current debt service on the existing diesel system at Scammon Bay is
the sum of two percent annual interest and six percent annual depreciation.
The 175 kW units wouJd be replaced every ten years and financed at 10 percent,
and the 300 kW unit would be replaced every 15 years and financed at 10 per-
cent. The low rate assumed for the cost of existing debt service was based on
data supplied by APA.
II 1-1
The base case analysis is presented in Tables 0-1 and 0-2 of Appendix 0
for the cases of with and without real fuel escalation respectively and is-=
presented in summary form on Tables III-1 through III-8. The cost for 1986 is
37.26¢/KWh for either the with or without fuel escalation case and increases
to 150.52¢/KWh for the with real fuel escalation by the end of the planning
period in 2005. The corresponding unit value for 2005 without fuel escalation
is 113.71¢/KWh.
C. SUPPLEMENTAL DIESEL
The supplemental diesel costs were assumed to be the same as the base case
diesel costs except that the energy demand and associated variable fuel oi 1
and maintenance costs would apply only to the portion of village energy demand
not met by the hydroelectric project. These diesel costs were discussed in
Section II of this report.
The detailed supplemental diesel analysis, which is the same to all finan-
cial plans, is presented in Appendix D as Tables 0-3 and 0-4 for the cases of
with and without fuel escalation, respectively. The summarized cost is then
presented in Tables III-1 through III-8 for each of the individual financial
alternatives studied. The unit cost of supplemental diesel for 1986, averaged
over the annual village demand and assuming real fuel escalation, would be
22.05¢/kWh; this cast escalates to 86.12¢/kWh by 2005. If the effects of fuel
escalation are neglected, the cost of power for 1986 would be 22.05¢/kWh,
escalating to 67 .59¢/kWh by 2005. The cost of supplemental diesel is the
component of the total cost not included in the hydroelectric financing.
D. SPACE HEATING
At some times of the year, the proposed hydroelectric project would pro-
duce electrical demand. This electricity could be used for space heating or
could be sold to any other use that might exit. For purposes of this analy-
sis, the value of this electricity was assumed to be a percentage of the
avoided cost of fuel oil that it could replace. This analysis is presented as
Tables F-1 and F-2 in Appendix F for the cases of with and without fuel esca-
lation, respectively. The potential savings is the indicated percentage of
II I-2
the avoided cost of fuel distributed over the entire village demand. The
existence of heating demand and the cost of distributing and metering this-=-
power were not considered; this data is presented to indicate a very conserva-
tive, low value for this power if a use for the power can be established. The
potential savings at 50 percent of the avoided cost of fuel oi 1 would be
0.98¢/kWh in 1986 and would escalate to 1.51¢/kWh by 2005 for the with fuel
escalation case and 0.94¢/kWh for the without fuel escalation case.
E. FINANCIAL PLANS
Using the criteria and assumptions previously presented, alternative
financial plans were analyzed. A description and results of the analysis for
each alternative studied are presented below.
Complete analyses are presented in this report for each alternative with
and without real fuel escalation. In addition, the results of each of these
analyses may be modified for the inclusion of excess energy sales to space
heating at selling prices of 25%, 50%, and 75% of avoided cost. A total of
six separate results for each of the eight financial alternatives studied then
results.
To simplify the following discussion of results, the with real fuel esca-
lation and without space heating conditions are used for discussion examples
since this combination is considered to be the most probable future scena-
rio. This is because most economists foresee long term real fuel escalation
occurring in excess of general inflation. Nevertheless, data is presented in
the various tables for the without real fuel escalation case and the potential
space heating credit if results for these alternatives are desired.
Financial summaries for each of the alternatives studied are included at
the end of this section as Table III-1 through III-8 (v4ith real fuel esca-
lation) and in Appendix G as Tables G-1 through G-9 (without real fuel escala-
tion). All alternatives are summarized in Table III-9 (with real fuel
escalation) and Table III 10 (without real fuel escalation}. Both Table III-9
and Table III 10 also include potential space heating savings.
I II-3
1. ALTERNATIVE I-A: 100% REVENUE BONOS
Under this alternative, the entire hydroelectric cost would be paid from
the sale of tax-exempt revenue bonds bearing an interest rate of 10 percent
for 35 years~ The total bond sale would include the direct construction
costs, an allowance of 10 percent for interest during construction, an allow-
ance of 3.75 percent for financing fees, and a reserve fund equal to 110 per-
cent of one year's debt service. The resu 1 t i ng tot a 1 bond size wou 1 d be
$1,925,900. Table III-1 shows the total annual unit cost of this alternative,
including both supplemental diesel and hydroelectric costs. As shown in
Table 111-1, the unit energy cost of Alternative 1-A for 1986 would be
61.47¢/kWh and would escalate to 115.74¢/kWh by the year 2005. Space heating
credits at 50% avoided cost would decrease these prices to 60.49¢/kWh and
114.23¢/kWh respectively. The cost of power for Alternative I-A would be
greater than the cost of Base Case power until 1997.
2. ALTERNATIVE I-8: 100% REVENUE BONDS WITH GRADUATED PAYMENTS
Under this alternative, the project would be funded 100% by revenue bonds,
as for Alternative I-A; however, the debt service payments would be made on a
graduated basis. The debt service for 1986 would be reduced to a level that
would make the unit cost of energy for that year the same for the base case
and the hydroelectric plus supplemental diesel case. The debt service would
then be increased at a maximum rate of 9.5 percent (the same rate of increase
of fuel with inflation and escalation), until a uniform payment could be made
for the remainder of the 35 years without exceeding the 9.5 percent
increase. This alternative is shown on Table III-2. The total cost of energy
for 1986 wou 1 d be 37 .26¢/kWh ( equa 1 to the base case cost) with or without
fuel escalation, but consideration of the space heating credit at 50% avoided
cost would decrease this figure by 0.98¢/kWh to 36.28¢/kWh.
3. ALTERNATIVE II-A: 50% REVENUE BONDS/50% STATE GRANT
This alternative is similar to Alternative I-A, but only 50 percent of the
direct construction cost would be borne by the power users. The results of
the analyses of this Alternative are presented as Table III-3. The remaining
III-4
r r _ T rn ~ tt n 1 .. ,1 r T T
50 percent of the project cost would be paid by State assistance. The cost of
power for this alternative in 1986 would be 42.86¢/kWh or 41.88¢/kWh with the .r
space heating credit at 50% of avoided cost. The cost would increase to
102.96¢/kWh or 101.45/kWh with the space heating credit at 50% of avoided cost
by 2005.
4. ALTERNATIVE II-8: 40% REVENUE BONDS/60% STATE GRANT
The project would be financed using tax-exempt revenue bonds for
40 percent of the construction cost and a state grant for the remaining
60 percent. The results of this analysis are shown in Tables III-4. The 1986
cost of power for this alternative would be 39.13¢/kWh or 38.15¢/kWh with
space heating credits at 50% avoided cost, increasing in 2005 to 100.40¢/kWh
or 98.89¢/kWh space heating credits at 50 percent avoided cost.
5. ALTERNATIVE II-C: 34.96% REVENUE BONOS/65.04% STATE GRANT
The project would be financed using a combination of tax-exempt revenue
bonds and a state grant. The bond sale would be sized in such a manner that
the unit cost of power in 1986 would be the same for the base case and the
hydroelectric plus supplemental diesel case, assuming fuel escalation. The
remainder of the capital cost (not included in the bond sale) would be paid by
a state grant. The results of this analysis are shown in Table III-5. The
unit cost of power for 1986 would be 37.26¢/kWh increasing to 99.11¢/kWh in
2005.
6. ALTERNATIVE III-A: STATE LOAN
Under this alternative, the project would be financed by a state loan
bearing an interest rate of five percent for 35 years.
struction and a reserve fund would not be considered
The results of this analysis are shown on Table III-6.
for this alternative ~auld be 43.43¢/kWh, increasing to
I II -5
Interest during con-
for this alternative.
The 1986 cost of power
103.35¢/kWh in 2005.
7. ALTERNATIVE III-8: STATE LOAN WITH DEFERRED PAYMENT
The project would be financed by a state loan at an interest rate of five
percent as above; however, principal and interest payments would be deferred
on the debt for 10 years, follows by 25 years of fully amortized debt serv-
ice. This alternative is shown in Table III-7. The 1986 unit cost of power
for this alternative would be 24.24¢/KWh increasing to 39.68¢/KWh in 1995 and
almost doubling to 73.73¢/kWh in the following year, 1996, when the 10-year
deferral period ends.
8. ALTERNATIVE IV: STATE EQUITY FINANCING
The state would pay the entire capital cost of the project and would
receive an annual payment equal to five percent of the capital cost. The
costs of operation, maintenance, and replacement would be paid from this five
percent payment and the remainder of the five percent would be the return on
investment to the state. The cash flow for this situation is shown in
Table III-8. The 1986 unit cost of energy, including fuel escalation, would
be 37.96¢/kWh increasing in 2005 to 96.90¢/kWh.
I II-6
"'t·-«;
TABLE II I-1
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE I-A
WITH REAL FUEL ESCALATIOH
JUNE 1984 -YEAR BASE SUPPL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh) (c/kWh) (c/kWh) (c/kWh) (c/kWh> (c/kWh) < c /kWh>
25~ 50~ 75%
(1) (2) (3) (4) (5) (6) (7)
---------------------------------------------------------------
1983 28.60 28.60 0.00 28.60 0.00 0.00 0.00
1984 29.98 29.98 0.00 29.98 0.00 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.00 0.00 0.00
1986 37.26 22.05 39.42 61.47 .49 .98 1. 48
1987 38.88 22.74 38.75 61.48 .50 1. 00 1. 50
1988 43.48 26.35 38.09 64.45 • 51 1. 01 1. 52
1989 45.93 27.40 37.46 64.86 .53 1. 05 1. 58
1990 48.61 28.57 36.84 65.41 .55 1. 09 1. 64
1991 51.55 29.87 36.24 66. 12 .56 1. 13 1. 69
1992 54.78 31.32 35.66 66.98 .58 1. 17 1. 75
1993 58.31 32.93 35.09 68.02 .60 1. 20 1. 80
1994 62. 18 34.77 34.55 69.31 .62 1. 24 1. 87
1995 66.42 36.82 34.01 70.84 .64 1. 29 1. 93
1996 72.94 40.99 33.50 74.49 .66 1. 33 1. 99
1997 77.97 43.46 33.00 76.46 .68 1. 37 2.05
1998 98.45 61. 17 32.52 93.69 .70 1. 41 2. 11
1999 102.22 61.94 32.05 93.99 .72 1. 44 2. 16
2000 108.54 65.01 31.61 96.61 .73 1. 47 2.20
2001 115.47 68.42 31. 18 99.59 .75 1. 49 2.24
2002 123.08 72.20 30.76 102.96 .76 1. 51 2.27
2003 131.41 76.38 30.36 106.74 .76 1. 52 2.28
2004 140.53 81.01 29.98 110.99 .76 1. 52 2.28
2005 150.52 86.12 29.62 115.74 .76 1. 51 2.27
2006 151.99 87.59 29.62 117.21 .76 1. 51 2.27
2007 151.96 87.56 29.62 117.18 .76 1. 51 2.27
2008 154.07 89.66 . 29. 62 119.28 • 76 1. 51 2.27
2009 154.04 89.64 29.62 119.25 .76 1. 51 2.27
2010 154.01 89.61 29.62 119.23 .76 1. 51 2.27
2011 153.98 89.58 29.62 119.20 . 76 1. 51 2.27
2012 153.95 89.55 29.62 119.17 .76 1. 51 2.27
2018 149.69 85.28 29.62 114.90 .76 1. 51 2.27
2019 149.69 85.28 15.41 100.69 . 76 1. 51 2.27
2020 149.69 85.28 15.41 100.69 • 76 1. 51 2.27
2021 149.69 85.28 4.07 89.35 .76 1. 51 2.27
2035 149.69 85.28 4.07 89.35 • 76 1. 51 2.27
(1)Se:e Tab 1 e D-1
<2>Se:e: Table: D-3
<3>Se:e: Table: E-1
(4)Sum of hydro and supplemental diesel costs.
<5>Potential space he.at i ng credit at 25~~ avoided cosi.See Table: F-1.
<6>Potentia1 space: heating credit at 50~ avoided cosi.Se:e Table F-1.
<?>Potential space heating credit at 75% avoided co:si.Se:e Table F-1.
TABLE III-2
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE I-II
WITH REAL FUEL ESCALATION
JUNE 1984 -YEAR BASE SUPPL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh) (c/kWh) (c/kWh> < c /kWh> (c/kWh> (c/kWh) (c/kWh)
25% 50% 75%
(1) (2) (3) (4) (5) (6) (7)
------------------------------------------------------ ---------
1983 28.60 28.60 0.00 28.60 0.00 0.00 0.00
1984 29.98 29.98 0.00 29.98 0.00 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.00 0.00 0.00
1986 37.26 22.05 15.20 37.26 .49 .98 1. 48
1987 38.88 22,74 16.65 39.38 .50 1. 00 1. 50
1988 43.48 26.35 18. 19 44.54 • 51 1. 01 1. 52
1989 45.93 27.40 19.84 47.24 .53 1.05 1.58
1990 48.61 28.57 21.60 50.17 .55 1. 09 1. 64
1991 51.55 29.87 23.47 53.35 .56 1. 13 1. 69
1992 54.78 31.32 25.48 56.80 .58 1. 17 1. 75
1993 58.31 32.93 27.62 60.55 .60 1. 20 1. 80
1994 62.18 34.77 29.92 64.68 .62 1. 24 1. 87
1995 66.42 36.82 32.37 69.19 .64 1. 29 1. 93
1996 72.94 40.99 35.00 75.98 .66 1. 33 1. 99
1997 77.97 43.46 37.80 81.26 .68 1. 37 2.05
1998 98.45 61. 17 40.81 101. 98 .70 1. 41 2. 11
1999 102.22 61.94 44.02 105.96 .72 1. 44 2. 16
2000 108.54 65.01 47.47 112.48 .73 1. 47 2.20
2001 115.47 68.42 49.57 117.98 .75 1. 49 2.24
2002 123.08 72.20 48.79 120.99 .76 1. 51 2.27
2003 131.41 76.38 48.04 124.42 .76 1. 52 2.28
2004 140.53 81.01 47.31 128.32 .76 1. 52 2.28
2005 150.52 86.12 46.61 132.73 .76 1. 51 2.27
2006 151.99 87.59 46.61 134.20 .76 1. 51 2.27
2007 151.96 87.56 46.61 134. 1 7 .76 1. 51 2.27
2008 154.07 89.66 46.61 136.28 .76 1. 51 2.27
2009 154.04 89.64 46.61 136.25 .76 1. 51 2.27
2010 154.01 89.61 46.61 136.22 .76 1. 51 2.27
2011 153.98 89.58 46.61 136. 19 .76 1. 51 2.27
2012 153.95 89.55 46.61 136.16 .76 1. 51 2.27
2018 149.69 85.28 38.19 123.47 .76 1. 51 2.27
2019 149.69 85.28 38.19 123.47 .76 1. 51 2.27
2020 149.69 85.28 38.19 123.47 .76 1. 51 2.27
2021 149.69 85.28 4.07 89.35 .76 1. 51 2.27
2035 149.69 85.28 4.07 89.35 .76 1. 51 2.27
<1>See Table D-1
(2)See Table D-3
<3>See Table E-2
<4>Sum of hydro and supplemental diesel costs.
(5)Potential space heating credit at 25% avoided cost.See Table F-1.
(6)Potent i al space heating credit at 50% avoided cost.See Table F-1.
(?)Potential space heating credit at 75% avoided cost.See Table F-1.
TABLE III-3
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE II-A
WITH REAL FUEL ESCALATION
JUNE 1984 -YEAR BASE SUP PL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh) (c/kWh) (c/kWh) (c/kWh) (c/kWh) < c /kWh) (c/kWh)
25% 50% 7S%
(1) (2) (3) (4) (5) (6) (7)
---------------------------------------------------------------
1983 28.60 28.60 e.ee 28.60 0.80 e.ea e.ee
1984 29.98 29.98 a.ea 29.98 0.80 a.0a a.e0
1985 31.46 31.46 a.e0 31.46 0.80 a.0e 0.00
1986 37.26 22.05 20.80 42.86 .49 .98 1. 48
1987 38.88 22.74 20.50 43.23 .50 1. 00 1. 50
1988 43.48 26.35 20.20 46.55 .51 1. 01 1. 52
1989 45.93 27.40 19.92 47.32 .53 1. 05 1. 58
1990 48.61 28.57 19.65 48.22 .55 1. 09 1. 64
1991 51.55 29.87 19.38 49.26 .56 1. 13 1. 69
1992 54.78 31.32 19. 13 50.45 .58 1. 17 1. 75
1993 58.31 32.93 18.89 51.82 .6a 1.20 1. 80
1994 62. 18 34.77 18.66 53.42 • 62 1. 24 1. 87
1995 66.42 36.82 18.44 55.26 .64 1. 29 1. 93
1996 72.94 40.99 18.23 59.22 .66 1. 33 1. 99
1997 77.97 43.46 18.03 61.49 .68 1. 37 2.05
1998 98.45 61. 17 17.84 79.02 .70 1. 41 2. 11
1999 102.22 61.94 17.67 79.61 .72 1. 44 2.16
2000 108.54 65.01 17.50 82.51 .73 1. 47 2.20
2001 115.47 68.42 17.35 85.76 .75 1. 49 2.24
2002 123.08 72.20 17.20 89.40 .76 1. 51 2.27
2003 131.41 76.38 17.07 93.45 .76 1. 52 2.28
2004 140.53 81.01 16.95 97.96 .76 1. 52 2.28
2005 150.52 86.12 16.84 102.96 .76 1. 51 2.27
2006 151.99 87.59 16.84 104.43 .76 1. 51 2.27
2007 151.96 87.56 16.84 104.40 .76 1. 51 2.27
2008 154.07 89.66 16.84 106.51 .76 1. 51 2.27
2009 154.04 89.64 16.84 106.48 .76 1. 51 2.27
2010 154.01 89.61 16.84 106.45 .76 1. 51 2.27
2011 153.98 89.58 16.84 106.42 .76 1. 51 2.27
2012 153.95 89.55 16.84 106.39 . 76 1. 51 2.27
2018 149.69 85.28 16.84 102. 12 .76 1. 51 2.27
2019 149.69 85.28 9.74 95.02 .76 1. 51 2.27
2020 149.69 85.28 9.74 95.02 .76 1. 51 2.27
2021 149.69 85.28 4.07 89.35 .76 1. 51 2.27
2035 149.69 85.28 4.07 89.35 .76 1. 51 2.27
(l)See Table D-1
(2)See Table D-3
(3)See Table E-3
(4)Sum of hydro and supplemental diesel costs.
(5)Potent i al space heating credit at 25% avoided cost.See Table F-1.
<6)Potential space heating credit at 50% avoided cost.See Table F-1.
<?)Potential space heating credit at 75% avoided cost.See Table F-1.
TABLE III-4
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE I I-B
WITH REAL FUEL ESCALATION
JUNE 1984 -YEAR BASE SUPPL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh> <c:/kWh> (c/kWh> (c/kWh> (c/kWh> (c/kWh) (c/kWh>
25% 50% 75%
(1) (2) (3) (4) (5) (6) (7)
------------------ --------- ------------------------------------
1983 28.60 28.60 0.00 28.60 0.80 0.00 0.00
1984 29.98 29.98 0,00 29.98 0.80 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.80 0.00 0.00
1986 37.26 22.05 17.08 39.13 .49 .98 1. 48
1987 38.88 22.74 16.85 39.58 .50 1. 00 1. 50
1988 43.48 26.35 16.63 42.98 • 51 1. 01 1. 52
1989 45.93 27.40 16.41 43.81 .53 1. 05 1. 58
1990 48.61 28.57 16.21 44.78 • 55 1. 09 1. 64
1991 51.55 29.87 16.01 45.89 .56 1. 13 1. 69
1992 54.78 31.32 15.83 47.15 .58 1. 17 1. 75
1993 58.31 32.93 15.65 48.58 .60 1. 20 1. 80
1994 62. 18 34.77 15.48 50.25 .62 1. 24 1. 87
1995 66.42 36.82 15.32 52.15 .64 1. 29 1. 93
1996 72.94 40.99 15. 18 56.16 • 66 1. 33 1.99
1997 77.97 43.46 15.04 58.49 .68 1. 37 2.05
1998 98.45 61. 17 14.91 76.08 .70 1. 41 2. 11
1999 102.22 61.94 14.79 76.73 .72 1. 44 2. 16
2000 108.54 65.01 14.68 79.69 .73 1. 47 2.20
2001 115.47 68.42 14.58 83.00 .75 1. 49 2.24
2002 123.08 72.20 14.49 86.69 .76 1. 51 2.27
2003 131.41 76.38 14.41 90.79 • 76 1. 52 2.28
2004 140.53 81.01 14.34 95.35 .76 1. 52 2.28
2005 150.52 86.12 14.29 100.40 .76 1. 51 2.27
2006 151. 99 87.59 14.29 101.88 .76 1. 51 2.27
2007 151.96 87.56 14.29 101. 85 .76 1.51 2.27
2008 154.07 89.66 14.29 103.95 .76 1. 51 2.27
2009 154.04 89.64 14.29 103.92 .76 1. 51 2.27
2010 154.01 89.61 14.29 103.89 .76 1. 51 2.27
2011 153.98 89.58 14.29 103.86 .76 1. 51 2.27
2012 153.95 89.55 14.29 103.83 .76 1. 51 2.27
2018 149,69 85.28 14.29 99.57 .76 1. 51 2.27
2019 149.69 85.28 8.60 93.88 .76 1. 51 2.27
2020 149.69 85.28 8.60 93.88 .76 1. 51 2.27
2021 149.69 85.28 4.07 89.35 • 76 1. 51 2.27
2035 149.69 85.28 4.07 89.35 .76 1. 51 2.27
<1>See Table D-1
<2>See Table D-3
<3>See Table E-4
(4)Sum of hydro and supplemental diesel costs.
<5>Potential spac: e heating credit at 25% avoided cost.See Table F-1.
< 6) Potent i a 1 space heating credit at 50% avoided cost.See Table F-1.
<?>Potential space heating credit at 75% avoided cost.See Table F-1.
TABLE III-5
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE I I-C
WITH REAL FUEL ESCALATIOH
JUNE 1984 -YEAR BASE SUPPL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh) (c/kWh) (c/kWh) (c/kWh) (c/kWh) (c/kWh) (c/kWh)
25% 50% 75%
(1) (2) (3) (4) (5) (6) (7)
--------------------------- ------------------------------------
1983 28.60 28.60 0.00 28.60 0.00 0.00 0.00
1984 29.98 29.98 0.00 29.98 0.00 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.00 0.00 0.00
1986 37.26 22.05 15.20 37.26 .49 .98 1. 48
1987 38.88 22.74 15.01 37.74 .50 1. 00 1. 50
1988 43.48 26.35 14.82 41. 17 .51 1. 01 1. 52
1989 45.93 27.40 14.64 42.04 .53 1. 05 1. 58
1990 48.61 28.57 14.47 43.04 .55 1. 09 1. 64
1991 51.55 29.87 14.31 44.19 .56 1. 13 1. 69
1992 54.78 31.32 14. 16 45.48 .58 1. 17 1. 75
1993 58.31 32.93 14.01 46.94 .60 1. 20 1. 80
1994 62. 18 34.77 13.88 48.64 .62 1. 24 1. 87
1995 66.42 36.82 13.75 50.57 .64 1. 29 1. 93
1996 72.94 40.99 13.63 54.62 .66 1. 33 1. 99
1997 77.97 43.46 13.53 56.98 .68 1. 37 2.05
1998 98.45 61. 17 13.43 74.60 .70 1. 41 2. 11
1999 102.22 61.94 13.34 75.28 .72 1. 44 2. 16
2000 108.54 65.01 13.26 78.26 .73 1. 47 2.20
2001 115.47 68.42 13. 18 81.60 .75 1. 49 2.24
2002 123.08 72.20 13. 12 85.32 .76 1. 51 2.27
2003 131.41 76.38 13.07 89.45 .76 1. 52 2.28
2004 140.53 81.01 13.03 94.04 .76 1. 52 2.28
2005 150.52 86.12 13.00 99. 11 .76 1. 51 2.27
2006 151.99 87.59 13.00 100.59 .76 1. 51 2.27
2007 151.96 87.56 13.00 100.56 • 76 1. 51 2.27
2008 154.07 89.66 13.00 102.66 .76 1. 51 2.27
2009 154.04 89.64 13.00 102.63 .76 1. 51 2.27
2010 154.01 89.61 13.00 102.60 .76 1. 51 2.27
2011 153.98 89.58 13.00 102.57 .76 1. 51 2.27
2012 153.95 89.55 13.00 102.54 .76 1. 51 2.27
2018 149.69 85.28 13.00 98.28 .76 1. 51 2.27
2019 149.69 85.28 8.03 93.31 .76 1. 51 2.27
2020 149.69 85.28 8.03 93.31 .76 1. 51 2.27
2021 149.69 85.28 4.07 89.35 .76 1. 51 2.27
2035 149.69 85.28 4.07 89.35 .76 1. 51 2.27
(l)See Table D-1
<2)See Table D-3
(3)See Table E-5
(4)Sum of hydro and supplemental diesel costs.
(5)Potent i al space heating credit at 25% avoided cost.See Table F-1.
(6)Potent i al space heating credit at 50% avoided cost.See Table F-1.
(7)Potentia1 space heating credit at 75% avoided cost.See Table F-l.
TABLE III-6
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE III-A
WITH REAL FUEL ESCALATION
JUNE 1994
...-:
YEAR BASE SUPPL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh> (c/kWh> (c/kWh) (c/kWh) (c/kWh> (c/kWh> (c/kWh>
25% 50% 75%
( 1) (2) (3) (4) (5) (6) (7)
---------------------------------------------------------------
1983 28.60 28.60 0.00 28.60 0.80 0.00 0.00
1984 29.98 29.99 0.00 29.98 0.80 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.80 0.00 0.00
1986. 37.26 22.05 21.38 43.43 .49 .98 1. 48
1987 38.88 22.74 21.06 43.80 .50 1. 00 1. 50
1988 43.48 26.35 20.76 4 7. 11 .51 1. 01 1. 52
1989 45.93 27.40 20.46 47.86 .53 1. 05 1.58
1990 48.61 28.57 20.18 48.75 .55 1. 09 1. 64
1991 51.55 29.87 19.90 49.78 .56 1. 13 1. 69
1992 54.78 31.32 19.64 50.96 .58 1. 17 1. 75
1993 58.31 32.93 19,39 52.32 .60 1. 20 1. 80
1994 62. 18 34.77 19. 15 53.91 .62 1. 24 1. 87
1995 66.42 36.82 18.92 55.74 .64 1. 29 1. 93
1996 72.94 40.99 18.70 59.69 .66 1. 33 1. 99
1997 77.97 43.46 18.49 61.95 .68 1. 37 2.05
1998 98.45 61. 17 18.30 79.47 .70 1. 41 2. 11
1999 102.22 61.94 18. 11 80.05 .72 1. 44 2. 16
2000 108.54 65.01 17.94 82.94 .73 1. 47 2.20
2001 115.47 68.42 17.77 86. 19 .75 1. 49 2.24
2002 123.08 72.20 17.62 89.82 • 76 1. 51 2.27
2003 131.41 76.38 17.48 93.86 .76 1. 52 2.28
2004 140.53 81.01 17.35 98.36 .76 1. 52 2.28
2005 150.52 86.12 17.24 103.35 • 76 1. 51 2.27
2006 151. 99 87.59 17.24 104.82 .76 1. 51 2.27
2007 151.96 87.56 17.24 104.80 .76 1. 51 2.27
2008 154.07 89.66 17.24 106.90 .76 1.51 2.27
2009 154.04 89.64 17.24 106.87 .76 1. 51 2.27
2010 154.01 89.61 17.24 106.84 . 76 1. 51 2.27
2011 153.98 89.58 17.24 106.81 .76 1. 51 2.27
2012 153.95 89.55 17.24 106.78 • 76 1. 51 2.27
2018 149.69 85.28 17.24 102.52 .76 1. 51 2.27
2019 149.69 85. 28, 17.24 102.52 .76 1. 51 2.27
2020 149.69 85.281 17.24 102.52 .76 1. 51 2.27
2021 149.69 85.28 4.07 89.35 .76 1. 51 2.27
2035 149.69 .. as. 28 'I 4.07 89.35 .76 1. 51 2.27
<1>See Table D-1
<2>See Table D-3
<3>See Table E-6
(4)Sum of hydro and supplemental diesel costs.
(5)Potent i al space heating credit at 25% avoided cos1..See Tab 1 e F-1.
(6)Potent i al space heating credit at 50% avoided C0$1..See Table F-1.
<?>Potential space heating credit at 75% avoided cost.See Table F-1.
TABLE III-7
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE I II-B
WITH REAL FUEL ESCALATION
JUNE 1984
~
YEAR BASE SUPPL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
< c /kWh) (c/kWh> (c/kWh) (c/kWh> (c/kWh> (c/kWh) (c/kWh)
25% 50% 75%
(1) (2) (3) (4) (5) (6) (7)
---------------------------------------------------------------
1983 28.60 28.60 0.00 28.60 0.00 0.00 0.00
1984 29.98 29.98 0.00 29.98 0.00 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.00 0.00 0.00
1986 37.26 22.05 2. 19 24.24 .49 .98 1. 48
1987 38.88 22.74 2.25 24.99 .50 1. 00 1. 50
1988 43.48 26.35 2.31 28.66 • 51 1.01 1. 52
1989 45.93 27.40 2.38 29.78 .53 1. 05 1. 58
1990 48.61 28.57 2.45 31.02 .55 1. 09 1. 64
1991 51.55 29.87 2.53 32.40 .56 1. 13 1. 69
1992 54.78 31.32 2.60 33.93 .58 1. 17 1. 75
1993 58.31 32.93 2.69 35.61 .60 1. 20 1. 80
1994 62.18 34.77 2.77 37.54 .62 1. 24 1. 87
1995 66.42 36.82 2.86 39.68 .64 1. 29 1. 93
1996 72.94 40.99 32.75 73.73 .66 1. 33 1. 99
1997 77.97 43.46 32.26 75.72 .68 1. 37 2.05
1998 98.45 61. 17 31.80 92.97 .70 1. 41 2. 11
1999 102.22 61.94 31.35 93.29 .72 1. 44 2. 16
2000 108.54 65.01 30.91 95.92 .73 1. 47 2.20
2001 115.47 68.42 30.50 98.91 .75 1. 49 2.24
2002 123.08 72.20 30.09 102.29 .76 1. 51 2.27
2003 131.41 76.38 29.71 106.09 .76 1. 52 2.28
2004 140.53 81.01 29.34 110.35 .76 1. 52 2.28
2005 150.52 86.12 28.99 115.11 .76 1. 51 2.27
2006 151.99 87.59 28.99 116.58 .76 1. 51 2.27
2007 151.96 87.56 28.99 116.55 .76 1. 51 2.27
2008 154.07 89.66 28.99 118. 65 .76 1. 51 2.27
2009 154.04 89.64 28.99 118.63 .76 1. 51 2.27
2010 154.01 89.61 28.99 118.60 .76 1. 51 2.27
2011 153.98 89.58 28.99 118.57 .76 1.51 2.27
2012 153.95 89.55 28.99 118.54 .76 1. 51 2.27
2018 149.69 85.28 28.99 114.27 .76 1. 51 2.27
2019 149.69 85.28 28.99 114. 27 .76 1. 51 2.27
2020 149.69 85.28 28.99 114. 27 .76 1. 51 2.27
2021 149.69 85.28 4.07 89.35 .76 1. 51 2.27
2035 149.69 85.28 4.07 89.35 .76 1. 51 2.27
<1>See Table D-1
<2>See Table D-3
<3>See Table E-7
<4>Sum of hydro and supplemental diesel costs.
<5>Potent i al space heating credit at 25% avoided cosi.See Table F-1.
(6)Potentia1 space heating credit at 50% avoided cos.I.See Table F-1.
<7>Potent i al space heating credit at 75% avoided cos.J.See Table F-1.
TABLE I II-8
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC AL TERNATI YE IV
WITH REAL FUEL ESCALATION
JUNE 1984 -YEAR BASE SUPPL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh> (c/kWh) (c/kWh) < c/k Wh) (c/kWh) (c/kWh) (c/kWh)
25% 50% 75%
( 1) (2) (3) (4) (5) (6) (7)
--------- --------- --------- ------------------------------------
1983 28.60 28.60 0.00 28.60 0.80 0.00 0.00
1984 29.98 29.98 0.00 29.98 0.80 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.80 0.00 0.00
1986 37.26 22.05 15.71 37.76 .49 .98 1. 48
1987 38.88 22.74 15.40 38.14 .50 1. 00 1. 50
1988 43.48 26,35 15. 10 41.45 .51 1. 01 1. 52
1989 45.93 27.40 14.80 42.20 .53 1. 05 1. 58
1990 48.61 28.57 14.51 43.08 .55 1. 09 1. 64
1991 51.55 29.87 14.23 44.10 .56 1. 13 1. 69
1992 54.78 31.32 13.95 45.27 .58 1. 17 1. 75
1993 58.31 32.93 13.68 46.60 .60 1. 20 1. 80
1994 62.18 34.77 13.41 48.17 .62 1. 24 1. 87
1995 66.42 36.82 13. 14 49.97 .64 1. 29 1. 93
1996 72.94 40.99 12.89 53.87 .66 1. 33 1. 99
1997 77.97 43.46 12.63 56.09 .68 1. 37 2.05
1998 98.45 61.17 12.39 73.56 . 70 1. 41 2. 11
1999 102.22 61.94 12. 14 74.08 .72 1. 44 2.16
2000 108.54 65.01 11.91 76.91 .73 1. 47 2.20
2001 115.47 68.42 11.67 80.09 .75 1. 49 2.24
2002 123.08 72.20 11.44 83.64 .76 1. 51 2.27
2003 131.41 76.38 11.22 87.60 .76 1. 52 2.28
2004 140.53 81.01 11.00 92.01 .76 1. 52 2.28
2005 150.52 86. 12 10.78 96.90 .76 1. 51 2.27
2006 151.99 87.59 10.78 98.37 .76 1. 51 2.27
2007 151. 96 87.56 10.78 98.34 .76 1. 51 2.27
2008 154.07 89.66 10.78 100.45 .76 1. 51 2.27
2009 154.04 89.64 10.78 100.42 .76 1. 51 2.27
2010 154.01 89.61 10.78 100.39 .76 1. 51 2.27
2011 153.98 89.58 10.78 100.36 .76 1. 51 2.27
2012 153.95 89.55 10.78 100.33 .76 1.51 2.27
2018 149.69 85.28 10.78 96.07 .76 1. 51 2.27
2019 149.69 85.28 10.78 96.07 .76 1. 51 2.27
2020 149.69 85.28 10.78 96.07 • 76 1. 51 2.27
2021 149.69 85.28 10.78 96.07 .76 1. 51 2.27
2035 149.69 85.28 10.78 96.07 .76 1. 51 2.27
(l)See Tab 1e D-1
<2>See Table D-3
(3)See Table E-8
(4)Sum of hydro and supplemental diesel costs.
(5)Potent i al space heating credit at 25% avoided cos1..See Table F-1.
<6>Potent i al space heating credit at 50% avoided cos1..See Tab 1 e F-1.
<7>Potent i al space heating credit at 75% avoided cos1..See Table F-1.
TABLE 111-9
ALASKA POWER AUTHORITY
FlHAHClAL AHALYSIS SUMMARY FOR SCAMMOH BAY HYDROELECTRIC PROJECT
UHlT COSTS OF EHERGY: W/ REAL FUEL ESCALATION
JUHE 1984
1 80~; REVEHUE REVEHUE BOHDS AHD STATE LOANS STATE
BOHDS ~~~~~-:~~~~~--------------------------~~~~~:-~~=~i~G;OF=~=C~H~=~~IHG ------------------------------YEAR IBASE 1-A J-B II-A Il-B 11-C III-A IIIl-11 IV 25% 1!58% 17!5%
CASE 188% 188% :58%/!58% 48~V68% 3!5lv6:5%
(C /kWh> (t.FkWh> (t.FkWh> <cJkWh> (C.FkWh> (c:.FkWh> (C/kWh) ( CJkWh) (C/kWh) <C•ntt./kWh> <C•ntt./kWh> <C•ntt./kWh>
(1) <2> (3) (4) <:5> (6) (7) (8) <9> <18> ( 11> <12> -------------------------------------------------------------------------------------------------------
1983 28.68 28.60 28.68 28.68 28.68 28.60 28.60 28.60 28.60 8.8e 8.ee 8.ee
1984 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 e.e8 8.88 8.8e
198:5 31.46 31.46 31.46 31.46 31.46 31.46 31.46 31.46 31.46 8.88 8.88 8.88
1986 37.26 61.47 37.26 42.86 39.13 37.26 43.43 24.24 37.76 .49 .98 1.48
1987 38.88 61.48 39.38 43.23 39.!58 37.74 43.80 24,99 38. 14 .!58 1. 88 1. !58
1988 43.48 64.45 44.:54 46.:55 42.98 41.17 47.11 28.66 41. 4:5 .!51 1. 81 1. !52
1989 4!5.93 64.86 47.24 47.32 43.81 42.84 47.86 29.78 42.20 .!53 1. es 1. !58
1998 48.61 6:5.41 :58.17 48.22 44.78 43.84 48.75 31.82 43.08 .:5!5 1,89 1. 64
1991 51.!55 66. 12 :53.3:5 49.26 4:5.89 44.19 49.78 32.40 44. 10 .56 1.13 1.69
1992 :54.78 66.98 :56.88 58.45 47.1:5 45.48 !58.96 33.93 45.27 • 58 t. 17 1. 7!5
1993 !58.31 68.82 68.:55 !51.82 48.!58 46.94 52.32 3!5.61 46.60 .68 t. 28 1, 88 I a
1994 62.18 69.31 64.68 !53.42 :58.2!5 48.64 !53.91 37.:54 48.17 .62 1.24 1.87
199!5 66.42 78.84 69. 19 !55.26 52. 15 !58.!57 :5:5.74 39.68 49.97 ,64 1. 29 1. 93
1996 72.94 74.49 7:5.98 :59.22 :56.16 54.62 :59.69 73.73 !53.87 ·" 1. 33 1.99
1997 71.91 76.46 81.26 61.49 !58.49 56.98 61.95 7:5.72 !56.09 .68 1. 37 2.8!5
1998 98.4!5 93.69 181.98 79.82 76.88 74.68 79.47 92.97 73.:56 .78 1.41 2.11
1999 182.22 93.99 18:5.96 79.61 76.73 7!5.28 ee.es 93.29 74.08 .72 1. 44 2.16
2888 188.!54 96.61 112.48 82.!51 79.69 78.26 82.94 9!5. 92 76.91 .73 1. 47 2.28
2001 11:5.47 99.59 117.98 8!5.76 83.80 81.60 86.19 98,91 8&.0~ .7!5 t. 49 2.24
2882 123.88 182.96 128.99 89.48 86.69 8:5.32 89.82 182.29 83.64 .76 1. !51 2.27
2883 131.41 186.74 124.42 93.4:5 98.79 89.45 93.86 106.89 87.t:>0 .76 1.152 2.28
2804 148.:53 118.99 128.32 97.96 9!5.35 94.84 98.36 110.35 92.01 .76 1.!52 2.28
2e8!5 1!5e.S2 11!5.74 132.73 182.96 188.4e 99.11 183.315 115. 11 96.90 • 76 1 .151 2.27
2806 1:51.99 117.21 134.28 184.43 181. sa tee." 184.82 116.58 98.37 • 76 1.151 2.27
2887 1!51.96 117.18 134. 17 184.48 181.8:5 18e.S6 184.8e 116.55 98.34 • 76 1.151 2.27
2888 154.87 119.28 136.28 186." 1e3.95 182.66 186.98 118.6S 100.45 .76 1." 2.27
2889 1!54.84 119.25 136.25 186.48 183.92 182.63 186.87 118.63 100.42 .76 1. !51 2.27
2818 1!54.81 119.23 136.22 186.4!5 183.89 182.68 186.84 118.60 100.39 .76 1. !51 2.27
2811 1!53.98 119. 2e 136.19 186.42 183.86 182.!57 186.81 116.:57 100.36 .76 1. 51 2.27
2812 1!53.9!5 119.17 136. 16 186.39 183.83 182.!54 186.78 116.!54 100.33 .76 1.!51 2.27
2813 1 "· 79 122.8e 139.80 189.23 186.67 18!5.38 189.62 121.37 103.17 .76 1. 51 2.27 . . . . . . . . . . . . . ... . . . . .. . . . . .. . ..
2818 149.69 114.98 123.47 182.12 99.!57 98.28 182. 52 114.27 96.87 • 76 1. 51 2.27
2819 149.69 188.69 123.47 95.82 93.88 93.31 182.!52 114.27 9t:>.07 .76 1.51 2.27
2828 149.69 188.69 123.47 9!5.82 93.88 93.31 182.!52 114.27 96.67 .76 1 • !51 2.27
2821 149.69 89.35 89.3:5 89.3!5 89.3!5 89.3!5 89.35 89.3S 96.07 .76 1. 51 2.27 . . . . . . . . . . . . . . . . . . . . . . . . ... . ..
2e3S 149.69 89.3!5 89.3!5 89.35 89.35 89.3!5 89.3:5 89.35 96.07 .761 1. Sll 2.27
<t>Su Tabl• D-1
<2>S•• Tabl• J)-3 and E-l.Su• of hydro and r.uppl•••ntal diltt.el cot.tt..
<3>S•• Tabl• J)-3 and E-2.Su• of hydro and r.uppl•••ntal diltt.ltl cot.tt..
<4>S•• Tabl• D-3 and E-3.SuM of hydro and t.uppl•••ntal diltt.ltl cot.tt..
<5>S•• Tabl• J)-3 and E-4.SuM of hydro and t.uppl•••ntal d1•t.•1 cot.tt.. h <6>S•• Tabl• J)-3 and E-5.SuM of hydro and t.uppl••ental dfet.el c:ot.tt..
<7>S•• Tabllt J)-3 and E-6.Su• of hydro and t.uppl•••ntal diet.•l cot.tt..
<8>S•• Tabl• J)-3 and E-7.Su• of hydro and r.uppl•••ntal dl•t.•l cot.tt..
<9>S•• Tabl• D-3 and E-8.Su• of hydro and t.uppl•••ntal di•t.•l c:ot.tt..
<18>Pot•ntial t.avingt. fro• spac• hltating • 2!5% avoid•d cor.t.S•• Tabl• F-1.
<11)Pot•ntia1 saving& fro• r.pac• hlt&ting I 58% avoidltd cor.t.S•• Tabl• F-1.
(12>Potential r.avingt. fro• t.pac:• h•ating I 75% avotd•d cot.t.S•• Tabl• F-1.
TABLE 111-tS
ALASKA POWER AUTHORITY
FINANCIAL ANALYSIS SUMMARY FOR SCAMMON BAY HYDROELECTRIC PROJECT
UNIT COSTS OF ENERGY:W/0 REAL FUEL ESCALATION
JUNE t984
tee% REVENUE REVENUE BONDS AND STATE LOANS STATE
BONDS STATE GRANTS EQUITY SAYINGS FROM ENERGY
---------------------------------------------------------------------------SALES TO SPACE HEATING
YEAR I BASE 1-A 1-B II-A 11-B 11-C lil-A 111-B IY 2:5% :59% 17:5%
CASE tee:.: tee:.: :59)1/:59% 49%/69% 3:5V65% ·----
<c /kWh> <c/kWh> (C/kWh> (C/kWh) (c/kWh> <c/kWh> (C/kWh) <c/kWh> (C/kWh) <C•nta/kWh> <C•nta/kWh> <C•nta/kWh>
< t) <2> (3) (4) <5> <6) <7> (8) (9) <19> < 11) <12> ---------------------------- -------
--------------------------------------------------------------------
1983 28.69 28.69 28.69 28.69 28.69 28.69 28.69 28.69 28.69 e.ee e.ee e.ee
t984 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 29.98 e.ee e.ee e.ee
t985 31.46 3t. 46 3t.46 31.46 3t.46 3t.46 31.46 3t.46 31.46 e.ee e.ee e.ee
1986 37.26 6t.47 37.26 42.86 39.t3 37.26 43.43 24.24 37.76 .49 • 98 1.48
1987 38.88 61.48 39.38 43.23 39.58 37.74 43.89 24.99 38. t4 .59 1.ee 1.59
1988 43.48 64.45 44.54 46.55 42.98 41. t7 47. tt 28.66 41.45 .51 1. 91 1. 52
1989 45.39 64.57 46.95 47.93 43.52 4t. 75 47.57 29.49 41. 9t .51 1.92 1.53
t999 47.25 64.78 49.54 47.59 44.15 42.41 48. t2 39.39 42.45 ,52 1.93 1.55
1991 49.36 65.99 52.32 48.23 44.86 43. 16 48.75 3t.37 43.98 .52 1.94 1.56
1992 51.62 65.59 55.32 48.97 45.67 44.99 49.48 32.44 43.79 .52 1. 94 1.57
1993 54.94 66.92 58.55 49.81 46.57 44.93 59.3t 33.6t 44.69 ,52 1.95 1, 571 I
t994 56.65 66.79 62.97 59.81 47.63 46.93 51.30 34.92 45.56 .53 1.9:5 1.58
1995 59.44 67.52 65.87 51.94 48.83 47.26 52.42 36.37 46.65 ,53 1.96 1.59
1996 64.33 79.36 7t.86 55.99 52.94 59.59 55.56 69.6t 49.75 .:53 1.96 1.69
1997 67.50 71.42 76.22 56.45 53.45 51.94 56.9t 70.68 5t.05 .53 1. 97 1.69
1998 85.89 87.69 95.89 72.93 69.99 68.51 73.38 86.88 67.47 .53 1. 96 1.69
1999 87.28 86.71 98.68 72.32 69.45 67.99 72.77 86.et 66.80 ,53 1. 96 1.59
2900 99.93 87.98 t93.84 73.87 71.95 69.63 74.3t 87.29 68.28 .53 1.95 1.58
200t 94.86 89.43 t07.82 75.69 72.83 71.44 76.02 88.75 69.92 ,52 1.94 1.56
2902 99.98 9t.e6 199.99 77.59 74.79 73.42 77.92 99.40 7t.74 .51 1.92 1.54
2993 193.62 92.90 119.57 79.69 76.94 75.60 8e.et 92.24 73.75 .59 1.ee 1.59
2994 198.49 94.94 tt2.27 81. 9t 79.30 77.99 82.31 94.30 75.96 .49 ,98 1. 46
2995 113.7t 97.2t 114.29 84.43 8t.87 89.58 84.82 96.58 78.37 .47 .94 1.42
2996 115.t8 98.68 115.67 85.90 83.35 82.96 86.30 98.95 79.84 .47 • 94 1.42
2997 115.16 98.65 115.64 85.87 83.32 82.93 86.27 98.92 79.82 .47 .94 1.42
2908 tt7.26 199.75 117.75 87.98 85.42 84.13 88.37 199.13 81.92 .47 • 94 1.42
2909 tt7.23 199.73 117.72 87.95 85.39 84.19 88.34 190.t0 8t.89 .47 • 94 1. 42
20te 117.29 tee.7e tt7.69 87.92 85.36 84.97 88.3t 199.97 81.86 .47 • 94 1. 42
2911 117.17 199.67 117.66 87.89 85.33 84.94 88.28 190.04 8t.83 .47 • 94 1.42
2912 117.t4 199.64 117.63 87.86 85.39 84.91 88.25 100.91 8t.80 .47 • 94 1.42
2913 119.98 193.47 129.47 99.79 88.14 86.85 91.99 102.85 84.64 .47 • 94 1.42 . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... . .. . ..
2918 112.88 96.37 194.94 83.59 81.94 79.75 83.99 95.74 77.54 .47 • 94 1. 42
2919 112.88 82.16 194.94 76.49 75.35 74.78 83.99 95.74 77.54 .47 .94 1. 42
2929 112.88 82.16 194.94 76.49 75.35 74.78 83.99 95.74 77.54 .47 .94 1.42
2921 112.88 79.82 79.82 79.82 79.82 79.82 79.82 79.82 77.54 .47 .94 1. 42 . . . . . . . . . . . . .. . . . . . . . .. . . . ... . ..
2935 112.88 79.82 79.82 79.82 79.82 79.82 79.82 79.82 77.54 .471 .941 1. 42
<1>Su Tabl• D-2
<2>S•• Tabl• D-4 and E-1.Sua or hydro and auppl•••nlal d1•a•1 coata.
<3>S•• Tabl• D-4 and E-2.Sua or hydro and auppl•••nlal di•a•l coat a.
<4>S•• Tabl• D-4 and E-3.Sua or hydro and auppl•••nlal di•a•l coata.
<5>S•• Tabl• D-4 and E-4.Sua or hydro and auppl•••nlal di•a•l coata.
<6>S•• Tabl• D-4 and E-5.Sua or hydro and auppl•••nlal di•a•l coata.
<7>S•• Tabl• D-4 and E-6.Sua or hydro and auppl•••nlal di•a•l coata. ~ <8>S•• Tabl• D-4 and E-7.Sua or hydro and auppl•••nlal di•a•l coat~.
<9>S•• Tabl• D-4 and E-8.Sua or hydro and auppl•••nlal di•a•l coat~.
<19>Pot•ntia1 aavinga rroa apac• h•ating I 25% avoid•d coat.S•• Tabl• F-1.
<11>Pot•ntia1 aavinga rroa apac• h•ating I 50% avoid•d coat.S•• Tabl• F-1,
<12>Pot•ntia1 aavinga rroa apac• h•ating I 75% avoid•d coat.S•• Tabl• F-1.
TABLE II I-ll
ALASKA POWER AUTHORITY
SCAMMON BAY HYDROELECTRIC PROJECT
SCHEDULE OF INVESTMENTS
DIESEL GENERATION
Cost
Year Replacements Additions ($1,000)
1986 175 KW 77.2
1986 Fuel Storage 64.3
1988 175 KW 87.5
1996 175 KW 144.9
1998 Fuel Storage 410.9
1998 300 KW 273.9
1998 175 KW 164.3
2006 175 KW 255.4
2008 175 KW 255.4
2013 300 KW 425.6
2016 175 KW 255.4
2018 175 KW 255.4
2026 175 KW 255.4
2028 175 KW 255.4
2028 300 KW 425.6
SF:IEB:AD1:4-III-2
160
1:50
140
130
120
,...
.c 110
3:
.::{.
'\. 100
tn
f-z 90 w u
'"" 90 f-
tn
0 u 70
>-
l.7 60 a::: w z 50 w
40
30
! I
I
I /A
,;t v r I
I
I . "'
20
10
!'sea 1990
,....r-h
I ~BASE CASE
I
II
J ~ ~~
f r 'l
'"~\ I
~ HY9~S AL TE~~ HYD ALTER ATIVE: I ATIVE I I-A -A
~ w ~?~~ g ~+~~~ ~H~~ i -J::t
HYDR ALTER~ ATIVE I -c
I
2000 2010
YEAR
2020 2030
l
1
I
2040
1. Costs shown include general inflation and real fuel escalation.
2. Alternative II-A is 50% tax-exempt revenue bonds and 50% state grants.
3. Alternative II-B is 40% tax-exempt revenue bonds and 60% state grant.
4. Alternative 11-C is 43.1% tax-exempt revenue bonds and 56.9% state grant.
5. Alternative III-A is State Loan at 5%.
6. Alternative IV is State Equity Financing with 5% return.
7. All hydro alternatives include cost of supplemental diesel and adjustment
for energy sold to cannery.·
ALASKA POWER AUTHORITY
SCAMMON BAY HYDROELECTRIC PROJECT
W/ FUEL ESCALATION,W/ SPACE HEATING
HEATING CREDIT @ 50% AVOIDED COST
FIGURE
III-1
168 t----t----!----f----1------1-----1
158 t-----t---t---r~=------~~\------4--!-----+-' -~ I '\.._BASE CASE
148 j---t---t-+--t---+---+----1
I r-~
139 r-----t----+-H II /---1---+l-+----+--~
1291----t----h~VV __ ~--~~---+-----1 ~ ' r r'r-f -~ 118!-----l--~~+--1-----~~---+-----1 ~ 1--!.......--f----¥-J~I-tr--'---1-n-...:t:,Lll-· --+---l' ~ _.r ~~I
~ 98r----r--~rvt---r---~====~==~~l
....,.
1-
(J)
0 u
>-~
et:: w z w
28t-----r---r---r---r----t---~
t'sa0 1999 2010
YEAR
2020 2840
1. Costs shown include general inflation and real fuel escalation.
2. Alternative I-A is 100% tax-exempt revenue bonds.
3. Alternative I-B is 100% tax-exempt revenue bonds with graduated repayment
schedule.
4. Alternative III-A is State Loan, 35 years at 5%.
5. Alternative 111-B is State Loan at 5% with payments deferred for
10 years.
6. All hydro alternatives include cost of supplemental diesel and adjustment
for energy sold to space heat1ng.
ALASKA POWER AUTHORITY
SCAMMON BAY HYDROELECTRIC PROJECT
W/ FUEL ESCALATION,W/ SPACE HEATING
HEATING CREDIT I 50% AVOIDED COST
F"IGURE
III-2
118
118
148
118
118
.....
.&: 118
X
~
' liB
UJ
1-z 18 w
(.) ..... 18 1-
UJ
0 78 (.)
>-l7 88 a:: w z 58 w
48
88
_,...r ..r-"\ ~FlJEl.. £SC ALATION
I
I BASE CASE
/
11 r -/ \ H/0 FlJ£1.. E j;CRLATION
L /~ ~
1/ !\ H/ FlJEL [SCALRTI Qll
/ v~ f-./ \_
I '("' v 1\ H/0 F"UEL ,..... ~Al..RTidN
I! HYDR 0 ALTERt-RTIVE Il I-A
7£/;
,1/ p
f ..
28
18
Plea 1888 2188 28UIJ
YEAR
21128 2838 2848
1. Costs shown include general inflation.
2. Costs shown with and without real fuel escalation.
3. Hydro Alternative III-A is State Loan, 35 years at 5%.
4. Hydro alternative includes cost of supplemental diesel and adjustment for
energy so 1 d to space heating.
ALASKA POWER AUTHORITY
SCAMMON BAY HYDROELECTRIC PROJECT
W/ AND W/0 rUEL ESCALATION
HEATING CREDIT 8 50~ AVOIDED COST
F"IGURE
III-3
.r:.
3::
.:t.
" (J)
1-z w u
1-
(J)
0 u
>-
l:J
~ w z w
1s0r-----r-----r-----+-----+-----4-----~
1:'!0 r---t----+--F-,..r--+n-\--..\..-l----1..-______.j' I 1 '-sAs . cAsE ,i
1
1
1
1~0r-----r-----+-~--+-----+-----4-----~
130 r-----r----++/-+1 -+--+------!
120 r-----t--++1//----1:----+----+------l
_,.-H;' SF~E HERTUG CREDIT II
uer' -----r-----t-----ti/~~f-----~----~
I. / ~;_t.,/ \ I ! Y1r i \= I i 1::~· =====;===~=;~)'=::\:;====:~\:::::::::==~! 80 ~----r---~~~~~---~+-~H~...-o~~S~~AC~E~H~E~RT~~·~ING~C~R~ED~I~T~
1 1. r 'HYDRP ALTERNfiTlVE ~~~-A ·
70! / ' l
serl -----r~-~~~+-----T-----4-----~----~~
ser----···~ ~~~~~---+,-----+-----+~----~----~~
40r--T~T-/r-----+-----+-----4-----~----~· If 30 I 7
2er-----r-----+-----+-----4-----4-----~
i'se0 1990 2000 2910
YEAR
I
2020 2030 2040
1. Costs shown include general inflation and real fuel escalation.
2. Hydro Alternative III-A is State Loan, 35 years at 5%.
3. Hydro alternative includes cost of supplemental diesel.
4. Hydro alternative shown with and without adjustment for energy sold to
space heating.
ALASKA POWER AUTHORITY
SCAMMON BAY HYDROELECTRIC
W/ FUEL ESCALATION
W/ & W/0 HEATING CREDIT @
PROJECT
FIGURE
III-4
50% AVOIDED COST
SF:IEB:A01:4-C
APPENDIX A
EBASCO COST ESTIMATE ~
' ' .
EBASCO SERVICES INCORPORATED
400 112th Avenue NE. Bellevue. WA 98004. (206) 451-4500
Alaska Power Authority
334 West Fifth Avenue
Anchorage, Alaska 99501
Attention: Remy Williams
June 23, 1982
' ....
' '
• • •. t r~ ·. • t 1~ 1
. ;w .. -'{
SUBJECT: SCAMMON BAY HYDRO PROJECT COST ESTIMATE
Dear Mr. Williams:
Ebasco Services Incorporated is pleased to present a second op1n1on feasi-
bility level construction cost estimate (June 1982 level) for the proposed
Scammon Bay Hydroelectric Project located at Scammon Bay, about 230 miles
south of Nome, Alaska. This cost estimate was accomplished under the pro-
posed Amendment No. 14 to our professional services agreement #081740 (dated
March 10, 1981). Our scope of work also included a spot check of major cost·
quantities presented by the U.S. Army Corps of ~ngineers (USCOE).
Our feasibility level cost estimate (June 1982 level) for the Scammon Bay
Hydro Project is $1,500,500. This second opinion estimate was based on
USCOE project drawings and preliminary construction cost estimate quan-
tities, USGS topographic maps of the project area, and Ebasco experience.
A site trip was not performed. The 11 0vernight 11 construction cost estimate
includes contingencies, but does not include professional services, owner's
overhead or interest and escalation during construction.
A project description, project cost summary, detailed cost estimate, and
basis of cost estimate are attached to provide details of how Ebasco's
cost estimate was developed. If you have any questions, please contact
me at (206) 451-4593.
Very truly yours,
~~~
Project Manager
RAZ:dd
Enclosures: As noted ,------------·
... 0 ~ ... ( ,-.-.· -.. • : 1 • ': ' .
'·{ f<· . ' . I -~ . .
.t l. .; .. '. . :.. ..._' t ..
---$. ... ---
1':\LI'\.)IV'\ rUWC.l\ "UiflUI\~ II
SCAMMON BAY HED 100 leW
PROJECT DESCRIPTION
Genera 1 .:. ;
·~, ,Ibe ]J:Oposed plan. for hydropower development at Scamnon Bay, loca~d
in the Yukon-Kuskokwim Delta region of southwestern··AlaSka {230 mi 1 es stuth
of Nome), is a run-of-the-river diversion project which has a capacity of
100 kW. The project consists of a 50-foot-wide rockfilled gabion dam with
its crest at 600 feet elevation, 3,500 feet of 12-inch buried steel pen~
stock, and a 10 x 11 foot powerhouse with one 100-kW rated impulse turb~ne
unit. ~
This system would provide most of Scammon Bay's current energy needs
for approximately 7 months of the year. In late fall it would be necessary
to supplement it with diesel. For approximately 5 month of the year it
would be shut down due to inadequate streamflow.
The system could generate an average of approximately 409,000 kWh of
an electricity annually.
Basin Description
The three-quarter-square-mile drainage basin varies in elevation from
600 feet at the damsite to almost 1,300 feet at·the highest point. Upstream
of the damsite, the basin is covered with wet, spongy tundra, which has a
tendency to retain water and release it over a period of time.
Dam, Spillway, and Intake
The dam will be constructed of rockfilled gabions arranged around a
cutoff wall that extends into bedrock. This cutoff wall will be constructed
of sackcrete and extend approximately 9 feet below the existing ground sur-
face and about 4 feet below the gabions.
The dam will have a crest length of 50 feet and a maximum height from
bedrock of 15 feet. The height above existing ground will be approximately
7 to 8 feet. The nonoverflow section of this gravity structure will have
a top elevation of 600 feet. The ungated weir overflow section will have
a total length of 13.5 feet at elevation 598 and overflow from the weir
will enter the existing streambed. The dam will consist of one row of
standard manufactured galvanized steel gabions on the upstream side of the
cutoff wall and two rows on the downstream side. These will be set down
into the existing streambed, then filled with rocks taken from the reser-
voir excavation and the nearby area.
The intake structure will be a square, metal dropbox set vertically
on the right bank. A French drain system will run from the left side of
the intake to the left abutment. The French drain will consist of clean
gravel which will allow flows to enter a perforated pipe in the drain and
be carried through the dam via a metal pipe. A blind flange will be
mounted on the drain pipe inside the intake structure to allow access for
maintenance and entrance of low flows to supplement power production. A
gate valve will be mounted on the drain pipe inside the intake structure
to allow regulation of flow through the dam. A 2 X 2.5-foot trashrack
will be mounted in the side of the intake structure below the elevation of
-2-
the overflow section. A movable bulkhead will be mounted above the trash-
rack intake. This will be lowered to dewater the intake or to shutoff the
intake during winter shutdown. The grating of the trashrack will be ~
coated with a hydrophobic fluorocarbon to reduce icing. A USGS-style~
gage house will be placed on top of the intake structure to keep it frt
~ --~saow~nd~to_.llo~ccess during periods of deep-snow. A ladde~_wil ___._
be installed inside the structure to allow access to the valves and in~ ru-
mentation that will be located inside the structure.
Flushing System
The intake structure will not have a flushing system because of its
small size. The reservoir bottom will be sloped away from the intake
toward the center of the small excavated reservoir to prevent rocks and
other debris from accumulating around the intake. If excessive material
does build up in the channel, the reservoir could be drawn down and the
material removed by hand or with a small tractor.
Penstock
The penstock will be buried throughout its length. It will run within
the confines of the ravine through which the stream flows. The streambed
is generally a composition of gravel, cobbles, and boulders that varies
from 6 to 20 feed in depth with some outcrops of:bedrock. The goundline
along the stream bottom has an average slope of 13.5 percent. The penstock
will cross from the right bank to the left bank of the stream about 550
feet downstream of the dam. The vegetation cover in the streambed is
minimal.
The penstock will be a 12-inch inside diameter steel pipe extending
3,500 feet from the intake invert at El. 589 (11 feet below the top of the
dam) to the powerhouse at El. 110 feet. The project gross head is 488
feet. A 12-inch diameter manually operated gate valve in the intake struc-
ture will allow the penstock to be drained during winter low-flow condi-
tions and during maintenance. A 1-7/8-inch diameter air vent will extend
from the penstock immediately downstream of the gate valve up through the
gatehouse to open atmosphere. A screen will cover the upstream end of the
gate valve to insure that no small objects are drawn into the penstock.
The penstock will be designed for a minimum working pressure of 440
psi with a minimum wall thickness of 0.172 inches. The penstock will be
completely encased in select bedding material to insure against point
loading that could develop with boulders and bedrock.
In periods of cold weather when frazil ice begins to form in the
stream, the downstream valve at the powerhouse will remain open until the
penstock was completely drained. Penstock drainage will be accomplished by
closing the upstream valve to the penstock and allowing the water to drain
by deflecting the water away from the buckets of the impuls~ turbine. This
was determined to be the safest and most cost effective method to avoid
penstock freezing. Insulation of the penstock was considered, but would
on1y delay the freeze-up for a few hours at a significantly greater cost.
I ~
:
-3-
Powerhouse
The 100-kW unit will have all equipment housed in a 10 x 11 foot~
prefabricated, insulated, weather tight, steel structure, built on a 1
'-
!---..,_...,._.._..,...JZ,-..:iw;b ;:oo.crete slab. The. RQwerhouse will...be located at_.ilevation l.lct
the finished floor elevation would be at-reast !"feet above the-maxfmum'
tailwater level. An open channel tailrace will be excavated below the
powerhouse.
Ventilation will be provided by a wall mounted fan. Two fire '·.r
extinguishers will provide fire protection to the building. A weather ·
tight, roll-up door will allow access for equipment installation. A 5-ton
underhung crane· will be installed for equipment handling.
Turbine, Generator, and Electrical Equipment
The hydroelectric power generation equipment will be procured as a
package unit. It will consist of one impulse turbine, a synchronous
generator. governor system, voltage regulator, and protective and control
devices. Units of this type are available from industry, either as
pre-engineered standard or custom designs, covering a wide range of heads
and flows, connected loads, and operating conditions. In addition to
being economical and simplifying installation, package unit procurement
reduces the number of supply con~racts from three or four to only one.
The 100-kW turbine will be a "standardized" horizontal axis impulse
or Turgo impulse turbine with one or two adjustable nozzles. The nozzles
will be actuated by servomotors controlled by the governor. Jet deflectors
will be used for diversion of water from the runner for rapid load change,
load rejection, or penstock draining. A cylinder actuated butterfly valve
in the penstock will be provided for shutoff of the water. The unit will
be specified to produce power over a range of 15 to 100 kW when operating
at 430 feet net head. The expected discharge from the turbine at maximum
power is estimated to be 3.4 cfs, and 0.63 cfs at minimum power (15 kW).
A flywheel will be provided, if necessary, to limit speed excursions during
load changes. The turbine will drive a generator through V-belts and a
parallel shaft gearbox, or through a direct connection to the generator.
The choice of the operating speed and power transmission system will be
left to the manufacturer.
The governor system will be furnished as an integral part of the
turbine-generator package unit. The governor system will be composed of
electronic speed sensitive elements (frequency transducer, controller. and
amplifier). a servo system consisting of either electric motor and gears
or hydraulic pump and electric motor, and the necessary controls. Respond-
ing to fluctuations in power demand, the governor will actuate the needle
valve in the water supply line, control the amount of water supplied to the
turbine and regulate the speed of the unit. The governor size and character-
istics (capacity ~nd speed regulation) will be determined 0y the manufacturer,
based on head, WR , speed, and power of the un1t. .
I
... ::-
-4-
The synchronous generator will be provided as part of the package
unit. The generator, which should be provided with special bearing and
lubricants suitable for peration in extended low temperatures, will be ~
rated single phase, 60Hz. 100 kW (125 kVA@ 0.8 pf), 120/240 volts wfth
full Class F thermal capacity (Class 8 temperature rise) and be capabl~ of == ··~~ou~~Ktion at 110 percent overload and + &-pereent· of-rated~lt
age. The generator will be equipped with a brushless, full wave rotating
rectifier excitation system and a saturable transformer type automatic ·
voltage regulator with a response time of 200 milliseconds, capable of·
regulation of one percent from no-load to full-load. The generator wil)
also be furnished with a control and protection equipment group. This con-
sists of a circuit breaker (with shunt-coil type, under-and-over voltage
relays, overcur.rent relay, stator thermal relay, instantaneous ground relay,
reclosing relay, and lockout device), an ammeter, watt-hour meter, watt-meter,
volt-meter, frequency meters, and indicator lights for manual synchroniza-
tion. In order to prevent moisture build-up, it may be necessary to partially
energize the system during winter shut-down.
The generator bus will be tapped between the generator circuit breaker
and the step-up transformer to provide three-wire, single phase 120/240
volts to a lighting distribution panel for service station lighting, con-
venience outlets, a ventilating fan, and other miscellaneous loads.
The main power transformer will be single phase, 120/240 volt primary,
12,470/7200 volt secondary, 15 kV class, dry type, and ventilated. It will
be floor mounted in the powerhouse. ·
The generator, excitation, breaker, and turbine controls will be
mounted on the governor equipment cabinet. Controls will be included to
manually synchronize the excited unit to the line. Metering will be pro-
vided for volts, amps, vars and watts. The generators will be provided
with voltage restraint overcurrent and overvoltage relays. Underfrequency
and overfrequency protection of customer equipment will be provided with
speed switches and some form of automatic time error control will be
considered.
Transmission System
The electrical connection to the existing distribution system will be
by 15 kV, No. 2 AWG aluminum conductor on wood poles from the wall-mounted
weatherhead fitting at the powerhouse to the existing 7.2 kV primary cable
in the surfact-mounted duct bank. Rigid steel conduit will be used to run
the cable from the terminal pole to a pad mounted terminal cabinet installed
in the duct bank.
.
I -· EBASCO SERVICES INCORPORATED
ESTIMATE OF COST 2 SHEETS NO. 1 ---
PREPARED TBU/CYH SCAMMON BAY PLACE LYNDHURST
CHECKED -=..JVM.;..::..:.. ___ _ PROJECT 100 KW DATE JUNE, 1982~
' ~r•n••-~-~~~~~~-~~~~-~~~~,-~~~S~O~P~O~W~R~A~~~~O~RI~TY~-~N0,~17~-~-~
CLIENT COMPANY 1"
DESCRIPTION
Mop & Prep Work
Lands & Damages
Administrative Costs
Lands
Dam, Sill & Reservior
Excavation
Sackcrete
Reinforcement
Gab ion
Rock
Backfill
Drain pipe 1r' 0
French Drain
Subtotal
UNIT
LS
LS
LS
CY
CY
LB
EA
CY
CY
LF
CY
QUANTITY
1
1
1
230J/
54J/
2, 70oJi
216
144
18
90
28.i/
UNIT
COST
21.30
1,774.07
2.52
35.65
189.58
38.89
26.67
185.71
10.21
TOTAL
1,000*
5,000*
4,900
95,800
6,800
7,700
27,300
700
2,400
5,200
150,800
•
Intake Structure
Steel Intake
Bulkhead Gate
Trashrack
Transducer
Manometer
LB
LS
LB
1, 224' 12,500
10,100
1,200
1,200
600
,_ ,.
Sluice Gate 12" 0
Insulated Structure
Subtotal
Penstock
Steel (12" 0 0. 17 2" thick)
Ring Stiffeners Expansion
Anchors, Anchor Supports
Concrete Anchor and Thrust
Blocks
Excavation
Backfill
Subtotal
Powerhouse
Structure
Turbines & Generators
Auxiliary Systems
Switchyard & Distribution System
Connection
Subtotal
Allow
Allow
EA
EA
LB
LB
LS
CY
CY
CY
LS
LS
LS
LS
100
2
1
J.l 80.820
4,900
12.00
2,950.00
6,400.00
4.02
• 92
2,296.67
20.52
36.15
* COE Estimated Amount J/ Quantities increased by Ebasco
5,900
6,400
37,900
324,900
4,500
30,200
68,900
43,100
72,300
543,900
44,300
173,000
51,500
62,200
331,000
' ..
•
PREPARED TBU/CYll
APPROVED V AM
Tailrace
Excavation
Riprap
Subtotal
Subtotal
DESCRIPTION
!.BASCO SERVICES INCORPORATED
· ESTIMATE OF COST
SCAMMON BAY
PROJECT 100 KW
ALASKA POWER AUTHORITY
UNIT QUANTITY
CY
CY
45
15
20 Percent Contingencies
Contract Cost
__ .:.2-~SBEETS N0 •. _2;;;...__
PLACE LYNDHURST
DATE JUNE, 1982 ·.
EST NO. APA 1727
UNIT
COST
22.22
53.33
~
TOTAL
1,000
800
1,800
1.250,400
250,100
1,500,500
\
• I •
\
ALASKA POWER AUTHORITY
SCAMMON BAY HED
100 KW . ,.
BASIS OF ESTIMATE
~
l
......... ~ ~,-.__.._., • ...--liC ..._,...., PIJ& ... J '-~ l """"""'• E I -~ a w ... J
General
This feasibility level Preliminary Project Estimate, prepared in the same
format as used by the Corps Engineers in section T-11 of the Technical ,
Analysis Report is based on the following: X
(a) The follow,,ing U.S. Army Corps of Engineers drawings 1Pxl7 11 were used
as pricing reference documents:
FIGURE NUMBER
1
2
3
4
5
DESCRIPTION
Location and Vicinity Map
General Plan
Dam and Intake Structure Plan,
Evaluation & Detail
Dam and Intake Structural Sections
Powerhouse Transverse Section & Plan
(b) Pricing Level of June, 1982 with no allowance to reflect construction
milestone dates.
(c) Section T-Technical Analysis of the Scammon Bay Hydro Project feasibility
study prepared by the U.S. Army Corps of Engineers.
(d) Wage rates applicable to Anchorage Union Agreements south of 63°
latitude, including costs for Workmen's Compensation and Public Lia-
bility and Property Damage insurance rates.
(e) Preliminary quantities of dam excavationsackcrete.penstock pipe, penstock
excavation, dam rockfill and dam backfill as submitted to Ebasco in the
Corp's format in section T-11 of the Technical Analysis have been checked
and revised as necessary.
(f) All construction labor to be performed on a Contract Basis.
(g) Insufficient craftsmen available locally to meet project requirements,
therefore construction crews are estimated as being housed in a labor
camp.
(h) Professional Services including Engineering, Design and Construction
Management are not included.
(i) Client costs, except for land and land rights not included. Admini-
strative and land costs as estimated by the USCOE were,used.
(j)
(k)
(1)
Interest during construction not included~
Contingency included at the rate of 20% based on the preliminary status
of drawings and other project requirements.
Unit costs are shown but due to the magnitude of the quantities entailed,
quantity changes may not be priced using the unit prices shown.
. . . ~. .. .BASIS OF ESTIMATE -2-6/23/82
(m) For construction of the dam and intake structure no access road is
required. Construction materials will be transported by Crawler
mounted Backhoe along the penstock alignment. . . .
~
.Freight costs are based on Foss Alaska line for Scheduled Barge f~m
~~~--------!~!~~~~"le-.,~wA-to Bethel, AK and via United Tran~~of ietbel~r -t-
Charter Barge from Bethel to Scammon Bay. ·
(n)
Civil
No rock excavation is assumed. Concrete is priced as pre-mixed in bags.
Pipe quotes were obtained from USS, BBL Co., and Foster. Pipe coupling
prices were quoted by Dresser. Powerhouse building and USGS gage house
prices were quoted by HAP Dealers for Soule Building, Anchorage, AK.
Gabions prices were quoted by Terra AQUA Conservation of Reno, Nevada.
Mechanical
Two preliminary quotes for the turbine-generator were obtained, one from
G.E. Turbine Division, Portland, Oregon and the other from Leffey Hydro
Energy, Springfield, Ohio. Other mechanical equipment, instruments and
controls are included as a conceptual allowance.
Electrical
An Auxiliary System lump sum allowance was based on a 125 KVA, single phase
Transformer 120/240 V primary -12,470/7200 Vsecondary,Ory Type. It will be
installed inside the powerhouse.
A Switchyard and Distribution System Connection allowance was based on 40 1
H Wood Pole, REA type with a span of 150 feet. The overhead conductor
cable used is No. 2 AWG, ACSR.
Indirects
The cost of the required construction camp and other indirects are included
in the individual work items.
• ••
SF:IEB:AD1:4-C
APPENDIX B
ALASKA POWER AUTHORITY
ANALYSIS PARAMETERS
SUMMARY OF RECO~~ENDATIONS
Analysis Parameters for the 1984 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 -6.5~
Project Debt to Equity Ratio -1:0
Cost of Debt.-10~
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! "'l e>
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 w/ Wood Poles
Transmission Lines w/ Steel Towers
Submarine Cables
Oi 1 Filled
Solid Dielectric
10 years
10 years
20 years
15 years
1t"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.
9204/020
SF:IEB:AD1:4-C
APPENDIX C
ECONOMIC ANALYSIS
UPDATE
:•
TABLE C-1
ALASKA POWER AUTHORITY
ECONOMIC ANALYSIS
SCAMMON BAY HYDROELECTRIC PROJECT:IASE CASE
JUNE 1984
YEAR FIRM VILLAGE FIXED VARIABLE FUEL OIL FUEL OIL TOTAL PRESENT
CAPACITY ENERGY COST COST UNIT COST COST COST WORTH
DEMAND
< k W) <MWh> ($) ($) ($/GAU ($) ($) ($)
(1) (2) (3) (4) (5) (6)
------------------------ -----------------------------------------
1983 180 449.88 24100 38240 1. 56 73106 135447 0
1984 180 458.88 23980 39005 1. 56 74568 137553 0
1985 180 468.06 23857 39785 1. 56 76060 139702 0
1986 180 477.42 95618 40581 1. 56 77581 213779 206550
1987 180 486.97 95490 41392 1. 56 79133 216015 201652
1988 280 496.71 133261 42220 1. 56 80715 256197 231075
1989 280 506.64 133128 43065 1. 61 84799 260992 227440
1990 280 516.78 132992 43926 1.66 89090 266009 223972
1991 280 527. 11 132854 44805 1.70 93598 271257 220668
1992 175 537.65 132713 45701 1. 76 98334 276748 217521
1993 175 548.41 132569 46615 1. 81 103310 282493 214529
1994 175 559.38 132422 47547 1. 86 108538 288506 211686
1995 175 570.56 132272 48498 1. 92 114030 294799 208989
1996 175 581.97 132119 49468 1. 98 119799 301386 206433
1997 175 593.61 131963 50457 2.04 125861 308282 204016
1998 350 605.49 289586 51466 2. 10 132230 473282 302619
1999 350 617.60 277374 52496 2.16 138921 468790 289610
2000 350 629.95 277208 53546 2.22 145950 476704 284540
2001 350 642.55 277040 54616 2.29 153335 484991 279697
2002 350 655.40 276867 55709 2.36 161094 493670 275075
2003 350 668.51 276692 56823 2.43 169245 502760 270667
2004 350 681.88 276513 57959 2.50 177809 512281 266466
2005 350 695.51 276330 59119 2.58 186806 522255 262468
2006 350 695.51 242159 59119 2.58 186806 488084 ·236999
2007 350 695.51 241969 59119 2.58 186806 487894 228896
2008 350 695.51 241775 59119 2.58 186806 487700 221068
2009 350 695.51 241578 59119 2.58 186806 487503 213505
2010 350 695.51 241376 59119 2.58 186806 487301 206200
2011 350 695.51 241170 59119 2.58 186806 487095 199143
2012 350 695.51 240960 59119 2.58 186806 486885 192326
2013 350 695.51 240746 59119 2.58 186806 486671 185740
2014 350 695.51 240528 59119 2.58 186806 486453 179379
2015 350 695.51 240306 59119 2.58 186806 486230 173233
2016 350 695.51 240078 59119 2.58 186806 486003 167297
2017 350 695.51 239847 59119 2.58 186806 485772 161563
2018 350 695.51 137657 59119 2.58 186806 383582 123261
2031 350 695.51 137657 59119 2.58 186806 383582 7881"4
2032 350 695.51 137657 59119 2.58 186806 383582 76149
2033 350 695.51 137657 59119 2.58 186806 383582 73573
2034 350 695.51 137657 59119 2.58 186806 383582 71085
2035 350 695.51 137657 59119 2.58 186806 383582 68682
TOTAL 8,853,698,
!.
TABLE C-2
t ALASKA POWER AUTHORITY
ECONOMIC ANALYSIS
SCAMMON BAY HYDROELECTRIC PROJECT:SUPPLEMENTAL DIESEL
JUNE 1984
YEAR FIRM VILLAGE FIXED VARIABLE FUEL OIL FUEL OIL TOTAL PRESENT
CAPACITY ENERGY COST COST UNIT COST COST COST WORTH
DEMAND
<kW> <MWh) ($) ($) ($/GAL) ($) ($) ($)
(1) (2) (3) (4) (5) (6) ----------------__ , ______ ------------------------- ----------------
1983 18121 449.88 24100 38240 1. 56 7311216 135447 0
1984 180 458.88 23980 39005 1. 56 74568 137553 0
1985 180 468.06 23857 39785 1. 56 76060 13971212 0
1986 180 477.42 95618 18604 1. 56 35566 149787 144722
1987 18121 486.97 95490 19048 1. 56 36415 15121952 140916
1988 280 496.71 133261 19501 1. 56 37281 190043 171408
1989 280 506.64 133128 19963 1. 61 39309 192400 167666
1990 280 516.78 132992 20434 1. 66 41445 194871 164076
1991 280 527. 11 132854 20915 1. 70 43692 197461 160635
1992 175 537.65 132713 2141215 1. 76 46058 20121176 157337
1993 175 548.41 132569 21906 1.81 48549 203023 154178
1994 175 559.38 132422 22474 1. 86 51303 206199 151295
1995 175 570.56 132272 23073 1. 92 5425121 21219595 148586
1996 175 581.97 132119 23684 1. 98 57357 213159 146003
1997 175 593.61 131963 24307 2.1214 60631 21691211 143541
1998 350 605.49 289586 24942 2. 1121 6412183 378611 242085
1999 350 617.60 277374 25590 2.16 67720 370684 22901212
21211210 35121 629.95 27721218 26251 2.22 71554 37512113 223842
201211 35121 642.55 277040 26926 2.29 75593 379558 218894
201212 350 655.40 276867 27613 2.36 79850 384331 21415121
212103 35121 668.51 276692 28315 2.43 84335 389342 21219606
2004 35121 681.88 276513 29030 2.50 89060 394603 205255
212105 35121 695.51 276330 29760 2.58 9412138 400129 201091
2006 35121 695.51 242159 29760 2.58 94038 365958 177698
2007 350 695.51 241969 2976121 2.58 94038 365768 171600
201218 35121 695.51 241775 29760 2.58 94038 365574 165709
21211219 350 695.51 241578 29760 2.58 94038 365376 16121019
2010 350 695.51 241376 29760 2.58 94038 365174 154522
2011 350 695.51 241170 29760 2.58 94038 364969 149213
2012 350 695.51 240960 29760 2.58 94038 364759 144084
2013 35121 695.51 24121746 29760 2.58 94038 364545 139130
2014 350 695.51 24121528 29760 2.58 94038 364327 134345
2015 350 695.51 240306 29760 2.58 94038 364104 129722
2016 350 695.51 240078 29760 2.58 94038 363877 125257
2017 350 695.51 239847 29760 2.58 9412138 363645 12121945
2018 350 695.51 137657 29760 2.58 94038 261455 8412117
2031 350 695.51 137657 29760 2.58 94038 261455 5372'1
2032 35121 695.51 137657 29760 2.58 94038 261455 51904
2033 350 695.51 137657 2976121 2.58 94038 261455 50149
2034 350 695.51 137657 29760 2.58 94038 261455 48453
2035 350 695.51 137657 29760 2.58 94038 261455 46814
TOTAL 6,513,473,
... -..>
TAflLE C-3
ALASKA POWER AUTHORITY
ECONOMIC ANALYSIS
SCAMMON BAY HYDROELECTRIC PROJECT:HYDROELECTRIC COSTS
JUNE 1984
YEAR CAPITAL DEBT OS.M REPLACE. REPLACE. ANNUAL PRESENT
COSTS SERVICE SCHEDULE SINKING COST WORTH
FUND
($) ($) ($) ($) ($) ($) ($)
------------------------------------ ------------------ ---------
1983 0 0 0 0 0 0 0
1984 0 0 0 0 0 0 0
1985 1500000 0 0 0 0 0 0
1986 0 63951 6000 0 1872 71823 62590
1987 0 63951 6000 0 1872 71823 60473
1988 0 63951 6000 0 1872 71823 58428
1989 0 63951 6000 0 1872 71823 56452
1990 0 63951 6000 0 1872 71823 54543
1991 0 63951 6000 0 1872 71823 52699
1992 0 63951 6000 0 1872 71823 50917
1993 0 63951 6000 0 1872 71823 49195
1994 0 63951 6000 0 1872 71823 47531
1995 0 63951 6000 0 1872 71823 45924
1996 0 63951 6000 0 1872 71823 44371
1997 0 63951 6000 0 1872 71823 42870
1998 0 63951 6000 0 1872 71823 41421
1999 0 63951 6000 0 1872 71823 40020
2000 0 63951 6000 0 1872 71823 38667
2001 0 63951 ! 6000 0 1872 71823 37359
2002 0 63951 6000 0 1872 71823 36096
2003 0 63951 6000 0 1872 71823 34875
2004 0 63951 6000 0 1872 71823 33696
2005 0 63951 6000 0 1872 71823 32556
2010 0 63951 6000 55000 1872 71823 27412
2015 0 63951 6000 632500 1872 71823 23080
2035 0 63951 6000 0 1872 71823 11599
TOTAL PRESENT WORTH: 1,519,460
TABLE C-4
ALASKA POWER AUTHORITY
SCAMMON BAY HYDROELECTRIC PROJECT
POTENTIAL SPACE HEATING CREDIT:ECONOMlC ANALYSIS
JUNE 1984
YEAR TOTAL
ELECTRICAL
DEMAND
HYDRO
AVAILABLE
FOR SPACE
HEATING
EQUIVALENT
GALLONS OF
FUEL OIL
FUEL
OIL
UNIT
COST
POTENT! AL
SA'r'INGS
AT 100~
AVOIDED
COST
PRESENT
WORTH
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2035
(kWh)
(1)
449.88
458.88
468.06
477.42
486.97
496.71
506.64
516.78
527. 11
537.65
548.41
559.38
570.56
581.97
593.61
605.49
617.60
629.95
642.55
655.40
668.51
681.88
695.51
695.51
(kWh)
(2)
0.00
0.00
0.00
150.35
146.02
141.61
137. 11
132.53
127.85
123.07
118.21
113.93
109.78
105.56
101. 25
96.85
92.37
87.79
83. 12
78.37
73.51
68.56
63.51
63.51
<GAU
(3)
0
0
0
5313
5160
5004
4845
4683
4518
4349
4177
4026
3879
3730
3578
3422
3264
3102
2937
2769
2598
2423
2244
2244
($/GAU
(4)
1. 56
1. 56
1. 56
1. 56
1. 56
1. 56
1. 61
1. 66
1. 70
1. 76
1. 81
1. 86
1. 92
1. 98
2.04
2. 10
2. 16
2.22
2.29
2.36
2.43
2.50
2.58
2.58
($)
(5~
(!)Total village electrical demand from Table 11-1.
0
0
0
8288
8049
7806
7785
7750
7701
7636
7554
7499
7443
7371
7282
7175
7048
6900
6729
6534
6313
6065
5786
($)
(6)
5786
TOT'AL
0
0
0
8007
7514
7041
6784
6526
6265
6002
5736
5502
5276
5049
4819
4588
4354
4118
3881
3641
3399
3154
2908
1036
158047
(2)Surplus hydro generation in excess of village electrical demand.
<3>Equivalent gallons of fuel oil for space heating based on 28.3 kWh/gal.
(4)1984 fuel oil cost=$1.56/gal.Constant at 6.5% through 1988,then at 3.5%
annually through 2005 according to APA letter to DOWL dated May 15,1984.
(5)Potential savings to total village electrical cos1s from sale of surplus
hydro at 100% of avoided cost of fuel oil used for space heating.
(6)Present worth January 1985 at 3%.
TABLE C-5
PRESENT WORTH AND B/C SUMMARY
SCAMMON BAY HYDROELECTRIC PROJECT
A. BASE CASE (Benefits)
Present Worth Base Case
B. RECOMMENDED HYDROELECTRIC PROJECT (Costs)
Present Worth Hydroelectric Costs
Present Worth Supplemental Diesel Costs
Total Cost w/o Space Heating
Present Worth Space Heating Credit
Total Net Cost w/ Space Heating
C. BENEFIT/COST RATIO
1. B/C w/o Space Heating Credit
B/c 8,853,700 1 10 = 8,033,000 = •
2. B/C w/ Space Heating Credit
B/C = 8,853,700 = 1•12 7,875,000
SF:IEB:AD1:4-C-5
$8,853,700
1,519,500
6, 513' 500
8,033,000
158,000
$7,875,000
SF:IEB:AD1:4-C
APPENDIX D
DIESEl ANALYSES
TABLE D-1
ALASKA POWER AUTHORITY
FINANCIAL ANALYSIS:COST OF POWER
SCAMMON BAY HYDROELECTRIC PROJECT:BASE CASE W/FUEL ESCALATION
JUNE 1984
YEAR FIRM VILLAGE FIXED
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
. 2014
2015
2016
2017
2018
CAPACITY ENERGY COST
DEMAND
<kW> <MWh> (f)
(1) (2) (3)
180
180
180
180
180
280
280
280
280
175
175
175
175
175
175
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
449.88
458.88
468.06
477.42
486.97
496.71
506.64
516.78
527. 11
537.65
548.41
559.38
570.56
581.97
593.61
605.49
617.60
629.95
642.55
655.40
668.51
681.88
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
24100
23980
23857
43849
43721
57838
57705
57570
57431
57290
57146
56999
56849
67715
67559
158142
145930
145764
145595
145423
145248
145069
144886
155126
154936
169559
169361
169160
168954
168744
188480
188261
188039
187812
187580
139085
VARIABLE FUEL OIL FUEL OIL TOTAL
COST UNIT COST COST COST
($)
(4)
35906
39005
42371
46028
50000
54315
59002
64094
69626
75634
82162
89252
96954
105322
114411
124285
135010
146662
159319
173068
188004
204228
221853
221853
221853
221853
221853
221853
221853
221853
221853
221853
221853
221853
221853
221853
($/GAL)
(5)
1. 46
1. 56
1. 66
1. 77
1. 88
2.01
2.20
2.41
2.63
2.89
3. 16
3.46
3.79
4. 15
4.54
4.97
5.45
5.96
6.53
7. 15
7.83
8.57
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
($)
(6)
68645
74569
81004
87995
95589
103838
115977
129535
144677
161590
180480
201578
225143
251462
280858
313690
350360
391318
437063
488155
545220
608957
680144
680144
680144
680144
680144
680144
680144
680144
680144
680144
680144
680144
680144
680144
($)
128651
137554
147232
177871
189310
215992
232685
251199
271734
294514
319788
347829
378946
424498
462828
596116
631300
683743
741977
806646
878472
958254
1046883
1057123
1056933
1071556
1071358
1071157
1070951
1070741
1090477
1090258
1090036
1089809
1089577
1041082
2031 350 695.51 139085 221853 9.39 680144 1041082
2032 350 695.51 139085 221853 9.39 680144 1041082
2033 350 695.51 139085 221853 9.39 680144 1041082
2034 350 695.51 139085 221853 9.39 680144 1041082
2035 350 695.51 139085 221853 9.39 680144 1041082
UNIT
COST
(C/kWh)
28.60
29.98
31.46
37.26
38.88
43.48
45.93
48.61
51.55
54.78
58.31
62. 18
66.42
72.94
77.97
98.45
102.22
108.54
115.47
123.08
131.41
140.53
150.52
151.99
151.96
154.07
154.04
154.01
153.98
153.95
156.79
156.76
156.72
156.69
156.66
149.69
149.69
149.69
149.69
149.69
149.69
<!>Existing system is 1-75 kW,1-110 kW,and 1-105 kW.Add 175 kW units in 1986
and 1988.Add 300 kW unit in 1998.Replace units in perpetuity.Add fuel
storage facilities in 1986 and 1998.
(2)1983 energy use from APA letter.Escalates at 2.5% annually.
<3>Debt service on existing and future loans.
(4)8.5 cents/kWh for 1984.Includes lube oil,operations,miscellaneous
consumables,maintenance,and insurance.AVEC system average.
<5>1984 fuel cost=$1.56/gal.Inflated at 6.5% through 1988,then at 9.5%
annually through 2005 according to APA letter to JOWL dated May 15,1984.
<6>Fuel oil consumption rate=9.6 kWh/gallon.
TABLE D-2
ALASKA POWER AUTHORITY
FINANCIAL ANALYSIS:COST OF POWER
SCAMMON BAY HYDROELECTRIC PROJECT:BASE CASE W/0 FUEL ESCALATION
JUNE 1984
YEAR FIRM VILLAGE FIXED
CAPACITY ENERGY COST
DEMAND
VARIABLE FUEL OIL FUEL OIL TOTAL
COST UNIT COST COST COST
UNIT
COST
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
. 2014
2015
2016
2017
2018
(kW) <MWh> ($)
(1) (2) (3)
180
180
180
180
180
280
280
280
280
175
175
175
175
175
175
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
449.88
458.88
468.06
477.42
486.97
496.71
506.64
516.78
527.11
537.65
548.41
559.38
570.56
581.97
593.61
605.49
617.60
629.95
642.55
655.40
668.51
681.88
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.'51
24100
23980
23857
43849
43721
57838
57705
57570
57431
57290
57146
56999
56849
67715
67559
158142
145930
145764
145595
145423
145248
145069
144886
155126
154936
169559
169361
169160
168954
168744
188480
188261
188039
187812
187580
139085
($)
(4)
35906
39005
42371
46028
50000
54315
59002
64094
69626
75634
82162
89252
96954
105322
114411
124285
135010
146662
159319
173068
188004
204228
221853
221853
221853
221853
221853
221853
221853
221853
221853
221853
221853
221853
221853
221853
($/GAU
(5)
1. 46
1. 56
1. 66
1. 77
1. 88
2.01
2. 14
2.28
2.42
2.58
2.75
2.93
3.12
3.32
3.54
3.77
4.01
4.27
4.55
4.85
5. 16
5.50
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
($)
(6)
68645
74569
81004
87995
95589
103838
112800
122534
133109
144596
157075
170630
185356
201352
218729
237605
258110
280385
304582
330868
359422
390440
424135
424135
424135
424135
424135
424135
424135
424135
424135
424135
424135
424135
424135
424135
($)
128651
137554
147232
177871
189310
215992
229507
244198
260166
277520
296382
316882
339160
374389
400699
520031
539050
572811
609497
649359
692673
739737
790874
801114
800924
815547
815350
815148
814942
814732
834468
834250
834027
833800
833568
785073
2031 350 695.51 139085 221853 5.85 424135 785073
2032 350 695.51 139085 221853 5.85 424135 785073
2033 350 695.51 139085 221853 5.85 424135 785073
2034 350 695.51 139085 221853 5.85 424135 785073
2035 350 695.51 139085 221853 5.85 424135 785073
(!)Existing system is 75 kW,110 kW,and 105 kW.Add 175 kW units in 1986
28.60
29.98
31.46
37.26
38.88
43.48
45.30
47.25
49.36
51.62
54.04
56.65
59.44
64.33
67.50
85.89
87.28
90.93
94.86
99.08
103.62
108.49
113.71
115.18
115.16
117.26
117.23
117.20
117.17
117.14
119. 98
119.95
119.92
119.88
119.85
112.88
112.88
112.88
112.88
112.88
112.88
and 1988.Add 300 kW unit in 1998.Replace units in perpetuity.Add fuel
storage facilities in 1986 and 1988.
<2>1983 energy use from APA letter.Escalates at 2.5% annually.
(3)Debt service on existing and future loans.
(4)8.5 cents/kWh for 1984.Includes lube oil,operations,miscellaneous
consumables,maintenance,and insurance.AVEC system average.
(5)1984 fuel oil cost=$1.56/gal.Inflated at 6.5% annually through 2005
according to APA letter to DOWL dated May 15,1984.
<6>Fuel oil consumpton rate=9.6 kWh/gallon.
'f.ABLE D-3
ALASKA POWER AUTHORITY
FINANCIAL ANALYSIS:COST OF POWER
SCAMMON BAY HYDROELECTRIC PROJECT:SUPPLEMENTAL D(ESEL W/FUEL ESCALATION
JUNE 1984
YEAR FIRM VILLAGE FIXED
CAPACITY ENERGY COST
DEMAND
<kW) <MWh> ($)
(1) (2) (3)
VARIABLE FUEL OIL FUEL OIL TOTAL
COST UNIT COST COST COST
($)
(4)
($/GAL>
(5)
($)
(I!))
($)
UNIT
COST
(C/kWh>
-------- ---------------- --------------------------------- --------
1983
1984
1985
1986
1987
1988
1989
1990
1991
19~2
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
180
180
180
180
180
280
280
280
280
175
175
175
175
175
175
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
449.88
458.88
468.06
477.42
486.97
496.71
506.64
516.78
527.11
537.65
548.41
559.38
570.56
581.97
593.61
605.49
617.60
629.95
642.55
655.40
668.51
681.88
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
24100
23980
23857
43849
43721
57838
57705
57570
57431
57290
57146
56999
56849
67715
67559
158142
145930
145764
145595
145423
145248
145069
144886
155126
154936
169559
169361
169160
168954
168744
188480
188261
188039
187812
187580
139085
35906
39005
42371
21101
23009
25087
27351
29817
32502
35426
38610
42187
46126
50425
55115
60232
65814
71902
78543
85785
93682
102293
111681
111681
111681
111681
111681
111681
111681
111681
111681
111681
111681
111681
111681
111681
1. 46
1. 56
1. 66
1. 77
1. 88
2.01
2.20
2.41
2.63
2.89
3. 16
3.46
3.79
4. 15
4.54
4.97
5.45
5.96
6.53
7. 15
7.83
8.57
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
9.39
68645
74569
81004
40340
43988
47961
53762
60259
67536
75686
84813
95281
107113
120393
135297
152023
170791
191847
215469
241965
271683
305011
342384
342384
342384
342384
342384
342384
342384
342384
342384
342384
342384
342384
342384
342384
128651
137554
147232
105289
110717
130887
138818
147645
157469
168402
180569
194468
210088
238533
257972
370397
382535
409514
439607
473173
510613
552372
598951
609191
609001
623624
623426
623224
623019
622809
642544
642326
642103
641876
641645
593150
2031 350 695.51 139085 111681 9.39 342384 593150
2032 350 695.51 139085 111681 9.39 342384 593150
2033 350 695.51 139085 111681 9.39 342384 593150
2034 350 695.51 139085 111681 9.39 342384 593150
2035 350 695.51 139085 111681 9.39 342384 593150
(!)Existing system is 75 kW,110 kW,and 105 kW.Add 175 kW units in 1986
and 1988.Add 300 kW unit in 1998.Replace units in perpetuity.Add fuel
storage facilities in 1986 and 1998.
<2>1983 energy use from APA letter.Escalates at 2.5% annually.
(3)Debt service on existing and future loans.
28.60
29.98
31.46
22.05
22.74
26.35
27.40
28.57
29.87
31.32
32.93
34.77
36.82
40.99
43.46
61. 17
61.94
65.01
68.42
72.20
76.38
81.01
86.12
87.59
87.56
89.66
89.64
89.61
89.58
89.55
92.38
92.35
92.32
92.29
92.25
85.28
85.28
85.28
85.28
85.28
85.28
(4)8.5 cents/kWh for 1984.Includes lube oil,operations,miscellaneous
consumables,maintenance,and insurance.AVEC system average.
(5)1984 fuel cost=$1.56/gal.Inflated at 6.5~ through 1988,then at 9.5%
annually through 2005 according to APA letter to DOWL dated May 15,1984.
(6)Fuel oil consumption rate=9.6 kWh/gallon.
T.ABLE D-4
ALASKA POWER AUTHORITY
FINANCIAL ANALYSIS:COST OF POWER
SCAMMON BAY HYDROELECTRIC PROJECT:SUPPLEMENTAL DIESEL W/0 FUEL ESCALATION
JUNE 1984
YEAR FIRM VILLAGE FIXED
CAPACITY ENERGY COST
DEMAND
VARIABLE FUEL OIL FUEL OIL TOTAL
COST UNIT COST COST COST
UNIT
COST
1983
1984
1985
1986
1987
1988
1989
1990
1991
199.2
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
<kW) <MWh> ($)
(1) (2) (3)
($)
(4)
($/GAL>
(5)
($)
(6) -------- ---------------------------------
180
180
180
180
180
280
280
280
280
175
175
175
175
175
175
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
449.88
458.88
468.06
477.42
486.97
496.71
506.64
516.78
527. 11
537.65
548.41
559.38
570.56
581.97
593.61
605.49
617.60
629.95
642.55
655.40
668.51
681.88
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
695.51
24100
23980
23857
43849
43721
57838
57705
57570
57431
57290
57146
56999
56849
67715
67559
158142
145930
145764
145595
145423
145248
145069
144886
155126
154936
169559
169361
169160
168954
168744
188480
188261
188039
187812
187580
139085
35906
39005
42371
21101
23009
25087
27351
29817
32502
35426
38610
42187
46126
50425
55115
60232
65814
71902
78543
85785
93682
102293
111681
111681
111681
111681
111681
111681
111681
111681
111681
111681
111681
111681
111681
111681
1. 46
1. 56
1. 66
1. 77
1. 88
2.01
2. 14
2.28
2.42
2.58
2.75
2.93
3. 12
3.32
3.54
3.77
4.01
4.27
4.55
4.85
5. 16
5.50
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
5.85
68645
74569
81004
40340
43988
47961
52289
57003
62136
67727
73814
80653
88184
96402
105368
115150
125822
137462
150157
164002
179100
195561
213509
213509
213509
213509
213509
213509
213509
213509
213509
213509
213509
21:3509
213509
213509
($)
128651
137554
147232
105289
110717
130887
137345
144389
152069
160442
169570
179839
191159
214541
228042
333524
337565
355128
374296
395211
418030
442923
470076
480316
480126
494749
494551
494350
494144
493934
513670
513451
513229
513002
512770
464275
2031 350 695.51 139085 111681 5.85 213509 464275
2032 350 695.51 139085 111681 5.85 213509 464275
2033 350 695.51 139085 111681 5.85 213509 464275
2034 350 695.51 139085 111681 5.85 213509 464275
2035 350 695.51 139085 111681 5.85 213509 464275
(!)Existing system is 75 kW,110 kW,and 105 kW.Add 175 kW units in 1986
and 1988.Add 300 kW unit in 1998.Replace units in perpetuity.Add fuel
storage facilities in 1986 and 1998.
(2)1983 energy use from APA letter.Escalates at 2.5% annually.
(3)Debt service on existing and future loans.
(4)8.5 cents/kWh for 1984.Includes lube oil,operations,miscellaneous
consumables,maintenance,and insurance.AVEC system average.
(5)1984 fuel cost=$1.56/gal.Inflated at 6.5% through 2005 according to
APA letter to DOWL dated May 15,1984.
<6>Fue1 oil consumption rate=9.6 kWh/gallon.
28.60
29.98
31.46
22.05
22.74
26.35
27. 11
27.94
28.85
29.84
30.92
32. 15
33.50
36.86
38.42
55.08
54.66
56.37
58.25
60.30
62.53
64.96
67.59
69.06
69.03
71. 13
71. 11
71.08
71.05
71.02
73.85
73.82
73.79
73.76
73.73
66.75
66.75
66.75
66.75
66.75
66.75
SF:IEB:AD1:4-C
APPENDIX E
HYDROELECTRIC ANALYSES
.. --~
TABLE E-1
ALASKA POWER AUTHORITY
FINANCIAL ALTERNATIVE I-A:100% REVENUE BONDS WITH LEVEL PAYMENTS
SCAMMON BAY HYDROELECTRIC PROJECT:HYDROELECTRIC COSTS
JUNE 1984
YEAR CAPITAL DEBT
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2010
2015
2018
2019
2020
2021
2035
COST SERVICE
($) ($)
(1) (2)
0
0
1925920
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
199698
199698
199698
199698
199698
199698
199698
199698
199698
199698
199698
199698
199698
199698
199698
199698
199698
199698
0 199698
0
0
0
0
0
199698
199698
199698
0
0
O&M
($)
(3)
0
0
0
7719
8221
8755
9324
9930
10575
11263
11995
12775
13605
14489
15431
16434
17502
18640
19852
21142
25538
REPLAC.
SCHED.
($)
(4)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
404357
25538 2620231
25538
25538
25538
25538
25538
0
0
0
0
0
REPLAC.
SINKING
FUND
($)
(5)
0
0
0
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
RESERVE
FUND
($)
(6)
0
0
0
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
2735 219668
2735
2735
2735
2735
2735
219668
109834
109834
0
0
INT.
ON
RESERVE
($)
(7)
0
0
0
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
TOTAL
COST
($)
(8)
0
0
0
188185
188687
189221
189790
190396
191041
191729
192461
193241
194071
194955
195897
196900
197968
199106
200318
201608
206004
21967 206004
21967
10983
10983
0
0
206004
107154
107154
28273
28273
UNIT
COST
(C/kWh)
(9)
0.00
0.00
0.00
39.42
38.75
38.09
37.46
36.84
36.24
35.66
35.09
34.55
34.01
33.50
33.00
32.52
32.05
31.61
31. 18
30.76
29.62
29.62
29.62
15.41
15.41
4.07
4.07
(!)Capital cost including 10% interest during construction,3.75% financing
charge,and reserve equal to 110% of one years deb1 service.
<2>Debt sservice for 35 years at 10%.
(3)$5,000 for 1983.
<4>Replace runner every 25 years.Replace transmission lines every 30 years.
<5>Sinking funds superimposed.
(6)110% of annual debt service.
(7)10% annual interest on reserve fund.
(8)Total annual cost of hydro.
<9>Annua1 unit ~ost of hydro.
TABLE E-2
ALASKA POWER AUTHORITY
FINANCIAL ALTERNATIVE I-B:100~ REVENUE BONDS WITH GRADUATED PAYMENTS
MAXIMUM ALLOWABLE RATE OF INCREASE IN ANNUAL DEBT SERVICE:9.5~
SCAMMON BAY HYDROELECTRIC PROJECT:HYDROELECTRIC COSTS
YEAR CAPITAL DEBT
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2017
2018
2019
2020
2021
2010
2015
2035
COST SERVICE
($) ($)
(1) (2)
0
0
1925920
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
a
0
84095
92084
100832
110411
120900
132386
144962
158734
173813
190326
208407
228205
249885
273624
299618
317881
317881
317881
317881
317881
317881
317881
317881
317881
0
317881
0 317881
0 0
OS.M
($)
(3)
0
0
0
7719
8221
8755
9324
9930
10575
11263
11995
12775
13605
14489
15431
16434
17502
18640
19852
21142
22516
23980
25538
25538
25538
25538
25538
25538
25538
REPLAC.
SCHED.
($)
(4)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
234101
25538 2692164
25538 0
JUNE 1984
REPLAC.
SINKING
FUND
($)
(5)
0
0
0
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
RESERVE
FUND
($)
(6)
0
0
0
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
219668
73223
73223
73223
0
219668
2735 219668
2735
INT.
ON
RESERVE
($)
(7)
0
0
0
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
21967
7322
7322
7322
0
21967
TOTAL
COST
($)
(8)
0
0
0
72582
81072
90355
100503
111598
123729
136993
151496
167356
184698
203664
224404
247087
271894
299026
318501
319791
321165
322629
324188
324188
265609
265609
265609
28273
324188
21967 324188
0 28273
UNIT
COST
(c/kWh>
(9)
0.00
0.00
0.00
15.20
16.65
18. 19
19.84
21.60
23.47
25.48
27.62
29.92
32.37
35;00
37.80
40.81
44.02
47.47
49.57
48.79
48.04
47.31
46.61
46.61
38. 19
38.19
38.19
4.07
46.61
46.61
4.07
<l>Capital cost including 10~ interest during construction,3.75~ financing
charge,and reserve equal to 110~ of one years debl service.
<2>Debt service required to make 1986 unit energy cost the same as base case.
Maximum allowable annual rate of incease in energy cost=9.5~.Capital
costs fully amortized over remainder of 35 year financing period when
amortization exceeds maximum allowable payment.
(3)$5,000 for 1983.Escalates at 6.5~ annually.
(4)Replace runner every 25 years.Replace transmission lines every 30 years.
(5)Sinking funds are superimposed.
(6)110~ of annual debt service.
(7)10~ annual interest earned on reserve.
(8)Total annual cost of hydro.
(9)Annual unit cost of hydro.
TABLE E-3
ALASKA POWER AUTHORITY
FIHAHCIAL ALTERNATIVE II-A:50% REVEHUE BOHDS ~ 50% STATE GRAHT
SCAMMOH BAY HYDROELECTRIC PROJECT:HYDROELECTRIC COSTS
JUHE 1984
YEAR CAPITAL DEBT O&M
COST SERVICE
REPLAC.
SCHED.
REPLAC.
SIHKIHG
FUHD
($)
RESERVE
FUHD
IHT.
OH
RESERVE
( $)
TOTAL
COST
UHIT
COST
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2010
2015
2017
2018
2019
2020
2021
2035
($) ($)
( 1) (2)
0
0
962960
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
99849
0
0
($)
(3)
0
0
0
7719
8221
8755
9324
9930
10575
11263
11995
12775
13605
14489
15431
16434
17502
18640
19852
21142
22516
23980
25538
25538
25538
25538
25538
25538
25538
25538
25538
($)
(4)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
263896
264747
0
0
0
0
0
0
(5)
0
0
0
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
($)
(6)
0
0
0
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
109834
54917
54917
0
0
(7)
0
0
0
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
10983
5492
5492
0
0
($)
(8)
0
0
0
99319
99821
100355
100924
101530
102176
102863
103595
104375
105205
106090
107031
108034
109103
110240
111452
112742
114116
115580
117139
117139
117139
117139
117139
67713
67713
28273
28273
0.00
0.00
0.00
20.80
20.50
20.20
19.92
19.65
19.38
19. 13
18.89
18.66
18.44
18.23
18~03
17.84
17.67
17.50
17.35
17.20
17.07
16.95
16.84
16.84
16.84
16.84
16.84
9.74
9.74
4.07
4.07
(!)Capital cost for 50% of construction cost.Includes interest during
construction,financing fee,and reserve fund.Balance of construction paid ·
by state grant
(2) 10% for 35 years.
(3)$5,000 for 1983, esca1ated at 6.5% annually.
(4)Replace runner every 25 years.Replace transmission lines every 30 years.
(5)Sinking funds are superimposed.
(6)110% of annual debt sevice.
<7)10% annual interest earned on reserve.
<8>Total annual cost of hydro.
<9>Annua1 unit cost of hydro.
TABLE E-4
ALASKA POWER AUTHORITY
FINANCIAL ALTERNATIVE II-B:40% REVENUE BONDS ~ 60% STATE GRANT
SCAMMON BAY HYDROELECTRIC PROJECT:HYDROELECTRIC COSTS
JUNE 1984
YEAR CAPITAL DEBT
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2010
2015
2017
2018
2019
2020
2021
2035
COST SERVICE
($) ($)
(1) (2)
0
0
770370
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
79879
0
O~M
($)
(3)
REPLAC.
SCHED.
($)
(4)
0 0
0 0
0 0
7719 0
8221 0
8755 0
9324 0
9930 0
10575 0
11263 0
11995 0
12775 0
13605 0
14489 0
15431 0
16434 0
17502 0
18640 0
19852 0
21142 0
22516 0
23980 0
25538 0
25538 110666
25538 264747
25538 0
25538 0
25538 0
25538 0
25538 0
25538 0
REPLAC. RESERVE
SINKING FUND
FUND
($) ($)
(5) (6)
0
0
0
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
0
0
0
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
87867
43934
43934
0
0
INT.
ON
RESERVE
($)
(7)
0
0
0
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
8787
4393
4393
0
TOTAL
COST
($)
(8)
0
0
0
81546
82048
82582
83151
83757
84403
85090
85822
86602
87432
88317
89258
90261
91330
92467
93679
94969
96344
97807
99366
99366
99366
99366
99366
59825
59825
28273
28273
UNIT
COST
(O'kWh>
(9)
0.00
0.00
0.00
17.08
16.85
16.63
16.41
16.21
16.01
15.83
15.65
15.48
15.32
15. 18
15.04
14.91
14.79
14.68
14.58
14.49
14.41
14.34
14.29
14.29
14.29
14.29
14.29
8.60
8.60
4.07
4.07
(!)Capital cost for 40% of construction cost.Includes interest during
construction,financing fee,and reserve fund.Balance of construction paid ·
by state grant
(2) 10% for 35 years.
(3)$5,000 for 1983, escalated at 6.5% annually.
(4)Replace runn•r every 25 years.Replace transmission lines every 30 years.
(5)Sinking funds are superimposed.
(6)110% of annual debt sevice.
<7>10% annual interest earned on reserve.
(8)Total annual cost of hydro,
(9)Annual unit cost of hydro.
TABLE E-5
ALASKA POWER AUTHORITY
FINANCIAL ALTERNATIVE II-C:34.96% REVENUE BOHDS & 65.04% STATE GRANT
SCAMMON BAY HYDROELECTRIC PROJECT:HYDROELECTRIC COSTS
YEAR CAPITAL DEBT
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2010
2015
2017
2018
2019
2020
2021
2035
COST SERVICE
($) ($)
(1) (2)
0
0
673200
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
69804
0
O&M
($)
(3)
REPLAC.
SCHED.
($)
(4)
0 0
0 0
0 0
7719 0
8221 0
8755 0
9324 0
9930 0
10575 0
11263 0
11995 0
12775 0
13605 0
14489 0
15431 0
16434 0
17502 0
18640 0
19852 0
21142 0
22516 0
23980 0
25538 0
25538 110666
25538 264747
25538 0
25538 0
25538 0
25538 0
25538 0
25538 0
JUHE 1984
REPLAC. RESERVE
SIHKIHG FUHD
FUHD
($) ($)
(5) (6)
0
0
0
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
0
0
0
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
76784
38392
38392
0
IHT.
OH
RESERVE
($)
(7)
0
0
0
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
7678
3839
3839
0
0
TOTAL
COST
($)
(8)
0
0
0
72579
73081
73615
74184
74790
75436
76123
76855
77635
78465
79349
80291
81294
82362
83500
84712
86002
87376
88840
90399
90399
90399
90399
90399
55846
55846
28273
28273
UNIT
COST
(c/kWh)
(9)
0.00
0.00
0.00
15.20
15.01
14.82
14.64
14.47
14.31
14. 16
14.01
13.88
13.75
13.63
13.53
13.43
13.34
13.26
13. 18
13. 12
13.07
13.03
13.00
13.00
13.00
13.00
13.00
8.03
8.03
4.07
4.0?
(!)Capital cost for 34.96% of construction cost.Includes interest during
construction,financing fee,and reserve fund.Balance of construction paid
by state grant
(2) 10% for 35 years.
(3)$5,000 for 1983, escalated at 6.5% annually.
(4)Replace runner every 25 years.Replace transmission lines every 30 years.
(5)Sinking funds are superimposed.
(6)110% of annual debt sevice.
(7)10% annual interest earned on reserve.
<8>Tota1 annual cost of hydro.
<9>Annua1 unit cost of hydro.
TABLE E-6
ALASKA POWER AUTHORITY
FINANCIAL ALTERNATIVE III-A:STATE LOAN WITH 35 YEAR PAYBACK
SCAMMON BAY HYDROELECTRIC PROJECT:HYDROELECTRIC COSTS
JUNE 1~84
YEAR CAPITAL DEBT OS.M REPLAC.
SCHED.
REPLAC. RESERVE
SINKING FUND
FUND
INT. TOTAL
COST
1~83
1~84
1~85
1986
1987
1988
1~8~
1990
1991
1~92
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2010
2010
2020
2021
2035
COST SERVICE
($) ($)
( 1) (2)
0
0
1500000
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
91608
91608
91608
~1608
91608
91608
91608
91608
91608
91608
~1608
91608
91608
91608
91608
91608
~1608
91608
91608
91608
91608
91608
91608
0
($)
(3)
0
0
0
7719
8221
8755
9324
9930
10575
11263
11995
12775
13605
14489
15431
16434
17502
18640
19852
21142
22516
23980
25538
25538
25538
25538
25538
25538
($)
(4)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
110666
110666
0
0
($) ($)
(5) (6)
0
0
0
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
ON
RESERVE
($)
(7)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
($)
(8)
0
0
0
102061
102563
103097
103666
104272
104918
105605
106337
107117
107947
108832
109773
110776
111845
112982
114194
115484
116858
118322
119881
119881
119881
119881
28273
28273
UNIT
COST
(c/kWh)
(9)
0.00
0.00
0.00
21.38
21.06
20.76
20.46
20.18
19.90
19.64
19.39
19. 15
18.92
18.70
18.49
18.30
18. 11
17.94
17.77
17.62
17.48
17.35
17.24
17.24
17.24
17.24
4.07
4.07
(!)Capital cost with no allowance for interest during construction,finance fees
or reserve fund.
<2>Debt service for 35 years at 5%.
(3)$5,000 for 1983,escalate at 6.5% annually.
(4)Replace runner every 25 years.Replace transmission lines every 30 years.
(5)Sinking funds superimposed.
(6)No reserve required.
(7)No reserve required.
<8>Annual total hydro cost.
(9)Annual unit hydro cost.
TABLE E-7
ALASKA POWER AUTHORITY
FINANCIAL ALTERNATIVE III-B:STATE LOAN WITH DEFERRED PAYMENT
SCAMMON BAY HYDROELECTRIC PROJECT:HYDROELECTRIC COSTS
JUNE 1984
YEAR CAPITAL DEBT O&M REPLAC.
SCHED.
REPLAC.
SINKING
FUND
($)
RESERVE INT. TOTAL
COST
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2010
2015
2020
2021
2035
COST SERVICE
($) ($)
(1) (2)
0
0
1500000
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
173361
173361
173361
173361
173361
173361
173361
173361
173361
173361
173361
173361
173361
0
($)
(3)
0
0
0
7719
8221
8755
9324
9930
10575
11263
11995
12775
13605
14489
15431
16434
17502
18640
19852
21142
22516
23980
25538
25538
25538
25538
25538
25538
($)
(4)
0
0
0
0
0
0
e
0
0
0
0
0
0
0
0
0
0
0
0
0
0
e
0
110666
264747
0
0
(5)
0
0
0
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
FUND ON
RESERVE
($) ($)
(6) (7)
0
0
0
0
0
0
0
0
0
0
0
e
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
e
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
($)
(8)
0
0
0
10454
10955
11490
12059
12665
13310
13998
14730
15509
16340
190585
191527
192530
193598
194736
195947
197238
198612
200075
201634
201634
201634
201634
28273
28273
UNIT
COST
(c/kWh)
(9)
0.00
0.00
0.00
2. 19
2.25
2.31
2.38
2.45
2.53
2.60
2.69
2.77
2.86
32.75
32.26
31.80
31.35
30.91
30.50
30.09
29.71
29.34
28.99
28.99
28.99
28.99
4.07
4.07
(!)Capital cost without interest during construction 1 finance charge,or reserve.
<2>Payment deferred for 10 years then amortized over 25 years at 5%.
(3)$5,000 for 1983.Escalates at 6.5% annually.
(4)Replace runner every 25 years.Replace transmission lines every 30 years.
<5>Sinking funds superimposed.
(6)No reserve fund required.
(7)No reserve fund required.
<8>Annual hydro cost.
<8>Annual hydro unit cost.
,..._
TABLE E-8
ALASKA POWER AUTHORITY
FINANCIAL ALTERNATIVE IV:STATE EQUITY INVESTMENT
SCAMMON BAY HYDROELECTRIC PROJECT:HYDROELECTRIC COSTS
JUNE 1984
YEAR CAPITAL
COST
TOTAL
ANNUAL
COST
($)
(2)
O&M REPLACEMENT
SCHEDULE OF
INVESTMENT
($)
REPLACEMENT
SINKING
FUND
RETURN ON UNIT
INVESTMENT COST
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2010
2015
2035
($)
( 1)
0
0
1500000
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
75000
($)
(3)
0
0
0
7719
8221
8755
9324
9930
10575
11263
11995
12775
13605
14489
15431
16434
17502
18640
19852
21142
22516
23980
25538
21142
21142
21142
(4)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
110666
264747
($)
(5)
0
0
0
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
2735
($)
(6)
0
0
0
64546
64045
63510
62941
62335
61690
61002
60270
59491
58660
57776
56834
55831
54763
53625
52414
51123
49749
48286
46727
51123
51123
51123
(c/kWh)
(7)
0.00
0.00
0.00
15.71
15.40
15.10
14.80
14.51
14.23
13.95
13.68
13.41
13. 14
12.89
12.63
12.39
12. 14
11.91
11.67
11.44
11.22
11.00
10.78
10.78
10.78
10.78
(!)Capital cost without interest during construction,finance charge,or reserve.
(2) 5% of project capital cost return to state annually.
(3) $5000 for 1983.escalated at 6.5% annually.
(4)Rep1ace runner every 25 years.Replace transmission lines every 30 years.
(5)Sinking funds superimposed.
(6)Net return to state after paying O&M and sinking fund.
<7>Unit cost to consumers.
SF:1EB:AD1:4-C
APPENDIX F
SPACE HEATING ANALYSES
YEAR TOTAL
ELECTRICAL
DEMAND
tABLE F-1
ALASKA POWER AUTHORITY
SCAMMON BAY HYDROELECTRIC PROJECT
POTENTIAL SPACE HEATING CREDIT W/FUEL ESCALATION
JUNE 1984
HYDRO
AVAILABLE
FOR SPACE
HEATING
EQUIVALENT
GALLONS OF
FUEL OIL
FUEL
OIL
UNIT
COST
POTENTIAL
SAVINGS
POTENTIAL
SAVINGS
AT 50%
AVOIDED
COST
POTENTIAL
SAVINGS
AT 75%
AVOIDED
COST
<kWh)
(1)
<kWh)
(2)
<GAL)
(3)
($/GAL>
(4)
AT 25%
AVOIDED
COST
<Cents/kWh)
(5)
<Cents/kWh) <Cents/kWh)
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2035
449.88
458.88
468.06
477.42
486.97
496.71
506.64
516.78
527.11
537.65
548.41
559.38
570.56
581.97
593.61
605.49
617.60
629.95
642.55
655.40
668.51
681.88
695.51
695.51
0,00
0.00
0.00
150.35
146.02
141.61
137. 11
132.53
127.85
123.07
118.21
113.93
109.78
105.56
101.25
96.85
92.37
87.79
83.12
78.37
73.51
68.56
63.51
63.51
0
0
0
5313
5160
5004
4845
4683
4518
4349
4177
4026
3879
3730
3578
3422
3264
3102
2937
2769
2598
2423
2244
2244
1. 46
1. 56
1.66
1. 77
1. 88
2.01
2.20
2.41
2.63
2.89
3.16
3.46
3.79
4. 15
4.54
4.97
5.45
5.96
6.53
7. 15
7.83
8.57
9.39
9.39
(!)Total village electrical demand from Table II-1.
0.00
8.00
0.00
.4~
.50
• 51
.53
.55
• 56
.58
.60
.62
.64
.66
.68
.70
.72
.73
.75
.76
• 76
.76
.76
.76
(6) (7)
0.00
0.00
0.00
.98
1. 00
1. a 1
1. 05
1. 09
1. 13
1. 17
1. 20
1. 24
1. 29
1. 33
1. 37
1. 41
1. 44
1. 47
1. 49
1. 51
1. 52
1. 52
1. 51
1. 51
<2>Surplus hydro generation in excess of village electrical demand.
(3)Equivalent gallons of fuel oil for space heating based on 28.3 kWh/gal.
<4>1984 fuel oil cost=$1.56/gal.Inflated at 6.5% through 1988,then at 9.5%
annually through 2005 according to APA letter to DOWL dated May 15,1984.
(5)Potential savings to total village electrical costs from sale of surplus
hydro at 25% of avoided cost of fuel oil used for space heating.
<6>Potentia1 savings to total village electrical costs from sale of surplus
hydro at 50% of avoided cost of fuel oil used for space heating.
<?>Potential savings to total village electrical costs from sale of surplus
hydro at 75% of avoided cost of fuel oil used for space heating.
0.00
0.00
0.00
1. 48
1. 50
1. 52
1. 58
1. 64
1. 69
1. 75
1. 80
1. 87
1. 93
1. 99
2.05
2.11
2. 16
2.20
2.24
2.27
2.28
2.28
2.27
2.27
T.ABLE F-2
ALASKA POWER AUTHORITY
SCAMMON BAY HYDROELECTRIC PROJECT
POTENTIAL SPACE HEATING CREDIT W/0 FUEL ESCALATION
JUNE 1984
YEAR TOTAL HYDRO EQUIVALENT FUEL POTENTIAL POTENTIAL POTENTIAL
ELECTRICAL AVAILABLE GALLONS OF OIL SAVINGS SAVINGS SAVINGS
DEMAND FOR SPACE FUEL OIL UNIT AT 25% AT 50% AT 75%
HEATING COST AVOIDED AVOIDED AVOIDED
COST COST COST
<kWh) <kWh) <GAL> ($/GAU <Cents/kWh> <Cents/kWh) <Cents/kWh)
(1) (2) (3) (4) (5) (6) (7) ---------------------------------------------------------------------
1983 449.88 0.00 0 1. 46 il.00 0.00
1984 458.88 0.00 0 1. 56 Q.00 0.00
1985 468.06 0.00 0 1. 66 Q.00 0.00
1986 477.42 150.35 5313 1. 77 .49 .98
1987 486.97 146.02 5160 1. 88 .50 1. 00
1988 496.71 141.61 5004 2.01 .51 1. 01
1989 506.64 137. 11 4845 2. 14 . 51 1. 02
199.0 516.78 132.53 4683 2.28 .52 1. 03
1991 527.11 127.85 4518 2.42 .52 1. 04
1992 537.65 123.07 4349 2.58 .52 1. 04
1993 548.41 118.21 4177 2.75 .52 1. 05
1994 559.38 113.93 4026 2.93 .53 1. 05
1995 570.56 109.78 3879 3. 12 .53 1. 06
1996 581.97 105.56 3730 3.32 .53 1. 06
1997 593.61 101.25 3578 3.54 .53 1. 07
1998 605.49 96.85 3422 3.77 .53 1. 06
1999 617.60 92.37 3264 4.01 .53 1. 06
2000 629.95 87.79 3102 4.27 .53 1. 05
2001 642.55 83.12 2937 4.55 .52 1. 04
2002 655.40 78.37 2769 4.85 .51 1. 02
2003 668.51 73.51 2598 5. 16 .50 1. 00
2004 681.88 68.56 2423 5.50 .49 .98
2005 695.51 63.51 2244 5.85 .47 .94
2035 695.51 63.51 2244 5.85 .47 .94
(l)Total village electrical demand from Table II-1.
<2)Surplus hydro generation in excess of village electrical demand.
<3>Equivalent gallons of fuel oil for space heating based on 28.3 kWh/gal.
·(4)1984 fuel oil cost=$1.56/gal.Inflated at 6.5% through 2005 annually
according to APA letter to DOWL dated May 15,1984.
<S>Potential savings to total village electrical costs from sale of surplus
hydro at 25% of avoided cost of fuel oil used for space heating.
(6)Potential savings to total village electrical costs from sale of surplus
hydro at 50% of avoided cost of fuel oil used for space heating.
<?>Potential savings to total village electrical costs from sale of surplus
hydro at 75% of avoided cost of fuel oil used for space heating.
0.00
0.00
0.00
1. 48
1. 50
1. 52
1. 53
1. 55
1. 56
1. 57
1.57
1. 58
1. 59
1. 60
1. 60
1. 60
1. 59
1. 58
1. 56
1. 54
1. 50
1. 46
1. 42
1. 42
SF:IEB:A01:4-C
APPENDIX G
FINANCIAL SUMMARIES
WITHOUT REAL FUEL ESCALATION
-I• ...
TABLE G-1
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE I-A
j,.l/0 REAL FUEL ESCALATION
JUNE 1994
YEAR BASE SUPPL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh) < c /kWh) (c/kWh) (c/kWh) (c/kWh> (c/kWh> (c/kWh>
25% 50% 75%
(1) (2) (3) (4) (5) (6) (7)
---------------------------------------------------------------
1983 28.60 28.60 0,00 28.60 0.80 0.00 0.00
1984 29.98 29.98 0.00 29.98 0.00 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.00 0.00 0.00
1986 37.26 22.05 39.42 61.47 .49 .98 1. 48
1987 38.88 22.74 38.75 61.48 .50 1. 00 1. 50
1988 43.48 26.35 38.09 64.45 .51 1. 01 1. 52
1989 45.30 27. 11 37.46 64.57 .51 1. 02 1. 53
1990 47.25 27.94 36.84 64.78 .52 1. 03 1. 55
1991 49.36 28.85 36.24 65.09 .52 1. 04 1. 56
1992 51.62 29.84 35.66 65.50 .52 1. 04 1. 57
1993 54.04 30.92 35.09 66.02 .52 1. 05 1. 57
1994 56.65 32.15 34.55 66.70 .53 1.05 1. 58
1995 59.44 33.50 34.01 67.52 .53 1. 06 1. 59
1996 64.33 36.86 33.50 70.36 .53 1. 06 1. 60
1997 67.50 38.42 33.00 71.42 .53 1. 07 1. 60
1998 85.89 55.08 32.52 87.60 .53 1. 06 1. 60
1999 87.28 54.66 32.05 86.71 .53 1. 06 1. 59
2000 90.93 56.37 31.61 87.98 .53 1. 05 1. 58
2001 94.86 58.25 31. 18 89.43 .52 1. 04 1. 56
2002 99.08 60.30 30.76 91.06 • 51 1. 02 1. 54
2003 103.62 62.53 30.36 92.90 .50 1. 00 1. 50
2004 108.49 64.96 29.98 94.94 .49 .98 1. 46
2005 113.71 67.59 29.62 97.21 .47 .94 1. 42
2006 115.18 69.06 29.62 98.68 .47 .94 1. 42
2007 115.16 69.03 29.62 98.65 .47 .94 1.42
2008 117.26 71. 13 29.62 100.75 .47 .94 1. 42
2009 117.23 71. 11 29.62 100.73 .47 .94 1. 42
2010 117.20 71.08 29.62 100.70 .47 .94 1. 42
2011 117.17 71.05 29.62 100.67 .47 . 94 1. 42
2012 117.14 71.02 29.62 100.64 .47 .94 1. 42 ...
2018 112.88 66.75 29.62 96.37 .47 .94 1. 42
2019 112.88 66.75 15.41 82. 16 .47 . 94 1. 42
2020 112.88 66.75 15.41 82.16 . 47 .94 1. 42
2021 112.88 66.75 4.07 70.82 .47 .94 1. 42
2035 112.88 66.75 4.07 70.82 .47 .94 1. 42
<t>See Table D-2
<2>See Table D-4
<3>See Table E-1
<4>Sum of hydro and supplemental diesel costs.
(5)Potent i al space heating credit at 25% avoided cosi.See Table F-1.
<6>Potent i al space heating credit at 50% avoided cos1..See Table F-1.
<?>Potential space heating credit at 75% avoided cosi.See Table F-1.
TABLE G-2
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE I-B
W/0 REAL FUEL ESCALATION
JUNE 1984
YEAR BASE SUP PL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh) <c /kWh) (c/kWh) (c/kWh) (c/kWh> < c /kWh) (c/kWh)
25% 50% 75%
(1) (2) (3) (4) (5) (6) (7)
------------------.. ---------------------------------------------
1983 28.60 28.60 0.00 28.60 0.00 0.00 0.00
1984 29.98 29.98 0.00 29.98 0.00 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.00 0.00 0.00
1986 37.26 22.05 15.20 37.26 .49 .98 1. 48
1987 38.88 22.74 16.65 39.38 .50 1. 00 1. 50
1988 43.48 26.35 18. 19 44.54 . 51 1. 01 1. 52
1989 45.30 27. 11 19.84 46.95 • 51 1. 02 1. 53
1990 47.25 27.94 21.60 49.54 .52 1. 03 1. 55
1991 49.36 28.85 23.47 52.32 .52 1. 04 1. 56
1992 51.62 29.84 25.48 55.32 .52 1. 04 1. 57
1993 54.04 30.92 27.62 58.55 .52 1. 05 1. 57
1994 56.65 32. 15 29.92 62.07 .53 1. 05 1. 58
1995 59.44 33.50 32.37 65.87 .53 1. 06 1. 59
1996 64.33 36.86 35.00 71.86 .53 1. 06 1. 60
1997 67.50 38.42 37.80 76.22 .53 1. 07 1. 60
1998 85.89 55.08 40.81 95.89 .53 1. 06 1. 60
1999 87.28 54.66 44.02 98.68 .53 1. 06 1. 59
2000 90.93 56.37 47.47 103.84 .53 1. 05 1. 58
2001 94.86 58.25 49.57 107.82 .52 1. 04 1. 56
2002 99.08 60.30 48.79 109.09 .51 1. 02 1. 54
2003 103.62 62.53 48.04 110.57 .50 1. 00 1. 50
2004 108,49 64.96 47.31 112.27 .49 .98 1. 46
2005 113.71 67.59 46.61 114.20 .47 .94 1. 42
2006 115.18 69.06 46.61 115.67 .47 • 94 1. 42
2007 115.16 69.03 46.61 115. 64 .47 .94 1. 42
2008 117.26 71. 13 46.61 117.75 .47 .94 1. 42
2009 117.23 71. 11 46.61 117.72 .47 .94 1. 42
2010 117.20 71.08 46.61 117.69 .47 .94 1. 42
2011 117.17 71.05 46.61 117.66 .47 .94 1. 42
2012 117.14 71.02 46.61 117.63 .47 .94 1. 42
2018 112.88 66.75 38.19 104.94 .47 .94 1. 42
2019 112.88 66.75 38.19 104.94 .47 .94 1. 42
2020 112.88 66.75 38.19 104.94 .47 .94 1. 42
2021 112.88 66.75 4.07 70.82 .47 .94 1. 42
2035 112.88 66.75· 4.07 70.82 .47 .94 1. 42
(1)See Tab 1 e D-2
<2)See Table D-4
<3>See Table E-2
<4>Surn of hydro and supplemental diesel costs.
<5>Potentia1 space heating credit at 25% avoided cos'I..See Tab 1 e F-1.
<6>Potent i al space heating credit at 50% avoided cosi.See Tab 1 e F-1.
<?)Potential space heating credit at 75% avoided cos'I..See Tab 1 e F-1.
TABLE G-3
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE I I -A
W/0 REAL FUEL ESCALATION
JUNE 1984
YEAR BASE SUPPL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh> (c/kWh> (c/kWh> (c/kWh> (c/kWh) (c/kWh) (c/kWh)
25% 50% 75%
(1) (2) (3) (4) (5) (6) (7)
---------------------------------------------------------------
1983 28.60 28.60 0.00 28.60 0.80 0.00 0.00
1984 29.98 29.98 0.00 29.98 0.80 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.80 0.00 0.00
1986 37.26 22.05 20.80 42.86 .49 .98 1. 48
1987 38.88 22.74 20.50 43.23 .50 1. 00 1. 50
1988 43.48 26.35 20.20 46.55 .51 1. 01 1. 52
1989 45.30 27. 11 19.92 47.03 . 51 1. 02 1. 53
1990 47.25 27.94 19.65 47.59 .52 1.03 1. 55
1991 49.36 28.85 19.38 48.23 . 52 1. 04 1. 56
1992 51.62 29.84 19. 13 48.97 .52 1. 04 1. 57
1993 54.04 30.92 18.89 49.81 .52 1. 05 1. 57
1994 56.65 32.15 18.66 50.81 • 53 1. 05 1. 58
1995 59.44 33.50 18.44 51.94 .53 1. 06 1. 59
1996 64.33 36.86 18.23 55.09 .53 1. 06 1. 60
1997 67.50 38.42 18.03 56.45 .53 1. 07 1. 60
1998 85.89 55.08 17.84 72.93 .53 1. 06 1. 60
1999 87.28 54.66 17.67 72.32 .53 1. 06 1. 59
2000 90.93 56.37 17.50 73.87 .53 1. 05 1. 58
2001 94.86 58.25 17.35 75.60 .52 1. 04 1. 56
2002 99.08 60.30 17.20 77.50 .51 1. 02 1. 54
2003 103.62 62.53 17.07 79.60 .50 1. 00 1. 50
2004 108.49 64.96 16.95 81.91 .49 .98 1. 46
2005 113.71 67.59 16.84 84.43 .47 .94 1. 42
2006 115.18 69.06 16.84 85.90 .47 .94 1. 42
2007 115.16 69.03 16.84 85.87 .47 .94 1. 42
2008 117.26 71. 13 16.84 87.98 .47 .94 1. 42
2009 117.23 71.11 16.84 87.95 .47 .94 1. 42
2010 117.20 71.08 16.84 87.92 .47 .94 1. 42
2011 117.17 71.05 16.84 87.89 . 47 .94 1. 42
2012 117.14 71.02 16.84 87.86 .47 .94 1. 42 ...
2018 112.88 66.75 16.84 83.59 .47 .94 1. 42
2019 112.88 66.75 9.74 76.49 .47 .94 1. 42
2020 112.88 66.75 9.74 76.49 .47 .94 1. 42
2021 112.88 66.75 4.07 70.82 .47 .94 1. 42
2035 112.88 66.75 4.07 70.82 .47 • 94 1. 42
(!)See Table D-2
(2)See Table D-4
<3>See Table E-3
(4)8ym of hydro and supplemental diesel costs.
<5>Potent i al space heating credit at 25% avoided cosJ.See Table F-1.
(6)Potential space heating credit at 50% avoided cost..See Table F-1.
<?>Potential space heating credit at 75% avoided cost..See Table F-1.
TABLE G-4
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE li-B
W/0 REAL FUEL ESCALATION
JUNE 1984
YEAR BASE SUPPL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh) < c /kWh> (c/kWh> (c/kWh) (c/kWh) ( c/k Wh) < c /kWh>
25% 50% 75%
(1) (2) (3) (4) (5) (6) (7) ------------------------------------------------------ ---------1983 28.60 28.60 0.00 28.60 0.00 0.00 0.00
1984 29.98 29.98 0.00 29.98 0.00 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.00 0.00 0.00
1986 37.26 22.05 17.08 39.13 .49 .98 1. 48
1987 38.88 22.74 16.85 39.58 .50 1. 00 1. 50
1988 43.48 26.35 16.63 42.98 .51 1. 01 1. 52
1989 45.30 27. 11 16.41 43.52 .51 1. 02 1. 53
1990 47.25 27.94 16.21 44.15 . 52 1. 03 1. 55
1991 49.36 28.85 16.01 44.86 .52 1. 04 1. 56
1992 51.62 29.84 15.83 45.67 .52 1. 04 1. 57
1993 54.04 30.92 15.65 46.57 .52 1. 05 1. 57
1994 56.65 32. 15 15.48 47.63 .53 1. 05 1. 58
1995 59.44 33.50 15.32 48.83 .53 1. 06 1. 59
1996 64.33 36.86 15. 18 52.04 .53 1. 06 1. 60
1997 67.50 38.42 15.04 53.45 .53 1. 07 1. 60
1998 85.89 55.08 14.91 69.99 .53 1. 06 1. 60
1999 87.28 54.66 14.79 69.45 .53 1. 06 1. 59
2000 90.93 56.37 14.68 71.05 .53 1. 05 1. 58
2001 94.86 58.25 14.58 72.83 .52 1. 04 1. 56
2002 99.08 60.30 14.49 74.79 .51 1. 02 1. 54
2003 103.62 62.53 14.41 76.94 .50 1. 00 1. 50
2004 108.49 64.96 14.34 79.30 .49 .98 1. 46
2005 113.71 67.59 14.29 81.87 .47 .94 1. 42
2006 115.18 69.06 14.29 83.35 .47 .94 1. 42
2007 115.16 69.03 14.29 83.32 .47 .94 1. 42
2008 117.26 71. 13 14.29 85.42 .47 .94 1. 42
2009 117.23 71. 11 14.29 85.39 .47 . 94 1. 42
2010 117.20 71.08 14.29 85.36 • 47 • 94 1. 42
2011 117.17 71.05 14.29 85.33 .47 .94 1. 42
2012 117.14 71. 02 14.29 85.30 .47 .94 1. 42
2018 112.88 66.75 14.29 81.04 .47 .94 1. 42
2019 112.88 66.75 8.60 75.35 .47 .94 1. 42
2020 112.88 66.75 8.60 75.35 .47 .94 1. 42
2021 112.88 66.75 4.07 70.82 .47 • 94 1. 42
2035 112.88 66.75 4.07 70.82 .47 .94 1. 42
(1)See Table D-2
<2>See Table D-4
(3)See Table E-4
(4)Sum of hydro and supplemental diesel costs.
(5)Potent i al space heating credit at 25% avoided cosi.See Tab I e F-1.
(6)Potential space heating credit at 50% avoided cost.See Table F-1.
<?>Potential space heating credit at 75% avoided cost.See Table F-1.
TABLE G-5
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE I I-C
W/0 REAL FUEL ESCALATION
JUNE 1984
YEAR BASE SUPPL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh) (c/kWh> (c/kWh) (c/kWh> (c/kWh> < c /kWh) (c/kWh)
25% 50% 75%
(1) (2) (3) (4) (5) (6) (7)
---------------------------------------------- --------- ---------
1983 28.60 28.60 0.00 28.60 0.00 0.00 0.00
1984 29.98 29.98 0.00 29.98 0.00 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.00 0.00 0.00
1986 37.26 22.05 15.20 37.26 .49 .98 1. 48
1987 38.88 22.74 15.01 37.74 .50 1. 00 1. 50
1988 43.48 26.35 14.82 41. 17 • 51 1. 01 1. 52
1989 45.30 27. 11 14.64 41.75 . 51 1. 02 1. 53
1990 47.25 27.94 14.47 42.41 .52 1. 03 1. 55
1991 49.36 28.85 14.31 43. 16 .52 1. 04 1. 56
1992 51.62 29.84 14. 16 44.00 .52 1. 04 1. 57
1993 54.04 30.92 14.01 44.93 .52 1. 05 1. 57
1994 56.65 32.15 13.88 46.03 .53 1. 05 1. 58
1995 59.44 33.50 13.75 47.26 .53 1. 06 1. 59
1996 64.33 36.86 13.63 50.50 .53 1. 06 1. 60
1997 67.50 38.42 13.53 51.94 .53 1. 07 1. 60
1998 85.89 55.08 13.43 68.51 .53 1. 06 1. 60
1999 87.28 54.66 13.34 67.99 .53 1. 06 1. 59
2000 90.93 56.37 13.26 69.63 .53 1. 05 1. 58
2001 94.86 58.25 13. 18 71.44 .52 1. 04 1. 56
2002 99.08 60.30 13. 12 73.42 . 51 1. 02 1. 54
2003 103.62 62.53 13.07 75.60 .50 1. 00 1. 50
2004 108.49 64.96 13.03 77.99 .49 .98 1. 46
2005 113.71 67.59 13.00 80.58 .47 .94 1. 42
2006 115.18 69.06 13.00 82.06 .47 .94 1. 42
2007 115.16 69.03 13.00 82.03 .47 .94 1. 42
2008 117.26 71. 13 13.00 84.13 .47 .94 1. 42
2009 117.23 71 • 11 13.00 84.10 .47 .94 1. 42
2010 117.20 71.08 13.00 84.07 .47 .94 1. 42
2011 117.17 71.05 13.00 84.04 .47 .94 1. 42
2012 117.14 71.02 13.00 84.01 .47 .94 1. 42
2018 112.88 66.75 13.00 79.75 .47 .94 1. 42
2019 112.88 66.75 8.03 74.78 .47 .94 1. 42
2020 112.88 66.75~ 8.03 74.78 .47 .94 1. 42
2021 112.88 66.75 4.07 70.82 .47 .94 1. 42
2035 112.88 .. 66.751 4.07 70.82 .47 .94 1. 42
<l>Se:e Table D-2
<2)See Table D-4
(3)See: Table: E-5
<4>Sum of hydro and supplemental diesel costs.
(5)Potential space heating credit at 25% avoided cosi.See Table F-1.
(6)Potent i al space heating credit at 50% avoided cosi.See Table F-1.
<?)Potential space heating credit at 75% avoided cosi.See Table F-1.
TABLE G-6
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE III-A
W/0 REAL FUEL ESCALATION
JUNE 1984
YEAR BASE SUPPL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh) (c/kWh> (c/kWh) (c/kWh) (c/kWh> < c /kWh) (c/kWh)
25% 50% 75%
(1) (2) (3) (4) (5) (6) (7)
---------------------------------------------------------------
1983 28.60 28.60 0.00 28.60 0.00 0.00 0.00
1984 29.98 29.98 0.00 29.98 0.00 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.00 0.00 0.00
1986 37.26 22.05 21.38 43.43 .49 .98 1. 48
1987 38.88 22.74 21.06 43.80 .50 1. 00 1. 50
1988 43.48 26.35 20.76 4 7. 11 . 51 1. 01 1. 52
1989 45.30 27. 11 20.46 47.57 .51 1. 02 1. 53
1990 47.25 27.94 20.18 48.12 .52 1. 03 1. 55
1991 49.36 28.85 19.90 48.75 .52 1. 04 1. 56
1992 51.62 29.84 19.64 49.48 .52 1. 04 1. 57
1993 54.04 30.92 19.39 50.31 .52 1. 05 1. 57
1994 56.65 32.15 19. 15 51.30 .53 1. 05 1. 58
1995 59.44 33.50 18.92 52.42 .53 1. 06 1. 59
1996 64.33 36.86 18.70 55.56 .53 1. 06 1. 60
1997 67.50 38.42 18.49 56.91 .53 1. 07 1. 60
1998 85.89 55.08 18.30 73.38 .53 1. 06 1. 60
1999 87.28 54.66 18. 11 72.77 .53 1. 06 1. 59
2000 90.93 56.37 17.94 74.31 .53 1. 05 1. 58
2001 94.86 58.25 17.77 76.02 .52 1. 04 1. 56
2002 99.08 60.30 17.62 77.92 .51 1. 02 1. 54
2003 103.62 62.53 17.48 80.01 .50 1. 00 1. 50
2004 108.49 64.96 17.35 82.31 .49 .98 1. 46
2005 113.71 67.59 17.24 84.82 .47 .94 1. 42
2006 115.18 69.06, 17.24 86.30 .47 .94 1. 42
2007 115.16 69.03 17.24 86.27 .47 .94 1. 42
2008 117.26 71. 13 17.24 88.37 .47 • 94 1. 42
2009 117.23 71. 11 17.24 88.34 .47 .94 1. 42
2010 117.20 71.08 17.24 88.31 .47 .94 1. 42
2011 117.17 71.05 17.24 88.28 .47 .94 1. 42
2012 117.14 71.02 17.24 88.25 .47 .94 1. 42
2018 112.88 66.75 17.24 83.99 .47 .94 1. 42
2019 112.88 66.75 17.24 83.99 .47 .94 1. 42
2020 112.88 66.75 17.24 83.99 .47 .94 1.42
2021 112.88 66.75 4.07 70.82 .47 .94 1.42
2035 112.88 66.75 4.07 70.82 .47 .94 1. 42
(1)See Table D-2
<2>See Table D-4
<3>See Table E...;.6
<4>Sum of hydro and supplemental diesel costs.
<5)Potent i al space heating credit at 25% avoided cos1,.See Table F-1.
(6)Potent i al space heating credit at 50% avoided cos1,.See Table F-1.
(?)Potential space heating credit at 75% avoided cos1,.See Table F-1.
TABLE G-7
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTIU C ALTERNATIVE II I-B
W/0 REAL FUEL ESCALATION
JUNE 1984
YEAR BASE SUP PL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(c/kWh) (c/kWh) (C/kWh) < c /kWh) (c/kWh) (c/kWh) (c/kWh)
25% 50% 75%
(1) (2) (3) (4) (5) (E)) (7)
---------------------------------------------------------------1983 28.60 28.60 0.00 28.60 0.80 0.00 0.00
1984 29.98 29.98 0.00 29.98 0.00 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.00 0.00 0.00
1986 37.26 22.05 2. 19 24.24 .49 .98 1. 48
1987 38.88 22.74 2.25 24.99 .50 1. 00 1. 50
1988 43.48 26.35 2.31 28.66 .51 1. 01 t. 52
1989 45.30 27. 11 2.38 29.49 .51 1. 02 1. 53
1990 47.25 27.94 2.45 30.39 .52 1. 03 1. 55
1991 49.36 28.85 2.53 31.37 .52 t. 04 t. 56
1992 51.62 29.84 2.60 32.44 .52 1. 04 1. 57
1993 54.04 30.92 2.69 33.61 .52 1. 05 1. 57
1994 56,65 32.15 2.77 34.92 .53 1. 05 t. 58
1995 59.44 33.50 2.86 36.37 .53 1. 06 1. 59
1996 64.33 36.86 32.75 69.61 .53 1. 06 1. 60
1997 67.50 38.42 32.26 70.68 .53 1. 07 1. 60
1998 85.89 55.08 31.80 86.88 .53 1. 06 1. 60
1999 87.28 54.66 31.35 86.01 .53 1. 06 1. 59
2000 90.93 56.37 30.91 87.29 .53 1. 05 1. 58
2001 94.86 58.25 30.50 88.75 .52 1. 04 1. 56
2002 99.08 60.30 30.09 90.40 • 51 1. 02 1. 54
2003 103.62 62.53 29.71 92.24 .50 1. 00 1. 50
2004 108.49 64.96 29.34 94.30 .49 .98 1. 46
2005 113.71 67.59 28.99 96.58 .47 .94 1. 42
2006 115.18 69.06 28.99 98.05 .47 .94 1. 42
2007 115.16 69.03 28.99 98.02 .47 .94 1. 42
2008 117.26 71. 13 28.99 100. 13 .47 .94 1. 42
2009 117.23 71. 11 28.99 100. 10 .47 .94 1. 42
2010 117.20 71.08 28.99 100.07 .47 .94 1. 42
2011 117.17 71.05 28.99 100.04 .47 .94 1. 42
2012 117.14 71.02 28.99 100.01 .47 .94 1. 42
2018 112.88 66.75 28.99 95.74 .47 .94 1. 42
2019 112.88 66.75 28.99 95.74 .47 .94 1. 42
2020 112.88 66.75 28.99 95.74 .47 .94 1. 42
2021 112.88 66.75 4.07 70.82 .47 .94 1. 42
2035 112.88 66.75 4.07 70.82 .47 .94 1. 42
(1)S~?e Table D-2
<2>See Table D-4
(3)See Table E-7
(4)S~m of hydro and s~pplemental diesel costs.
(5)Pot~?rtt i al space heating credit at 25% avoided cost.See Table F-1.
(6)Potent i al space heating credit at 50% avoided cost.See Table F-1.
<7)Poter.t i al space heating credit at 75% avoided cost.See Table F-1.
TABLE G-8
ALASKA POWER AUTHORITY
FINANCIAL SUMMARY FOR SCAMMON BAY HYDROELECTRIC ALTERNATIVE IV
W/0 REAL FUEL ESCALATION
JUNE 1984
YEAR BASE SUPPL. HYDRO. TOTAL SPACE SPACE SPACE
CASE DIESEL VILLAGE HEATING HEATING HEATING
CREDIT CREDIT CREDIT
(C/kWh) (c/kWh) (c/kWh) ( c /kWh) (c/kWh) (c/kWh) (c/kWh)
25% 50% 75%
(1) (2) (3) (4) (5) (6) (7)
-------------------.,. _______ --------- ---------------------------1983 28.60 28.60 0.00 28.60 0.00 0.00 0.00
1984 29.98 29.98 0.00 29.98 0.00 0.00 0.00
1985 31.46 31.46 0.00 31.46 0.00 0.00 0.00
1986 37.26 22.05 15.71 37.76 .49 .98 1. 48
1987 38.88 22.74 15.40 38.14 .50 1. 00 1. 50
1988 43.48 26.35 15. 10 41.45 . 51 1. 01 1. 52
1989 45.30 27. 11 14.80 41.91 . 51 1. 02 1. 53
199o3 47.25 27.94 14.51 42.45 .52 1. 03 1. 55
1991 49.36 28.85 14.23 43.08 .52 1. 04 1. 56
1992 51.62 29.84 13.95 43.79 .52 1. 04 1. 57
1993 54.04 30.92 13.68 44.60 .52 1. 05 1. 57
1994 56.65 32.15 13.41 45.56 .53 1. 05 1. 58
1995 59.44 33.50 13. 14 46.65 .53 1. 06 1. 59
1996 64.33 36.86 12.89 49.75 .53 1. 06 1. 60
1997 67.50 38.42 12.63 51.05 .53 1. 07 1. 60
1998 85.89 55.08 12.39 67.47 .53 1. 06 1. 60
1999 87.28 54.66 12. 14 66.80 .53 1. 06 1. 59
2000 90.93 56.37 11.91 68.28 .53 1. 05 1. 58
2001 94.86 58.25 11.67 69.92 .52 1.04! 1. 56
2002 99.08 60.30 11.44 71.74 • 51 1. ('2 1. 54
2003 103.62 62.53 11.22 73.75 .50 1. 00 1. 50
2004 108.49 64.96 11.00 75.96 .49 .98 1. 46
2005 113.71 67.59 10.78 78.37 .47 .94 1. 42
2006 115.18 69.06 10.78 79.84 .47 .94 1. 42
2007 115.16 69.03 10.78 79.82 .47 .94 1. 42
2008 117.26 71. 13 10.78 81.92 .47 .94 1. 42
2009 117.23 71. 11 10.78 81.89 .47 .94 1. 42
2010 117.20 71.08 10.78 81.86 .47 .94 1. 42
2011 117.17 71.05 10.78 81.83 .47 .94 1. 42
2012 117.14 71.02 10.78 81.80 .47 .94 1. 42
2018 112.88 66.75 10.78 77.54 .47 .94 1. 42
2019 112.88 66.75 10.78 77.54 .47 .94 1. 42
2020 112.88 66.75 10.78 77.54 .47 .94 1. 42
2021 112.88 66.75 10.78 77.54 .47 .94 1. 42
2035 112. 88 66.75 10.78 77.54 .47 .94 1. 42
<l)See Table D-2
(2)See Table D-4
<3)See Table E-8
(4)Sum of hydro and supplemental diesel costs.
<5>Potent i al space heating credit at 25% avoided cos1..See Table F-1.
<6>Potent i al space heating credit at 50% avoided co:s1..See Table F-1.
(7)Potent i al :space heating credit at 75% avoided cos1..See Table F-1.