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Devil Canyon
UPPER SUSITNA
RIVER PROJECT
POWER MARKET
ANALYSES
This report is included as Section G, Appendix -Part 2 of
the Southcentral Railbelt Area, Alaska, Upper Susitna River
Basin, Supplemental Feasibility Report by the Corps of En-
gineers, revised February 1979.
® .. .
. . . .
Department Of Energy
Alaska Power Administration
P.O. Box 50
Juneau, Alaska 99802
Colonel George R. Robertson
District Engineer
Corps of Engineers
P.O. Box 7002
Anchorage, Alaska 99510
Dear Colonel Robertson:
April 2, 1979
This is Alaska Power Administration's new power market report for the
Upper Susitna Project. It's an update of the previous power market
analyses provided for the Corps' 1976 Interim Feasibility.report.
The power market report includes: a new set of load projections for the
Railbelt area through year 2025 and a review of alternative sources of
power. Load/resource and total power system cost analyses were prepared
for different scenarios under various assumptions to determine effects
on power rates.
Under .the assumptions made for this report, Alaska Power Administrat,ion
determines that the Upper Susitna Project is feasible from a power ·
marketing standpoint.
1
I
A draft of th.is report was circulated to the area utilities and con-i
cerned State officers for informal review and comment. Comments havb
been incorporated and the letters of comments are appended.
Sincerely,
~·; ,/
l" ~/ / c ~->·-c:i:c:/2._..--<~
Robert J. Cross
Administrator
I
CONTENTS
TITLE
PART I -INTRODUCTION
PART II -SUMMARY
PART III -POI.JER MARKET AREAS
Anchorage-Cook Inlet •••••..
Fairbanks-Tanana Valley ••••••••
PART IV -EXISTING POWER SYSTEMS
Utility Systems and Service Areas •••••.•.•.••.•
National Defense Power Systems ••..•••..•.•.••••
Industrial Power Systems ••.•.•.••.•••.•••••..•.
Existing Generation Capacity •.••.•.•.•.•..••
Planned Generation Capacity •..••..•.•......•
PART V -POWER REQUIREMENTS
Introduct-ion
Data •....••.
Analysis
Utility •••••.·!-••••••••••••o•••••••••••••••••••••••••••
National Defense .................................... .
Self-Supplied _Industry • • • • • • • • • • . . . • . • • • . • • ••••..•
Energy & Power Demand Forecasts •••••••.•••••••••.•••
Assumptions and Methodology ••.•.....••.•••••••••
Population . . . . . . . . . . . . . . . . . . . .. . . ..... D •
Utility ................................... .
National Defense •.••••••••••......••••••••.
Self-Supplied Industry •.•••••..••.
Estimate of Future Demands •.••.•.
Comparison With Other Forecasts ..•..•
Load Distribution ............... ~ .......... .
Capacity Requirements
PART VI -ALTERNATIVE POWER SOURCES
Introduction .......................... .
Alternatives Considered .•••••.•••••.•••
Coal .... " .......................... . . . . . · ....
Location ............... !t •...............
Capacity .. •••••e•••••••••••••• •••••••••. ••••••••
Investment Costs ............................... .
Fuel Cost and Availability ••••••••••••••••.•••.•
Cost of Po·wer ............ o ••••• " ••••••••••••••••
Comparative Cost of Power (FERC) •.••••••••••••••
Oil and Natural Gas ................................. .
Hydro ....................... ~ ....................... .
Criteria ....................................... .
Single Large Capacity Sites •••••••••••.•••••••••
Combinations of Small Capacity Sites ••••••••
Summary .•........•..•..••....•..................
i
PAGE NO.
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55
61
63
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67
70
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71
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71
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72
73
CONT~NTS (Continued)
Title Pag~ No.
Nuclear
Wind
Geothermal
Tide
Conclusion
PARr VII -LOAD/RESOURCE AND SYSTEM COST ANALYSES
Introduction .............. .
Basic Data and Assumptions
Study Methodology
Results ......... .
toad/Resource Analyses
System Power Costs
PART VIII -INVESTMENT COSTS
PART IX -OPERATION, MAINTENANCE,
AND COSTS •.•..•.•
Operation and Maintenance
AND REPLACEMENT PLAN
Ill! • & • Plan Description ••• , ••
Marketing and Administration ...................
Annual Costs . , .......... , ..... . ! ••••••••••••••••••
R~placem~nts ~ ..... ~., .... ~ ....... . ., •••••••••••• !!•••"!
PART X -FINANCIAL AN~LYSIS ............
Market for Project Power ••••.•.
Cost of :j?roj ect •• , ••••••••••.•
Average Rate Determipation
Power Marketing CopS~iderations ••..••
Market Aspects of Other Transmission Alternatives
Anchorage-Cook Inlet Area •••••.••...•...•.•.•.
Comparisop of Susitna to Steamp~ants With and Without
Inflation ...... a ••••••••••••••••••••••••••••••••••• ~.
PART XI-GLENNALLEN-VALDEZ AREA ••••
Introductton •.....•........•......
Power Ma+ket A+e~ ..................... .
Power Req4ire~ents ••••••••••••••
Transmiss~on Plap apd Cost •••••• . ................. .
Operation and Maintenance
Assessment of Feasibility
Cost ..........................
AfPENDIX ••••••••••••••••• I! •• 41! •••
73
73
73
73
74
75
75
75
·77
79
79
79
86
89
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89
90
90
91
97
97
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101
102
105
105
106
108
108
108
109
110
114
116
117
1. Letter dated January 3, 1979 to Col.
District Corps of Engineers, transmitting
faJ,.l~ng in AP~'s a+"ea of responsib:i,l:i,.ty.
G.R. Robertson, AJ,.ask&
responses to OMB questio.n,s
ii
!
2. Previous Studies and Bibliography.
3. LOAD/RESOURCE AND SYSTEM COST ANALYSIS FOR THE RAILBELT REGION
OF ALASKA: 1978~2010 --Informal Report--by Battelle Pacific Northwest
Laboratories, Richland, Washington -January, 1979.
4. Comments.
a. Federal Energy Regulatory Commission, San Francisco, California.
b. Battelle Pacific Northwest Laboratories, Richland, Washington.
c. Corps of Engineers, Anchorage, Alaska
d. The Alaska State Clearinghouse, Juneau, Alaska
e. Municipal Light and Power, Anchorage, Alaska
iii
TABLES
NUMBER
1.
2.
RAILBELT AREA GENERATION CAPACITY SUMMARY -1977
BASIC POWER AND ENERGY FORECASTING DATA
ANCHORAGE-COOK INLET AREA (INCLUDING SEWARD)
3. BASIC POWER AND ENERGY FORECASTING DATA
PAGE NO.
14
18
FAIRBANKS-TANANA VALLEY AREA.......................... 19
4. BASIC POWER AND ENERGY FORECASTING DATA
Xl~LBELT AREA (ANCHORAGE-COOK INLET AND
FAIRBANKS-TANANA VALLEY) . . . . . • • • . . • • . . . . • • . • . . . • • • . • • • 20
5. NET GENERATION (GWH)
ANCHORAGE-COOK INLET AREA • • . . . . . • . . . . . • . • . • • . . . . • . • • • . 21
6. NET GENERATION (GWH)
FAIRBANKS-TANANA VALLEY AREA.......................... 22
7. AVERAGE ANNUAL UTILITY GROWTH SUMMARY................. 26
8. POPULATION ESTIMATES 1980-2025 •.....•••••••••••••••••• 34
9. • NET ANNUAL PER CAPITA GENERATION (KWH)
RAILBELT AREA UTILITIES .... .'. .. .. .. .. . .. .. • • • . • . • • . • • • 39
10. POWER AND ENERGY REQUIRE~ffiNTS
(ANCHORAGE-COOK INLET AREA) • • • • • • • • . • • • . • • • • • • • • • • • • • • 40
11. POWER AND ENERGY REQUIRE~NTS
(FAIRBANKS-TANANA VALLEY AREA)
12. RAILBELT AREA POWER AND ENERGY REQUIRE~NTS
ANCHORAGE-COOK INLET AREA AND FAIRBANKS-TANANA VALLEY
43
AREA COMBINED ••••••••••••••.•.•..•.••• G • • • • • • • • • • • • • • • 4 6
13. COMPARISON OF UTILITY ENERGY ESTIMATES,
1975 MARKETABILITY REPORT, UPDATE OF 1975,
AND 1978 ANALYSIS •••.• lit •••• I •••••••••••••••••• 0....... 49
14. UTILITY ENERGY FORECASTS (GWH)
ANCHORAGE-COOK INLET AREA .•.••.••••••••••••••••••••••. 52
15. UTILITY PEAK DEMAND FORECASTS (MW)
ANCHORAGE-COOK INLET AREA ••••••••••••••••••••••••••••• 53
16. UTILITY ENERGY AND PEAK DEMAND FORECASTS
FAIRBANKS-TANANA VALLEY AREA •••••••••••••••••••••••••• 54
iv
TABLES (Continued)
NUM,BER
17 .. LOAD DISTRIBUTION CHARACTERISTICS
MONTHLY PEAK LOADS AND LOAD FACTORS
18. MONTHLY ENERGY REQUIREMENTS AS PERCENT OF ANNUAL
PAGE NO.
59
REQUIREMENT •.•..•..... ~ • ., .. II ••••••••••••••• 0 • • • • • • • • • • 60
19. COMPARISON OF INVESTMENT COSTS FOR COAL-FIRED
STE.AtfPLANTS •••.•••.••.••..••......•. ~ • . • . . • • . • . . . . • . . . 65
20. GENERATION COSTS FOR CONVENTIONAL COAL-FIRED
STE~LANTS ..............................•...•... o • • • • 69
21. SUMMARY OF THERMAL GENERATING CAPACITY ADDITIONS TO
THE YEAR 2010 . . . . . • . . . . . . . • . . . . . . . . . • . • • • . • . . • . . • . • . . . 78
22. ANNUAL POWER SYSTEM COSTS -0% INFLATION
(COMBINED ANCHORAGE-COOK INLET AND FAIRBANKS-TANANA
VALLEY AREAS) .. • ..•.•. ~................................. 81
23. AVERAGE POWER COSTS ANCHORAGE-COOK INLET
AREA -0% INFLATION ..•.. , ..•..... ·• • . • . • • . • . . • • • • . . . • . • 83
24. AVERAGE POWER COSTS -0% INFLATION
FAIRBANKS-TANANA VALLEY AREA.......................... 84
24a. COMBINED ANCHORAGE-COOK INLET AND FAIRBANKS-TANANA
VALLEY AREA AVERAGE ANNUAL POWER COSTS .•....•••....•.• 85
25. CONSTRUCTION COST SUMMARY . . • . . . . . . . . • . . • • • . • . . . . . . • . . • 8 7
26. INVESTMENT COST SUMMARY . . • . • . • . • • • • . . • . • . . • • . • . . • . • • • . 88
27. ANNUAL OPERATION AND MAINTENANCE COST ESTIMATE .•.•...• 92
28. OPERATION AND MAINTENANCE COST SUMMARY................ 95
2 9. REPLACEMENT COSTS . . • . • • . • • . . . • • • • • • • • . • • • . • • • • • • . • • • • • 9 6
30. MARKET FOR UPPER SUSITNA POWER (ANCHORAGE AND
FAIRBANKS AREAS) MEDIUM LOAD GROWTH ESTIMATES 99
31. INVESTMENT A.t.'TD OM&R COST SUMMARY .. .. .. .. .. .. • . . • .. • .. • 100
32. COST SUMMARY COMPARISON WITH 1976 INTERIM
FEASIBILITY REPORT .•........•....•..•• ~............... 103
33. AVERAGE RATE DETERMINATION
(WATANA AND DEVIL CANYON) . • • • . . • • • • • • . . • . • • • • • • . • . • . . . 104
v
TABLES (Continued)
NUMBER PAGE NO.
34. HISTORIC DATA (GLENNALLEN-VALDEZ AREA) •...••.••••••••. 111
35. UTILITY NET GENERATION (GWH)
(GLENNALLEN-VALDEZ AREA) , .•••...••........•.•••••••.•• I 112
·i
36. UTILITY FORECASTS (VALDEZ-GLENNALLEN AREA) ..••.••••••• 113
37. TRANSMISSION SYSTEM INVESTMENT COST SUMMARY
(GLENNALLEN-VALDEZ AREA) • • • . • • . . • • • • . . • • . . • • . . • • • • . • • . 114
38. TRANSMISSION SYSTEM OPERATION, MAINTENANCE, AND
REPLACEMENT COST SUMMARY (GLENNALLEN-VALDEZ AREA) ....• 115
vi
FIGURES
NUMBER PAGE NO.
1. UPPER SUSITNA RIVER BASIN PROJECT
FEATURE SITE LOCATION ...... , . . . . . . • . . . • . • . . • . • • . . • . . • . viii
2. UPPER SUSITNA.RIVER PROJECT AREAS PRESENTLY
SERVED BY RAILBELT UTILITIES .....••••..•••••••.. :. • • . • 11
3. ENERGY SECTOR RATIOS ANCHORAGE-COOK INLET AREAS AND
ANNUAL ENERGY GENERATED OR SOLD ANCHORAGE-COOK INLET
AREA·~········································ .. ······· 27
4. ANNUAL ENERGY USE PER CAPITA & PER CUSTOMER
ANCHORAGE-COOK INLET AREA • • . . . . • • • • • . . • . • • • • • • • • • • • . • . 28
5. ANNUAL POPULATION, EMPLOYMENT, AND UTILITY CUSTOMERS
ANCHORAGE-COOK INLET AREA............................. 29
6. ENERGY SECTOR RATIOS FAIRBANKS-TANANA VALLEY AREA
AND ANNUAL ENERGY GENERATED OR SOLD FAIRBANKS-TANANA
VALLEY .AREA . • . .. . • . . • . • . • • . . . . . . . • • • . . • . . . • . • . • • • • • . . . . 3 0
7. ANNUAL ENERGY USE PER CAPITA AND PER CUSTOMER
FAIRBANKS-TANANA VALLEY AREA.......................... 31
8. ANNUAL POPULATION, EMPLOYMENT, AND UTILITY CUSTOMERS
FAIRBANKS-TANANA VALLEY AREA.......................... 32
9. ENERGY FORECAST ANCHORAGE-COOK INLET AREA............. 41
10. PEAK LOAD FORECAST &~CHORAGE-COOK INLET AREA 42
11. ENERGY FORECAST FAIRBANKS-TANANA VALLEY AREA 44
12. PEAK LOAD FORECAST FAIRBANKS-TANANA VALLEY AREA • • • • • . . 45 •
13. TOTAL RAILBELT AREA ENERGY FORECAST................... 47
14. TOTAL RAILBELT AREA PEAK LOAD FORECAST ••••.••••..••••• 48
15. SYSTEM DAILY GENERATION CURVE ANCHORAGE AREA 1976 ••••• 56
. 16. SYSTEM DAILY GENERATION CURVE ANCHORAGE AREA 1977-78 • • 57
17. LOAD DURATION CURVE -19 77 ANCHORAGE AREA
18. ANNUAL POWER SYSTEM COSTS WITH AND WITHOUT SUSITNA
COMBINED ANCHORAGE-COOK INLET AND FAIRBANKS-TANANA
58
VALLEY • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • 82
19. COMPARISON OF SUSITNA AND ALTERNATIVE COAL-FIRED
STEAMPLANT RATES CONSIDERING 5% ANNUAL INFLATION
vii
107
viii.
DEVIL
CANYON
Figure 1
DAM SITE~~
" WATANA
DAM SITE
\
ALA-~1$1 POWER .ADMIN IS TRA TION
Project Power Market Analysis
PROJECT FEATURE
Sl TE LOCATIONS
SCALE
~·--·--·---:::.
0 50 •OOMi!l!'t
APA 12/78
PART I. INTRGDUCTION
The Interim Feasibility Report of the Upper Susitna River Basin Project
(1976 report) was completed by the Alaska District Corps of Engineers
(Corps) in 1976. Alaska Power Administration (APA) provided the trans-
mission system and power market analyses for that report.
The Corps submitted the 1976 report to the Office of Management and
Budget (OMB) for. review. In September 1977, OMB requested the Corps
obtain additional data before submitting the report to Congress. The
requested data were to: (1) provide additional geologic data for the
Watana damsite; (2) reanalyze the cost estimate contingency factor; (3)
reanalyze area development benefits; and ( 4) reanalyze the projected
construction schedule. There were also questions about power supply and
demand, including. sensitivity to developing a large block of power in
APA's area of responsibility.
This report updates the power market analysis and addresses OMB
concerns. It uses three years additional data on power usage, effects
of the oil embargo, and other factors. Specifically, it (1) updates the.
power demand forecasts reflecting data since the 1976 report; (2)
updates the transmission and project OM&R costs; (3) presents
load/resource analyses to determine timing of major generation and
transmission investments and reflect resulting impacts on power system
costs; (4) presents system power c.ost analyses that show annual
system-wide costs of power with and without the Upper Susitna Project;
(5) examines the value of an Anchorage to Fairbanks interconnection with
and without Susitna; (6) provides a subanalysis of the feasibility of
delivering Susitna power to the Valdez-Glennallen area; (7) determines
power rates and marketability of Susitna power compared with alternative
generation methods; and (8) responds to the OMB questions in APA's areas
of responsibi~ity.
APA gave the Corps, for their report purposes: updated transmission
system costs and project OM&R estimates; load estimates; detailed
load/resource and system cost analyses with and without Susitna project;
and proposed responses to OMB questions pertinent to APA areas of
responsibility.
The Corps' current proposal for the Upper Susitna Project is essentially
the same as plan 5 in the 1976 report: a two-phase, two-dam complex
including Watana and Devil Canyon dams and powerplants, with the Watana
phase· a-nd .. a _.transmission' system interconnecting Anchorage and Fairbanks·
coming on-line first. Power production facilities include Watana dam,
reservoir, and powerplant, and Devil Canyon dam, reservoir, and
powerp lant. Watana dam would be an earthfill structure with reservoir
normal water surface elevation of 2,185 feet; the powerplant would have
795 MW capacity. Devil Canyon dam would be a double-curvature
concrete-arch structure with maximum pool elevation of 1,450 feet,
providing water for a 778-~~ powerplant. The transmission system would
be constructed in conjunction with the first stage (Watana), and,
1
as planned, would be totally required for system reliablilty. The
system would incude two parallel 230-kv single circuit lines from Watana
to Devil Canyon (30 miles), two parallel single circuit 345-kv lines
from Devil Canyon to Pt. McKenzie (Anchorage, 135 miles), and two
parallel single circuit 230-kv lines from Devil Canyon to Ester-Gold
Hill (Fairbanks, 198 miles).
Several significant changes were made by the Corps since -t;he 1976
report:
(1) The Devil Canyon dam design and costs are presented for both a
gravity struc·ture and a thin-arch concrete structure. The 1976 report
was based on a thin-arch concrete structure.
(2) The construction period for Watana was increased from 6 years to
ll;.Devil Canyon from 4 years to 7; and the Anchorage-Fairbanks intertie
re-scheduled for 1991--three years before Watana POL.
(3) Watana dam (earth fill) was redesigned, based on new geologic data.
The APA power market report uses certain assmnptions that differ from
the Corps plan, namely:
(1) Design power generation capacity_: The Corps design capacity is
based on critical year primary energy and 50 percent annual plant factor
(1,392 MW). The APA load/resource analyses assume a design capacity
based on average annual energy and 50 perce~t plant factor (1 ,573 MW).
APA analyses include both primary and secondary energy as well as firm
and n~:m-firm power. ·
(2)-Transmission intertie schedule:
The Corps plans show a 1991 on-line date for the transmission intertie.
The APA system cost analyses examine alternative on-line dates of 1990,
1992, and 1994. The load/resource analysis showed the earliest intertie
dates could be 1986, 1989, and 1991. APA financial analyses are
consistent with the Corps schedule •
• (3) For Devil Canyon Design:
The APA system cost and financial analyses assume the thin-arch design
for Devil Canyon as presented in the 1976 report, rather than the more
costly gravity structure alternative now being used by the Corps for
feasibility testing. A separate analysis demonstrates the effect of the
gravity dam alternative on cost of power.
The term "1976 report" is used throughout this report. This term refers
to the Corps of Engineers Interim Feasibility Report on the Upper
Susitna project, dated Decemb~r 1975, revised June 1976. It also refers
to APA's Power Market analysis dated 1975 and included as Appendix G in
the revised Interim Feasibility Report.
2
Part II. SUMMARY
Current studies have updated and revised the power market analyses of
the 1976 Upper Sus tina Report (1976 report). New estimates of power
requirements through the year 2025 have been prepared.
The 1976 report used energy and power estimates based on data through
December 1974. The new analyses benefit from three full years of
additional data through December 1977. This provides a full four years
of "post oil-embargo" data--especially significant from the viewpoint of
identifying conservation trends. Evidence of conservation shows in the
Anchorage-Cook Inlet area growth comparisons before and after the
1973-74 fuel cr~s~s. The 1970-73 average annual growth in . net
generation dropped from 14.2 percent to 12.7 percent in the 1973-77
period. The decrease was more dramatic for per capita net generation:
A drop from 8 percent to 3.8 percent.
Because the net generation kwh/capita raio seemed to reflect the closest
correlations, particularly in recent years, this ratio and population
were used to forecast net generation values between 1980 and 2025.
The following Railbelt totals are detailed in Part V. Trended values
offer an interesting comparison but are not presented as part of the
forecast. The trend is an average annual growth of 12.3 percent
resulting from 12.7 percent for the Anchorage area and 10.5 percent for
the Fairbanks area.
Utility:
High
Mid
Low
National Defense:
High
Mid
Low
Railbelt Area Energy Forecast
(GWH)
1977 1980 1990
(Historic)
3,410 8,200
2,273 3,155 6,110
2,920 4,550
348 384
338 338 338
330 299
Self-Supplied Industry:
High 170 2,100
Mid 70 170 630
Low 141 370
Total:
High 3, 928 10,684
Mid 2, 681 3,663 7,078
Low 3,391 5,219
Trend @ 1973-77 annual/growth: (3,215) (10,270)
3
2000 2025
16,920 38,020
10,940 . 17' 770
7,070 8,110
425 544
338 338
270 210
3,590 8,490
1,460 3,470
550 1,310
20,935 47,054
12,738 21,578
7,890 9,630
(33,000) (601,000)
Area load characteristics data were updated and new estimates of monthly
energy distribution were made. The conclusion was that the 50 percent
plant factor sizing assumption is still valid.
A further review of possible power supply alternatives included oil and
natural gas, coal, alternative· hydro projects, nuclear, wind,
geothermal, and tide. It concluded again that coal-fired steam plants
are the most logical alternatives for major railbelt area power supplies
in the proposed Susitna project timeframe.
New estimates of cost of power from coal-fired steamplants were prepared
using results of several recent studies. They indicate:
Investment costs of $1,620-$1,860/kw
Unit cost of power of 5.2-6.4¢/kwh (including transmission to
load center)
A set of load/resource and annual system cost analyses were performed to
examinE;! the ·effects of Susitna and the transmission intertie from an
overall power system approach. These analyses were needed to provide
responses to OMB questions regarding: (1) the value of an
interconnected trq.nsmission system between Anchorage and Fairbanks; (2)
scheduling of major powerplants; and, (3) sensitivity of developing
large blocks of power. APA' s resp.onse to the OMB questions are
appended. Three cases were analyzed using three projected load growth
estimates:
Case 1. A without Sus i tna Project and without transmission intertie
situation assuming all generating capacity to be supplied by coal-fired
steamplants.
Case 2. Same as case 1 but with transmission intertie.
Case 3. A with Susitna Project and with intertie situation assuming
additional generating capacity supplied by coal-fired steamplants.
The load/resource· analyses showed the schedule of new plant additions
needed for all three cases for 1978-2011.
The system cost analyses compared annual power system costs for all
three cases, assuming 0 and 5 percent inflation rates. The analyses
showed annual system cost savings of $2.23 billion between 1990 and
2011~ with the Susitna project. Average power system rates for the year
2000 assuming no inflation will be:
4
Load
Forecast
High
Mid
Low
Case 1
Without .susi tna
or Intertie
6.6 1/
6.9 T!
7.5 1/
¢/KWH
Case 2
Wi.thout Sustina
With Intertie
6.4
6.6
6.7
Case 3
With Susitna
and Intertie
5.8
5.7
6.4
J:../ Anchorage and Fairbanks are not interconnected for case
combined system rate. is shown for academic purposes. only.
1· ·' the
For the medium energy use range, system rates, compared to those without
Susitna or interconnections, will be 5.7 1 / percent· less with
interconnections 18.6 percent less with Susitna.-The analyses showed
Susitna will result in cheaper power cost to Anchorage and -Fairbanks in
all load growth cases. It also shows that the P:f,Pj ect power could be
fully used unde~ all projected power demand cases.-
In comparison with the 1976 report, investment costs are 89 percent
($1.567 billion) greater. Contributing factors are: interest rate
increase from 6 5/8 to 7 1/2 percent total construction period increase
from 6 years to 10 years, cost inflation; and redesign of Watana dam and
powerplant facilities. New construction cost estimates for Watana dam
(containing effects of both design quanitity changes and unit cost
inflation) are $595 million (72 percent) higher. Construction cost
estimates for Devil Canyon dam (thin-arch concrete) power plant
facilities, and the transmission system were updated primarily by
indexing. This resulted in a 54 percent increase over the 1976 report·
($233 million for Devil Canyon and $82 million for the transmission
system). The.total interest during construction increase is 265 percent
($657 million). In summary, the increases in construction costs are:
Watana
Devil Canyon
Transmission System
Interest during Construction
Total
$ 595
233
82
657
$1567
million
"
"
II
million project investment
cost increase
Financial analyses were based on the October 1978 price level, Fiscal
Year 1979 .Federal· interest rate of 7 1/2 percent, intertie in 1991 or
1992, and repayment of all principal and interest within 50 years after
the last unit is installed.
}j Case 2 Value (6.6%) -1
Case 1 Value (7.0%)
-5.7%; Case 3 Value (5.7%) -1 = -18.6%
Case 1 Value (7.0%)
l:_/ Interconnection benefits leading to lower rates involve load supply
flexibility, economics of scale and operations, decreased reserve
requirements, and better reliability.
5
A comparison of the rate for Sustina at 4. 7¢/kwh with the coal-fired
steamplant alternative at 5.2/kwh to 6.4¢/kwh shows Susitna is 1,ess
costly.
The Glennallen-Valdez ar.ea was considered as a market area supplementary
to the Railbelt. The .Copper Valley Electric Association (CVEA) plans to
construct a Glennallen-Valdez transmission line, and the presence of the
pipeline terminal in Valdez with its related economy has made this area
a more attractive market since the 1976 report. Service to the area
would require a 138-kv line from Palmer to Glennallen (136 miles). Area
market factors are subject to fluctuation. Potential industrial loads
are difficult to project at this time, but service to utility loads can
be evaluated for a probable range of demands. Energy costs to serve the
incremental market area will range from 2.6¢/kwh to 1.3¢/kwh for a range
of loads from 150 to 300 kwh/year in addition to the project energy cost
of ·4. 7¢/kwh. Inclusion of the market area costs with other project
costs for a sing~e project-wide rate would not adversely arfect the
rate.
6
PART II I. POWER MARKET AREAS
Throughout its history of investigations, the Upper Susitna River Basin
Project has been of interest for hydroelectric power generation because
of its central location to the Fairbanks and Anchorage areas. These
areas have Alaska's largest concentrations of population, economic
activity, services, and industry. Under any plan of development, major
portions of the project power will be used in these two areas. In
addition, the basic project transmission system serving Anchorage and
Fairbanks could provide electric service to present and future
developments between the two cities.
The potential major market areas are the Anchorage-Cook Inlet area and
the Fairbanks-Tanana Valley area.
Ancho.rage-Cook Inlet Area
This area includes the developed areas of the Matanuska Valley, Greater
Anchorage Area, and Kenai Peninsula.
This general area has been the focal point for most of the State 1 s
growth in terms of population, business, services, and industry since
World War II. Major building of defense installations, expansion of
government services, discovery and development of natural gas and oil in
the Cook Inlet area, and emergence of Anchorage as the State's center of
government, finance, travel, and tourism are major elements in the
history of this area.
Because of its central role in business, commerce, and government, the
Anchorage area is directly influenced by economic activity elsewhere in
the State. Much of the buildup in construction and operation of the
Alyeska pipeline, much of the growth related to Cook Inlet oil
development, and much of the growth in State and local government
services since Statehood has occurred in the immediate Anchorage
vicinity.
Initially, economists overestimated the impacts of completion of the
trans-Alaska oil pipeline. In a recent study prepared by the University
of Alaska Institute of Social and Economic Research, the projected 1980
population for Anchorage-Cook Inlet was lower than that of the
historical 1977 population. Though this has been corrected, it
indicates that the area's economy has been stronger than anticiapted.
The Greater Anchorage Area Borough estimated its July 1, 1977 population
.at 195,800, an increase of nearly 55 percent since the 1970 census. This
was more than 48 percent of the total estimated State population in
1977.
7
The Matanuska Valley includes several small cities (Palmer, Wasilla,
Talkeetna) and the State's largest agricultural community. Other
economic activities include recreation and light manufacturing. Much
recent growth in the Borough has been in residential and recreational
homes for workers in the Anchorage area. Estimated 1977 population was
15,740, a 61 percent increase since 1974.
The Kenai Peninsula Borough includes the cities of Kenai, Soldotna,
Homer, Seldovia, and Seward; with important fisheries, oil and gas, and
recreation resources. Estimated 1977 population was 23,100, a 39
percent increase since 1974.
Present and proposed activities indicate likelihood of rapid growth in
this general Cook Inlet area for the future. Much of this activity is
related to oil and natural gas, including expansion of the refineries.
The State capital city site relocation issue remains unresolved. In the
November 1978 general election, voters turned down the $966 million bond
issue to relocate the capital. In the same election, voters approved an
initiative which would require full disclosure of the costs to move the
capital. Therefore, it is impossible at this time to include specific
assumptions concerning the capital move.
The area will continue to serve as the transportation hub of western
Alaska, and tourism will likely continue to increase rapidly. Major
local development seems probable.
Fairbanks-Tanana Valley Area ·
Fairbanks is Alaska's second largest city-the trade center for much of
Alaska's Interior, the service center for several major military bases,
and the site of the main campus of the Un.'iversi ty of Alaska with its
associated research center. The outlying communities of Nenana, Clear,
North Pole, and Delta Junction are included in the Fairbanks-Tanana
Valley area. Historically, the area is famous for its gold.
The completion of the pipeline construction has taken its toll in
Fairbanks. The area is experiencing a severely depressed economy.
Employment in the construction industry has decreased to half of the
previous pipeline level. There has been a slight increase in employment
generated by government, distributive industries, and retail trade. In
1977-78, Fairbanks and its outlying areas experienced a 16 percent
decline in population.
The decision favoring the ALCAN route for the proposed natural gas
pipeline was made in late 1977. The proposed gas pipeline will follow
the route of the trans-Alaska oil pipeline route from Prudhoe Bay to
Delta Junction. Fairbanks has been selected as the operation
headquarters by the Northwest Pipeline Company, responsible for
construction and operation of the gas pipeline. The Fairbanks-Tanana
Valley area will probably be heavily impacted again by the pipeline
construction; however, a more stable permanent employment base is likely
to become established.
8
The Fairbanks-North Star Borough had an estimated. 1977 population of
44,262 and an estimated additional 8, 000 in the outlying communities
within the power market area. The total population decreased 10 percent
since 1974.
9
PART IV. EXISTING POWER SYSTEMS
Utility Systems and Service Areas
The electric utilities in the Rail belt power market area are listed
below, and areas now receiving electric service are shown on figure 2.
A detailed listing of power generating units is in the appended Battelle
report, table 3.4.
Anchorage-Cook Inlet Area
Alaska Power Administration (APA)
Anchorage Municipal Light and Power (AML&P)
Chugach Electric Association (CEA)
Matanuska Electric Association (MEA)
Homer Electric Association (HEA)
Homer (Standby)
Seldovia, English Bay, Port Graham
Seward Electric System (SES)
Fairbanks-Tanana Valley Area
Fairbanks Municipal Utility System (FMUS)
Golden Valley Electric Association (GVEA)
l/ Major generation supplied by CEA system.
Installed
Nameplate 21 Capacity MW -
. 30.0
121.1
345.7
])
0.3 l/
1.8
5.5 y
69.6
219.2
1J Consists of 45 MW hydro. All the rest are fuel-fired (80% gas turbine).
10
11
Figure 2
ALA,SKA POWER ADMINISTRATION
Project Power Market Analysis
AREAS PRESENTLY SERVED
BY RAILBELT UTILITIES
APA 12/78
0
These totals differ from the Battelle appended report because the report
includes some planned units not installed in 1977 as well as use of some
ratings other than nameplate.
APA operates the Eklutna hydroelectric project and markets wholesale
power to CEA, AML&P, and MEA.
AML&P serves the Anchorage Municipal area. CEA supplies power to the
Anchorage suburbs and surrounding rural areas, and provides power at
wholesale rates to HEA, SES, and MEA. The HEA service area covers the
western portion of the Kenai Peninsula, including Seldovia, across the
bay from Homer: MEA serves the town of Palmer and the surrounding rural
area in the Matanuska and Susitna Valleys.
The utilities serving the Anchorage-Cook Inlet area are now loosely
int·erconnected through facilities of APA and CEA. An emergency tie is
avaiiable bet~een the AML&P and Anchorage area military installations.
FMUS serves the Fairbanks municipal area, while GVEA provides service to
the rural areas. The Fairbanks area power suppliers have the most
complete power pooling agreement in the State. FMUS, GVEA, the Univer-
sity of Alaska, and most of the military bases have an arrangement which
includes provisions for sharing reserves and energy interchange.
The delivery point for Upper Susitna p'ower to the GVEA and FMUS systems
is assumed at a substation of GVEA near Fairbanks.
Other small power generating systems in the Fairbanks-Tanana Valley area
were included in determining the power requirements of the region. They
include:
Fairbanks-Tanana Valley Area
Alaska Power and Telephone Company
(Tok and Dot Lake vicinity)
Northway Power and Light Company
(Northway vicinity) 0
National Defense Power Systems
Installed
Capacity MW
2.28
0.48
The six major national defense installations in the power market area
are:
Anchorage area--
Elmendorf Air Force Base
Fort Richardson
12
Fairbanks area--
Clear Air Force Base
Eielson Air Force Base
Fort Greely
Fort Wainwright
Each major base has its own steamplant that is used for power and for
central space heating. Except for Clear Air Force Base, each is inter-
connected with the local utility. Numerous small isolated installations
are not included in this study.
In the past, national defense electric generation has been a major
portion of the total installed capacity. With the projected stability
of military sites and the growtq of the utilities, the national defense
installation will become a less significant part of the total generating
capacity.
Industrial Power Systems
Three industrial plants on the Kenai Peninsula maintain their own power-
plants, but are interconnected with the REA system. The Union 76
Chemical Division plant generates its basic power to satisfy its energy
needs, receiving only standby capacity from REA. The Kenai liquified
natural gas plant buys energy from REA, but has i~s own standby
generation. Tesoro Refinery buys from REA and also satisfies part of
its own needs.
Other self-supplied industrial · generators include oil platform and
pipeline terminal facilities in the Cook Inlet area.
Existing Generation Capacity
Table 1 provides a summary of existing generating capacity. The table
was generally current as of 1978; The Anchorage-Cook Inlet area-had a
total utility installed capacity of 504.5 MW in 1977-78. Natural
gas-fired turbines were the predominant energy source with 435.1 MW.
Hydroelectric capacity of 45 MW was available from two projects, Eklutna
and Cooper Lake. Steam turbines comprised 14.5 MW. Diesel generation,
mostly in standby service, accounted for the remaining 9.8 MW.
The Fairbanks-Tanana Valley area utilities had a total installed
capacity of 288.8 MW in 1977. Gas turbines (oil-fired) provided the
largest block of power in the area with an installed capacity of 203.1
MW. Steam turbine generation provided 53.5 MW of power and diesel
generators contributed 32.1 MW to the area.
13
Area
Table 1
~ILBELT AREA GENERATION CAPACITY
Sununary -1977
Upper Susitna Project Power Market Analysis
Installed Capacity -
Diesel Gas
Hydro Int. Comb. Turbine
MW
Steam
Turbine
Anchorage-Cook Inlet
Utility System 45.0 9.8 435·.1 14.5
National Defense 9.2 40.5 ..
Industrial System 10.2 14.8
Subtotal 45.0 29.3 449.9 55.0
Fairbanks-Tanana Valley
Utility System 32.1 203.1 53.5
National Defense 14.0 63.0
Subtotal 46.1 203.1 116.5
Notes: The majority of the diesel generation is in standby status.
Rounding causes differences between sununations of the parts
and the totals shown.
Source: Utility reports to Alaska Public Utility Commission to the
Department of Energy, the Alaska Air Command, the oil and gas
companies, and APA files.
(Minor differences exist between this table and the appended Ba~telle
Report.)
Total
504.5
49.7
25.0
57·9. 2
288.8
77.0
365.8
APA 11/78
14
Planned Generation Capacity
The two major utilities in the Anchorage-Cook Inlet area, A~L&P and CEA,
plan to add a total of approximately 420 MW installed capacity to their
existing system between 1979 and 1985. A~&P plans to add a 16.5-M\~
combined cycle system to their existing combustion turbine. In
addition, CEA has plans to complete the 230-kv interconnection loop with
MEA.
In December 1978, GVEA decided to postpone development of their proposed
Healy II steam turbine system (104 MW) until more favorable economic
conditions prevail ..
A unit by unit breakdown of planned generating systems is presented in
the appended Battelle report, table 3.8.
15
PART V. POWER REQUIREMENTS
I
Introduction
This summarizes the analyses of historic data and estimates of future
needs in the p.ower market areas. The study examines in detail electric
utility statistics 1970 to 1977 with special effort to identify changes
in use patterns related to conservation measures since the 1973 oil
embargo.
Estimates of future utility power needs are derived from estimates of
individual energy use and area population. Population projections were
developed by the University of Alaska, Institute of Social and Economic
Research (ISER). The individual use forecast was estimated by assumed
conservation-induced changes in kwh/capita growth rates. The end
results are forecasts of net generation (kwh) and peak load demand (kw).
The three energy use sectors analyzed in this study are:
Utility Includes all utilities which serve residential and
commercial/industrial customers •.
National Defense -Includes all military installations.
Self-Supplied Industry -Includes limited number of heavy industries,
i.e., natural gas and oil processing industries on the Kenai Peninsula
which generate their own power. The study assumes that these industries
will purchase energy if it ·becomes economically feasible. Some have
interchange agreements with local utilities.
Evaluations of monthly energy distribution and installed capacity
requirements are included and are premised on characteristics of area
power demands.
Data
This presents the basic parameters used in the analyses leading to the
Susitna Power Harket forecast assumptions.
The historical data summarizes the Anchorage-Cook Inlet and
Fairbanks-Tanana Valley areas which comprise the Railbelt area. Each
area is divided into utility, national defense, and self-supplied
industrial components (Fairbanks-Tanana Valley area has no known
significant self-supplied industries).
The utility component is divided into four sectors: ResidentiC\_l,
Commercial-Industrial, Total Sales, and Net Generation.
16
0
'
Dat~ wa~ collected from utility and industry reports to various
government agencies, from utilities directly, from Alaska military
commands, by correspondence with industry, and from various statistical
publications and news media.
Basic data needed for the 1970-1977 analysis are presented on tables 2,
3, and 4 included is utility annual energy and customers for each
sector, national defense and industrial annual energy consumption,
utility and national defense annual peak load, industrial installed
capacity, annual population, and average annual employment, In
addition, utility net generation, listed on tables 5 and 6, was compiled
for the 1960-1977 period.
As part of the forecasting foundation, the following historical
chronology indicates fluctuations affecting Railbelt energy use.
1970. Uncertainty
construction, and approval.
Above averag.e temperature.
1971.
temperature.
Uncertainty
concerning the oil
Native land claims
pipeline design,
legislation pending.
concerning pipeline. Below average
1972. Uncertainty concerning pipeline. Coldest year of period.
1973. Start of fuel crisis and conservation publicity in December.
Below average temperature.
1974.
1975.
ture.
Start of pipeline construction. Near average temperature.
Peak of pipeline construction activity. Near average tempera-
1976. Start of pipeline construction 11 wind-down,11 Electric power
cable across Knik Arm out of service for an extended period (all but one
circuit). Above average temperature.
1977. Oil started flowing in pipeline. Warmest year of . period.
Residential construction boom in Anchorage. Large incre.ase. in
non-residential author·izations issued. . '
17
Table 2
BASIC POWER AND ENERGY FORECASTING DATA
ANCHORAGE-COOK INLET AREA (INCLUDING SEWARD)
Upper Susitna Project Power Market Analysis
Utility Energy Sales (GWH) Net Generation (GWH)
Year Resi. Comm./Indu. Total l/ Utility!/ Nat. Def. 11 Indu.
1970
1971
1972
1973
1974
1975
1976
1977
Year
1970
1971
1972
1973
1974
1975
1976
1977
1970
1971
1972
1973
1974
1975
1976
1977
310.5
369.7
421. 6.
459.5
496.1
595.1
677.6
741.0
342.3
393.9.
454.0
514.8
552.8
631.9
738.7
813.4
678.7
792.5
911.6
1,012.2
1,087.4
1,270.6
1,462.-2
1,600.8
744.1
886.9
1,003.8
1,108.5
1,189.7
1,413.0
1,615.3
1,790.1
Utility Customers
Resi. Comm./Indu.
39,271
42,501
46,724
49,307
52,585
56,801
61,881
68,320
5,230
5,581
6,104
6,491
6,798
7,478
8,220
9,221
Population
Civilian Total
135,963
145,108
155,084
160,162
165,938
196,320
207,090
222,424
149,428
159,046
167,765
174,280
179,544
209 '049
219,337
234,674
Total Utility
45,042
48,670
53,278
56,280
59,893
64,797
70,622
78,066
165.2
184.8
212.8
22·9.9
257.2
345.8
349 ."9
423.9
Employment
Avg. Annual
47,408
51,092
54,329
57,157
65,919
78,786
83,604
88,869
1/ Excludes deliveries to national defense.
156.2
161.2
166.5
160.6
155.1
132.8
140.3
130.6
Peak Load (MW)
Nat. Def.
34.6
33.9'
. 32.6
40.5
1. 65
45.3
45.3
69.5
Indu. !:;_!
12.3
12.3
12.3
24.8
Z/ Total retail sales of energy + non-revenue energy used + losses.
3! Includes receipts from utilities, excludes deliveries to utilities. !I Self-supplied industrial data is installed capacity rather than peak load.
GWH = million KWH
MW = thousand KW
KW = Kilowatt
18
APA 11/78
Table 3
BASIC POWER AND ENERGY FORECASTING DATA
FAIRBANKS-TANANA VALLEY AREA
Upper Susitna Project Power Market Analysis
Utility Energy Sales (GWH) Net Generation (GWH)
Year
1970
1971
1972
1973
1974
1975
1976
1977
Year
1970
1971
1972
1973
1974
1975
1976
1977
1970
1971
1972
. 1973
1974
1975
1976
1977
Resi. Comm. /Indu. Total];_/
91.7 108.3 210.2
112.4 119.8 244.3
122.3 127.3 262.9
134.4 139.5 282.3
155.8 150.3 323.0
193.0 196.3 409.2
195.9 204.2 420.5
200.7 221.6 442.7
Utility Customers
Resi. Comm. /Indu. Total
10,364 1' 721 12,268
11,014 1, 779 12,947
11,584 1, B39 13 '611
11,931 1,929 14,041
12,832 2,069 15,084
14,025 2,247 16,447
15,569. 2,435 18,179
16,709 2,580 19,463
Population Employment
Civi.l:i.an Total Avg. Annual
42,310 52,141 15,681
43,188 50,585 15,817
45,516 52,383 16,873
45,396 52,246 16,794
51,137 57,836 21,960
60,884 67,011 34,451
58,05l(e) 63,762 34,325
47,155(e) 52,155 27,385
1/ Excludes deliveries to national defense.
Z/ Total sales + non-revenue use + losses.
Utility ];_/ Nat. Def.
239.3 203.5
275.5 201.4
306.7 203.3
323.7 200.0
353.8 197.0
450.8 204.4
468.5 217.5
482.9 206.8
Peak Load (MW)
Utility Nat. Def.
56.3 44.4
65.3
66 •. 6' 41.4'
72.7
87.5 40.8
110.0
102.6
118.9 41.0
l_j
3!
4/
Includes receipts from utilities, excludes deliveries to utilities.
Self-supplied industrial data is installed capacity rather than peak load.
GWH = million KWH
MW = thousand KW
19
APA 9/78
Year
1970
1971
1972
1973
1974
1975
1976
1977
Year
1970
1971
1972
1973
1974
1975
1976
1977
1970
1971
1972
1973
1974
1975
1976
1977
Table 4
BASIC POvillR AND ENERGY FORECASTING DATA
RAILBELT AREA
Upper Susitna Project Power Market Analysis .
Utilit~ Energ~ Sales (GWH) Net Generation (GWH)
Resi. Comm. /Indu. Total Utility Nat. Def. Indu.
402.2 450.6 888.9 983.4 359.7 1.6
482.1 513.7 1,036.8 1,162.4 362.6 25 (e)
543.9 581.3 1,174.5 1,310.5 369.8 45.3
593.9' 654.3 1,294.5 1,432.2 360.6 45.3 (e)
651.9 703.1 .1,410.4 1,543.5 352.1 45.3
788.1 828.2 1,679.8 1,363.8 337.2 45.3(e)
873.5 942.9 1,882.7 2,083.8 357.8 45.3(e)
941.7 1,035.0 2,043.5 2,273.0 337.4 69.5
Utility Customers Peak Load (MW)
Resi. Comm./Indti. Total Utility Nat. Def. Indu.
49,635 6,951 57,310 221.5 79.0 12.3
53,515 7,380 61,617 250.1 77(e) 12.3(e)
58,308 7,943 66,889 279.4 75.3 12.3
61,238 8,420 70,321 302.6 74(e) 12.3(e)
65,417 8,867 74,977 344.7 73.4 12.3
70,826 9, 725 81,244 455.8 73 (e) 12.3(e)
77,450 10,654 88,801 452.5 76(e) 12.3(e)
85,029 11,801 97,529 542.8 81.5 24.8
Total Avg. Annual
Population Employment
201,569 63,089
209,631 66,909
220,148 71,202
226,526 73,951
237,380 87,879
276,060 113,237
283,099 117,929
286,829 116' 254
20
Total
1,344.7
1,550.0
1,725.6
1,838.1
1,940.9
2,246.3
2,486.9
2,679.9
Total
312.8
339.4
367.0
388.9
430.4
541.1
540.8
649.1
APA 11/78
N ,_.
Table 5
NET GENERATION (GWH)
ANCHORAGE-COOK INLET AREA
Upper Susitna Project Power Ma.rket Analysis
(Includes receipts of electric energy from military; excludes electric energy deliveries to military)
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
AML&P
CEA
APA
. MEA
HEA
KU
SES
AML&P CEA APA MEA
0.8 27.5 187.6 0.1
3.2 44.8 193.8 0.1
20.0 101.8 150.'3 0.2
55.7 100.5 152.7 0.2
97.3 94.5 146.1 0.5
101.2 16 7.4 132.1 0.6
108.6 204.6 138.2 0.7
100.1 217.1 178.5 0.8
125.3 280.0 155.5 0.8
148.1 314.6 158.2 0.9
186.0 385.5 15lf. 7 1.1
24_5.3 476.6 144.9 1.3
270.0 554.2 164.0 1.5
359.0 657.3 96.3 0.3
389.6. 678.4 1.1
384.3 888.8 135.1
442.9 1,054.5 118.5
420.3 1,179.7 203.6
-Anchorage Municipal Light and Power
-Chugach Electric Association
-Alaska Power Administration
-Matanuska Electric Association
-Homer Electric Association
-Kenai Utilities
-Seward Electric System
HEA KU SES Total Growth %
8.2 1.8 5. 7' 231.6
3.6 2.0 6.2 253.7 9.5
0 2.3 3.7 278.2 9.7
0 2.7 0 311.8 12.1
1.2 3.8 0 343.4 10.1
1.4 4.1 0 406.8 18.5
1.4 5.2 0 458.7 12.8
1.5 6.7 0 504.6 10.0
1.7 10.1 0 573.4 6.5
2.2 8.9 0.1 633.0 17.8
2.4 9.0 0.1 738.8 16.7
2.7 8.0 0.1 878.9 19.0
3.3 7.0 0. 1 • 1,000.1 13.8
3.6 0.1 1,116.5 11.6
4.2 0.1 1,197.4 7.2
3.4 3.2 1,414.9 18.2
0.5 1.5 1,617.3 14.3
0.5 0.8 1,804.9 11.5
APA 11-78
Table 6
NET GENERATION (GWH)
FAIRBANKS-TANANA VALLEY AREA
Upper Susitna Project Power Market Analysis
(Includes receipts of electric energy from military;
excludes electric energy deliveries to military)
Year FMU GVEA AP&T DLE NP&L Total Growth %
1960 36.7 24.4 0.1 0.6 61.8
1961 38.8 29.4 0.1 0.6 68.9 11.5
1962 42.3 33.3 1. 0.1 0.6 77.2 12.1
1963 45.4 39.1 1.2 0.1 0.6 86.4 11.9
1964 48.4 53.6 1.5 0.1 0.6 104.2 20.6
1965 49.5 56.6 1.8 0.1 0.6 108.6 4.2
1966 52.6 67.0 2.1 0.1 0.6 122.4 12.7
1967 55.9 75.9 2.0 0.2 0.6 134.6 10.0
1968 64.0 97.9 2.0 0.2 0.6 164.7 22.4
1969 72.2 118.1 2.1 0.2 0.6 193.3 17.4
1970 85.6 150.2 1.9 0.2 0.6 238.6 23.4
1971 106.7 164.9 2.4 0.2 0.6 274.7 15.1
1972 120.3 182.2 2.6 0.2 0.8 306.1 11.4
1973 115.4 202.2 2.7 0.2 0.9 321.4 5.0
1974 123.0 214.3 3.5 0.2 1.2 342.1 6.4
1975 137.2 28.6.9 3.9 0.2 1.6 429.7 25.6
1976 139.6 315.1 4.2 0.2 1.4 460.4 7.1
1977. 133.5 346.3 4.5 0.2 1.4 485.8 5.5
FMU -Fairbanks Municpal Utilities
GVEA -Golden Valley Electric Association
AP&T -Alaska Power and Telephone (Tok)
DLE -Dot Lake Electric (Purch~sed by AP&T in 1978)
NP&L -Northway Power artd Light
22
Detailed investigations
are listed in tables 2,
major sector (utility,
within each geographic
Utility
Analysis
of relationships among the basic data components
3 ,. and 4. Analysis was done separately for each
national defense, and self-supplied industry)
area.
The analysis of utility data set out to develop assumptions for fore-
casting net generation and peak load. Investigations evaluated the
impact of changes in population, employment, customers, weather,
tariffs, and other events upon energy use. These evaluations then
helped to: (1) determine if energy sectors (residential,
commercial-industrial, total sales) other than net generation needed to
be forecast; (2) determine which energy ratio (kwh/capita, kwh/employee,
kwh/customer) to use in the forecasting procedure; (3) develop
procedure for forecasting utility annual net generation from energy use
assumptions and demographic parameters (population, employees, or
customers); (4) determine load factor with which to calculate peak load
forecast from the net generation forecast.
Constants, small amplitude cycles, or trends in relationships among the
energy use and customer sectors were investigated for use as forecasting
aids. If, for instance, the residential energy use/net generation ratio
remained almost constant from 1970 through 1977, only net generation
need be subjected to the forecasting procedure. The same type of
analysis was applied to energy use ratios: a look for an average or
trend to be used as .a factor in forecasting net generation.
After developing the net generation forecast, the peak load forecast was
calculated using energy and an assumed load factor. Analysis of
historic load factors determined an average or trend from which the
assumed load factor was derived. Forecasted net generation and the
assumed future load factor were then used in the formula: Peak
load= 8,760 hr/yr. x load factor x net generation.
The evaluations showed a mix of similarity and contrast between the two
Railbelt areas. In both areas, the major energy use determinants were
the trans-Alaska oil pipeline construction and the fuel crisis of
1973-74. Other correlations with weather, tariffs, etc., seemed
insignificant. For instance, energy growth increased in some years
despite above average t·emperatures which reduced energy need.
Anchorage-Cook Inlet Area Analysis Results -The foregoing
procedures resulted in the following observations
Anchorage-Cook Inlet area.
23
evaluation
for the
(a) Observations indicate no significant shift· in energy use patterns
or in share of total load among the various utility sect.ors
(residential, etc.). The ratios among the sectors (residential/total
sales; total sales/net generation, etc.) remained ~ssentially constant
through the study period. This was true for both energy and customers.
Therefore, only one sector--net generation--represents all sectors in
the forecast.
(b) Energy rate of growth per customer and per capita had a significant
reduction after the 1973-74 fuel crisis. The 1973-77 per capita average
growth rate was about half that for 1970-73. It appears that
conservation can·be considered an influence after 1973.
(c) Events impinging upon energy use are listed in the previous
section. Between 1973 and 1977, several events bear repeating for
emphasis: fuel cr~sis in 1974; start of pipeline construction in 1974;
peak pipeline activity in 1975; decrease of pipeline activity in 1976
and 1977; cables across Knik Arm, which carry a large share of Anchorage
energy, went out of service in 1976; warmer than average weather in
1974, 1976, and especially 1977. Yearly growth rates reflected rather
large fluctuations as different historical events influenced each
parameter. (This is a recurring phenomenon in Alaskan history).
(d) Parameters were not influenced alike as·figures 3 through 8 attest.
For instance, customer growth ·reacted· to events in a steadier pattern
than did populatioD: and employment. Reasons for this are more people
per customer and tiine needed for connecting more customers to a utility
system at the initial onslaught of large demographic growth.
(e) Comparing the energy fluctuations with others, such as population
and employment, gave a measure of correlation between parameters. (The
energy use and customer growth fluctuations correlated only in part;
their patterns did not coincide every year). However, energy and popu-
lation growth rate changes were coincidental for every year but 1977.
That is, when the energy growth rate increased, so did the population
grqwth rate; when the population growth rate decreased, so did the
energy growth rate.
(f) Energy use and weather comparisons were inconclusive. Warm weather
did riot bring corresponding reduction in energy use. Cold weather
increases in energy use were buried in other events (pipeline
const~uction, etc.).
(g) Because the net generation kwh/capita ratio seemed to reflect the
closest correlations, particularly in recent years, this ratio and
population were used to forecast net generation values between 1980 and
2025.
(h) Values basic to the forecasting assumptions are the kwh/capita
ratio averaging 3.8 percent average annual growth between 1973 and 1977
and net generation averaging 12.7 percent.
(i) Average annual growth results are summarized on table 7. Figures
3, 4, and 5 are graphs of pertinent elements of the analysis.
24
Fairbanks-Tanana Valley Area Analysis Results Some of the
Anchorage-Cook Inlet area evaluation results apply also to .the
Fairbanks-Tanana Valley area, others do not. The following observations
parallel those of Anchorage-Cook Inlet.
(a)
load
one
No significant shift in energy use patterns or in share of total
among the various utility sectors (residential, etc.). Again, only
sector--net generation--need be forecast.
(b) Energy growth was similar to that of Anchorage (somewhat smaller in
the pre-1973 period); but customer, population, and employee growth were
different in the two areas. Consequently, the energy use per customer,
per capita, and per employee ratios indicate different growth patterns
in Fairbanks. The large swings of employment and population in
Fairbanks during pipeline construction compared to almost constant
preconstruction values cloud comparisons of the two periods.
(c) Although the effects of pipeline construction are evident, the
population/ employee ratio (2. 29 average through the study period) was
constant enough to indicate that either population or employment can be
used as. a forecasting parameter.
(d) The effects of weather on energy use could not be detected. In
some years, degree day variations were not in phase with energy. use
variations.
(e) Energy use/capita exhibited wider variations than the other two
ratios, but, nevertheless, had the nearest to constant average annual
growth rates. Because of this and the other observations, net
generation kwh/capita and population were used to forecast net genera-
tion.
(f) As in the Anchorage-Cook Inlet area, values basic to the
forecasting assumptions are the net generation/capita growth, averaging
10.6 percent per year, and net generation growth, averaging 10.5
percent per year between 1973 and 1977.
(g) . Growth rale results. are summarized on table 7. Figures 6, 7, and 8
are graphs of some pertinent elements of the analysis.
25
Table 7
AVERAGE ANNUAL UTILITY GROWTH SUMMARY
ANCHORAGE-COOK INLET AREA
Upper Susitna Project Power Market Analysis
Avg. Growth Avg. Growth
1970· 1973 1977 1970-1973 1973-1977
Energy GWH
Residential Sales 310 460 741 14.0% 12.6%
Commercial/Industrial 342 515 813 14.7 12.1
Total Sales 679 1,012 1,601 14.2 12.1
Net Generation 744 1,108 1,790 14.2 12.7
Energy Use, kwh/Customer
Residential 7,907 9,319 10,846 5.6 3.8
Commercial/Industrial 65,449 79,310 88,212 5.6 2.6
Total Sales 15,068 17,985 20,506 6.0 3.3
Energy Use, kwh/Capita
Residential 2,284 2,869 3,332 8.0 3.8
Commercial/Industrial 2,518 3,214 3,657 8.6 3.3
Total Sales 4,992 6,320 7,197 8.3 3.3
Net Generation 5,473 6,921 8,048 8.0 3.8
Fairbanks-Tanana Valley Area
Avg. Growth Avg. Growth
1970 1973 1977 1970-1973 1973-1977
Energy GWH
Residential Sales 92 134 201 13.4% 10.7%
Commercial/Industrial 108 140 222 9.1 12.2
Total Sales 210 282 443 10.2 11.9
Net Generation 239 324 483 10.8 10.5
Energy Use, kwh/Customer
Residential 8,852 11,262 12,010 8.3 1.7
Commercial/Industrial 62,931 72,303 85,899 4.8 4.4
Total Sales 17,134 20,104 22,746 5.4 3.1
Energy Use, kwh/Capita
Residential 1,759 2,572 3,848 13.5 10.6
Commercial/Industrial 2,077 2,670 4,249 8.7 12.3
Total Sales 4,031 5,403 8,488 10.3 12.0
Net Generation 4,589 6,196 9,259 10.5 10.6
APA 11/78
26
Figure 3
1:-:t\iT:RGY SEC'l'OP. Pi\TJ CS
Ai\'Q!Q(::J,CE-CCOJ:·~ l~·U~r.:T ARJ-::!\
Susitna Market
51
50
49
48
:; 47
c 46 .....
45
0 44 H
t< 43 < "' 42.
41
. Rcsid~ntiill.-saTes _____ _
40 ~=---------;------------+------------1;~----------~N~e~t~G~e~.n~c~r~a~t~.~io~n ______ ~A~v~~~·~--4~l~.7~·~·_j
19,70 1971 1972 1973.
YEl\P.S
1974 1976 1975 1977
]\_l'l,i'·i'UJ\JJ J::r.:ER3Y GL.NIC:PATED OP. SOLD
AN010.l~\GE-CCOK lNl.u'ST lu"'W .. t'\
1800
Upper Susitna Project Power Market Analysis
1700
1600
1500
~ 1400 ~ 1300 c
0 1200 .....
.-l llOO .-l T ..-I
~' 1000 II
§ 900
" t:: 800 •
•rl 700 T ;>< 600 t t? rr: 500
"" ~:: ~GO ~l 1:: 300
1970 1971 1972 1973 197•! 1975 197G 1977
YJ.::i\PS
APA 12/78
27
Figure 4
11,000
.i\NNUl\J, ENERGi. USE PJ.:d{ Ci\l?JT,'\ AND PER CUSTQ.\illR
ANCIIO~.GE-COOK INIJ:r AHE.l\
Upper S_usitna Project Pov1er Market Analysis
10,000
9,000
s,ooo
7,000
6,000
5, ooo •
4,000
3,000
L----------~----------~-----------J,--·---------+-----------r----------+----------J 2,0(10
19'70 1971 1972 1973 1974 19"/5 1976 1977
APA 12/78
28
250,000
225,000
200,000
w
...J a..
0
175,000
w 150,000 0... •
l1..
0
(/)
0:: w
mi25,0CO
:2: .:::> z
100,000-
75,000
ANNU.P.L POPULATION 9 Ef;1PLOYi\:H.:NT,
AND UTiLITY CUSTOP.1ERS
ANCHORAGE-COO~·< INLET AREA
Upper Susitna Project Power Market Analysis
Figure. 5
25,000~~------!--------~---------L--------~--------J----------~------~
1970 1971 1972 1973 1974 1975 1977
YEARS
APA l/79
29
Figure 6
ENERGY SECTOR RATIOS
FAIRBANKS-TANAN·A VALLEY AREA
52 Upper Susitna Project Power Market Analysis
Commercial-Industrial Sales ·
50 Total Sales Avg. = 48.9%
48 -~ 0 46
z -44 0
1-42 <t a::
:.__Net Generation
Avg. == 41.3% .
:38
36------~------~------~------~------~------~----~ 1970 1971 1972 1973 1974 1975 1976 1977
~
z
0 -::]300 -:a-
'tl
:r::
~200
z ->-(.!) a: 100
LtJ z
LLI
YEARS
ANNUAL ENERGY GENERATED OR SOLD
FAIRBANKS-TANANA VALLEY AREA
Upper Susitna Project Power Market Analysis
· al sales (GWH)
C ial-!ndustr1 . comme:I:
'dential sales (GWH) :ReS1
0~----~------_.------~------~------~------._----~
1970 1971 1972 1973 1974 1975 1976 1977
YEARS
.• 30 APA 1/79
14,000
13poo
12,000
11,000
10,000 --:t:9000
3:
~
8000 z -~7000
>--
(!)
0::.6000
w ..
z
LU 5000
. 4000
3000
2000
1000
0
1970"
Figure 7
ANNUAL ENERGY USE PER CAPITA
AND PER CUSTOMER
FAIRBANKS-TANANA VALLEY AREA
Upper Susitna: Project Power Market Analysis
· t:ion.~ ~et Genet:a.. . ...
1971 1972
ttt:tl-·) capita.
1973
{Ttl.)
1974
YEfRS
31
1975 1976 1977
APA 1/79
lJJ
..J a...
0
70,000
60,000
50,000
w 40,000
{b.
lL.
0
CJ)
0:: w co 30,000
:E
;:::) z
20,000
10,000
Figure 8
ANNUAL POPULATION 8 EMPLOYMENT,
AND UTILITY CUSTOMERS
_:Et\.IRBA.~K$-=:_IAI~t~NA VAL LEY AREA
Upper Susitna Project Power Market Analysis
ation· C).vil.i~ -eopUl · · · .
.. -
Average AnnUal Employment
Residential customers.
·eomrnercial-Industrial CUstomers
.. _------~------_.------~------~------~------~----~ t970 1971 1972 1973 1974 1975 1976 197.7
-~-ARS
A'PA 1/79
National Defense
Evaluation of historical national defense data resulted in net
generation and peak load averages. The analysis encompassed the u.s.
Army and Air Force installations in the Anchorage and Fairbanks areas.
No defini~e trends surfaced--only a small, cyclic decrease in the
Anchorage area net generation and. an increase in peak load. In the
Fairbanks area, net generation increased slightly and peak load
decreased. Total national defense is about 15 percent of utility for
both net generation and peak load.
Self-Supplied Industry
.Railbelt industry and the upper Kenai Peninsula complex showed no
significant change in capacity and energy generation until 1977 when the
chemical plant expanded. Therefore, the analysis consisted of a plant
factor determination only. Other factors needed in forecasting are
discussed as assumptions in the next section.
Energy and Power Demand Forecasts
This section presents future energy and power requirement estimates
developed from the previous analyses. Work for the new estimates
.consisted of: (1) using the analyses to obtain forecasting assumptions;
(2) using the assumptions in forecasting utility net generation/capita;
(3) combining net generation/capita with Institute of Social' and
Economic Research (ISER) population projections to obtain the utility
net generation forecast, and forecasting national defense and industry
generation from pertinent assumptions; and (4) combining the net
generation forecast with load factors resulting from the historical data
analysis to obtain peak load (power requirement) forecasts.
Assumptions and Methodology
Population -The ISER econometric model of the Southcentral Region Water
Study (Level B) furnished high and low range population forecasts. The
model disaggregated the Anchorage-Cook Inlet area from a statewide
population forecast. No recent, applicable forecast of Fairbanks-Tanana
Valley population was available; therefore, APA assumed statewide growth
rates from the ISER model applied to the Fairbanks-Tanana Valley areas.
(See table 8).
Utility -Assumptions, based on the preceding analyses, lead to the net
generation and peak load forecast. Net generation is the product of
forecasted energy use per capita and projected population. Peak load
demand is derived from net generation and the assumed utility load
factor. Multiplying these growth rates by forecasted 1980 values of
kwh/capita resulted in the energy use estimates.
0
33
Year
1980
1985
1990
1995
2000
2025
Table 8
POPULATION ESTIMATES
1980-2025
RAILBELT AREA
Upper Susitna Project Power Market Analysis
1/ Anchorage-Cook Inlet -Statewide 1./ Fairbanks-Tanana
High Low High Low High
270,200 239,200 513,766 500,225 62,020
320,000 260,900 640,718 563,303 77 '350
407,100 299,200 790,042 618,397 95,370
499,200 353,000 947,312 680,286 114,360
651,300 424,400 1,157,730 743,034 139,760
904,000 491,100 1,484,784 820,369 179,240
Notes: * No mid-range estimates are shown because, when the forecasts
were done, ISERl/ had made only the high and low projections.
A comparison of the mid-range forecast already performed (see
text for method) with one using the mid-range population, when
received, indicated no reason to re-do the forecasts.
* Values shown include national defense population
11 From Iser, Southcentral Alaska's Economy and Population: A base
Study 1965-2025. September 1978 with December 1978 revisions.
11 Calculated from statewide growth rates.
34
Valley Jj
Low
60,390
68,010
74,660
82,130
89,700
99,040
Since the ratios of residential, commercial-industrial, and total sales
energy to net generation remain constant' net generation is assumed. to
be an appropriate forecasting parameter. The evaluations indicated that
the other sectors do not need individual forecasting.
The basic energy use (net generation kwh/capita) assumption for the
entire Railbelt area is a 3.5 percent average annual, mid-range, 1980-85
growth rate. It is based on the Anchorage-Cook Inlet area value of 3.8
percent annual growth ffom ·1973-77 and an assumed continuation of the
post-1973 conservation-trend. As mentioned in the Anchorage-Cook
Inlet area evaluations, a conservation trend was apparent when comparing
energy use growth rates for 1973-776 and 1970-73 (see table 7). Tied to
this is the assumption of gradually increasing effectiveness of future
conservation programs coupled with perhaps upper limits of electric
energy use. These are reflected in an average annual growth by the year
2000 or 2 percent for high range, 1 percent for mid-range, and 0 percent
for low range. These assumptions result in decreased growth rates for
each five-year increment, as shown below:
Time Period High Mid Low
1980-1985 4.5% 3.5% 2.5%
1985-1990 3.5% 3.0% 2.0%
1990-1995 3.0% 2.5% 1.5%
1995-2000 2.5% 2.0% 1.0%
2000-2025 2.0% 1.0% 0%
Multiplying these growth rates by forecasted 1980 values of kwh/capita
resulted in the energy use estimates.
The 1980 mid-range value of kwh/capita was derived from the 1973-1977
average annual growth of net generation. The 1980 net generation was
estimated. The Anchorage-Cook Inlet mid-range assumption of 12 percent
annual load growth rate for 1977-80 net generation came from a
historical 12.7 percent. The respective Fairbanks-Tanana Valley values
were 10.5 percent assumed, 10.6 percent historical. Mid-range 1980
kwh/capita was calculated using the estimated net g~neration and
projected population. The 1980 high and low range average annual
kwh/capita growth rates for Fairbanks-Tanana Valley were assumed 120
percent and 80 percent of the calculated mid-range value respectively.
Comparable values for Anchorage-Cook Inlet were 130 percent and 80
percent. The differences between the two areas reflect population
estimates and an attempt to derive a reasonable 1977-80 transition
period coupled with the population estimates.
Peak·load (MW) forecasts were calculated using a 50 percent load factor.
Anchorage-Cook Inlet area load factor averaged 51.9 percent between 1970
and 1977 and 51.0 percent between 1973 and 1977. Fairbanks area
averaged 48.9 percent and 48.4 percent in the same periods.
1/ Conservation here includes results of the fuel crlSlS and perhaps
of nationwide publicity on the need for saving energy. Other factors
may be involved, but no other events are as coincidental with reduced
energy use as is the fuel crisis.
35
National Defense -Historical data from Army and Air Force installations
in the Anchorage and Fairbanks areas indicate reasonable energy
assumptions to be:
1. 0 percent annual growth for mid-range forecast, 1 percent for high
range, and -1 percent for low range.
2. A 50 percent load factor was assumed for use with energy (net
generation) to obtain peak ldad.
Self-Supplied Industries -The following assuw.ptions were developed from
existing data and conditions, consultations with many knowledgeable
people in government and industry, and from reports on future
developments:
1. Industries will purchase power and energy if economically feasible.
2. Forecast based on listing in the March 1978 Battelle report.
3. High range includes existing chemical plant, LNG plant, and
refinery as well as new LNG plant, refinery, coal gasification plant,
mining and mineral processing plants, timber industry, city and aluminum
smelter or some other large energy intensive industry.
4. Mid-range includes all of the above except the aluminum smelter.
5. Low range includes all listed under high range except the aluminum
smelter and the new capital.
6. In some instances, high, mid, and low range may be differentiated
by amount of installed capacity as well as the type of installations
assumed.
7. No self-supplied industries are assumed for the Fairbanks-Tanana
Valley area. Any industrial growth has been assumed either (1) included
in utility forecasts or (2) not likely to be interconnected with the
area power systems.
8. Net generation forecast calculated from forecasted capacity and a
plant factor of 60 percent.
The ISER model assumed the following Cook Inlet area industrial
scenario. It is compared to industries assumed for the self-supplied
industrial forecasts of this report.
36
Cook Inlet Industrial Scenarios
Assumptions
ISER Self-Supplied Industries Forecast
HIGH RANGE
Oil treatment and shipping facilities
Small LNG
Beluga Coal (40 employees in shipping)
New capital (2,750 employees 1982-84)
Refinery-petrochemical complex 1/
Pacific LNG -
Bottom fish industry
Oil lease development
No new pulp mills or sawmills
Existing refinery (2.4 MW)
Existing LNG plant (.4 to .6 Mw)
Coal gasification (0 to 250 MW)2/
New city (0 to 30 MW) -
New refinery (0 to 15.5 MW)
New LNG plant (0 to 17 MW)'
Mining and mineral plants (5 to 50 MW)
Timber (2 to 12 MW)
Existing chemical plant (22 to 26 MW)
Aluminum smelter or other energy intensiv
industry (0 to 280 MW)
MID RANGE 3/
LOW RA.."fifGE
Pacific LNG New LNG plant (0 to 17 ~m)
Existing refinery (2.4 MW)
Existing LNG plant (.4 MW)
Existing chemical plant (22 MW)
Coal gasification (0 to 10 MW)
New refinery (0 to 15.5 MW)
Mining and mineral plants (0 to 25 MW)
Timber (2 to 12 MW) ·
lf A recent decision by ALPETCO changes this to the Valdez area.
The changes involved were not enough to warrant forecast revisions.
};./ Part of coal gasification could be equivalent to "Beluga Coal," but
it is much more than "40 employees in shipping."
11 At the time this forecast and analysis was performed, no ISER mid-range
projections of populations and employment had been developed.
37
Estimate of Future Demands
Using the high and low population projections and high, mid, and low
kwh/ capita assumptions, six different net generation utility forecasts
were obtained. From these, the high population/high energy use and the
low population/low energy use were used for the high and low range final
forecasts. The mid-range final forecast came from averaging the high
population/low energy use and the low population/high energy use
forecasts. In lieu of a mid-range net generation based on a 'mid-range
population projection, these last two forecasts were enough alike to
justify the average as mid-range net generation.
Near the completion of this analysis, ISER provided APA with a mid-range
population projection. Comparing the previous results with forecasts
using these mid-range projections, APA concluded that the two were
consistent and that no changes were necessary.
National defense and self-supplied industrial forecasts were calculated
from the assumptions and summarized with the utilities on table 10 for
the Anchorage-Cook Inlet area and table 11 for the Fairbanks-Tanana
Valley area. Railbelt totals, both peak load demand and net generation,
are summarized on table 12. Appropriate graphs follow each table on
figures 9 and 10 for Anchorage-Cook Inlet, 11 and 12 for
Fairbanks-Tanana Valley, and 13 and 14 for the Railbelt totals.
Trend lines based on 1973-1977 average annual energy growth are
superimposed on the energy graphs, figures 9, 11, and 13.
1973-1977 Average Annual Growth
Anchorage-Cook Inlet
Fairbanks-Tanana Valley
Railbelt
10.9%
7.1%
9.9%
Historical and forecast energy use comparisons are summarized in table'
9.
Comparison with Other Forecasts
· This section compares the present forecast (1978) with two previous
forecasts, and forecasts available from various utilities.
The previous forecasts included the 1976 report and its 1977 update.
The 1977 update used 1975 criteria and assumptions. See table 13 for a
comparison tabulation. In general, the present forecasts produced values
less than the previous ones.
38
. .>
Historical
High
Mid
Low
Historical
High
Mid
Low
Table 9
NET ANNUAL PER CAPITA GENERATION (KWH)
RAILBELT AREA UTILITIES
Upper Susitna Project Power Market Analysis
1970 1977 1990 2000 2025
Anchorage-Cook Inlet Area
4980 7630
16,300 21,400 35,100
14,000 17,500 22,400
12,000 13 '600 13,600
Fairbanks-Tanana Valley Area
5655 10,240
18,400 24,000 39,000
16,300 20,300 26,000
14,100 15,800 15 '900
APA 11/78
Energy use per capita nearly doubled in both areas in the historical
seven years. Growing use of electric space heating, electric cooking in
place of gas and oil, and many other possibilities can justify the
assumptions shown. Again, conservation has been factored in through
decreasing growth rates.
39
Table 10
POWER AND ENERGY REQUIREMENTS
ANCHORAGE-COOK INLET AREA
Upper Susitna Project Power Market Analysis
PEAK POWER
1970 1973 1977 1980 1985 1990 1995 2000 2025
MW MW MW MW MW MW MW MW MW --.
UTILITY
High 620 1,000 1,515 2,150 3,180 7,240
Mid 165 230 424 570 810 1,115 1,500 2,045 3,370
Low 525 650 820 1,040 1,320 1,520
NATIONAL DEFENSE
High 31 32 34 36 38 48
Mid 35 33 41 30 30 30 30 .30 30
Low 29 28 26 24 24 18
.p.. INDUSTRIAL
0 High 32 344 399 541 683 ·1,615
Mid • 12 12 25 32 64 119 199 278 660
Low 27 59 70 87 104 250
TOTAL
High 683 1,376 1,948 2, 727 3,901 8,903
Mid 212 275 490 632 904 1,264 1, 729 2,353 4,060
Low 581 737 916 1,151 1,448 1,788
ANNUAL ENERGY
GWH GWH GWH GWH GWH GWH GWH GWH GWH
UTILITY
High 2, 720 4,390 6,630 9,430 13,920 31,700
Mid 744 1,108 1,790 2,500 3,530 4,880 6,570 8,960 14,750
Low ·2, 3oo 2,840 3,590 4,560 5, 770 6,670
NATIONAL DEFENSE
High 135 142 149 157 165 211
Mid 156 161 131 131 131 131 131 131 131
Low 127 121 115 105 104 81
INDUSTRIAL
High 170 1,810 2,100 2,840 3,590 8,490
Mid 2 45 70 170 340 630 1,050 1,460 3,470
Low 1Lf1 312 370 460 550 1,310
TOTAL ---·----
High 3,025 6,342 8,879 12,427 17,675 40,1~01
Mid 902 1,314 1,990 2,801 4,001 5,641 7,751 10,551 18,351
Low 2,568 3,273 4,075 5,125 6,424 8,061
v APA 2/79
U)
a:
:J
0
J:
}-
}-
<t
3
<t
c., -c.,
100,000 ,.---------""---------:--------:-----~---------,
90,000
80,000
70,000
60,000
50,000
40,000
:30,000
20,000
10,000
9000
8000
7000
6000
5000
4000
3000
2000
ANCHORAGE-COOK INLET AREA /
ENERGY FORECAST
Upper susitna Project Power Ma~ket Analysis
1000 U----~~--~----~----~----~----~------~----~----J-----~----~
1970 1975 1977 1980 . 1985 .1990 1995 2000 2005 2010 2015 . 2020 2025
·YEAR
(/)
.p. l-
N l-
<(
~
~
(!;)
tl.J
~
id
:t:'
f-'
1'0
'-.
-..J
())
. 10,000 t-------------------------:----------,
9000
8000
7000
6000
5000
4000
3000
2000
1000
900
600
700
600
500
400
300
200
ANCHORAGE-COOK INLET AREA
PEAK LOAD FORECAST
Upper Susitna Project Power Market Analysis
LOW
IOOL----~~-~----~---~---~---~---~----~---~---~---~
1970 1975 1977 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025
YEAR
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101000,.---------------..,.._.----------~----r------,
9000
8000
7000 .•
6000
5000
4000
3000
2000
1000
900
800
700
600
500
400
300
200
100
-
1970
FAIRBANKS-TANANA VALLEY AREA /
ENERGY FORECAST ~~
Qpper Susitna Project Power Market Analysis ~
1995 2000
Vr:'llR
_,"-0"./ ~"?/
2005
LOW
2010 2015 2020 2025
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9000 -
8000
7000
6000
5000
4000
3000
2000
1000
900
BOO
700
600
500
400
300
. 200
FAIRBANI<S-TANANA VALLEY AREA
PEAK LOAD FORECAST
Upper Susitna Project Power Market Analysis
LOW
1975 1977 1980 1905 1990 . 1995 2000 2005 2010
YEAR
2015 2020. 2025·
-!>-
0\
Table 12
POWER AND ENERGX REQUIREMENTS
(RAILBELT AREA)
Upper Susitna Project Power Market Analysis
PEAK POHER
1970 1973 1977 1980 1985 1990
MH MH MH MH MH MH
TOTAL
High 890 1,671 2,360
Mid 313 389 650 829 1,162 1,592
Low 769 961 1,177
Average Annual
Growth for period % % % % %
High 11.0 13.4 7.1
Mid 7.5 13.7 8.4 7.0 6.5
Low 5.8 4.6 4.1
ANNUAL ENERGY
GHH GHH GHH GWH GWH GWH
TOTAL
High 3,928 7,636 10,684
Mid 1,345 1,838 2,681 3,663 5,133 7,078
Low 3,391 4,256 5, 219·
Average Annual
Growth for period % % % % %
High 13.6 14.2 6.9
Mid 1LO ·9.9 11.0 7.0 6.6
Low 8.1 4.6 4.2
Note: The increase in 1980-1985 high range growth rates reflects the
addition in 1985 of the e~ergy intensive self-supplied industry load
(280 MH).
1995 2000 2025
MH MH MW
3,278 4,645 10,422
2,134 2,852 4,796
1,449 1,783 2,146
% % %
6.8 7.2 3.3
6.0 6.0 2.1
4.2 4.2 0.7
GVJH GWH GHH
14,844 20,935 47,054
9,528 12,738 21,578
6,430 7,890 9,630
% % %
6.8 T.T 3.3
6.1 6.0 2.1
4.3 4.2 0.8
APA 11/78
JOT.AL .:RAILBEL T .AREA.
I ' '' 'i J ' I .}
ENERGY .FORECAST
t
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9000
8000
7000
6000
5000
4000
3000
2000
1000
900
800
700
600
500
400
300
200
TOTAL RAILBEL T AREA
PEAK LOAD FORECAST
Upper Susitna Project Power Market Analys~s
LOW
2015 2020 2025
Table 13
COHPARISON OF UTILITY ENERGY ESTIMATES
1976 MARKETABILITY REPORT, UPDATE OF 1976, AND 1978 ANALYSIS
·upper Susitna Project Power Market Analysis
-.,l Anchorage-Cook Inlet Fairbanks-Tanana Valley Total Rail belt
--;Forecast' 1976 Update 1978 1976 Update 1978 1976 Update 1978 'l~ !l{ '. J. R Report of 1976 Forecast Report of 1976 Forecast Report of 1976 ~., :Year t-ange ~· Forecast "• •!J
' 1974 Historic 1,305 Jj 1,189.7 Jj 330 353.8 1,635 1,543.5
1975 High 1,489 377 1,866
"Mid 1,467 371 1,838
Low 1,450 367 1,816
Historic 1,413.0 450.8 1,863.8
"" 1976 High 1,699 430 2,129
1.0 Mid 1,649 417 2,066
Low 1 '611 407 2,018
Historic 1,615.3 \. 468.5 2,083.8 \
'1
1977 High 1,939 490 2,429
Mid .. 1,853 469 2,322
Low 1,790 453 2,242
Historic 1,790.1 1,790.1 482.9 482.9 2,273.0 2,273.0
1980 High 2,850 2,660 2, 720 700 720 690 3,550 3,380 3,410
Mid 2,580 2,540 2,500 660 690 655 3,240 3,230 3,155
Low 2,410 2,460 2,300 610 660 620 3,020 3,120 2, 920
1990 High 6,880 6,300 6,630 1,660 1,700 1,570 8,540 8,000 8,200
Mid 5,210 5,000 4,880 1,270 1,360 1,230 6,480 6,360 6,110
Low 4,420 4,410 3,590 1,050 1,180 960 5,470 5,590 4,550
~-%00'b"-;)· High 15,020 13,600 13,920 3,500 3,670 3,000 18,520 17,270 16,920
Mid 9,420 8,950 8,960 2,230 2,440 1,980 11' 650 11' 390 10,940
Low 6,570 6,530 5,770 1,530 1,750 1,300 8,100 ·s,28o 7,070
y 1974 historic data revised between 1975 and 1978. APA. 11/78
GWH = million kwh
Further comparisons confirm that the 1976 report forecast was valid.
Historic values through 1977 fell between the high and low ranges of the
forecast.
The 1976 report was based on load data through 1974 and the following
assumptions for utility load growth:
High Range
Mid-Range
Low Range
Average Annual Growth Rates
1974-1980
14.1%
12.4
11.1
1980-1990
9.0%
7.0
6.0
1990-2000
8.0%
6.0
4.0
The following percentages compare this report and the above assumptions.
High Range
Mid-Range
Low Range
Average Annual Growth Rates From
1978 Utility Energy Forecast
1977-1980
14.5%
11.5
8.7
1980-1990
9.0%
6.8
4.5
1990-2000
7.5%
6.0
4.5
The 1976 report based the utility energy forecast on assumed average
annual growth rates. The 1978 report based the forecast on assumed
growth in population and per capita energy use. Both reports considered
energy conservation, but it was given more specific and higher
importance in the 1978 forecast.
Forecasts available from various utilities are tabulated on tables 14,
15, and 16. Some were done by the utilities, some by consultants, and
some by REA. All data was tabulated and, where necessary, extrapolated
as part of the State Alaska Power Authority Railbelt Intertie Study.
Comparisons are summarized in 5-year increments.
Utility Forecasts 1978 Susitna Forecasts
Energy (GWH) High Mid Low
1980 3,344 3,410 3,155 2,920
1985 6,277 5,460 4,455 3,630
1990 10,965 8,200 6,110 4,550
1995 17,748 11,600 8,140 5,690
2000 26,550 16,920 10,940 7,070
Peak (MW)
1980 725 778 720 667
1985 1,377 1,244 1,021 830
1990 2,986 1,873 1,396 1,039
1995 3,835 2,645 1,858 1,298
2000 5,641 3,865. 2,497 1,617
so
The utility forecasts run higher than those of this report. No definite
reason for the differences can be made other than the utilities assu~ed
higher growth rates. The basis of the utility assumptions was not
considered in this study.
51
Table 14
UTILITY ENERGY FORECASTS (GWH)
ANCHORAGE-COOK INLET AREA
Upper Susitna Project Power Market Analysis
Year AML&P l/ CEA !:_/ MEA]./ HEA !!._/ Total
1979 634 1,109 280 310 2,333
1980 699 1,283 333 374 2,689
1981 771 1,468 395 452 3,086
1982 847 1,679 468 546 3,541
1983 930 1,921 559 620 4,030
1984 1,018 2,197 668 705 4,588
1985 1,111 2,509 799 800 5,219
1986 1,210 2,810 954 909 5,883
1987 1,313 3,147 1,140 1,033 6,634
1988 1,422 3,525 1,322 1,155 7,424
1989 1,534 3,948 1,5~4 1,290 8,306
1990 1,650 4,422 1, 779 1,442 9,293
1991 1 '770 4,864 2,064 1,611 10,309
1992 1,891 5,350 2,394 1,801 11,437
1993 2,014 5,885 2,706 1, 9'78 12,584
1994 2,1_;38 6,474 3,057 2,173 13,843
1995 2,245 7,121 ~,455 2,388 15,209
1996 2,357 7,691 3,904 2,623 16,575
1997 2,475 8,306 4,412 2,882 18,075
1998 2,599 8, 971 4,853 3,111 19,533
1999 2, 729 9,638 5,338 3,359 21' 113
2000 2,865 10,463 5,872 3,626 22,82.6
Source: Obtained from utilities in 1978 for Alaska Power Authority
Rai1belt Intertie Study.
1/ Anchorage Municipal Light & Power Department
2/ Chugach Electric Association
3; Matanuska Electric Association
4/ Homer Electric Association
APA 1/79
52
Table 15
UTILITY PEAK DEMAND FORECASTS (MW)
ANCHORAGE-COOK INLET AREA
Upper Susitna Project Power Market Analysis
Year AML&P l/ CEA ]j MEA1} HEA !!} Total
1979 124 239 67 64 495
1980 138 271 81 78 567
1981 152 310 97 94 653
1982 167 355 116 113 752
1983 184 406 142 129 860
1984 202 465 171 146 983
1985 221 530 207 166 1,124
1986 241 594 251 188 1,274
1987 263 655 303 214 1,445
1988 285 745 343 239 1,612
1989 309 835 389 267 1,800
1990 333 935 442 299 2,008
1991 358 1,028 501 334 2,222
1992 384 1,131 569 373 2,458
1993· 4U 1,244 630 <. 410 2,695
1994 437 1,369 698 451 2,954
1995 461 1,505 773 495 3,234
1996 486 1,626 857 544 3,512
1997 512 1,756 950 598 3,816
1998 539 1,901 1,026 645 4,111
1999 568 2,048 1,108 696 4,421
2000 599 2,212 1,197 752 4,759
Source: Obtained from utilities in 1978 for Alaska Power Authority
Railbelt Intertie Study.
1/ Anchorage Municipal Light ~ Power Department
2; Chugach Electric Association
3! Matanuska Electric Association
4/ Homer Electric Association
APA 1/79
53
Table 16
UTILITY ENERGY AND PEAK DEMAND FORECASTS
FAIRBANKS-TANANA VALLEY AREA
Upper Susitna Project Power Market A.11.alysis
Net Eneq!;Y (GWH) Peak Demand (MW)
Year GVEA 1_/ FMU .Y Total GVEA FMU Total
1979 450 144 594 111 33 144
1980 502 153 655 123 35 158
1981 . 560 162 722 136 37 173
1982 62·5 172 796 151 39 190
1983 693 182 875 167 42 209
1984 769 193 962 186 44 230
1985 853 205 1,058 206 47 253
1986 947 217 1,164 228 50 278
1987 1,050 230 1,280 252 53 305
1988 1,155 244 1,399 278 56 334
1989 1,271 259 1,529 305 59 364
1990 1,398 274 1,672 335 63 398
1991 1,537 288 1,825 368 66 434
1992 1,691 302 1,993 405 69 474
1993 1,843 317 2,160 440 72 512
1994 2,009 333 2,342 480 76 556
1995 2,190 350 2,540 521 80 601
1996 2,387 367 2,754 569 84 653
1997 2,602 386 2,987 619 88 707
1998 2,810 405 3,215 668 92 760
1999 3,035 425 3,460 722 97 819
2000 3,278 446 3. 724 780 102 882
Source: Obtained from utilities in 1978 for Alaska Power Authority
Rail belt Intertie Study.
1/ Golden Valley Electric Association
2/ Fairbanks Municipal Utilities
APA 1/79
54
Load Distribution
Reservoir operation studies used in sizing reservoirs need an average
monthly distribution of annual energy to help relate hydroelectric
output to the electric load. This section reports updated averages of
monthly energy use divided by annual energy use within the
Anchorage-Cook Inlet area.
This section also reports a study of hourly load distribution in the
weeks of winter peak load (same as annual peak) and summer minimum peak
load. By studying these load curves from several years, hydroelectric
plant factor is evaluated. (See capacity section).
The utility systems have had combined annual load factors slightly over
50 percent in the past few years (54 percent in 1977 as shown on figure
17)·. Data presented in table 17 shows that mid-summer peaks have been
running about 60 percent ·of mid-winter peaks and that monthly load
factors generally exceeded 70 percent. For 1977, the December load
factor was 76 percent. Figures 1~ and 16 illustrate that winter and
summer loads are quite similar. The load duration curves of figure 17
present these daily load curves concisely. The 1976 report contains
daily load curves of previous years. Winter and summer curves are
plotted together showing similarities of slope and shape.
The update of average monthly energy· is presented as percent of the
annual value in table 18. Average percentages used in the 1976 report
compare closely with 1970-77 averages. Slight changes are reflected in
the "recommended distribution" column. Winter load is about two-thirds
of total.
55
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Figure 17
ANCHORAGE AREA
LOAD DURATJ'ON CURVE
1977
Upper Susitna Project Power Market Analysis 100~--~----~--~--~~--~----~----~---r----~---4
90
80
l · December 1977
54o/o Load Factor
. · l-. . Winter Peak. Load
. 65°~0----------------------------I<
70
60 Winter Base Load
cJune 1977
40
30 Summer Peak Load
-----------------------t-27Cfo
Summer Base Load
20
10
0 10 20 30 40 50 60 70 80 90 100
% TIME
APA 12/78
58
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{:.. \,()
0 't1
..-i -I .s :::: t;) :::
:.!; g >. ;;;
~ 0'1 ·" :ii k . ~· r.l C) l:: 5 u t: ~ <:l ::;;: .... " ::.1 ... !'-<
I
Octo;;,a.:: 185.8 73 94.1 68 209.2
Nove~a: 222.a 80 113;0 70 ·236.3
Dacz.::-:Oe.r 236.2 93 121.1 70 260.7
Jan'..!G:.!"'Y 254.5 100 135.3 72 203.0
cbr\!z.::y 224.5 sa 115.3 76 259.6
~a~ch 222.8 87 119.2 70 225.1
p:::.l 176.7 69 96.6 76 196.4
<ay 157.9 62 B7.S 75 176.7
cne '' 152.1 J 66 78.5 72 165.2
~'.l1y " 14.6. a· '52 76.6 70 162.8
t:<;\!St: 154.5 54 86.9 75 175.9
s ·';)~ . _, '
c. ~c=e-1 179.6 64 92.9 72 194.5
·:i:-. St.:::::;'.C!" ?Ci:!.;;__ "' S? • 7 ~
·!c.:~. ~\i.:~"t.c:: ?c~J.;.
57.5~
'Table 17
LOAD DISTRI13'(JTION. CHARACTERlSTJCS
MONTHLY Pl]:AK LOADS· AND LOAD FACTORS'
"Upper Susitna Project Power Market Analysis.
1972-1973 1973-1974
. ::.: JJ ~ .:i ~ u ~ "' r.;
1:.1 ~ I!)
{:.. \0 't1 ll< \,()
0 0
.-! .-! r.J .-! .-!, ~" .s .,. I'll
~ !1: !:) >. r:: r:: 0'1 r:: !.4 ~ r:: l-1
"" (,) r:: "" iiJ
tl 0· CJ r::
dP ::: ll< d? ~
74 108.8 70 224.3 82 122.7
83 124.4 73 269.6 98 . 144.6
92 143.3 74 266.9 97 1'17.0
100 153.6 72• 274.5 100 159.3
92 127.5 73 264.5 ·96 139.4 .
ao 125.5 75 249.4 91 135.5
69 105 .4· 75 201.6 73 112.4
62 98.5 75 180.4 66 104.1
58 87.6 74 176.2 64 95.4
59. 89.8 74 178.9 65 97.5
64. 96.2 73 195.7 71. 101.9
71. 100.8 72 210.3 77 106.1
64.2'11
1974-1975 1975-1976
. . .
JJ ::.: J.J ;:;: J.)
u ~ ~ u .;.: u
12 r.l r.l :;;: r,)
I!) ~ 1:.1 ~ !'-< Ul ll< \,()
'0 0 '0 . 0 ~
"' .-! -I Ill ..-! -I t'J 0 g-:-.,.. . I'll .s t?:: r,) 0 ...
H "" !:) >. ;;:; !:) >. ~ ~ r:: t'\ r:: V\ .;.: c l-1 .:i r:: k .u t: r.l "" (,) r:: r.l "" u " 0 Cl c: :8 C) c: 0 C)
;<: ... ··p 1'.1 ... <P t£i :£: p..
73 252.9 71 134.3 71 342.2 81 153.0 60 359.8
74 266.2 75 156.0 81 367.6 87 196.2 74 360,7
74 314.9 89 170.7 73 420.5 100 226.3 72 408,3
78 354.1 100 180.8 69 394.1 94 213.3 73 375.4
79 316.7 89 166.9 78· 383.3 . 91 203.5 76 356.8
73 268.6 76 156.6 78' 342,·1' 81 187.6 7t. 369.0
77 249.0 70 129.2 72 2.85. 3 60 159.0 77 33!,.4
76 222.0 63 120.9 73 253,6 60 1!.5.0 77 2s~.s
75 209.0 59 113. o. 75 236.1 56 128.9 76 265,0
73 207.0 sa 110.9 72 240.0 59 134.4 73 257.1
70' 211.5 61 118.3 73 250.6 60 139.9 75 27l.8
70 247.4 70 131.9 74 278.0 66 151,2 76 318.9
58.5% 56.1'1l 63. 0 '•
l
l/~cpresants su~ of loads for the Anchora~c (~V~&P, C~A)
-And &ai:::b.:tn.l~s {FNi.i 1 GVEA) utilities
1976-1977
~ ,).!
3
I'< \,()
0 .... -I
I';
5 >-
t'\
k .< u c::
t',) ~
88 182.2 f
88 193. a .
100 223.4 .
'
92 209.9 j
87 181. 7. i
90 208.6 .
82 177;0
70 161.3
65 lt.S .1
63 141.3
67 151.7
79 166.7
Table 18
MONTHLY ENERGY REQUIREMENTS AS PERCENT OF ANNUAL REQUIREMENT
Upper Susitna Project Power }'!..arket Analysis
1970-1972 1970-1977
Utility Utility Recommended
MONTH Loads 1/ Loads 2/ Distribution
Oct. 7.9 8.1 8.2
Nov. 8.9 9.2 9.0
Dec. 10.2 10.2 9.7
Jan. 11.3 10.8 10.2
Feb. 9.2 9.3 9.1
Mar. 9.8 9.4 9.1
April 8.0 7.8 7.9
May 7.2 7.3 7.6
June 6.5 6.6 7.0
July 6.4 6.7 7.1
Aug. 7.1 7.1 7.4
Sept. 7.5 7.5 7.7
Total 100.0 100.0 100.0
SEASONAL
Oct.-April 65.3 64.8 63.2
May-Sept. 34.7 35.2 36.8
lf Combined loads of CEA, AML&P, GVEA, FMUS, for Oct. 1970-Sept. 1972.
Basis for (1975 Susitna Power market analysis) 1976 report.
11 Combined net generation of CEA, AML&P, APA, GVEA, FMUS, for Oct.
1970-Sept. 1977. Updated Basis.
3/
~ Assumes total requirements consisting of 25 percent industrial loads
and 75 percent utility loads. Update of previous recommendations.
60
/
Capacity Requirements
With reference to the load factor evaluatior~ in the previous section, a
trend towards somewhat higher annual load factors in the future is
anticipated. In addition to benefitting from any load diversity in the
interconnected system, peak load management (including such practices as
peak load pricing) offers considerable opportunity for improving load
factors, which in turn reduces overall capacity requirements for the
system in any given year. For planning purposes, it is assumed that the
annual system load factor will be in the range of 55 to 60 percent by
the latter part of the century.
System capacity requirements are determined by winter peak load
requirements plus allowances for reserves and unanticipated load growth.
The lower summer peaks provide latitude for scheduled unit maintenance
and. repairs.
System daily peak load shapes indicate that a very small portion of the
capacity is needed for very low load factor operation. Some of the gas
turbine capacity now· used for base load is expected to be used mainly
for peak shaving purposes, eventually. It will be operating during peak
load hours for the few days each year when loads approach annual peak,
and will be in standby reserve for the balance of the year. Figure 17,
the annual peak week duration curve, s1lows that the highest 10 percent
load occurs for 30 percent of the week (about two days).
I
Reliability standards would be upgraded as the power systems develop.
Likely inclusions are specific prov~s~ons for maintaining spinning
reserve capacity to cover possible generator outages and substantial
improvements in system transmission reliability.
Results -:Examination of the winter load duration curve (figure 9)
indicates that the base load portion is about 65 percent of total load
and the peak load is about 35 percent of total load. Load factor for
the peak portion is about 54 percent. Winter weekly load factors are
approximately 80 percent •• This is illustrated in the winter and summer
load duration curves by proportioning the areas under the curves to the
total possible area if 'peak load occurred 100 percent of the time.
An annual plant factor of 50 percent is rec_ommended for the proposed
Upper Susitna Project. This is largely a judgment factor and is based
on the following considerations:
1. The recommended plant factor provides for serving a proportional
share of both peaking and energy requirements throughout the year while
maintaining adequate flexibility to meet changing conditions in any
given year.
2. Any significant reduction in this capacity could materially reduce
f lexib ili ty.
61
3. A significant market for low load factor peaking capacity seems
unlikely within the foreseeable future. Load management and additional
industrial loads will probably increase the overall system load factor
in the future. It is expect~d that severai existing and planned gas
turbine units could eventually be used for peak shaving.
4. It is recognized that the mode of operation for the hydro will
change through time. In the initial years of operation, it is likely
that the full peaking capacity will be used infrequently. For example,
the mid-range Railbelt estimated system peak load for the year 2000 is
2,852 MW. Assuming load shapes similar to the current Anchorage area
loads, the winter peak week would require about 1,850 MW of continuous
power to cover the base loads and about 1,000 MW of peaking.power. Load
factors of the peak portion would be about 50 percent.
A design capacity based on 50 percent plant factor applied to average
annual energy (primary plus secondary) appears appropriate. Machine
overload capability contributes to spinning reserves for emergencie~ or
otper short term contingencies.
The Corps based nameplate capacity on 50 percent plant factor applied to
critical year firm energy. This smaller capacity, when applied to
average annual energy, results in a 56 percent plant factor. APA feels
the smaller design capacity may unduly reduce flexibility.
62
PART VI. ALTERNATIVE POWER SOURCES
Introduction
This section examines alternative power supply options in, the Railbelt
in lieu of the Upper Susitna Project and presents detailed cost
estimates of power from new coal-fired steam plants.
Alternatives premised on unproven technology were eliminated.
Alternatives Considered
Potential alternative sources of electric power generation are identi-
fied by energy type. They are coal, oil and natural gas, hydro,
nuclear, wind, geothermal, and tide.
Some ,alternatives will be restricted in time or capacity because of
Federal energy policy controlling use of energy resource. Others will
be restricted by practical· available energy supply. Still others are
impractical because of lack of large-scale technology.
Coal
Evaluation of coal utilization is based on mine-mouth coal-fired steam
generation. Potential advanced technology, such as gasiiication, is not
considered because development would not be available within this study
period.
Recent studies provide general information about possible locations,
sizing, and cost of new steanplants, but Alaska specific data are
limited and extrapolations have been made for local conditions.
Information sources of specific interest for this analysis are: studies
by Battelle Pacific Northwest Laboratories (March 1978); the Electric
Power Research Institute (EPRI) (January 1977); and the Washington
Public Power Supply System (WPPSS) (June 1977); the Federal Energy
Regulatory Commission (FERC) determination of power values for the
Bradley Lake Project (October· 1977) and the Upper Susitna Project
(October 1978); and evaluations of costs for the proposed Golden Valley
Electric Association (GVEA) plant additions at Healy. These are all
listed in the bibliography.
Location It is assumed that new coal-fired steamplants would be
located near the Beluga fields for service to the Anchorage-Cook Inlet
area and at Healy for service to the Fairbanks-Tanana Valley area. The
plants would use known but undeveloped coal resources at Beluga and the
existing coal mining operation near Healy.
63
It is recognized that other locations are possible. For example, ·it may
be possible to locate a coal-fired plant on the Kenai Peninsula and .use
coal from either local reserves or Beluga. A Kenai location might offer
co-generation possibilities because steam could be reused in
manufacturing by the petrochemical industry. The pot.ential for mining
coal on the Kenai Peninsula is substantially less attractive than for
Beluga because of thin coal seams and other geologic factors.
Capacity -These analyses a:re for two-unit 200-MW and 500-MW plants.
This size range is considered appropriate for new coal-fired plants that
might come on-line between 1985 and 2000.
Investment Cost -Table 19 summarizes unit investment costs for new
coal-fired plants presented in several recent studies. The data
assembled by each entity is quite complex with respect to original
estimated price levels, inflation to updated price levels, or pr·ojected
future on-line dates, size, pollution control equipment, location, type
of plant, and other items. Price levels were not adjusted to a uniform
date because of the complexity of data involved.
All 1977 and 1978 estimates are substantially higher than APA estimates
for the 1976 Alaska Power Survey and the 1976 report.
The most in-depth analysis was the WPPSS study which investigated the
construction of 1,000-MW steamplants at 10 plant sites in Washington,
Montana, and Wyoming. Several grades and sources were assumed. Costs
were estimated for with and without sulphur dioxide scrubbers
(scrubbers). Twenty-two options of plant sites, coal supply, and trans-
portation were investigated.
APA's estimate of coal-fired steamplant investment costs is derived from
the WPPSS study. Procedures for adjusting costs to current Alaska
conditions are similar to the analysis used in the appended Battelle
report.
The basic cost in ·the WPPSS study for a 1,000 MW single unit plant in
operation during mid-1976 was:
Without Scrubbers $554/kw
With Scrubbers $684/kw
The WPPSS procedure increased these costs for the quality of the coal
used and other specific powerplant site conditions. The coal quality
problems have not been considered in this estimate, and the construction
site·variable is assumed to be included in the Alaska factor.
64
Table 19
COMPARISON OF INVESTMENT COSTS FOR COAL-FIRED STEAMPLANTS
Upper Susitna Project 'Power Market An?lysis
Price No. of Investment
Source of Estimate Level Location Size, MW Units Scrubbers Cost, $/kw
ALASKA LOCATIONS
APA ]:_/ 'Oct. 1978 Healy or Beluga 200 2 No 1,500
Oct. 1978 Healy or Beluga 200 2 Yes 1,860
Oct. 1978 Healy or Beluga 500 2 No 1,300
Oct. 1978 Healy or Beluga 500 2 Yes 1,610
APA Susitna River Studies
Jan. 1975 Healy or Beluga 200 2 Yes· 726
Jan. 1975 Healy or Beluga 500 2 Yes 630
0\
V1 Golden Valley Electric
Association ~./ 1974 Healy 132 2 No 950
197.7 Healy 150 2 No 1,400
1977 Healy 150 2 Yes 1,700
1978 Healy 100 1 Yes 1,800
3 1977 Beluga 200 1 Battelle -/ Jan. No 1,220 to 1, 571
Jan. 1977 Beluga 200 1 Yes 1,400 to 1,766
Jan. 1977 Healy or Nenana 200 1 No 1,470 to 1,920
Jan. 1977 Healy or Nenana 200 1 Yes 1' 710 to 2,158
Jan. 1977 Anchorage 200 1 No 1,120 to 1,440
Jan •• 1977 Anchorage 200 1 Yes 1,280 to 1,690
Federal Energy Regulatory
Commission !!._/ Jan. 1977 Anchorage or 450 2 Yes 900
Kenai Areas
Oct. 1978 Anchorage or Kenai
Areas 450 2 Yes 1,220 to 1,240
Oct. 1978 Healy 230 2 Yes 1,475 to 1,510
0\
0\
Table 19 (cont.)
COMPARISON OF INVESTMENT COSTS FOR COAL-FIRED STEAMPLANTS
Source of Esttmate
Upper Susttna Project Power Market Analysts
Prtce
Level Locatton Stze, MW
PACIFIC NORTHWEST AND WESTERN U.S. LOCATIONS
Washington Public Power
Supply System 2/ Mid 1976 Pacific Northwest 1,000
Mid 1976 Pacific Northwest 1,000
July 1987 Pacific Northwest 1,000
July 1987 Pacific Northwest 1,000
Electric Power Research
Institute 6/ July 1976 Western U.S. Remote 500
July 1976 Western U.S. Remote 500
July 1976 Western U.S. Remote· 1,000
July 1976 Western U.S. Remote 1,000
Idaho Nuclear Energy
Commission Jj 1984 Boise, Idaho 1,000
1984 Boise, Idaho 1,000
No. of
Units
2
2
2
2
1
1
2
2
2
2
Scrubbers
No
Yes
No
Yes
No
Yes
No
Yes
No
Yes
Investment
Cost, $/kw
554
684
848
1,056
896
1,036
830
960
828
934
l/ APA's estimate is based largly on the WPPSS study with adjustments for Alaska conditions and size of plant.
Future inflation not shown.
~ GVEA 1974 estimate assumed units becoming operational in 1983 and 1986. The 1978 estimates assume operation
in 1984 at $2,500/kw assuming 7% inflation.
2/ Battelle's estimates are based on adjusting both WPPSS and EPRI study data. The higher figures are from the
EPRI study. Their studies with future operation dates include inflation.
4/ Scrubbers are assumed included in the cost.
S/ This is the basic study adjusted by APA and Battelle above. The 1987 costs include 5 percent annual inflation.
6! The July 1976 price level includes costs for initial operation in 1978.-
7/ The price level is 1975 costs adjusted to show costs for a 1984 operation date.
v ------------·
Adjusting the cost for the time between mid-1976 and October 1978 using
the Randy-Whitman Steamplant Cost Index increased the cost 18.4 percent.
Hithout Scrubbers
With Scrubbers
$656/kw
$810/kw
Powerplants smaller than the 1,000 MW that will fit near-future Alaska
power needs have a smaller total cost, but a larger cost per installed
kilowatt. An adjustment needs to be applied to the costs to compensate
for the loss of economy of the large scale plants. The factor recom-
mended is the ratio of the plant size to the 0. 85 exponent. A 500-MW
plant thus costs 55.5 percent of a 1,000 MW plant, and a 200-MW plant
costs 25.5 percent. Scaling the plants to 200 MW and 500 MW ·gives:
· Plant Size
Without Scrubbers
With Scrubbers
$ Million
167,000
207,000
200 MW
$/kw
835
1,035
$ Million
364,000
450,000
500 MW
$/kw
728
899
An Alaska factor of 1. 8 was used to adjust Pacific Northwest costs to
Alaska wages and conditions:
Plant Size
Without Scrubbers
With Scrubbers
$ Million
300,000
372,000
200 MW
1,500
1,860
$ Million
655,000
810,000
500 MW
1,310
1,620
Fuel Cost and Availability -There is a wide range of opinions about the
probable future cost of coal. For many years, coal prices were set at a
small margin above production costs so that coal could compete with
low-cost oil and natural gas. This situation has changed drastically
because of price increases for oil and gas and incentives for power
generation and has resulted in industrial conversion to coal. Coal
production costs are also increasing rapidly due to normal inflationary
and regulation factors. FERC reported the national average price of
coal at 96.2¢/million Btu in July 1977, up from 80.8¢ in July 1975, and
39.8¢ in August 1973.
Alaskan coal prices have shown sizable increases recently. The cost of
coal at Healy in September 1978 was 80 cents per million Btu, up from 62
cents in 1975. The Fairbanks Municipal Utility System (FMUS) pays an
additional $6/ton shipping cost for Healy coal resulting in a price of
$1.15 per million Btu at the powerplant in Fairbanks.
67
In October 1978, owners of the Beluga coal field stated that large
reserves in the Beluga coal field may compete in the world energy market
at a price of $1.10 to $1.40/million Btu stockpiled on the shore of Cook
Inlet. The conclusions were based on company studies that included
geologic investigations, drilling, bulk sampling programs, mining
preparation, environmental evaluation, and navigation and shipping
studies.
FERC estimated $1.00/milliori Btu for determination of power values in
the Bradley Lake Project (October 1977). Other recent studies suggest
this is a reasonable current (1978) cost for Beluga coal delivered to a
steamplant at Beluga, with no allowance for price increase in future
years.
Earlier APA studies for the 1976 FPC Power Survey and the 1976 Susitna
report assumed $1.00 to $1.50/million Btu for coal at 1985 price levels
in 1974 dollars. This included consideration of future economies of
scale of larger mining operations.
APA analyses for this report are still based on a coal cost of $1.00 to
$1.50/million Btu for a mine-mouth plant at either Beluga or Healy for
mid-1980 conditions. This is comparable with $1.28 in 1985, estimated
by GVEA for Healy coal by increasing the current 80 cents by 7 percent
annually. Because of the wide diversity of studies and opinions,
analyses based on a range of costs are presented.
In this study, we are assuming fuel values will increase about 2 percent
per year--more rapidly than overall price indexes. This is consistent
wi~h other analyses.
68
Table 20
GENERATION COSTS FOR CONVENTIONAL COAL-FIRED STEAMPLANTS
Upper-Susitna Project Power Market Analysis
1985 COSTS (1978 PRICES)l/ Plant Size, MW
Number of Units
Investment Cost, Raifbelt, $/kw
Capital Cost, mills/kwh
Operation and Maintenance, mills/kwh
Subtotal
200 500
2
1,860
38.5
6.5
45.0
2
1,620
33.5
5.6
39.1
1.00/mmBtu 1.50/mmBtu
Assumed Fuel Costs, mills/kwh
Transmission Cost to Load Center
Total Energy Cost, mills/kwh
1994 ENERGY COST
Capital Cost, mills/kwh
Operation and Maintenance, mills/kwh
Transmission Cost, mills/kwh
Subtotal
Fuel, Inflated 2% 1985 to 1994
Total
10.0
4.0
59.0
Fuel
12.0
61.0
15.0 10.0
4.0 3.0
64.0 52.1
escalated 2%/year
38.5
6.5
4.0
49.0
17.9 12.0
66.9 54.1
Fuel Escalated 7%/Year from 1~85 to 1994;
Capital Cost and O&M Escalated 5%/Year from 197-8 to 1994
Capital Cost 80.0
Operation and Maintenance 13.5
Transmission 8.3
Subtotal 101.8
Fuel 18.4 27.6 18.4
Total 120.2 129.4 105.9
15.0
3.0
57.1
1985 to 1994
33.5
5.6
3.0
42.1
17.9
60.0
69.7
11.6
6.2
87.5.
27.6
115.1
l/ APA estimate based on studies by Washington Public Power Supply System
Studies 1977.
69
Cost of Power -The estimated total cost of electric power that would be
generated by a coal-fired steamplant alternative to the Susitna proJect
is presented in table 20. Development of the estimated cost applied to
a plant in either the Beluga or Healy area is based on the investment
and fuel costs discussed earlier in this section, and includes other
criteria developed in this report. In summary, the parameters are:
1. Investment cost includes all construction, overhead, and interest
during construction, and is based on updating and adjusting WPPSS
Pacific Northwest costs for Alaska conditions. Annual capital costs are
based on a 35-year life and 7 percent interest rate.
2. Operation and maintenance costs are based on a detailed WPPSS
·personnel and materials estimate adjusted for plant capacity in the same
man~er as investment costs, increased by 50 percent for Alaska
conditions, as developed in the 1976 Alaska Power Survey, and indexed
from January 1977 to October 1978 using the U.S. Department of Labor
index.
3. Fuel costs of both $1.00 and $1.50/kw are presented with a heat
rate of 10,000 Btu/kwh.
4. Transmission costs are for lines connecting Beluga with Anchorage,
and Healy with Fairbanks.
The resulting average unit cost of electric power from coal-fired
steamplants to supply the Railbelt market area ranges from 5.21 to
6.40¢/kwh, varying with fuel cost and plant capacity.
Table 20 also presents an analysis of the cost of energy with fuel costs
escalated at 2 percent anually from 1985 through 1994 (Susitna project,
Watana phase on-line) and fuel cost escalated at 7 percent annually from
1985 through 1994.
Comparative Cost of Power (FERC) -FERC evaluated alternative costs for
coal-fired steam plants at Beluga for the Anchorage area and Healy for
the Fairbanks area as part of their power benefit studies for the Upper
Susitna Project.
The FERC estimates of 4.93 to 5.64¢/kwh are in the same range as those
estimated by APA for the Anchorage area. Howe"<!er, the FERC estimates of
4.02 to 4.30¢/kwh for the Fairbanks area are low compared to APA
estimates. FERC estimated construction costs (July 1978) at $1,475/kw
compared to $1,810/kw estimated by APA. In addition, GVEA recently
estimated a cost of $1,800/kw for a comparable Healy steamplant.
FERC data are based on:
1. An Anchorage area plant assumed to be a two-unit 450-MW plant with
fuel cost of $1.10/million Btu and a heat rate of 10,000 Btu/kwh. The
Fairbanks plant is assumed to be two units, totaling 230 MW, with a fuel
cost of $0.80/million Btu and a heat rate of 10,500 Btu/kwh. For
non-Federal cases, the Anchorage area plant investment cost was
estimated at $1,240/kw and the Fairbanks investment cost at $1,475/kw.
70 .
2. Financing is based ~n a composite Anchorage-Kenai interest rate of
7.9 percent with 75 percent financing by REA at 8.5 percent and. 25
percent by the municipality of Anchorage at 6.25 percent. The interest
rate for Fairbanks is 5. 75 percent assuming State of Alaska Power
Authority financing. In comparison, a Federal rate of 6.875 percent is
used for both areas, the same rate ·used in the Corps of Engineers
benefit analysis.
Oil and Natural Gas
The Upper Susitna Project involves a large new power supply beginning in
1994, with an expected life in excess of 100 years.
APA does not believe that oil and natural gas are realistic alternatives
for equivalent power supplies, particularly in view of the timeframe
(start in 1994) and very long life (through 2094).
Hydro
Criteria -Evaluation of possible hydroelectric generation alternatives
to the Susitna project is based on comparing: (1) the potential
generation capability, and (2) unit cost of power. Possible sites are
identified by: (1) single sites with sufficient capacity to supply the
projected power demands; (2) combinations of smaller sites within
selected geographic areas and river basins; and (3) a combination of the
best sites from all areas accessible to the Railbelt.
The hydro evaluation considered power requirements ranging from 600 MW
to 2, 290 MW, which are, respectively, the low-range and high-range
projected increases in Railbelt demands from 1990 to 2000. Associated
annual firm energy requirements would range from 2, 6 70 gwh to 10, 260
gwh. By comparison, the Susitna project is scheduled·to provide about
1,573 MW capacity and 6,100 gwh annual firm energy.
Possible hydro generation alternatives were selected from the APA
inventory of hydroelectric resources. The inventory estimates unit cost
of power at the generator bus bar based on 1965-1966 cost at 3 174
percent interest rate. Susitna inventory cost data indexed to !975
price levels give unit costs within 10 percent of that determined for
the 1976 report.
Single Large Capacity Sites Seven single sites have sufficient
capacity potential to be an alternative to supplying minimum Susitna
market area requirements. These are within a maximum of 1.4 times the
unit cost for Susitna power. However, land use designations (National
Parks and Monuments and Wild and Scenic Rivers) and/ or known major
environmental impacts preclude consideration of developing any of the
sites at the present time.
71
The sites are:
Site
Holy Cross
Ruby
Rampart
Porcupine
Woodchopper
Yukon-Taiya
Wood Canyon
Stream
Yukon R.
Yukon R.
Yukon·R.
Porcupine R.
Yukon R.
Yukon R.
Copper R.
Firm
Energy
GWH/yr
12,300
6,400
34,200
2,320
14,200
21,000
21,900
Capacity Percent
MW of Susitna
Cost
2,800 140
1,460 62
5',o4o 32
530 79
3,200 71
3,200 52'
3,600 51
None of the above sites can be considered available resources in the
1990's timeframe. This is due to: (1) Holy Cross, Ruby, Rampart, and
Woodchopper are main-stem Yukon River sites with known major environ-
mental problems, (2) Porcupine, Woodchopper, and Yukon-Taiya have major
international considerations, and (3) Wood Canyon has a known major
fishery problem.
Sites within the Nenana River basin have also been identified in past
work. their economic feasibility depends upon being developed as a
unit. However, several of the sites are located partially within Mount
McKinley National Park and are precluded from development.
In conclusion, no single, large hydro generation sites are available as
alternatives to the Upper Susitna Project.
Combination of Small Capacity Sites -Combinations of single sites with
less capacity than the Susitna project consist of 78 sites within the
Matanuska, Tanana, Yentna-Skwentna, Talkeetna, and Chulitna River
basins, the northwest drainage of Cook Inlet, the Kenai Peninsula, and
scattered small sites· and small basins within the Railbelt area. None
of these areas contain sites with total capacity potential to supply
m1n1mum Susitna requirements. (Site combinations with the most
capacity--the Yentna-Skewntna River basin and Kenai Peninsula--total 609
MW and 646 MW respectively, but with costs for individual sites ranging
from 1.4 to 20 times Susitna costs.)
If consideration is given to combining the best small sites from each of
the geographic areas, 12 sites totalling 1,276 MW are within the range
of twice the cost of Susitna. Only one (Chakachamna) is near Susitna
cost (103 percent), and has 366 MW potential.
Chakachamna is partly within the new Lake Clark National Monument. Other
new or proposed Federal land withdrawals would preclude sites with about
half of the total potential of the combined sites. Other sites have
various environmental impact potentials. Some streams that would be
affected have major anadromous fish resources. Also, because the sites
are widely distributed, the needed transmission systems would be fairly
extensive and costly.
72
Summary -Based on examination of individual sites and combinations of
sites, there are no hydro generation opportunities available to provide
enough power to be an alternative to the Susitna Project. Small
individual sites may be available, but would satisfy only a small
portion of the market area demand. Other sites, with apparently
acceptable quantity and economic capability, have been or will be
precluded by land status designation.
Nuclear
Nuclear generation may be technically viable in Alaska, but probable
cost and siting problems eliminate it as a potential alternative to
Susitna. Available information indicates that in other states, nuclear
is economically competitive with coal, depending on specific conditions.
Difficult conditions, possible seismic and environmental siting
problems, and readily available coal indicate that nuclear generation
will probably not be economically attractive in Alaska in the
foreseeable future.
Wind
The State has shown serious interest in wind generation technology by
developing pilot projects in the bush communities of Ugashik, Nelson
Lagoon, and Kotzebue. Wind seems to provide near-term power for small
communities presently dependent on high~cost diesel generation.
The cost and applicable scale of technology does not make wind power a
viable alternative for large near-future power demands.
Geothermal
Investigations to date have found no high quality geothermal resources
suitable for power development in areas accessible to the Railbelt area.
Geothermal potential is considered high in the Wrangell Mountains and
portions of the Alaska Range, and may be applicable to the Railbelt in
the future. At this time, insufficient data are available to define the
-resource, even for appraisal of the large Susitna project market.
Tide
There is a large physical potential for tidal power development in the
Cook Inlet area where the State estimates that a total of 8,560 MW could
be harnessed.· A potential of 785 MW is estimated for Knik Arm alone,
and approximately twice that amount for Turnagain Arm.
Several different concepts have been developed for the Cook Inlet tidal
potential because of the interest in alternative energy sources. There
is merit to preparing a good reconnaissance of this alternative, as
pointed out in the 1976 report. However, the scope of work involved to
develop the tidal resource, the large cost of development, and the
important environmental considerations eliminate tidal power as a
reasonable alternative to the Susitna project.
73
Conclusion
The range of power options for the Alaska Railbelt is narrowing rapidly.
1. Oil and natural gas are very suspect in terms of long-range
national supply and availability for use in power production.
2. Coal is proving to be far more expensive as a power source than
previously anticipated.
3. Many hydroelectric alternatives have moved to the "unavailable"
classes because of land area designations. The remaining are less
desirable in terms of cost and ability to meet projected requirements.
4. Nuclear is expected to be as expensive as coal.
5. Geothermal, tide, and wind are unrealistic planning alternatives at
this time.
74
PART VII. LOAD/RESOURCE AND SYSTEM POWER COST ~~ALYSES
Introduction
A series of load/resource and system cost analyses were made to
demonstrate impacts of the Susi tna project in terms of overall power
system costs.
The load/resource analysis' -determined probable timing of new major
investments in generation and transmission facilities. It also shows
annual energy from each type of plant. The load/resource analyses were
prepared for these basic power supply strategies:
Case 1. All additional generating capacity assumed to be coal-
fired steam turbines without a transmission interconnection between the
Anchorage-Cook Inlet area and the Fairbanks-Tanana Valley area load
centers.
Case 2. All additional generating capacity assumed to be coal-
fired steam turbines, including a transmission interconnection.
Case 3. Additional capacity to include the Upper Susitna project
(including transmission intertie) plus additional coal as needed, and
for the three load limits (high, medium, and low).
f
Tne system cost analyses, keyed to the load/resource, determined cost by
year to amortize investments and pay all annual costs (fuel, O&M
expenses, etc). Inflation rates of 0 and 5 percent were considered.
APA developed a number of the key inputs, e.g., demands, unit sizes and
costs, etc. APA contracted with Battelle to make the· studies and
prepare the report.
This section summarizes key assumptions and results. More detailed
information is available in the appended Battelle report.
Basic Data and Assumptions
Basic data and assumptions used in the load/resource and system power
cost analyses are:
1. Interest rate for repayment of facilities = 7 1/2 percent.
2. Inflation rates of 0 and 5 percent, with construction costs
increasing at inflation rate, and fuel costs increasing at 2 percent
abov~ inflation rate.
3. System reserve capacity of 25 percent for non-interconnected load
centers and 20 percent for interconnected systems.
4. Transmission losses of 1. 5 percent for energy and 5 percent for
capacity.
75
5. Retirement schedules for proposed generating facilities (economic
facility lifetime):!/
Coal-Fired Steam
Oil-Fired Steam
Gas-Fired Combustion Turbine
Oil-Fired Combustion Turbine
Hydroelectric
Diesel
Years
35
35
20
20
50
20
6. Plant factors for new and most of the existing facilities
are:
Hydro
Steam
Combustion turbine
Diesel
Percent
50
75
50
10
The factor for combustion turbines was reduced to 10 percent in the
study when adequate steam turbine capacity was available.
l/ See tables 3.4 and 3.5 of appended Battelle report for est.imated
retirement dates of existing facilities.
7. Hydro plants designed for 115 percent of nameplate capacity for
limited reserve requirements.
8. Watana power on-line (POL) in 1994 and Devil Canyon POL in 1998.
9. Existing and planned generating facilities for Anchorage and
Fairbanks are shown in the appended Battelle report.
10. New coal-fired steamplants for Fairbanks assumed to be 100-MW units
(first six), then 200-MW units. Anchorage units assumed to be 200 MW
(first five), then 400-MW units.
11. New coal-fired steamplants to be located at Beluga for Anchorage
area and at Healy (or other sites within 100 miles) for Fairbanks.
12. Fuel costs--see appended Battelle report.
13. Power demands will be met by resource allocation using Susitna
hydro generation first, coal-fired second, and natural gas and oil last.
14. Heat rate for new coal-fired steamplants = 10,500 Btu/kwh.
76
15. Total investment cost in October 1978 dollars.
Plant
100-MW Coal Steam Turbine
200-MW Coal Steam Turbine
400-MW Coal Steam Turbine
Watana Dam (795 MW) and
Transmission Line
Devil Canyon Dam (778 MW)
Total Susitna Project (1,573 MW)
($ million)
245.4
372.0
646.8
2,020.7
470.5
834.0
3,335.2
16. Operation, maintenance, and replacement costs.
Plant
100-MW Coal Steam Turbine
200-MW Coal Steam Turbine
400-MW Coal Steam Turbine
Watana Dam (795 MW)
Devil Canyon Dam (778 MW)
New Transmission Facilities
Study Methodology
($ million/yr.)
3.76
5.7
9.8
0.74
0.73
($/kw)
2,454
1,860
1,617
2,554
1,072
2,120
($/Rw/yr.)
37.6
28.5
24.5
0. 941/
0.94l/
2.0])
As stated in the introduction, three cases were analyzed to determine
timing of generation and transmission (G&T) investments and their impact
on total power system costs.
The first step in estimating the cost of power from alternative
generation and transmission system configurations was to perform a
series of load/resource analyses. These analyses determined the
schedule of major investments based on assumptions of load growths,
capacity and energy production of the potential generating facilities,
and constraints as to when the facilities could come on-line. The
load/resource analyses also determined the annual power production from
each type of generating plant in the system.
The system cost analyses then determined the annual cost for amortizing
and operating the facilities. Summing the annual cost for generation
and transmission of each of the generating facilities gave a total cost,
by year, for the entire system being analyzed. Dividing the total
annual cost by·· the power produced gave an average annual cost of power
for the entire system.
1/ This breakdown of OM&R costs by project feature for convenience of
the load/resource analysis resulted in slightly higher cost. Signifi-
cance to Susitna rate is, at most, less than 1 percent.
77
Rounded Thermal generating capacity additions to the year 2010 from the
previous tables are summarized as follows:
. Table 21
SUMMARY OF THERMAL GENERATING CAPACITY ADDITIONS TO THE YEAR 2010
Upper Susitna Project Power Market Analysis
Case 1: Without Interconnection & Without Susitna
Assumed Load Me!:1iawatts
Growth Anchora~e Fairbanks Total
Low 2,600 471 3,071
Mid 4,600 871 5,471
High 8,200 1,471 9,671
Case 2: Interconnection Without Susitna·
Assumed Load Megawatts
Growth Anchorage Fairbanks Total
Low 2,200 471 2,671
Mid 4,200 671 4, 871
High 8,-200 1,271 9,471
Case 3: Interconnection With Susitna
Assumed Load Megawatts
Growth Anchorage Fairbanks Total
Low 1,000 171 1,171
•
Mid 3,000 371 3,371
High 6,600 1,071 7,671
Note: Bradley Lake and Susitna hydroelectric projects are not included.
78
Results
Load/Resource Analyses
The schedule of new plant additions for Anchorage and Fairbanks for
1978-2011 are shown in the appended Battelle report. A summary of the
thermal generating capacity additions is in table 21. Further
discussion of the computer model results and graphs are also shown in
the appended Battelle report~
Under the criteria used, completion of construction for interconnection
is scheduled in 1986, 1989, and 1994 for high, mid and low load growth
cases, respectively, without Upper Susitna. With Upper Susitna, the
corresponding dates are 1986, 1989, and 1991.
System Power Costs
Annual system costs and unit power costs are presented in detail, both
tabular and graphically, in the appended Battelle report. The following
tabulations summarize these findings. Table 22 shows annual power
system costs for cases 1, 2, and 3, high, mid and low range, with 0
percent inflation. The first few years after Watana comes on-line, the
total annual power system costs increase slightly. However, comparing
the total annual power system costs for the 1990-2011 period to case 1,
construction of the Susitna project results in a savings of $2.20
billion, or 12 percent.
Figure 18 shows the relative savings in annual cost for case 3, with
Susitna, and case 1, without Susitna, for the three load growth
assumptions.
Tables 23, 24, and 24a summarize Anchorage and Fairbanks separately plus
the combined system average annual power costs in ¢/kwh for 1978-2011.
The tables verify the feasibility of the intertie in power cost savings
for Anchorage and Fairbanks. By the year 2000, system wide power rates
would be:
79
Average Power System Rates for Anchorage and Fairbanks -0% Inflation
(¢/kwh)
Anch.
High 6.2
Mid 6.6
Low 7.1
High
Mid
Low
Case 1
Without Susitna
or Intertie
Case 2
With Intertie
Case 3
With Susitna
and·Intertie
Combined Combined Combined
Fbks. S:2:stem Anch. Fbks. System Anch. Fbks. System
8.8 6.6 1/ 6.1 8.0 6.4 5.8 6.2 5.8
8.9 6.9 l/ 6.2 8.4 6.6 5.5 6.7 5.7
9.2 7.5 1/ 6.2 8.8 6.7 6.1 7.8 6.4
Comparison of Power Costs by Year 2000
Percent Change in Cost of Power Below Case 1 -0% Inflation
Case 2 Case 3
Combined Combined
Anch. Fbks. System Anch. Fbks. System
-1.6 -10.0 -3.1 -6.7 -41.9 -13.8
-6.5 -6.0 -4.5 -20.0 -32.8 -21.1
-14.5 -4.5 -11.9 -16.4 -17.9 -17.2
For the Anchorage-Cook Inlet area, inclusion of the Susitna Project into
the system (case 3) generally raises the cost of power above cases 1 and
2 during the first two to four years after Watana comes on-line, but
lowers power costs during the 1996-2011 period. This reduction in the
cost of power is significant in most cases.
For the Fairbanks-Tanana Valley load center construction of the inter-
connection (case 2) again generally reduces the cost of power compared
to without an interconnection (case 1). The inclusion of the Susitna
project (case 3) generally raises the cost of power above case 2 for
about two years after Watana comes on-line, but, as with the
Anchorage-Cook Inlet area, results in lower power costs during the
1996-2011 period.
l/ ·Anchorage and Fairbanks are not interconnected for case 1, the
combined system rate is shown for academic comparison purposes only.
80
Table 22
CCMBINED .l\NOIORAGE-cOOK IN!..FJI' liND FAIRBl\."00)-Tl\NA..i.m. WJ.J.El ANNUAL PCWER SYSTEM COSTS -0% INFIATICN
1978-79
1979-80
1980-81
1981-82
1982-83
1983-84
1984-85
1985-86
1986-87
1987-88
1988-89
1939-90
1990'-91
1991-92
1992-93
1993-94
1994-95
1995-96
1996-97
1997-98
1998-99
1999-2000
2000-2001
2001-2002
2002-2003
2003-2004
2004-2005
2005-2006
2006-2007
2007-2008
2008-2009
2009-2010
. 2010-2011
Total
Subtotal 1990-2010
' I " U).)per Susitna Project Power Market" Analysis
Wii
68.4
80.3
89.i
95.9
108.4
107.1
109.3
120.7
119.1
173.4
170.8
236.8
243.5
256.8
292.5
297.3
364.4
404.8
464.4
480.6
511.1
592.9
586.2
588.7
584.1
587.5
590.1
651.9
655.6
659.2
662.4
666.6
670.4
12,290.3
CliSEI
MEDIUM
68.3
80.2
89,0
95.9
146.0
147.4
152.1
252.5
257.9
296.7
298.5
362.6
371.0
422.4
5'01.0
512.6
521.1
591.3
701.4 .
783.7
819.7
888.2
886.7
894.8
955.3
998.7
1,008.2
1,096.1
1,106.3
1,117.0.
1,127.6
1,139.7
1,209.5
19,905.4
'HIGH
68.3
80.2
89.0
95.9
203.5
245.3
321.6
383.2
456.8
464.7
547.9
575.3
587.7
667.7
754.9
766.1
865.0
863.6
1,060.8
1,164.7
1,282,6
1,389.3
1,450.2
1,471.2
1,544.0
1,661.5
1,684.5
1,787.1
1,872.1
1,935.1
2,021.4
2,108.5
2,136.6
32,606.3
10,811.0 17,658.3 ·29,074.6
68,4
80.3
89.1
95.9
108.4
107.1
109.3
120.7
ll9.1 *
173.4
170.8
236,8
243.5
256.8
292.5
297.3
339.6
382.7
441.0
517.4
525.1
527.2
600.2
602.7
598.1
601.6
604.1
606.2
632.6
636.2
639.9
643.6
647.5
l2,ll5.1
10,796.4
CASE II
MEDIUM
68,3
80.2
89.0
95.9
146.0
147.4
152.1
252.5
257.9
296.7
298.5
338.7 *
382.8
434.0
498.1
503.3
536.2
629.8
714.7
737.2
832.8
841.7
899.8
907.9
931.3
999.4
1,009.5
1,018.0
1,028.2
1,118.2
1,128.9
1,140.0
. 1,151.1
lg,666.1
17,442.9
HIGH
68.3
80.2
89.0
95.9
203.5
245.3
321.6
383.2
434.0
502.1
510.8
593.7
603.1
682.0
735.1
832.8
847,4 *
951. 3.
1,068.2
1,172,2
1,254.6
1,333.7
1,423.1
1,503.9
1,576,7
1,634.5
·1,691.9
1,774.8
1,859.8
1,965.2
1,991.8
2,078.9
2,163.1
32,671.7
29,144.1'
($ Million)
CASE III
. 68.4
80.3
89.1
95.9
108.4
107.1
109.3
120.7
ll9.1 *
173.4
170.8
236.8.
243.5
293.4
290.5
330.9
487.9 jf
MEDIUM
68.3
80.2
89.0
95.9
146.0
147.4
152.1
252.5
257.9
296.7
298.5
338.7 *
382.8
434 .o
498.1
503.3
658.0 jf
662.7
667.0
688.5
721.4+
722.9
719.9
725.9
827.2
834.7
841.4
847.8
915.6
923.9
932.4
941.3
. 487.6
486.0
479.1
485.8 +
506.6
495.9
494.8
487 .2·
488.6
488.9
488.7
490.2
491.7
493.3
494.9
496.6
10,981:4
1,010.0
17,682.0
HIGH
68.3
80.2
89.0
95.9
203.5
245.3
321.6
. 383.2
434.0
502.1
510.8
593.7
603.1
682.0 *
735.1
832.8
990.7 il
1,004.1
1,097.1
1,165.6
1,210.4 +
1,222.4
1,253.7
1,355.3
1,426.4
1,482.0
1,583.7
1,662.9
1,686.0
1,769.6
1,853.8
1,913.4
2,018.6
31,076.3
9,502.1 15,458.8· 27,548.7
Note: Savings to total power system 1990-2010 for mid range case l of $17,658.3 million less case 3 $15,458,8 million is $2,199.5 million;'
* Inte:::connection installed
# Nata"la on-line
+ Devil Canyon on-line
..
.z
0
...J
_J -2
-6'7-
I
(/)
1-
(/)
0
(.)
0:: w ;:
0 a..
...J <J:.
:J z
2
<J:
2400·
2200
2000
1800
1600
1400
12'00
1000
800
600
400
200
. ·o
Figure 18
<cOMBir~ED ANCHORAGE-COOl-( INLET AND
FAIRBANKS-TANANA VALLEY
ANNUAL POWER SYSTEM COSTS
\filTH AND VJITHOUT SUSITNA
Upper Susitna Project Power Market Analysis
Case I High
t---+-------+------+------r:<--!1 Case 3 High
•
78 1980
Case f: without :Susitno
Case 3: with Susitna
1990 94 982000 2010
YEAR
82 APA l/79
,.
. Table 23
ANCHORAGE-COOK INLET AREA
AVERAGE POWER COSTS -CENTS PER KILOWATT HOUR -0% INFLATION
Upper Susitna Project Power Market Analysis
Case 1 Case 2 Case 3
Year High Medium ·LOW· High l1edium Low High Medium Low
78-79· 1.3 1.3 1.4 1.3 1.3 1.4 1.3 1.4
79-80 1.4 1.5 1.7 1.4 1.5 .1. 7 1.4 1.7
·80-81 1.3 1.6 .1.8 1.3 1.6 1.8 1.3 1.8
81-82 1.2 1.6 1.9 1.2 1.6 1.9 1.2 1.9
82-83 3.2 2.9 2.2 3.2 2.9 2.2 3.2 2.2
83-84 3.6 2.8 2.1 3.6 2.8 2.1 3.6 2.1
84-85 4.0 2.8 2.2 4.0 2.8 2.2 4.0 2.2
85-86 4.6 4.3. 2.4 4.6 4.3 2.4 4.6 2.4
86-87 5.0 4.2 2.3 4.8 * 4.2 2.3 4.8 * 2.3
87-88 4.8 4.7 3:7 5.3 4.7 3.7 5.3 3.7
88-89 5.4 4.4 3.5 5.1 4.4 3.5 5.1 4.4 3.5
89-90 5.1 4.8 4.2 5.7 4.5 * 4.2 5.7 4.5 * 4.2
90-91 4.8 4.5 4.1 5.4 4.8 4.1 5.4. 4.8 4.1
91-92 5.2 5.0 4.1 5.7 5.3 4.1 5.7 5.3 4.6 *
92-93 5.5 5.6 . 4. 7 5.4 5.9 4.7 5.4 5.9 4.4
93-94 5.3 5.3 4.6 5.7 5.6 "4.6 5.7 .5.6 5.0
94-95 5.5. 5.1 5.3 5.5 5.4 4.9 * 6.4 # 6.9 # 7.3 ~ lr
95-96 5.8 5.6 5.7 5.6 5.8 5.4 6.0 6.5 6.8
96-97 5.9 6.2 6.5 5.8 6.4 5.8 6.2 6.1 6.5
97-98 6.0 6.5 _6.3 5.9 6.1 6.6 6.2+ 5.8+. 6.3+
98-99 6.1 6.3 6.1 6.0 6.5 6.4 6.1 5.8 6.1
99-2000 6.2 6.6 7.1 6.1 6.2 6.2 5.8 5.5 6.1
00-01 6.3 6.4 6.9 6.2 6.6 7.2 5.5 5.3 5.9
01-02 6.1 6.3 6.9 6.3 6.4· 7.2 5.6 5.2 5.6
02-03 6.2 6.6 6.8 6.4 6.3 7.1 5.7 5.7 5.7
03-04 6.3 6.5 6.8 6.2 6.7 7.1 5.6 5.6 5.6
04-05 6.1 6.4 6.7 6.1 6.6 7.0 5.8 5.5 5.6
05-06 6.3 6.9 7.6 6.2 6.5 7.0 5.9 5.4 5.5
06-07 6.4 ·6.8 7.5 6.3 6.4 7.0 5.8 5.8 5.5
07-08 6.3 6.8 7.5 6.5 6.9 7.0 5.9 5.8 5.5
08-09 6.4 6.7 7.5 6.3 6.8 6.9 6.0 5.7 5.4
09-10 6.5 6.6 7.5 6.4 6.7 6.9 5.9 5.6 5.4
10-11 6.3 6.9 7.5 6.5 6.7 6.9 6.0 5.9 5.4
* Interconnection Installed
# Watana on-line
+ Deveil Canyon on-line
83
APA 11/78
Table 24
AVERAGE PCWER COSTS -0% INFlATION (¢/KWH)
FAIRBANKS-TANANA VALLEY AREA
Upper Susitna Project Power Market Analysis
case 1 Case 2
Year High Me:iium Ii:Jw High Medium IJ:::;w
78-79 4.1 4.3 4.4 4.1 4.3 4.4
79-80 4.1 4.3 4.5 4.1 4.3 4.5
80-81 4.1 4.3 4.7 4.1 4.3 4.7
81-82 4.0 4.3 4.7 4.0 4.3 4.7
82-83 3.8 4.2 4.7 3.8 4.2 4.7
83-84 3.4 3.8 4.3 3.4 3.8 4.3
84-85 5.2 3.4 3.9 5.2 3.4 3.9
85-86 4.7 5.4 3.6 4.7 5.4 3.6
86-87 5.9 5.1 3.3 5.5 * ' 5.1 3.3
87-88 5.6 4.8 3.0 5.1' 4.8 3.0
88-89 5.5 4.8 3.1 5.0 4.8 3.1
88-90 6.5 6.3 5.6 4.7 5.8 * 5.6
90-91 6.5 6.4 5.8 4.6 5.9 5.8
91-92 6.2 6.2 5.9 4.4 5.7 5.9
92-93 6.8 7.3 5.6 6.3 5.4 5.6
93-94 6.6 7.1 5~5 7.3 5.2 5.5
94-95 7.4 6.9 7.1 7.0 6.5 6.7 *
95-96 7.2 6.9 7.3 7.8 7.7 6.9
96-97 7.6 7.8 7.1 8.2 7.4 8.3
97-98 8.1 8.3 7.9 8.7 7.8 9.1
98-99 8.9 9.1 9.4 8.3 8.7 ·8.9
99-2000 8.8 8.9 9.2 8.0 8. 4 . 8.8
00-01 8.3 8.7 9.3 7.7 8.3 8.8
01-02 8.0 8.6 9.3 7.5 8.2 8.8
02-03 7.7 8.4 9.1 7.2 9.0 8.7
03-04 8.5 9.8 9.1 8.0 8.9 8.7
04-05 8.2 9.7 9.1 8.7 8.8 8.7
05-06 8.0 9.5 9.0 8.4 8.6 8.6
06-07 7.8 9.4 9.0 8.2 8.6 10.1
07-08 8.5 9.3 9.1 8.1 8.5 10.1
08-09· 8.4 9.2 9.0 7.9 8.4 10.1
09-10 8.2 9.1 9.1 7.7 8.3 10.2
10-11 8.0 9.1 9.1 7.6 8.2 10.2
* Interconnection Installe:i
# Watana on-line
+ Devil Canyon on-line
84
Case3
High Me:iium IJ:::;w
1.3 4.3 4.4
1.4 4.3 4.5
1.3 4.3 4.7
1.2 4.3 4. 7, .}
3.2 4.2 4.7
3.6 3.8 4.3
4.0 3.4 3.9
4.6 5.4 3.6
4.8 * 5.1' 3.3
5.3 4.8 3.0
5.1 4.8 3.1
5.7 5.8 * 5.6
5.4 5.9 5.8
5.7 5.7 7.2
5.4 5.4 6.9
5.7 5.2 6.8
6.4 # 6.8 # 8.8 #
6.0 6.7 8.9
6.2 6.4 8.6
6.2 6.9 7.8
6.1 + 6.9 + 7.6 +
5.8 6.7 7.8
5.5 6.6 7.8
5.6 6.5 7.7
5.7 7.3 7.6
5.6 7.2 7.6
5.8 7.1 7.5
5.9 7.0 7.4
5.8 6.9 7.4
5.9 6.8 7.4
6.0 6.8 7.4
5.9 6.7 7.4
6.0 6.6 7.4
Table 24a
COMBINED ANCHORAGE-COOK INLET AND FAIRBANKS-TANANA VALLEY
AREA AVERAGE ANNUAL POWER COST l/ (¢/KWH)
Upper Susitna Project Power Market Analy~is
Case 2 Case 3
YEAR HIGH MEDIUM ·LOW HIGH MEDIUM LOW
1978-79
1979-80
1980-81
1981-82
1982-83
1983-84
1984·-85
1985-86
1986-87 4.90 * 4.90 * 1987-88 5.31 5.31
1988-89 5.07 5.07
1989-90 5.56 4.79 * 5.56 4.79 *
1990-91 5.24 5.06 5.24 5.06
1991-92 5.52 5.39 5.52 5.39 5.14
1992-93 5.58 5.83 5.58 5.83 4.89
1993-94 5.94 5.57 5.94 If 5. 57 If 5.35 If
1994-95 5. 71 5.63 5.28 * 6.67 6.91 7.59
1995-96 5.92 6.19 5.69 6.25 6.52 7.25
1996-97 6.18 6.61 6.29 6.35 6.17 6.93
1997-98 6.34 6.44 7.08 6.30 6.01 6.56
1998-99 6.36 6.88 6.91 6.14 + 5.96 + 6.39 +
1999-2000 6.37 6.61 6.68 5.84 5.68 6.42
2000-2001 6.47 6.87 7.54 5.70 5.50 6.23
2001-2002 6.53 6.75 7.51 5.89 5.40 6.16
-2002-2003 6.55 6.75 7.39 5.93 5.99 6.02
2003-2004 6.51 7.06 7.37 5.90 5.90 5.98
2004-2005 6.47 6.96 7.33 6.05 5.80 5.93
2005-2006 6.52 6.85 7.30 6.11 5. 71 ~ 5.88
2006-2007 6.58 6.76 7.55 5.97 6.02 5.85
2007-2008 6. 71 1.18 7.53 6.04 5.94 5.82
2008-2009 6.57 7.09 7.51 6.11 5.86 5.79
2009-2010 6.62 7.01 7.50 6.10 5.78 5.76
2010-2011 6.67 6.92 7.48 6.23 6.07 5.74
1/ Case I not interconnected, therefore combined system rate does not
apply.
* Interconnection Installed
' If Watana on-line
+ Devil Canyon on-line
85
Part VIII. INVESTMENT COSTS
Construction costs for power producing facilities were prepared by the
Corps of Engineers (Corps); those for the transmission facilites by
Alaska Power Administration (APA). APA prepared estimates of interest
during construction based on 7 1/2 percent.
Corps estimates include alternative design concepts
Canyon--thin-arch, as orginally proposed by Bureau of
(USBR), and the concrete gravity design, which is more
conservative.
for Devil
Reclamation
costly and
Transmission estimates are based on same plan presented in 1976 report,
with costs updated by indexing.
Current costs for transmission facilities are based on indexing
construction costs presented in the 1976 report (January 1975 prices) to
current levels (October 1978 prices) by applying a factor of 1.38 to
clearing and rights-of-way, 1.33 to all other transmission line
components (access roads, structures, etc.), and 1.28 to substations and
switchyards, resulting in an overall factor of about 1.32. The clearing
and rights-of-way factor is based on experience of the Alaska Department
of Transportation and on recent experience of the USBR and Bonneville
Power Administration (BFA). The 1975 prices are based on component
prices from BFA with an increase of 90.percent for labor and 10 percent
for material transportation from the ~acific Northwest to Alaska.
Examination indicated that these factors are also valid for this
analysis, but sbould be reevaluated if more detailed cost estimates are
made in future years.
Transmission system costs are summarized in table 25.
Investment costs are calculated by adding interest during construction
at the annual rate of 7 1/2 percent to construction costs presented
previously.
The project schedule includes (1) first-stage construction of Watana dam
and powerplant and the total project transmission system, and (2)
second-stage Devil Canyon dam and powerplant. The transmission system
will be completed about three years before completion of Watana to
develop interconnection benefits by deferring of required steamplant
capacity (discussed in Part XIII, Load Resource Analysis).
Table 26 summarizes the investment costs required.
86
Table 25
CONSTRUCTION COST SUMMARY
Upper Susitna Project Power Market Analysis
Item Construction Cost ($1,000 -10/78)
Transmission Lines
Clearing
Right-of-Way
Access Roads
Line Structures
Subtotal -T.L.
Switchyards and Substations
Fairbanks Substation
Talkeetna Substation
Anchorage Substation
Healy Switchyard
Watana Switchyard
Devil Canyon Switchyard
Subtotal-S.S.
Total
Rounded
87
System
No. 5
$ 3,350
5,000
19,110
242,190
$269,650
$ 11,710
10,100
15,890
4, 770
6,360
19,660
$ 68,490
$338,140
$338,000
A:EA 10/78
Table 26
INVESTMENT COST SUMMARY ($/MILLION)
Upper Susitna Project Power Market Analysis
Stage
Power Production Facilities
Construction
Interest during Construction
Investment
Power Transmission Facilities
Construction
Interest during Construction
Investment
Total Investment -Susi tna
88
Watana
(1st)
1,427.0
603.7
2,030.7
338.0
132.5
470.5
2, 501.2
Devil
Canyon
(2nd)
665.0
168.6
833.6
Total
2,092.0
772.3
2,864.3
338.0
132.5
470.5
833.6 3,334.8
APA 10/78
PART IX. OPERATION, MAINTENANCE, AND REPLACEMENT PLAN .AJ.'lD COSTS
Operation and Maintenance
T~is updates information furnished in the 1976 report. Operation,
maintenance, and replacement costs were indexed for this report.
Plan Description
This plan assumes Federal operation of the facilities.
. The plan assumes the headquarters and main operations center for the
Susitna project will be near Talkeetna or at some other equally
accessible point. Equipment at the center will remotely control the
operation of the generation and transmission system and operation of
Devil Canyon and Watana dams and reservoirs. Electrician/operators and
mechanic/operators will be located at the powerplants to provide routine
maintenance and manual operation when required.
Specialized personnel, such as electronic ·technicians and meter and
relay repairmen, will service both powerplants and the substations and
switchyards from the project headquarters. Project administration,
including superv~s~on of power production, water scheduling, and
transmission facilities, will also be from the project headquarters •.
Major turbine and generator inspection and maintenance will be done by
electricians, mechanics, engineers, and other experienced personnel from
AfA. Manufacturers 1 representatives and other specialized expertise
will be consulted.
Alaska Power Administration's (APA) headquarters office in Juneau will
handle power marketing, accounting, personnel management, and general
administrative services.
Transmission line maintenance will be performed by two line crews, with
assistance from the existing Eklutna Proje.ct line crew. Transmission
llne mainten~nce warehous~s and parts storage yards will be at Devil
Canyon or Watana, approximately mid-way between Devil Canyon and
Fairbanks, and at the project headquarters. Line crew personnel will be
stationed along the lines at designated maintenance stations and at the
major substations to provide routine line patrol and maintenance tasks.
Crews from throughout the project will be assembled for major work.
Visitor facilities with provisions for self-guided powerplant tours will
need assistance from operation personnel.
Project-related recreation facilities will require cooperation between
Federal, State, and local interests, and are assumed to be maintained by
a State or local entity.
89
Proj"ect operation, maintenance, and administration could be combined
with the existing Eklutna Project. Eklutna could be supervisory
controlled from the Susitna project operations center with
electrician/operators and mechanic/operators stationed at Eklutna. It
is estimated that approximately $100,000/year could be saved by joint
operation.
Marketing and Administration
Marketing and administration include three main functions:
1. Administration
Personnel management
Property management
Budgeting .
Marketing policy
Rate and repayment studies
2. Accounting
Customer billing
Collecting
Accounts payable
Fina~cial records
Payroll
3. Marketing
Rate schedules
Power sales contracts
Operating agreements
System reliability and coordination
Part of this work would be carried out by the project, with overall
administration and support services provided by the APA headquarters
staff.
Annual Costs
The estimated annual costs for operation, maintenance, marketing, and
administration are based on itemized estimates of personnel, equipment,
supplies, and services needed to do the work, with a provision for
contingencies.
The estimate assumes Federal classified personnel providing management
and administrative functions and wage grade personnel performing
technical operation and maintenance activities. Classified salaries are
based on a mid-grade rate. 1-lage grade rates are based on those in
effect in the Anchorage area and include basic hourly rates, benefits,
and overtime.
90
Costs of supplies, equipment, and ,personnel requirements are based on
Bureau of Reclamation (USBR) guidelines and the experience of the
Eklutna and Snettisham Projects. The Eklutna Project is fully staffed,
i!!cluding a line crew, which has been in operation since 1955. The
Snettisham Project is isolated; it is separated from the Juneau load.
center by 45 miles of rugged terrain and water. A maintenance crew
resides and performs routine maintenance at the powerplant; project
operations are remotely controlled from Juneau. The Susitna project
would have some characteristics of both projects.
Itemized costs for operation, maintenance, marketing, and administration
are presented in table 27.
Costs by major category and number of personnel are summarized in table
28.
Replacements
The annual replacement cost prov1.s1.on establishes a sinking fund to
finance replacement of major items which have an expected service life
of less than the 50-year project repayment period. The objective is to
cover costs and ensure financing for a timely replacement of major cost
items to keep the project operating efficiently throughout its life.
The replacement cost is based on factors developed from USBR experience.
The factors apply to the total powerplant, substation, switchyard,
transmission tower, fixtures, and conductors. Replaceables include
genera tor windings, communication equipment, a small .percent of the
transmission towers, and items in the substation and switchyards. Items
covered by routine annual maintenance costs include vehicles, small
buildings, camp utilities, and materials and supplies. Major features,
such as dams and powerp lant structures, are considered to have service
lives longer than the 50-year repayment period. Their costs are not
covered by the replacement funds. Right-of-way and clearing costs are
not included. The 7~ percent interest rate used for project repayment
was used to establish the replacement sinking fund.
Table 29 presents calculations of the annual replacement fund.
The following tabulation summarizes the operation, maintenance, and
replacement costs:
Watana
Devil Canyon
Total
Annual Operation
and Maintenance
$1,000
$2,360
530
$2,890
Price base -October 1978.
91
Annual
Replacement
$1,000
$260
170
$430
Total
OM&R
$1,000
$2,620
700
$3,320
Table 27
ANNUAL QPERATION & MAINTENANCE COST ESTIMATE
Upper Susitna Project Power Market Analysis
October 1978 Prices
Dam and Po we rp lant, Total Transmission System
Grade Annual
Personnel Number or Rate Cost
Supervisory & Classified
Project Manager 1 GS-14 $ 35,000
Assistant Project Manager 1 GS-13 29,500
Electrical Engineer 1 GS-12 24,800
Mechanical Engineer 1 GS-12 24,800
Supply & Property Clerk 1 GS-9 17,100
Administrative Assistant 1 GS-7 14,000
Clerk-Steno 1 GS-5 11' 300 >
Subtotal Supervisory 7 $. 156,500
& Classified
Wage Grade
Electrician 2 17.00/hr. $ 70,720
Mechanic 2 17. 00/hr. 70,720
Heavy Duty Equip. Operator 1 17.00/hr. 35,360
Laborer 2 13.00/hr. 54,080
Meter Relay Mechanic 1 17. 00/hr. 35,360
Electronic Technician 1 17. 00/hr. 35,360
Powerplant Operator 6 17. 00/hr. 212,160
Ass't. Powerplant Operator 4 15.00/hr. 124,800
Subtotal Wage Grade 19 $ 638,560
Line Crew
Foreman 2 19.00/hr. $ 79,040 .
Lineman 4 17.00/hr. 141,440
Equipment Operator 2 17. 00/hr. 70,720
Ground man 4 17.00/hr. 141,440
Subtotal Line Crew 12 $ 432,640
Allowances
C.O.L.A.-Sup. & Class X 25% 39,130
Shift Differential 22,430
Sunday Pay 12,030
Overtime 32,000
Government Contributions 96,410
Longevity N. A.
Subtotal-Allowances $ 202,000
TOTAL PERSONNEL COST 38 $1,429,700
92
Table 27 (cont.)
ANNUAL OPERATION & MAINTENANCE COST ESTIMATE
Miscellaneous
Telephone
Official travel
Vacation travel
Supplies, Services & Maintenance--Powerplant
Supplies & Services--Vehicles & Equipment
Employee training
Line spray
Government camp maintenance
Subtotal -Miscellaneous
Equipment Operation, Maintenance, and Replacement
Initial
No. Cost
Tractor with Dozer 1 $150,000
Loader 1 75,000
Maintainer 1 75,000
Pickup 10 80,000
Sedan 1 5,000
Tractor & Lowboy 1 75,000
Dump truck 1 25,000
Flatbed 2 20,000
Firetruck 1 25,000
Sno trac 2 16,000
Backhoe 1 35,000
Crane," 50 ton 1 200,000
Hydraulic Crane, 20 ton· 1 100,000
Line truck 4 200,000
Subtotal -Equipment
APA Headquarters Marketing and Administration
Subtotal
Contingencies (20% +)
TOTAL WATANA & TRANSMISSION
93 .
Service
Life
10
10
10
7
7
10
10
7
10
7
10
20
20
10
$
$
$
$
Annual
Cost
10,000
19,000
19,000
125,000
50,000
6,000
25,000
19,000
273,000
15,000
7,500
7,500
11,400
700
7,500
2,500
2,900
2,500
2,300
3,500
10,000
5,000
20,000
98,300
165,000
1,966,000
394,000
$2,360,000
Table 27 (cont.)
ANNUAL OPERATION & MAINTENANCE COST ESTIMATE
Devil Canyon Dam and Powerplant
Personnel
Watana and Devil Canyon, supervisory controlled from a remote
operation-dispatch center.
Increase base staff for Devil Canyon.
Assistant operators 2@15.00/hr.
Electricians 2@17.00/hr.
Mechanics 1@17.00/hr.
Maintenance 1@15.00/hr.
Subtotal
Overtime
Government Contributions
Foreman Pay
Subtotal
Subtotal -Personnel
Miscellaneous
Vacation travel
Employee training
Supplies, Services & Materials
Supplies and Services
Subtotal -Miscellaneous
Eguipment
Initial Service/
Cost Life
Pick up 2 @ 16,000 7
Snow tractor 1 @ 10,000 7
Subtotal -Equipment
APA Headquarters Marketing and Administration
Subtotal Devil Canyon Additions
Contingencies (20% +)
TOTAL DEVIL CANYON O&M ADDITION
TOTAL WATANA AND TRANSMISSION
TOTAL SUSITNA PROJECT
94
$ 62,400
70,720
70,720
31,200
$ 235,040
12,000
21,160
6,500
$ 39,660
$ 274,700
$ 3,800
1,200
112,500
13,400
$ 130,900
$ 2,300
$
$
1,100
3,400
35,000
444,000
86,000
$ 530,000
2,360,000
$2,890,000
\.0
lJl
Table 28
OPERAT~ON AND MAINTENANCE COST SUMMARY
Upper Susitna Project Power Market Analysis
Watana & Trans-
mission System
NYmber Dollars
Personnel:
Salaries/Wages, Allowances
Classified Personnel 7
Wage Board Personnel 31
Miscellaneous:
Telephone, Travel, Supplies,
Services, Training, Line
Spray, Camp Maintenance
Equipment:
Annual cost Replacement
Marketing and Administration
APA Headquarters
Subtotal
Contingencies (20% ~)
TOTAL
$1,429,700
273,000
98,300
165,000
$1,966,000
394,000
$2,360,000
Devil Canyon
Number Dollars
0
7
$274,700
130,900
3,400
35,000
$444,000
86,000
$530,000
Total Devil Canyon,
Watana & Transmission
Number Dollars
7
38
$1,704,400
403,900
101,700
200,000
$2,410,000
480,000
$2,890,000
1.0
"'
Feature
Powerplant
Transmission towers,
fixtures, & conductors
Substations and
swi tchyards
Total
Rounded
Table 29
REPLACEMENT COSTS
Upper Susitna Project Power Market Analysis
Watana and Transmission
System Devil
Annual Annual
Replace-Replace-
ment Construction ment Construction
Factor Cost Cost Cost
0.0010 $197,370,000 $197,370 $120,860,000
0.0001 251,324,000 25,130
0.0033 11,000,000 36,300 14,760,000
$258,000
$260,000
Replacement factors are based on 7 1/2 percent interest rate.
Can:l:on
Annual
Replace-
ment
Cost
$120,860
48,710
$169,570
$170,000
Construction cost based on the portion of the feature·subject to replacement.
Total
Annual
Replace-
Construction ment
Cost Cost
$318,230,000 $318,230
251,324,000 25,130
25,760,000 85,010
$428,370
$430,000
PART X. FINANCIAL ANALYSIS
This part estimates the market for project power and evaluates power
rates needed to repay the investment in power facilities. Power market
size is in more detail in this study than in the 1976 report. Likewise,
costs are slightly more detailed.
The Upper Susitna Project is primarily for hydroelectric power
generation and transmission •. Minor portions of project costs (less than
1 percent) would be allocated to other purposes, such as recreation and
flood control. Project financial viability is the essential element in
demonstrating feasibility of the power development. The repayment rate
is influenced principally by size of the market, amount of investment,
and applicable interest rates. Operation, maintenance, and replacement
costs are a minor part of total annual costs; they influence these rates
insignificantly. If rates needed to repay the hydro project are
attractive in comparison to other available alternatives, the project is
economically justifiable.
The 1976 report compared the costs of five dam and reservoir plans for
developing the Susitna River hydroelectric potential and found all costs
were within a 15 percent range. Therefore, the scoping analysis was not
repeated for this study.
In addition to analyzing the basic Susitna project plan, "variations were
also analyzed for sensitivity. These included interconnection with
additional service areas, different timing-for interconnection between
Anchorage and Fairbanks, use of the more expensive Devil Canyon gravity
dam instead of the arch dam, low load growth, and the effect of
inflation. In addition, the load/resource and system cost analyses
examine impact of the Susitna Project on overall system costs.
Market for Project Power
Upper Susitna will operate as part of a hydro/thermal power system.
The 1976 report assumed the market for Susitna firm energy as 75 percent
of the mid-range utility requirements. Average rates for firm energy
were estimated on ttat basis.
For this analysis, the market for firm energy was assumed to be
approximated by load growth after Susitna power becomes available, plus
market made available through retirement of older plants.
The balance of the Susitna energy is assumed marketable as secondary
energy for fuel replacement, as long as all energy fits under the load
curve. A value is assigned for marketable secondary energy based on
estimated future coal costs. The actual value is probably significantly
higher.
97
The value of fuel replacement energy is the same as that used in the
load resource analysis, which is $1.00 to $1.50/million Btu by 1985.
This is based on the concept that large, efficient coal mines will be
developed in the Beluga area by then. The price is escalated at 2
percent per year above the zero inflat·ion rate from 1985 to 1994,
resulting in a cost of $1.20 and $1.80/million Btu'~.
Table 30 summarizes the estimated market for Susitna energy using these
criteria.
Cost of Project
Table 31 summarizes the construction 'cost, interest during construction,
ope~ation, maintenance, and replacement costs ·for Devil Canyon and
Watana phases. Construction costs were furnished by the Corps for an
October 1978 price level. Interest during construction was calculated
from Corps construction cash flow estimates with interest accumulated
until the project becomes operational. OM&R costs were updated from APA
earlier estimates.
Costs have increased from the 1976 report for several reasons. Table 32
presents a summary comparison of the cost factors. Interest rates have
increased from 6 5/8 to 7 1/2 percent. Design and cost changes were
made by the Corps as a result of foundation drilling. Costs were
updated for the Devil Canyon dam and the transmission line by indexing
procedures. The major change in operation, maintenance, and replacement
costs was due to inflation in personnel wages and provisions for con-
tingencies such as unlisted items and state of the art. Watana' s
construction period was extended from 6 years to 10 years, increasing
its construction period from 10 years to 14 years. The revised project
investment cost is 89 percent higher than in the 1976 report.
98
Year
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
TABLE 30
MARKET FOR UPPER SUSITNA POWER
ANCHORAGE AND FAIRBANKS AREAS
Upper Susitna River Project Power Market Analysis
Finn Energy
Sales GWH
633
1,385
2,231
2,873
3,531
4,244
4,686
5,055
5,630
5,983
6,352
6,767
6,787
MEDIUM ESTIMATE
Fuel Replacement
Sales GWH
2,401
2,043
1,197
555
2,872
2,543
2,101
1,732
1' 115
804
235
20
0
COMPARISON WITH TOTAL AREA POWER·REQUIREMENTS
Estimated Anchorage Estimated Market for
and Fairbanks Energy New Hydroelectric Power
Annual Energy
Year Million KWH
1995 10,323
2000 13,288
2005 15,083
l/ Percent of total area requirements
Data Source: APA Load/Resources Analysis
Medium Load Growth Estimates,
Energy Losses are included.
99
Annual Energy
Million KWH
1,385
(13).!/
4,686
(35)..!J
6,767
(45)..!J
Table 31
INVESTMENT AND OM&R COST SUMMARY
Upper Susitna Project Power Market Analysis
Unit Watana
Completion Date 1994
Costs -$1,000
Power Production Facilities
Construction Costs
Interest During Construction
Investment Cost
Transmission Facilities ~/
Construction Costs
Interest During Construction
Investment Cost
Total System Investment Cost
1,427,000
603,700
2,030,700
338,000
132,500
470,500
Annual Operation and Maintenance
Annual Replacement
Annual OM&R
Devil Canyon
1998
665,000 l;
168,600
833,600
Total System
2,864,300
470,500
3,334,800
2,890
430
3,320
Price level is October 1978. Interest rate for repayment purposes in FY
1979 is 7-1/2%.
1/ Costs are for arch dam plan at Devil Canyon.
2/ Transmission system assumed online in 1991.
100
Average Rate Determination
Table 33 summarizes the estimated average firm energy rate for f:.rn
energy .needed to repay project facilities inv.estment for mid-range load
growth conditions. The method used is similar to that used in the 1976
report. Present Federal criteria for power producing facilities require
repayment ·of project costs, with interest, within 50 years after the
unit becomes revenue producing. The applicable interest rate for Fiscal
Year 1979 is 7 1/2 percent. · Revenues were credited to the project frmn
sale of secondary energy at a fuel replacement rate of 1.2¢/kwh during
early years of project operation. The average required rate for
repayment over 50 years after the last unit is installed is 4. 7¢/kwh.
Total repayment period will be 54 years with Devil Canyon coming on-line
four years after Watana.
Alternatives to the basic project plan were analyzed to determine
effects on average power rates:
1. Devil Canyon gravity dam in lieu of the thin-arch dam:
Investment cost increased $204.9 million.
Average rate for firm energy increased to a total of 4.9¢/kwh.
2. Transmission investment deferred until Watana phase comes on-line
(1994):
Watana phase investment reduced $76 million.
Average rate reduced 0.1¢/kwh to a total of 4.6¢/kwh.
3. Mid load growth case, 5 percent inflation:
Investment cost increased $3.598 billion.
Revenue needs increased $243 million annually.
Firm energy is the same for all mid growth cases.
Average rate for firm energy increased 4.7¢/kwh to 9.7¢/kwh.
4. Low load growth case:
Revenue needs same as for mid range growth case.
Firm ·energy sales decreased; fuel replacement sales increased.
Average firm energy rate increased 1.7¢/kwh.
All Corps plans are based on completing Watana first, fqllowed by Devil
Canyon four years later. This is appropriate for mid range and high
range growth conditions, but if low range conditions remain, it may mean
the Devil Canyon unit could be deferred a few years.
101
Power Marketing Considerations
The average rate is useful for comparing the proposal with the
alternatives. Actual marketing contracts will likely include separate
provisions for demand and energy charges, wheeling charges, reserve
agreements, and other factors.
There are some built-in inequities for any method of pricing. What
amounts to a postage stamp ·rate is used by most utilities and large
Federal systems. That is, power rates are the same for all delivery
points on the system. Actual costs vary with the distance, size, and
characteristics of load--it is more.costly to serve a small load several
miles from the power source than to serve a large load nearby. Policies
vary from system to system as to "hookup" costs born by the customers.
102
Table 32
COST SUMMARY COMPARISON
WITH 1976 INTERIM FEASIBILITY REPORT
Upper Susitna Project Power Market Analysis
1976
Interim
Feasibility
Report
1978 Difference
Item
(Costs $ Million)
Interest Rate for Repayment
Construction ~eriod
Watana
Devil Canyon
Transmission System
Total
Construction Cost
Watana
Devil Canyon
Transmission System
Total
Interest During Construction
Watana
Devil Canyon
Transmission System
Total
Investment Cost
Watana
Devil Canyon
Transmission System
Total
Annual Cost for Repayment
of Investment
Annual Equivalent OM&R
Total Annual Equiv. Cost
(Less Secondary Energy Sales l/
-(Fuel Replacement Sales)-
Total Net Annual Equiv. Cost
Annual Equiv. Energy GWHl/
Total Annual Equiv. Energy
Cost -¢/KWH
ll Median load growth
6-5/8%
6 yrs.
5
3
10 yrs.
832.0
432.0
256.0
1,520.0
165.4
57.2
25.4
248.0
997.4
489.2
281.4
1,768.0
113.34
'
2.27
115.61
s. 77
109.84
5,218
2.11
Marketability
Analysis ~~aunt
Update
7-1/2% + 7/8%
10 yrs.
8
3
14 yrs.
1,427.0
665.0
338.0
2,430.0
603.7
168.6
132.5
904.8
2,030.7
833.6
470.5
3,334.8
239.20
3.14
242.34
11.34
231.00
4,923
4.69
+ 4 yrs.
+ 3
0
+ 4 yrs
+ 595.0
+ 233.0
+ 82.0
+ 910.0
+438.3
+111.4
+107.1
656.8
+1,033.3
+ . 344.4
+ 189.1
+1,566.8
+125.86
+ 0.87
+126.73
+ 5.57
121.16
-295
2.58
Percent
+ 13
+ 67
+ 60
0
+ 40
+72
+ 54
+ 32
+ 60
+265
+195
+422
+265
+104
+ 70
+ 67
+ 89
+111
+ 38
+110
+ 97
+110
-6
+123
Note: Total energy during period of analysis is the same in both reports.
Difference is due to variation in load build-up.
103
)
'
Project Costs
$1,000
Revenue
Table 33
AVERAGE RATE DETERMINATION
(WATANA AND DEVIL CANYON)
Upper Susitna Project Power Market Analysis
1994 PW Costs
$1,000
Project Energy Sales
Million KWH
Producing Firm Fuel Replacement 1994 PW Fuel Replace-
Year Investment
1994 2,501,200
1995
1996
1997
1998 833,600
1999
2000
2001
2002
2003
2004
2005
2006-2047
Totals 3,334,800
Annual Equivalents
Average Rate Computation:
OM&R Investment OM&R Energy Eneq-;y Sales Firm Energy
2,620 2,501,200 2,437 633
2,620 2,267 1,385
2,620 2,109 2,231
2,620 1,962 2,873
(1998-2047)
3,320 624,200 32,256 3,531
3,320 4,244
3,3~0 4,686
3,320 5,055
3,320 5, 630.
3,320 5,983
3,320 6,352
3,320 6,767
6,787
3,125,400 41,031
239,200 3,141
(1) Annual Costs:
(2) Revenue From Fuel Replacement Energy
at 12 mills per kilowatt hour
(3) Equivalent Annual Firm Energy Sales
2,401
2,043
1,197
555
2,872
2.543
2,101
1,732
1 '115
804
235
20
000
Capital
OM&R
Total
(4) Average Rate For Repayment ($231,000,000/
4,923,000,000 KWH)
(1994-2005)
589
1,198
1,796
2,151
2,459
2.750
2,824
2,834
2,937
2,903
2,867
2,841
36' 171
64,320
$239,200,000
3,140,000
$242,340,000
4,923
-11,340,000
$231,000,000
4,923,000,000 KWH
46.9 mills/KWH
ment Sales
2,233
1,768
964
416
2,000
1,648
1,266
971
582
390
106
8
12,352
845
Actual rates for the Susitna system could reflect several items of costs
and revenues not identified in the project studies. For example, during
its life, project facilities would likely be used to wheel power from
other sources. Wheeling revenues will lower overall project power rates
somewhat. Conversely, wheeling costs for project power delivered over
non-Federal transmission lines will be added to project rate schedules.
This is now done under APA marketing contracts for the Snettisham
Project; there are similar situations in other Federal power systems.
Market Aspects of Other Transmission Alternatives
It is reasonable to expect modifications of the project transmission
system as requirements (or needs) change. The main 345-kv and 230-kv
lines could be upgraded substantially by adding compensation and
transformer capacity. Substations could be added as future loads
increase to a case-by-case determination of economics. Similarly,
extensions of the project transmission lines to serve other areas would
be considered on the basis of needs, economics, and available
alternatives.
Anchorage-Cook Inlet Area
The costs in the proposed plan are ·premised on delivery points to
substations near Talkeetna and Anchorage. Rough estimates indicate
similar costs for a plan with delivery points at Talkeetna, Anchorage,
and the existing APA Palmer substation. Basically the proposed plan
includes costs to provide for delivery points on the existing CEA and
APA systems north of Knik Arm, but does not include costs of delivering
power across or around the Arm.
With or without the Susitna project, additional transmission capability
is needed on the approaches to Anchorage. CEA plans for a Knik Arm
system considers 230-kv transmission an important step in developing
this capability, but more capacity will be needed by the mid-1980's.
Essentially the same problems will exist with alternative"power sources,
such as the Beluga coals. ·
Following project authorization, detailed studies will be needed to
consider alternatives for providing power across Knik Arm. Costs would
be worked into rate structures through wheeling charges on non-Federal
lines or annual costs on project lines, if needed.
The transmission plan to deliver project power in Anchorage will need to
be worked out in the detailed post authorization studies. It will
involve added costs, either wheeling charges for project power over
non-Federal lines, or constructing project transmission lines around or
under Knik Arm. These costs could be about the same for alternative
power sources such as the .Beluga coals.
It is essential that scheduling of project facilities be closely tied to
the marketing function.
105
Comparison of Susitna to Steamplants With and Without Inflation
Without inflation, the 4.7¢/kwh rate for the Susitna project is
significantly lower than the estimated cost of power from .coal-fired
steamplants at 5. 2 to 6.4¢/kwh at October 1978 costs. Considering
inflation, the capital costs of both the steamplant and hydro powerplant
increase until construction is complete. For the completed projects,
inflation affects only the hydro project operation and maintenance cost,
a small part of the energy cost: For the steamplant, inflation
continues to increase the fuel cost as well as the much larger operation
and maintenance cost.
The difference of the effect of inflation is shown on figure 19.
Capital and O&M costs are assumed to inflate at 5 percent per year for
both. Fuel costs are assumed to inflate 2 percent per year higher than
a base price of $1.00 or $1.50 per million Btu in 1985. The conclusions
are that Susitna is considerably less susceptible to inflation than
steamplants.
0
106
17
16
15
. 14
13
12
II
:z:
3:
~10
' en
1-
z 9 w
(.)
w 8
1-
<l: a::
7
6
5
4
3
2
0
COMPARISON OF SUSITNA ·Figure 19
AND ALTERNATIVE COAL-FIRED STEAM PLANT RATES
CONSIDERING 5% ANNUAL INFLATION
( pper Susitna Pro ect Power Me rket Anal f{s s /
/ v
v
·j
I
I
I
I /
STEAM PLANT
AL., ERNATIVE~ I ./
/·
.. ~ V/
./ v/ v
/' ~ /
..
/
\__ SUSITNA
1978 1980 1985 1990 1994 1995 2000
YEAR OF PRICE BASE
iE ( Fue I cost infla-ted 2% higher)
107 APA l/79
PART XI. GLENNALLEN AND VALDEZ
Introduction
The primary justification for the Upper Susitna project is to supply
power and energy to the State's two largest power market areas,
Anchorage-Cook Inlet and Fairbanks-Tanana Valley.
The Glennallen-Valdez area is recognized as a possible additional market
area. The two communities are the principal load centers for the Copper
Valley Electric Association (CVEA). At present, both are supplied from
oil-fired generators.
CVEA is now moving into initial construction phases of its Solomon Gulch
hydroelectric plant near Valdez, and is in final design stages for a
138~kv transmission line extending 104 miles to interconnect Valdez and
Glennallen. CVEA could be interconnected with the major ui tlities in
the Anchorage-Cook Inlet area by adding a transmission line between
Palmer and Glennallen. The transmission distance is 136 miles; minimum
transmission voltage would likely be 139 kv. Depending on future
demand, a higher voltage such as 230 kv may be justified.
Very preliminary studies summarized in the following section indicate a
good chance that the Palmer-Glennallen intertie is feasible.
Power Market Area
Introduction
Similar to Fairbanks, both Glennallen and Valdez have been heavily
impacted by trans-Alaska oil pipeline construction and operation. The
pipeline terminus storage and shipping facilities are at Valdez. The
pipeline was· completed and went into operation in 1977. The
Glennallen-Valdez area 1977 population was approximately 9,905, 39
percent higher than in 1974. However, the 1976 population (13,000)
decreased 31 percent in 1977.
Valdez is the proposed site of a major refinery and petrochemical
complex to process the State's royalty share of Prudhoe Bay oil. Plans
are not yet finalized, but construction could begin as early as 1980.
This would "have major impacts in terms of both construction employment
and a long term increase in employment and population for Valdez. The
operations phase of the refinery involves 1,000 new jobs according to
recent reports. Glennallen's population and economy are expected to
continue to grow.
Existing Power System
The Copper Valley Electric Association (CVEA) serves both Glennallen and
Valdez. CVEA' s radial distribution lines extend from Glennallen, 30
miles north on the Copper River, 55 miles south on the Copper River to
Lower Tons ina, and 70 miles west on the Glenn Highway. Figure 2
outlines the area.
108
CVEA plans to construct 104 miles of 138-kv long transmission line
between Valdez and Glennallen. This is related to the Solomon Gulch
12-MW hydro development now beginning construction. At present, the
utility loads are served totally b'y diesel generation of 17.7 MW: 10.1
MW at Valdez and 7. 6 MW at Glennallen. Two small utilities serving
limited areas on the highways north of Glennallen are included in
historical data. Their installed diesel capacity totals 1/3 MW.
The Alyeska oil terminal facility at Valdez has 3 7. 5 MW in oil-fired
steam-turbine capacity. This is a total energy facility that satisfies
the terminal's electrical and steam requirements.
Power Requirements
This section summarizes historic energy use and related data,
information from a 1976 load forecast prepared for CVEA, and some
general observations on likely magnitude of future power requirements.
Historic Data
Energy use and peak demand data were obtained from three power
generating sources in the Valdez-Glennallen area: CVEA, the utility
serving over 95 percent of the area; Chistochina Trading Post; and
Paxson Lodge, Incorporated. The utility data yielded information on
energy use, peak demand, and customer sector breakdowns.
Population and employment data were derived from statistics provided by
the State of Alaska Department of Labor. This information illustrates
demographic characteristics or the study area.
The 1970-77 Valdez-Glennallen area is summarized on table 34. Net
generation by utility from 1960-77 is on table 35.
Analysis
The energy use, population, and employment data reflect events tied to
construction and operation of the Alyeska oil pipeline. The large jumps
in population and employment during the construction years cannot be
directly tied to utility power requirements since most of the workers
were housed in construction camps that supplied their own power.
The 1977 use data show total utility requirements at more than four
times the 1970 level. Total number of customers tripled during the
period.
Per customer residential use increased from 3,846 to 6,423 kwh per year
over the 7-year period.
This historic data provides no clear insight to probable future levels
of power use--any trends that would be useful in forecasting are hidden
by the construction impacts.
109
Forecast
Table 36 summarizes future power demand estimates from CVEA's 1976 power
requirements study. The study included estimates of demands through
1991; APA m~de a rough extension to the year 2000, assuming a 6 percent
rate of increase.
The average energy capability of the Solomon Gulch project is estimated
at 55 million kwh/year. The forecasts indicate that the Solomon Gulch
power would be fully utilized as soon as it comes on-line. By the time
Upper Susitna power would be available, CVEA total demands would exceed
Solomon Gulch capability by around 100 million kwh/year.
The CVEA study predated the plans for the oil refinery at Valdez, ,_hence
there is substantial likelihood that the actual requirements will exceed
the·forecast amounts.
Transmission Plan And Cost
Incremental service to the Glennallen-Valdez market areas would require
constructing transmission facilities from Palmer to Glennallen to
connect to the CVEA system serving the market area. Susitna project
generation and transmission to the Anchorage-Cook Inlet area would be
sufficient to accomodate the incremental service.
The Palmer-Glennallen transmission system would have 136 miles of single
circuit 138-kv line,· with a substation at Palmer. and a switchyard at
Glennallen. The Palmer substation would have a 230/138-kv transformer,
a 230-kv breaker, and a 138-kv circuit breaker. The Glennallen switch-
yard would include two 138-kv circuit breakers, and would connect with
the planned CVEA 138-kv line extending to Valdez. Peak capacity of the
138-kv Palmer-Glennallen line would likely be from 50 to 80 ~~. This is
an assumption for study purposes (stability, sizing, and power flow
studies were not made).
System costs are based on comparable elements of other project
transmission systems, indexed from the 1976 report (January 1975 prices)
to October 1978 prices (about 32 percent increase). The basic prices
are based on Bureau of Reclamation (USBR) and Bonneville Power
Administration (BPA) with adjustments for Alaska conditions (refer to
Part VIII). Advance planning would analyze evaluations of structural,
operation control, environment, and other elements affecting route
location, design, and operation of the system serving this area.
Investment costs are calculated by adding 7~ percent interest annually
during construction. The Palmer-Glennallen line would be constructed
during the same period as other facilities, and would be ready for
service when project power is available in 1994. Table 37 summarizes
construction and investment costs.
110
1970
1971
1972
1973
. 1974
1975
1976
1977
1970
1971
1972
1973
1974
1975
1976
1977
1970
1971
1972
1973
1974
1975
1976
1977
Table 34
HISTORIC DATA
GLENNALLEN-VALDEZ AREA
Upper Susitna Project Power Market Analysis
Utility
Res
2.1
2.6
2 •. 8
2.9
3.7
7.7
10.3
10.9
Utility
Res
546
S81
655
684
911
1,172
1,677
1,697
Energy Sales (GIVE)
CI Total
7.4 9.9
7.8 10.8
7.6 10.8
8.3 11.6
10.4' 14.5
16.0 24.4
22.4 33 • .5
31.0 42.9
CustoiPers
CI Total
221 793
226 939
237 926
247 965
317 1,268
361 1,576
404 2,128
427 2,183
Population (Total)
3,098
2,932
3,464
3,568
3,833
9,639
13,000.
9,905
Res residential
CI Commercial-industrial
111
· Net Generation
Utility
11.9
12.8
13.0
13.8
16.8
28.2
40.7
48.7
Industry
39.4
Peak Load (MW)
Utility
2.4
2.5
2.6
2.7
4.0
7.3
8.6
Industry
9. 3 37
(38.6 installed
capacity}
Employment (Avg. Annual)
831
1,085
904
985
1,526
4,626
7,818
3,918
APA 12/78
Table 35
UTILITY NET GENERATION (GWH)
GLENNALLEN-VALDEZ AREA
Upper Susitna Project Power Market
Year CVEA CTP PLI
1960 3.2 O.l
1961 3.4 O.l
1962 4.0 0.1
1963 4.5 0.1
1964 4.2 0.1
1965 6.5 o. 2 .
1966 8.0 0.2
·1967 8.2 0.3
1968 8.6 0.4
1969 9.7 0.4 0.5
1970 10.7 0.4 0.7
1971 ll. 7 0.4 0.7
1972 ll.8 0.4 0.7
1973 12.6 0.4 0.7
1974 16.6 0.4 0.7
1975 26.9 0.4 0.7
1976 39.3 0.4 0.7
1977 47.4 0.4 0.7
CVEA -Copper Valley Electric Association
CTP -Chistochina Trading Post
PLI -Paxson Lodge, Inc.
112
Analysis
Total Growth %
3.3
3.5 6.1
4.1 17.1
4.6 12.2
4.3 -6.5
6.7 55.8
8.2 22.4
8.5 3.7
9.0 5.9
10.6 17.8
11.8 11.3
12.8 8.5
12.9 0.8
13.7 6.2
17.7 29.2
28.0 58.2
40.4 44.3
48.5 20.1
APA 12/78
Table 36
VALDEZ-GLENNALLEN AREA UTILITY FORECASTS
Upper Susitna Project Power Market Analysis
Energy (gwh) Peak Demand (NN)
CVEA 1/ CVEA 1f
Year Glennallen Valdez Total Glennallen
1976 12.5 24.5 37.0 40.7 2/
1977 21.0 27.0 -48.0 48.7 y
1978 22.1 27.2 49.3
1979 24.0 27.6 51.6
1980 45.9 27.9 73.8
1981 48.5 30.5 79.0
1982 50.0 33.0 83.0
1983 52.2 35.5 87.7
1984 55.0 38.2 93.2
1985 57.6 41.4 99.0
1986 60.0 45.0 105.0
1987 63.1 48.5 lll. 6
1988 66.0 52.5 .118.5
1989 69.1 56.8 125.9
1990 72.3 61.4 133.7
1991 75.0 66.4 141.4
1995 180
2000 240
2025 1,025
1/ Copper Valley Electric Association Forecast from
1976 REA Power Requirements Study.
2/ Historical values
113
3.1
4.2
4.4
4.6
7.3
7.7
8.1
8.5
9.0
9.5
10.1
10.6
11.1
11.7
12.4
13.0
Valdez
6.0
5.9
5.8
5.8
5.8
6.3
6.8
7.4
8.0
8.6
9.3
10.1
10.9
11.8
12.8
13.8
Table 37
INVESTMENT COST SUMMARY
GLENNALLEN-VALDEZ AREA TRANSMISSION SYSTEM
Upper Susitna Project Power Market Analysis
(Costs-$1,000 10/78)
Construction Interest
During
Construction
Investment
Transmission Line
(Palmer-Glennallen)
Clearing
Right-of-Way
Access Roads
Line Structures
Subtotal
Switchyards & Substations
Palmer Substation
Glennallen Switchyard
Subtotal
Total
$ 1,540
310
5,490
25,760
$33,100
$ 3,880
920
$ 4,800
$37,900
Operation and Maintenance Costs
$2,900
Addition of the 136-mile Palmer-Glennallen transmission line would
involve comparatively minor increases in overall system operation,
maintenance, and replacement costs.
For purpose of this analysis we are assuming the incremental O&M costs
$40,800
would be roughly equivalent to 1/3 of the annual cost of one transmis$ion v
line maintenance crew. Adding an allowance for replacements, the
annual OM&R cost is estimated at $131,000 per year. This is indicated
on Table 38.
114
Table 38
OPERATION, MAINTENANCE, AND REPLACEMENT COST SUmMARY
GLENNALLEN-VALDEZ. AREA TRANSMISSION SYSTEM
Upper Susitna Project Power Market Analysis
Annual Cost -$1,000
Operation and Maintenance
Personnel
Salary & allowances for 6 Wage Grades
Miscellaneous
Telephone, travel, supplies, services
training, line spray, camp maintenance
Equipment (Replacement)
Marketing and Administration
Subtotal
Contingencies 20% +
Subto.tal -O&M
Rounded
Replacement
Transmission towers, fixtures, conductors
0.0001 X $25,766,000
Substations &·Switchyards
0.0033 X $4,800,000
Subtotal -Replacement
Rounded
Total OM&R
115
Full Crew 1/3 Crew
240 80
10 3.3
8 2.7
22 7.3
280 93.3
60 20
340 113.3
113
2.6
15.8
18.4
18
131
Assessment of Feasibility
A minimum intertie between Palmer and Glennallen would involve
incremental investment costs on the order of $40.8 million. Incremental
annual costs are estimated as:
Amortization
OM&R
Total Annual Cost
$3,140,000
131,000
$3,271,000
Based on the utility forecast for CVEA, it is possible that a market in
excess of 100 million ktvh/year could be supplied over the
Palmer-Glennallen line. This would equate to transmission costs of
3.3¢/kwh.
The ·100 million kwh/year would be equivalent to 22.8 MW at 50 percent
annual load factor. This is substantially less than half the estimated
capacity for a 138-kv Palmer-Glennallen line.
Full utilization of the intertie could involve transmission of 200 to
300. million kwh/year, in which case, average transmission cost would
drop from one-half to one-third the cost indicated above.
Regardless of the source of power--coal, oil, hydro--generation costs
for CVEA will likely be higher than for the larger utility systems
serving the Anchorage-Cook Inlet area. In this context, transmission
costs on the order of 1.1 to 3.3¢/kwh between Palmer and Glen~allen may
be justifiable.
APA concludes that the Palmer-Glennallen intertie has a good chance for
feasibility, and that a more detailed examination is warranted.
116
APPENDIX
1. Letter dated January 3, 1979 to Col. G. R. Robertson, Alaska
District Corps of Engineers,·transmitting responses to OMB questions
falling in APA's area of responsibility.
2. Previous Studies and Bibliography.
3. LOAD/RESOURCE AND SYSTEM COST ANALYSIS FOR THE RAILBELT REGION
OF ALASKA: 1978-2010 --Informal Report -by Battelle Pacific Northwest
Laboratories, Richland, Washington-January, 1979.
4. Comments.
a. Federal Energy Regulatory Commission, San Francisco, California,
March 6, 1979~
b. Battelle Pacific Northwest Laboratories, Richlanp, Washington,
February 27, 1979.
c. Corps of Engineers, Anchorage·, Alaska, March 19, 1979.
d. The Alaska State Clearinghouse, Juneau, Alaska, Harch 23, 1979.
e. Municipal Light and Power Company, Anchorage, Alaska, March 1, 197·9.
117
Deoartment Of Energy • Alas!<a Power Administration
P.O. Box 50
Juneau, Alaska 99802
Colonel George R. Robertson
Alaska District Engineer
Corps of Engineers
P.O. Box 7002
Anchorage, AK 99510
Dear·Colonel Robertson:
January 3, 1979
Attached are our responses to the Susitna Project mm questions \'l'e
agreed to provide {re: our letters dated January 20 1 24, 1978).
Copies of these responses were sent via Goldstreak direct to Captain
· Mohn December 28 1 · 1978.
Sincerely,
Donald L. Shira
Chief, Planning Division
1
OMB question 5.1, and .2.
0!-·lB asked that the analysis of the "without" project condition be expanded
to clearly analyze:
1. Why, with natural gas projected to be in such short supply, the
Anchorage utilitles have only· contracted for 55 percent of proved
reserves or 25 percent of estimated ultimate reserves, and,
2.. The sensitivity of the analysis to the collapse of OPEC and the
cost of shippin~ oil to the East Coast.
Both questions must be considered in terms of national energy policy.
The Nation needs to reduce dependency on oil ~~ports on both a short-
term and a long-term basis, and to accomplish a major shift a\vay from
oil and natural gas to alternative energy sources. The reasons for this
include national economic considerations, as \vell as very real_limits on
nat~onal and world supplies of oil and natural gas.
;n terms of national energy policy, oil and natural gas are not available
alternatives for l~ng-term production of electric power. There are ·
remaining questions as to hat-1 quickiy existi:ng uses •vill be phased out
and on hoH complete the prohibitions will be on ne>v oil. and n9-tural gas-
fired powerplants.
There is general ~greement that implementation of national policy must
include str~ng efforts in conservation, substantial increase in use of
coal, and major efforts to develop renewable energy sources. Each of
these components is sensitive to energy price and supply variables. A
reduction in world oil prices or·a period of oversupply serves as a
marketplace disincentive for conservation efforts and \'lark· on alterna-
tive_energy sources.
The lm·;est cost alternatives and those \'lith fully proven technology are
the least sensitive; those that depend on further R&D are most easily
sidetracked.
Th~ Susi_tna Proj ec·t involves la.rge blocks of pmver and ne>v enl?:rgy from
a rene,,;able source, fully proven technol_ogy 1 long revenue-produci_ng
period {in excess of 100 years) 1 and essential freedom from long-t.erm
price increases. Its unit costs appear attrac~ive in comparison to
coal-fired po"t·:erplants. It is a two-stage project \·lith opportunity to
defer the second st_agc if demands are lO\ver than present estimates or if
price relationships cha_nge.
The above factors suggest that the Upper Susitna Project is much less
sensitive to short-:-term oil price anc1 supply variations than most o·thcr
U.S. energy options.
2
If it: i!; assm:1ec1 that 1\.lc:tsl~an o:i.l and nat\u~al gas vd.ll b8 izol.atcx1 fro=n
U.S. and world c.lent<llld and 1n::i.<.::i.ng, AJ aska would proh~tbly continue to usc
its oil .:mc1 gas for mo.st of its po\.;c.n:. 'l'hi~: a~;sumption clicl, in fnct.,
prcvnil h<~b.rccn the initial oil and gas c1:i.t;coveries in the Cook Inlet
area u.nd the 1973 oil crnbn_rgo. In 1960, the l1nchoru.ge-Cook Inlet aren
power !>upplies came almost entirely from coal nnd hydro. The lm·r cost,
clbundant: gas brought Cl. h<llt to hydro development and destroyecl the
area's coal inc1ustry. ~·he one remaining Alaskan co~1l mine barely made
it thro_ugh the 1960 1 s because of comp~tition from relatively cheap. oil.
. .
The Cook Inlet gas has been subjected to increasing competition in ·the
last few years, including proposals for LNG facilities, additional
petrochemical plants, a·nc1 consideration of pipeline alternatives to tie
in \·lith the Alcan pipeline project. The competition resulted in ;increas-
ing_prices and increas~g difficulty in 6btaining long-term commitments
o~ gas for pm¥"er. The competitions and the price increases arc e:x:pectec1
to continue. ·
The real question on gas availability as it pertai;s to Upper Susitna·
is: \-lhat is the outlook for long-term gas supplies for pm.;er after
1990? That outlook is not good in terms of competing uses and national
policy.
. .>
'
3
Response to OHB question 5.3.
"The Neces~ity for an AnCJJorage-Fairbanks intertie at a cost of $200-300
million"
The estimated construction cost (1978 dollars) for the transmission
lines from the Susitna Project to the Fairbanks area is $152 million,
and $186 million for the lines from the project to the Anchorage area
(total $338 million).
Th . l . d. l/ d . h f . . . ere are severa prev~ous stu les-that emonstrate ~n erent eas~b~l~ty
of an Anchorage--Fairbanks intertie with or without construction of the
Upper Sus~tna Project. The main reason that the intertie is not now in
place is that short term benefits to the Anchorage area are quite small,
i.e., most of the short term benefits for the intertie would occur
through reduced energy arid power costs in the Fairbanks area.
APA studies in the 1975 feasibility report evaluated Susitna Project
power to Fairbanks on a cost-of-service basis (see Appendix I, p. 6-89).
This ~1as a specific demonstration of feasibility of including F~irbanks
as part of the Upper Susitna Power Market area.
1/ Among the previous studies are:
Alaska Power Survey, Federal Power Commission, 1969.
Central .Alaska PO\ver Pool, working paper 1 Alaska PO\'Ier Administration 1
October 1969.
Alaska Railbelt Transmission System, working paper, Alaska Power Admin-
istration, December 1967.
Electric Generation and Transmission Intertie System for Interior
and Southcentral Alaska, CH2M Hill, 1972.
Central Alaska Power Study, The Ralph M. Parsons Company, undated.
Alaska Pmver Feasibility Study, The Ralph M. Parsons Company, 1962.
4
Further verification of feasibility of the intertie is provided in the
new load-resource analyses and system cost analyses prepared for the
current studies. These general cases were analyzed:
Case 1.
Case 2.
Case 3.
All future generating capacity assumed to be coal-fired
steam turbines '\vi thout intertie.
All future generating capacity assumed to be coal-fired
steam turbines with intertie.
Future generating capacity to include Upper Susitna Project
plus coal-fired steam plants as needed. Includes intertie.
Results of pmver cost analyses for Anchorage and Fairbanks for the year
2000, with and without intertie are as follows:
Power Costs for Anchorage and Fairbanks (0% Inflation)
(¢/KWH)
Case 1 Case 2 Case 3
Without Intertie With Intertie With Susitna
and Intertie
Anchorage Fairbanks Anchorage Fairbanks Anchorage Fairbanks
High 6.2 8.8 6.1 8.0 5.8
Med 6.6 8.9 6.2. 8.4 5.5
LOVl· 7.1 9.2 6.2 8.8 6.1 0
The following table presents a comparison of the costs of power in the
\
year 2000 for Case 2, and 3 as compared to Case 1. As shown the costs
of power are reduced below the cost of power for Case 1 in all cases.
The reduction in the cost of power is typically greater in the
6.2
6.7
7.8
5
Fairbanks-Tanana Valley area than in the Anchorage-Cook Inlet area
becau~e the Anchorage-Cook Inlet area will.have a higher percent_of its
generation supplied by steam plants \<7hich are more costly than Susitna.
Comparison of Pm-.1er Costs for Year 2000
Percent Change in Cost of Power Belm-1 Case 1 -0% Inflation'---.
Anchorage Fairbanks
High Medium Low High Medium Low
Case 2 -1.6 -6.5 -14.5 -10.0 -6.0 -4.5
Case 3 -6.9 -20.0 -16.4 -41.9 -32.8 -17.9
Table 1 compares annual system costs for all three cases for Anchorage
and Fairbanks during the 1990-2011 period.
.
Table 1 shows the follm'ling percent" savings in system costs (1990-2011)
for Cases 2 and 3 compared to Case 1: .
Case 2
Case 3
Anchorage
-0.4
-10.7
Fairbanks
-7.9
-28.1
Total
-1.4
-14.1
Table 1. Annual Power System Costs for Power Supply Under
Cases I, II, and III -Mid-Range Load Projections -0% Inflation
($Million)
Period Case I Case II Case III
Anchorage Fairbanks Anchorage Fairbanks Anchorage Fairbanks
1980-90 272.0 90.6 254.5 84.2 254.5 84.2
90-91 274.2 96.8 293.8 89.0 293.8 89.0
. 91-92 324.2 98.2 343.8 90.2 343.8 90.2
92-93 387.5 119.5 409.9 88.2 409.9 88.2
93-94 391.7 120.9 414.1 89.2 414.1 89.2
94-95 398.9 122.2 421.3 114.9 537.5 120.5
95-96 463.7 127.6 486.1 143.7 537.9 124.8
96-97 549.0 152.4 571.5 143.2 543.0 124.0
97-98 615.9 167.8 578.7 158.5 549.3 139.2
98-99 627.7 192.0 650.2 182.6 576.3 145.1
1999-2000 694.4 193.8 657.2 184.5 577.2 . 145.7
Sub total 4,999.4 1, 481.8 5,081.1 1,368.2 5,037.3 1,240.1
00-01 691.8 194.9 . "714. 3 185.5 573.4 146.5
01-02 698.6 196.2 721.1 186.8 578.5 147.4
02-03 760.3 195.0 723.1 208.2 658.6 168.6
03-04 767.9 230.8 789.8 209.6 665.1 169.6
04-05 776.0 232.2 798.5 211.0 670.8 170.6
05-06 864.0 232.1 807.1 210.9 677.6 170.2
06-07 872.8 233.5 815.9 21~.3 744.4 171.2
07-08 881.9. 235.1 904.4 213.8 751.6. 172.3
08-09 891.1 236.5 913.6 215.2 759.0 173.4
09-10 901.6 238.1 923.1 216.9 766.7 174.6
10-11 969.9 239.6 932.7 218.4 834.3 175.7
Total 14,075.1 3,945.8 14,124.7 3,656.9 12,717.3 3,080.2
Response to OMB question 5.4.
"Scheduling of po~.;erplants and the reduced risk of building small
increments."
The Load/Resource analysis for \vi thout project condition addresses, the
'·.
7
scheduling of steamplants and size of units needed. This is demonstrated
in Chapter VII of the marketability report. Annual power system costs
shown in Table 1 under question 5.3 show savings from Susitna over the
without Susitna case. The steamplants are smaller units than Susitna,
but their higher cost contributes to higher overall system costs. An
analysis of hydro alternatives inqicate that there are not economical
sites available in sufficient quantity to be compar9bie to Susitna.
This is supported by APA's draft report on "Analysis of Potential
Alternative Hydroelectric Sites to Serve Railbelt Area."
Response to OMB question 6.1, .2, and .3.
Demand Estimates
The analysis of load growth should be more specific with respect
to:
1. Increasing use by consumers; and,
2. Increasing number of consumers.
8
3. Industrial growth, i.e., where does Alaska's comparative /-
advantage lie outside the area of raw materials and government
fu.nctions?
The new estimates of future pov1er demand are responsive to the first t\-10
parts of this question. APA completed a very careful analysis of recent
power use trends by class of customer, with particular emphasis on
~dentifying recent trends that could be attributed~o conservation
efforts. The future demands are based on future population estimates
developed by the University of Alaska's Institute of Social and Economic
Research and incorporate assumptions of substantially improved efficiency
in use of electric power through conservation.
The third part of the question requires consideration of the overall
Alaskan economy, present and future, and the role of Upper Susitna
power.
Alaska is not a heavily industrialized State nor is it expected to be •
• The oil and gas industry is presently the dominating sector of the
State's GNP, and will continue to be so for at least the balance of the
20th century. This is the principle source of revenues for the State
and thus the driving force behind State programs for education, local
government assistance, welfare, and so on. Other important industries
are the fisheries, forest products, and recreation-tourism.
The low-and mid-range population estimat~s incorporate very modest
assumptions of industrial expansion based on pioneering of Alaskan
natural resources for the most part. The specific industrial assumptions
reflect proven sources of natural resources and projects that are '.'lell
along in the planning stages.
. ..>
9
Extraction and processi11g of natural resources will undoubtedly continue
to be major aspects of the Alaskan economy. Other important aspects
include business activities of Native Corporations and increasing amounts
of land made available to State and private ownership. Actions pending
on the new National Parks, Refuges, and Wild and Scenic Rivers will
encourage further develop~ent of the recreation and tourism industries.
As in most parts of the country, Alaska employment is not domihated by· . . _,--..
the industrial sectors. 1-Iost jobs are in service. industries, the co:inmer-
cial establishments, transportation, utilities, and government. The new
population esti~ate by ISER indicates that the distribution of employment
will not change sUbstantially. The anticipated growth in the economy,
employment, and in pmver demands is primarily in the non-industrial
sectors.
It should be noted that the Railbelt area demands for electric energy in
1977 were 2. 7 billion kilmvatt-hours, \·lhich is approaching the firm
energy capability of the Watana Project. The load resource analyses
demonstrate full utilization of Watana energy essentially as soon as it
becomes available, even under the lower power demand case. This basically
leads us to a finding that the Upper Susitna justification is not dependent
on major industrial expansion in Alaska.
\ '
10
Response to or.m Question 7.
Under the topic Scnsi ti vi ty Analysis, OMB provided the follo't7ing comments:
"Pov1er demand should be subjected to a sensitivity analysis to better
assess the uncertainties in development of such a large block of por,.;er.
The typical utility invests on the basis of an 8-10 year time horizon.
The Susitna plan has an 11-16 year horizon in face of risks that loads
may not develop and the option of wheeling power to other markets is not
available. It should be noted that the po;ver demand for Snettisham t'las
unduly optimistic t-1hen it tvas built. This resulted in delays in installing
generators. A similar error in a project the size of Susitna would be
much more costly and would.have a major adverse effect on the project's
economics . "
The new power demand estimates, load resources analyses, and financial
analysis presented in this report~ all provide a better basis for examining
these questions. In addition, there is need to review some of the
Snettisham Project history to bring out similarities and differences
\vi th the Upper Susi tna case.
Snettisham Review
The $nettisham Hydroelectric Project is located near Juneau, Alaska, and .
is now the main source of power for the greater Juneau area .. The project
was authorized in 1962 on the basis of feasibility investigations by the .
Bureau of Reclamation, constructed by the Corps of Engineers, and opera-
ted by the Alaska Power Administration.
The·project was conceived as a xwo-stage development and construction of
the first, or Long Lake, stage was completed in late 1973 with first
commercial power to Juneau in December 1973. The second, or Crater
Lake, stage \o.lould be added t,o;hen power demands dictate.
11
Juneau Has, anci is, an isolated pmver market area. Difficult terrain
and long distances have thus far pr-evented electrical interconnection
with other Southeast Alaska communities and neighboring areas of Canada;
however, such interconnections may prove feasible within the next 15 to
20 years. The p~oject planning and justification was 'premised on ser-
vice only to the greater Juneau area.
The Snettisham authorization was based on pmver demand estimate-s_ by the
Alaska District, Bureau of Reclamation {nm-7 Alaska Pmver Administration).
1/ The estimates \vere based on actual pmver use through 1960 and projec-
tions to the year 1987. The outlook-at that time \·las that the first
stage c·onstruction. would be completed in 1966, and that total project
capability would not be needed until 1987.
A comparison of power demand estimates at the time of authorization with
actual demands is shm·m on Table 1. The 1977 energy load was 112,197
megawatt-hours or 81 percent of the amount estimated in 1961 based on
historical records through 1960.
1/ Reappraisal of the Crater-Long Lakes Division, Snettisham Project,
Alaska, USBR, November 1961.
.>
Table 1 Pmver and Energy Requirements-Juneau Area
Actual Demands
Fiscal Year MWH Peak 1-1\v
(oct. 1 -sept. 30)
1958. 23,945 4,788,
1959 26,297 5,321
1960 28,499 5,465
1970 58,266 12,420
1971 63,786 13,780
1972 70,225 14,910
1973 75,753 15,470
1974 83,059 16,220
1975 94,609 17,840
1976 106,296 19,800
1977 112,197 20,440
Forecasted Demands at
Time of Authorization 1(
.Mt'7H Peak MW
73,400 15,230
80,700 16,750
88,800 18,430
97,500 20,240
106,900 22,190
116,900 24,260
127,600 26,480
139,100 28,870
From Reappraisal of the Crater-Long Lakes Division, Snettisham
Project, Alaska, USBR, November 1961.
12
.>
The inherent flexibility of a staged project proved to be very benefi-
cial in the case of Snettisham. APA made periodic updates of the power
demand estimates during construction of the Long.Lake stage. For
several years, these forecasts indicated a need to proceed with the
Crater Lake stage construction immediately on completion of the Long
13
Lake stage. The Corps of Engineers construction schedules and budget
requests,. based on the APA power demand estimates, anticipated start of
construction on Crater Lake in FY 1977. Najor factors in these fore-
casts \vere plans for a major ne>v pulp mill in the Juneau area and for
iron ore mining and reduction facility in the vicinity of Port Snettisham.
Neither of these developments >iere antic;ipa·ted at the time of authoriza-
tion. Both of these resource developments fell through, and this
resulted in a substantial reduction in the APA power demand estimate and
a decision in late 1975 to defer the Crater Lake construction start.
The pulp mi~l \'las particularly influential in the change in demand
estimates. The mill was planned for operation in the early 1970's with
a large population and commercial impact on Juneau. Initial access
facilities were constructed and site preparation >vas well underway when
the project became entangled in protracted law suits involving logging
practices in Southeast Alaska. Several court decisions were made in
favor of the development, but a last minute remand put the project back
to base one and led to oahcellation in early 1975.
This type of uncertainty faces all utility planners. The staged project
like Snettisham affords a great deal of capability to adjust to changes
in demand.
Nany other factors influenced Juneau area pm'ler demands and utilization
of project power. Of particular concern at the moment is impact of
Alaska's capital move initiative. This would certainly change use of
project pm·1er, v7i th the most likely outcome that the community -...;ould
move more quickly into an all-electric mode (space heating and electric
vehicles appear particularly attractive in this area) and industrial use
of power would increase through economic diversification.
14
The key points of the Snettisham revie\·1 are:
l. The project was planned and authorized with intent to handl!= grov1th
in area power requirements for a 20-year period.
2. The load forecasts used ·as a basis for authorization 'vere reasonably
accurate.
3. The actual use of project power may turn out to be substantially
. different than originally anticipated.
4. The flexibility of staged projects 'vas actually used.
5. The outlook for financial viability appears excellent at this time
in history.
Implications for Susitna
First, the norm for utility investments cannot remain as the bqsis of an
8 to lO.year time horizon. This is evidenced by experiences since about
1970 on time required to.p1an, obtain necessary permits or authorizations,
find financing, and then build new powerp1ants and major transmission
facilities. The 8 to 10 years is much too short for nuclear, coal, and
hydro plants and for major transmission lines.
•
It appears appropriate to require a 20-year planning horizon with careful
checks at each step in the process and business-like decisions to shift
construction schedules if conditions (demands) change. We believe the
Snettisham experience is very positive in this light.
The Susitna Project is similar in that project investment is keyed to
tvm major stages. The commi tmcnt of construction funds for Watana ,.,auld
be needed in 1986 or 1987 to have pm·7er on line by 1993 or 1994. If
conditions in 1986 indicate need to defer the project, it should be
deferred. Similarly, star·t of actual construction on Devil Canyon can
15
and should be based on. conditions thut actuully prevail at the time.the
decision is. made.
The level of uncertainty for Upper Susitna is greater than was the case
for Snettisham on counts of higher interest costs and larger total
investment. Sensitivity to ~hange in demands is much less for Susitna
because of its large and diversified power market area. There are many
more v1ays that Susitna Project pmver could be effectively utilized in
the event that traditional utility power markets are smaller than
anticipated at the present.
Upper Susitna.does not have as many uncertainities in terms of environ-
mental questions as would equivalent power supplies from coal or nuclear
plants. Uncertainties on air quality are particularly relevant for any
larger Alaskan coal-fired powerplants.
16
Current Evaluation
Power demands were estimated for High, Medium, and Low cases to year
2025 assuming logical variations in population and energy use per capita . .
The projections reflect energy use per capita based on detailed studies
of 1970-1977 data from both the Anchorage and Fairbanks areas. The
projections considered va~iations in per capita use ranging from increased
use of electricity in the home to anticipated effects of con~ervation on
decreasing the growth rates. A detailed discussion of the development
of the power demands is included in Chapter 5 of this report.
The load/resource and cost analysis provided system cost for comparison
of cases both with and without the Susitna Pr~ject. The analysis also
compared the power demands to the resources required to determine sizes
and timing of new plants (the load/resource analysis is summarized in
Chapter VII). Table 2 summarizes the resources needed during the 1990's
for the range of projections.
The Table indicates that even under the most conservative load growth
condition (low}, 1,500 MW are needed to meet the combined Anchorage-
Fairbanks demands, which is roughly the capability of Susitna.
Tables 3 and 4 show the power costs for Anchorage and Fairbanks during
the 1990's with an interconnection and with and without the Susitna
Project. It is readily apparent the rates are less for the case with
Susitna.
For example, in the medium case for the year 2000, Anchorage costs are
5.5¢/kwh or 13 percent less than without Susitna. In the Fairbanks
costs, the difference is much larger, 6.7¢/kwh or 25 percent less than
without Susitna.
In Table 5, annual system interest costs are composed with and without
Susitna with intertie from 1990 to 2011. Examination of the system cost·
on an annual basis reveals the case with Susitna is cheaper than the
without Susitna case for each year except the first few years after
Watana comes on line.
17
'!'able 2. Schedule of Plant Additions -HW
Cases with ·Interconnection without Upper Susitna
Anch()rage Fairba~s
Period High Median. IDw High Hedian Low·
89-90 400 * 200 * 100
90-91 200
91-92 400 200
92-93 400 200 200
93-94 400 100
94-95 * 100 *
95-96 400 400 200 100 100
96-97 400 400 200 100 100
97-98 400 400 200 100 100
98-99 400 400 100
99-00 400
.TOTAL 90-2000 3200 2000 1200 700 . 400 300
*Interconnection Installed in 1987 for high case, 1990 for median case,
& 1995 for low case.
Rcpla,cement of military powerplants, many of which also supply heat for
buildings are additional but not shmvn here •
. ·'-":,
18
TABLE 3. Pm·1er Costs for Anchorage and Fairbanks Areas \•1i th
Interconnection and 'vi thout Upper Susitna -0% Inflation
{cents/kwh)
Anchorage Fairbanks
Period High Median Low High Median Low
89-90 5.7 4.5 4.2 4.7 5.8 5.6
90-91 5.4 4.8 4.1 4.6 5.9 5.8
9).-92 5.7 5.3 4.1 4.4 5.7 5.8
92-93 5.4 5.9 4.7 6.3 5.4 5.6
93-94 5.7 5.6 4.6 7.3 5.2 5.5
94-95 5.5 5.4 4.9 7.0 6.5 6.7
95-96 5.6 5.8 5.4 7.8 7.7 6.9
96-97 5.8 6.4 5.8 8.2 7.4 8.3
97-98 5.9 6.1 6.6 8.7 7.8 9.1
98-99 6.0 6.5 6.4 8.3 8.7 8.9
99-00 6.1 6.2 6. 2 . 8.0 8.4 8.8
19
•.rABLE 4. Po\ver Costs for Anchorage and Fairbanks Areas Hith
Interconnection and With Upper Susitna Coming on
Line in 1994 -0% Inflation
(cents/kwh)
Anchorage Fairbanks
Period High Median Low High Median Lm•
89-90 5.7 4.5 4.2 4.7 5.8 5.6
90-91 5.4 4-8 4.1 4.6 5.9 5.8
91-92 5.7 5.3 4.6 4.4 5.7 7.2
92-93 5.4 5.9 4.4 6.3 5.4 6.9
93-94 5.7 5.6 5.0 7.3 5.2 6.8
94-95· 6.4 6.9 7.3 7.9 6.8 8.8
95-96 6.0 6.5 6.8 7.7 6.7 8.9
96-97· 6.2 6.1 6.5 7.2 6.4 8.6
97-98 6.2 5.8 6.3 6.6 6.9 7.8
98-99 .. 6.1 5.8 6.1 6.5 6.9· 7~6
99-00 5.8 5.5 6.1 6.2 6.7 7.8
20
TABLE 5. Pm-1er System Annual Costs for Anchorage ancl Fairbanks
With Upper Susitna Coming On Line in 1994 -0% Inflation
(million $)
Anchorage Fairbanks
Period High Median Low High Median Low
89-90 508.5 254.5 173.4 85.2 84.2 63.4
90-91 514.1 293.8 175.0 89.0 89.0 68.5
91-92 591.8 343.8 206.0 90.2 90.2 87.4
92-93 597.3 409.9 205.0 137.8 88.2 85.5
93-94 666.0 414.1 244.5 166.8 89.2 86.4
94-95 798.5 537.5 372.3 192.'2 120.5 115.6
95-96 806.1 537.9 368.4 198:0 124.8 119.2
96-97 898.6 543.0 368.5 198.5 124.0 117.5
97-98 793.1 549.3 369.9 192.5 139.2 109.2
98-99 1,009.1 576.3 376.1 201.3 145.1 109.7
99-00 1,018.9 577.2 391.7 203.5 145.7 114.9
00-01 1,025.1 573.4 381.4 228.6 146.5 114.5
01-02 1,101. 3 578.5 380.3 ·254. 0 147.4 114.5
02-03 1,172.1 658.6 375.3 254.3 168.6 111.9 .
03-04 1,190.4 665.1' 376.6 291.6 169.6 112.0
04-05 1,287.7 670.8 376.8 296.0 170.6 112.1
05-06 1,366.8 677.6 378.0 296.1 170.2 110.7.
06-07 1,386.8 744.4 379.4 299.2 171.2 110.8
07-08 1,467.2 751.6 380.8 302.4 . 172.3 110.9
08-09 1,548.1 759.0 382.2 305.7 173.4 111.1
09-10 1,569.9 766.7 383.7 343.5 174.6 111.2
10-11 1,671.6 834.3 385.2 347.0 175.7 111.4
Total 22,989.0 12,717.3 7,430.5 4,973.4 3,080.2 2,308.4
/
( con1;inued).
TABLE·5. PO\'ler System Annual Costs for Anchorage and Fairbanks
Wi,thout Upper Susitna Coming On Line in.l994-0% Inflation
(million $)
Anchorage Fairbanks
Period High Median Low High Median Low --
89-90 508.5 254.5 173.4 85.2 84.2 63.4
90-91 .514.1 293.8 175.0 89.0 89.0 68.5
91-92 591.8 343.8 185.7 90.2 90.2 71.1
92-93 597.3 409.9 223.3 137.8 88.2 69.2
93-94 666.0 414.1 227.2 166.8 89.2 70.1
94-95 678.0 421.3 252.4 169.'1 114.9 87.2
95-96 750.0 486.1 290.9 201.3 143.7 91.8
96-97 843.4 571.5 327.9 224.8 143.2 113.1
97-98 918.8 578.7 389.8 253.4 158.5 127.6
98-99 998.3 650.2 396.7 256.3 182.6 128.4
99-00 1,074.0 657.2 397.9 259.7 184.5 . 129.3
00-01 1,160.8 714.3 470.6 262.3 185.5 129.6
01-02 1,238.6 721.1 472.5 265.3 186.8 130.2
02-03 1,310.9 723.1 469.8 265.8 208.2 128.3
03-04 1;331.0 789.8 472.8 303.5 209.6 128.8
04-05 1,350w7 798.5 474.8 341.2 211.0 129.3
05-06 1,431. 7 807~1 477.8 343.1 210.9 128.4
06-07 1,513.3 815.9 480.9 346.5 212.3 151.7
07-08 1,615.1 904.4 484.0 350.1 213.8 152.2
08-09 1,638.1 913.6 487.1 353.7 215.3 152.8
09-10 1, 721.4 923.1 490.3 357.5 216.9 153.3
10-'-11 1,801.7 932.7 493.6 361.4 218.4 153.9
Total 24,253.5 14,124.7 8,314.4 5,484.3 3,656.9 2,558.2
It should be noted· that in the low energy use estimate the total system
cost for Anchorage during this period amounts to $883.9 ~~llion less
22
with Susitna than \vithout the project. ·The difference is even larger in
the medium and high cases. The combined Anchorage-Fairbanks cash savings
for the same period based on the 1nedium power use estimate is almost $2 BillioJ
Previous Studies
There vas a fairly substantial backlog of power system and project
studies relevant to the 1976 evaluation of the Upper Susitna River
Project. The previous studies most relevant include:
1. Advisory Committee studies completed in 1974 for the Federal Power
Commission's (FPC) 1976 Alaska Po"tver Survey. The studies include
evaluation of existing power systems and future needs through the year
2000, and the main generation and transmission alternatives available to
meet the needs. The power requirement· studies and alternative
generation system studies for the 1976 pmver survey were used
extensively.
2. A series of utility system studies for Railbelt area utilities
include assessments of loads, po'-7er costs, and generation and trans-
mission alternatives.
3. Previous work by the Alaska Power Administration, the Bureau of
Reclamation,· the utility systems, and industry on studies of various
plans for Railbelt transmission interconnections and the Upper Susitna
hydroelectric potential. ·
It should be noted that many of the studies listed in the bibliography
represent a period in history when there \vas very little concern about
energy conservation, growth, and needs for conserving oil and natural
gas resources. Similarly, marty of these studies reflected anticipation
of long term, very low cost energy supplies. In this regard, the
studies for the 1976 pmver survey are considered particularly
significant in that they provide a first assessment of Alaska pmver
system needs reflecting the current concerns for energy and fuels
c.onserva tion and the environment, and the rapidly increasing costs of
energy in the economy.
The latter concern for conservation, etc. has been carried even further
in this report. As yet unpublished studies by the Alaska Pm.;er Admini-
stration have made a definite reflection of conservation assumptions.
The resulting load forecasts were used in· load/resource analyses done
and reported by Battelle Pacific Northwest Laboratories in 1978 and
1979. (Battelle also published a report in 1978 entitled Alaska
Electric Pmver, and Analysis of F'l:lture Requirements and Supply
Alternatives for the Rail belt Region.) Population and employment used
in the recentforecasts were projected and reported by the Institute of
Social and Economic Research in September 1978. The result of their
econometric model is entitled South Central Alaska's Economy and
Population, 1965-2025: A Base Study and Projection. A partial
bibliography of related studies including those of the 1976 Susitna
report, is appended.
25
PARTIAL BIBLIOGRAPHY OF RELATED STUDIES
The 1976 Alaska Power Survey, Federal Power Commission Vol. I and
Vol. II.
Alaska Regional Energy Resources Plant Project -Phase I, Alaska
Division of Energy and Power Development, Department of Commerce.
and Economic Development, October 1977.
Volume I -Alaska's Energy Resources, Findings and Analysis
Volume II-Alaska's Energy Resources, Inventory of Oil, Gas,
Coal, Hydroelectric, and Uranium Resources
Jobs and Power For Alaskans: A Program for Power and Economic Develop~
ment, July 1978. Department of Commerce and Economic Development.
Appendix: Power and Economic Development Program, July 1978.
Alaska Electric Power Statistics 1960-1976, Alaska Power Administration,
July 1977.
The Proposed Glennallen-Valdez Transmission Line. An Analysis of
Available Alternatives. Robert W. Retherford Associates, May 1978.
Power Requirements Study, Matanuska Electric Association, Inc. Rural
Electrification Administration, May 1978.
Southcentral Railbelt Area, Alaska, Upper Susitna River Basin
Interim Feasibility Report. Hydroelectric Power and Related
Purposes, Corps of Engineers, December 1975.
26
Appendix I, Part I: (A) Hydrology, (B) Project Description
and Cost Estimates, (C) Power Studies and Economics,
(D) Foundation and Materials, (E) Environmental Assessment,
(F) Recreational Assessment
Appendix I, Part II: (G) Marketability Analysis, (H) Trans-
mission System, {I) Environmental Assessment for Transmission
Systems
Appendix II: Pertinent Correspondence and Reports of Other
Agencies.
A Hydrologic Reconnaissance of the Susitna River Below Devils Canyon.
Environaid, October 1974.
Solomon Gulch Hydroelectric Project. Definite Broject Report.
Robert W. Retherford Associates, March 1975.
Electric Power in Alaska, 1976-1995. Institute of Social and Economic
Research, University of Alaska, August 1976.
Southcentral Alaska's Economy and Population, 1965-2025: A Base
Study and Projection. Report of the Economic Task Force, Southcentral
Alaska Water Resources Study (Level B). Institute of Social and
Economic Research, University of Alaska, September 1978 (Draft Report).
27
Interior Alaska Energy Analysis Team Report. Fairbanks Industrial
Development Corporation for Division of Energy and Power Development,
June 1977"
Natural Gas Demand and Supply to the Year 2000 in the Cook Inlet
Basin of Southcentral Alaska" SRI International for Pacific Alaska
LNG Company, November 1977.
Load/Resource and System Cost. Analysis for the Railbelt Region of
Alaska; 1978-2010. Battelle Pacific NorthT,.;est Laboratories,
January 1979.
Participation in Healy II Electric Generation, Fairbanks Municipal
Utilities System. Harstad Associates, Inc. June 1978.
Economic Feasibility of a Possible Anchorage-Fairbanks Transmission
Intertie. Robert w. Retherford Associates for Alaska Power Authority
(not yet completed).
1976 Power Systems Study, Chugach Electric Association,Inc. Tippett and
Gee. March 1976.
Comparative Study of Coal and Nuclear Generation Options in the Pacific
Northwest, Washington Public Power Supply System, June 1977.
Coal-Fired Powerplant Capital Cost Estimates, Electric Power Research
Institute, January 1977.
28
Analysis of the Economics of Coal Versus Nuclear for a Powerplant 'Nea.,..
Boise, Idaho, Idaho Nuclear Energy Commission, March 1976.
Alaska Electric Power, An .Analysis of Future Requirements and Supply
Alternatives for the Railbelt Region, Battelle Pacific Northwest
Laboratories, March 1978.
Geology and Coal Resources of the Homer District Kenai Coal Field, Alaska,
Geological Survey Bulletin 1058-F, 1959.
Development of the Beluga Coal Field, a status report, A.M. Laird,
Placer Amex Inc., San Francisco, California, October 1978.
TTidal' Power From Cook Inlet, Alaska, S"tvales, M.C. and ~1ilson, E.M.,
published in Tidal Power, Proceedings of the International
Conference on the Utilization of Tidal Power, May 1970.
Advisory Committee Reports for'Federal Power Commission Alaska
Power Survey:
Report of the Executive Advisory Committee, December 1974
Economic Analysis and Load Projections, May 1974
Resources and Electric Power Generation, May 1974
Coordinated Systems Development and Interconnection, December 1974
Environmental Considerations and Consumer Affairs, May 1974
29
Alaska Pmver Survey 1 Federal Power Commission, 19.69.
Devil Canyon Status Report 1 Alaska Power Administration, May 1974.
Devil Canyon Project -Alaska 1 Report of the Commissioner of Reclamation,
March 1961, and supporting reports. Reprint, March 1974.
Reassessment Report on Upper Susitna River Hydroelectric Development
for the State of Alaska 1 Henry J. Kaiser Company 1 Sept. 1974.
Project Independence, Federal Energy Adminis·tration 1 1974. A main
report, summary, seven task force reports, and the draft environmental
impact statement.
Engineering and Economic Studies for the City of Anchorage, Alaska
Municipal Light and Pmver Department, R. W. Beck and Associates
and Ralph R. Stefano and As-sociates, August 1970.
Power Supply, Golden Valley Electric Association, Inc., Fairbanks,
·Alaska, Stanley Consultants, 1970.
Copper Valley Electric Association, Inc. -15 Year Power Cost Study,
Hydro/Diesel, Rober·t · W. Retherford Associates, October 197 4.
..
3Q
Environmental Analysis for Proposed Additions to Chugach Electric
Association, Inc., Generating Station at Beluga, Alaska, Chugach
Electric Association, October 1973.
Central Alaska Power Pool, working paper, Alaska Power Administration,
October 1969.
Alaska Railbelt .Transmission System, working paper, Alaska Power
Administration, December 1967.
Electric Generation and Transmission Intertie System for Interior and
Southcentral Alaska, CH2M Hill, 1972.
Central Alaska Power Study, The Ralph M. Parsons Company, undated.
Alaska Power Feasibility Study, The Ralph M. Parsons Company, 1962.
LOAD/RESOURCE AND SYSTEM COST ANALYSIS
FOR THE RAILBELT REGION OF ALASKA:
1978-2010
for
ALASKA POWER ADMINISTRATION
U.S. DEPARTMENT OF ENERGY
by
J. J. Jacobsen
W. H. Swift
J. A. Haech
January 1979
Pacific Northwest Laboratory
Richland, Washington 99352
;
PNL-2896
INFORMAL REPORT
LIST OF FIGURES
LIST OF TABLES .
1.0 INTRODUCTION
2. 0 SUt~MARY AND CONCLUSIONS
3.0 LOAD/RESOURCE ANAlYSES
3.1 ANALYSIS METHODOLOGY
3.2 ASSUMPTIONS
CONTENTS
3.2.1 Forecasted Power and Energy Requirements
3.2.2 Existing and Planned Generating Capacity
3.2.3 Reserve Margin
3'.2.4 Transmission Losses
v
vi
4
7
8
8
8
15
15
21
3.2.5 Construction Schedule Constraints 21
3.2.6 Plant Availability Constraints 2.2
3.2.7 Economic Generating Unit -Size 25
3.3 SYSTEM CONFIGURATIONS: DEFINITION OF CASES ANALYZED 25
3.3.1 Case 1: Without Interconnection and Without Upper
Susitna Project 25
3.3.2 Case 2: With Interconnection, Without Upper Susitna
Project . 26
3.3.3 Case 3: Interconnected System With Upper Susitna
Project 30
3.4 RESULTS OF LOAD/RESOURCE ANALYSES 31
4:0 SYSTEM POWER COST ANALYSES. 66
4.1 FACTORS DETERr·1INING THE COST OF POWER 66
4.1 .1 Capital Costs 66
4.1 .2 Heat Rate
4.1~3 Operation, Maintenance, and Replacement Costs
4.1 .4 Financing Discount Rate
4.1 .5 Payback Period
4.1 .6 Annual Plant Utilization Factor
4.1 .7 Unit Fuel Costs
4.1 .8 General Inflation Rate .
4.1 .9 Construction Escalation Rate
iii
68
68
69
69
69
69
73
73
4.1.10 Fuel Escalation Rate. . 73
4.2 METHOD OF COMPUTING THE ANNUAL COST OF POWER FROM INDIVIDUAL
GENERATING FACILITIES 73
4.3 METHOD OF COMPUTING AVERAGE SYSTEM POWER COST 75
4.4 RESULTS OF SYSTEM CASH FLOW AND POWER COST CALCULATIONS 76
•
iv
FIGURES
3.1 Railbelt Region Peak Loads 12
3.2 Anchorage-Cook Inlet Area Annual Energy 13
3.3 Fairbanks Area Annual Energy 14
3.4 Plant Utilization Factor versus Plant Age 23
3.5 Railbelt Region Showing the Watana and Devil Canyon Damsites, a
Possible Route for the Interconnection, and the Beluga Area 28
3.6 Load/Resource Analysis for Anchorage-Cook Inlet Area Without
Interconnection and Without Susitna Project (Case 1) . 60
3. 7 . Load/Resource Analysis for Ancho"rage-Cook Inlet Area With
Interconnection but Without Upper Susitna Project (Case 2) 61
3.8 Load/Resource Analysis for Anchorage-Cook Inlet Area With
Interconnection and With Upper Susitna Project Coming On Line in
1994 (Case 3) 62
3.9 Load/Resource Analysis for Fairbanks-Tanana Valley Area Without
Interconnection and Without Upper Susitna Project (Case 1) 63
3.10 Load/Resource Analysis for Fairbanks-Tanana Valley Jl.rea With
Interconnection but Without Upper Susitna Project (Case 2) · 64
3.11 Load/Resource Analysis for Fa·irbanks-Tanana Valley Area i.fi.th
Interconnection and With Upper Susitnp Project Coming On Line
1994 (Case 3)
4.1 Components of the Total Annual Cost of Power
4.2 Estimates of Future Coal Prices -2% and 7% Escalation
4.3 Estimates of Future Natural Gas Prices -2% and 7% Escalation
4.4 Estimates of Future Fuel Oil and Diesel Prices -2% and 7%
Escalation
4.5 Power Costs for Anchorage Low Load Growth Scenario
4.5 Power Costs for Anchorage Medium Load Growth Scenario
4.7 Power Costs for Anchorage High Load Growth Scenario
$
4.8 Power Costs for Fairbanks Low Load Growth Scenario
4.9 Power Costs for Fairbanks Medium Load Growth ScenaPio
4.10 Power Costs for Fairbanks High Load Growth Scenario
v
in
65
67
70
71
72
116
117
118
119 .
i 20
121
TABLES
2.1 Compariion of Power Costs for Year 2005 6
3.1 Anchorage-Cook Inlet Area Power and Energy Requirements 9
3.2 Fairbanks-Tanana Valley Area Power and Energy Req~irements 10
3.3 Total Power Requirements; Anchorage-Cook Inlet Area and
Fairbanks-Tanana Valley Area Combined . 11
3.4 Existing (Fa11-1978) Generating Capacities for,Anchorage-Cook
Inlet Area 16
3.5 Existing (Fall-1978) Generating Capacities for Fairbanks-Tanana
. Valley Area 18
3.6 Anchorage-Cook Inlet Area Existing Capacity and Maximum Annual
Plant Utilization (October 1978) . 19
3.7· Fairbanks-Tanana Valley Area Existing Capacity and Maxi.mum
Annual Plant Utilization (October 1978) . : . 19
3.8 Planned Additions for Railbelt Region (1979-1995) 20
3.9
3.10
3.11
3.12
3.13
4.1
4.2
4.3
4.4
4.5
4.6
4.7
Transmission System Alternatives .
Load/Resource Balance for Case 3: r~edium Load Growth Scenario
Schedule of Plant Additions -(Megawatts) Base Cases Without
Interconnections
Schedule of Plant Additions -(Megawatts) Cases With
Interconnection Without Upper Susitna .
Schedule of Plant Additions -(Megawatts) Cases With
Interconnection With Upper Susitna Coming On Line in 1994
Anchorage-Cock Inlet Area, Low Load Growth Scenario, Case 1,
0~~ Inflation .
Anchorage-Cook Inlet Area, Low Load Growth Scenario, Case 1,
5% Inflation .
Anchorage-Cook Inlet Area, Low Load Growth Scenario, Case 2 :
0% Inflation .
Anchorage-Cook Inlet Area, Low Load Growth Scenario, Case 2,
5% Inflation . . -
Anchorage~Cook Inlet Area, Low Load Growth Scenario, Case 3,
0% Inflation .
Anchorage-Cook Inlet Area, Low load Growth Scenario, Case 3,
5% I n fl at i on
Anchorage-Cook Inlet Area, Medium Load Growth Scenario, Case 1,
O~b Inflation .
vi
27
32
54
56
58
78
79
80
81
82
83
84
TABLES (contd)
4.8 Anchorage-Cook Inlet Area, Medium Load Growth Scenario, Case 1 ' .
5% Inflation . 85
4.9 Anchorage-Cook Inlet Area, Medium Load Growth Scenario, Case 2,
0% Inflation . 86
4.10 Anchorage-Cook Inlet Area, Medium Load Growth Scenario, Case 2,
5% Inflation . 87
4.11 Anchorage-Cook Inlet Area, Medium Load Growth Scena ria, Case 3,
0% Inflation . 88
4.12 Anchorage-Cook Inlet Area, Medium Load Growth Scenario, Case 3,
. 5% Inflation 89
4.13 Anchorage-Cook Inlet Area, High Load Growth Scenario, Case 1,
0% Inflation . 90
4.14 Anchorage-Cook Inlet Area, High Load Growth Scenario, Case 1,
5% Infl atian . . 91
4.15 Anchorage-Cook Inlet Area, High Load Growth Scenario, Case 2,
m~ Inflation . 92
4.16 Anchorage-Cook Inlet Area, High Load Growth Scenario, Case 2,
5% Inflation . 93
4.1T Anchorage-Cook Inlet Area, High Load Growth Scenario, Case 3,
0% Inflation . 94
4.18 Anchorage-Cook Inlet Area, High Load Growth Scenario, Case 3,
5% Infiation . 95
4.19 Fairbanks~ Tanana Va 11 ey Area, Low Growth Scenario, Case 1 ' 0% Inflation . 96
4.20 Fairbanks-Tanana Va 11 ey Area, Low Growth Scenario, Case 1 ' 5% Inflation . 97
4.21 Fairbanks-Tanana Va 11 ey Area, Low Growth Scenario, Case 2,
0% Inflation . 98
4.22 Fairbanks-Tanana Valley Area, Low Growth Scenario, Case 2,
5% Inflation . 99
4.23 Fairbanks-Tanana Va 11 ey Area, Lmv Growth Scenario, Case 3,
0% Inflation . 100
4.24 Fairbanks-Tanana Va 11 ey Area, Low Growth Scenario, Case 3,
5~~ Inflation . 101
4.25 Fairbanks-Tanana Va 11 ey Area, Medium Growth Scenario, Case 1,
0% Inflation . 102
4.26 Fairbanks-Tanana Va 11 ey Area, ~~edi urn Growth Scenario, Case 1,
5% Inflation . 103
vii
TABLES (contd)
4.27 Fairbanks-Tanana Va 11 ey Area, Medium Growth Scenario, Case 2,
0% Inflation . 104
4.28 Fairbanks-Tanana Va 11 ey Area, Medium Growth Scenario, Case 2,
5% Inflation . 105
4.29 Fairbanks-Tanana Va 11 ey Area, Medium Growth Scenario, Case 3,
0% Inflation . 106
4.30 Fairbanks-Tanana Va 11 ey Area, Medium Growth Scenario, Case 3,
5% Inflation . 107
4.31 Fairbanks-Tanana Va 11 ey Area, High Growth Scenario, Case 1 ' · 0% Inflation . 108
4.32 Fairbanks-Tanana Va 11 ey Area, High Growth Scenario, Case 1 '
5% Inflation . 109
4.33 Fairbanks-Tanana Va 11 ey Area, High Growth Scenario, Case 2,
0% Inflation . 110
4.34 Fairbanks-Tanana Va 11 ey Area, High Growth Scenario, Case 2,
5% Inflation . 111
4.35 Fairbanks-Tanana Va 11 ey Area, High. Growth Scenario, Case 3,
0% Inflation . 112
4.36 Fairbanks-Tanana Va 11 ey Area., High Growth Scenario, Case 3,
5 ~& I n fl at i on . 113
viii
LOAD/RESOURCE AND SYSTEM COST ANALYSIS
FOR THE RAILBELT REGION OF ALASKA -1978-2010
Prepared for the
Alaska Power Administration
by
Battelle
Pacific Northwest Laboratories
January 1979
1.0 INTRODUCTION
The Alaska Railbelt region presents some unique attributes for considera-
tion in future power system planning. The region currently consumes 83% of
the State 1 S electric power and even the lower e?timates of electrical load
g.rowth (5% per annum) for the region are above the national average.
The State, and particularly this region, is a difficult one in which to
forecast load growths. This difficulty results from the nature of the economic
activity base being influenced by externai forces such as oil and gas develop-
ments and transportation systems~·with their cyclical tendency. Also, since the
economic base is still not large, the injection of a competitively scaled
inpustry such as major petroleum refinery or electrochemicai' industry can sig-
~ificantly perturb a forecast.
A major shift in the Alaskan Railbelt future power generating mode appears .
inevitable. The Cook Inlet Region's capacity is presently dominated by combus-
tion turbines fired by currently low-cost natural gas; the Fairbanks-North Star
Borough by a mix of coal-fired steam t~rbine generation and oil-fired combus-
tion turbines. The oil and gas based mode of generation, however, are highly
exposed to inflationary pressures, external market forces, and Federal regula-
tory intervention.
The Railbelt region, however, does have a number of options open in the
future. These include:
1
• Continued use of oil and gas in existing plants.
• Lncreased coal based thermal generation both in the interior based on the
Healy Coal Field and in the Cook Inlet Region based on several coal
fields~ including the very large reserves in the Beluga Region.
• Development of the significant hydroelectric potential, including Upper
Susitna River and Bradley Lake.
o A transmission intertie between the Cook Inlet and Fairbanks load centers
is of obvious interest as a means of increasing reliability or alternately
reducing additional generating capacity needed for reliability. Marketing
of power from Upper Susitna projects will be dependent upon such an
intertie.
Electric power generation by whatever means is a very capital intensive
activity. Different forms of generation, however, have different levels of
exposure to infiation and escalation and,.cost comparisons on a straight $/kW
of installed capacity can be misleading. Thus a higher cost per kilowatt hydro-
electric project has this exposure largely limited to the time peridd during
planning and construction. On the other hand, a fossil fueled plant faces
rising fuel costs as well as operating and maintenance ~osts in the future.
Regardless of these factors, all generation options are faced with long lead
times from decision to proceed to commercial operating date.
The purpose of this report is to examine the probable timing of major
generation and transmission investments and their impact on system power costs
under a range of assumptions about power demands and inflation and escalation
rates for the following general Railbelt power supply strategies:
~ Case 1. All additional generating capacity assumed to be coal fired steam
turbines without a transmission interconnection between the Anchorage-
Cook Inlet area and the Fairbanks-Tanana Valley area load centers.
Case 2. All additional generating capacity assumed to be coal fired steam
turbines, including a transmission interconnection.
Case 3. Additional capacity to include the Upper Susitna Project (including
transmission intertie) plus additional coa1 as needed.
2
The first step involved in estimating the cost o~ power from alternative
generation and transmission system configurations is to perform a series of
load/resource analyses. These analyses determine the schedule of major invest-
ments based on assumptions about the load growth, the capacity and power produc-
tion of the prospective generating facilities, and constraints as to when the
facilities can come on line.
The load/resource analyses provide information on the annual power produc-
tion of the various types of generating plants. Once the annual plant utiliza-
tions are known, they can be used in conjunction with estimates of annual
system costs to calculate the annual cost of producing power from the facili-
ties. Summing the annual cost for generation and transmission of each of the
generating facilities gives a total cost for the entire system being analyzed.
Dividing the total annual cost by the power produced gives an average annual
cost of power for the entire system. By comparing the average annual power
costs over the period of interest (1978-2010) the alternative configurations
can be ranked based on the cost of power. All other things being equal, the
system configuration producing ~ower at the lowest cost should be selected. as
the most desirable system.
The report was prepared on contract to the Alaska Power Administration (APA)
as input to APA 1 s power market analysis for the Upper Susitna Project. The APA
furnished, and is responsible for, all data on power requirements, cost assump-
tions, and certain key criteria for the study. The balance of the criteria were
developed jointly by the APA and Battelle.
Chapter 2 contains a brief summary of the results of the study. The 1oad/
resource analyses are described in Chapter 3. Chapter 4 presents the methodol-
ogy and results of the. cash flow and power cost calculations. Appendix A con-
tains the data used in the load/resource analyses. Appendix 8 contains a list-
ing of the computer model (AEPMOD) used to perform the load/resource matching.
The output of AEPMOD for the cases analyzed in this report are presented in
Appendix C. Appendix 0 contains a listing of the model used to compute the cost
of power and Appendix E contains some selected results of ECOST 4 model runs.
3
2.0 SUMMARY AND CONCLUSIONS
Load/Resource Matching
e Forecasted peak loads for the Anchorage/Cook Inlet and the fairbanks/
Tanana Valley load centers have been matched with schedules of plant addi-
tions for low, median, and high forecasted load growths. These were
replicated for cases considering 1) continued separation of the load cen-
ters~ 2) interconnection without development of Upper Susitna hydroelec-
tric power, 3) interconnection including development of the proposed Upper
Susitna hydroelectric projects beginning in 1994.
e Thermal. generating capacity additions to the year 2010 were estimated as
fallows:
Case 1: Without Interconnection and Upper Susitna
Assumed Load Megawatts
Growth Anchorage Fairbanks Total-
Low 2600 471 3071
Median 4600 871 5471
High 8200 1471 9671
Case 2: Interconnection without Upper Susitna
. Assumed Load Mega\'latts
Growth Anchorage Fairbanks Total
Low 2200 471 2671
Median 4200 671 4871
High 8200 1271 9471
Case 3: Interconnection with Upper Susitna
Assumed Load Megawatts
Growth Anchorage · Fairbanks Total
Low 1000 171 1171
Median 3000 371 3371
High 6600 l 071 7671
4
• Provision of the interconnection without Upper Susitna reduces thermal
plant addition requirements by 200 to 600 MW over the period.
• Interconnection with Upper ·susitna reduces thermal plant addition require-
ments by 1500 to 1800 MW depending on the assumed load growth.
• Under the criteria used, the interconnection is called for in 1986, 1989,
and 1994 for high, median, and low load growth cases, respectively, with-
out Upper Susitna projects. With Upper Susitna, the corresponding dates
are 1986, 1989, and 1991.
System Power Cost
• For the Anchorage-Cook Inlet load center construction of the inter-
connection reduces the cost of power compared to the case without an
intetconnection.
I
• For the Anchorage-Cook Inlet area inclusion of the Upper Susitna project
into the system generally raises the cost of power above the other cases
during the first 2 to 4 years after the Watana Dam comes on line with
results in lower power costs during the 1996-2010 time period.
• For the Fairbanks-Tanana Valley area construction of the interconnection
again generally reduces the cost of power.
• For the Fai.rbanks-Tanana Valley load center inclusion of the Upper Susitna
project generally raises the cost of power above the case with the inter-
connection for about 2 years after the Watana Dam comes on line but, as
with the Anchorage-Cook Inl~t area, results in lower. power costs during
the 1996-2010 time period.
• Table 2.1 presents a comparison of the costs of power in the year 2005
for the cases evaluated in the report using the case without either the
interconnection or the Upper Susitna projects (Case 1) as the base. The
costs of power computed in Case 1 are compared to cases with the inter-
connection (Case 2), and with Upper Susitna coming on line in 1994 (Case 3).
As shown, the costs of power are reduced below the cost of power for
Case 1 in but one case. This reduction varies from 4.3% to 39.3% depend-
ing upon the situation.
5
TABLE 2.1. Comparison of Power Costs far Year 2005
Percent Change in Cost of Power
Bel ow Case 1 5% Inflation
Anchorage Fairbanks
High Median Low High Median Low
Case 2 -4.3 .-10.1 -12.2 +8.9 -9.6 -4.2
Case 3 -10.5 -30.3 -39.3 -8.9 -30.8 -26.3
6
3.0 LOAD/RESOURCE ANALYSES
The load/resource analysis.is intended to match forecasted electric power
requirements with appropriate generating capability additions. The analysis
schedules new plant additions, keeps track of older plant retirements, and com-
putes the loading of installed·capacity on a year-by-yea·r basis over the period
1978 to 2010.
The analysis schedules the additions to assure that both peak loads and
energy requirements (including reserves) ·are met on a year-by-year basis with
the least amount of installed capacity and with generating plants loaded in any
preselected order, typically in order of lowest to highest marginal power costs.
A number of factors must be taken into account:
1. Forecasted loads in terms of peak power requirements in megawatts (MvJ) and
annual energy requirements in millions of killowatt hours (MMkWh).
2. The stock of existing generating capacity by type, size, year of retirement,
and maximum allowable plant factor.
3. Desired reliability reserve margin to provide insurance against forced
outages, unforeseen delays in plant availability, or load growths in excess
of those anticipated.
4. Transmission and distribution losses.
5. Construction schedule constraints; i.e., lead times necessary beb1een unit
selection and first power on line date.
6. Plant availability constraints based on types and age. (Thermal plants
generally have lower availability at the start and end of their economic
1 i fe. )
7. Assumptions about the economic size of future generating plants in relation
to.the loads.
8. System configuration; i.e., interconnections, alternative siting strategies.
7
3.1 ANALYSIS METHODOLOGY
The load/resource matching is done on an annual basis. The Alaskan elec-
tric utility systems experience their annual peak load requirements during the.
winter months and resources must be available to meet these peak loads. During
recent years the annuaZ load factor for Railbelt electrical demand has typi-
cally been about 46-50%. It is expected to r.emain in the range of 50-52%
during the time horizon of this study. The existing and planned future gener-
ating capacity in the 'Railbelt region is capable of operating at a capacity
factor either equal to or greater than 50%. Because of this, the decision to
add new capacity will usually be based on the need for capacity (kW) rather
than energy (kWh). Thus in this analysis capacity additions are scheduled
based on peak loads rather than upon average an~ual energy.
The general approach to load/resource analysis is to summarize existing
and planned gross resources for each year, adjust them downward for a reliabil-
ity margin and for system transmission losses to arrive at net resources. If
these net resources exceed the critical period load for the year being analyzed,
plant additions are not called up and the analysis proceeds to the next year
and is repeated. At some point~ the net resources will not meet the forecasted
peak loads and additional capacity must be added. Also, for each year, the
energy generated by each class of plants (e.g., hydl~o, steam turgine, combus-
tion turbine, and diesel is computed so that plant utilization factors are
available for review and system energy costs can be developed. The stepwise
calculati9ns are continued to the end of the period being studies (2010).
3.2 ASSUMPTIONS
3.2.1 Forecasted Power and Energy Requirements
The analyses are based on forecasts prepared by the Alaska Power Adminis-
tration for both the Anchorage-Cook Inlet and the Fairbanks-Tanana Valley areas.
Probable high and low bounds were provided along with median forecasts. These
are presented in Tables 3.1 through 3.3 and are shown graphically in Figures 3.1
through 3.3. In addition to utility loads, Anchorage-Cook Inlet forecasts
include both national defense and industrial loads and the Fairbanks-Tanana
Valley forecasts include national defense loads.
8
TABLE 3.1. Anchorage-Cook Inlet Area Power and Energy Requirements
PEAK POWER
1977 1 I 1980 1985 1990 1995 2000 2025
MW-~1W MW MW MW MW MW
UTILITY
High 620 1 '000 1 '515 2 '150 3,180 7,240
Median 424 570 8i0 1 '115 1 '500 2,045 3,370
Low 525 650 820 1,040 1,320 1,520
NATIONAL DEFENSE
High 31 32 34 36 38 48
Median 41 30 30 30 30 30 30
low 29 28 26 24 24 18
INDUSTRIAL
High 32 344 399 541 683 1 , 615
Median 25 32 64 119 199 278 660
Low 27 59 70 87 104 250
TOTAL
High 683 1,376 1 ,948 2,727 3,901 8,903
Median 490 632 904 1 ,264 1 '729 2,353 4,060
Low 581 737 916 1 '151 1 ,448 1,788
ANNUAL ENERGY
UTILITY Gwhll GWh GWh GWh GWh GHh . GHh
High 2,720 4,390 6,630 9,430 13,920 31,700
Median 1,790 2,500 3,530 4,880 6,570 8,960 14,750
Low 2,300 2,840 3,590 4,560 5, 770 6,670
NATIONAL DEFENSE
High 135 142 149 157 165 211
Median 131 131 131 131 131 131 131
Low 127 1 21 115 105 104 81
INDUSTRIAL
High 170 1,810 2,100 2,840 3,590 8,490
Median • 70 170 340 630 1,050 1,460 3,470
Low 141 312 370 460 550 1 ,310
TOTAL
High 3,025 6,342 8,879 12,427 17,675 40,401
Median 1 ,991 2,801 4,001 5,641 7,751 10,551 18,351
Low 2,568 3,273 4,075 5,125 6,424 8 '061
l! MW = Megawatts
GWh = Gigawatt-hours (Equivalent to MMkWh =Millions of kilowatt-hours)
Source: Alaska Power Administration, October 1978
9
TABLE 3.2. Fairbanks-Tanana Valley Area Power and Energy Requirements
PEAK POHER
1977 1 I 1980 1985 19'90 1995 2000 2025
~1W -MvJ r'1H ~1W ~1W MW t·1~·J
UTILITY
High 158 244 358 495 685 1 '443
t4edi an 119 150 211 281 358 452 689
Low 142 180 219 258 297 329
NATIONAL DEFENSE
High 49 51 54 56 59 76
Median 41 47 47 47 47 47 47
. Low 46 44 42 40 38 29
TOTAL
High 207 295 412 551 744 1 • 519
Median 160 197 258 328 405 499 736
Low 188 224 261 298 335 358
ANNUAL ENERGY
Gwhll GWh GHh GWh GWh GHh GWh
UTILITY
High 690 1,070 1 '570 2' 170 3,000 6,320
Median 483 655 925 1,230 1 '570 1 ,980 3,020
Low 620 790 960 1,130 1,300 ],440
NATIONAL DEFENSE
High 213 224 235 247 260 333
Median 207 207 207 207 207 207 207
Low 203 193 184 175 166 129
TOTAL
High 903 1 ,294 1 ,805 2,417 3,260 6,653
Median 690 862 1 '132 1 '437 1, 777 2' 187 3,227
Low 823 983 1,144 1,305 1 ,466 1 '569
ll MW = t1egawa tts
GWh = Gigawatt-hours (Equivalent to MMkWh =Millions of kilowatt-hours)
Source: Alaska Power Administration, October 1978
10
TABLE 3.3. Total Power Requirements; 'Anchorage-Cook Inlet Area
and Fairbanks-Tanana Valley Area Combined
PEAK POWER
1977 1 I 1980 1985 1990 1995 2000 2025
MW -MW MW MW MW MW ~~~~
TOTAL
High 890 1 '671 2,360 3,278 4,645 10,422
Median 650 829 1,162 1 ,592 2,134 2,852 4,796
Low 769 961 1,177 1,449 1,783 2,146
ANNUAL ENERGY
G\Vhl/ GWh GWh Gt~h GWh GWh GWh
TOTAL
High 3,928 7,636 10,684 14,844 20,935 47,054
Median 2, 681 3,663 5,133 7,078 9,528 12,738 21,578
Low 3, 391 4,256 5,219 6,430 7,890 9,630
ll r~W = Megawatts
GWh = Gigawatt-hours (Equivalent to MMkWh =Millions of kilowatt-hours)
Source: Alaska Power Administration, October i978
11
(/)
1-1-
<C
:5:
<C c.::>
I.J..J
~ -0
<C
0
......!
:::.::::
<C
I.J..J
0..
6000
5000
4000
3000
2000
1000
900
800
700
600
500
400
300
200
ANCHORAGE -COOK INLET AREA
LOW
LOW
FAIRBANKS -TANANA VALLEY AREA ,
1oo·~----J-----~----~------~----~----~----~
1980 1985 1990 1995 2000 2005 2010
FIGURE 3.1. Railbelt Region Peak Loads
12
60,000
50,000
40,000
30,000
~ 20,000
0
=t= ......
1-<:
~
0 -I
::.::: z 10,000
0 9000
-I 8000 -I
:E 7000 ->-~ 6000 c:::
u..J z 5000 ·..u
-1
<:
~ 4000 z z
<:
3000
MEDIUM
LOW
1~~----~----~------~----~----~------~'------~
1980 1985 1990 1995 2000 2005 2010
FIGURE 3.2. Anchorage-Cook Inlet Area Annual Energy
13
CJ')
0:::
:::J
0 + I= <:
3:
0
....I
~
z
0
....I
....I
:E ->-C)
0:::
I..U z
I..U
....I
~ z z <
6000
5000
4000
3000
2000
1000
900
800
700
600
500
400
300
200
LOW
100 L-----~----~----~----~----~----~------U
1980 1985 1990 1995 2000 2005 2010"
FIGURE 3.3. Fairbanks Area Annual Energy
14
The Alaska Power Administratio'n data indicate that approximately 80% of
the Railbelt region loads are expected to be in the Anchorage-Cook Inlet area.
These loads have been interpreted as recognizing distribution losses.
3.2.2 Existing and Planned Generating Capacity
The exi.sti ng stock of gen~rati ng capacity for the Anchorage-Cook Inlet
area and the Fairbanks-Tanana Valley area is presented in Tables 3.4 and 3.5,
respectively.
The total existing capacities and maximum plant utilization factors for
the various generating types for the Anchorage-Cook Inlet area and the
Fairbanks-Tanana Valley area are shown in Tables 3.6 and 3.7, respectively.
The load/resource matching analyses use these totals for the first year of the
analyses (1978-1979).
Generating capacity additions can be specified to be added in one of two
ways. It can either be added in a specified year or can be added when it is
required to maintain adequate generating capacity. In the former case the
generating units are added whether they are required or not. The planned addi-
tions shown in Table 3.8 are brought on line in the years specified. National
defense generating units are assumed to be replaced by steam turbine generating
units the same year as they are retired. (See Section 3.2.7 for a discussion
of the units added as required to maintain adequate generating capacity.)
3.2.3 Reserve Margin
Utility systems invariably carry a reserve margin of generating and trans-
mission capacity as insurance against loss of load, unexpected peak require-
ments as a result of severe weather, load growths more rapid than anticipated,
adverse hydroelectric conditions, and delays in the commercial operation of new
generation. The most appropriate reserve margin will vary from system to
system depending on the nature of the loads and types of resources and special
factors. Typically, a reserve capacity at peak of 20% is used nationally.
However, this can vary to as low as 12% as is the present case for the Pacific
Northwest with its predominance of reliable hydropower and interruptable loads.
15
TABLE 3.4. Existing (Fall 1978) Generating Capacities
for Anchorage-Cook Inlet Area
Type of Capacity Retirement
Unit Reference/Name Location Generation {kW} Year
ANCHORAGE MUNICIPAL LIGHT AND POWER {AML&P}
Dei sel Anchorage Diesel 2,200 1982
Unit 1 Anchorage S.C.C.T.* 15' 130 1982
Unit 2 Anchorage S.C.C.T. 15 '130 1984
Unit 3 Anchorage S.C.C.T. 18,650 1988
Unit 4 Anchorage S.C.C.T. 31,700 1992
Unit 5 Anchorage S.C.C.T. 36,000 1995
Unit 6 Anchorage c.c. 16,500 1995
Subtotal 137,soo(a)
CHUGACH ELECTRIC ASSOCIATION {CEA}
Beluga
Unit 1 Beluga S.C.C.T.} 33,000 1988 Unit 2 Beluga S.C.C.T.
Unit 3 Beluga R.C.C.T.* 54,600 1993
Unit 4 Beluga S.C.C.T. 9,300 1996
Unit 5 Beluga R.C.C.T. 65,000 1995
Unit 6 Beluga S.C.C.T. 67,810 1996
Unit 7 Beluga S.C.C.T. 68,000(e) 1996
Unit 8 Beluga c.c. 32,200 1996
Bernice Lake
Unit 1 Bernice Lake S.C.C.T. 8,370 1983
Unit 2 Bernice Lake S.C.C.T. 17,860 1992
Unit 3 Bernice Lake s.c.c. T. 18,000 1998
Cooper Lake Cooper Lake Hydro 16,500 NA
International
Unit 1 S.C.C.T.} 30,510 1985 Unit 2 S.C.C.T.
Unit 3 S.C.C.T. 18,140 1991
Knik Arm Combined s. T. * lo,oooU) 1987
Subtotal 449,790
MATANUSKA ELECTRIC ASSOCIATION {MEA}
Talkeetna Talkeetna Diesel 600(b) 1993
HOMER ELECTRIC ASSOCIATION {HEA}
English Bay English Bay Diesel 100 1993
Homer & Kenaie 300(c) Combined Homer Diesel 1993
Homer Combined Homer S.C.C.T. 7,000(d) 1995
Port Graham
Combined Port Graham Diesel 200 1993
16
TABLE 3.4. (contd)
Type of Capacity
Unit Reference/Name Location Generation (kW)
HOMER ELECTRIC ASSOCIATION (HEA) (contd)
Seldovia Combined Seldovia Diesel 1,500
Seward Combined
Ft. Richardson/
Emendorf
Kenai
Subtotal 9,100
SEWARD ELECTRIC SYSTEM (SES)
Seward Diesel
Subtotal
ALASKA POWER ADMINISTRATION
Eklutna Hydro
Subtotal
NATIONAL DEFENSE
S.T.
Diesel
Diesel
Subtotal
INDUSTRIAL
S.C.C.T.
3,000(b)
2,500
5,500
(APA)
30,000
30,000
40,500
7,300
2,000
49,800
12,300(g)
TOTAL 685,290
* S.C.C.T. -Simple Cycle Combustion Turbine
R.C.C.T. -Regenerative Cycle Combustion Turbine
S.T. -Steam Turbine
C.C. -Combined Cycle
Retirement
Year
1980
1985
1996
NA
1991
1985
1991
1988
(a) Capacities for individual units are from sources and 2. These sum
to 118,810 kW. Total shown is from source 2.
(b) Standby
(c) Leased to CEA
(d) Leased to HEA by Gold~n Valley Electric Associatfon for 1977-1979.
(e) Included in this study, but late 1978 plans are to defer Betuga 8
until 1980 and double the capacity.
(f) Nameplate capacity derated to 10,000 KW from 14,500 KW.
(g) Recent data shows industrial load to be 25~000 KW rather than 12,300
KW.
SOURCES:
I. Electric Power in Alaska, 1976-1995, ISER, University of Alaska,
pp. J.5.2~7.4, August 1976.
2. Alaska Electric Power Statistics 1960-1976, Alaska Power Administra-
tion, pp. 15-17, July 1977.
3. 1976 Power System Study, Chugach Electric Association, Inc., Tippett
and Gee, Dallas, TX, p. 7, March 1976.
4. Alaska Power Administration, August 1978.
17
TABLE 3.5. Existing (Fall 1978) Generating Capacities
for Fairbanks-Tanana Valley Area
Unit
Reference Type Capaci.ty Year of
Name Location Generation {kW} Retirement
FAIRBANKS MUNICIPAL UTILITIES SYSTEM { FMUS}
Chena 2 Fairbanks s. T. 2,000 1988
Chena 3 Fairbanks S.T. 1 ,500 1988
Chena 1 Fairbanks S.T. 5,000 1988
Chena 4 Fairbanks S.C.C.T. 5,350 1983
Diesel 1 Fairbanks Diesel 2,664 1988
Diesel 2 Fairbanks Diesel 2~665 1988
Diesel 3 Fairbanks Diesel 2,665 1988
Chena 5 Fairbank!? S.T. 20,000 2005
Chena 6 Fairbanks S.C.C.T. 23,500 1996
Subtotal 65,345
GOLDEN VALLEY ELECTRIC ASSOCIATION (GVEA}
Fairbanks Diesel 24,000 1984
_Healy #1 Healy s. T. 25,000 2002
Fairbanks S.C.C.T. 40,000 1992
Delta Diesel 500 1988
North Pole #1 North Pole S.C.C.T. 70,000 1997
North Pole #2 North Po 1 e S.C.C.T. 70,000 1997
Subtota 1 229,500
NATIONAL DEFENSE
Combined Diesel 14,000 1988
Clear A.F.B. and
Ft. Greely s. T. 24,500 1995
Ft. vJa i nwri ght and
32,000 (a) Eilson A.F.B. S. T. 1990
Subtotal 70,500
(a) 5 MW plant ~t Eilson A.F.B. installed in 1970 and old 1.5 MW plant
~t Ft. Wainwright were inadvertantly omitted.
SOURCE:
1. Interior Alaska Energy Analysis Team, Final Report, June 1977.
2. Alaska Power Administration, August 1978.
18
TABLE 3.6. Anchorage-Cook Inlet Area Existing
Capacity and Maximum Annual Plant
Utilization (October 1978)
Plant
Capacity Utilization
{MW} ~%)
Hydro 46.5 50.0
Steam Electric 50.5 75.0
Combustion Turbine 575.01 50.0
Diesel 19.13 15.0
TABLE 3.7. Fairbanks-Tanana Valley Area Existing
Capacity and Maximum Annual Plant
Utilization (October 1978)
. Plant
CapacitY Utilization
(MW) un
Hydro 0 50.0
Steam Electric 110 75.0
Combustion Turbine 208.9 50.0
Diesel 46 10.0
19
TABLE 3.8. Planned Additions for Railbelt Region (1979-1995)
Unit Reference/ Year of
Name Installation Location
Type of
Generation
ANCHORAGE MUNICIPAL LIGHT AND POWER (AML&P)
Unit 7 1979 Anchorage S.C.C.T.
Unit 6 1979 · Anchorage c.c.
CHUGACH ELECTRIC ASSOCIATION (CEA)
Beluga #9 1979 Beluga c.c.
X-1 1980 S.C.C.T.
Bernice Lake #4 1981 Bernice Lake S.C.C.T.
X-2 1982 S.C.C.T.
Bernice Lake #5 1984 Bernice Lake S.C.C.T.
GOLDEN VALLEY ELECTRIC ASSOCIATION {GVEA)
Healy #2 As Required Healy S.T.
ALASKA POWER ADMINISTRATION {APA)
Bradley Lake 1985 Bradley Lake Hydro
NATIONAL DEFENSE
1985 Ft. Richardson and
Emendorf A.F.G. S.T.
1988 Fairbanks Combined S.T.
1990 Ft. Greely and
Clear A.F.B. S.T.
1991 Ft. Richardson and
Emendorf A.F.B. s. T.
1995 Ft. Greely and
Clean A.F.B. S.T.
Capacity
{kW)
(a) 65,000(b)
16,500
32,200(c)
J 00,000
18,000
100,000
18,000
100,000
70,000
7,300
14,000
32,000
42,500
24,500
(a) Unit #7 is a simple cycle combustion turbine unit which also supplies
exhaust heat to Unit #6.
(b) This increase reflects the increase in capacity resulting from the addition
of Unit #7. .
(c) Beluga #9 is a steam unit addition to Beluga #7 (converts these to a 100 MW
combined cycle unit).
SOURCES:
1. 1976 Power System Study, Chugach Electric Association, Inc., Tippett and
Gee, Dallas, TX, pp. 7 and 25, March 1976.
2. Electric Power in Alaska, 1976-1995, ISER, University of Alaska,
pp. J.5.2-7.4, August 1976.
3. Alaska Power Administration, August 1978.
20
Since a reserve margin effectively increases the amount of generating
capacity in place at any given time, it does contribute costs to the system.
Therefore, an excessive reserve margin is to be avoided while at the same time
recognizing that an inadequate reserve margin could, on outage, result in a
wide variety of soc·ial costs.
For the purposes of this study, the Alaska Power Administration has
suggested that the analysis be based on reserve margins of 25% and 20% for non-
interconnected load centers and the interconnected systems, respectively. In
the future, a more refined analysis of t'he desired reserve margin appears
warranted.
3.2.4 Transmission Losses
Transmission losses must be added to forecasts of peak and energy loads to
establish net capacity and energy at the plant substations. The Alaska Power
Administration expects losses as follows:
%
Capacity 5
Energy 1 .5
The results of the load/resource analysis are thus in net deliverable capacity
and energy and do not include energy and capacity required for internal plant
operations.
The above losses are reasonably applicable for the independent operation
of the load centers, for interconnected systems including the Upper Susitna
project and for configurations with future generation capacity additions being
distributed proportionally near the load centers. In the case of interconnec-
tion without Upper Susitna and with a tendency to centralize Railbelt thermal
generation, the transmission losses may be considerably higher as discussed
later in Section 3.2.8.
3.2.5 Construction Schedule Constraints
Due to the lead times necessary for the permit processes and construction,
generating unit and site selection must take place a number of years in advance
21
of the forecasted date when the units commercial operation will be required.
For coal-fired thermal plants, the Pacific Northwest Utilities Conference
Committee estimates a 62 month (5.2 years) period from final site selection to
commercial operation for plants in the 500 MW and higher range based on recent
U.S. experience.
Although individual thermal plant capacities appropriate to A1aska's loads
are somewhat smaller and may require less field erection work, the construction
season is shorter and the 5 to 6 year scheduling period appears reasonable.
For the potential Upper Susitna hydroelectric projects, the scale of
effort is more demanding and increased site evaluation is necessary. Current
understanding is that the Watana Dam and power plant could be brought to commer-
cial oper~tion by 1994, followed by Devil Canyon no sooner than 1998 ..
A transmission interconnectiDn between Anchorage-Cook Inlet and Fairbanks-
Tanana Valley could be brought into service prior to completion of Watana,
possibly as early as 1986.
The load/resource analysis technology recognizes the above schedule con-
straints by not allowing callup of new generation or transmission capacity that
could not be made available.
3.2.6 Plant Availability Constraints
Generating and transmission plant availability can be expressed in terms
of maximum and minimum plant utilization factors (PUF). These factors are
primarily dependent upon plant·type and plant age. For purposes of this analy-
sis we have assumed the following economic facility lifetimes after which the
facility is retired from service. (l)
Years
Coal-Fired Thermal Generation 35
Oil-Fired Steam Generation 35
Gas-Fired Combustion Turbine 20
Oil-Fired Combustion Turbine 20
Hydroelectric Generation 50
(1) See Tables 3.4 and 3.5 for dates of expected retirements for existing
systems.
22
Due to the nature of the system, some plants could be retired from service
prior to the expiration of their economic life. In actual practice, however,
it is expected that utilities may elect to retain the units on standby. In
order to assure their availability in emergencies, the utilities will periodi-
cally operate the units to make sure they are in working condition.
Experience has shown that ·large thermal plants experience a learning curve
during the first few years of operation as 11 bugs 11 are worked out. Once past .,
this period they reach a maximum that allows for scheduled maintenance and
replacement conducted during the off-peak season. Toward the end of the
economic life, increased frequency and duration of outages for maintenance
usuallY oecur and the maximum plant utilization factor declines. For purposes
of this analysis, we have assumed constraints on the maximum PUF for new coal-
fired steam electric plants as s·hown in Figure 3.4.
c::
0
!-u
80
70
60
L't 50
z
0 -~ 40
N -....J -!-
:::;) 30
!-z c::::
....J
c. 20
10
0
0 5 1 0 1 5 20 25 30 35
PLANT AGE (YEARS)
FIGURE 3.4. Plant Utilization Factor versus Plant Age
23
Other types of generating capacity are allowed to run at their maximum
PUF from the start. For new capacity and most types of existing capacity, the
following maximum PUFs are assumed:
Maximum Plant
Utilization (%)
Hydro 50.0
Steam Electric 75.0
Combustion Turbine 50.0
Diesel 10.0
Hydroelectric generation systems, as a result of their storage ability
and conservative ratings, can make adaitional power available for peaking and
it is assumed they can be scheduled at 115% of design capacity for this
service.
As pointed out earlier in Section 3.1. the peak demand during the winter
usually determines the amount of generating capacity required rather than the
annual energy. Because of this, some generating units are utilized at less
than their maximum annual plant utilization factors. The decision as to which
units should not be loaded is usually based on the margin cost of operating
the facilities. In this analysis it is assumed that diesel capacity has the
highest margin operating cost followed by combustion turbines, steam turbines
and hydroelectric capacity in that order. It is assumed that diesel PUFs can
be reduced to 0.0 while the PUFs for combustion turbine and steam electric
capacity is not allowed to go below 10%.
Transmission plant availability is generally not as schedule constrained
as are generating plants with their long lead times. For purposes of these
analyses, the interconnection between the Anchorage-Cook Inlet area and the
Fairbanks-Tanana Valley area will be provided 3 years before the completion of
the ~latana dam or when the Healy 1 (existing 25 MW) and Healy 2 (planned
100 MW net) plants become fully loaded, whichever occurs first. (2) This
assumption in effect places oil-fired plants serving the area on standby after
that date.
· (2) It will probably be desirable to provide at least a portion of the inter-
connection prior to Watana date on-line as a source of power for
construction.
24
3.2.7 Economic Generating Unit Size
The selection of optimum generating size can be a complex process involv-
ing uncertain· assumptions regarding probability of future load growth paths,
desirability of sizing individual units in comparable sizes and types for each
of maintenance, assuring that system reliability is not penalized by addition
of too large a single unit, ·smoothing of construction schedules for possible
multiunit plants, and maintaining as small as possibie departure from the
desired reliability margin. A full optimization does not appear warranted at
this stage and is beyond the scope of this analysis.
Thus for the purposes of this study, the first six coal-fired steam
electric plants in the Fairbanks-Tanana Valley area are assumed to be 100 MW
units. Any additional units are assumed to be 200 MW units. In the Anchorage-
Cook Inlet area the first five coal-fired steam electric plants are assumed to
be 200 MW units, while any additional plants are assumed to be 400 MW units.
These. size ranges, though probably not exact optimums, appear reasonable block
sizes for introduction and typically become fully loaded at about 10% of plant
1 ife.
3.3 SYSTEM CONFIGURATIONS: DEFINITION OF CASES ANALYZED
3.3.1 Case 1: Without Interconnection and Without Upper Susitna Project
The base case consists of power supply to the Anchorage-Cook Inlet and
Fairbanks-Tanana Valley on a noninterconnected basis. In this instance, no
power is available from the Upper Susitna project.
Future capacity additions for the Anchorage-Cook Inlet load center are
assumed to be near-mine-mouth coal-fired units located on the west side of Cook
Inlet with a nominal 50-mile transmission distance using two 345 kV circuits
with a capacity of 1600 MW. Capital cost of this transmission system is
$228 million in October 1978 prices.
Further capacity additions for the Fairbanks-Tanana Valley load center are
assumed to be coal-fired units with a nominal 100-mile transmission distance.
The Healy site is used as a proxy recognizing, however, that the Prevention of
Significant Deterioration (PSD) provisions of the Clean Air Act may preclude
25
the siting of additional plants beyond the planned Healy 2 100 MW unit. A
230 kV single circuit will transmit up to 400 MW and a 230 kV double circuit,
800 MW. Capital costs are $44 million and $70 million, respectively.
Table 3.9 provides a summary of the transmission system alternatives. A map of
the Railbelt region showing the Watana and Devil Canyon dam sites, a possible
route for the interconnection, and the Beluga area 'is presented in Figure 3.5.
3.3.2 Case 2: With Interconnection, Without Upper Susitna Project
In the case of an interconnected system without the Upper Susitna project
and all new capacity coal fired, the load/resource analysis is not as straight-
forward in that it is not readily apparent what strategy for siting plants
should be followed. Two primary options are apparent:
1. All coal plants sited at a single location{l) (Concentrated Siting).
Advantages
a) Lower capital and operating costs for generation.
b) Economies of scale can be achieved.
c) Siting problems in the interior may be avoided.
Disadvantages
a) Higher transmission losses (and costs) are incurred for the fraction of
power flowing to the Fairbanks-Tanana Valley load center. These costs
may cancel out savings from the advantages.
b) The latter area becomes strongly dependent upon reliability of the
transmission system--possibly to the point of requiring a second cir
cuit or maintenance of additional standby combustion turbine capac~ty.
c) Any adverse environmental effects are borne by a single area not neces
sarily benefiting in proportion.
2. Coal Plants Sited in Proportion to Relative Load Growth (Distributed
Siting) ..
. (1) For the purposes of this analysis, mine-mouth location at Beluga is used as
a proxy.
26
(}
TABLE 3.9. Transmission System Alternatives(l)
Approx.
Capacity Capacity Investment
Location Circu1t MW Loss % Cost -$MM $/11L_
Isolated Load Centers
Healy -Fairbanks
100 miles 230 kV Single 400 6 44 110
230 kV Double 800 6 70 88
Beluga -Anchorage
100 miles 345 kV Single 400 2 114 285
800 3 114 142
N Two 345 kV Single 800 2 228 285
"-..J 1600 3 228 142
Interconnected Without Susitna
Anchorage -Healy
200 miles 230 kV Single 200 6 88 293
300 8 88 225
345 kV Single 400 3 228 570
560 5 228 407
Interconnection With Susitna 1573(2 ) 5 471 (299)
(1) Source: Alaska Power Administration
(2) Actual peak power availability could be about 15% higher or 1808 MW.
ALASKA POWER ADMINISTRATION
SCALE
0 50
FIGURE 3.5. Railbelt Region Showing the Watana and Devil Canyon
Damsites, a Possible Route for the Interconnection,
and the Beluga Area
28
Advantages
a) The interconnection becomes lightly loaded, thus reducing transmission
losses to some degree although charging losses would continue.
b) Transmission interconnection reliability dependence is reduced as the
intertie assumes more o.f a capacity reserve characteristic.
c) Environmental burdens are distributed, possibly with more equity.
Disadvantages
a) Possible economies of scale are lost.
b) Generation costs in the Fairbanks-Tanana Valley are increased.
c) Siting problems related to meteorological considerations may result in
the latter area.
In this report coal plants are assumed to be sited in proportion to the
relative load growths of the two load centers. As with Case 1, additional
coal-fired generating units are sited at Beluga to serve the Anchorage-Cook
Inlet area and at Healy/Nenana to serve the Fairbanks-Tanana Valley areas.
The transmission interconnection is used for capacity reserve allowing
the reserve margin for both load centers to be reduced from 25% to 20% (see
Section 3.2.3). Under this scenario there is no net energy transfer during
any single year. If one load center is low on capacity the other load c_enter
provides the additional capacity required assuming it has a surplus. If no
surplus exists the original load center must add capacity.
0
The interconnection is assumed to b'e brought on 1 i ne in the same year as
the Healy 2 coal plant becomes fully 1oaded and new generating capacity would
be required in the Fairbanks-Tanana Valley area. Addition of the interconnec-
tion allows the Fairbanks-Tanana Valley area to get capacity reserve from the
Anchorage-Cook Inlet Area. This allows the Fairbanks area to postpone the
construction of additional capacity by 2 to 6 years depending upon the
scenario.
In the high load growth case the interconnection would be completed in
1986, in the medium load growth case it would come on line in 1989, and in the
low load growth case it would come on line in 1994. In all cases 45% of the
cost of the interconnection is assigned to the Fairbanks-Tanana Valley load
center. 29
3.3.3 Case 3: Interconnected System With Upper Susitna Project
In addition to the interconnection described in the previous sec~ion,
Case 3 includes two hydroelectric generating facilities. The Watana dam is
scheduled to come on line in 1994. The date is assumed to be the same for all
three load growth scenarios. The Devil Canyon dam is assumed to come on line
as soon as required following i994 but not before 1998. It is assumed it
would take at least 4 years to complete the Devil Canyon dam following comple-
tion of the Watana dam. It turns out that the Devil Canyon dam is required in
1998 in the medium of high load growth scenarios but not until 1999 in the low
load growth scenario.
Because of reservoir filling requirements it is assumed that both dams
will take 2 years to reach full capacity and power output. The capacities,
power production and plant utilization factors for the two dams are show below.
Watana
Capacity Energy Utilization
Year {MW} {MMkWh} {%}
7ro 3080 50.0
2+ 795 3480 50.0
Devil Can~ on
689 3020 50.0
2+ 778 3410 50.0
~r the medium and high load growth the transmission interconnection is
assumed to come on line in 1989 and 1986 respectively; the same years as for
Case 2. In the low load growth·scenario the interconnection comes on line in
1991 rather than 1994. This earlier completion date will allow the Watana dam
construction site to be supplied with power from either the Anchorage-Cook
Inlet area or the Fairbanks-Tanana Valley area.
The power output of the two dams is divided between the two load centers
in proportion to their relative energy consumption in 1994. This results in
the percentage divisions shown below.
30
Load Growth Anchorage-Fairbanks-
Scenario Cook Inlet Tanana Valley
Low 80%. 20%
Medium 81% 19%
High 84% 16%
3.4 RESULTS OF LOAD/RESOURCE ANALYSES
Using the methodology outlined in Section 3.1 and the assumptions
explained in Section 3.2, a series of load/resource analyses were performed.
As pointed out earlier, three basic cases were evaluated:
Case 1
Case 2
Case 3
All additional generating capacity beyond utility plans assumed to
be coal-fired steam turbines without a transmission interconnection
between the Anchorage-Cook Inlet area and the Fairbanks-Tanana Valley
area load centers.
All additional generating capacity beyond utility plans assumed to be
coal-fired steam turbines including a transmission interconnection.
All additional generating capacity beyond utility plans assumed to be
coal-fired steam turbines but including the Upper Susitna project
(including a transmission intertie) coming on line in 1994.
For each of these three cases. Three load growth scenarios (low~ medium
and high) are evaluated resulting in a total of nine load/resource.analyses.
The assumptions discussed in this chapter are incorporated in a computer
model called AEPMOD. The output of AEPMOD for Case } assuming the medium load
growth scenario is presented in Table 3.10. The results of all nine cases are
presented in Appendix C. The AEPMOD computer code is presented in Appendi~ B
and the data base necessary to make the runs is presented in Appendix A.
The capacity additions called up in the various cases are presented in
Tables J.ll, 3.12 and 3.13.
The results of the runs are summarized in Figures 3.6 through 3.11.
31
TABLE 3.10. Load/Resource Balance for Case 3: Medium Load Growth Scenar,io
htfoA: .&"'C)1t11-1AI>~
AMCrlU~AbE CASt: a •• MEDIUM LOAD GkUWTH
I~TtRTlt YEAH: !9~0.
~oTEs:otc. b, 197~ ~~ u.s.·t99a.
C ~ I T l C A L
I
I PEA~
1---------------------1 fiEtlU li<tME'•TS I
---------------1 ~<e:,ouwc.es 1
EXJ::.TI'lG I
I'IYUI"<U I
<;li:.AMIELI:C I
COI"f\ • fUiil:l INE I
O!E.SE:L I
I
TO TAL I
I
Auflll!Ut.S I
t1'1'1J.HIJ I
:,Ti:,.AMIELEC I
CfiMri.TtJIHilllE I
lJlt!;€L I
I
>If.. Tl ;,fMEiiT S I
I'ITli"IJ I
~TO:A'HELEC I
CO"S. TUI'ItHNE I
lJli:5EL I
I
---------------1
sas.
s 3.
~~OSS ~ESOURCES/ b9B.
I
C.&P I'IES. MARHIHI
I
kE!>f.WVE rl(fJ. I
I
LO:.St.S I
I
NET ... e:.ou~ce:s 1
I
TRAt.Si'C:I'IEO I
I
I
SU~PLIJS I
5?.3.
o.
19/8•1979
i>IPIIF APUF
• ::.o .::oo
• 75 • 75 • ~o .<~o
.15 .oo
I
Et;EkGY I f'EAII. --------, _____ _
I
as3t. 1
I
I
I
c:!O'I. I
~3a. 1
ao34. 1
u. I
I
cS&'l. I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
2Sb9o I
I
&32.
'B.
51.
57':5 •
19.
812 •.
I .0.264
I
I 15b.
I
38 • I 32. •
I
as31. 1 1>22.
I
I 0.
I
I o. I •10.
1979•1'H>Il
~tf>Uf APUF
.~o .so
.75 .75
.so .36
.1 s • 00
• so • 50
I
E~EHiiY I t"t::AK --------1·-----1
2801. I 108&.
I
I
I
ao4. 1 53 •
33a. 1 st.
l!>IO. I &89.
O. I 14.
I
C!34&. I 812.
I
I
I
I
497. I 100.
I
I
I
I
I
I
I 2.
I
I
28113. I 910.
I
1 o.32&
I·
I 112.
I
<~a. 1 ~q.
I
2801. I 704.
I
I o.
I
I
0 0 I 11!.
Pt::AK •• PtAK LOAOIGENE~ATINH CAPACITY REYUlR;,;MENTS(MEGANATTS)
MPIIF •• MAXIMUM PLAN! Ufii.!ZATlON FACTOR
A~UF -· ACTUAL PLANl uTILiZATION FACTON
1980•1981
MPUF .I.PUF
.::.o .so
.75 .75
• so .3S
.15 .oo
• :>0 • 50
• uo .oo
E~ERGY •• GEN~RAT!ONIAN~U4L El~E~GY ~EQUlWtMtNTS\MlLLlON~ OF KlLUNATl•HUUw~)
32
.5041.
.<04.
3.!2.
21U. <•.
o •
3067.
3041.
o.
TABLE 3.10.
A><t.A: '"ll<tiAN~S
FAI~~AN~S C~S~: 2 --~EOIUM LUAO GROWTH
li<TE.~l II:. YeAR: 19<;0,
NOTES:OI:.C. oo 1978 ~/ U.S.-1994,
(contd)
CRITICAl. I' E R I Q 0
------------------------------------------------------------------~----------------------I l'llil-1'17'1 I 1'17'1•1981) I 1'1tlll-1'<dl
I PEAK MPLiF APUF EI.ERGY I I'EAK r-<PUF APUF ENERGY I PtAK MPUF APUF EI\E>IGY
1--------------1--------------1--------------_______________ ,
I I
io:fi.iU!~t"4f::.Nl5 I ld<l. !!<)I;. I l'H. 8b2. I 209. '!lb.
---------------1 ... I I
i<t:::>nu-<CIOS I I I
l:l I:, T I 'H> / I I
t<YuRn I r.. .so .so o. / o. .so .so il. I o. • so .so o •
!> fi:.A•··IELEC / llll. ,75 ,bb b33. I 110, .1~ ,72 b'lc, I 11 0 •. ,7':> • 1~ 7«3 •
CO~<f>. TV>l:o HiE I 209, • so .10 18 ~ •. I 209, .~o .10 liB, I 209, .so .11 2C7,
lllt~E!.. I 4o, ,10 ,00 il, I 4b, • 10 .uo v • / lie. ,10 .uo o.
I I /
TOT.lL I 3o5. !!lb. I 3&5, a1s. I 3b5. '13u,
/ I I
,l.IJO!T lrJI•S I I I
fi11Ji<IJ I I I
ST~A>IIF.L£C I I I
CO.;::-!. TIJ~d!Ne: I / I
Ul~SEL I I I
I I I
>~E T I.ie~~c.tHS I I I
H'f'VRU I / I
!> rtA:~t~LEC I I I
CO "'t>, T<JFI~ !Nf I I I
OIE'>EI. I I I
I I I _______________ ,
I /
t .. wsl:> liESIJ<JWCESI 3&S-at<>. I 3&5 •. 87'5~ I 3b~., 9.SO~
I I I
CAl' we:. S. MA~GI lol 0.9"3 I o.~~c I 0,741>
I I I
"<ESE.;v!O RE!J. I 4&, I ~9. I 52.
I I I
L!J::.S~.!> I 'to 12, I 10. I .s •. I 10. 1~.
I I I
'<Ei kJ:SOUilCES I .51\J, 80<1. I 30n, !!&2, I 302. 91!>,
I I I
fioi~'<:,FE><EC I n. I (), I o.
I I I
I I I
SUo<Pt.uS I 12b. u. I 109. o. / 93. a.
PEAK Pf.AI( l.OAU/GENt:t<AflNG CAPACITY ~EOUikEMENTS(MEG.l~ATTSl
~IP1JF MAX il"tUM >'LANT UTII.llATIUN FACTUM
AI-\JF ACTuAL PLANT UT!LlZJ\TlUN ~ACTOw
El<f.llGY --GENERATION/ANNUAl. ENERGY kEuuiRE'"'EIHS (MlL.I.lONS OF Kil.OWHT•nOURS) . .
33
TABLE 3.10. (contd)
Ai<f'o\: A~>oCnU11AuE
ANr.rlO~A(;F CA:;• I ~ .. MEIJliJ/'1 I.IIAO r.lllh<TH
!'HEW rit:. YE•IH 1'!<,10.
I<OTES:OI:.C. b, 1'!7<1 .u U.S.•I9'i4.
c ~ 1 T 1 c A I. p E lo! I u u
-------------------------------------------------------------------------------·----~----/ I t'l<~l•t"'sa I t9Sc•!9&3 I I 9tl3•196•1
I PEU ·'IPUF APUF ENEIIG'Y I PE.AK i'll'tiF A,OUF Ef'<cllGY I PEAK "'PUF Ai>UF EN!i.tlGY I
1----·---------1--------------, ______ _OD __ .. __ .I
··-------------1 I I
"EIJU11o'E 4f:NT3 I 7<1!. .SciH. I 79'5. 3':>.:!1 • I 6'50. .37b1'Z
--------·------1 I I
i<ESIIU~CF.5 I. I I
E .X I :01 IIIIi r I I
ri'l'iJRO I 53. .!lO .so 204. I 53. • so .so 204. I 53 • • so .so 204 .•
Sloi.A~IELEC I St. .75 .75 .532. I St. ·.7'5 • 75 332 • I 251. • 75 .<12 '123 •
CUt·HI. ruUti lNE I 789. .:.o • .59 271b. I &07. .so • .sa aasu • I <lq1. .so • .IS 2o':l1.
OIC.SEL. I 11. • 15 .oo ~. I 17. .1'=> • oo o • I 15. .IS .LIO o •
I I I
TOr AI.. I 'HO. .ScSI. I 928. 2/85. I 1cto. 3d17.
I I I
AODIT lll··•S I I I
HI'Uk'l I I I
:>TE.A.~I'FLEC I I 200. .7';i .zo 3!>0. I
ca:.a. rutolf:l lilt: I ~~-• so .so 79. I too. .so • s.o <I.S8 • I
..,.' ultSEL. I I I
I I I
RE.Ti'leMENT5 I I I
I'! 'I'Ll~') I I I
;:,T"A"'Itt.EC I I I
C01o!I'I.TU>I111Nii I I IS. • oo .oo o. I s • .uo .uo o •.
Uit.SEL I I 2. .oo .oo o. I
\ I I I
----------·----1 I I
~FlUS~ HESOUHCES/ 928. 333u. I '1210 •. 35711. I IC!02. 3bl7.
J J I
C.&P kES. 1o!ARGI/</ 0.252 I 1).523 I 0.1114
I I I
HE:>Ei-IVE Hfi.Y. I !H~. I 19'1. I <!1:5.
I I I
L.IJSSC.S I 31. 119. I 110. 53. I <1.5. ~a.
I I I
'•ET HESOIJFICES I 10i>. 3281. I 972. 3s.n. I '!47. ..S7bl.
I I I
FRANSFEHE!i I -'II-. I o. I o.
J I I
I I I
Sut<PLUS -3~. o. I 177. o. I 91. u.
I'E.lK PEA~ L.DAO/GENEFIATING CAI'ACITY kEUUlWEMENTS(MEG.&~ATTS)
kPIIF MAXI~uM PI..ANT UTILlZAIION FACTOR
.lPIJF ACTUAl.. l'l.ANf U rtL.lZA f ION FACFUH
E>•ER!;Y --GcNC.HATluNIANNUAL. ENERGY kEijUIFIEMENFS(MlLL.IO~S OF Kli.01'4ATT•hUU~S)
34
TABLE 3.10 . (contd)
.OI<EA: FAI~f>ANJ<.S
~AINHA~~S CASk: 2 •• ~EDIUM LUAO GRO~IH
!Nf~~Tl~ T~Ak: 1q9o. ,
NDIES:U~C. b, 19/d hi U.S.-1q94.
C " l T I C A I.. f' I: t< I U 0
----------------------~------------------------------------------------------------------I }qb1•1'!82 I !982•198:; I 191!3-19~4
I PEA~ "'"uF Ai-'UF f,,Ef<GY I P~AK MPUF ~PUF ENEi<GT I PEAK I"PUF APUF I:Nt::><I>Y ,_":' ____ --------1-------------... 1-----------------------------1 I I
~~''''i~EMI:IHS I 2ll. 97(). I .!33. 1 Oc'"· I 245. 1\171;.
---------------1 I I
><I:.~Ul.i~CES I I I
E~ !Sft;;G I I I
><Yui?O I o. .so .::.u o. I u. .so .o;o o. I llo .so .so o.
:>Tf_Aioii<.LEC I 110. • 7'5 .75 723 • I 11 o. .'75 •. 7'5 723. I II 0. .75 .7'5 723 •
CU"'l. TUP.o H<E I 209. • so • 14 2&2 • I 209 • .so .17 317. I 209. .su .21 .Hl.
llit:StL I .. b. • 10 ... ou o • I 1.1&. • 10. .oo o. I <~c • .10 .oo o.
I I I
TOUI. I 3&5. 9l:l5~ I .5&5. 10.39. I 3&5. lli-.14 •.
I I I
AIJO!T[tJNS I I I
f"tl'\.!oo(tJ I I I
~TEA•II€LEC I I I
(.U•'>i• Tuk.; lNE I I I
ult.SEL I I I
I I I
~I:TlREI-'€:NTS I I I
!-tl'llloiiJ I I I
SiE~-../ELEC I I I
co.•d. ru.;., !liE I I I s. .oo .oo o.
vli:SI:L I I I
I I I . ------------.---1 I I
l::rKOS~ ilE:OOU~CESI .s&s. 985 •. I 3b'5~ 103 ... I 3&0. 1094.
I I I
CAl' '<ES. loiAiiGllil o.ast. I o.sc.e. I" o.4o7
I I I
i<E:if:<VC: !<Ell~ I 55. I 58~ 'I "1 •.
I I I
t..O:>St.S I ll. 15. I 12 •. lj. I 12 •. lb.
I I I
ht.T kfSI)UiiCES I 2'1'1. 970. I ac;s. 102<1. I 28o. I 0 71> •.
I I I
TI<AtlSFEREO I u. I o. I o.
I I I'
I I I
SuF<PI.u::; I 78·-o. I oc. lj. I <11 •. a.
PEAK Ptu t..OAll/GIENeRA Tl :<IG-C.,t,;>,o;C-I TY -i<El.IUli'tl:i•t:til':T(...eGA"'A-TTS )-
l-li>IJF MAXIMUM PLA~T ~flt..1ZAT!ON FACTO!'(
AI'UF .>.r;Tui.~o. PLANT UTILiZATION FAC TOi<l
Ei•EI<GT --G~Nt~ATIONIANNUAL ENtr<GY NfUUINtMtNlS(MILLIONS OF_ KlLOWA TT•nOUR:S)
35
TABLE 3.10.
A><!:A: A.\oCHOWAGE
AtiCnOIIAI.oE CA:>t.: c •• "'full.JM LIJAO GIIOI'ITH
lNTE~llt I~ARl ~~~~.
NOTEs:oac. &, t¥7~ ~~ u.s.-1~~4.
(contd)
CIIITIC.I.l. P E 1< 1 0 o
I
I PEAt< , _____ _ _______________ ,
~E'III l"ll::"l:rl T S I
---------------1 "E~IIIJi<CE:; I
EX 1::. fiiH> I
liYUkO I
:.TEA"~IELfC I
C();.,., • TUII6 HIE I
OIE:.SEI.. I
I
'53.
c'H.
<1~.5.
15.
TOTAl.. I 1202.
I
I
HYLikll I
STtAMIEl.t:C I
CfJ>u1,TUIIbiiiE I !rio
Ol~SE.l. I
I
i<tTIREMENTS I
HYUI<f) I
:OTi:Aioi/E.l.!:C I
co~~.ru~~IIIE 1 1s.
uiESEl. I
I
---------------1 biiOS:. ~ESOU~CESI 1205.
I
CA~ ~es •. MARGlN/ 0.333
I
wE:>EkVE ~EYo I 22&.
I
l.OSStS I 45.
I
~ET k!:SOUIICES I ~1~.
I
1RANSrEREO I u~
I
I
SuRPLUS I 30.
19.,41-1965
MPUF APUF
.so .so
.15 • 53
.:.o .~41
.15 .oo
.~o .so
I
Eo~C:FIGY I PEAK --------, _____ _
I
4001. I 91&,
I
I
I
<!04, I 53.
11&41, I 251.
2b15 • I 886,
o. I IS.
I
.5¥1!2. I 1205.
I
I
I 61.
I 207.
79. I
I
I
I
I
I
u. I 31.
1 to.
I
I
GOal. I 1~52·
/
I 0 .4188
I
I 21HI,
I
&o. 1 419.
I
41001. I 1159,
I
I 0 •.
I
I
o. I 183.
198~·1981>
MI"UF APUF
.5o .~o
• 75 .b4
.so .28
,15 .oo
.~o .so
.75 ,20
.uo .uo
,00 .oo
I
ENEIIG Y I PE '-K
--------1------1
11329, I 1048.
I
I
I
20'1, I
h05. I
<!l1c. 1
0~ I
I
37211. I
I
I
301. I
31>3. I
I
I
I
I
I
I
o. I
o. I
I
I
4394. I
I
I
I
I
I
aS. I
I
11329. I
I
I
I
I
o. I
1311.
<1'5.,.
!ISS.
s.
o.:sas
2&2.
sa.
1138.
u.
PEAK •• PeAK l.OAOIGENERATING CAPACIU RE.r.llllREr-t€NTS(MEGA..,ATT;;)
HPUF ••"MA~IM~M PLA~T UfiL!ZATI&N FACTUH
APIJF •• ACTUAL l't.ANT UTil.llAf!OIIt·~·A'irlV...'
19d&•19o7
~,OlJF Ai>UF
.so .so
• 7 5 • 5b
.su .cb
.15 .uo
ENERGY ·-GC:NE.RA fiON/ AfliNUAt. EiiiERGY k'ECUIREME.NTS (MILL.IONS OF 1\ II. OWA T1•HOU~-
36
llo57.
510.
22':>'1.
1958.
o.
~727.
4727.
70.
<~c57.
o.
TABLE 3.10. (contd)
.A~EA: F AI ktJ AIH\S
F 4lktiAI•"-5 CASt: i! --MED IU11 L04D GRu,.TH
INTER TIE YEt.k! 1'1'10.
NuTE.S:DEC. bt t'l7o til U.S.-1'1'14.
c R I T I c A L p E ~ l 0 D
---------------------~-------------------------------------------------------------------I 1'1<>4-l'lfl') I l'lt15-19!lb I lqflb-1'167
I PEAo< MPUF APIJF ENEioii>Y I f'E;.AK "'PIJF Af'UF ENERGY I PEAK MPIJF APUF E~>o~EI<.OY , ______ --------1--------------1-----------------------------1 I I
.-;.:!Oul .. ~•tE•I rs I 2SB. 1132 • I 272. ll'U. I ~ll&. 125<1.
--------------1 I I
t<E::.OcHCES I I I•
eJ.I::, r IN~> I I I
HYui<u I o. .so .'::>0 o. I o. .so .so o. I o. .su .so o.
::.1 t.A'11ELEC I 110. .7S .f'5 72!.. I 110. • 75 .7S 12!.". I 21u. ,;1s .ss 10 11!.
CO'<o • Tulhl lNE I 2(14. .sc. .211 42b. I 2011~ .so .18 313. I 204. .so .1:1 25<4.
u !i:.StL I 116. .10 .oo "· I 22. .IV .oo o. I 22. .10 .uo o.
I I I
T(llAL I 31>0. 1149. I 33<>. 10 :Sb •. I 1136. 1213.
I I I
A[;Dl r !OoiS I I I
n'fuW~) I ~ I I
::.H.~ <IELEC I I toe.. .7':> .20 17~. I ...
CU"·'"• TUR>llll!:. I I I
DIE!:>EL I I I
I I I
o<!: 1 lk!:MI:NTS I I I
nl'vHIJ I I I
5 TEA ·4/ELEC I I I
;.;u·•H. TUt<tJI:1E I I I
UH.SEL. I 2'1~ .c.o .oo o. I I
I I I
---------------1 I I
GROSI> ~<c::.uu>~cE.sl .53&. 1lll9. I ll5b. 1211 • I 1131>. 1273.
I. I I
CAP ><Es.· rUR(;Ir.l o.3uO I o.&lil I 0.523
I I I
'<ESERVE i<Efl. I I:>S. I &8. I 72.
I I I
1-DSSE~ I l.S. 17. I 111. 111. I \II. 19.
I I I
hET h'ESOIJKCES I 2S6. 1132. I 3511. 1193. I 3Sil. 125<~.
I I I
. li<ArJ::OFE:Kt:O I o. I o. I II.
I I I
I I I
SUR?LUS I o. o. I 112. ll.-I 1>4. u.
PEAK PEAK L.O&D/GENE~ATlNG CAPACITY NEQUIREkE~TS(MEGA~ATTS)
MPIJF MAXiMUM PLANT UtiL.llATIUN F4CT0i<
A~UF ACTUAL PLA~T UTILlZAflON FACIO~
·e~ENGY --G~N=RATIONIA~NUAL ENERGY REQUINEME~lS(MlLLID~S OF KILUWATT-HOU~S)
37
TABLE 3.10 .
.!.IlEA: AI.Ci"IOkA!>E
ANCHUI<A!>E. (;A·St: ~ •• Mf:l!!UM L.UAU GWOWTH
I~TEHTI~ YEAR: 19~0.
NUTES:DtC. b, 197d wl U.5.•1994.
(contd)
C ~ I T I C A L P E I< ! 0 0
I
I l't:.Ai(
1---------------------1 WtYVI~EHENTS I 1120. _______________ ,
' RE;iOuKCES I
eXI:.TI~;I. I
hYURU I 134.
~T~A~IELEC I 458.
C0-·1.-1. TIJo<tsiUE I ""'~·
~IE.SEL I S.
I
TOTAL I 111'52.
I
AIJIJ L T I!mS I
riY!.oi<O ·1
~TtAMitLEC I iDU.
CIJ'"'• I•JI<tHNf. I
t:IC.SEL I
I
<>U!f<I:'-1Er11S I
1'1YUK0 /
ST~~MIEL.EC I 1'5.
CO"o.TIJI<<J!N£ I
v!t:.SE.L. I
I
---------------1 ,5RUS~ HESQUIICES/ lb37.
I
C.I.P t<ES. MA~GlNI u.4&2
I
l<f:b£HVE kEU. I 28u.
I
,LOSSES I '5&.
I
~ET ~ESOUWCES I 1!01.
I
TRANSFEREU I o.
I
I
SUHPLUS I 1~1.
l'lb7•1'16d
MI'Uf A!>Uf
• .,o .!i(J
.7'5 .... ~
• :.o .211
.15 ".oo
.75 .20
• uo • oo
I
f:NEWG Y I Pt AK
--------1------1
11'185. I 119~.
I
I
I
stu. 1 134.
2'113. I &113.
17116. I 8!:>5 •
0 • I 5.
I
<1709~ I 1&37.
I
I
I
35U • I
I
I
I
I
I
o. I
I bllo
I
I
I
. SQoO. I 1573.
I
I 0.320
I
I 29tl.
I
75. I &Q.
I
4985. I 121b.
I
I 0 •
I
I
il. I 211.
l'idb•l98q
Ml-'lll' AP\JF
;.,1} .so
.7!:1 .!:18
• so .23
.IS .00
.oo .oo
I
eNI:WI.iY I 1-'!:.4~ --·-----, _____ _
I
~515. I 121>11.
I
J
I
511). I
3254. I
lb2tl. I
ll. I
I
5393. I
I
I
I
I
I
I
I
I
I
I
o. I
I
I
I
!:>39.5. I
I
I
I
I
I
1!0. I
I
5315 • I
I
I
J
I
0 • I
1573.
1575.
2'33.
b5.
1257.
7.
o.
PEAK •• PIOAK L.OAOIGENEHATlNG CAPACITY WEYUlREMENTS(MEGAWArTS)
HPUF --MAXlMUM PLANT UTILIZATION FACTOR
AI'IIF -• ACTUAL PL. ANT UT lLlZA TlOIII FAC TuW
19d'l•l9qll
i<!PUF ~I>UF
• ~0 • 50
• 7 5. .bO
• .,II .21
• I '5 • UO
ENEWGY --G'NtRATIONIANIIIUAL ENEnGY REQUIHEMENTSlMll.LlONS Of KILOWATT~MOUH:ll
/
38
Sb'llo
5lu •
31'15.
!<HI •
v.
S72b.
S72b.
o.
TABLE 3.1 0. (contd)
~REA: FAl"tiANI\S
FAII<fUNI\S CAS!::: 2 --MEDIUI'I 1.040 GROWTH
Ir<TE.Id It TEAll: !990.
i'<UTES:Ot.C. "• !'Ills ill u.s.-t'l'14.
.c R I T l c A I. p E I( I (J D
-----------------------------------------------------------------------------------------I 1907•1'1!11:1 I l'l!!d-191:59 I l9o9·19'1o
I PEAl( MPUF APtJF EilE:RGr I PtA~ MPUF APUF ENEiiGY I PEAl< MPUF Ai>UF ENEI<GY
1-------------1·-------------1-----------------------------1 I I
f\Ef~Ui><f.,•E.•I r S I .$00. 1315. I 3114. 137b • I .32!1. 1<137.
---------------1 I I
;;e:sou><c<::s I I I
E .. l~T V<G I I I.
...,YUI-!1) I o. .sv .so o. I 0 •. .so .so o • I u •. .:.u .so o.
SteA ... ~/tLi:.C I .:no. .1'5 .oC! 113'1 • I 210. • 75 .ba 11'1'1. I <!to. .7S .b8 12"0 •.
C D:1~ .:r •JI~b I NE I 204. .':>0 • 11 I 'Itt • I-2V4. .so .10 1711. I 204. .so .1() 17<1.
IH~SEL I 22. .. 10 ... .oo o. I 22. .10 .oo o • I o. .10 .oo o.
I I I
Til r.t.t. I 430 •. 1.$35. I 431>. 1372. I <119. 1'159.
I I I
.t.(ln IT I u'JS I I I
>Hvi<O I I I
Z, T!:.AMIE.LI:.C I I 1'1. • 75 .20 25. I
CD;o..,t;.rurc~tr.E I I I
U!t!>E.L I I I
I I I
R!::Tl~t:."'E.>IIS I I I
l"tY-.Jal) I I I
S ft;.A·~IEI.f:C I I q. .oo .oo u. I
co"'". Tlli<n!NE I I I
UltSEL I I 22. .oo .oo 0 •. I
I I I
---------------1 I I
~ROSS .<ES<Ju~CE::.I 4.3e. 1.:135~ I 41'1. 1397. I <H'1 •. t'l':i9-
I I I
CAl' .. c:s. 1-IAHGHU o.~':>c I ll.33<1 I u.cn
I I I
i<ESE;<VE WEU. I 75. I 79 •. I &&.
I I I
i.OSSES I 1':i. 20. I 1o. 21. I lb. 22.
I I I
><ET «rSO•iKCES I 3llo. 1315. I 325. 137b. I .;37. 1437,
I I I
TR.t.~•~FEREO I I) • I o. I -7.
I I I
I I I
SU«I'LIJS I ao. o. I 11. o. I "· o.
PEAK PEAl< i.OAOIGENE~AT!NG CAPACITY ~Er.ul«EMENTS(M€GA~ATTS)
I"PIIF MAXl.MUM PLANT UTILIZATION FACTOw
AI'UF ACTUAl. PLANT UTILILAT!UN FALTO«
E~E~GT •• GEN~kAT.ON/A~NUAI. ENE~GT REQuiRE~ENTS(MII.LlONS OF Kli.UWATT•HOUKS)
•
39
TABLE 3.10.
At<cA: A<>Ct10t<A~E
4•·iCH01lAGE CA~.e: 2 •• .'IEDIUM L.UAll GROJ'iTii
!NTERIIt YEARl 19~0.
NvT£S:O~C. bo 1~7CI wl U.5.•1994.
(contd)
C R I T 1 C A l. P E R I 0 0
I
I PEAl(
1---------------------1 ~~~U!REMfNTS I 1357.
~--------------1 kESOol~CE5 I
e:~ I~ T lNG I
11Y1Jk.J I
STEA'~IEL.~C I
CIJ~'~k.TUtlfJ!NF. I
ld!:.l>EL. I
TOUL.
HYU>-1)
SIE.Artlel.EC
CO·~!!. TUKct I ••E
0 lt:.SEL.
I<Yuilll
~TeA"'If'l.tC
L!J'•Ib. IUt<t<INI:.
CJ!E:OEI.
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
---------------1
5.
157$.
200.
GR~SS ~E~OU~CE~I 1773.
I
CAP ~ES. MAHGINI 0.307
I
kE~Et<V~ REa. I 271.
I
L.OSS~S I &ij.
I
~ET ~E50URCES I 1434.
TiHNSFEf'IEU
SURPLUS
I
I
I
I
I
o.
77 •.
l'l'10•19'H
MI'UF APUF
• !30 .!)0
• 7'5 • 71
• :.o .19
.15 • GO
.75 • .20
I
I PEAK
1------1
I 1450 0
I
I
I
510. I 134.
39cs&. I 843 •
• I 'SOB. I 79 I •
0 0 I 5.
I
5804. I 1773.
I
I
I
350. I
I
I
I
I
I
I
I
I
I
I
41.
Ill.
2 •·
I 1955.
I
I 0.349
I
I 290.
I
91. I 7J.
I
oo&3. 1 1593.
I
I •2'1.
I
I
O. I 114 0
19'+1•199.?
MPIJF APUF
.50 .so
• 75 .&5
.so .1&
• 15 .oo
• 75 .20
.ou .oo
.uo • 00
.00 .GO
I
ENERGY I PEAK
--------1------1
&4d5 0 I 1543.
I
I
I
'510. I
4'55.?. I
10'15. I o. I
I
&157. I
I
I
I
1125. I
I
I
I
I
I
o. I
u. I
O. I
I
I
&582. I
I
I
I
I
I
97. I
I
&1185. I
I
I
I
I o. I
1311 •
10<15 •
773 •
3.
1100.
su.
230e.
().<194
77.
1920.
P~AK •• PtAA ~OAOIGt~EHATIN~ CAPACITY ktQUlRE~ENTS(MEGA~ATTS)
r•PtJF •• MAXIMuM PLANT UTIL.llAriON FACTUH
~~uF •• ACTUAL PL.A~T UTILILATIUN FACTUH
19'iZ•l'l93
MPUF JoPUF
.~o .so
.7'5 .5b
.so .10
.15 .oo
• 7'5 • .20
.oo .uo
ENERGY •• GENI:.RATIONIANNUAL E~ERGY REQUIHEMENTS(MIL.LIONS OF KIL.O~ATT·~OUHSl
40
&9117.
'51 0.
Slbo •
b3'1.
a •
701 •
7011.
b907.
TABLE 3.10.
•l?Ea; FAl"II,.N~S
FAI~HANKS CASe: 2 •• MEDIUM LOAO GROWTH
lhT€RTIE YEAR: 1'190.
NUTES:OEC. o, 1978 Nl U.S.-199~.
(contd)
C><IT!CAL fJ E R I u D
I 19'10•1991 I 1'1'11•1'1'lc
I i"f'.Ao( ,"tPUF APUF E.'<t:i<GY I I'E.lK lolPUF APuF ENEr<G1'
1--------------1--------------
---------------1 I
1<E.1JUl;.£·~toNTS I 343. 1SOS. I 3Sl!. 1~73.
---------------1 I
.><ESOUPCES I I
Etl~Tl'!f, ~ I
;,vul<v I (J. .so • so o. I o. .so .so o •
STE-.A>~IIOLEC I 2lb. .15 • 13 1172. I 21b. • 75 .oa tess •
C 0/o\o. TuRS Il>E· I 20~. .so .17' 300. I 204. • so • 18 313 •
(<leSEL I o. .~o .oo (1. I o. .I <I .oo IJ •.
I I
TOTAL I 419. 1472. I 419. 1597.
I I
.&our r ror,:; I I
HYur<O I I
:, 1tAMitLEC I 3c •. • 75 • 20 -so • I
tfJ;·IH • TURtt l Nf. I I
ult:.SEL I I
I I
1<1:. T !RlMI:.NI S I I
kYu"O I I
~Tt.AM/eLE-.C I 32. .oo .oo o. I
Cfl~tf;. TlJ"11l liE I I
0lt:.SEL I I .. I
~--------------1 I
~I<USS,NESUU><CESI "'l '~•-· !Self .•. I 419 ... 1597.
/· I
£AI" i<ES • MARGIN/ 0.222'. I o.u~
I I
:iESEi<VE ;cEQ. I &<t •. I 7c.
I I
i;,OSSE.i I t 7.' 23. I 111. 24.
I I
',tET ,.ESOvRCES I 333. 1S05. I 330~ 1573.
I I
LUAI<:Ol'-f.Ht() I u. I 2'1.
I I
I I
SuRPLUS .. I -1o. o. I o. o.
I 1'~9c•t'~•S
I PEAK 1-ti'UF A?UF 1:.. _____
I
I 374.
I
I
I
I o. .so .so
I i!l&. .7".:1 .71
I 204 • .:.o .23
I o. .10 .oo
I
I <119.
I
I
I
I
I
I
I
I
I
I
I '10. .uu .uo
I
I
I
I .S7'1,.
I
I Q.Ql3
I
I 75.
I
I !9.
I
I 28&.
I
I ~'j.
I
I
I II.
PEAl( --P€A" I.OAOIGE"'i:R.t.fll'lG CAPACITY ~EQUIRE~ERTS(MEGA~ATTS)
Mi'UF --l"~lC'IMLIM PLANT Ul !LIZAT!ON FACTOR
J.PUF --ACTUAI. .. Pt.ANT UTlLlZATlON t-AC ruw
E!<ERGT --GENt:.RATION/ANkUAL ENERGY ~EQUIREME~lS(MIL~ONS ~ KlLOWA TT•HOUI<Sl
?--
41
"!>
!::NEI<GY --------
lo~l.
u.
135'1 •
327. .
II.
lbb&.
u.
1bob.
.1'5.
lb4t.
o.
TABLE 3.10 .
.H;EA: A•'•Cn0f.(At;£
A·~C>iCJf.(A!>E. CASt: 2 •• I~EOIUH LOAO GHu~ITH
INTE~TII:. YEAH: 1~~0.
NaTES:O~:.C. &, 197d WI U.S.•1994,
(contd)
Cl'llTlC4L. P E 1< I U D
I 1'1'13•1994 I 1'194•1995
I PEA II I"PUF APIJF EN£)1GY I PEAK MI'IIF APUF ENEHGY 1--------------1----------·------------------1 I
><E.uu L'1e•1!:"' rs I lb3&. 7329. I 17 29 •. 77Sl. _______________ ,
I
.;E::.OI.!IlCES I I
E~I:,Tl'lG I I
>iYuiHJ I 134. • ~o .~o ':110 • I 13<1. .50 .so ':Hil.
:;HliMIF'LEC I 1 ""~-.1'5 • ~II bS<~.S. I 1'1115. .75 .34 ll"bo •
cn"s.ruRBI~E I 72<1. • so .10 ':il>b • I bb'l. .so .10 SSo.
IJIE~el.. I 3. • lS .011 o • I .s. .15 • oo o.
I I
TOTAL I 230o. 71i.S'I. I 2251. 53a2.
I I
AUiJ l T TIIN5 / I
>iYlJI<(J I. I o5t>. • :,u .:,o 25u:..
S Tt. ~:<~EI.F.C I I
CUM!. tUI<f1 [NE. I I
Uli:.:'!EL. 1-I'
I I
FIETlffEI>IENTS I I
·.,,u~li I I
;;TO.IIEI.EC I I
CIJ~lil. TuHHINE / 55. .uo .oo ~--I
utpt.L I I
I ,.
---------------1 I Go<os:. I<ESilURCESI ?i/'51. 7439-,. I 2'109, 7ao7 •.
I I
CAP' "ES. lo!AkGINI 0.37& I o.&e~
/. I
W€1>E~<VE nEU. I 30!7·. I .Silo •.
I I
L.uS::i£!1 I 1'>2. llp. I 8&. 11&.
/ I
I•E T "<"SOuRCES I 11142. 7329 .. I i!47&. 7751.
I I
Tlo!AN:.FEREO I •107. I o.
I I
I I
SURPLUS I qq. o. I 747. 0 o.
I 1995•199&
I Pli:411 Mt'UF APUF
1-•----I
I 1<'1'511.
I
I
I
I 7'12. ,':iO .50
I 1114~. ,75 .3b
I bb'+. .so .10
I 3 • .1'3 ,00
I
I 2'10'1.
I
I
I <lb. ,50 ,511
I
I
I
I
I
I
I
I 125 •. .oo .oo
I
I
I
I C!l\11.
I
I 0.548
I
I .5"7 1.
I
I 93.
I
I 2<107.
I
I u.
I
I
I 553.
Pt:AK --Pt:AII L.UAOIGEN~RAilNG CAP'ACllY ~~UUlHE.M~NTS(MEGAWAITS)
MP>JF --!o4AXll'lliM Pl. ANT UI~I.IZJ.IIIJN FACT~R
At>IJF ·-ACTUAL. PLANT UHI.lZATION FACTUI'I
tNtWGY •-GtN~~ATlONIANNUAL ENfloiGY t<EilUIW~I'It:NT S (141 L.L!ONS OF I( ILOWJ. TT•HilUR:, I
-: • .... ~
_ ..
42
I:.NE.RGY ,
----•o••
6311.
.lUI~.
<lhl<~.
<111.
o.
•t)10b,
.52'1 •
u.
a"$o.,.
125.
6311 •.
1).
TABLE 3.10. (contd)
Ail'!: A! F ~I ..tBAI~I<!T
FA!><~AN~S CASt: ~ --MEU!U<'I LOAIJ Go<O,.TH
l."HE!H 11:. ~EA~t: 1990.
NOTES!Ot:.C. ... 1978 ..I u.s.-19911 •
c lot I T l c A L p 1:. I< I u u
-------·---------------------------------------------------------------------------------I l'l't:S-1994 19911•199S I 199S•t99o
I PtA.< •ii"Uf AI'Ur ENE;lGy I PEAK MPtJF Af'ttF EI'<E~GY I PtAK MPUF A?\Jf EN€"1b~
1-------------1--------------1--------------
---------------1 I I
tot€t.iUlkt:.r1t,:~;5 .Sil<t. 1709. I "os •. 1 7 7 7. I a.:3. 1o':l"i. ---------------i I I
!(E!>ttu~<CF.S I I I
Exl:.TL>;G I I I
HY~>Ir) I "· • SIJ .so u. I o. .• so .sa u • I lSI. .so .so 57 ...
s>.;A:ili:LEC I 2tb.,., • 7S • 73 1377. I 21&. .75 .sa lUdb • I 2Jo. .7S .&3 10S3 •
co .. .;. TU>lb II<E I u:i.:~. • :oo .25 357. I 1&4 •. .so .10 1113 • I 1""· .:oo .10 1'13 •.
c.z .. sF.t.. I o. • 10 ... c.o o~ I .'¥. .10 .oo o • I o. .10 .oo u.
I I I
TOTAL I 31'1 •. 1735. I.·· 379. 12:!"·· I :030. 177"1i.
I ,. I
Aunt rru••s I I I
H'f!J;;(U .I ... I 151. .so .so S74 • I 19. .so .:oa 7~.
:> TC.A"< IO:Lt C I I I 25. • 75 .2V 43 •
CUM'l. TU-IH INc I I I
Dlt.!:i .. L I I I
I I I
i<t T !Rt:it;N!S I I I
r·n'tJ~fJ I I I ;,
:;l.OA..,/EI..EC I I I c!S. .011 .uo v.
Cr'JM.,.Till<.;fi'<E I I
Dlc.~EI.. I I r
I I I
'
_______________ ,
I I
GWuS.:. ;{F.::iOIJt<CE:;I j79. 17JS •. I 530. 1804. I :; .. q. 18117.
I I I
CAP ;:.tfS. "'ARGINI•U.Oc!o I 0.308· I 0.2'111
I I I
o<t.:.t::><~IE I<EC... I 7'!>. I Ill. I l!';;.
I I I
Lo,;se.s· I 19. 2a. I 20 •. 27. I 21. 26.
I I I
'•£ r ><e.:;uo~<ce.s I 2112. 1709. I <12'1. 1777". I "l-'4.$. lt!::.q.
I I I
THA'J!>Fii.REIJ I !07. I 0 •. I o.
I I I
I I I
SURPLUS I o. o. I 2a. o. I 20. o.
PEAK PtA' LOAUIG~NE~ATJNG CAPACITY ~EYO!REMEI'<TSIMEGA~ATTS)
MPUF MAXiMUM PI..AhT IJTILIZATION FACTOR
APUF ACTU~L PLA~T Ufii.IZ4TION FICTU!ol
E~eWGT ·-· G'NcRATION/ANNUAI. ENEWGY ~EQUl~EMENTS(MlLLIONS QF KILUwATl•"UUK!>l
~---···--
4-3
TABLE 3.10.
A~EA: Ao•ICHOriA~E
ANCHU~A~E CA~~: 2 •• MEU!UM LOAO Gkb~TH
INTE~TI~ TEA~: 1990.
N~TES:OEC. o, 197ij WI U.S.•1994o
(contd)
C k 1 T l C A L. P E R I 0 0
---------------1 Wf.r.IUli<E"'t.'H::S I
---------------1 IIE:;QuRCES I
EXt;",Tl;U; I
rt1ullo 1
& T i: AI~/EI.EC I
CO:-.n. TU-<? [ilE I
Uli:.SEL I
I
IOI&t_ I
I
AOfil T fii .. S I
11tiJiol0 I
5 T£Ao.ti€LEC I
i;U..,?.TUI<bOlE I
iJlt.SE.t_ I
I
Rt::Tl!'IO::t4ENTS I
J..
2811.
HYUI<(J I
!>TI:A!</ELE.C I
CbM8.TuloiSikE I 210.
011:~1:1. I ~~
I
---------------1 Gf<l;SS. l<t~IJIJI<CESI 2!>':>'1 •.
I
CAP NES. ~AFIGl"l 0.3G3
I
kESEhV~ ~o!EQ. I 396.
LOSSI:S
I
I
I
NET I<ESOUKCES I 21bQ.
I
II<A~SFEREO I •27.
I
I
SuRPLUS I 156.
19'16-19'1-7
MI'UF :.01'UF
.::.o .50
• 75 ·"a
.50 .10
.15 .oo
• uo .oo
.110 .oo
111Hl.
I
I PEAK
1------1
I 2103.
I
I
I
3344. I
5.$&&. I
2911. I
871:1.
1445.
335.
o. I
I
I 2&59.
I
I
I
I
I
I
I
I
I
I
a. 1
o. I
I
I
9004. I 2!>~9.
I
I 0 ~2b4
I
I 421.
I
133. I 105.
I
8871 •. I 2133 •.
I
I 0.
I
I
o. I 30.
1997•1998
MI'UF APIJF
• 50 • so
• 75 .47
• so .10
.1'; .oo
ENErlGY
I
I PI:.A ..
1------1
1 222~.
I
I
I
3344. I
~'134. I
294. I
u. I
I
a.
9572. I 2b59.
I
I
1 o5<~.
I
I
I
I
I
I
I
I
I
I
I
lll •
I .i2'1';.
I
I 11.479
I
I ll4b.
141. 111.
9431. I 2738.
I
I o.
I
I
o. I 510.
PEA~ •• PEA~ L.OAO/GENEHATING CAPACITY ~EUIJlkEMENTS(MEG.l~ATTS)
~PUP •• MAXIMUM PL.A~T UTI~lZ.t.f!ON FACTOR
1998•1999
~li"UF APUF
.~o .so
.75 .32
.51) .to
.15 .oo
• :iO • 50
.oo .uo
.t.PIIF •• AtTUAL. PLANT UTlL.llATIOI'o FACTiJ~ ~~EkGt --G~NI:.HAT!ON/ANNUA~ ~~ERGY ~EnUIH~MENTS(HILL.lONS UF KIL.O~ATl-HOU~Sl
44
3.511'1 •
.;1)2':>.
275 •
v.
2493 •.
o.
1\ll111.
tso.
o.
TABLE 3.10.
Ai<EA: FAI~flANI\S
FAikHANI\~ C4St: ~ •• HEUIUM LUAU GNO~TM
I~TE~Tie YEA~: 1~~0.
NQTES:DEC. ~~ l'l7~ WI u.S.-19~4.
(contd)
C lol I T l C A L I' E fi I tl 0
I l'l'<t>-1997 1C,97·1'19o
I PEAK MI'UF A>'tJF EI•E~GY I >'!::All MPtJF APUF EI•E~GY • 1.: _____ --------1--------------
---------------1 I
><E<<UlR€HE•'lfS I <14.?. 1':141. I '>t> 1. 2023. _______________ ,
I
RESOIIo:ICES I I "t I::. T !riG I I
11'1'1.1"'0 I 170. .50 .so !>48. I 170. • so .50 o-.a •
SH:.•:</ti..EC I 2lo. .1'5 ·"" !cOO. I 21&. .7'::J • 1>5 1250 •
(.(),.;e. Tui<B IllE I 164.-.:.o .10 123. I 140. .so .10 o.
i.>iio:.El. I u. .10 • uo o • I u. .10 .oo u.
I I
TOTAL. · I 54'1. 1970 •. I 526. 1878.
I I
AIJ!Jl TlOII!i. I I
nYuwr) I I
~I!:A·•Jt::U.C I I 100, • 75 .20 17'; •
CCHt'l. Tuwt'JINE I I
0 IE.SEL I I
I I
i<E. Tir<E~~ttn:;. I I
>!YUNO I I
S rt . .a.:HELEC I I
t(Jr1..,.Tl1Rb zr;E I 24. .oo .oo o. I 140. .uu .o.o o.
:J.It::SEL I I
I I
---------------1 I ~Nos• RESUUkCESI :.2f:r· •. 19711 •.. I· ~llo. 20'!B.
' I I
~~ .. o.Es. :•11.>1GlN/ 0.1 59· I 0.053
I I
~!:':.e: .. ve WEiJ. I II"'• I 'l<l.
I I
t..OSSES I 22 •• 29. I 23. 30.
I I
NET f<ESOuRCES I 415. 1941 •·· I 370. 2023.
I I
II<M~.':iFERE.O I 27. I o.
I I
I I
Sui!PLUS I o. (1, I -91 •. o.
I l'1'l8-1'l99
I Pt::..-"-,-1fo)tJF A>'lJF
1------I
I <180.
I
I
I
I 170. .:>0 .so
I 31<>. .75 .35
I o. .so· .10
I o. .10 .oo
I
I 48b.
I
I
I 138. .so .su
I
I
I
I
I
I
I
I
I
I
I
I o24.
I
I 0.299
I
I 9t>~
I
I 24.
I
I 504.
I
I o.
I
I
I 24,
PEJ.K Pt::AK LOAO/GE••ER AT l NG CAPAC! TY KEQUl~E~ENTS(MEGJ.wAfTSl
MPIJF MAXIMUM PLANT UTH.l.ZAT!ON FACT OW
APUF ALTU41.. f'LANT UTlL!lAUON FACTO~
ENE~GY --GE.NtRAflONIANNUAI.. ENEI<GY REYUI~EME~TS(MILLIONS OF K Il..u>'IA Tl•HOUHS)
45
\::l<t~GY --------
2!1l5.
04ti.
9o.;.
ll.
o.
loll.
525.
2137.
32.
2105.
u.
------··· "" .. ----····------------",. ·-·--··· .,, .. , ' ________ ,,.,,. ___ , __ , ________ ........... --------------
IAIL~ ~.] ~~ (e~n~~~)
A~EAI ANtaFIIIHAiiE
AUiliHJRAIIIi llUe.l e iiii Mii:I!I:IM l,;t:JAU fiiHI~JfR
lNf@Hfl& fEA~I J~ijQ,
NUfiiit~aa, 81 l~'ij ~~ l:la8,aJ~~a.
a N f f i f! i 1,; ~ e ij 1 B a
&~ww~&a~a&•••••aaama••••aaaaaaaa•••;==~;;;;;;;;;:;:•;••=•=•:;:;;::=;;;;:::;:::::;;;;;••••
I l~li~iiifldU ' eoou;;eogl , ll~5»6lAB~~e I fiiiU lolfiUii AliUii ENi~B;V I f"I:U Ml:iUF Alii:! l!f46~fiy ; iiU~ ~FII:Iltiv
laiililliliilil lilliliil& iiiliiii liliiiiiBIIIiiii liiiliiiiil:i ;:;;;;: ,;;;;;;.;; ;r;;;;;:;;;:;; i•=:=•• ::;:: ·=--;.:;:.;aa.li ••••••••••••• .,.1 I I
k4h1Ullf~l4f!.IUII I en,. 10!§1, I li!lli!h lU8Ua ~ eitliiJ; Hils. •••••••••••••••I ' NUOUHCU I I ; u lt!f I'll• I ; ;
H¥1JN(J I Jt;H, tl!IIJ t!iO !/Uf a I hl7a a90 a;!ll Willa i ilil7a a!i8 ;§6 s~ao~ IIUAM"I.~a ' ltiiHi •· .n aJii IUIUs; I lllli~& a Hi ;i!7 IIUh I lU~a ;'§ ali II 5 6th SOM8,TUIIIWIC I au, ,!HI aiD iha I ua. a!O dO U~a I U a II q d8 iB!i 1.1111.1181. I o, .u .oo IIi I Oa a iS aBO Ba I Ui d! aBO B,
' I i H6i!Ba ~ !U~. TDI•I. I nu, lO!Ua i 3ifi8a iUUji.
I I I
AIJIHT 1111~11 I I I
l'tYtJIW I u. ,!;0 li!i6 !Ua i .. .. .. il I .. .. ;a ;o .
GaA~<~II!t.rc I .. .. .. .. i li Iii li .. I il li li ifi
CIJiltJ, TIJNIHfll!. I ... .. .. ii I li .. li li I a li a li
t•!&UI. I .. .. .. ii i ii ii li ii ; .. li :a iii
I I i
lit Tlil,lll.ll!hTII I I ;
,. tiJ~IJ I .. ... .. .. , ; li .. li ii I .. li :a " 61Uio4/lit.I!C I .. .. .. .. i .. ii· .. ii ; ii "' li ii
~nw~. TIIHI'I WI' I Rio .uo .ao ~li I 160a a60 a61l o,, I llh aUU aUil Ua
U!i.Eit:l., i ... ... .. ii; I ... .. li li ; a li li Iii
I I I
••--••••••••M••I I ;
!11<01111 IIIUIMHC!IIi :u!"ll·· &OfOt»". I ina .. uuaaa. ; auo. I iitt!.
i I i
CAP H!&o MAAQlhl 0,1102. I ti.;.JU I lllii'l'f ' I I I
k!-.l!HVt Ull.lo I U1lo I II Iiiia ; II If h.
I I i
t.OS8U I 1111. 1'511. I 1214 IEiio~o I' U!. iba.
I I I
NET WEliUUHCEll I 2 71 ''· IO~!U., I 2'!1jJI. 108113. I 2~!18. 1117'5.
'I I I IIUNIIFEUEO I ,. I u. I •b.
I I I
I I I
SIJRPI.IJS I 357. o .. I 172. a. I u. o.
PIA~ •• PEA~ I.OAUIGaN!RATlNU CAPACITY ~EQUliiEMENTS(ME~AWATTSl
MI"UF· ••· NUifoi\Jiol P\,ANT UTli.IZATlCIN FAC:TUR
APUF •• ACTUAL PL~NT Ufii.IZATlON FACTOH
ENE"GV •• G~N~HAfiON/ANNUAL EN~Rwf kEYUlHEMENTS(MILLlON~ UF KII.O~•TT•HUu"a)
46
TABLE 3.10.
AWtA: FAll<i:lAI.II::i
FATRRA~IIS CAS~: 2 --~EDIUM LOAD GRU~TH
I~IE~!It YE~~: 19~0.
NOTE5:UEC. o, 1976 ~I u.a.-t~•q•
(contd)
C R I T I C A L
I
I PEAK
1---------------------1 I<Euut~<t:~tNTS I
---------------1 .,t.SOUI<CilS I
E~t::iTI••G I
•ITIJktJ I
:; TEA><IELEC I
CO"'o. TUi~ti H•E I
DIESEL. I
I
TOIAL I
I
.A(JOlTiiJ:JS I
~Yui'!'J I
S T E ~-·IIELEC I
C(Htl. TUw" INE. I
0 l"SEL I
I
~ETIRE"!E•HS I
><YLJf.Ot; I
S rcji-1/ELi:C I
C,(;,.':l. TU'it> lht. 1·
OIE::.<:L I
I
---------------1
308.
.Sib.
o~.
u •.
to.
Gr.t~SS. ~ESOU~CESI ~~1.
I
CA~· NE.:;~ ~•r.t~Ihl o.aes
r
kE5E'<V~ wE<I. I 10u_.
I
LOSSES I 25.
I
~ET ~esuu~CES I 51b.
I
TRAkSFEREO I v~
I
I
SuRPLUS I 17.
19"9-2000
MPI.JF APUF
.~o .so
.75 .35
.so •. 10
.10 .oo
.so .so
I
ENERGY I PEAK --------1------
1
21&7. 1 soa.
I
I
I
1173. I
960. I
O. I
O. I
/
2153. I
I
I
&7. I
I
I
I
I
I
I
/
I
I
I
I
31o.
a.
a.
2220. I &41.
I
I O.Zb2
I
I 102,
I
33. I 2S.
I
211:!7. I 514.
I
1 a.
I
I
0. I· b.
2000-2001
MI"UF APUF
.so .so
.75 .37 .so .10
.1 0 .oo
I
ENERGY I PEAK --------1-----1
2229 •. I
I
I
I
t24u. 1
1022 •· I a. 1
a. 1
I
22&2. I
/
/
I
I
I
I
I
I
I
I
I
I
I
I
32&.
31&.
22&2. / &41.
I
1 o.c.s6.
I
I 104•
I
33. I 2&~
I
222-J. I S12.
I
I &.
I
I
a. 1 o.
PE~~ PtAK LOAO/GENERATI~~ CAPlClTY ~c~UlkEMENTS(MEGA~ATTS)
~~UF MAXiMUM ~LANT UfiLilATlON FACTuP
APUF ACTUAL ;.<LANt UTtLllAT!ON FACTUi<
2001-2002
MPUF A~UF
.so .so
.7S .38 • so .1 0
.10 .• oo
tME~GY --GtNtRATlONIANHUAL ENENGI NEuUikt~tNfS(MILLlONS OF ~lLO~ATT•MUU~::i)
47
ENEWGl
2270.
o.
TABLE 3.10.
Al<tA: Ao~C1'10l<At.E
ANCHO~At.E CASe: 2 •• ME~IUM LOAO GROWTH
I~TERTlt YEaR: 1990.
NQitS:OtC. &, 1~7~ ~I U.S.•t99'1.
(contd)
C R I~l ! C A L P E R I 0 0
-·------------------------------------------------·--------------------------------------I,
I PE.h ,_.., ___ _
---------------1 ,;£1JU1REM~NT5 I 2SS1i. _______________ ,
><El>OOJiiC£5.
EAIST!t<t;
11YLIRO
STEA"~/ELEC
.CIJM~. Till<!:! ["€
lJitSE.L
TOTAL
AUu 1 r rn:.:.
,.,,,JI'ilJ
!>TtA'Itt,t.£!i;o
Cf'H':I. 1 U.ii:l Ltl£
CIE::iEL
I
I
I 11>17.
I 11145.
I llcl.
1 o.-
' I 3100.
'I
I
I
I <I flO •·
I
I
I
ilt;.Tlk£MENTS I
•••uiiO I
l>TC . .l;~JEL£C I
t.•J~tiO .. TtJHtslf .. C. I 100.
ul:.Sf.l. I
I _______________ ,
~RIJS~ ~!SOuRCES/ 34RD.
I
c;.p I<ES-MAWGII</ 0.31>1
I
~E~~wve "EO. I ~12.
I
~usses 1 12b.
I
NET ~ESUURCES I 2841.
TRANl>F£i'IED
Sl.lkPI,.IIS
I
I O.
I
I
I C!R5.
coua-~uo3 /,
MPUF APUF E~E~GVJ~ PEAK
.~u .. -
.7"'!
-• :.o
.15
.IS
.uo
• so
• 38
• 10
• uo
•• w
• uu
--------, _____ _
I r"iqar. 1
I
I
I
o1bll. I
ll/o3. 1
1~. I
o. I
I
10959. I
I
I
I
7Q1. I
I
I
I
I
I
I
u. I
I
I
I
11&59. I
I
I
'I
I
I
17c. 1
I
111187. I
I
I
I
I
o. I
2&2&.
to17 •
184~ •
111 •.
o.
3480.
34110.
0.32")
525.
131.
u.
c003•2V04 I
MPUF APUF ENERGY I PEAK
.so
.75 .so
• 15
.so
.!b
.10
.oo
--------1------1
11799. I 2b94.
I
I
I
bi&O. I 1&17.
5aot. 1 to4':1.
15. I liS.
O. I O •
I
1197&. I 3480.
I
I
I
I
I
I
I
I
I
I
I ld.
I
I
I
1197&. 1 34o2.
I
1 o.aso;
I
I 539.
I
171 • I 1.5':i.
I
11799. I 2789.
I
I u.
I
I
u. I 9':1.
PEAK •• PEAK LOAOIGEN€RATl~G CA~4ClTY ~ECUlRE~ENTS(MEGAwATTSl
MPUF --MAXIMUM PLA~T UTILIZATION FACTOR
.li'IJF ·-ACTUAl.. PLANT Ul lt.l.ZAT!IJN F4.CI11ii
c?Oil'l•cllo>5
MPUF APUF ENEHGr
.:.o
.75
.so
.15
.:.o
.3a
.10
.oo
.uo
12111.
b1oO.
ot33.
o.
o •
12293.
u •
11:12.
lc:!lll.
o.
E~ERGT --Gfl'l:.iiATlUN/ANNUAL ENERGY riEUUIREMENJS(MILt.IONS OF ~ILU~ATl-HOUR~l
48
TABLE 3.10.
•i<E.A: FAL,.ciANI\S
· FAIR~ANI\S"CASe: 2 ·-MEDIUM LUAO G~O~TH
"lr.TEIH!i:. TEAi<: !'lql),
NultS:UEC. &, 1'173 ~/ U.S.•!9~4.
(contd)
C II I T l C A i. , -.P E ~ I 0 0
-----------------------------------------------------------------------------------------I
I PEAl( , _____ _ _______________ ,
kE~U!~E~E.~TS I ·~21.
---------------1 r<ES:Jc.f<CES I
E.Xl!:>f 11.•1> I
,_,TtiRt/ I
:.·TC.-'·"1-'LEC I
C Or•~. 1 Ufto! NE I
li!i:.SEL. I
I
TOTAl. I
I
Joi)Ul no.-..s 1·
rHtJ~() I
Sil:.4MIE!.EC I
Cu·.;~. To;R,INE I
Dli:..';fL I
I
fiET!f>E~>'E.'HS I
"'Y\Ji<O I
STU'Aii:.l.i:C I
CU/~:s •. Tu"o !NE I
CJ!C.SE!. I
I _______________ ,
;.;.;(;S;l ;.cESOUkCESI
I
CA?· ><i:.S •. HARGiro/
I
NESE><VE "EQ. I
I
~o:,scs 1
I
~ET i€5DURCES· I
I
TkAN:,fE!If.O I
I
I
SUki'LUS I
u ...
71&.
10~.
o.
';7 •·
20u2-2\I03
MPUF APUF
• sa .SQ
,15 • .$7
• 50 .1 0
.10 .uO··
.7'5 .20
.oo .oo
I
f:I,Ef<li Y I PEAK
--------1------1
2312. I 537.
I
I
I
l2'~u. 1
931. I
O •. I
0,. I
I
2171. I
I
I
I
17'5 •. I
I
I
I
I
I
o. I
I
I
I
I
2.547. I
I
I
I
I
I
.55. I
I
2312. I
I
I
I
I
u. I
326.
391.
0 •. o.
71&.
71&.
107 •.
2.7.
soa.
0:003•20011
MPlJF APUF
' .su .so
• 7';:> .34
• 5u .1 o
.lU .,00
I
ENERGY I PEAK
--------1------1
2353. I 5<~1.>.
I
I
I
!2<:o. 1 32& •
1l'lo. 1 391.
0 I o •.
0 • I 0.
I
2338. I 716.
I
I
I
I
I
I
I
I
I
I
I
I
I
I
2388. I 71b.
I
I 0.311
I
I 109.
I
35. I 27.
I
.<353. 1 sao.
I
I u.
I
I
O. I 3'1.
PEA~ --PEAK LOAUIGENEIIATING CAPACllY NEWUlNE~ENTSIMEGA~ATlS)
HPUF --MAX!Mu~ PLA~T UTILliATIUN FACTUM
Ai'UF ••· ACTUAl Pt.~NT UTILIZ.ATHlN FACT(I><
20U'l•2005
MPUF APUF
.50 .so
• 75 • .35 .su .10
.10 .oo
ENE~GY ·-GENtRATIO~/ANNUAI. EhENGY PEQ!Jl~EMENfS(MI!.LIONS OF KII.OnAT1-~0URSj
49
ENERGY
12"0.
1191 •
0'"'.
o.
.<431.
2<131.
o.
TABLE 3.10.
AwE A: Ar•CHOIHuE
A'ICHII~AbC: CASt.: i! •• I~EIHUM l.,OAU GROWTH
INI~kiiE TEAR: 199U~
NUTES:O!C, bo 1978 WI U,S,•1994,
(contd)
C ~ I T 1 C A L 1-' E >< I 0 0
I
I PEAK , _____ _ _______________ ,
><El<•llREI~""' IS I 27,.,3,
_______________ ,
NE:;Oli>ICES I
Ed:.Tt:,r, I
n1l.IHU I 1&17.
:.T~AM/EL~C I 1845,
COH6,TUR81~£ I B,
UI!SEL I u_
I
TOTAl.-· I 34&2,
I
AuOITlONS I
H1'0k•1 I
STEA"IELEC I
CCJMtt, TIJ>ifj I~E I
IJIESEL I
I
RETIRE 1~1:NTS I
1-H'UitfJ I
STtiA~IELEC I
Cu!~a, TU><tHi•E I
fJIIiSEL I
I --------------·1 GRUS~ HE~OUHCESI 34b2.
I
CA~ ><~5, MARGIN/ 0,25!
I
kE:;e;Hv~ ><E~. I ~53,
I
L.ObS!S I 131,
I
NET ><ESOU><CES I 2771,
I
TRAN~FEREJ I 0,
I
I
SUR Pit. US I
20QS•i!OO&
MPUF APIJF
.~o .so
,IS ,40
,SG ,10
,15. .uo
I
ENEHiiY I PEAK ---·-·---, _____ ,.
I
12423, I 21131,
I
I
I
i>1b0, I 1&17,
b45U, I 11145,
{), I 0,
fJ • I 0 •
I
12&09. 1 34&a.
I
I
I
I 400,
I
I
I
I
I
I
I
I
I
I
12&09 •. 1 3&&a.
I
1 o.3oll
I
I 5obp
I
18&, I 142.
I
tc4c3. 1 3154.
I
I •10,
I
I
0. I 313.
2Do&-aoo7
MPUF AI'UF
.so ,!:;0
,75 .38
,SO ,1(1
.15 • 00
.75 .20
I
EIIIE~tH I I'I:AI\ --------1---·--1
12735, I 2119.<i,
I
I
I
blbll, I lbl7,
I>Obo, I 224~.
0, I O.
o. / o.
I
122as. 1 3aca.
I
I
I
701, I
I
I
I
I
I
I
I
I
I
I
1292&, I 38bc!.
I
I 0,332
I
I ::1811.
I
l'H. I 145.
I
12735, I 3137 •
I
1 -a.s.
I
I
o. I i!l&.
P~AK PEA' l..OAUIGEN€~ATING CA~AClTY HEQUlkEMENT~(MEGA~ATTS)
~PVF MA~lMUM PLANT Uf!LIZAI!UN FACTUR
A~UF ACTUAL PLA~f UTILIZATIO~ FACTO~
2007•i!OO!l
MPUF APUF
• so ,!30
.75 .~& .so .10
.15 .uo
E:1EHGY -Gi:Nt"fUTIOri/AN~UAL t::t•€kGY RELIUlHE>H:tHS(MlLI.IONS tJF ~ILUWATT•.,tlUioiS)
1.5047.
blbU •
7083.
o.
o.
1.32•13.
• 1c;,;,,
o.
-----------------
50
-
.~
·1\t'
\
TABLE 3.10.
A~EA: F•I~t<ANI\S
rA1~84N~S CAS~: 2 •• ME~IUM LOAO GRO~TH
!rtTEid !!:' YEAI'<: 1'790.
NUTES:O~C. bo 1476 hi U.S.-1994.
(contd)
C R I T 1 C ,~o L P £ il I 0 0
-----------------------------------------------------------------------------------------I ~uu5-2uOo I 2011o-<'u07 I 20o7-2o08
I Jo>EAK 11i>UF A>'UF Ei<Eid;y I PEAK ,..PUF A?\IF EI<E>~GY I ?F.AK lo!PUF A?UF ENEI<GY
1-------------1-------------1----------------~------------1 I I
wEiou.l~E!o<C:r.TS I sso-. 2437 •· I Sos. 2478. I 575. 25211.
---------------1 I I
·.;f·::.uu"cEs I I I
El' 1::. T!tJ& I· I I
r!TililO I 32o. • :.o • so 12'10. I 32& • .so .so 12'11o • I 321:>. .so .so !2110.
!>T'.A,~IEL£C I j'll. • IS • ~0 1234. I .171 •. .7':J • .19 1-!T!:i • I Hl • .75 ... 1 1.11 !1.
CONio. TU;.tl311•E I o. .::.o .!()· o. I ()~ .so .10 o. I o. .so .10 (j
iiH~c:c.· I o. .10 .oo o •. I o. .10 .oo IJ. I o. .1 0 .oo ().
I I I
TOT AI. I 7H>. 2•174 •. I o9&. 2515. I o9&. 255<1.
I I I
.&ODlTIO~<S I I I
.rtYU"'I) I ,. I
STC.4""1tLEC I I I
CUI->':!. Tu.;f\ tr<E I I I
ju r E.SEL. I I I
·' I I I
~~TI,.~:o~r.~<TS I I I
• rH~>l; I I I
.:.HAUELEC I 20. .uo .oo o. I I
! co"'". Tul?" lt•E I I I
Olt!>6L I I I
' I I I --------------1· I I
i:fj"..j(j~!j ;;!£souRcE:;;/ b'H:a. 2'174. I' bq& •. 2515~ I oqo. 2558.
l /· I I
C~P· ~f.S .... A.RG 1111 0.252. I 0.232 I 0.211
I I I
><ESEJ<v( I<E.Ii. I lll ~ I 11.3 •. I 115.
I I I .
i.OSSt!> I 26. .H. t· 26. 37 •· I 29. 311.
I I I
·•E r ~<Esouwc<:s . I 557. 2'137. I 555. 2<178. I 552. 2520.
I' I' I T~A,.SFEI<EU I "·· I 10. I 23.
I I I
I I I
SuRPLUS I 1.:.. o. I o •. o. I "· u.
>'!OAK PEAK LOAOIGE~ERA TPI!i CAI'ACllT iiEYUIRE~ENTS(~E&A~ATTSl
Mi'tJF MAXlMU14 ?!.ANT UT!UlATl(JN FACTuil
AP'IJF ACTUAL ?LA'<T U f ll.lZA T ION FACTUw
E'>Et<GY --GEN~~ATIO~/ANNUAI.. EIIIERGY RECUIREMENTS(MlLLIONS OF K li.OWA TT•nOURS)
TABLE 3.10.
AI<EA: ~:•CI'IUkA<>E
AI•ChU;IAt..f CA~t.: 2 •• I~EOIUM I.OAO GHOI'iTH
I~~~~Tlt rEA~; 19~0.
NUlt&:o~c. ~. 1~7~ ~~ u.s.•tq•q·
(contd)
C R l T I C A I. P E R ! IJ 0
I
I P!AI( 1·-------------------1 "RE~U!N!~tHT3 I 2q~d.
---------------1 kt;::.:;uo;Cl:.i:> I
Exl:.JIIIG I
HVOkO I 1~17.
"l~A~IEI.EC I 224~.
COMI3.Tilfl>;ll'lf I v.
. _. ux .... e.t. 1 u •.
I
TOTAL I 3~~i.
I
"UiHTI0"5 "J
ttTui<IJ I
.<; rf.A.</ll.fC I
CO>ti3.TUHt!WE I
UI~.&I:.I. I
I
Hf..Tlll£11!NT3 I
;.,y <JiiO I
SllA"</t:.LEC I cc;,_,.,. ToJ.l.; II<E I
Ult:SE.l. I
I
---------------1 i.l<Oi:>.:; f.IF..SUiJi<CES/ 38&2.
I
CA~ k£5. ~&PGINI 0.301
I
kE~E"vf ~Eu. I 5'1~.
I
l.!li:>3l.> I 14d.
I
NET i<ESOU.:CCES I .5120.
I
T~~NbFERE.D I •3qo
I
I
SUWPI.US I lltlo
20ua•c!UU'1
MPUF Ar'UF
• 50 • 50
• 7 5 • 38
.~o ~10 .1s-.ua
I
E~Eio<GY I PEAK
--------1------1
13359. I 303&.
I
y
I
&t&o. 1
7400. I
a. 1
O. I
I
u~sq. 1
I
I
.l I
I
I
I
I
I
I
I
I
I
I
I
11>17.
2245 •
0 •. u.
13'!159. I "38&2.
I
I 0.212
I
I 1)07 •·
I
200. I 152.
I
1335'1. I "3103.
I
I •4&.
I
I
o. 1 a1.
zoo<~•co1u
MPUF At>UF
.so .so
• 7 5 .39
• so .10
.1~ .(10
I
ENf>lGY I PEAl( --------1·-----1
13&71. I 310'1.
I
I
I
blbO. I lt>Ll.
7po. 1 22.qs •
0 • I 0 • -o •. 1 o •
I
13871>. I 3t>o<.
I
I
I
I QQO.
I
I
I
I
I
I
I
I
I
I
1387&. I 4262.
I
I 0.373
I
I to2l.
I
205. I 155.
I
13&71. I 348b.
I
1 -sa.
I
I
0 • I :5.:!5.
PEA~ ---PEAl( l.OAUIGENERATlNb CAPAClTY REQUlHEMENTS(MEGAwATTS)
~PUF •• MAXIMU~ P~ANI UTILIZATION FACTUW
Ai'IJF •• ACTLIAL PLAiH UTlLlZATION FACTUtl
2tJ10•2U11
MPUF Ao"UF
• 50 • so
• 75 .37
.~o .10
.15 •. uo
.75 .<u
ENtHGY --GEN~RATIUNI~NkUAL eNE~GY REQUlKEMENTS(Mli.LlONS OF ~ILOWATT-~~URS)
52
13'11;~.
olou •
7j3c!.
"· u.
'"'·
21U.
o •..
TABLE 3.10.
Ar<EA: FAI><bANKS
FAIRBAN~S CAS~: 2 --MEDIUM ~UAO
I~TF.RT!c YEAR! 1990,
NUlcS;UtC. o, lild ~I u.~.-1~94.
GRO;.jTH
(contd)
C R I T I C ~ ~ P E R I U 0
------------•••-••••••••••••••••-•••••-•••c•••••-••••••••••••-••••••-•••-•••••-••••••••••
I co,n~-2Uv9 I 2009-2010 I ~010•2U11
I PEAl< MPUF ~i>IJF Ei'!EI<GY I PEAK MPUF 'APUF EI.ERGY I PEAK ;.oPuF ·APUF ENt:i<GY
1--------------1--------------1-----------------------------1 I I
kt.u•;li<L.~tliT S I 5n<~. 2Sol. I 594. 2&0~. I &03. 2&4::i,
---------------1 I I
i<E:;uui<CES I I I
Ex r.:.T !rJG I I I
HYIJi(0 I 32& •.. .~o .so 12"0· I 32& •. .so .so 1240, I 32io, .so .50 1240.
STU!-!IELEC I 371. • 7 5, .42 1359. I 371 ~ .75 .43 140~. I 371. .75 ,45 1445.
COk6,TURtiiNE I 1). .so .~o o. I o. .so .10 o. o. .so .10 "·· lll'-SEL I u, ,10 .oo 0· •. I o. .10 .oo o. o. .10 .oo o·.
I I I
T'lf AL I o9&. 259'1. I l>'lh, 2b42. I &l.fhqo· c~~~-~
I I I
AuO 1 TI'11•S I I I
H'ffJRO I I I
:;T~J<>oi/EUC I I I
C014FI. Tu.~;; I I.E I I I
ui::cSEL I I I
I I I
I<E r 1RE.'-4C.IH S I I I
"TIJRII I I I
S Tl: t.'~/€Lt:C I .,. I I
CO"<b. Tu><»!I>E I I I
liii:.SEL I I I
I I I
---------------1 I I
G:;os.:. f<ESuURCf:SI <>96. 2599~ I &9& •. 2&42 •. I 6'7&. 2t.&5 •..
I I I
C~~-~EI,. ~ARGINI 0.1'12. I 11.17<! I Q.l~'l
I I I
"'ESE,., \IE: .<eo. I 117. I 119· •. I 121.
I I I
I...OSS!:S I 29. 38 .. I 30 •. 3~. I 30. '40 •.
I I I
NET ~ESO"UI<CES I 5'50. asc.1. I 54<1. 2!>03. I 545. 2t>'15 •.
I I I
TRAI'<SFEREO I 3<1 •. I 4&. I 58 •.
I I I
I I I
SURPLUS I o. o. I o~ u. I o. o •.
PEAl( PEAl<. ~-QAD/GC:NER.I. T ING CAo>ACIT\' ~EUUlREMENTS(MEGA~ATTS)
lolf'UF 1-!AXlMLJ/01 f'LA·H UT li...lZA fiON FACTO!<
APIJF ACTuAl.. ?LAN r UTILIZATION FACTO~
ENEWGY --G~NkRATlONIANNUAL. ENEI<GT REQUIREMENTS(MILLIONS OF K I LUnA TT•toiOURSJ
53
TABLE 3.11. Schedule of Plant Additions -(Megawatts)
Base Cases Without Interconnections
Anchorage Fairbanks
Period High Median Low High ~·1edi an ~ow
78-79
79-80 114 1 114 1 1141
80-81 100l 1001 1 OOl
81-82 18 1 18 1 181
82-83 5002 300 4 1 Q01
83-84 200
84-85 218 4 18 1 18 1 100
85-86 288 6 288 6 88 5 100
86-87 400 100
87-88 200 200
88-89 400 14:7 14 7 14 7
89-90 200 200 100 100 100
90-91 32 7 32 7 32 7
91-92 443 9 243 8 43 7
92-93 400 400 200 100 100
93-94
94-95 400 3 200 100 100
95-96 4003 400 200 25 7 25 7 25 7
96-97 4003 400 400 100 100
97-98' 400 3 400 200 100 100
98-99 400 3 200 100 100
99-00 400 3 400 400
00-01 400 3
01-02
02-03 400 3 400
03-04 400 3 200 200
04-05
05-06 4QQ3 400 400
06-07" 400 3
07-08 200
08-09 4003
09-10 400 3
10-11 400
TOTAL 78-11 8,281 4,681 2,681 1 ,471 871 471
See footnotes next page
54
( 1 )
( 2)
( 3)
( 4)
(5)
(6)
(7)
( 8)
( 9)
TABLE 3.11 .. (contd)
Scheduled Combustion Turbines
Scheduled Combustion Turbines + 400 MW S.T . .
Anchorage 400 MW Coal-Fired Units Could be Replaced with Staged 800 MW
Capacity Units
Scheduled Combustion Turbine+ 200 MW S.T.
Bradley Lake (70 MW) x 1.15 for Peaking+ 7 ~1W S.T. National Defense
Bradley lake (70 MW) x 1.15 for Peaking+ 200 MW S.T. + 7 MW S.T. National
Defense
National Defense
200 ~4W S. T. + 43 M~~ S. T. Nati ona 1 Defense
400 MW S.T. + 43 MW S.T. National Defense
55
TABLE 3.12. Schedule of Plant Additions -(Megawatts)
Cases With Interconnection Without Upper Susitna
Anchorage Fairbanks -;
Period High Median Low High Median Low
78-79
79-80 114 1 114 1 114 1 .
80 ... 81 100 1 100 1 100 1
81-82 18 1 18 1 18 1
82-83 500 2 300 3 1 00 1
83-84 200
84-85 218 6 18 1 18 1 100
85-86 288 5 288 5 88 4 100
86-87 -* -*
87-88 400 200 200
88-89 148 14 8 14 8
89-90 400 -* 200--* 100
90-91 200 32 8 32 8 32 8
91-92 443 11 243 9 43 8
92-93 400 200 200
93-94 400 100
94-95 -* 100 -*
95-96 400 7 400 200 12510 12510 25 8
96-97 400 7 400 -200 100 100
97-98 400 7 400 200 100 100
98-99 400 7 400 100
99-00 400 7
00-01 400 7 400 400
01-02 400 7
02-03 4ooi 100
. 03-04 400 200
04.-05 200
05-06 400 7
06-07 400 7 TOO
07-08 400 7 400
08-09
09-10 400 7
10-11 400 7
TOTAL 78-11 8,281 4,281 2,231 1 ,271 671 471
See footnotes next page
56
TABLE 3. 12. ( contd)
*Interconnection Installed
(1) Scheduled Combustion Turbine Additions
(2) 100 MW Scheduled Combustion Turbine + 400 MW S.T.
(3) 100 MW Scheduled Combustion Turbine + 200 MW S.T.
(4) Bradley Lake (70 I~W) x 1.15 for Peaking+ 7 MW S.T. National Defense
(5) Bradley Lake (70 MW) x 1.15 for Peaking+ 200 MW S.T. + 7 MW S.T. National
Defense
(6) 18 MW Scheduled Combustion Turbine + 200 MW S.T.
(7) Anchorage 400 t~W Coal-Fired Units Could be Replaced with Staged 800 1·1W
Units
(8) National Defense
(9) 200 MW S.T. + 43 MW S. T. National Defense
( 10) 100 MW S.T. + 25 MW S. T. National Defense
( 11 ) 400 MW S.T. + 43 MW S. T. National Defense
.•
57
TJI.BLE 3.13. Schedule of Plant Additions -(Megawatts)
Cases With Interconnection With Upper Susitna
Coming On Line in 1994
Anchorage Fairbanks
Period High Median Low High Median Lov1
78-79
79-80 114 1 114 1 1141
80-81 1001 1 OOl . 1001
81-82 18 1 18 1 18 1
82-83 500 2 3005 1001
83-84 200
84-85 218 8 181 18 1 100
85-86 288 7 . 288 7 88 6 100
86-87 -* -*
87-88 400 200 200
88-89 . 1410 1410 1410
89-90 400 -* 200 -* 100
90-91 200 3210 3210 3210
91-92 443 14 243 12 4310 -*
92-93 -400 200
93-94 400 200 100
94-95 677 3 658 3 644 3 132 3 lSi 3 1643
95-96 893 86 3 85 3 4211 4411 46 11
96-97 400
97-98 400 100
98-99 688 4 654 4 124 4 138 4
99-00 86 4 85 4 645 4 16 4 184 1474
00-01 83 4 100 19 4
01-02 4009 100
02-03 400 9 400 100
03-04 200
04-05 400 9
05-06 4009
06-07 400
07-08 400
08-09 400 9
09-10 200
1 0-11 400 9 400
TOTAL 78-11 8,221 4,564 2,538 1 ,360 697 522
See footnotes next page 58
TABLE 3.13. (contd)
*Interconnection Installed
(1) Scheduled Combustion Turqine Additions
(2) Scheduled 100 MW Combustion Turbine+ 400 MW S.T.
(3) Share of Watana Capacity x 1.15 for Peaking
(4) Share of Devil Canyon Capacity x 1.15. for Peaking
(5) Scheduled 100 MW Combustion Turbine+ 20U MW S.T.
(6) Bradley Lake (70 MW) x 1.15 for Peaking+ 7 MW S.T. National Defense
(7) Bradley Lake (70 MW) x 1.15 for Peaking+ 200 MW S.T. + MW S.T. National
Defense
(8) Scheduled 18 MW Combustion T~rbine +200 MW S.T.
(9) Anchorage 400 MW Coal-Fire& Units Could be Replaced with Staged 800 MW
Units ·
(10) National Defense )
(11·) Share of Watana Capacity x 1.15 for Peaking+ 25 ~1W S.T. National Defense
(12) 200 MW S.T. + 43 MW S.T. National Defense
(13) Share of Watana Capacity x 1.15 for Peaking+ 25 MW S.T. National Defense
'(14) 400 MW S.T. + 43 MW S.T. National Defense
59
-3:
:§
Q
~
...J
~ < L.U a..
Q z <
V')
L.U u
~
=:l
0
V')
I.U
~
~
I.U z
7000
6000
5000
4000
I
I
3000
2000 ~---c:a-. ..
1000
0
80 85 90 95
YEAR
I
I
2000 2005 2010
FIGURE 3.6. Load/Resource Analysis for Anchorage-Cook Inlet Area
Without Interconnection and Without Susitna Project
(Case 1). Low, Medium, and High Load Growth Scenarios
60
-:5:
~
0
~
-J
~ < 1..1..1 a_
0 z <
V')
1..1..1 u c:::
::::;)
0
V')
1..1..1 c:::
i-
1..1..1 z
7~~------------------------------------~--------~
6000
5000 7
4000
3000
2000
1000
0 L-----~------~----~------~------~----~'------~~
80 85 90 95
YEAR
2000 2005 2010
FIGURE 3.7. Load/Resource Analysis for Anchorage-Cook Inlet Area
With Interconnection but Without Upper Susitna Project
(Case 2). Low, Medium, and High Load Growth Scenarios
61.
7~r-----------------------------------------------~
6000
3: 5000
~ -Q
~
-I
~ 4000 <C
u.J c..
Q z
<C
~ 3000
(..)
0:::
;:::)
0
V')
u.J
0:::
1-
u.J -------..... -z
1000
0~----~------~----~------~----~------~----~--~ 80 85 90 95 2000 2005
YEAR
FIGURE 3.8. Load/Resource Analysis for Anchorage-Cook Inlet Area
With Interconnection and With Upper Susitna Project
Coming On Line in 1994 (Case 3). Low, Medium, and
High Load Growth Scenarios
62
2010
-:1:
~
0
~
-l
:::.:::: < u.J
0..
0 z <
~
u.J u a::
:::J
0
~
u.J
0:::
1-
u.J z
1200
1050
900
i50
600
450
300
150
0
80 85 90
, .... ~
I
95
YEAR
,.. ..... _
I -I
J
I
I
,..._ I
I ..... ,/
I
I
I
I
I
, ___ , ______
2000 2005 2010
FIGURE 3.9. Load/Resource Analysis for Fairbanks-Tanana Valley Area
Without Interconnection and Without Upper Susitna Project
(Case 1). Low, Medium, and High Load Growth Scenario
63
-3:
:E -c
C3
-1
~ < LU c..
c z <
V')
LU u c:::
::::::1
0
V')
LU c:::
1-
LU z
1200 r---------------------------------------------~
1050 " u ,_ /
I
I
900 I
I
I 750
-I -'\}
600
c._ca.,CO~ezq,
450
300
150
0
80 85 90 95 2000 2005 2010
YEAR
FIGURE 3.10. Load/Resource Analysis for Fairbanks-Tanana Valley Area
With Interconnection but Without Upper Susitna Project
(Case 2). Low, Medium, and High Load Growth Scenari
64
900 -3:
;§
0 < 750 0
..J
~ < UJ c..
0 600 z <
(I')
UJ u
0::
::::J s; 450
UJ
0::
!-
UJ z
300
80 85 90 95
YEAR
2000 2005 2010
FIGURE 3.11. Load/Resource Analysis for Fairbanks-Tanana Valley Area
With Interconnection and With Upper Susitna Project
Coming On Line in 1994 (Case 3). Low, Medium, and High
Load Growth Scenarios
65
4.0 SYSTEM POWER COST ANALYSES
This chapter describes the methodology used to evaluate the annual
cost of power from individual generating facilities (or groups of sim·ilar
generating facilities), the method of computing the average system-wide
power costs, and presents· the results of the system power cost analyses.
The first section briefly discusses the factors which determine the cost
of power. The second section describes the computational method used to
compute tbe annual cost of power. This method is incorporated into a
computer model titled ECOST4. A listing of the computer code is given in
Appendix D.
The third section of this chapter contains a discussion of how the
system-wide power costs are computed given the power costs for the indi-
vidual facilities. The results are presented in the last part of the
chapter.
4.1 FACTORS DETERMINING THE COST OF POWER
Three cost categories are evaluated in this report: 1) interest and
amortization charges (capital cost); 2) fuel costs; and'3) operating,
maintenance and replacement costs. Of course, there are other cost items
included in the cost of power to the consumer, such as taxes, insurance,
distribution and billing charges, but these costs are not evaluated in
this report since they typically do not vary among the three cases
evaluated.
These components of the cost of power are shown in Figure 4.1. The
annual plant capital expenses are fixed by the initial financing and are
typically constant over the life of the plant. Operation, maintenance,
and replacement fuel costs typically increase over time as affected by
inflation and real price increases. As a result, the total annual cost
of power progressively increases over time.
4.1.1 Capital Costs
The capital costs repres~nt the total cost of constructing a gene-
rating facil"ity. The capital cost estimates used in this analysis include
0
66
COST OF
ELECTRICITY
(MILLS/Ki~H)
TOTAL
1~, N N U A l C 0 S T.
\
TIME (YEARS)
FIGURE 4.1. Components of the Total Annual Cost of Power
67
.:;
•
interest and escalation during construction. It is assu~ed that the capital
costs are repaid in equal annual payments over the payback period of the
plant. The capital cost estimates used are in terms of constant October
1978 do 11 ars.
The total investment cost for the coal-fired and hydroelectric
generating facilities are shown below.
Total Investment Cost
(million $) ($/kW)
100 M~l Coal Steam Turbine 245.4 2454
200 r~w Coal Steam Turbine 372.0 1860
400 WA Coal Steam Turbine 646.8 1617
Watana Dam (795 r·1W) 2501 . 2 3146
Devil Canyon Dam (778 MW) 834.0 1071 . 9
SOURCE: Alaska Power Administration, August 1978.
Transmission facility costs are presented in Table 3.7.
4.1 .2 Heat Rate
The heat rate is the ratio of the Btu•s going into the plant as fuel
to the kWh 1 s of electricity produced by the plant. The heat rate is
assumed to remain constant for all plant utilization factors over the
lifetime of the plant. The heat rate for new coal-fired steam electric
plants is assumed to be 10,500 Btu/kWh.
4.1.3 Operation, Maintenance, and Replacement Costs
The operating, maintenance, and replacement (OM&R) costs include the
administrative and general expenses as well as the interim replacement
costs. All estimates are expressed in terms of October 1978 dollars.
They are escalated at a rate equal to the rate of general inflation.
The OM&R costs for coal~fired steam electric and hydroelectric
generating facilities and transmission facilities are shown below.
68
I .
I
OM&R CO'Sts
(million $) ($/kW/yr)
100 ~1\.-J Co a 1 Steam Turbine 3.76 37.6
200 MH Coal Steam Turbine 5.7 28.5
400 MW Coal Steam Turbine 9.8 24.5
Watana Dam (795 MYJ) 0.74 0.94
Devil Canyon Dam (778 MW) 0.73 0.94
New transmission facilities 2.0
SOURCE: Alaska Power Administration, August 1978.
4.1 .4 Financing Discount Rate
The financing discount rate represents the cost of capital to
utility. A rate of 7.0% is assumed in this report. This ,is assumed to
be an average of all types of financing available~
4.1.5 Payback Period
The length of time over which the plant is financed is the payback
period. This is assumed to be equal to the plant lifetime except for
hydro projects where a 50-year payback period is assumed versus at least
a 100-year plant lifetime (see Section 3.2.6).
4.1 .6 Annual Plant Utilization Factor
The plant utilization factor (PUF) is the ratio of the actual power
production during a year to the theoretical maximum if the plant was to
run 8760 hours at 100% capacity during the year.
The annual plant utilization factor is highly variable depending upon
many factors (e.g., forced outage rate, cost of power from alternative
sources, and power production requirements). Because of this, it is
necessary to explicitly·consider the effects of the PUF on the cost or
power over the lifetime of a plant. As pointed out earlier, the PUFs
used in the report are determined by the load/resource analyses (see
Section 3.2.6).
4.1 .. 7 Unit Fuel Costs
Fuel costs for thermal generation plants are expected to increase
over times following paths shown in Figures 4.2 through 4.4 for natural
69
BELUGA & HEALY
80 90 2000 10
FIGURE 4.2. Estimates of Future Coal Prices -
2% and 7% Escalation
SOURCE: Alaska Power Administration, August 1978.
70
20
10. 0
1.0
ANC HO RAGE -KENA I
BELUGA
0. l
70 80 -90
7%/
I
I
I
00
I
/
I
I
10 20
FIGURE 4.3. Estimates of Future Natural Gas Prices -
2% and 7% Esca1ation
SOURCE: Alaska Power Administration, August 1978
71
:=!
I-
CO
~ /~
/I "flo
II
II
II
:a: 10. 0 I/
~
~
FAIRBANKS
1/
II II
//
II
II
ANCHORAGE-KENAI PENINSULA
90 00 10 20
FIGURE 4.4. Estimates of Future Fuel Oil and Diesel
Prices -2% and 7% Escalation
SOURCE: Alaska Power Administration, August 1978.
72
gas (Cook Inlet areas), coal and distillable o{l. Although natural gas
is likely to become available in the Fairbanks region in the early to mid
1980's~ Federal policies are expected to preclude its use for power gen-.
eration except for probing and the cost is indeterment at the present
time.
4.1.8 General Inflation Rate
Because of the uncertainty involved in estimating the future rate of
inflation, two alternative cases are evaluated. A constant dollar case
(0% inflation), and a 5% inflation case.
4.1 .9 Construction Escalation Rate
In this analysis, ~onstruction costs are assumed to escalate at the
same rate as the rate of general inflation.
4.1 .10 Fuel Escalation Rate
The fuel escalation rate is set to equal the general inflation rate
plus 2%.
4.2. METHOD OF COMPUTING THE ANNUAL COST OF POWER FROM INDIVIDUAL
GENERATING FACILITIES
During any year the electrical power production is computed thus:
* EPPR0 1.= (ICAP * PUFi * HPY)/ 1000
where:
ICAP = Installed capacity (MW)
PUF. =Plat utilization factor in year i (fraction)
1
HPY = Hours per year (8760 hours/year)
* Parameters with the subscript i are assumed to vary each year over the
lifetime of the plant. Parameters without the subscript are assumed to
be constant over the lifetime of the plant.
73
The total annual costs (TAC) are composed of two elements: variable costs
and fixed costs. In equation form:
TAC. = VARC. + FIXC. 1 1 1
where:
VARCi = Variable cos~s in year i ($/Year)
F!XC; = Fixed costs in year i ($/Year)
The variable costs consist only of the fuel costs.
VARC. = FUELC. 1 1
where:
FUELC; = Fuel costs in year i ($/Year).
In turn, fuel costs are computed:
~UELC; = HEATR * EPPROi * UFUELC;
where:
HEATR = Heat rate (Btu/kWh)
EPPROi = Electrical power production in year i (MMkWh)
UFUELC; = Unit fuel costs in year i ( $/MMB"tu)
The fixed costs consist of two factors. These factors can be writ-
ten in the following equation form:
FIXC; = INTAM + OMRC;
where:
INTAM = Interest and amortization (capital recovery) charges ($/Year)
OMRCi =Operations, maintenance and replacement costs in year i ($/Year).
The interest and amortization charges (INTAM) represent the annual debt
service payments.
74
INTAM = CRF * TINVC
where:
CRF = Capital Recovery Factor
TINVC = Total Investment Costs ($)
The capital recovery factor is used to compute a future series of equal
end-of-year payments that will just recover a present sum p over n periods ...
at compound interest (IR). It is computed thus:(l' P-26 )
· IR(l + IR)PBP CRF = -~-~~,.--
(1 + IR)PBP_l
where:
PBP = Payback period (years)
The methodology described in this section is incorporated into a
computer model called ECOST4.
4.3 METHOD OF COMPUTING AVERAGE SYSTEM POWER COST
Once the costs of producing power from the various individual gen-
erating facilities in a system are known, a method of comparing the total
cost of power from the three alternative system configurations evaluated
in this report is needed.
To compare the overall cost of power produced by these alternatives
a relatively straightforward method is used. The costs of producing and
transmitting power for each of the generation and transmission facilities
are added together for each year during the period 1978-2010. In equation
form:
TAC.
J
where:
n
= :E
i=l
AC .. · 1J
TAC. = total annual cost of power production for the system in
J
year j ( $)
75
AC .. =annual cost of prod~cing .. or .. t;ansmitting power for facility 1J
i during year j ($)
n =number of generation and transmiss.ion facilities in system.
Likewise the amount of power produced by each facility during each
year is summed to give a system-wide total.
where:
n
= L PPiJ.
i=l
TAPPj = total annual power production for the system in year j (kWhs)
PPij = power ·produced by each generating facility i during year j
( KWHs)
n = number of generating facilities in system
By dividing the total cost by the total generation an average cost of power
for the system is obtained for each year.
EPCOSTj
where:
EPCOSTj = average system-wide cost of power for year j ($/kWh)
By comparing the costs of power, the system producing the lowest cost of
power can be selected.
4.4 RESULiS OF SYSTEM CASH FLOW AND POWER COST CALCULATIONS
The results of the system cash flow and power cost calculations are pre-
sented in this section. As pointed out earlier in the report three cases were
evaluated:
Case 1. All additional generating capacity assumed to be coal-fired
steam turbines without a transmission interconnection between
the Anchorage-Cook Inlet area and the Fairbanks-Tanana
Valley load centers.
76
Case 2. All additional generating assumed to be coal-fired steam
turbines including a transmission ir.terco~nection.
Case 3. Additional capacity to include the Upper Susitna project
(including transmission interconnection) plus additional
coal as needed. Upper Susitna assumed to come on line in
1994.
Tables 4.1 through 4.36 present the.cash flow and power cost calculated
for the 3 cases. The contents of these tables are summarized below:
Table
Number
4.1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
Area
Anchorage
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
Fairbanks
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
"
Load Growth
Scenario
Low
II
II
II
II
II
Medium
II
II
"
II
High
"
"
"
"
"
Low
"
II
II
II
II
Medium
II
II
II
II
II
High
II
II
II
II
II
77
Case
1
II
2
II
3
II
1
II
2
II
3
II
II
2
II
3
II
II
2
"
3
II
1
II
2
II
3
II
II
2
II
3
II
Inflation
Rate (%)
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
5
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
Bo-37
87-88
83-$9
89-90
90-91
91-92
92-93
93-94
94-95
%-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-07
07-0S
08-09
09-10.
10-11
TABLE 4.1. Anchorage-Cook Inlet Area, Low Load Growth Scenario, Case 1, 0% Inflation
Total Cost
of Existing
Capacity
33.1
42.2
48.2
52.8
61.1
62.0
66.7
66.7
67.2
66.4
59.0
54.5
50.2
47.1
42.4
38.9
39.4
34.5
~0.3
25.4
27.4
22.6
12.2
11.0
4.8
4.0
3.6
3.6
3.6
3.6
3.6
3.6
3.6
!lew Coc11 Fired Capaclty _
Investment OM&R Coal
__fos ts_ Costs Costs
1.3
1.3
30.0
30.0
58.7
58.7
66.8
95.5
95.5
124.2
152.9
202.0
202.8
202.8
252.7
252.7
252.7
252.7
252.7
252.7
302.6
302.6
;302~6
302.6
302.6
302.6
0.2
0.2
5.9
5.9
11.6
11.6
13.~
18.9
18.9
3.1
3.3
3.3
3.6
3.7
6.7
9.6
16.6
22.5
26.6
34.5
41.9
24.6 50.7
30.3 56.9
40:1 64.1
40.1 69.1
40.1 74.1
49.9 80.4
49.9 83.8
49.9 86.9
49.9 90.4
49.9 93.3
49.9 96.6
59.7 9!!.6
59.7 102.7
59.7 105.8
59.7 108.9
59.7 112.1
59.7 115.4
New Hydroelectric
Costs
Investment OM&R
Costs_ Costs
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9 .
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
Transmission
Systems
Investment OM&R
Cos n__ Costs
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
17. I
17.1
17.1
17.1
17.1
17. 1
17:1
17.1
17.1
17.1
17.1
17. 1
3.3.5
33.5
33.5
33.5
33.5
33.5
33.5
33.5
33.5
33.5
33.5
33.5
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
3.6
3.6
3.6
3.6
3.6
3.6
3.6
3.6
3.6
3.6
3.6
3.6
6.8
6.3
6.0
6.8
6.8
6.8
6.8
6.8
6.11
6.8
6.3
6.0
Totaf
Investment
Costs
12.8
12.8.
58.0
58.0
86.7
86.7
94.8
123.5
123.5
152.2
100.9
230.8
230.8
230.3
297.1
297.1
297.1
297.1
297.1
297.1
347.0
347.0
347.0
347.0
347.0
347.0
Total
System
Costs, $
34.1
43.2
49.2
53.8
65.3
66.3
71.1
84.1
84.8
141.0
'136.6
173.4
175.0
185.7
223.3
227.2
270,9
306.6
't67.3
369.4
376.4
457.2
450.2
452.1
449.4
452.3
454.4
517.1
520.2
523.3
526.4
529.6
532.9
Total System
Consumption,
~1l1t:Wil
2376
25611
2706
2850
2991
3132
3273
3433
3594
3754
3915
4075
4285
4495
4705
4915
5125
5385
5645
5904
6164
6424
6<1!39
6555
6620
6686
6751
6017
6882
6948
7013
7079
7144
Average Power
Costs, ¢/KIIIl
1.4
1.7
1.8
1.9
2.2
2.1
2.2
2.4
2.3
3.7
3.5
4.2
4.1
4.1
4.7
4.6
5.3
5.7
6.5
6.3
li.1
7.1
6.9
6.9
6.U
6.8
6.7
7.6
7.5
7.5
7.5
7.5
7.5
70-79
79-00
80-01
81-02
82-03
IJJ-84
84-05
85-86
86-87
ll7-88
88-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
SB-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-07
07-08
Oll-09
09-10
10-11
TABLE 4.2. Anchorage-Cook Inlet Area. Low Load Growth Scenario. Case l, 5% Inflation
Totd 1 .Cost
of Existing
~~
29.7
39.1
45.7
47.9
59.5
63.6
60.7
68.9
69.8
67.1
60.6
56.4
52.5
49.0
47.4
46.5
48.5
43.8
36.3
37.7
37.5
31.7
16.7
15.3
5.4
5.5
3.6
3.7
3,.9
4.0
4.1
4.2
4.4
New Coal Fired Capacity__
Investment OH&R Coal
Costs f~~ Costs
2.0
2.0
46.6
46.6
95.7
95.7
111.1
l68.'rl
168.0
230.7
296.5
416.7
416.7
416.7
555.8
555.8
555.0
555.8
555.8
555.0
742.3
742.3
742.3
742.3
472.3
H2.3
0.4
0.4
9.2
9.7
19.9
20.9
24.8
37.4
39.2
51.6
67.3
94.3
99.0
103.9
136.4
143.3
150.4
157.9
165.8
174.1
219.4
230.4
241.9
254.0
266.7
280.1
3.1
3.3
3.3
3.6
3.9
7.3
11.1
20.1
28.6
3G.2
48.4
61.3
77.9
92.2
108.6
122.6
138.4
156.6
172.0
lll6. 5
204.8
221.6
240.4
259.8
280.8
303.6
321l.2
354.6
302.9
Nm~ llydroelectl'lc
Costs
Investment OM&R
_Costs_ Costs
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
'14.8
14.8
14.0
14.0
14.0
14.8
14.0
14.0
14.11
0.6
0.6
0.6
0.6
0.7
0.7
0.7
·o.8
0.8
0.9
0.9
0.9
1.0
1.0
1.1
1.1
1.2
1.3
1.3
1.4
1.5
1.5
1.6
1.7
1.0
1.9
Tt·ansml s s ion
__ _iy~tems Invcstme~nt~~o=M~&R
_f_Qs ts__ Costs
0. 7
o. 7
0.7
0. 7
0.7
0.7
0.7
0. 7
0.7
24.1
24.1
24.1
24.1
24.1
24.1
24.1
24.1
24.1
24.1
24.1
24.1
6!l. 3
60.3 .
60.3
60.3
68.3
60.3
68.3
68.3
68.3
60.3
60.3
60.3
0.4
0.4
0.4
0.5
0.5
0.5
0.5
0.5
0.5
5.4
5.7
6.0
6.3
6.6
6.9
7.3
7.7
8.1
8.5
8.0
9.3
Hl.4
19.3
20.3
21.3
22.4
23.5
24.6
25.9
27.2
20.5
30.0
31.5
Total
Investment
Costs
17.5
17.5
85.5
85.5
134.6
134.6
150.0
206.9
206.9
269.6
335.4
455.6
455.6
455.6
630.9
638.9
630.9
638.9
630.9
638.9
825.4
025.4
025.4
025.4
025.4
025.4
Total
System
Costs, $
30.0
40.1
46.8
49.1
63.9
68.1
73.3
90.8
92.7
175.2
173.2
237.8
243.6
267.2
347.8
362.0
456.2
547.7
704.2
724.8
•745. 7
903.1
991.3
1012.6
1029.6
1055.fi
1001.9
1334.4
1367.9
1403.7
1441.9
]402.7
1526.2
Total System
Consumption,
MMKWII
2376
2568
2706
2050
2991
3132
3273
3433
3594
3754
3915
4075
4285
4495
4705
4915
5125
5385
5645
5904
6164
6424
6498
6555
6620
6686
6751
6017
6082
6948
7013
7079
7144
Average Power
Costs, ~/KWH
1.3
1.6
1.7
1.7
2.1
2.2
2.2
2.6
2.6
4.7
4.4
5.8
5.7
5.9
7.4
7.4
8.9
10.2
12.5
12.3
12.1
15.3
15.3
15.4
15.5
15.8
16.0
19.6
19.9
20.2
20.6
20.9
21.4
00
0
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
86-87
87-88
88-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-07
07-08
08-09
09-10
10-ll
TABLE 4.3. Anchorage-Cook Inlet Area, Low Load Growth Scenario, Case 2, 0% Inflation
Total Cost
of Ex! sting
Capac! ty
33.1
42.2
48.2
52.8
61.1
62.0
66.7
66.7
67.2
66.4
59.0
54.5
50.2
47.1
-42.4
38.9
39.4
34.5
28.3
25.4
27.4
22.6
12.2
11.0
4.8
4.8
3.6
3.6
3.6
3.6
3.6
3.6
3.6
New Coal Fired Capacity
Investment OM&R coal
Costs Costs Costs _
1.3
1.3
30.0
30.0
58.7
58.7
66.8
95.5
95.5
95.5
124.2
152.9
202.8
202.8
202.5
252.7
252.7
525.7
252.7
252.7
525.7
252.7
2.52.7
252.7
252.7
252.7
0.2
0.2
5.9
5.9
11.6
11.6
13.2
18.9
18.9
3.1
3.3
3.3
3.6
3.7
6.7
9.6
16.6
22.5
26.6.
34.5
41.9
18.9 46.3
24.6 55.3
30.3 64.1
40.1 69.2
40.1 74.1
40.1 80.4
49.9 83.8
49.9 86.9
49.9 90.4
49.9' 93.4
49.9 96.6
49.9 99.6
49.9 99.6
49.9 105.7
49.9 108.9
49.9 112.1
49.9 115.4
New llydroe1ectr1c
Costs
Investment OH&R
~~-fQill.
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
Transmission
Systems
Investment OM&R
Costs Costs
0.6
0.6
0.6
0.6
0.6
0.6
·0.6
0.6
0.6
17.1
17.1
17.1
17.1
17 .]
17. 1
17:1
35.9
35.9
35.9
35.9
35.9
35.9
52.4
52.4
52.4
52.4
52.4
52.4
52.4
52.4
52.4
52.4
52.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
. 0.4
3.6
3.6
3.6
3.6
3.6
3.6
3.6
5.6
5.6
5.6
5.6
5.6 .
5.6
8.8
8.8
8.6
6.8
8.8
8.8
8.8
8.8
8.6
8.8
8.8
Total
Investment
Costs
12.8
12.8
58.0
58.0
86.7
86.7
94.8
123.5
123.5
142.3
171.0
199.7
249.6
249.6
249.6
316.0
316.0
316.0
316.0
316.0
316.0
316.0
316.0
316.0
316.0
316.0
Total
System
Costs, $
34.1
43.2
49.2
53.8
65.3
. 66.3
71.1
84.1
84.8
141.0
136.6
173.4
175.0
185.7
223.3
227.2
252.4
290.9
J27.9
389.8
396.7
397.9
470.6
472.5
469.8
472.8
474.8
477.8
460.9
484.0
487.1
490.3
493.6
Total System
Consumption,
MMKWH
2376
2568
2706
2850
2991
3132
3273
3433
3594
375~
3915
4075
4285
4495
4705
4915
5125
5365
5645
5904
6164.
6424
6489
6555
f620
6686
6751
6817
6882
6948
7013
7079
7144
Average Power
Costs, lt/KWII
1.4
1.7
1.8
1.9
2.2
2.1
2.2
2.4
2.3
3.7
3.5
4.2
4.1
4.1
4.7
4.6
4.9
5.4
5.8
6.6
6.4
6.2
7.2
7.2
7.1
7.1
7.0
7.0
7.0
7.0
6.9
6.9
6.9
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
86-87
87-88
SB-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
90-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-07
07-08
08-09
09-10
10-11
TABLE 4.4. Anchorage-Cook Inlet Area, Low Load Growth Scenario, Case 2, 5% Inflation
Total (:ost
of Existing
Capacity
29.7
39.1
45.7
47.9
59.5
63.6
68.7
68.9
69.6
6-7'.1
60.6
56.4
52.5
49.8
47.4
46.5
48.5
43.8
36.3
37.7
37.5
31.7
16.7
15.3
5.4
5.5
3.6
3.7
3.9
4.0
4.1
4.2
4.4
2.0
2.0
46.6
46.6
95.7
95.7
111.1
168.0
168.0
168.0
233.8
302.9
429.1
429.1
429.1
575.2
575.2
575.2
575.2
575.2
575.2
575.2
575,2
575.2
575.2
575.2
0.4
3. 1
3.3
3.3
3.6
0.4 ) r·
9.2 7.J
9. 7 11.1
19.9 20.1
20.9 28.6
24.8 35.2
37.4 48.4
39.2 61.3
39.3 71.2
54.4 89.5
70.0 108.6
99.1 122.6
104.1 130.4
109.3
143.4
150.6
]58. 1
166.1
174.4
183.1
192.2
201.8
211.9
222.5
233.7
156.6
172.0
106.4
204.9
221.6
240.4
259.8
21lO.fl
303.6
328.2
354.6
31l2.9
New llydroe1ectric
Costs
liivestmentoM&"R-
Costs Cos_h
14.8
14.8
14.8
14.0
14.8
14.8
14.8
14.8
14.0
14.8
14.8
14.8
14.8
14.8
]4.8
14.8
14.8
14.8
14.0
14.8
14.8
14.8
14.0
14.8
14.8
14.8
0.6
0.6
0.6
0.6
0.7
0.7
0.7
0.8
0.8
0.9
p.9
0.9
1.0
1.0
1.1
1.1
1.2
1.3
1.3
1.4
1. 5.
1.5
1.6
1.7
1.8
1.9
Transmfssfon
~IS
TriVestment -uW&R
Costs Costs
0.7
0.7
0.7
0. 7
o. 7
0.7
0.7
0.7
0.7
24.1
24.1
24.1
24.1
24.1
24.1
24.1
63.6
63.6
63.6
63.6
63.6
63.6
110.0
1]0.0
110.0
110.0
110.0
110.0
110.0
110.0
110.0
110.0
110.0
0.4
0.4
0.4
0.5
0.5
0.5
0.5
0.5
0.5
5.4
5.7
6.0
6.3
6.6
6.9
7.3
9.7
10.3
10.8
11.3
11.9
12.5
22.1
23.2
24.4
25.6
26.9
20.2
29.6
31.1
32.7
34.3
36.0
Total
Investment
Costs
17.5
17.5
05.5
85.5
134.6
134.6
150.0
206.9
206.9
246.4
312.2
381.3
507.5
507.5
507.5
700.0
700.0
700.0
700.0
700.0
700.0
700.0
700.0
700.0
700.0
700.0
Total
System
Costs, $
30.8
40.1
46.8
49.1
63.9
68.1
73.3
90.8
92.7
175.2
173.2
n1.8
243.6
267.2
347.8
362.0
416.0
511.1
608.7
779.2
800.4
818.7
1055.3
1076.7
1094.1
1120.1
1H6.7
1176.3
120B.O
1242.1
12711.6
1317.4
1358.9
Total System
C.onsumptlon,
MMK\.111
2376
2568
2706
2850
2991
3132
3273
3433
3594
3754
3915
4075
4285
4495
4705
491!!,
5125
5385
5645
5904.
6164.
. 6424
6489
6555
6620
6686
6751
CiB17
6882
6949
7013
7079
7144
Average Power
Costs, ¢/Kio.'~
1.3
1.6
1.7
1.7
2.1
2.2
2.2
2.6
2.6
4.7
4.4
5.8
5.7
5.9
7.4
7.4
8.1
9.5
10.8
13.2
13.0
12.7
16.3
16.4
16.5
16.7
17.0
1 ~.2
17.5
17.9
18.2
18.6
19.0
00
N'
TABLE 4.5. Anchorage-Cook Inlet Area, Low Load Growth Scenario, Case 3, 0% Inflation
Total Cost
of Existing
_!~ CapdCity
78-79
79-80
80-81
81-1!2
82-83
83-84
84-85
85-86
86-87
87-88
68-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
lliJ-01
Cl-02
02-03
03-04
0~-05
05-06
06-07
07-08
08-09
09-10
10-11
33.1
42.2
48.2
52.8
61.1
62.0
66.7
66.7
67.2
66.4
59.0
54.5
50.2
47.1
42.4
38.9
39.4
34.5
28.3
25.4
27.4
22.6
12.2
11.0
4.8
4.8
3.6
3.6
3.6
3.6
3.6
3.6
3.6
New Coal Fired Capacity ____
Investment OM&R Coal
Costs Costs Costs
1.3
1.3
30.0
30.0
58.7
58.7
66.8
66.8
95.5
95.5
95.5
95.5
,95.5
95.5
95.5
95.5
95.5
95.5
95.5
95.5
95.5
95.5
95.5
95.5
95.5
95.5
0.2
0.2
5.9
5.9
11.6
11.6
13.2
13.2
18.9
18.9
1H.9
18.9
1!1.9
18.9
18.9
10.9
18.9
18.9
18.9
18.9
18.9
16.9
18.9
18.9
18.9
18.9
3.1
3.3
3.3
3.6
3.7
6.7
9.6
16.6
22.5
26.6
30.3
38.9
20.6
21.6
27.9
32.2
26.4
7.9
8.0
8.1
9.3
10.6
12.0
13.2
14.6
16.0
17.4
18.9
20.4
New llydroe1ectric
Costs
Investment OM&R
Costs ~
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
155.9
155.9
155.9
155.9
155.9
204.2
204.2
204.2
204.2
204.2
204.2
204.2
204.2
204.2
204.2
204.2
204.2
0.4
0.4
0~4
0.4
0.4
0.4
0.4
0.4
0.4
1.0
1.0
1.0
1.0
1.0
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
Transmission
Systems
Investment OM&R
Costs Costs
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
17.1
17.1
17.1
17.1
35.9
35.9
35.9
35.9
35.9
35.9
35.9
35.9
35.9
• 35.9
35.9
35.9
35.9
35.9
35.9
35.9
35.9
35.9
35.9
35.9
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
3.6
3.6
3.6
3.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
Total
Investment
Costs
12.8
12.8
58.0
58.0
86.7
86.7
113.6
113.6
142.3
287.3
287.3
287.3
287.3
287.3
335.6
335.6
335.6
335.6
335.6
335.6
335.6
335.6
335.6
335.6
335.6
335.6
Total
System
Costs, $
34.1
43.2
49.2
53.8
65.3
66.3
71.1
84.1
84.8
141.0
136.6
173.4
175.0
206.0
205.0
244.5
372.3
368.4
368.5
369.9
376.1
391.7
381.4
380.3
375.3
376.6
376.8
370.0
379.4
380.8
382.2
383.7
385.2
Total System
Consumption,
MMKWH
2376
2568
2706
2850
2991
3132
3273
3433
3594
3754
3915
4075
4285
4t,95
4705
4915
5125
5385
5645
5904
6164
6424
6489
6555
6620
6686
6751
6817
68S2
6948
7013
7079
7144
Average Power
Costs, UKWII
1.4
1.7
1.8
1.9
2.2
2.1
2.2
2.4
2.3
3.7
3.5
4.2
4.1
4.6
4.4
5.0
7.3
6.8
6.5
6.3
6.1
6.1
5.9
5.6
5.7
5.6
:;.6
5.5
5.5
5.5
5.4
5.4
5.4
(X)
w
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
86-67
87-88
88-89
89-90
90-91
91-92
92-93
93--94
94-95
95-96
96-97
97-96
98-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-07
07-08
08-09
09-10
10-11
TABLE 4.6. Anchorage-Cook Inlet Area, Low Load Growth Scenario, Case 3, 5% Inflation
Total Cost
of £x1stfng
Capacity__
29.7
39.1
45.7
47.9
59.5
63.6
68.7
68.9
69.3
67.1
60.6
56.4
52.5
49.8
47.4
46.5
48.5
43.8
36.3
37.7
37.5
31.7
16.7
15.3
5.4
5.5
3.6
3.7
3.0
4.0
4.1
4.2
4.4
!lew Coal Fired Capacity
lnvestmer.t-OM&R Coar--
Costs Costs Costs
2.0
2.0
46.6
46.6
95.7
95.7
111.1
111.1
170.11
170.8
ll0.6
170.8
170.6
170.8
170.11
170.11
1/0.11
170.8
170.11
170.8
170.8
170.8
170.8
170.8
.170.8
170.8
0.4-
0.4
9.2
9.7
19.9
20.9
24.8
26.1
29.2
41.1
43.2
3.1
3.3
3.3
3.6
3.9
7.3
11.1
20.1
28.6
35.3
42.5
56.9
31.7
35.0
45.4 47.4
47.6 56.9
!;0.0 68.1
52.5 15.4
55.0 . 16.3
57.9 17.4
60.3 21.2
63.8 25.1
67.0 29.9
70.4 34.3
73.9 40.0
77.6 45.9
111.5 52.4
85.5 59.7
89.8 67.5
New llydroelectrlc
Costs
Tnves tment""OM&R-
Costs Costs
14.6
14.8
14.8
14.8
14.8
14.8
14.6
14.8
14.8
319.9
319.9
319.9
319.9
319.9
449.7
449.7
449.7
449.7
449.7
449.7
449.7
449.7
449.7
449.7
449.7
449.7
0.6
0.6
0.6
0.6
0.7
0. 7
0.7
·o.8
0.8
2.1
2.2
2.3
2.4
2.5
4.2
4.5
4.7
4.9
5.2
5.4
5.7
6.0
6.3
6.6
6.9
7.3
Transmission
Sys tcms
Investment ~
Costs _ Costs
0.7
D. 7
0.7
0. 7
0.7
0.7
0.7
0.7
0.7
24.1
24.1
24.1
24.1
58.2
58.2
50.2
58.2
50.2
58.2
51l.2
50.2
50.2
58.2
50.2
50.2
58.2
58.2
58.2
58.2
58.2
56.2
58.2
58.2
0.4
0.4
0.4
0.5
0.5
0.5
0.5
0.5
0.5
5.4
5.7
6.0
6.3
6.4
8.6
9.3
9. 7
10.2
10.7
11.3
11.8
-12.4
13.5
13.7
14.4
15.1
15.9
16.7
17.5
10.4
19.3
20.2
21.3
Total ·
Investment
Costs
17.5
17.5
85.5
85.5
134.6
134.6
184.1
164.1
243.8
548:9
548.9
540.9
548.9
540.9
676.7
6711.7
676.7
670.7
670.7
670.7
676.7
678.7
676.7
&78.7
678.7
678.7
Total
System
Costs, $
30.6
40.1
46.0
49.1
63.9
66.1
73.3
90.8
92.7
175.2
173.2
237.6
243.6
303.1
309.7
396.5
682.0
683.3
691 .0
704.8
718.8
794.9
764.0
707.7
785.4
793.4
800.5
809.5
620.0
830.9
642.6
855.2
869.0
Total System
Consumption,
MMKWII
2376
2566
2706
2850
2991
3132
3273
3433
3594
3754
39i 5
4075
4285
4495
4705
4915
5125
5385
5645
5904
6164
6424
5489
6555
6620
6606
6751
6016
6082
6948
7013
7079
7144
Average Power
Costs, ~/KWH
1.3
1.6
1.7
1.7
2.1
2.2
2.2
2.6
2.6
4.7
4.4
5.8
5.7
6.7
6.6
6.1
13.3
12.7
12.2
11.9
11.7
12.4
12.1
12.0
11.9
11.9
11.9
11.9
11.9
11.9
12.0
12.1
12.2
~
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
86-87
87-88·'
88-89
89-90
90-91
91-92
92-93
93-94
94-95
95-95
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-07
07-08
08-09
09-10
10-11
TABLE 4.7. Anchorage-Cook Inlet Area, Medium Load Growth Scenario, Case 1, 0% Inflation
Total Cost
of Existing
Capac tty
33.1
42.2
48.2
52.8
61.1
62.0
66.7
66.7
67.2
66.4
59.0
54.5
50.2
47.1
42.4
38.9
39.4
34.5
28.3
25.4
27.4
22.6
12.2
11.0
4.8
4.8
3.6
3.6
3.6
3.6
3.6
3.6
3.6
New Coal Fired Capacity
Investment ON&R Coal
Costs Costs Costs
28.7
28.7
28.7
58.7
58.7
87.4
87.4
116.1
116.1
152.9
202.8
202.8
202.8
252.7
302.6
352.5
353.5
402.4
402.4
402.4
452.3
452.3
452.3
502.2
502.2
502.2
502.2
502.2
552.1
5.7
5.7
5.7
11''.6
11.6
17.3
17.3
23.0
23.0
30.3
40.1
40.1
40.1
49.9
59.7
69.5
69.5
79.3
79.3
79.3
89.1
89.1
89.1
98.9
98.9
98.9
98.9
90.9
106.7
6.5
9.2
11.8
18.5
24.19
29.9
36.2
46.4
52.9
61.9
70.2
77.9
84.6
9·1 6
106.8
116.9
126.7
130.5
146.3 .
15·>. 3
162.5
170.7
179.4
188.0
196.8
205.9
215.1
22/o. 6
£34.2
New llydroe 1 ectrf c
Costs
Transmt sst on
Systems
Investment OM&R Investment OH&R
Costs fosts Costs Costs
10.9
10.9
10.9
10.9
10.9
10.9
10.9
]0.9
10.9
10.9
10.9
10.9
10.9
10.9'
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
.6 .4
.6
.6
.6
.6
.6
.6
.4 17.1
.. 4 17.1
0.4 17.1
0.4 17.1
,0.4 17.1
o.4 -·11.1
0.4 17.1
0.4 17.1
0.4 17.1
0.4 17.1
0.4 17.1
0.4 33.5
0'.4 33.5
0.4 33.5
0.4 33.5
0.4 33.5
0.4 33.5
0.4 33.5
0.4 33.5
0.4 -33.5
0.4 50.0
0.4 50.0
0.4 50.0
0.4 50.0
0.4 50.0
0.4 50.0
.4
.4
.4
.4
.4
.4
3.6
3.6
3.6 .
3.6
3.6
3.6
3.6
3.6
3.6
3.6
3.6
6.8
6.0
6.8
6.8
6.8
6.8
6.8
6.8
6.8
10.0
. 10.0
10.0
10.0
10.0
10.0
Total
Investment
Costs
29.3
29.3
29.3
86.7
86.7
115.4
115.4
144.1
144.1
100.9
I 230.8
230.8
230.3
200.7
347.0
396.9
396.9
446.3
446.0
446.8
496.7
496.7
496.7
563.1
5[.3. 1
56.~. 1
563.1
563.1
613.0
Total
System
Costs. $
34.1
43.2
49.2
53.8
103.0
106.6
114.0
187.6
193.7
233.0
231.9
272.0
274.2
324.2
387.5
391.7
390.9
463.7
549.0
615.9
627.7
694.4
691.8
698.6
760.3
767.9
776.0
864.0
872.8
081.9
!J91.1
969.9
Total System
Consumption.
HMKUH
2531
2801
3041
3281
3521
3761
4001
4329
4657
4985
5313
5641
6063
6485
6907
7329
7751
8311
0871
9431
9991
10551
10063
; 1175
11437
11799
12111
12423
12735
13047
13359
13671
13983
Average !'ower
Costs, ¢/KWH
1.3
1.5
1.6
1.6
2.9
2.8
2.8
4.3
4.2
4.7
4.4
4.8
4.5
5.0
5.6.
5.3
5.1
5.6
6.2
6.5
6.3
6.6
6.4
6.3
6.6
6.5
6.4
6.9
6.8
6.8
6.7
6.6
6.9
())
U1
~
78-79
79-80
80-81
81-62
82-83
83-84
84-85
85-86
86-87
87-88
88-89
89-90
9!1-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2COO
00-01
01-02
02-0J
03-04
04-05
05-06
06-07
07-08
08-09
09-10
I 0-11
TABLE 4.8. Anch~rage-Cook Inlet Area, Medium Load Growth Scenario, Case 1, 5% Inflation
Total Cost
of Exlstlng
~ac~_IL_
29:7
39.1
45.7
47.9
59.5
63.6
68.7
68.9
69.8
67.1
60.6
56.4
52.5
49.8
47.4
46.5
48.5
43.8
36.3
37.7
37.5
31.8
16.7
15.3
5.4
5.5
3.6
3.7
3.9
4.0
4.1
4.2
4.4
New Coal Fly_!~ _ _f_apac~J;L_
Investment OM&R oal
Costs ~ill Costs
34.9
34.9
34.9
77.3
77.3
121.9
121.9
171.0
171.0
240.6
339.5
339.5
339.5
454.0
574.2
700.4
700.4
839.5
839.5
839.5
1000.6
1000.6
1000.6
1187.1
1187.1
11117.1
1187.1
1107.1
1425.1
6.9
J.2
7.6
16.4
17.2
26.8
28.2
39.3
4].3
56.9
79.2
83.2
87.3
114.2
143.5
175.5
184.2
220.8
231.6
243.4
287.2
301.5
316.6
369.0
387.5
406.8
427.2
440.5
517.7
6.5
9.2
11.8
18. 1
25.3
32.7
41.6
56.3
67.3
82.2
98.6
113.9
130.1
153.3
WO. 8
207.2
236.7
269.7
300.2
331.2
368.3
405.2
446.6
490.4
5311.4
590.9
648. 1
710.1
777.3
New Hydroelectric
Costs
Transml ss !on
Systems
Investment OH&R
_ _fosts _ Costs
Investment 0~
~t.L_ Costs
14.8
14.0
14.8
14.8
14.6
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.0
14.8
14.8
14.0
14.0
0.7 0.4
0.7 0.4
0.7 0.4
0.7 0.5
0. 7 0.5
0.7 0.5
0. 7 0.5
0.6 • 23.0 4.9
5.1
5.4
5.7
6.0
6.3
6.6
6.9
7.2
7.6
8.0
0.6 23.0
0.6 23.0
0.6 23.0
0.7 23.0
0.7 23.0
0.7
0.0
0.3
0.9
0.9
0.9
1.0
1.0
1.1
1.1
1.2
1.3
1.3
1.4
1.5
1.5
1.6
1.7
1.0
1.9
23.0.
23.0
23.0
23.0
23.0
63.0
63.0
63.0
63.0
63.0
63.0
63.0
63.0
63.0
116.7
116.7
116.7
116.7
116.7
116.7
16.0
16.6
17.4
18.3
19.2
20.2
21.2
22.2
23.3
34.9
36.6
30.5
40.4
42.4
44.6
Total
Investment
Costs
35.6
35.6
35.6
115.1
115.1
159.7
159.7
208.8
208.8
278.4
377.3
377.3
377.3
491.8
652.0
770.2
778.2
917.3
917.3
917.3
1078.4
1070.4
10711.4
1319.6
1310.6
1318.6
1310.6
1318.6
1556.6
Total
System
Costs, $
30.8
40.2
46.8
49.1
109.1
116.1
124.3
. 224.0
233.2
292,3
296.5
367.5
376.9
474.6
600.6
628.9
659.3
812.0
1029.5
1216.2
1255.0
1459.0
1406.3
1528.6
1761.0
1014.1
1069.9
2210.1
2286.5
2360.4
2440.1
2525.6
2902.5
Total System
Consumpt1on,
fo'J~KWH
2531
2801
3041
3281
3521
3761
4001
4329
4657
4985.
5313
5641
6063
6485
6907
7329
7751
8311
0871
9431
9991
10551
10863
11175
1H87
11799
12111
12423
12735
13047
13359
13671
13983
Average Power
Costs, UKWil
1.2
1.4
1.-5
1.5
3.1
3.1
3.1
5.2
5.0
5.9
5.6
6.5
6.2
7.3
8.8
8.6
8.5
9.7
11.6
12.9
12.6
13.8
13.7
13.7
15.3
15.4
15.4
17.8
. 17.9
10.1
10.3
10.5
20.7
ro m
TABLE 4.9. Anchorage-Cook Inlet Area, Medium Load Growth Scenario, Case 2, 0% Inflation
Total Cost
of Existing
~ Capacity
78-79 33.1
7!1-80
80-81
81-82
82-113
83-84
1:14-85
85-86
86-87
87-88
llB-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-0~
04-05
05-06
06-07
07-08
08-09
09-10
10-11
42.2
48.l
52.8
61.1
62.0
66.7
66.7
67.2
66.4
59.0
54.5
50.2
47.1
42.4
38.9
39.4
34.5
28.3
25.4
27.4
22.6
12.2
11.0
4.8
3.6
3.6
3.6
3.6
3.6
3.6
3.6
3.6
·!lew Coal Fired Capactt/
Investment OH&R Coal
Costs ~ Costs
28.7
28.7
28.7
58.7
58.7
87.4
87.4
87.4
116.1
152.9
202.8
202.8
202.8
252.7
302.6
302.6
352.5
352.5
402.4
402.4
402.4
452.3
452.3
452.3
452.3
5G2.2
502.2
502.2
W?..Z
5,7
5.7
5.7
11;6
11.6
17.3
17.3
17.3
24.6
31.9
41.7
41.7
41.7
51.5
61.3
61.3
71.1
71.1
80.9
00.9
00.9
90.7
90.7
90.7
90.7
100.5
100.5
100.5
100.5
6.5
9.2
11.8
18.5
24.19
29.9
36.2
42.5
50.1
59.1
70.2
77.9
84.6
94.6
106.0
1]6.9
126.7
130.5
146.3
154.3
162.5
170.7
179.4
1ll0.0
196.0
205.9
215. I
224.6
234.2
'New Hydroelectric
Costs
Investment OM&R
Costs Costs
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10,!)
10.9
10.9
10.9
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0,4
0.4
0.4
0.4
C.4
0.4
Transmission
Systems
Investment OM&R
Costs Costs
0.6 0.4
0.6
0.6
0.6
0.6
0.6
0.6
17.1
17.1
17.1
17.1
35.9
35.9
35.9
35.~
35.9
35.9
35.9
52.4
52.4
52.4
52.4
52.4
52.4
52.4
52.4
52.4
52.4
52.4
Gll.9
Cf!.9
Cfi.9
6[1,9
0.4
0.4
0.4
0.4
0.4
0.4
3.6
3.6
3.6
3.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
!1.0
8.0
0.0
0.3
B.B
B.B
'0.0
ll.l!
0.3
IJ.8
6.6
12.0
i2.0
12.0
12.0
Total
Investment
Costs
29.3
29.3
29.3
IJ6.7
06.7
115.4
115.4
134.2
162.9
199.7
249.6
249.6
249.6
299.5
365.9
36!i.9
415.0
415.()
4G5.7
465.7
465.7
515.6
515.()
515.6
515.6
5[!2.0
582.0
E(]2.0
5P.2~G
Total
System
Costs, $
34.1
43.2
49.2
53..8
103.0
106.6
114.0
187.6
193.7
233.0
231.9
254.5
293.8
343.8
409.9
414.1
421.3
406.1
571.5
578.7
650.2
657.2
714.3 '
721.1
723.1
709.0
793.5
P-07. 1
£15.9
904.4
913.6
923,1.
~!32. 7
Total System
Consumption,
fV~KWII
2531
2801
3041
3281
3521
3761
4001
4329
4657
4985
5313
5641
6063
6485
6907
7329
7751
8311
8871
9431
9991
10551
10063
11175
11437
11799
12111
12423
12735
130·17
13359
13E71
13~133
Average Power
Costs, ¢/ KWII
1.3
1.5
1.6
1.6
2.9
2.8
. 2.8
4.3
4.2
4.7
4.4
4.5
4.!1
5.3
5.9
5.6
5.4
5.!1
6.4
6.1
6.5
6.2
6.6
6.4
6.3
6.7
6.6
6.5
6.4
6.9
6.8
G.1
6.7
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-B,6
86-87
87-ll3
!ltl-89
89-90
90-91
91-92
92-93
93-94
Y4-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-0J
03-04
04-05 .
05-06
06-07
07-08
08-09
09~10
10-11
J~BL~4.10. Anchorage-Cook Inlet Area, Medium Load Growth Scenario, Case 2, 5% Inflation
Total Cost
of fxlstlng
Capacity
29.7
39.1
45.7
47.9
59.5
63.6
68.7
68.9
69.8
67.1
60.6
56.4
52.5
49.8
47.4
46.5
48.5
43.8
36.5
37.7
37.5
31.7
16.7
15.3
5.4
5.5
3.6
3. 7
3.9
4.0
4.1
4.2
4.4
Nr.w Coa 1 Fh·ed Capac! ty_
Inves tniei\t1JF1&R Coal-
Co5 ts Costs Costs
34.9
34.9.
34.9
77.3
77.3
121.9
121.9
121.9
173.6
243.1
342.0
342.0
342.0
465.5
576.7
576.7
709.2
709.2
855.3
855.3
955.3
1024.4
1024.4
1024.4
1024.4
1230.0
1230.0
1230.0
1230.0
6.9
7.2
7.6
]6.4
17.2
26.8
28.2
29.6
41.3
56.9
79.2
83.2
87.3
114.2
143.5
150.6
184.2
193.4
231.7
243.3
225.5
301.5
316.6
332.4
3•19.0
406.13
427.1
44fJ.4
470.8
6.5
9.2
11.8
18.1
25.3
32.7
41.6
51.5
63.7
70.3
90.5
113.3
130.1
153.3
180.8
207.1
236.6
. 269.7
300.2
331.2
368.3
405.2
446.6
490.4
538.4
590.9
643. I
710.1
777.3
New Jiydroelectrlc
Costs
lnvestmentom.~-
Costs Costs
14.3
14.8
14.8
14.8
14.8
14.8
14.8
.14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.0
1-Ul
14.0
0.6
0.6
0.6
0.6
0. 7
0. 7
0. 7
0.0
0.6
0.9
0.9
0.9
1.0
1.0
1.1
1.1
1. 2
1.3
1.3
1.4
1.5
1.5
1,6
1.7
1.8
1.9
Transmf ss ion
Systems
I nves tmen t OM&l<
Costs Costs
. 0. 7
0.7
0.7
0.7
0. 7
0.7
0.7
23.0
23.0
23.0
23.0
53.9
53.9
53.9
53.9
53.9
53.9
53.9
93.9
93.9
93.9
93.9
93.9
93.9
93.9
93.9
93.9
93.9
93.9
148.9
HfJ. 9
140.9
140.9
0.4
0.4
0.4
0.5
0.5
0.5
0.5
4.9
5.1
5.4
5.7
9.3
9.7
10.2
10.7
11.3
11.8
12.4
20.9
21.9
23.0
24.2
25.4
26.7
28.0
29.4
30.9
32.4
34.0
46.7
49.0
51.5
54.1
Total
Investment
_.£Q.m.__:___
35.6
35.6
35.6
115.1
115.1
159.7
159.7
190.6
242.2
311.8
410.7
410.7
410.7
534.2
685.4
6!l5.4
817.9
017.9
964.0
964.0
964.0
1133.1
1133.1
1133.1
1133.1
1393.7
1393.7
1393.7
1393.7
Total
System
Costs, $
30.8
40.2
46.8
49.1
109.1
116.1
124'.3
224.0
233.2
292.3
296.5
330.1
410.1
507.0
647.4
666.4
689.3
850.8
1067.8
1103.0
1300.3
1338.1
1539.1
1581.7
1592.5
1876.0
1932.2
'1993.5
2059.9
2443.7
2523.7
2609.7
2702.2
Total System
Consumption,
MMKWII
2531
2801
3041
3281
3521
3761
4001
4329
4657
4985'
5313
!;641
6063
6405
6907
7329
7751
8311
8871
9431
9991
10551
10063
11175
11487
11799
12111
12423
12735
13047
13359
13671
13983
Average Power
Costs, ~I KWII_
1.2
1.~
1:5
1.5
3.1
3.1
3.1
5.2
5.0
5.9
5.6
6.0
6.8
7.0
9.4
9. I
8.9
10.3
12.0
11.7
13.0
12.7
14.2
14.1.
13.9
15.9
15.9
16.0
16.2
18.7
18.9
19.1
19.3
co co
Year
73-79
79-80
il0-81
81-82
82-83
83-84
84-85
85-86
!16-87
87-88
U8-89
89-90
90-91
91-92
92-93
93-94
~4-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-07
07-08
Otl-09
09-10
10-11
TABLE 4.11. Anchorage-Cook Inlet Area, Medium Load Growth Scenario, Case 3, 0% Inflation
Total cost
of Existing
Capacity
33.1
42.2
78.2
52.8
61.1
62.0
66.6
66.7
67.1
66.3
59.0
54.5
50.2
47.1
42.4
38.9
39.4
31.5
28.3
25.4
27.4
22.6
12.2
11.0
4.8.
4.8
3.6
3.6
3.6
3.6
3.6
3.6
3.6
New Coa 1 Fired Capaclil__
Investment OM&R Coal
Costs_ Costs Costs
2!1.7
20.7
28.7
50.7
50.7
87.4
87.4
87.4
116.1
152.9
202.8
202.8
202.8
202.8
202.0
202.8
202.8
202.8
202.8
202.8
252.7
252.7
252.7
252.7
302.6
302.6
302.6
302.6
352.5
5.7
5.7
5.7
11.6
ll.6
17.3
17.3
17.3
24.6
31.9
41.7
41.7
41.7
41.7
41.7
41.7
41.7
41.7
41.7
41.7
51.5
51.5
51.5
51.5
61.3
61.3
61.3
61.3
71.1
6.5
9.2
11.8
18.4
24. I
30.1
36.2
42.5
50.1
59.1
70.2
77.9
53.3
5!1.6
69.9
79.1
54.5
60.2
66.8
73. 1
80.0
86.5
93.4
100.2
107.3
114.5
121.9
129.6
137.5
Nc1~ llydroe 1 ectric
Costs
Investment OH&R
Costs Costs
1.0
1.0
1.0
1.0
1.0
1.0
20.7
20.7
20.7
20.7
10.9
10.9
10.9
10.9
10.9
10.9
157.7
157.7
157.7
157.7
206.6
206.6
206.6
206.6
206.6
206.6
206.6
206.6
206.6
206.6
206.6
206.6
206.6
0.4
0.4
0.4
0.4
0.4
0.4
1.1
1.1
1.1
1.1
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
Ul
Transmission
___2ystems
I nves tme=n'7't =-,O"'M""&R.-
Costs Costs
17.1
35.9
35.9
35.9
35.9
35.9
35.9
35.9
35.9
35.9
35.9
35.9
35.9
35.9
52.4
52.4
52.4
52.4
52.4
52.4
52.4
52.4
52.4
3.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
8.8
8.8
a.o
8.8
8.8
8.8
8.8
8.8
&.8
Total
Investment
Costs
29.3
29.3
29.3
86.7
86.7
115.L;
1 I 5.4
134.2
162.9
199.7
249.6
249.6
396.4
396.4
396.4
396.4
445.3
445.3
445.3
445.3
511.7
5"11.7
511.7
511.7
561.6
561.6
561 .6
561.6
611.5
Total
System
Costs, S
34.1
43.2
49.2
53.8
103.0
106.6
114.0
187.6
193.7
233.0
231.9
254.5
293.8
343.8
409.9
414.1
537.5
537.9
543.0
549.3
576.3
577.2
573.4
578.5·
658.6
665.1
670.3
677.6
744.4
751.6
759.0
7E6.7
834.3
Total System
Consumpt1on,
M11KI-IIl
2531
2801
3041
3281
3521
3761
4001
4329
4657
4985
5313
5641
6063
6485
6907
7329
7751
8311
8871
9431
9991
10,551
10,863
11,175
11,487
11,799
12,111
12,423
12.735
13,047
13,359
13,671
1:!,983
Average Power
Costs, t/KIIH
4.4
4.5
4.8
5.3
5.9
5.6
6.9
6.5
6.1
5.8
5.8
5.5
5.3
5.2
5.7
5.6
5.5
5.4
5.8
5.8
5.7
5.6
5.9
78-79
79-80
80-81
81-82
82-ll3
63-ll4
tl4-85
8~-d6
ll6-87
ll7-ll8
88-89
89-90
90-91
91-92
92-93 •
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-0l
01-02
02-03
03-04
M-05
05-06
06-07
07-08
08-09
09-10
lO-ll
TABLE 4.12. Anchorage-Cook Inlet Area, Medium Load Grow~h Scenario, Case 3, 5% Inflation
Total Cost
of Existing
Capacl ty
29.7
39.1
45.7
47.9
59.5
63.6
68.7
6d.9
69.8
67.1
60.6
56.4
52.5
49.8
47.4
46.5
48.5
43.8
36.3
37.7
37.5
31.7
16.7
15.3
5.4
5.5
3.6
3.7
3.9
4.0
4.1
4.2
4.4
...
New Coal Fired Capacity
TiiVes tment0t1&R Coa 1
Costs ~ Cos~_s_
34.9
34.9
34.9
77.3
77.3
121.9
121.9
121.9
173.5
243.1
342.0
342.0
342.0
342.0
342.0
342.0
342.0
342.0
342.0
342.0
503.1
503.1
503.1
503.1
698.9
698.9
69Ll.9
698.9
936.9
6.9
7.2
7.6
16.4
17.2
26.8
28.2
29.6
41.3
56.9
79.2
83.2
tl7 .4
91.7
96.3
101.1
106.2
111.5
117.1
122.9
160.7
l6Ll.7
177 .I
165.9
233.7
245.4
257.6
270.5
330.7
6.5
9.2
11.8
18.1
25.3
32.7
41.6
51.5
63.7
78.3
98.5
ll3.il
82.1
94.9
l Hl.3
140.2
101.8
117.2
137. l
156.8
181.4
205.3
232.5
261.4
293.5
326.7
367.5
40~.9
456.3
Ne1~ ftydroe 1 ect rl c
Costs
Investment Ot1&R
~!..L_ Costs
14.3
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
323.7
323.7
323.7
323.7
448.8
441l.8
448.8
446.8
441l.8
446.8
448.8
448.8
448.6
446.8
440.6
44fl.O
440.6
0.6
0.6
0.6
0.6
0.7
0.7
0.7
0.8
0.8
2.4
2.5
2.7
2.8
4.4
4.6
4.9
5.1
5.4
5.6
5.9
6.2
6.5
6.8
7.2
7.5
7.9
Transml ss Jon
Systems
Investment OM&~
Costs Costs
0.7
0.7
0.7
0.7
0.7
0.7
0.7
23.0
23.0
23.0
23.0
53.9
53.9
53.9
53.9
53:9
53.9
53.9
53.9
53.9
53.9
53.9
53.9
53.9
104.9
104.9
104.9
104.9
104.9
104.9
104.9
104.9
104.9
0.4
0.4
0.4
0.5
0.5
0.5
0.5
4.9
5.1
5.4
5.7
9.3
9.7
10.2
10.7
11.3
11.8
12.4
13.0
13.7
14.3
15.1
15.(1
16.6
26.9
26.2
29.6
31.1
32.7
34.3
36.0
37.8
39.7
Total
Investment
Costs
35.6
35.6
35.6
115.1
115.1
159.7 -
159.7
190.6
242.2
311.8
410.7
410.7
119.6
719.6
719.6
719.6
644.7
844.7
644.7
644.7
1056.6
1056.8
1056.6
1056.8
1252.6
1252.6
1252.6
1252.6
1490.6
Total
System
Costs, $
30.8
40.2
46.8
49.1
109.1
116.1
124.3
224.0
233.2
292.3
296.5
336.1
410.1
507.6
647.4
666.4
951.8
964.9
986.2
1015.1
1109.0
1124.6
1136.3
1161.4
1436.6
1470.1
1505.5
1545.1
1822.9
1671.8
1925.0
1982.2
2329.6
Total System
Consumption,
MHKWH
2531
2601
3041
3281
3521
3761
4001
4329
4657
4985
5313
5641
6063
6465
6907
7329
7751
0311
8871
9431
9991
10,551
10,863
11,175
11 ,487
11,799
12 ,Ill
12,423
12,735
13,047
13,359
13,671
13,963
Average Power
Costs,~
1.2
1.4
1.5
1.5
3.1
3.1
3.1
5.2
5.0
5.9
5.6
6.0
6.8
7.6
9.4
9.1
12_3
11.6
11.1
10.8
11.1
10.7
10.5
10.4
12.5
12.4
12.4
12.4
14.3
14.3
14.4
14.5
16.7
Year
76-79
79-60
60-61
IH-62
62-83
83-84
84-85
85-86
86-87
87-88
88-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
05-07
07-08
08-09
09-10
10-11
TABLE 4.13. Anchorage-Cook Inlet Area, J-ligh Load Growth Scenario, Case 1, 0% Inflation
Total Cost
of Existing
Capacity
33.1
42.2
48.2
52.6
61.1
62.0
66.7
66.7
67.2
66.4
59.0
54.5
50.2
47.1
42.4
38.9
39.4
34.5
28.3
25.4
27.4
22.6
12.2
11.0
4.8
4.8
3.6
3.6
3.6
3.6
3.6
3.6
3.6
•
New Coal Fired Capac.t9L ___
Investment ~&R Coar--
Costs Costs Cosli.__
57.4
86.1
114.8
144.8
164.7
164.7
214.6
214.6
214.6
272.6
322.5
322.5
372.4
422.3
472.2
522.1
572.0
621.9
671.8
671.8
721.7
771.6
771.6
821.5
871 ~4~·
871.4
921.3
971.2
971.2
11.4
17.1
22.8
28.7
38.5
38.5
48.3
48.3
40.3
9.8
18.6
29.9
44.8
66.2
73.4
81.2
88.6
98.5
59.7 109.9
69.5 120.1
69.5 132.6
7!1.3
89.1
98.9
108.7
118.5
128.3
138.1
138.1
147.9
157.7
157.7
167.5
177.3
177.3
187.1
196.9
195.9
143.9
161.3
181.5
200.1
217.9
238.7
256.6
275.8
294.6
314.7
335.6
356.9
378.8
401.2
424.2
447.0
472.0
New Hydroelectric
Costs
Investment OM&R
Costs. Costs
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
19.9
10.9
10.9
10.9
10.9
10.9
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.~
0.4
0.4
0.4
0.4
0.4
0.4
0.4
Transmi ss. f on
__jys.tems
TriVeSlinerifOH&lf'
Costs Costs
0.6
0.6
0.6
0.6
17.1
17.1
17.1
17.1
17. 1
17.1
33.6
33.6
33.6
33.6
33.6
33.6
33.6
50.1
50.1
50.1
50.1
66.6
66.6
66.6
66.6
66.6
66.6
83.1
83.1
83.1
83.1
63.1
83.1
0.4
0.4
0.4
0.4
3.6
3.6
3.6
3.6
3.6
3.6
6.0
6.8
6.8
6.8
6.8
6.0
6.6
10.0
10.0
10.0
10.0
13.2
13.2
13.2
13.2
13.2
13.2
16.4
16.4
16.4
16.4
16.4
16.4
Total
Investment
Costs
74.5
103.2
131.9
142.8
192.7
192.7
259.1
259.1
259.1
317.1
367.0
367.Q
416.9
483.3
533.2
583.1
633.0
699.4
749.3
749.3
799.2
. 849.1
849.1
.915.5
965.4
965.4
_1015.3
1065.2
1065.2
Total
System
Costs, $
34.1
43.2
49.2
53.6
160.5
204.5
254.9
317.0
368.6
375.0
454.8
457.7
463.3
541.0
606.2
615.2
636.7
770.6
852.3
927.7
1008.2
1102.6
1169.8
1187.8
1260.1
1339.9
1359.6
1460.3
1541.9
1564.3
1647.0
1730.3
1754.5
Total System
Consumption,
MMKWH
2680
3025
3688
4352
5015
5679
6342
6849
7357
786~
8372
8879
9509
10,298
11,008
11,717
12,427
13,477
14,526
15,576
16,625
17,675
18,584
19,493
20,402
21.311
22,220
23,129
24,030
24,947
25,1l56
26.765
27,674
Average Power
Costs, t/KIJH
1.3
1.4
1.3
1.2
3.2
3.6
4.0
4.6
5.0
4.8
5.4
5.1
4.8
5.2
5.5
5.3
5.5
5.8
5.9
6.0
6.1
6.2
6.3
6.1
6.2
6.3
6.1
6.3
6.4
6.3
6.4
6.5
6.3
TABLE 4.14. Anchorage-Cook Inlet Area, H·igh Load Growth Scenario, Case 1, 5% Inflation
Total Cost
of Exfsting
_rm_ ~!U!L
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
86-87
87-88
36-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-07
07-08
OIJ-09
09-10
10-11
29.7
39.1
45.7
47.9
59.5
63.6
68.7
68.9
69.8
67.1
60.6
5604
5205
49.6
4704
46.5
4805
43.8
36.3
37.7
37.5
31.7
16.7
15.3
5.4
5.5
3.6
3.7
3.9
4.0
4.1
4.2
4.4
New Coa1·ffred Capac_~
Investment OM&R Coal -
Costs Costs Cos~-
69.6
10604
144.9
187.3
261.1
261.1
342.5
342.5
342.5
452.1
551.0
551.0
660.0
774.5
894.7 •
1020.9
1153.4
Wi2.6
1438.7
143007
1599.0
1769.0
1769.0
1955.5
2151.3
2151.3
2367.2
2593.9
2593.9
l3o8 909
2108 18.6
30.5 29o9
38.9. 44.8
49.2 • 69.4
51.7 80.5
70.2 93o4
73.7 107.4
77.4
102o6
127.2
133.5
161.6
19202
225o4
261.5
300.5
342.6
300o7
40tl. 1
46001
516.3
542.?.
605o9
674o6
700.3
7fl6o1
869o9
91304
125.4
145o9
16805
193o8
221.3
261.2
307.4
354 0 5
407 01
464.8
526.5
592.6
667 0 5
746o8
835.5
930.8
1035o9
1151.5
1278.1
141603
1566.6
New Hydroe1ectrfc
Costs
lnvestment OB£R
Costs ~
14.8
14.8
14.8
14.8
14.8
1400
1408
14.8
14.8
1408
14.8
1408
1408
14.8
14.0
14.6
l4o8
14.8
14.8
14.8
14.8
14.8
1408
14.8
14.8
1408
0.6
0.6
0.6
0_,6
0.7
0.7
0.7
0.8
0.8
Oo9
0.9
0.9
1.0
1.0
1.1
1.1
1.2
1.3
1.3
1.4
1.5
1.5
1.6
1.7
1.0
1.9
Transmission
Systems
Investment OM&R
_fill_s _ Costs
0.7
0.7
Oo7
Oo7
21.0
21.0
21.0
21.0
21.0
21.0
48.1
48.1
48.1
48.1
48 .. 1
48.1
48.1
67.1
87.1
87.1
67.1
131.3
131.3
131.3
131.3
131.3
131.3
184o3
184.3
184.3
164.3
184.3
184.3
004
0.4
0.4.
0.5
4.4
4o6
4o9
5.1
5.4
5.6
11.2
11.7
12.3
12.9
13.6
14.3
l5o0
22.7
23.9
25.1
26.3
36o2
37.9
3909
41.9
43.9
4601
58.4
61.3
Mo4
67o6
70.9
74.5
Total
Investment
Costs
9008
127.4
165.9
223.1
296.9
296.9
405o4
405.4
40504
515o0
613.9
613.9
722.9
876.4
996.6
1122.11
1255.3
l43llo7
15!i4o0
1513406.
1745.9
1915.1
1915.1
2154.6
2350o4
2350.4
2566.3
2793.0
2793o0
Total
System
Costs, ~
30.8
40.2.
46.8
49.1
178.4
236o0
299.9
381.4
491.3
502.4
641.4
655.3
673.7
826.9
971.4
1002.8
1)7002
1397.2
1590.5
180206
. 2027.7
2315.3
2555.7
2641o!l
2922.1
3220.9
3343.9
3754.9
4127.6
428002
47030 9
5156.1
5353.8
Total System
Consumption,
MMI:WH
2680
3025
3688
435i
5015
5679
6342
6849
7356
7664
8372
8tl70
9589
10,2980
11,008
11,717
12,427
13,477
14,526
15,576
16,625
17,675
18,504
19,493
20,402
21,311
22,220
23,129
24,038
24,947
25,856
26,765
27,674
Average Power
Costs, UKWH
1.1
1.3
1.3
1.1
3.6
4.2
407
5.6
6.7
6.4
707
7.4
7.0
8.0
808
806
904
10.4
1009
11.6
12.2
13.1
13o0
13.6
14.3
15.1
1500
16.2
1702
17 02
11lo2
19.3
19.3
lO
N
TABLE 4.15. Anchorage:Cook Inlet Area, High Load Growth Scenario, Case 2, 0% Inflation
Total Cost
of Existing
~ Capacity
78-79
79-80
80-81
61-82
82-83
83-84
84-85
85-86
86-87
87-88
88-89
B9-9ll
90-91
91-92
92-93
93-9-1
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-0/
07-08
08-09
09-10
10-11
33.1
42.2
48.2
52.8
61.1
62.0
66.7
66.7
67.2
66.4
59.0
54.5
50.2
47.1
42.4
38.9
39.4
34.5
28.3
25.4
27.4
22.6
12.2
11.0
4.0
4.8
3.6
3.6
•. 6
3.6
3.6
3.6
3.6
New Coal Fired Capacity
Investment OM&R Coal
Costs ~ Costs
57.4
86.1
114.8
144.8
144.8
194.7
194.7
244.6
244.6
302.6
302.6
352.5
352.5
402.4
452.3
502.2
552.1
602.0
651.9
701.8
751.7
751.7
751.7
001.6
051.5
901.4
901.4
951.3
1001.2
11.4
17.1
22.8
26.7
26.7
33.5
9.8
18.6
29.9
44.8
58.7
73.4
38.5 81.2
48.3 88.6
48.3 98.5
59.7 109.9
59.7 120.1
69.5
69.7
79.3
89.1
98.9
108.7
118.5
128.3
138.1
147.9
147.9
147.9
157.7
167.5.
177.3
177.3
187. I
1!?5.9
132.6
143.9
161.3
181.5
200.1
217.9
238.7
256.5
275.8
294.6
314.7
335.6
356.9
378.8
401.2
424.2
447.8
472.0
New Hydroelectric
Costs
Investment OM&R
Costs Costs
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.,4
0.4
0.4
0.4
0.4
0.4
0.4
Transmission
Systems
Investment OM&R
Costs Costs
0.6
0.6
0.6
0.6
17.1
17.1
17.1
17.1
35.9
35.9
35.9
52.4
52.4
52.4
52.4.
52.4
52.4
52.4
60.9
68.9
68.9
60.9
85.4
85.4
85.4
85.4
85.4
85.4
85.4
101.9
101.9
101.9
101.9
0.4
0.4
0.4
0.4
3.6
3.6
3.6
3.6
5.6
5.6
5.6
8.8
8.8
8.8
0.8
0.0
8.8
8.8
12.0
12.0
12.0
12.0
15.2
15.2
15.2
15.2
15.2
15.2
15.2
18.4
18.4
10.4
16.4
Total
Investment
Costs
74.5
103.2
131.9
142.8
191.6
241.5
241.5
307.9
307.9
365.9
365.9
415.8
415.8
465.7
532.1
582.0
631.9
681.8
748.2
798.1
048.0
648.0
848.0
897.9
947.0
t 1014.2
1014.2
1064 .I
1114.0
Total
System
Costs, $
34.1
43.2
49.2
53.8
160.5
204.5
254.9
317.0
352.2
420.8
426.2
508.5
514.1
591.8
597.3
666.0
678.0
750.0
843.4
918.8
998.3
107'4.0
llGO .0
123ll.6
1310.9
1331.0
1350.7
1431. 7
1513.3
1615.1
1638.1
1121.4
1001.7
Total Syst;,em
Consumption,
MMKWH
2680
3025
3688
4352
5015
. 5679
6342
6849
7357
7864
8372
8879
9539
10,298
11,008
11 ,717
12,427
13,477
14,526
15,576
16,625
17,675
18,584
19,493
20,402
21,311
22,220
23,129
24,038
24,947
25,856
26,765
27.674
Average Power
Costs, ¢/KWH
1.3
1.4
1.3
1.2
3.2
3.6
4.0
4.6
4.8
5.3
5.1'
5.7
5.4
5.7
5.4
5.7
5.5
5.6
5.8
5.9
6.0
6.1
6.2
6.3
6.4
6.2
6.1
6.2
6.3
6.5
6.3
6.4
c.s
tO w
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
86-87
87-88
88-89
89-90
90-91
91-92
92-93
93-94
9-1-95
95-96
96-97
97-98
98-99
99-2000
00-01
Ol-02
02-03
03-04
04-05
05-06
06-07
07-08
Oll-09
O:J-10
10-11
TABLE 4.16. Anchorage-Cook Inlet Area, High Load Growth Scenario, Case 2, 5% Inflation
Total Cost
of Ex1st1ng
Capac lty
29.7
39.1
45.7
47.9
59.5
63.6
68.7
68.9
69.8
67.1
60.6
56.4
52.5
49.8
47.4
46.5
48.5
43.8
36.3
37.7
37.5
31.7
16.7
15.3
5.4
5.5
3.6
3.7
3.9
4.0
4. 1
4.2
4.4
New Coal fire~ Capacity
Investmen~IiH& Coal
Costs . Costs Costs
69.8
106.4
144.9
187.3
187.3
264.8
264.8
350.2
350.2
459.8
459.8
563.6
563.6
678.1
79!).3
924.5
1057 .o
1196.2
1342.3
1495.7
1656.8
1656.8
1656.11
1843.3
2039.1
2244.7
2244.7
24 71.4
2709.4
13.11 9. 9
21.8 18.6
30.5 29.9
38.9 44.8
40.8 61.5
58.0 80.5
60.9 93.4
80.8 107.4
84.8'
110.5
115.9
142.2
149.3
179.2
211.8
247.2
285.5
327.1
372.2
420.9
473.5
497.2
522.1
584.8
652.4
725.3
761.6
844.2
933.1
125.4
145.9
168.5
193.9
221.3
261.2
307.4
354.5
407.1
464.8
526.5
591.8
667.5
746.8
835.5
930.8
1035.9
1151.5
127!l. 1
1416.3
1566.6
New llydroe1ectr1c
Costs
Investmen~~
Costs Costs
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.s
14.8
14.8
14.8
14.8
14.8
14.8
14.8
14.1)
14.8
14.8
14.0
14.0
14.8
0.6
0.6
0.6
0.6
0.7
0.7
0.7
0.8
0.8
0.9
0.9
8.9
1.0
1.0
1.1
1.1
1.2
1.3
1.3
1.4
1.5
1 "
1.6
1.7
1.0
1.9
Transmission
Systems
Investment OM&R--
Costs Costs
0.7
0.7
0. 7
0.7
21.0
'21.0
21.0
21.0
47.7
47.7
47.7
74.8
74.8
74.8
7·1.8
74.8
74.8
74.8
113.8
113.8
113.8 .
113.8
160.2
160.2
160.2
160.2
160.2
160.2
160.2
215.a
215.2
215.2
215.2
0.4
0.4
0.4
0.5
4.4
4.6
4.9
5.1
8.1
8.6
9.0
14.7
15.4
16.2
17.0
17.9
18.8
19.7
27.7
29.1
30.5
32.0
42.6
44.7
46.9
49.3
51.8
54.4
57.1
70.9
74.5
78.2
82.1
-Total
Investment
Costs
90.8
127.4
165.9
223.1
249.8
327.3
327.3
439.8
439.8
549.4
549.2
653.2
563.2
767.7
926.9
1053.1
1105.6
132Ul
1517.3
1670.7
1831.8
1831.8
1831.8
2018.3
2214.1
2474.7
2474.7
2701.4
2939.4
Total
System
Costs, $
30.8
40.2
46.8
49.1
178.4
236.0
299.9
381.4
430.6
542.1
551.8
699.8
718.6
872.5
899.0
1054.5
1092.0
1272..5
1511.0
ln2.6
1947.2
2181.5
2476.4
2744.6
3026.4
3131.9
3246.2
3593.5
3964.9
4428.0
4594.7
5046.1
5527.5
Total System
Consumption,
MMKWII
2680
3025
3688
4352
5015
5679
6342
6849
4357
7864
8372
8879
9589
10,7.98
11,008
11,717
12,427
13,477
]4,526
15,576
16,625
17,675
18,584
19,493
20,402
21 ,311
22,220
23,129
24,030
24,947
25,856
26, 7G5
27,674
Average Power
Costs, UKWII
1.1
1.3
1.3
1.1
3.6
4.2
4.7
5.6
5.8
6.9
6.6
7.9
7.5
8.5
8.2
9.0
8.8
9.4
10:4
11.1
11.7
12.3
13.3
14.1
]4.8
14.7
14.6
15.5
16.5
17.7
17.8
18.8
19.9
78-79
79-80
80-81
61-82
82-83
83-84
84-85
85-86
86-87
87-88
88-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-04
01-05
05-06
06-07
07-08
08-09
09-10
lO-ll
TABLE 4.17.· Anchorage-Cook Inlet Area, High Load Growth Scenario, Case 3, 0% Inflation
Total Cost
of Existing
Capacity
33.1
42.2
48.2
52.8
61.1
62.0
66.7
66.7
67.2
66.4
59.0
54.5
50.2
47.1
42.4
38.9
39.4
34.5
28.3
25.4
27.4
22.6
12.2
11.0
4.8
4.8
3.6
3.6
3.6
3.6
3.6
3.6
3.6
_ New Coal fired Capacity
Investment OM&R Coal
Costs Costs Costs
57.4
86.1
114.8
144.8
144.8
194.7
194.7
244.6
244.6
302.6
302.6
352.5
352.5
352.5
402.4
452.3
452.3
452.3
452.3
502.5
552.1
552.1
602.0
651.9
651.9
701.8
751.7
751.7
[101.6
11.4
17.1
22.8
28.7
28.7
33.5
38.5
40.3
48.3
59.7
59.7
69.5
69.5
69.5
79.3
89.1
89.1
09.1
89.1
9B.9
108.7
108.7
118.5
128.3
128.3
138.1
147.9
147.9
157.7
9.8
18.6
29.9
44.8
58.7
73.4
81.2
88.6
911.5
109.9
120.1
132.6
111.7
124.2
143.5
161.2
143.9
150.5
175.1
192.5
210.1
228.4
247.5
266.9
286.9
307.6
32B.O
350.6
372.9
New Hydroelectric
Costs
Investment Of.l&R
Costs Costs
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
10.9
163.1
163.1
163.1
163.1
213.0
213.8
213.8
213.0
213.8
213.0
213.8
213.8
213.8
213.8
213.8
213.8
213.8
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
1.1
1.1
1.1
1.1
1.7
1.7
1.7
1.7
1.7
1.7
1.7
1. 7
1.7
1.7
1.7
1.7
1.7
Transmission
_ Systems
In~estment OM&R
Cos!_?_ ~os ts
0.6
0.6
0.6
0.6
17.1
17.1
17.1
17.1
35.9
35.9
35.9
52.4
52.4
52.4
52.4
52.4
52.4
52.4
68.9
68.9
68.9
60.9
68.9
68.9
68.9
68.9
85.4
115.4
85.4
85.4
85.4
85.4
101.9
0.4
0.4
0.4
0.4
3.6
3.6
3.6
3.6
5.6
5.6
5.6
8.8
8.11
8.8
8.8
8.8
8.8
8.8
12.0
12.0
12.0
12.0
12.0
12.0
12.0
12.0
15.2
15.2
15.2
15.2
15.2
15.2
13.4
Total
Investment
Costs
74.5
103.2
131.9
142.8
191.6
241.5
241.5
307.9
30?.9
365.9
365.9
415.[1
568.0
568.0
634.4
684.3
604.3
684.3
684.3
785.2
ll34.0
034.8
901.2
951.1
951.1
1001 .. 0
1050.9
1050.9
1117.3
Total
System
Costs, $
34.1
43.2
49.2
53.8
160.5
204.5
254.9
317.0
352.2
420.8
426.2
508.5
514.1
591.8
597.3
666.0
798.5
806.1
898.6
973 .. 1
]009.1
1018.9
1025.1
1101.3
1172.1
1190.4
1287.7
1366.ll
131l6.!l
1467.2
15413.1
1569.9
1671.6
Total System
Consumption,
11M KWH
2680
3025
3688
4352
5015
5679
6342
6849
7357
7864
11372
6879
9589
10,298
11,008
11,717
12,427
13,477
14,526
15,576
16,625
17,675
18,584
19,493
20,402
21,311
22,220
23,129
24,038
24,947
25,856
26,765
27,674
Average Power
Costs, UK\IH
1.3
1.4
1.3
1.2
3.2
3.6
4.0
4.6
4.8
5.3
5.1
5.7
5.4
5.7
5.4
5.7
6.4
6.0
6.2
6.2
6.1
5.8
'5.5
5.6
5.7
5.6
5.8
5.9
5.8
5.9
6.0
5.9
6.0
lO
<.n
Year
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
06-87
87-88
88-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
Ol-02
02-03
03-04
04-05
05-06
06-07
07-08
08-09
09-10
10-ll
TABLE 4.18. Anchorage-Cook Inlet Area, High Load Growth Scenario. Case 3, 5% Inflation
Tota 1 Cost
of Existing
Capacity
29.7
39.1
45.7
47.9
59.5
63.6
60.7
60.9
69.8
67.1
60.6
56.4
52.5
49.0
47.4
46.5
48.5
43.8
36.3
37.7
37.5
31.7
16.7
15.3
5.4
5.5
3.6
3.7
3.9
4.0
4.1
4.2
4.4
New Coal Fired ~acity
lnvestment-~OFl&R-Coal
Costs Costs Costs
69.8
106.4
144.9
187.3
187.3
264.8
264.8
350.2
350.2
459.8
459.8
563.6
563.6
563.6
683.8
810.0
810.0
1110.0
810.0
963.4
1124.5
1124.5
1302. 1
1488.6
1480.6
1694.2
1910.1
1910. i
2140.1
13.8
21.8
30.5
38.9
40.8
56.0
60.9
80.0
84.8
110.5
115.9
142.2
149.3
156.6
160.2
222.4
233.5
245.2
257.5
300.5
347.1
364.4
417.5
474.9
49tl.7
563.9
1>34.5
666.3
746.3
9.9
10.6
29.9
44.8
61.5
80.5
93.4
107.4
125.4
145.9
.168. 5
193.9
171.3
201.2
243.1
21l5.6
260.9
30B.5
359.3
413.1
476.1
541.9
616. I
696.2
704.9
602.8
990.5
1100.7
1237.0
New llydroe1ectrlc
Costs
Tnves tment om.r
Costs ~
14.8
14.8
14.11
14.8
14.0
14.6
14.0
14.6
14.0
335.2
335.2
335.2
335.2
464.9
464.9
464.9
464.9
464.9
464.9
464.9
464.9
464.!)
464.9
464.9
464.9
464.9
0.6
0.6
0.6
0.6
0.7
0.7
0.7
0.6
0.0
2.2
2.3
2.4
2.5
4.2
4.4
4.6
4.8
5.1
5.1
5.6
5.9
6.2
6.~
6.8
7.1
7.~
Transmission
~-1 nves tinerit OH&R-
Costs Costs
D. 7
0.7
0.7
0.7
21.0
21.0
21.0
21.0
47.7
47.7
47.7
74.8
74.8
74.8
74.8
74.1)
74.8
74.8
114.8
114.6
114.8
114.8
114.8
114.8
114.8
114.6
168.5
168.5
168.5
168.5
160.5
160.5
222.0
0.4
0.4
0.4
0.5
4.4
4.6
4.9
5.1
8.1
8.6
9.0
14.7
15.4
16.2
17.0
17.9
18.6
19.7
27.7
29.1
30.5
32.0
33.6
35.3
37 .I
38.9
51.9
54.5
57.2
60. 1
63.1
66.2
01.5
Total
Investment
Costs _
90.8
127.4
165.9
223.1
249.8
327.3
327.3
439.8
439.6
549.4
549.2
653.2
973.6
973.6
1133.6
1260.0
1389.7
13139.7
1389.7
1543.1
1704.2
1704.2
1935.5
·2122.0
2122.0
2327.6
2543.5
2543.5
2035.0
Total
System
Costs, $
30.8
40.2
46.8
49.1
178.4
236.0
299.9
381.4
430.6
542.1
551.8
699.0
718.6
072.5
899.0
1054.5
1364.2
1397.4
1595.2
1837.3
1964.3
2011.5
2061.4
2312.1
2575.0
2660.2
3030.2
3357.2
34 72.9
3844.9
4238.4
4396.0
4912.5
Total System
Consumption,
MMKWII
2680
3025
3688
4352
5015
5679
6342
6849
4357
7864
fJJ72
0079
9509
10,298
11,008
11.717
12,427
13,477
14,526
15,576
16,625
17,675
18,584
19,493
20,402
21,311
22,220
23,129
24,03B
24,947
25,856
26,765
27,674
Average Power
Costs, ¢/KWH
1.1
1.3
1.3
1.1
3.6
4.2
4.7
5.6
5.8
6.9
6.6
7.9
7.5
8.5
8.2
9.0
10.9
10.4
10.9
11.0
11.8
11.4
11.1
11.9
12.6
12.5
13.6
14.5
14.4
15.4
16.4
16.4
17.7
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
86-87
87-88
88-89
119-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-04
0-1-05
05-06
06-07
07-0il
Oll-09
O'l-10
10-11
TABLE 4.19. Fairbanks-Tanana Valley Area, Low Growth Scenario, Case l, 0% Inflation
Total Cost
of Existing
Capacity
33.8
36.6
39.4
41.6
35.6
33.1
30.3
28.2
26.1
24.0
22.9
23.1
20.9
18.2
18.4
18.5
16.9
14.3
3.8
3.8
3.8
3.8
3.8
1.5
1.5
1.5
New Coal Fired Capac!~
Investmeor-llH&R Coal-
Costs ~sts Costs
2.6
21.5
27.6
27.6
27.6
27.6
46.5
51.2
51.2
70.1
69.0
89.0
69.0
89.0
89.0
89.0
69.0
1!9.0
8~LO
1!9.0
1!9.0
O!l.O
89.0
0.5
4.3
5.5
5.5
5.5
5.5
9.3
10.2
10.2
14.0
17.8
17.8
17.8
17.8
17 .ll
17.0
17.8
17.fl
17.6
17 .IJ
17 .ll
17.8
17.8
6.9
7.2
7.3
7.5
7.7
7.8
7.7
10.0
10.0
12.4
13.3
14.1
14.7
15.4
16.4
lll. 9
19.6
20.6
20.9
21.5
21.9
22.4
22.9
23.5
24.1
24.6
24.7
25.7
26.2
New Hydroelectric
Costs
Investment 011&R
Costs Costs
Transmission
Systems
Investment OM&R
Costs ~
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
J.5
3.5
3.5
3.5
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
Total
Investment
Costs
2.9
25.0
31.4
31.7
31.1
31.1
50.0
54.7
54.7
73.6
92.5
92.5
92.5
92.5
92.5
92.5
92.5
92.5
92.5
92.5
92.5
92.5
92.5
Total
System
Costs, $
34.3
37.1
39.9
42.1
43.1
40.8
38.2
36.6
34.3
32.4
34.2
63.4
68.5
71.1
69.2
70.1
93.5
98.2
97.1
111.2
' 134.7
135.7
136.0
136.6
134.7
135.2
135.7
134.8
135.4
135.9
136.0
137.0
137.5
Total System
Consumption,
MMKI-IH
778
823
855
887
919
951
983
1015
1047
1079
1111
1144
1176
1208
1240
1272
1305
1337
1369
1401
1433
1466
1470
1474
1478
1482
1437
1491
1495
1499
1503
1507
1511
Average Power
Costs, ¢/KIIH
4.4
4.5
4.7
4.7
4.7
4.3
3.9
3.6
3.3
3.0
3.1
5.6
5.8
5.9
5.6
5.5
7.1
7.3
7.1
7.9
9.4
9.2
9.3
9.3
9.1
9.1
9.1
9.0
9.0
9.1
9.0
9.1
9.1
TABLE 4.20. Fairbanks-Tanana Valley Area, Low Growth Scenario. Case 1 ' 5% lnfl at ion
New Hydroelectric Transmission
Total Cost New Coal fired Ca~cl~ co~ts sxstems Total Total Total System
of Existing fnvestment Of1&R Coa Inves fiiierit--llM&R lnvestment OM&R Investment System Consumption, Average rower
.J'lli_ Cal.!acl tx Costs Costs Costs Costs Costs Costs Costs ~-ts __ Costs, $ _l_~ Costs, ¢/KIIH
78-79 30.5 0.2 0.2 30.9 778 4.0
79-80 33.9 0.2 0.2 34.2 823 4.2
80-81 37.4 0.2 0.2 37.8 655 4.4
81-82 40.7 0.2 0.2 41.0 887 4.6
82-83 36.6 6.9 0.2 0.2 43.9 919 4.8
83-84 35.6 7.2 0.2 0.2 43.2 951 4.5
84-85 33.5 7.3 0.2 0.2 41.3 983 4.2
85-86 32.3 7.5 0.2 0.2 40.3 1015 4.0
86-87 30.4 8.1 0.2 0.3 36.9 1047 3.7
87-88 28.7 8.6 0.2 0.3 37.8 1079 3.5
80-89 27.9 4.2 0.7 8.9 0.2 0.3 4.4 42.4 1111 3.8
89-90 29.3 36.6 7.0 12. I 4.5 1.7 41.1 91.3 1144 7.9
90-91 28.4 48.0 7.4 12.7 4.5 1.8 52.5 102,8 1176 8.7
~ 91-92 30.1 48.0 7.4 16.5 4.5 1.9 52.5 100.2 1208 8.9
'-l 92-93 26.7 46.0 7.4 18.7 4.5 2.0 52.5 107.6 1240 8.6
93-94 28.1 46.0 7.6 20.6 4.5 2.1 52.5 . 110.6 1272 6.7
94-95 29.5 89.4 17.0 22.6 . 4.5 2.2 93.9 16!.\.1 1305 12.7
95-96 28.8 100.2 17.2 24.9 4.5 2.3 104.7 177.6 1337 13.3
96-97 27.7 100.2 111.0 27.9 4.5 2.4 104.7 180.4 1369 13.2
91-98 6.1 140.1 28.5 33.5 4.5 2.5 152.6 222.9 1401 15.9
98-99 6.4 1911.4 39.6 36.7 4.5 2.6 202.9 287.9 1433 20.1
99-2000 6.6 190.4 41.6 40.1 . 4.5 2.7 202.9 294.0 1466 20.0
00-01 7.0 19(!. 4 43.6 43.1 ' 4. 5 2.8 202.9 299.4 1470 20.4
01-02 7.3 190.4 46.0 46.2 4.5 2.9 202.9 305.2 1474 20.7
02-03 2.7 198.4 48.4 49.6 4.5 3.0 202.9 306.5 1478 20.7
03-04 2.8 198.4 50.11 53.2 4.5 3.2 202.9 312.6 1482 21.1
04-05 2.9 198.4 53.6 57.1 4.5 3.3 202.9 3.19.6 1487 21.5
05-06 190.4 56.0 61.3 4.5 3.4 202.9 323.6 1491 21.7
06-07 1911.4 511.11 65.11 4.5 3.5 202.9 330.9 1495 22.1
07-08 193.4 60.0 70.6 4.5 3.7 202.9 337.0 1499 22.5
00-09 198.4 56.2 75.11 4.5 3.9 202.9 347.5 1503 23.1
09-10 1911.4 6B.O Ill. 3 4.5 4.2 202.9 356.4 1507 23.6
10-11 190.4 71.6 Ill. I 4.5 4.3 202.9 365.9 1511 24.2
TABLE 4.21. Fairbanks-Tanana Va 11 ey Area, Low Growth Scenario, Case 2, 0% Inflation
New Hydroelectric Transmission
Total Cost New Coal Fired Caeacity Costs SJ:stems Total Total Total System
of Existing Investment .OM&R · Coa 1 Investment OM&R Investment OM&R Investment System Consumption, Average Power
~ Ca(!actty Costs Costs Costs_ Costs ~ Costs Costs Costs Costs 1 S M11KI-IH Costs, ¢{KWH
78-79 33.8 0.3 0.2 34.3 778 4.4
79-80 36.6 0;3 0.2 37.1 823 4.5
80-81 39.4 0.3 0.2 39.9 855 4.7
81-82 41.6 0.3 0.2 42.1 887 4.7
82-83 35.6 6.9 0.3 0.2 43.1 919 4.7
83-84 33.1 7.2 0.3 0.2 40.8 951 4.3
84-85 30.3 7.3 0.3 0.2 38.2 983 3.9
85-86 28.2 7.5 0.3 0.2 36.6 1015 3.6
86-87 26.1 7.7 0.3 0.2 34.3 1047 3.3
87-88 24.0 7.8 0.3 0.2 32.4 1079 3.0
88-89 22.9 2.6 0.5 7.7 0.3 0.2 2.9 34.2 1111 3.1
89-90 23.1 21.!i 4.3 10.0 3.5 1.0 25.0 63.4 1144 5.6
90-91 20.9 27.6 5.5 10.0 3.5 1.0 31.4 6!1.5 1176 5.8
1.0 91-92 21.1 27.6 5.5 12.4 3.5 1.0 31.7 71.1 1208 5.9
00 92-93 18.2 27.6 5.5 13.3 3.5 1.0 31.1 69.2 1240 5.6
93-94 18.4 27.6 5.5 14.1 3.5 1.0 31.1 70.1 1272 5.5
94-95 16.5 27.6 5.5 14.7 18.6 2.0 46.4 87.2 1305 6.7
95-96 16.9 32.3 6.4 15.4 18.8 2.0 51.1 91.8 1337 6.9
96-97 14.3 51.2 10.2 16.4 18.8 2.0 70.0 113.1 1369 8.3
97-98 3. 7 70.1 14.0 18.9 16.8 2.0 88.9 127.6 1401 9.1
98-99 3.7 70.1 14.0 19.6 18.8 2.0 88.9 128.4 1433 8.9
99-2000 3.7 70.1 14.0 20.6 16.0 2.0 00.9 129.3 1466 8.8
00-01 3.8 70.1 14.0 20.9 10.8 2.0 80.9 129.6 H70 8.6
01-02 3.0 70.1 14.0 21.5 18.8 2.0 00.9 130.2 1474 8.8
02-03 1.5 70.1 14.0 21.8 18.8 2.0 ll8.9 123.3 1478 8.7
03-04 1.5 70.1 14.0 22.4 18.8 2.0 88.9 128.fl 1482 8.7
04-05 1,5 70.1 14.0 22.9 18 .. 0 2.0 88.9 129.3 1407 8.7
05-06 70.1 14.0 23.5 18.8 2.0 83.9 128.4 1491 8.6
06-07 89.0 17.8 24.0 18.6 2.0 107.8 151.7 1495 10.1
07-08 89:o 17.8 24.5 10.11 2.0 107.0 152.2 1499 10.1
08-09 89.0 17.0 25.1 18.0 2.0 107.0 152.tl 1503 10.1
09-10 89.0 17.8 25.7 10.0 2.0 107.8 153.3 1507 10.2
. 10-11 89.0 17.0 26.2 18.8 2.0 107.8 153.9 1511 10.2
78-79
79-80
80-81
81-82
82-83
83-8·1
84-85
85-86
86-87
87-88
88-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
9b-91
97-98
9tl-99
99-2000
00-01
01-02
02-03
03-0·1
04-05
05-06
06-07
07-08
GB-09
09-10
JO .. J1
TABLE 4.22. Fairbanks-Tanana Valley Area, Low Growth Scenario, Case 2, 5% Inflation
Tota 1 Cost
of Existing
Capac1 ty
30.57
33.9
37.4
40.7
36.6
35.6
33.5
32.3
30.4
28.7
27.9
29.3
28.4
30.1
26.7
28.1
29.5
28.8
27.7
6.1
6.4
6.6
7.0
7.3
2.7
2.8
2.9
New Coal Fired Capacity
Tiive5tment-OM&R Coa)-
Costs Costs Costs
4.2
36.6
48.0
48.0
48.0
48.0
48.0
58.8
105.4
153.3
Hi3.3
153.3
153.3
153.3
153.3
153.3
153.3
153.3
227.6
227.6
227.6
227.6
227.6
0.7
7.0
7.4
7.4
7.4
6.9
7.2
7.3
7.5
8.1
8.6
8.9
12.1
12.7
16.5
18.7
7.8 20.6
11.9 22.6
14.6 .. 24.9
24.4 27.9
35.2 33.5
36.9 36.7
38.7 40.1
40.7· 43.0
42.7 46.1
44.9 49.6
47.1 53.2
49.5 57.1
51.9 61.3
69.2 65.7
72.6 70.5
76.3 75.7
ll0.1 lll.2
84.1 87.1
New Hydroe1ectl'1c
Costs
lnvestment OM&R
Costs Costs
Tran~mfsslon
~stem~
l11VCS tmcnt ---of.l&R
Costs Costs
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
4.5
4.5
4.5
4.5
4.5
36.8
36.8
36.8
36.8
36.8
36.8
36.8
36.8
36.8
36.8
36.8
36.(!
36.8
36.fJ
36.8
36.8
36.8
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.3
0.3
0.3
1.7
1.8
1.9
2:o
2.1
4.0
4.2
4.4
4.6
4.8
5.1
5.3
5.6
5.9
6.2
6.5
6.8
7.2
7.5
7.9
8.3
8.7
Total
lnves tment
Costs
4.4
41.1
52.5.
52.5
52.5
52.5
84.8
95,6
142.2
190.1
190.1
190.1
190.1
190.1
190.1
190.1
190.1
190.1
264.4
264.4
. 26~ .4
264.4
264.4
Total
System
Costs, $
30.9
34.2
37.8
41.0
43.9
43.2
41.3
40.3
38.9
37.8
42.4
91.3
102.8
106.2
107.0
110.8
153.0
168.1
226.6
269.6
275.0
280.6
286.2
291.9
293.2
299.4
306.2
310.1
406.6
415.1
424.4
43-1. 1
443.3
Tota 1 System
Consumption,
MMKWII
778
823
855
887
919
951
983
1015
1047
1079
1111
1144
1176
1208
1240
1272
1305
1337
l 369
1401
1433
1466
1470
1474
1478
1482
1487
1491
1495
1499
1503
1507
1511
Average Power
Costs, UKWH
4.0
4.2
4.4
4.6
4.8
4.5
4.2
4.0
3.7
3.5
3.8
7.9
8.7
8.9
8.6
8.7
11.7
12.6
16.5
19.2
19.2
19.1
19.4
19.8
19.8
20.2
20.6
20.8
27.2
27.7
2B.2
28.8
29.4
__,
0
0
TABLE 4.23. Fairbanks-Tanana Valley Area, Low Growth Scenario, Case 3, 0% Inflation
Total Cost
of Existing
~ Capacity
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
86-87
87-88
88-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03"
03-04
04-05
05-06
06-07
07-08
08-09
09-10
10-11
33.8
36.6
39.4
41.6
35.6
33.1
30.3
28.2
26.1
24.0
22.9
23.1
20.9
21.1
18.2
18.4
18.5
16.9
14.3
3.8
3.8
3.8
3.8
3.8
1.5
1.5
1.5
New Coa 1 Fired Capac.!J;y__
Investment OM&R Coal
Costs Costs Costs
2.6
21.5
27.6
27.6
27.6
27.6
27.6
32.3
32.3.
32.3
32.3
32.3
32.3
32.3
32.3
32.3
32.3
32.3
32.3
32.3
32.3
32.3
32.3
0.5
4.3
5.5
5.5
5.5
5.5
5.5
6.4
6.4
6.4
6.4
6.4
6.4
6.4
6.4
6.4
6.4
6.4
6.4
6.4
6.4
6.4
6.4
6.9
7.2
7.3
7.5
7.7
7.8
7.7
10.0
10.0
12.4
13.3
14.1
6.9
6.5
7.3
9.6
10. 1
3.1
2.7
2.7
2.4
2.5
2.6
2.7
2.8
2.9
3.1
3.2
3.4
New llydroe1ectrtc
Cilsts
Transmission
Systems
Investment
Costs
OM&R Investment OM&R
Costs . Costs_ Costs
36.2
36.2
36.2
36.2
36.2
40.3
48.3
48.3
48.3
48.3
40.3
48.3
48.3
48.3
48.3
46.3
48.3
0.1
0.1
0:1
0.1
0.1
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
3.5
3.5
18.8
18.8
18.8
18.8
18.8
18.8
16.8
18.6
18.8
16.8
18.8
18.8
16.8
18.8
16.6
18.8
18.8
18.8
10.8
10.6
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
1.0
1.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.8
2.0
Total
Investment
Costs
2.9
25.0
31.4
46.4
46.4
46.4
82.6
82.6
82.6
82.6
82.6
99.4
99.4
99.4
99.4
99.4
99.4
99.4
99.4
99.4
99.4
99.4
99.4
Total
System
Costs, $
34.3
37.1
39.9
42.1
43.1
40.8
38.2
36.6
34.3
32.4
34.2
63.4
68.5
87.4
85.5
86.4
115.6
119.2
117.5
109.2
109.7
114.9
114.5
114.5
111.9
112.0
112.1
110.7
110.8
110.!)
Ill. 1
111.2
111.4
Total System
Consumption,
MMKWH
778
823
85~
887
919
951
983
1015
1047
1079.
lll1
1144
1176
1208
1240
1272
1305
1337
1369
1401
1433
1466
1470
1474
1476
1482
1487
1491
1495
1499
1503
1507
1511
Average Power
Costs, ¢/KWH
4.4
4.5
4.7
4.7
4.7
4.3
3.9
3.6
3.3
3.0
3.1
5.6
5.8
7.2
6.9
6.8
8.8
8.9
8.6
7.8
7.6
7.6
7.1l
7.7
7.6
7.6
7.5
7.4
7.4
7.4
7.4
7.4
7.4
........
0
78-79
79-60
60-81
81-62
82-83
83-84
84-85
65-86
66-67
87-88
88-69
8~-90
90-91
91-92
92-9.3
93-94
94-95
95-96
96-97
97-98
93-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-07
07-08
Oll-09
09-10
I O-Il
TABLE 4.24. Fairbanks-Tanana Valley Area, Low Growth Scenario, Case 3, 5% Inflation
Total Cost
of Exfstlng
Capacity
30.5
33.9
37.4
40.7
36.6
35.6
33.5
32.3
30.4
28.7
27.9
29.3
28.4
30.1
26.7
28. l
29.5
28.6
27.7
6.1
6.4
6.6
7.0
7.3
2.7
2.8
2.9
New Co a I Ff red Capad ty___
Investment OM&R Coal
. Costs_ Cosli_ Costs
4.2
36.6
48.0
48.0
48.0
48.0
48.0
58.8
58.8
58.8.
56.8
58.8
58.8
56.6
58.8
58.8
58.8
56.8
58.6
51!.6
58.8
51Ul
58.8
0.7
7.0
7.4
10.3
10.8
11.4
11.9
14.6
15.3
16.1
16.9
17.7
11!.6
19.6
20.5
21.6
22.6
23.7
24.9
6.9
7.2
7.3
7.5
8.1
8.6
8.9
12. I
12.7
16.4
18.7
20.6
10.7
10.5
12.4
16.9
18.9
5.9
5.4
5.8
5.5
5.9
6.5
7 .I
7.6
26.2 • B.5
27.5 • 9. 3
26.9 10.2
30.3 11.1
New ltydroe 1 ectrl c
Costs
·Investment OM&R
Costs Costs
76.2
76.2
76.2
76.2
76.2
106.6
100.6
100.6
108.6
108.6
106.6
108.6
108.6
100.6
100.6
108.6
100.6
0.3
0.3
0.3
0.4
0.4
0.0
0.0
0.9
0,9
1.0
1.0
1.1
1.1
1.2
1.2
1.3
1.4
Transmfss I on
Systems
Investment OM&R
Cos t_s _ Costs
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
4.5
4.5
32.4
32.4
:l2.4
32.4
32.4
32.4
32.4
32.4
32.4
32.4
32.4
32.4
32.4
32.4
32.4
32.4
32.4
32.4
32.4
32.4
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.3
0.3
0.3
1.7
1.8
3.5
3.6
3.8
4.0
4.2
4.4
4.6
4.0
5.1
5.3
5.6
5.9 .
6.2
6.5
6.8
7.2
7.5
7.9
6.3
8.7
Total
Investment
Costs
4.4
41.1
52.5
60.4
80.4
60.4
156.6
167.4
167.4
167.4
167.4
199.8
199.8
199.8
199.6
199.6
199.8
199.8
199.8
199.6
199.6
199.6
199.8
Tot11l
System
Costs, $
30.9
34.2
37 .If
41.0
43.9
43.2
41.3
40.3
38.9
37.8
42.4
91.3
102.8
140.7
140.3
144.3
213.1
225.8
227.5
211.5
214.8
236.0
236.9
239.0'
235.3
237.3
239.3
238.5
240.8
243.2
245.7
Wl.!i
251.3
Total System
Consumption,
MMKWil
716
823
855
867
919
951
963
1015
1047
1079
1111
1144
1176
1206
1240
1272
1305
1337
1369
1401
1433
1466
1470
1474
1478
1462
1407
1491
1495
1499
1503
1507
1511
Average Power
Costs, ¢/KWH
4.0
4.2
4.4
4_.6
4.8
4.5
4.2
4.0
3.7
3.5
3.8
7.9
8.7
11.6
11.3
11.3
16.3
16.9
16.6
15.1
15.0
16.1
16.1
16.2
15.9
16.0
16.1
16.0
16.1
16.2
16.3
16.5
16.6
TABLE 4.25. Fairbanks-Tanana Valley Area, Medium Growth Scenario, Case 1 ' 0% Inflation
New Hydroelectr1c Transmiss1on
Total Cost New Coal Fired Ca(!acitl Costs Slstems Total Total Total System
of Existing Investment OM&R Coal Investment OM&R Investment OM&R Investment System Consumption, Average Power
~ Ca(!ac1t~ Costs Costs Costs Costs Costs Costs Costs Costs Costs 2 ! fi.!-1KWII Costs, UKWH
78-79 33.8 0.3 0.2 34.2 804 4.3
79-80 36.6 0.3 0.2 37.0 862 4.3
80-81 39.4 0.3 0.2 39.8 916 4.3
81-82 41.6 0.3 0.2 42.1 970 4.3
82-83 35.6 6.9 0.3 0.2 43.0 1024 4.2
83-84 33.1 7.2 0.3 0.2 40.8 1078 3.8
84-85 30.3 7.3 0.3 0.2 38.1 1132 3.4
85-86 28.2 18.9 3.8 9.4 3.5 1.0 22.4 64.9 1193 5.4
86-87 26.1 18.9 3.8 10.9 3.5 1.0 22.4 64.2 1254 5.1
87-88. 24.0 18.9 3.8 12.4 3.5 1.0 22.4 63.7 1315' 4.8
88-89 22.9 21.5 4.3 13.3 3.5 1.0 25.0 66.6 1376 4.8
89-90 23.1 40.4 8.1 14.5 3.5 1.0 43.9 90.6 1437 6.3
90-91 20.9 46.5 9.3 15.5 3.5 1.0 50.0 96.8 1505 6.4
--J 91-92 21.1 46.5 9.3 16.8 3.5 1.0 50.0 98.2 1573 6.2
C>
N 92~93 18.2 65.4 13.1 Hl.2 3.5 1.0 68.9 119.5 1641 7.3
93-94 18.4 65.4 13.1 19.5 3.5 1.0 68.9 120.9 1709 7.1
9-1-95 18.5 65.4 13.1 20.7 3.5 1.0 68.9 122.2 1777 6.9
95-96 16.9 70.1 14.0 22.1 3.5 1.0 73.6 127.6 1859 6.9
96-97 14.3 89.0 17.8 24.0 5.3 1.8 94.3 152.4 1941 7.8
97-98 3.7 107.9 21.6 27.3 5.3 1.8 113.2 167.8 2023 8.3
9>:J-99 3.7 126.8 25.4 28.9 5.3 1.8 132.1 192.0 2105 • 9.1
99-2000 3.7 126.8 25.4 30.7 5.3 1.8 132.1 193.8 2187 8.9
00-01 3.8 126.8 25.4 31.8 5.3 1.8 132.1 194.9 2229 8.7
01-02 3.8 126.8 25.4 33. 1 5.3 1.8 132. I 196.2 2270 8.6
02-03 1.5 126.8 25.4 34.2 5.3 1.8 132.1 195.0 2312 8.4
03-04 1.5 155.5 31.1 35.6 5.3 1.8 160.8 230.8 2353 9.6
04-05 155.5 31.1 37.0 5.3 1.8 160.8 232.2 2395 9.7
05-06 155.5 31.1 38.4 5.3 1.8 160.8 232.1 2437 9.5
06-07 155.5 31.1 39.9 5.3 1.8 160.8 233.5 2478 9.4
07-08 155.5 31.1 41.4 5.3 1.8 160.8 235.1 2520 9.3
08-09 155.!f' 31.1 42.8 5.3 1.8 160.8 236.5 2561 9.2
09-10 155.5 J1.1 44.4 5.3 1.8 160.8 238.1 2603 9.1
10-11 155.5 31.1 45.9 5.3 1.8 160.8 239.6 2645 9.1
_ __,
C> w
78-79
79-80
80-81
81-82
82-83
83-84
134-85
85-86
86-137
87-B8
88-09
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-07
07-08
08-0'l
O'l-10
lO-ll
TABLE 4.26. Fairbanks-Tanana Va"lley Area, Medium Growth Scenario, Case 1, 5% Inflation
Total Cost
of Existing
~af.lli_
30,5
33.9
37.4
40.7
36.6
35.6
33.5
32.3
30.4
28.7
27.9
29.3
28.4
3il. 1
26.7
28.1
29.5
28.8
27.7
6.1
6.4
6.6
7.0
7.3
2.7
2.6
2.9
New Coal fired Capacity
Investment i:iM&R Coal
Costs Costs Costs
26.6
26.6
26.6
30.6
63.2
74.6
74.6
112.1
112. 1
112.1
122.9
169.5
217.4
267.7
267.7
267.7
267.7
267.7
365.0
365.0
365.0
365.0
365.0
365.0
365,0
365.0
5.3
5.5
5.8
7.0
13.6
16.4
16.4
23.8
25.0
26.2
29.7
40.1
51.7
64.1
67.3
70,7
74.3
77.9
77.9
102.1
107.2
112.6
118.2
124.1
6.9
7.2
7.3
9.4
11.4
13.6
15.4
17.6
19.8
22.3
25.5
28.5
31.8
35.8
40.7
48.5
54.0
59.9
65.3
71.1
77.6
77.6
92!1
100.3
109.1.
118.7
129.1
130.3 1~0.4
136.8 152.5
New llydroe 1 ectrl c
Costs
Investment ON&R
~!L_ Costs
Transmf ss ion
____jystems
I nves tmen~ol>T&R
· Costs Costs
0.2
0.2
0.2
0.2
0.2
0.2
0.2
4.11
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
8.5
8.5
8.5
8.5
8.5
8.5
8.5
8.5
0.5
8.5
8.5
6.5
8.5
8 ,.
.~
8.5
0.2
0.2
0.2
0.2
0.2
0.2
0.2
1.2
1.3
1.4
1.5
1.5
1.6
1.7
1.8
1.9
2.0
2.2
2.3
2.4
2.6
2.7
2.8
3.0
3.2
3.4
3.6
3.7
3.0
4.2
4.2
4.4
4.!i
Total
Investment
Costs
31.0
31.0
31.0
35.2
67.6
79.0
79.0
116.5
116.5
1.16. 5
127.3
178.0
225.9
276.2
276.2
276.2
276.2
276.2
373.5
373.5
373.5
373.5
373.5
373.5
373.5
373.5
Total
System
Costs, $
30.9
34.2
37.8
41.0
43.9
43.2
41.3
79.2
79.6
80.5
87.0
129.7
145.3
149.5
194.4
200.1
20,6.1
223.8
280.8
334.6
403.4
412.7
422.0
431.9
437.6
56].5
574.2
504.7
599.0
614.4
630.9
648.6
667.3
Total System
Consumption,
MMKWII
804
662
916
970
1024
1076
1132
1193
1254
1315.
1376
1437
1505
1573
1641
1709
1777
1859
1941
2023
2105
2187
2229
2270
2312
2353
2395
2437
2478
2520
2561
2603
2645
Average Power
fosts, UKWII
3.8
4,0
4.1
4.2
4.3
4.0
3.6
6.6
6.3
6.1
6.3
9.0
9.6
9.5
11.6
11.7
11.6
12.0
14.9
16.5
19.2
16.9
16.9
19.0
18.9
23.9
24.0
24.0
24.2
24.4
24.6
24.9
25.2
TABLE 4.27. Fairbanks-Tanana Valley Area, Medi:um Growth Scenario, Case 2, 0% Inflation
Total tost
of Ex~sting
~ Capacity
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
86-87
87-88
88-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-0J
03-04
04-05
05-06
06-07
07-08
08-09
09-10
10-11
33.8
36.6
39.4
41.6
35.6
33.1
30.3
28.2
26.1
24.0
22.9
Z3.1
20.9
21.1
18.2
13.4
18.5
16.9
14.3
3.76
3.7
3.7
3.8
3.8
1.5
1.5
1.5
New Co a 1 F1 red Capad ty
18.9
18.9
18.9
21.5
21.5
27.6
27.6
27.6
27.6
46.5
70.1
70.1
89.0
107.9
107.9
107.9
107.9
126.8
126.8
126.8
126.8
126.8
126.8
126.8
126.8
126.8
.3.8
3.8
3.8
4.3
4.3
5.5
5.5
5.5
5.5
9.2
13.8
13.8
17.5
21.2
21.2
21.2
21.2
24.9
24.9
24.9
24.9
24.9
24.9
24.9
24.9
24.9
6.9
7.2
7.3
9.4
,0.9
12.4
13.3
14.5
19. 1
15.2
16.0
16.9
19.8
22.1
24.0
27.3
28.9
30.7
31.6
33.1
34.2
35.6
~7.0
38.44
39.8
41.3
42.6
44.3
45.9
New Hydroelectric
Costs
Investment OM&~
Costs Costs
Transmission
Systems
Investment OM&R
Costs Costs
0.3
0.3
0.3.
0.3
0.3
0.3
0.3
3.5
3.5
3.5
3.5
18.8
18.8
18.8
18 .. 8
18.8
18.8
18.8.
18.8
18.8
18.8
18.8
18.8 .
18.8
18.8
18.8
18.8
18.8
18.8
18.8
18.8
18.8
18.8
0.2
0.2
0.2
0.2
0.2
0.2
0.2
1.0
1.0
1.0
1.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
Total
Investment
Costs
22.4
22.4
22.4
25.0
40.3
46.4
46.4
26.4
46.4
65.3
86.9
68.9
107.8
126.7
126.7
126.7
126.7
145.6
145.6
145.6
145.6
145.6
145.6
145.6
145.6
145.6
Tot~l.
System
Costs, $
34.2
37.0
39.8
42,1
43.0
40.8
38.1
64.9
64.2
63.7
66.6
84.2
89.0
90.2
88.2
89.2
. 114.9
143.7
143.2
158.5
'102.6
184.5
185.5
166.8
208.2
209.6
211.0
210.9
212.3
213.8
215.3
216.9
218.4
Total System
Consumption.
Mf.IKI-IH
804
862
916
970
1024
1078
1132
1193
1254
1315
1376
1437
1505
1573
1641
1709
1777
1859.
1941
2023
2105
2187
2229
2270
2312
2353
2395
2437
2478
2520
2561
2603
2645
Average Power
Costs, t/KWH
4.3
4.3
4.3
4.3
4.2
3.8
3.4
5.4
5.1
4.8
4.8
5.8
5.9
5.7
5.4
5.2
6.5
7.7
7.4
7.8
8.7
8.4
8.3
8.2
9.0
8.9
8.8
8.6
8.6
8.5
8.4
8.3
8.2
......
0
Ol
78-79
79-80
80-81
81-62
82-83
83-84
84-85
85-86
86-87
87-88
88-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
Ol-02
02-03
03-04
04-05
05-06
06-07
07-08
013-09
09-10
10-II
TABLE 4.28. Fairbanks-Tanana Valley Area, Medium Gro\tJth"Scenario, Case 2, 5% Inflation
Total Cost
of fKistlng
Capacl ty
30.5
33.9
37.4
40.7
36.6
35.6
33.5
32.3
30.4
26.7
27.9
29.3
28.4
30.1
26.7
28.1
29.5
28.8
27.7
6.1
6.4
6.6
7.0
7.3
2.7
2.8
2.9
New Co a 1 FJred Capacity
Investment OM&R Coal
Costs ~ Costs
26.6
26.6
26.6
30.8
30.9
42.3
42.3
42.3
42.3
83.7
137.9
137.9
185.8
236.1
236. 1
236.1
236.1
29/.2
297.2
297.2
297.2
297.?.
297.2
297.2
297.2
297.2
5.3
5.5
5.8
7.0
7.3
9.8
10.3
10.8
6.9
7.2
7.3
9.4
11.4
13.6
15.4
17.6
18.0
20.2
22.4
11.4 24.7
20.2 30.5
31.9 35.8
33.5 40.7
44.7 40.5
56.8 54.0
59.6 59.9
62.6 65.3
65.7 71.1
81.1 77.5
85.2 84.4
89.5 92.1
93.9 100.2
98.6
103.6
100.7
114.2
119.9
109.1
JIB. 7
129.1
140.3
152.5
New Hydroelectric
Costs
Investment llM&R
Cost.L__ fasts
Transmission
Systems
Investment OM&R
Costs Costs
0.2
0.2
0.2
0.2
0.2
0.2
0.2
4.4
4.4
4.4
4.4
29.7
29.7
29.7
29;7
29.7
29.7
29.7
29.7
29.7
29.7
29.7
29.7
29.7
29.7
29.7
29.7
29.7
29.7
29.7
29.7
29.7
29.7
0.2
0.2
0.2
0.2
0.2
0.2
0.2
1.2
1.3
1.4
1.5
3.2
3.4
3.5
3.7
3.9
4.1
4.3
4.5
4.7
5.0
5.2
5.5
5.7
6.0
6.3
6.7
7.0
7.3
7.7
8.1
(l,!i
8.9
Total
Investment
Costs
31.0
31.0
31.0
35.2
60.6
72.0
72.0
72.0
72.0
113.4
1p7 .6
167.6
215.5
265.8
265.8
265.6'
265.8
326.9
325.9
326.9
326.9
326.9
326.9
326.9
326.9
326.9
Total
System
Costs ,_1
30.9
34.2
37.8
41.0
43.9
43.2
41.3
79.2
79.6
60.5
87.0
118. 1
131.8
136.1
135.7
,140.1
197.8
268.5
274.0
319.5
388.1
397.1
406.2
415,6
494.3
505.7
518.2
526.1
541.9
556.9
572.8
590.0
608.2
Tota 1 Sys tern
Consumption,
MHKWH
804
862
916
970
1024
1078
1132
1193
1254_
1315
1376
1437
1505
1573
1641
1709
1777
1859
1941
2023
2105
2187
2229
2270
2312
2353
2395
2437
2478
2520
2561
2603
2ii45
Average Power
Costs; (!KWH
3.8
4.0
4.1
4.2
4.3
4.0
3.6·
6.6
6.3
6.1
6.3
8.2
8.7
8.6
8.3
8.2
11.1
14.4
14.1"
15.8
18.4
18.2
16.2
18.3
21.4
21.5
21.6
21.7
21.9
22.1
22.4
22.7
23.0
TABLE 4.29. fajrbanks-Tanana Valley Area, Medium Growth Scenario, Case 3, 0% Inflation
Total Cost
of Existing
Year Capacl ty
78-79
79-80
80-81
81-82
82-83
SJ-84
84-85
85-86
66-87
87-88
88-89
89-90
90-91
91-92
92-93
93-94
:14-95
95-96
96-97
97-39
98-99
99-2000
00-01
01-02
02-03
03-04
0-1-05
05-06
06-07
07-08
08-09
09-10
10-11
33.8
36.6
39.4
41.6
35.6
33.1
30.3
28.2
26.1
24,0
22.9
23.1
20.9
21.1
18.2
13.4
18.5
16.9
14.3
3.7
3.7
3.7
3.8
3.8
1.5
1.5
1.5
_New Coal f1 red Capacity
Investment OM&R . Coa 1
Costs ~ Costs
18<9
18.9
18.9
21.5
21.5
27.6
27.6
27.6
27.6
27.6
32.3
32.3
51.2
51.2
51.2
51.2
51.2
70. 1
70.1
70.1
70.1
70.1
70. 1~
70.1
70.1
70.1
3.8
3.8
3.8
4.3
4.3
5.5
5.5
5.5
5.5
5.5
6.4
6.4
10.2
10.2
10.2
10.2
10.2
14.0
14.0
14.0
14.0
14.0
14.0
14.0
14.0
14.0
6.9
7.2
7.3
9.4
10.9
12.4
13.3
14.5
19.1
15.2
16.0
16.9
13.6
13.9
15.6
18.7
13.0
13.6
14.4
15.3
16.1
17.1
18.1
19.2
20.2
21.3
22.4
23.6
24.7
New llydroelectl'lc
Costs
Investment OM&R
Costs ~
34.4
34.4
34.4
34.4
45.9
45.9
45.9
45.9
45.9
45.9
45.9
45.9
45.9
45.9
45.9
45.9
45.9
0.1
0.1
-o. 1
0.1
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
(\2
0.2
0.2
0.2
0.2
Transmission
Systems
Investment OM&R
Costs Costs
0.3
0~3
0.3.
0.3
0.3
0.3
0.3
3.5
3.5
3.5
3,5
18.8
18.0
18.8
18.8
18.0
18.8
16.8
16.8'
18.0
]8.8
10.0
10.0
18.8
10.8
18.8
18.0
18.8
18.8
18.8
10.8
]9.8
]8.8
0.2
0.2
0.2
0.2
0.2
0.2
0.2
1.0
1.0
1.0
1.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
Total
Investment
Costs
22.4
22.4
22.4
25.0
40.3
46.4
46.4
26.4
46.4
80.8
85.5
85.4
104.4
115.9
115.9
115.9
115.9
134.0
134.8
134.8
134.8
134.8
134.8
134.8
134.8
134.8
Total
System
Costs, $
34.2.
37.0
39.0
42.1
43.0
40.8
38.1
64.9
64.2
63.7
66.6
84.2
89.0
90.2
88.2
89.2
. 120.5
124.6
124.0
139.2
145.1
145.7
146.5
147.4
168.6
169.6
170.6
170.2
171.2
172.3
173.4
174.6
175.7
Total System
Consumption,
HI-IKWII
804
862.
916
970
1024
1078
1132
1193
1254
1315
1376
1437
1505
1573
1641
1709
1777
1659
1941
2023
2105
2107
2229
2270
2312
2353
2395
2437
2470
2520
2561
2603
2645
Average Power
Costs, UKIIII
4.3
4.3
4.3
4.3
4.2
3.8
3.~.
5.4
5.1
4.8
4.8
5.8
5.9
5.7
5.4
5.2
6.8
6.7
6.4
6.9
6.9
6.7
6.6
6.5
7.3
7.2
7.1
7.0
6.9
6.8
6.0
6.7
6.6
Year
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
86-87
87-88
80-89
89-90
90-91
91-92
92~93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-07
07-08
08-09
09-10
10-11
TABLE 4.30. Fairbanks-Tanana Valley Area, Medium Growth Scenario, Case 3, 5% Inflation
Total Cost
of Existing
Capacl ty
30.5
33.9
37.4
40.7
36.6
35.6
33.5
32.3
30.4
28.7
27.9
29.3
28.4
30.1
26.7
28.1
29.5
28.8
27.7
6.15
6.4
6.6
7 .o
7.3
2.7
2.8
2.9
New Coal Fired Capacity
Investment OM&R Coal
Costs Costs Costs
26.6
26.6
26.6
30.8
30.9
42.3
42.3
42.3
42.3
42.2
53.0
53.0
100.9
100.9
100.9
100.9
100.9
162.0
162.0
162.0
162.0
162.0
162.0
162.0
162.0
16?..0
5.3
5.5
5.8
7.0
7.3
9.8
10.3
10.8
11.4
11.9
14.7
15.4
25.7
26.9
20.3
29.7
31.2
44.9
41. l
49.5
51.9
5~. 6
57.3
60.2
63.2
66.4
6.9
7.2
7.3
9.4
11.4
13.6
15.4
17.6
18.0
20.2
22.4
24.7
20.9
22.6
26.5
33.2
24.4
26.4
29.5
32.0
~6.6
40.6
45. I
50.0
55.3
61.2
67.5
74.5
82.1
tlt!w llydroe 1 ectr1 c
Costs
Jnvestment"OM&R
. Costs_ ~
72.5
72.5
72.5
72.5
101.8
101.8
101.8
101.8
101.8
101.8
101.8
101.8
101.8
101.8
101.8
101.8
101.8
0.2
0.3
0.3
0.3
0.7
0. 7
0.0
0.8
0.9
0.9
1.0
1.0
1.1
1.1
1.2
1.2
1.3
Trilnsmi ss ion
~stems lnvestmcn~t~"O~M&~Rc-
Costs Costs
0.2
0.2
0.2
0.2
0.2
0.2
0.2
4.4
4.4
4.4
4.4
29.7
29.7
29.7
29.7
29.7
29.7
29.7
29.7 .
29.7
29.7
29.7
29.7
29.7
20.7
29.7
29.7
29.7
29;7
29.7
29.7
29.7
29.7
0.2
0.2
0.2
0.2
0.2
0.2
0.2
1.2
1.3
1.4
1.5
3.2
3.4
3.!i
3.7
3.9
4.1
4.3
4.5
4.7
4.9
5.2
5.5
5.7
6.1
6.4
6.7
7.0
7.3
7.7
8.7
8.5
0.9
Total
Investment
Costs
31.0
31.0
31.0
35.2
60.6
72.0 .
72.0
72.0
72.0
144.4
155.2
155.2
203.1
232.4
232.4
232.4
232.4
293.5
293.5
293.5
293.5
293.5
293.5
293.5
293.5
?93.5
Total
System
Costs, $
30.9
34.2
37.8
41.0
43.9
43.2
41.3
79.2
79.6
80.5
87.0
118.1
131.8
136.1
135.7
140 .I
211.2
. 225.9
229.6
273.1
295.7
299.6
305.1
310.2
384.7
391.3
393.7
403.4
411.0
420.6
430.5
440.9
452.2
Total System
Consumption,
1-'.MKWII
804
662
916
970
1024
1078
1132
1193
1254
1315'
1376
1437
1505
1573
1641
1709
1777
1859
1941
2023
2105
2137
2229
2270
2312
2353
2395
2437
2478
2520
2561
2603
2645
Average Power
Costs, t/KWH
3.8
4.0
4.1
4.2
4.3
4.0
3.6
6.6
6.3
6.1
6.3
8.2
8.7
8.6
8.3
8.2
11.8
12.1
11.8
13.5
14.0
13.7
13.7
13.7
16.6
16.6
16.6
16.6
. 16.6
16.1
16.0
16.9
17.1
TABLE 4.31. Fairbanks-Tanana Va 11 ey Area, lligh Growth Scenario, Case 1, 0% Inflation
New Hydroelectric _ Transmission
Total Cost New Coal Fired CaQaC~ Costs S~stems Total Total Total System
of Existing Investment OM&R Coa Investment OM&R Investment OM&R Investment System Consumption, Average Power
~ Ca~acl tl Costs Costs Costs Costs c.osts Costs Costs Costs Costs! 1 Ml~KWH Costs, t/KWH
78-79 38.8 0.3 0.2 34.2 832 4.1
79-80 '36.6 0.3 0.2 37.0 903 4.1
80-81 39.4 0.3 0.2 39.8 931 4.1
81-82 41.7 0.3 0.2 42.1 1059 4.0
82-83 35.7 6.9 0.3 0.2 43.0 1137 3.8
83-84 33.2 7.2 0.3 0.2 40.8 1215 3.4
3~-35 30.4 13.9 3.8 9.1 3.5 1.0 22.4 66.7 1294 5.2
85-86 28.3 18.0 3.8 10.6 3.5 1.0 22.4 66.2 1396 4.7
86-87 26.1 37.8 7.6 12.1 3.5 1.0 41.3 88.2 1498 5.9
87-88 24.1 37.8 7.6 15.6 3.5 1.0 41.3 89.7 1600 5.6
88-89 22.9 40.4 8.1 17.2 3.5 1.0 43.9 93.1 1702 5.5
89-90 23.1 59.3 11.9 18.7 3.5 1.0 62.8 117.6 1605 6.5
90-91 20.9 65.4 13.1 • 20.5 3.5 1.0 68.9 124.4 1927 6.'5 _, 91-92 21.1 65.4 13.1 22.5 3.5 1.0 68.9 126.7 2049 6.2 0 co 92-93 18.3 64.3 16.9 24.6 3.5 1.0 07.8 148.7 2172 6.8
93-94 18.4 84.3 16.9 26.8 3.5 1.0 87.8 150.9 2294 6.6
94-95 18.5 103.2 20.7 28.0 5.3 1.8 108.5 170.3 2417 7.4
95-96 16.9 107.9 21.6 31.5 5.3 1.6 113.2 85.0 2585 7.2
96-97 14.4 126.8 25.4 34.6 5.3 1.8 132.1 208.5 2754 7.6
97-98 3.8 155;5 31.1 39.5 5.3 1.8 160.8 237.0 2922 8·.1
98-99 3.8 184.2 36.8 42.4 5.3 1.8 189.5 274.4 3091 8.9
99-2000 3.8 184.2 36.8 45.8 5.3 1.8 109.5 286.7 3260 8.8
00-01 3.8 184.2 36.8 48.5 5.3 1.8 189.5 200.4 3395 8.3
01-02 3.8 1il4.2 36.8 51.5 5.3 1.8 189.5 203.4 3531 8.0
02-03 1.5 184.2 36.8 54.3 5.3 1.8 189.5 2!13.9 3667 7.7
03-04 1.5 212.9 42.5 57.6 5.3 1.8 218.2 321.6 3803 8.5
04-05 1.5 212.9 42.5 60.9 5.3 1.8 218.2 324.9 3939 8.2
05-06 212.9 42.5 64.3 5.3 1.8 218.2 326.8 4074 8.(}
06-07 212.9 42.5 67.7 5.3 1.8 218.2 330.2 4210 7.8
07-08 241.6 48.2 71.3 7.1 2.6 248.7 37(}.8 4346 8.5
08-09 241.6 48.2 74.9 7.1 2.6 248.7 374.4 4481 8.4 . 09-10 241.6 48.2 78.7 7.1 2.6 248.7 . 378.2 4617 8.2
10-11 241.6 48.2 82.6 7.1 2.6 248.7 382.1 4753 8.0
_.
C)
tO
70-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
05-87
87-88
88-89
89-90
90-'ll
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-07
07-08
OB-09
09-10
lO-ll
TABLE 4.32. Fairbanks-Tanana Valley Area, High Growth Scenario, Case 1, 5% Inflation
Tota 1 Cost
of £x1sting
Capac1 ty
30.6
33.9
37.5
40.7
36.7
35.6
33.6
32.4
30.4
28.7
27.9
29.4
28.5
30. I
26.8
28.1
29.6
28.8
25.7
6.2
6.4
6. 7
7.0
7.3
2.7
2.8
2.9
New Coal Fir&~ Capac~
JiiVestment (i~f Coal
Costs Costs Cos t_s _
25.4
25.4
43.3
53.3
57.5
89.9
101.3
101.3
136.8
138.0
100.2
191.0
237.6
310.2
306.4
386.4
336.4
306.4
386.4
483.7
433.7
433.7
483.7
602.0
602.0
602.0
602.0
5.0
5.2
11.0
11.5
13.0
20.1
23.2
24.3
32.9
34.6
44.5
48.9
57.9
75.2
94.0
90.7
103.7
108.8
114.3
139.3
146.3
153.6
161.2
192.8
202.5
212.6
223.2
6.9
7.2
9.1
10.6
12.7
17.1
19.8
22.7
26.1
29.9
34.6
39.2
44.3
51.0
58.9
70.0
79.3
69.3
99.5
110.7
123.1
136.6
151.5
167.6
]85.3
204.7
225.9
246.9
274.0
tk'W 11ydroe 1 ectri c
Costs
l ilves tment-Ol.f&l!-
Costs Costs
Transmission
~terns
1 nvcstmeilfOll&lr
Costs Costs
0.2
0.2
0.2.
0.2
0.2
0.2
4.4
4.4
4.4
4.4
H
4.4
4.4
4.4
4.4
4.4
8.4
8.4
8.4
8.4
8.4
8.4
8.4
. ll.4
8.4
8.4
8.4
8.4
8.4
16.5
16.5
16.5
16.5
0.2
0.2
0.2
0.2
0.2
0.2
1.2
1.3
1'.3
1.4
1.5
1.6
1.7
1.7
1.8
1.9
3.6
3.8
4.0
4.3
4.6
4.8
5.1
5.3
5.6
5.8
6.0
6.3
6.7
10.2
10.5
10.9
11.4
Total
Investment
Costs
29.8
29.8
57.7
57.7
61.9
94.3
105.7
105.7
143.2
143.2
188.6
199.4
246.0
318.6
394.8
394.8
394.8
394.8
394.8
492.1
492.1
492.1
492 .. 1
618.5
618,5
618.5
618.5
Total
System
Costs, $
30.9
34.2
37.8
41.0
43.9
43.2
78.8
79.4
113.2
116.5
124.1
168.1
165.3
191.7
239.3
247.0
310.7
331.9
392.5
474.3
,579.2
594.3
610.1
626.9
640.5
776.6
790.8
019.6
845.3
1026.2
1057.4
1090.9
1127.1
Totd1 System
Consumption,
1-'oMKWil
832
903
081
1059
1137
1215
1294
1396
1498
1600
1702
1805
1927
2049
2172
2294
2417
2505.
2754
2922
3091
3260
3396
35.11
3667
3803
3939
4074
4210
4346
4431
4617
4753
Average Power
Costs, t/K\.111
3.7
3.8
3.9
3.9
3.9
3.6
6.1
5.7
7.6
7.3
7.3
9.3
9.6
9.4
11.0
10.8
12.8
12.8
14.2
16.2
18.7
18.2
17.9
17.7
17.5
20.4
20~ 3
20.1
20.1
23.6
23.6
23.6
23.7
__, __,
0
TABLE 4.33. Fairbanks-Tanana Valley Area, High Growth Scenario, Case 2, 0% Inflation
Total Cost
of Existing
~ Capacity
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-86
86-87
87-88
88-89
69-90
90-91
91-92
92-93
93-94
9-1-95
95-96
96-97
97-98
98-99
99-2000
00-01
Ol-02
02-03
03-04
04-05
05-06
06-07
07-08
08-09
09-10
10-11
33.8
36.6
39.4
41.7
35.7
33.2
30.4
28.3
26.1
24.0
22.9
23.1
20.9
21.1
18.2
18.4
18.5
16.9
14.3
3.7
3.7
3.7
3.8
3.8
1.5
1.5
1.5
New Coal fired Capacity
Investment OH&R Coal
Costs Costs Costs
13.9
18.0
16.9
18.9
21.5
21.5
27.6
27.6
65.4
64.3
64.3
107.9
126.8
155.5
155.5
155.5
155.5
155.5
155.5
164.2
212.9
212.9
212.9
212.9
212.9
212.9
212.9
3.6
3.8
3.6
3.8
4.3
4.3
5.5
5.5
13.1
16.9
16.9
21.6
25.4
31.1
31.1
31.1
31.1
31. I
31.1
36.8
42.5
42.5
42.5
42.5
42.5
42.5
42.5
6.9
7.2
9.1
10.6
12. 1
13.7
15.0
15.4
14.1
15.2
20.2.
26.3
28.8
31.5
34.8
39.5
42.4
45.8
48.4
51.5
54.3
57.5
60.6
64.2
67.7
71.3
74.9
78.7
82.5
New llydroelectric
Costs
Jnvastwent OM&R
Costs ~
Transmission
Systems
Investment OM&R
Costs Costs
0.3
0.3
0.3
0.3
0.3
0.3
3.5
3.5
16.8
16.8
18.8
·18.8
10.8
18.8
18 .. 8
18.8
18.8
20.6
20.6
20.6
20.6
20.6
20.6
20.6
20.6
. 20.6
20.6
20.6
20.6
20.6
20.6
20.6
20.6
0.2
0.2
0.2
0.2
0.2
0.2
1.0
1.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.8
2.8
2.8
2.6
2.8
2.8
2.8
2.8
2.1l
2.1l
2.8
2.8
2.6
2.8
2.1l
2.1l
Total
Investment
Costs
22.4
22.4
37.7
37.7
40.3
40.3
46.4
46.4
ll4.2
103.1
103.1
128.5
147.4
176. 1
176.1
176.1
176.1
176.1
176.1
204.8
233.5
233.5
233.5
233.5
233.5
233.5
233.5
Total
System
Costs, $
34.2
37.0
39.8
42.1
43.0
40.8
66.7
66.2
1!1.8
81.3
64.6
ll5.2
89.0
90.2
137 .a
166.8
. 169.4
20i.3
224.8
253.4
256.3
259.7
262.3
265.3
265.0
303.5
341.2
343.1
346.5
350.1
353.7
357.5
361.4
Total System
Consumption,
MtmtH
832
903
981
1059
1137
1215
1294
1396
1498
1600
1702
11!05
1927
2049
2172
2294
2417
2505
2754
2922
3091
3260
3396
3531
3667
3803
3939
4074
4210
4346
4481
4617
4753
Average Power
Costs , c/ KWH
4.1
4.1
4.1
4.0
3.8
3.4
5.2
4.7
5.5
5.1
5.0
4.7
4.6
4.4
6.3
7.3
7.0
7.1l
8.2
0.7
6.3
8.0
7.7
7.5
7.2
8.0
0.7
8.4
8.2
8.1
7.9
7.7
7.6
...
TABLE 4.34. Fairbanks-Tanana Valley Area, High Growth Scenario, Case 2, 5% Inflation
Total Cost
of Exl~ting
Year ~d!Y__-
78-79
79-80
80-81
81-02
82-83
83-84
84-85
85-86
86-87
07-88
88-89
89-90 .
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
9B-99
99-2000
00-01
01-02
02-03
03-04
04-05
05-06
06-07
07-08
08-09
09-10
lO-ll
30.6
33.9
37.5
40.7
36.7
-35.6
33.6
32.4
30.4
28.7
21.9
29.3
28.4
30. l
26.7
28.1
29.5
28.8
27.7
6.1
6.4
6.6
7.0
7.3
2.7
2.8
2.9
New Coa 1 Ft red Ca~t ty
loves fiiieiit--ru.oor-coa I
___fQlli____ Costs Costs
25.4
25.4
25.4
25.4
29.6
29.6
41.0
41.0
116.0
155.4
155.4
209.6
256.2
328.8
328,8
328.6
328.8
328.8
328.8
426.1
528.3
528.3
523.3
528.3
528.3
520.3
528.3
5.0
5.2
5.5
5.8
7.0
7.3
9.8
10.3
25.6
34.7
36.4
48.9
60.3
77.7
01.6
85.7
89.9
94.5
99.2
123.4
149.9
157.4
165.3
173.5
182.2
191.3
200.9
6.9
7.2
9.1
10.6
12.7
14.9
17.2
18.7
18.0
20.2
28.3
38.4
44.3
51.0
58.9
70.7
79.3
89.2
99.5
110.6
123.1
136.6
151.5
167.6
lll5. 3
204.7
225.0
240.9
274.0
New Hydroelectric
Costs
Tnves finent.,-OM&R
_Costs___ Costs
Transmission
Systems
Investment OM&R
Costs Costs
0.2
0.2
0.2
0.2
0.2
0.2
4.4
4.4
26.3
26.3
26,3
26.3
26.3
26.3
26.3
26.3
26.3
30.4
30.4
30.4
30.4
30.4
30.4
30.4
30.4
30.4
30.4
30.4
30.4
30.4
30.4
30.4
30.4
0.2
0.2
0.2
0.2
0.2
0.2
1.2
1.3
2.8
2.9
3.1
3.2
3.4
3.6
3.7
3.9
4.1
6.0
6.3
6.6
6.9
7.3
7.7
8.1
8.5
8.9
9.3
9.8
10.3
10.8
11.4
11.9
12.5
Total
Investmer.t
Costs ;. •
29.8
29.6
51.7
51.7
55.9
55.9
67.3
67.3
142.3
181.7
181.7
240.0
266.6
359.2
359.2
359.2
359.2
359.2
359.2
456.5
558.7
556.7
556.7
550.7
556.7
550.7
558.7
Total
System
Costs, ~
30.9
34.2
37.8
41.0
43.9
43.2
78.8
79.4 •
103.3
104.1
111.2
114.6
127.1
131.5
226.8
286.9
296.2
374.8
439.8
519.7
533.5
548.1
563,3
579.7
592.7
. 720.2
fl72.3
393.5
919.6
947.7
978.1
1010.0
10~6.1
Total System
Consumption,
MHKWfl
832
903
1 9!11
1059
1137
1215
1294
1396
1498 -
1600
1702
1805
1927
2049
2172
2294
2417
2585
2754
2922
3091
3260
3396
3531
3667
3003
3939
4074
4210
4346
4401
4617
4753
Average Power
Costs, ¢/KWH
3.7
3.8
3.9
3.9
3.9
3.6
6.1
5.7
6.9
6.5
6.5
6.3
6.6
6.4
10.4
1?..5
12.3
14.5
16.0
17.8
17.3
16.8
16.6
16.4
16.2
19,2
22.1
21.9
21.8
21.8
21.8
21.9
22.0
TABLE 4.35. Fairbanks-Tanana Valley Area, High Growth Scenario, Case 3, 0% Inflation •
Total Cost
of Ex1stlng
~ Capacity
78-79
79-80
80-81
81-82
82-83
83-84
84-85
85-85
86-87
87-88
08-89
89-90
90-91
91-92
92-93
93-94
94-95
95-96
96-97
97-98
98-99
99-2000
00-01
01-02
02-03
03-04
0•1-05
05-06
06-07
07-0il
00-09
09-10
10-11
38.8
36.6
39.4
41.7
35.7
33.2
30.4
28.3
26.1
24.0
22.9
23.1
20.9
21.1
18.2
18.4
18.5
16.9
14.4
3.8
3.3
3.8
3.8
3.3
1.5
1.5
1.5
New Coal Fired Capacity
Investment ON&R . Coal
Costs Cp.sts Costs_
13.9
18.0
18.9
18.9
21.5
21.5
27.6
27.6
65.4
34.3
114.3
39.0
119.0
09.0
39.0
139.0
107.9
126.8
126.8
155.5
155.5
155.5
155.5
155.5
155.5
10·1.2
lll4. 2
6.9
7.2.
3.8.. 9.1
3.8 10.6
3.8 12.1
3.0 13.7
• 4.3 15.0
4.3
5.5
5.5
13.1
16.9
16.9
17.8
17.8
17.0
17.0
17.8
21.6
25.4
25.4
31.1
31.1
31.1
31.1
31.1
31.1
36.0
36.0
15.4
14.1
15 .. 2
20.2
26.3
22.6
24.4
27.4
32.0
23.4
30.6
33.0
35.7
38.3
41.2
45.6
47.2
50.3
53.5
56.0
60.2
63.7.
New llyd1'oe 1 ectrl c
Cost5
Investment OM&R
Costs Costs
29.0
29.0
29.0
29.0
.38.7
213.7
38.7
38.7
3B.7
30.7
38.7
38.7
30.7
30.7
30.7
38.7
33.7
0.1
0.1
0.1
0.1
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2.
Trans1nlssion
Systems
Investment OM&R
Costs Costs
0.3
0.3
0.3
0.3
0.3
0.3
3.5
3.5
18.8
18.8
18.8
18.8
18.8
IB.Il
18.6
18.8
18.8
18.8
18.8
18.8
20.6
20.6
20.6
20.6
20.6
20.6
20.6
20.6
20.6
20.6
20.6
20.6
20.6
0.2
0.2
0.2
0.'2
0.2
0.2
1.0
1.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.8
2.!!
2.0
2.8
2.0
2.8
2.0
2.8
2.8
2.3
2.3
2.8
Total
Investment
Costs
22.4
22.4
37.7
37.7
40.3
40.3
46.4
46.4
04.2
103.1
132.1
136.8
136.8
136.0
140.3
146.3
167.2
106. 1
1136. 1
214.0
214.0
214.tl
21UJ
214.0
214.0
2.43. 5
243.5
Total
System
Costs, $
34.2
37.0
39.8
42.1
43.0
40.8
66.7
66.2
81.8
81.3
84.6
85.2
89.0
90.2
137.8
166.8
192.2
1911.0
190.5
192.5
201.3
203.5
220.6 .
254.0
254.3
291.6
296.0
296.1
2!)9.2
302,4
305.7
~43.\i
3U.O
Total System
Consumption,
MMK',-IH
832
903
931
1059
1137
1215
1294
1396
1498
1600"
1702
1805
1927
2049.
2172
2294
2417
2585
2754
2922
3091
3?.60
3396
3531
3G67
3803
3939
4074
41!10
4346
4481
4617
4753
Average Power
Costs, ¢/Kiill
4.1
4.1
4.1
4.0
3.8
3.4
5.2
4.7
5.5
5.1
5.0
4.7
4.6
4.4
6.3
7.3
7.9
7.7
7.2
6.6
6.5
6.2
6.7
7.2
6.9
7.7
7.5
7.3
7.1
7.0
6.6
., .4
7.3
_. _.
w
78-79
79-BO
80-81
81-82
82-83
83-84
84-85
85-86
86-87
87-88
88-89
89-90
90-91
91-92
92-93
93-94
9~-95
95-96
96-97
97-98
98-99
99-2000
00-01
Ol-02
02-03
03-CJ4
04-05
05-06
06-07
07-08
08-09
09-10
10-ll
TABLE 4.36. Fairbanks-Tanana Valley Area, High Growth Scenario, Case 3, 5% Inflation
Total Cost
of Existing
Capac! ty
30.6
33.9
37;5
40.7
36.7
35.6
33.6
32.4
30.4
28.7
27.9
29.3
28.4
30.1
26.7
28.1
29.6
28.8
27.7
6.2
6.4
6.7
7.0
7.3
2.7
2.8
2.9
New Coa 1 FJr~ Capac! ty_
Investment OM&R Coal
Costs Costs Cos li___
25.4
25.4 •
25.4
25.4
29.6
29.6
41.0
41.0
116.0
155.4
155.4
166.2
166.2
166.2
166.2
166.2
224.4
202.6
282:6
380.0
380.0
380.0
380.0
360.0
300.0
510.4
510.4
5.0
5.2
5.5
5.8
7 .o
7.3
9.8
10.3
25.6
34.7
36.4
40.3
42.3
44.5
46.7
49.1
62.4
77.0
80.9
104.2
109.5
114.9
120.7
126.7
133.0
165.5
173.7
6.9
7.2
9.1
10.6
12.7
14.9
17.2
16.7
18.0 .
20.2
28.3
36.4
34.8
39.5
46.4
56.7
53.1
59.6
67.8
76.7
8li.7
97.7
113.6
123.0
137.6
153.7
171.3
190.5
211.5
New llydroelectrlc
· Costs
lnvestm~OM&R
Costs Cos~t
61.0
61.0
61.0
61.0
85.7
85.7
85.7
85.7
85.7
85.7
85.7
85.7
05.7
85.7
85.7
85.7
85.7
0.3
0.3
0.3
0.3
0. 7
0.7
0.8
0.8
0.8
0.9
0.9
1.0
1.0
l.1
1.1
1.2
1.3
Transmission
-~stems I nv es tm-"-en"-'t::=.."O-;-;:M&""R:-
Costs Costs
0.2
0.2
0.2
0.2
0.2
0.2
4.4
4.4
26.3
26.3
26.3
26.3
26.3
26.3
26.3
26.3
26.3
26.3
26.3
26.3
30.5
30.5
30.5
30.5
30.5
30.5
30.5
30.5
30.5
30.5
30.5
30.5
30.5
0.2
0.2
0.2
0.2
0.2
0.2
1.2
1.3
2.8
2.9
3.1
3.2
3.4
3.6
3.7
3.9
4.1
4.3
4.5
4. 7
6.8
7.1
7.5
7.8
8.2
8.6
9.1
9.5
10.0
10.5
11.0
11.6
12.2
Tot<~ I
Investment
Costs
29.8
29.8
51.7
51.7
55.9
55.9
67.3
67.3
142.3
181.7
242.7
253.5
253.5
253.5
202.4
282.4
340.6
398.8
398.0
496.2
496.2
496.2
496.2
496.2
496.2
626.6
626.4
. .Tot a 1
System
Costs, $
.
30.9
34.2
37.8
41.0
43.9
43.2
78.8
79.4
103.3
104.1
111.2
114.6
127.1
131.5
226.8
286.9
347.9
366.7
374.7
365.9
396.1
qos.6
486.1
568.4
570.1
710.4
732.2
744.6
765.5
788.2
812.6
995.4
1025.3
Total System
Con~um;~tlon,
NMKWH .
832
903
981
1059
1137
1215
1294
1396
1498
1600
1702
1605
1927
2049
2172
2294
2417
2585
2754
2922
:l091
3260
3396
3531
3667
3803
3939
4074
4210
4346
4481
4617
4]!;3
Average Power
'Cos.t s, ¢/KWII
3.7
3.8
3.9
3.9
3.9
3.6
6.1
5.7
6.9
6.5
6.5
6.3
6.6
6.4
10.4
12.5
14.4
14.2
13.6
12.5
12.8
12.4
14.3
16.1
15.8
18.7
10.6
18.3
18.2
18.1
18.1
21.6
21.6
' All entries in the tables are in millions of dollars unless noted. The first
column is the total cost of the existing capacity. This includes investment,
OM&R, and fuel costs except coal costs after 1982-1983 as noted below. This
column includes the cost of the combustion turbine units planned tnrough 1984
in the Anchorage area. The cost of existing capacity is assumed to be the
same for all load growth scenarios and system configurations. This assumption
is warrented in this case for two reasons. First, an examination of the load
resource analyses for the alternative load growth scenarios and cases reveals
relatively little variation in the plant utilization factors among the various
scenarios and cases. Second, the cost of operating the existing capacity is a
relatively small part of the overall system costs in the 1990-2010 time period
which is of primary interest in this report.
The next three columns present the. costs· for the new coal-fired capacity.
The investment cost is the total of all the individual plant investments. The
OM&R costs are the sum of all the OM&R costs of the individual plants. Entries
in these two columns begin the same year as the first coal-fired plant·comes
on line. The coal costs include the coal costs of the new coal-fired capacity.
In addition, the coal costs of the existing capacity are included in this
column after 1982-1983. (It is subtracted aut of the existing capacity after
1982-1983. )
The next twa columns present the costs for any new hydroelectric capacity
that is added. These are the Bradley Lake project, the Watana dam and the
Devil Canyon dam. As painted out earlier the Watana and Devil Canyon costs .
are divided between the Anchorage-Cook Inlet area. and the Fairbanks-Tanana
area in proportion to their relative energy consumption in 1994.
The transmission system costs are shown in the next two columns. These
columns contain the investment and OM&R costs for all the transmission lines
required. The total investment cost column represents the sum of the new coal-
fired capacity investment costs, the hydroelectric capacity investment costs,
and the transmission system investment costs.
The total system cost is the sum of all the costs (not including the new
investment cost column). The total system consumption figures are the same as
114
,,
,,
J
/!
I
/'
/!
l
the energy demand forecasts presented in Chapter 3. The average cost of power
in the total system costs divided by the total system consumption.
The costs of power for the 5% inflation cases are· presented in Figures 4.5
)
~hrough 4.10. While the power costs are different (lower) for the 0% inflation
cases. The relationships among the various cases are the same for beth infla-
tion rates.
For the Anchorage-Cook Inlet load center construction of the interconnec-
tion (Case 2) reduces the cost of power com~ared to the case 1-1ithout an inter-
connection (Case 1). In general, construction of the interconnection also
reduces the total investment costs.
For the Anchorage-Cook Inlet area inclusion of the Upper Susitna project
into the system (Case 3) generally raises the cost of power above Cases 1 and
2 during the first 2 to 4 years after the Watana Dam comes on 1 ine· but results
in lower power costs during the 1996-2010 time period. This reduction in the
cost of power is significant in most cases. The addition of the Upper Susitna
project appears to slightly increase the totai investment costs for the
Anchora-ge-Cqok Inlet area although this varies from year to year. ·
For the Fairbanks~Tanana Valley load center construction of the inter-
connection (Case 2) again generally reduces the cost of power compared to the
case without an interconnection (Case 1). In general, construction of the
interconnection also reduces the total investment costs.
Fer the Fairbanks-Tanana Valley load center inclusion of the Upper Susitna
project (Case 3) generally raises the cast of power above Case 2 for about
Z years after the \.Jatana Dam comes on line but, as with the Anchorage-Cook
Inlet area~ results in lower power costs during the 1996-2010 time period.
The addition of the Upper Susitna. project appears to slightly lower the total
investment cost.
In some of the scenarios it is difficult to determine which case resul:i.:s
in the lowest total investment or ~he lowest cost of power over the entir,/
1978-2010 time period by looking at the tables or figures. One method of(com-
' paring investment or cost over a period of years is to compute the presenV
worth. In equation-form:
115
I
~
l
30
28
26
24
22
..c:: 20
s:
~ -18 ~ -c:
Q.)
u 16 -(,I')
I-
(,I')
0 14 u
~
L.U 12 s:
0
0..
10
8
6
4
2
1985 1990 <,
. . . . . .
1995
.... .~········ ........................ ········· ...
2000
--CASE 1
=---CASE 2
-............. CASE 3
2005 2010
FIGURE 4.5. Power Costs for Anchorage Low Load Growth Scenario
116
30
28
26
24
22
..c::: 20
5
~ -18 V1 -c:
Q.)
~ 16 (/)
1-
(/)
0 14 u
0:::
l..i.J
5 12 0 a..
10
8
6
4
2
1985 1990 1995 2000
.. . . .····•········
. ···········•· .
. .
CASE 1
---CASE 2
·••••••• .. CASE 3
2005 ' 2010.
FIGURE 4.6. Power Costs for Anchorage Medium Load GrO'r'lth Scenario
117
1985 1990 1995 2000 2005 2010
FIGURE 4.7. Power Costs for Anchorage High Load Growth Scenario
118
30
28
26
24
22
..c: 20
.$
~ -18 (,1') -c::
Q;)
~ 16 (./)
I-
(./)
0 14 u
•••••• I . -'( ........ . j. ,... ..··•··••·•···· ................................ .
:: I . ...... ·
: I
0::::
l..I.J 12 s
0
0...
10
8
6 --CASE 1
---CASE 2
4 ............ CASE 3
2
1985 1990 1995 2000 2005 2010
FIGURE 4.8. Power Costs for Fairbanks Low Load Growth Scenario
119
.c s: ..:::.:: -V) -....... c
Q)
~
(/')
1-
(/')
0 u
e:::
1..1..1 s:
0
0..
30
28
26
24
22
20
18
16
14
12
10
8
6
4
2
1985
J
I
I .,.-"'-' "
1990 1995
I
I
········ ..... : .··· . . . . .
2000
\
\~
--_,..,. _,..,..
······· :••••••••••••••••••••o•
CASE 1
---CASE 2
........ · ·-CASE 3
2005 2010
fiGORE'4.9. ·rawer Costs for Fairbanks t~edium Load Grm11th Scenario
120
I· .
..c:
$
.:::&. -V) --c
Q)
~
V)
!-
V)
0 u
0:::
L..I.J
$
0
0..
30
28
26
24
22
20
18
16
14
12
10
8
6
4
2
1985 1990
I
I
I
: · .. .... ll
/I
f
I
1995
,_ ___________ ___
1 r ...
I :
I. .
l:······ . ,; ............ :
....... t: ---....~:
.. ··· .:
2000
................
zoos·
CASE 1
CASE 2
CASE 3
2010
FIGURE 4.10. Power Costs for Fairbanks High Load Growth Scenario
121
i1 1
PW = .2: APC i * ---:-
l=n (l+r)i
where:
PW = Present worth of the cost of power
APCi = Average power cost in year i
r = Discount rate
n = Total number of years.
Usi~g this formula the total investment cost and the average power cost over a
period of years can be more easily compared~ A 7% discount rate is used in
these ~nalyses.
The results for each of the load growth scenarios for both of the load
centers are briefly discussed below.
Anchorage-Cook Inlet -Low Load Growth
The present worth of the total investment and the present worth of average
power costs are shown below.
Reference P. W. Total P.W. Average
Case Table No. Investment ($) Power Costs (¢/kWh)
1 2 2329 • 78
2 4 2251 76
3 6 2504 70.
Case 3 results in the lowest cost of power followed by Case 2 and Case 1.
Case 2 gives the lowest overall investment costs while Case 3 results in the
highest· investment costs.
122
Anchorage-Cook Inlet -Medium Load Growth·
Reference P.W. Total P.W. AvErage
Case Table No. Investment {$} Power Costs (t/kWh)
1 8 3920 83
2 10 3930 83
3 12 3920 77
The present worth of the total investment is almost identical for all
three cases. The present worth of the cost of power is the same for CaseE 1
and 2,_ while the present worth power cost for Case 3 is lowest.
Anchorage-Cook Inlet -High Load Growth
Reference P. W. Tota 1 P. ~~. Average
Case Table No. Investment {$) Power Costs {t/kWh)
1 14 7053 86
2 16 6837 85
3 -18 7084 83
Again Case 3 results in the lowest present worth for the cost of power.
For this scenario Case 2 results in the lowest present worth _investment with
Cases 1 and 3 slightly higher.
Fairbanks-Tanana Valley-Low Load Growth
Reference P. W. Total P.W. Average
Case Table No. Investment {$) Power Costs (¢/kWh)
1 20 666 110
2 22 699 113
3 24 742 104
Case 3 gives the lowest cost of power while Case 1 gives the lowest
investment cost. Case 3 results in the highest present worth. investment cost.
123
Case
2
3
Fairbanks-Tanana Valley -Medium
Reference P.W. Total
T?ble No. Investment ($)
26 1128
28 1042
30 970
Load Growth
P. LV. Average:
Power Costs (¢/kWh)
117
111
99
Again Case 3 results in the lowest present worth cost of power. In this
scenario however, Case 3 also gives the lowest present worth total ·investment
costs.
Fairbanks-Tanana Valle~ -High Load Grm'-lth
Reference P.i~. Total P.W. Average
Case -Table No. Investment ($) Power Costs (¢/kWh)
1 32 1642 115
2 34 1587" 110
3 36 1527 103
Again Case 3 results in the lowest present worth cost of power and the
lowest present worth total investment.
124
REFERENCES -CHAPTER 4
1. Taylor, G. A., Managerial and Engineering Economy, D. van Nostrand
Company, Inc., Princeton, NJ, 1964.
125
,.
I
I
-· ·-·· ~··-· ·.-·. · .. __ ..... .:.-·-···~--·--····-.-·-..
_, • ., :-~ ... r= J \ I ';:"' r,
\\ <:.1 .... • :EE:D~~f::! ENERGY REGULATORY COMMISSION
1! no_:-,!! /.::_,!-3$\-\q REGIONAL OFFICE \,! . ._ .• ' ...... --1
555 BATTERY STREET, ROOM 415
)"C; f.\ic!:) --il J~\ 2: 33SAN FRANCISCO, CA 94111
'.' i v i1t'tlt v
Mr. Robert J. Cross
Administrator
Department of Energy
Alaska Power Administration
P. 0. Box 50
Juneau, Alaska 99S02
Dear Mr. Cross:
March 6, 1979
__ ,_, .. ~ ....... · ..
This will respond to your letter of February 2, 1979, requesting our
informal review and comments on your Upper Susitna Project Power
Market Draft Report.
Although we were unable to make an in-depth review of the draft report
due to time and staffing limitations, we do wish to make the following
comments:
Page 95, second paragraph, third sentence. FERC estimated costs are as
of July 1, 1978, not October 1978 as stated.
Page 95, ·second paragraph, last sentence. The San Francisco Regional
Office of FERC did include cost adjustments for Alaska conditions in
its power value study as it routinely does for all studies in Alaska.
Page 95, last paragraph, last sentence. The investment cost estimates
of the Fairbanks plant are $1475/kW (@ s:7s% financing) and $1510/kW
(@ 6.875% financing). Cost estimates of the Anchorage-Kenai area
plant are $1240/kW (@ 7.94% financing) and $1220/kW (@ 6.875% financing).
Page 96, Oil and Natural Gas. Our thoughts on this subject were stated
in our October 31, 1978, letter to the District Engineer, Alaska District,
Corps of Engineers. In that letter we stated that oil-fired combined
cycle and regenerative combustion turbine plants were significantly
less costly than alternative coal-fired plants for the Upper Susitna
River Basin. We are not able to state, however, which alternative is
the more probable source. The determining factors would be the Alaska
fuel situation and the interpretation of the Fuel Use Act.
Mr. Robert J. Cross - 2 .. March 6) 1979
While the Fuel Use Act prohibits the use of oil or natural gas as
primary fuel for electrical generation, the Department of Energy,
Economic Regulatory Administration (ERA), is promulgating regulations
which will provide for various exemptions. The regulations are ex-
pected to be issued in May. We suggest that you contact ERA on this
matter.
Page 105, item 5. The retirement schedule for combustion turbine is
stated to be 20 years. Most studies.in the Continental United States
use 30 years.
Pages 159 and 160, Assessment of Feasibility. A cost estimate of
Copper Valley Electric Association's purchase of Upper Susitna power
would be useful to this discussion.
Appendix, page 21, 3.2.4, Transmission Losses. The 1.5% for energy
loss appears to be lowo
We appreciate the opportunity to review and comment on your draft
report.
Sincerely,
~~-e~
~u(~~e~lett
Regional Engineer
February 27, 1979
Mr. Robert Cross
Department of Energy
Alaska Power Administration
P. 0. Box 50
Juneau, AK 99802
Dear Mr. Cross:
Thank you for the opportunity to comment on your Draft Power Market Analysis.
Both Ward Swift and I read it over and came up with only a few minor comments.
The primary focus of our review was the consistency between the body of the
report and our background analysis presented in Appendix 3.
1. Page 4, 2nd paragraph-The alternative on-line dates of 1990, 1992,
and 1994 seem to refer to the interconnection on-line dates for high,
medium, and low load growth cases respectively. I believe those dates
should be 1986, 1989, and 1991. This would be consistent with the
dates given in the last line on page 109.
2. Page 8, Table at bottom -It appears that the costs of power listed
for Case 1 should be the same numbers listed for the Case 1 of the
combined system in the table at the top of page lll.(i.e., the costs
of power should be 6.6, 6.9, and 7.5¢/Kt~h rather than 7.0, 7.0 and
6.6¢/KWh for the high, medium, and low load growths respectively).
3. Page 17, Installed name plate capacities-As pointed out on page 19
the tot a 1 s differ from those used by us in Appendix 3. t·1ost of the
differences are relatively minor. The only major difference seems to
be the capacity listed for the Chugach Electric Association. As you
indicate these differences are due to recent changes in plans to
install new capacity. The difference would have a minor impact on the
1978 through 1985 results and practically no impact on the results
after 1985.
Mr. Robert Cross
February 27, 1979
Page 2
4. Pages 52, 59, 80, and Appendix 3 page 8-Annual.Load Factors-On
page 42 and Appendix 3, page 8, both reports are generally in agree-
ment that the annual load factor is presently between 46-52%. In
Appendix 3 we go on to say that it appears the annual load factor
will remain in the 50-52% range during the time horizon of the re-
port. On page 80 it is stated that for planning purposes it is
assumed that the annua 1 system 1 oad facltor wi 11 be in the range of
55-60% by the latter part of the century.
If the load factor is defined as:
ALF = GEN
CAP* 8.760
where:
ALF = Annual load factor (fraction)
GEN = Generation (MW)
CAP = Capacity (GVJH)
and use data for the year 2000, low load growth as presented on page 59 we
compute an annual load factor of 51%.
i.e.
ALF = 6424 =
1448 * 8.760 . 51
This is lower than the 55-60% mentioned on page 80.
5. Page 95, Healy II plant costs -It would be good to point out that the
GVEA estimate is probably in terms of 1985$.
6. Page 101-102~ Conclusions - I think your summary of the alternatives
available to Alaska is good.
Mr. Robert Cross
February 27, 1979
Page 3
7. Cover Sheet, Appendix 3-Enclosed are different cover pages for our
report presented in Appendix 3 and the Appendices to our report.
Please replace the cover pages you presently have.
Thank you for the opportunity to comment on the report.
Sincerely,
. -.-cf11 (!kob.rG-J
J. Jay Jacobsen
Energy Assessment Unit
Energy Systems Department
JJJ:tw
Enclosures
REPLY TO
ATTENTION OF:
NPAEN-PL-R
DEP~R-;FMEN:T;-OF THE ARMY AL~~~A~1r!s:J!'f~l;q-f,;G-¢>~PS OF ENGINEERS
·..J ·.~ • ''-·~' ' 1P~chi'c5l<<J,oo2
1 t IANAE;HORA.GE •. ALAjS,KA 99510
i·;:1r·\ L 1 i .. ; ;: 0L
Mr. Robert J. Cross
Administrator
Alaska.Power Administration
P.O. Box 50
Juneau, Alaska 99802
Dear Mr. Cross:
1 9 MAR 1979
I am writing to advise you of actions taken in response to your comments
on the draft Susitna Supplemental Feasibility Report and also to comment
on your draft Power Market Analysis.
Your letter of 26 January 1979 transmitting your comments on our draft·
report arrived during the final report printing. Any delay at that
point would have caused us to miss our deadline which I was unwilling
to permit except under extreme circumstances. On the verbal assurance
from your staff that there was nothing of such gravity that the integ-
rity of the report would be jeopardized, the decision was made to pro-
ceed with the printing as scheduled. ·
I regret that your written comments did not arrive sooner, because the
report would have benefited from their incorporation. I am especially
sensitive to your ~ontention.that insufficient credit was given where
APA materials were used. In the future, my staff will be more careful
in this regard.
Our review of your excellent draft Power Market Analysis has resulted
in only one comment. On page 4 you note that the more costly gravity
structure for Devil Canyon is 11 currently proposed u by the Corps. This
is inaccurate in that the gravity structure was presented to insure that
estimated costs were sufficient to cover a range of possible foundation
conditions at the Devil Canyon site. · With appropriate word changes to
correct this matter, we find nothing else requiring alteration.
Since the Main Report and Appendix Part 1 are already fn Washington, please
transmit 20 copies of the final Appendix Part 2 to HQDA (DAEN-CWP-W),
NPAEN-PL-R
Mr. Robert J. Cross 19 MAR 1979
Washington D.C. 20314; 2 copies to Division Engineer~ North Pacific
Corps of Engineers, 210 Custom House~ Portland, Oregon 97209, ATTN;
NPDPL; and the remaining 138 copies to the Alaska District, ATIN:
NPAEN~US. ·
If you have any questions, Mr. Chuck Bickley at (907) 752-5135 can pro-
vide assistance.
Sincerely yours,
~~~--~~·~.~~--~
Lt Colonel, Corps of Engineers
Acting District Engineer
2
DEPARTMENT OF THE ARMY
REPLY TO
ATTENTION OF:
NPAEN-PL-R
Mr. Robert J. Cross
Administrator
ALASKA DISTRICT, CORPS OF ENGINEERS
P.O. BOX 7002
ANCHORAGE.ALASKA 99510
Alaska Power Administration
.P.O. Box 50
Juneau, Alaska 99802
Dear Nr. Cross:
1 9 ~1AR 1919
I am writing to advise you of actions taken in response to your comments
on the draft Susitna Supplemental Feasibility Report and also to comment
on your draft Power Market Analysis.
Your letter of 26 January 1979 transmitting your comments on our: draft
report arrived during the final report printing~ Any delay at that
point would have caused us to miss our deadline which I was unwilling
to permit except under extreme ci.rcumstances. On the verbal assurance
from your staff that there was nothing of such gravity that the integ-
rity of the report· \•Jou1d be jeopardized, the decision was. made to pro-
ceed with the printing as scheduled ..
I regret that your written comments did not arrive sooner, because the
report would have ben~fited fr~« their incorporation. I am especially
sensitive to your cantention that insufficient credit was given where
APA materials were used. In the future, my staff wi11 be w~re careful
in this regard. ;·
Our review of your excellent draft Power Market Analysis has resulted
in only one comment. On page 4 you note that the more costly gravity
structure for Devil Canyon is "currently proposed" by the Corps. This
is inaccurate 1n that the gravity structure was presented to insure that
estimated costs were sufficient to cover a range. of possible foundation
conditions at the Devil Canyon site. With appropriate word changes to
correct this matter, we find nothing else requiring alteration.
Since the Main Report and Appendix Part 1 are already in Washington~94[~~
transmit 20 copies of the final Appendix Part 2 to HQDA (DAEN-CHP-~o.%
<( ~ (.) m Eo z ~ ~
"'..>-~
7?76-191\:>
NPAEN-PL-R
~1r. Robert J. Cross
Hashington D.C. 20314; 2 copies to Div1s.1on Engineer, Horth Pacific
Corps of Engineers., 210 Custom House, Portland, Oregon 97209, ATTN;
NPOPL; and the remaining 133 copies to the /\laska District, ATii·::
ilPAEN-US.
If you have any questions, t-iro Chuck Bickley at (907) 752-5135 can pro-
vide assistance.
· Sincerely yours,
~{LTC. Vemelle T. Smith
VERNELLE T. Si~ITH
Lt Colonel, Corps of Engineers
Acting District Engineer
2
., -···~-··"'~ .,.,.~ ..•• .--••-• ·•·•·-··--·•-··-••·-·--•••••·•-··~····---····-··--•·.-"-"'' -.·••••-·•·•· --• -·--•· "' ,,,,. .. ,.,._¥ ,,..-_.,,,, ••' , . .,_,_ .,..., .... , .. , ..
JAY S. HAMMOND
GOVERNOR
..:...,
INti
1
' lJ;;it
Mr. Jim Cheatham
U.S., Department. of Energy
Alaska Power Administration
· P .0. Box. 50
Juneau; AK 99801
March 23, 1979
POUCH AD-JUNEAU 99811
PHONE 465-3577
Subject: Pow~r Market Analysis -Draft on the Upper Susitna River
Project
State I.D. No. 79020902
JM/cz
COO£ 1
1CD A ·~~
1ol
~t:o
rqa; JJ:l.o
\...•-J:-M"'• /[ .
~
~ . ' .. Municipality of Anchorage
MEMORANDUM
DATE: February 15, 1979
TO: Thomas R. Stahr, Ge~~ral Manager
FROM: H. C. Purcell, Assistant Chief Engineer
SUBJECT: DOE APA UPPER SUSITNA RIVER_PROJECT POWER MARKET ANALYSES
I have reviewed the January 1979 draft of this report and find nothing controver-
sial in it. There is an error, and there are a few points I will comment on,
none of which, however, affect the conclusions reached.
On page 33, Table 5 shows AML&P generation in 1965 as 156.2 GWH. This res~lts in
area growth 1964-1965 of 34.4% and 1965-1966 growth of -0.6%. AML&P generation
in 1965 was actually 101.5 GWH. This changes the area total in 1965 to 407.0 GWH,
1964-1965 growth to 18.5% and 1965-1966 growth to 12.7%.
O"n pages 37 and 38, the report states 11
••• correlations with weather ... seem-
e~ indeterminable or of little significance.11 and 11 Energy use and weather com-
parisons were inconclusive.11 This does not agree with my work or with plain common
se·nse. Growth between 1973 and 1977 is used to forecast energy requirements. In
three of these four years, i974, 1976 and 1977, the weather was warmer than normal.
Ignoring the influence-of weather depresses the growth rate. However, this does
not affect the report materially, since it winds up using three different growth
rates (low, medium and high) in its market analyses. .
It is interesting that the situation hasn't changed in twenty years. Page 98 lists
six major hydro projects with much better economics than the Upper Susitna. But
they all remain tied up by 11 major environmental and land use problems."
On pages 100-102 the report brushes off exotic energy sources as 11 not realistic
planning alternatives ... '' I applaud this, but suspect that much more work will
have to be done to convince the vocal proponents of 11 natural energy.11
On page 104 the report specifies 11 System reserve capacity of 25 percent for non-in-
terconnected load centers and 20 percent for interconnected systems.'' I checked
these numbers against the PROBS runs I made in connection with DOE regulations on
transitional facilities. For the Anchorage area at present, PROBS showed a loss~
of load probability of 0.2 days per year with a peak load of 466.3 MW. On the ·
same basis, 25% reserve capacity would correspond to a peak load of 468.8 MW. 25%
reserve capacity would result in LOLP only slightly over 0.2 days per year. With
-the larger interconnected system ten or twelve years in the future, 20% reserve
capacity wi 11 probably pro vi de reasonable LOLP.
Page 34 of the Battelle Informal Report schedules a 200 MW steam plant to be on
line in 1982, three years hence. Yet Battelle page 22 says "the 5 to 6 year sche-
duling period [from final site selection to commercial operatic~ appears reason-
able." Either CEA is about to break-ground for its coal-fired steam plant or ·
Battelle's dates are inconsistent. Again, however, it doesn't really matter. The
relative economics of Susitna vs. coal-fired steam would ~at be affected.
,..,... l(oc::ld
Municipal LmB!;\ .) Po"'Wer
1200 EAST FIRST AVE~~UE~4f~!3R..td~S:k_asKA 99501
TE LEPHO~E;-ti90{l..27~76~ J
!,Jf::f f'll-lK -) AA 7: so
us o::-o-1. o:::-r-;.·~;;l'"''( •. '-' • ' C.d~"i•i.J
Ill ~ $!(1 ·' QowcR-A·O~. March l, 1979 ''"··' ' ,., 1 '' Ll i1.
Robert J. Cross, Administrator
Department of Energy
Alaska Power Administration
P .0. Box 50 ·
Juneau, Alaska 99802
Dear Mr. Cross:
This letter responds to your letter of February 2, 1979, which
requested informal comments on the draft Power Market Analyses
of the Upper Susitna River Project.
Mr. Stahr is out of town and I am writing without knowledge of his
personal. opinion and comments. The Municipal Light and Power's
staff comments appear in the two attached memorandums. Mr. Stahr
may forward more comments . upon his .return·.
Thank you for the opportunity to review the draft. If you have
any questions or· want more comments please do not hesitate to con-
tact us.
Very truly yours,
~rd~-·-
Max Foster.
Revenue Requirements Supervisor
MF.:bw
Enclosur.e:
PROVIDE FOR TOMORROW, SAVE ENERGY TODAY.
Municipality of Anchorage
MEMORANDUM
DATE: _March 1, 1979
TO: Thomas R. Stahr, General Manager, ML&P
FROM: Max Foster, Revenue Requirements Supervisor, ML&P
SUBJECT: DOE-APA Upper Susitna River Project
Power Market Analyses
This memo comments on the Alaska Power Administration's Upper
Susitna River Project Power Market Analysis draft dated January
1979. My impression is that the demand projections for the
Anchorage area are conservative. I also think that the installed
cost of coal plants is conservative. The Susitna project costs are
probably the most reliable cost estimates appearing in ~he report.
I am not happy with the methodology developing the cost of coal. I
think coal could actually cost much more than $1.00 to $1.50 per
million BTU. The inflation rates used in the analysis (0% and 5%)
seem low in light of recent trends.
Significantly, despite the conservative assumptions contained within
the report, the Susitna project represented the least cost option in
every case.
My page by page review of the report elicited the following
comments~
Page 37 -The lack of correlation to weather and price disburbs
me. It may indicate improper equation specification caused by
omitting important variable or failing to insert dummy
variables in the regression equations to correct for cyclical
abnormalities. Additionally, it seems to m~ demand projectio,ns '·
qy rate class would be more statistical1~y figni.ficant. Carre-/4.L:C£''17 t-.-~f~ 1""j-S-t~'3 0"1'\-a. ;-rt.(j">l--ff-tLy 1 CyC;;Ca--hcti!.J b/.J...--t.. YLc,-f: Cl.AJ1?{4.J/7 ,
Page 77 -The shape of the Anchorage Area load duration curve
suggests that a heavy proportion of generation for the area
could be large base load increments. This is very favorable
for hydroelectric development.
Page 94 - I don 1 t like the treatment of 0 & M costs. How does
this relate to present actual Anchorage labor costs and trends?
I think the prices should be measured directly, not arbitrarily
increased.
Page 150-The pipline terminal's 37.5 MW generation plant is
not. ir;tercon~cted with CVEA.__, It..,, i~ not a, cogene~r~ tion~
fac~l~ty. Jo-t-a! e..--1 er-t::::-J.._, ~r-,/'-f-,_1 yC'fTI\Cr-L"/:~"" _.! ./ 7 \ -~ ~ ' f . ' '
.-·~ .. '
..,. ~ • J "
,_, 1
Memo t9 Ttlomps R. Stahr, General Manager
March 1, 1979
Page 2
Appenq~x 3, Pages 66 to 75 -Where is the present worth or
annualized cost of power computed? This is a major change from
the earlier ECOST2 model. I think the present worth analysis
is an important part of any power cost analysis.
!rt geheral, the analysis seems complete. The conclusions echo those
of. pr~vious studies. From an economic prospective, the Susitna
Project is unquestionably justified. Its time to stop revising
Jecitsibility analyses and get on with li"cens1ng and construction. /}1'/IE?."'l
ltllf: bw
,