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Railbelt Electric Power
Alternatives Study:
Evaluation of Railbelt
Electric Energy Plans
Volume I
December 1982
Prepared for the Office of the Governor
State of Alaska
Division of Policy Development and Planning
and the Governor's Policy Review Committee
under Contract 2311204417
()Banelle
Pacific Northwest Laboratories
LEGAL NOTICE
This report was prepared by Battelle as an .account. of sponsored
research activities. Neither Sponsor nor Battelle nor any person acting
on behalf of either:.
MAKES ANY WARRANTY OR REPRESENTATION, EXPRESS OR
IMPLIED, with respect to the accuracy, completeness, or usefulness of
the information contained in this report, or that the use of any informa-
tion, apparatus, process, or composition disclosed in this report may not
infringe privately owned rights; or
Assumes any liabilities with respect tp the use of, or. for damages result-
ing from the us~ of, any information, ~pparatus, pr~cess, or composition
disclosed in this report.
JAN 1 4 1983
ALASKA RBSOURCES LT?~ARY
U.S. DEPT. OF INTERIOR
RAILBELT ELECTRIC POWER
ALTERNATIVES STUDY:
EVALUATION OF RAILBELT ELECTRIC
ENERGY PLANS
VOLUME I
J. J. Jacobsen
D. L. Brenchley
J. C. King
M. J. Scott
H. Harty
T. J. Secrest
F. H. Boness (Consultant)
J. E. Haggard (Consultant)
December 1982
Prepared for The Office of the Governor
State of Alaska
Division of Policy Development and Plann·lng
and the Governor's Policy Review Committee
under Contract 2311204417
BATTELLE
Pacific Northwest Laboratories
Richland, Washington 99352
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EXECUTIVE SUMMARY
During the next 30 years -to the year 2010 -the electrical demand in the
Railbelt region of Alaska is expected to increase from its present peak demand
of about 520 MW to between 1000 MW if low economic growth is experienced and
1760 MW if high economic growth is experi~nced. This report, Volume I,
analyzes alternative plans for meeting this growth in electricity demand. The
project was commissioned by the State of Alaska with Battelle, Pacific
Northwest Laboratories. The major effort in this project was the development
of models and forecasting methodologies and associated data bases that would
permit the State of Alaska to make its own forecasts to account for changing
economic conditions or to evaluate different scenarios. This report
illustrates the use of the models and methodologies based on economic forecasts
prevalent in January 1982.(a)
The analysis included generating resources which could potentially
contribute to meeting the electrical load over the time horizon of the study as
well as conservation and consumer-installed small-scale generating resources.
The generating resources included hydroelectric and those associated with the
use of oil, gas, coal, wind, wood waste, municipal solid waste fuels, and tidal
power. Nuclear plants were not considered because their size ranges do not
match the load growths expected. In addition, State statutes specifically
exclude nuclear energy production from the definition of power projects that
can be funded through the Power Development Fund (see Power Authority Act as
amended 4483.230(4)). Utility-scale solar thermal plants were not considered
because of high construction costs and low capacity factor during winter peak
load periods. Peat, while a potentially promising resource, was not included
because of uncertainties relative to availability and cost of fuel-grade
supplies in the Railbelt region.
(a) Because of recent rapidly changing forecasts of oil prices and consumption,
an addendum to the Executive Summary was prepared which describes the
likely effects of recent forecasts on the results in this report. Such
changes were anticipated and account for the major emphasis being placed on
methodology development rather than forecasting, so that the State of
Alaska could readily update its forecasts as economic conditions change.
iii
Six plans(a) were developed using different combinations of these
generation and conservation options:
Plan 1A -"Present Practices" Without Upper Susitna -includes the
addition of about 400 MW each of natural gas combined-cycle and coal
steam plants, and 430 MW of hydroelectric generation.
Plan 18 -"Present Practices" With Upper Susitna -includes the
first stage of Watana (680 MW) and Devil Canyon (600 MW) dams of the
Upper Susitna Project plus some natural gas combustion turbine and gas
combined-cycle capacity.
Plan 2A -"High Conservation and Renewables" Without Upper Susitna -
emphasizes conservation renewables such as refuse-derived fuels (50
MW) and wind (175 MW), as well as six smaller hydroelectric dams
(about 600 MW). Some nonrenewable resources are also required.
Plan 28 -"High Conservation and Renewables" With Upper Susitna -
includes the Upper Susitna Project and lesser quantities of the other
resources described in plan 2A.
Plan 3 -"High Coal" -is based on a transition from existing generating
technologies to alternatives that directly or indirectly use coal as a
fuel. It assumes that coal will be available from the Beluga area
before the end of the decade. A small amount ( 100 MW) of hydro-
generation is developed.
Plan 4 -"High Natural Gas" -is based upon continued use of natural gas
for generation in the Cook Inlet area, conversion to natural gas in
the Fairbanks area, and the availability of North Slope gas before the
end of the decade. As in Plan 3 a small amount of hydrogeneration is
developed.
The annual average cost of power for the six plans is shown in the
following figure. It is difficult to discern from the figure which plan has
the lowest costs. It is clear, however, that the two cases which include the
(a) To assist the reader in identifying the content of each plan, a foldout
sheet is included at the end of this report which contains the titles of
the plans.
iv
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75
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65
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55
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-PIAN 2A(al
( PLAN 4
f' .. ..., ..... PIAN 3
I PIAN lA . ; "':\·--
.... \
....... ~\
\.\PLAN 2B ....
.......
'-PLAN IB
1980 1985 1990 1995 2000 2005 2010
Comparison of Annualized Cost of Power for Railbelt
Electric Energy Plans (1982 dollars)
(a) Plan lA "Present Practices" Without Upper Susitna
lB "Present Practices" With Upper Susitna
2A ••High Conservation and Renewables" Without Upper Susitna
2B "High Conservation and Renewables 11 With Upper Susitna
3 "High Coal•i
4 "High Natural Gas"
v
Levelized Cost of Power for the Period 1981-2010 (mills/kWh)
(1982 Dollars)
Low . Medium
Economic Economic
Scenario Scenario
Plan 1A -"Present Practices" 58 58
Without Upper Susitna
Plan 1B -"Present Practices" 58 58
With Upper Susitna
Plan 2A -"High Conservation and 58 59
Renewables" Without Upper Susitna
Plan 28 -"High Conservation and 57 58
Renewables" With Upper Susitna
Plan 3 -"High Coal" 58 59
Plan 4 -"High Natural Gas" 57 59
High
Economic
Scenario
60
58
58
57
62
61
Upper Susitna Project show the lowest costs after the turn of the century as
they are amortized.
A second way to consider the elecrical energy costs is to express them as
levelized costs (the.equivalent of the present worth), and these are shown in
the above table forthree economic growth scenarios. Over the next 30 years
there is no significant difference in the present value of the plans as
measured by the levelized cost of electrical energy to the consumer,
irrespective of economic growth. Energy costs range from a low of 5.7
cents/kWh to 6.2 cents (less than 5% difference).
There are several reasons for the similarity in consumer cost of power
among the plans. First, given the long lead times in constructing generating
facilities, all plans are virtually identical until after 1990. At the 3%
discount rate used in this study, the present value of cost differences after
1990 is worth between 75% and 40% of what those differences would be if
incurred today. Second, the differences in the power generating costs actually
represent differences in generation and transmission costs only, but these tend
to be obscured by the addition of local utility billing and distribution costs,
which are assumed to be identical in all plans. Third, although there is still
vi
some difference among bus-bar energy costs of the various generating techno-
logies included in the plans, the main generation options contained in each of
the plans have fairly similar costs per kWh generated. Very high cost options
were screened out in the selection of technologies to be included in the plans.
It is common in power planning
life of the longest-lived project.
extends to about 2050. Halting the
to do all economic comparisons over the
In the case of Susitna, its economic life
analysis in the year 2010 would ignore the
benefits of lower power costs after the year 2010 in plans containing Susitna.
Assuming the relative annual costs of power for the plans remained constant
from 2010 to 2050, the resulting power costs were discounted and annualized to
get a levelized cost of power over the extended time horizon. These costs are
shown in the following table. The differences between the plans containing the
Upper Susitna project ·and the other plans are conservative because the annual
costs of power would likely be growing in the latter cases and falling in the
Susitna cases, not remaining constant as assumed.
Levelized Cost of Power for the Period 1981-2050 (mills/kWh}
(1982 Do 11 ars)
Plan 1A -11 Present Practices 11
Without Upper Susitna
Plan 1B -11 Present Practices 11
With Upper Susitna
Plan 2A -11 High Conservation and
Renewables 11 Without Upper Susitna
Plan 2B -11 High Conservation and
Renewables 11 With Upper Susitna
Plan 3 -11 High Coal 11
Plan 4 -11 High Natural Gas 11
Low
Economic
Scenario
65
63
66
61
67
64
Medium
Economic
Scenario
64
59
66
61
65
66
High
Economic
Scenario
66
60
66
59
68
68
There are several important assumptions underlying these results that
relate to future fossil fuel prices, availability of Beluga coal, penetration
vii
of conservation options, availability of North Slope natural gas, and the
capital cost of major facilities. Sensitivity analyses were performed to
evaluate the importance of each assumption.
1. Fossil fuel prices were assumed to escalate at three rates above
inflation: 2, 1, and 3% per year. At lower rates of escalation, those
plans that rely on fossil fuels (1A, 3, and 4) are more competitive, and
vice versa. The effect of continued escalation is most pronounced over
the longer term and in the high economic growth scenario. Unfortunately,
experts do not agree on whether fossil fuel prices will escalate faster,
slower, or equal to general inflation but the general consensus appears to
be that fossil fuel prices will escalate faster than general inflation
over the long term.
2. The Beluga coal resource is assumed to be developed by 1988. Failure to
develop that resource in this time frame would increase the power costs
for Plans 1A and 3.
3. Plan 2A, and to a lesser extent Plan 2B, stresses conservation and assumes
that a continuing State conservation grant program exists to encourage
conservation efforts.
4. Plan 4 assumes the continued availability of Cook Inlet gas and the
availability of natural gas from the North ·Slope by 1987. Unavailability
of these resources for use in the Railbelt region would jeopardize this
plan.(a)
(a) The future price of natural gas is also uncertain, for example, in the
Fairbanks region. At low rates of oil price escalation, gas from the North
Slope could have difficulty competing with oil in the Lower 48 states at
$10.60/MMBtu (1982 dollars). If that is the case, then a netback price at
the North Slope could be somewhat below the maximum legal $2.13/MMBtu
assumed in the study. The minimum price would likely be $1.00 to $1.50
per MMBtu, or about 50 cents to $1.00 less than assumed. Prices below this
would lead to the gas pipeline not being built. The future pipeline tariff
could follow any of a number of scenarios. The likeliest is now considered
to be a declining tariff that results in -4.3 percent per year change in
gas prices in Fairbanks as shown in Volume VII. The study assumed the
maximum wellhead price and constant real tariff. The lower price would
improve the competitiveness of Plan 4 vis-a-vis the other plans.
viii
5. Cost overruns of 20% in the Upper Susitna Project increase the present
value of power cost in Plans lB and 2B by about 5%. Similar overruns on
thermal electric plants have little effect on power costs.
With the exception of capital cost overruns, the plan that is most
insensitive to these assumptions is Plan lB, which includes construction of the
Upper Susitna Project~ This plan provides either the lowest or nearly the
lowest cost of power in all sensitivity tests over the extended time period.
It is also the most resistant to inflation once it is completed. From an
environmental impact standpoint, it is believed that fishery impacts can be
mitigated, though dam construction can result in significant boom/bust and land-
use effects.
The effect of a five-year delay in the Upper Susitna Project had little
effect on levelized power costs for Plans lB and 2B. While not specifically
analyzed, the relatively small difference in power costs over the 30-year
period suggests that a decision on which path to follow could be delayed for at
least several years without affecting the present value of power, though the
effects on annual cost of power might be significant. The effects of project
delay on power costs appears worthy of continuing study. Delay might permit a
clearer understanding of several technical-economic issues which could affect
the power costs of the several plans. These include:
1. The re-evaluation of fossil fuel price escalation, especially f0r oil and
gas.
2. The cost and effectiveness of conservation measures.
3. The competitivenes of advanced fossil fuel and renewable-based generating
technologies.
4. The growth of electricity as an energy form compared to alternative forms
of energy.
5. The resolution of air pollution issues (e.g., acid rain and co 2) as they
apply to fossil fuel uses.
With respect to institutional barriers, no Federal statutes, rules, or
regulations absolutely prohibit implementing any of the plans, including the
use of natural gas for generating electricity in new power plants. The Alaskan
Energy Program (as embodied in Senate Bill 25) does not preclude implementing
any of the plans, with the exception of the energy conservation option, which
appears to require new authorizing legislation. Some parts of the program may
require court interpretation of the authorizing statufe.
X
ADDENDUM TO EXECUTIVE SUMMARY: THE EFFECT OF LOWER OIL PRICES
The major change that has occurred since the data in the body of this
report were calculated (January 1982) relates to future world petroleum
prices. The range of increase of oil prices assumed in this study was 1% to 3%
per year above inflation. As late as December 1981 the Alaska Petroleum
Revenue Division {APRD) was projecting that the weighted average price of
Prudhoe Bay-type crude oil would increase from $32.38 per barrel in 1982 to
$117.56 in 1998--about an 8.4% nominal rate of increase or (given 7% inflation)
about a 1.4% real price increase per year. The dramatic collapse of world oil
prices in January through March of 1982 reduced nominal crude prices by between
$4 and $6 per barrel and, among other things, divided oil analysts into two
schools of thought--those foreseeing a stabilization of prices at about $25 per
barrel and those forecasting further declines to as little as $15 per barrel.
Even without substantial economic recovery in the United States and other major
developed economies, it now appears that the OPEC market price has stabilized
at $32 to $34 per barrel.
Industry sources now are·forecasting real price increases for the 1980s
ranging from minus 3.3% in constant dollars to plus 2.8%, with low-probability
political crises resulting in possibly higher rates of increase (Oil and Gas
Journal, May 17, 1982). The most recent APRD forecast {March 1982) for the
weighted average price of Prudhoe Bay-type crudes is $29.84 per barrel in 1982
increasing to $87.95 per barrel in 1998, or about 7% per year (0% above the
assumed 7% inflation). The netback wellhead price was assumed by APRD to
increase annually at about 8.1% in nominal dollars (1.1% above inflation) due
to market price increases and the TransAlaska Pipeline System (TAPS) tariff.
The lower starting point for oil prices and slower rate of increase now
being forecast result in lower petroleum revenues for Alaska than were assumed
in this study. The difference between the March and December APRD forecasts
ranges from minus 8.0% for 1982 to minus 61.3% for 1998, but it could be
greater since oil exploration activity and pipeline construction might be
deferred or cancelled at. the projected lower prices. The Alaska economy, which
is heavily dependent on oil field activity and State spending, can be expected
to grow at a slower rate with the lower oil prices foreseen in the new
xi
forecast. Moreover, because oil and natural gas prices would not rise as
rapidly, the incentives for conservaton and for fuel switching to electricity
by consumers would be reduced, possibly further reducing electricity demand
beyond that projected for economic growth.
To estimate the effect of the State's revised oil price projections,
calculations were made to determine whether the low-case (Case LL) government
expenditures assumed in the study could be maintained with the lower State
revenue projections. These calculations were made without the benefit of
University of Alaska Institute of Social and Economic Research (ISER) economic
models which had been used previously. The previous ISER low-case economy,
population, and government expenditures forecasts were assumed. Other
assumptions included:
• Petroleum ~evenues available for disbursement equal severance taxes plus
75% of royalties. APRD forecasts were used.
• General Fund revenues total the sum of available petroleum revenues,
earnings of the General Fund and Permanent Fund, plus "other unrestricted"
revenues (forecast to be about $728 million in FY 1985). This latter
category includes other taxes, licenses, fees, permits, rents, inter-
governmental receipts, investments, and miscellaneous. State Department
of Revenue forecasts were used to FY 1982, and for subsequent years
increased with inflation.
• The average balance in both the General Fund and Permanent Fund earns 10%
per year throughout the forecast period.
The results of this comparison between new revenues and old expenditures
to 1990 are shown in the following table. General Funds deficits occur after
FY 1985. Since the State of Alaska cannot legally incur deficits at present,
the level of expenditures would have to be below those previously shown in the
low case. In turn, employment and population would be reduced below that in
the low-case forecast.
rii
FY
1982
1983
1984
1985
1986
1987
1988
1989
1990
Alaska Revised State Revenues and Low Case Expenditures
(Million $)
Severance Tax General Fund
Plus 75% of General Fund (1 ) Expenditures Average Genera~2 )
Ro~alties Total Revenues (Low Case} Fund Balance
2717.0 4292.5 3238.5 2481.1
1932.0 2941.5 3539.2 1863.3
2315.9 3113.4 3893.8 1090.5
2695.0 3797.7 4322.9 539.8
3130.8 4267.8 4913.4 -120.5
3665.5 4889.9 5517.5 -627.6
3759.8 5134.8 5907.3 -772.5
4243.5 5708.1 6306.7 -598.6
4294.8 5893.8 6789.5 -895.7
(1) May not correspond to Department of Revenues estimates because of
differences in assumptions concerning General Fund expenditures (affecting
the size of the balance), rate of return on General and Permanent Fund, and
growth in nonpetroleum production revenues.
(2) General Fund balance is based on an assumed carryover from 1981 and
earnings on the average General and Permanent Funds. It is not the sum and
difference of the other columns because of carryover and fiscal
calculations.
To estimate the likely size of the change, the moderate (Case MM) and low-
case forecast of government employment was reduced to 40,000 persons in the
Railbelt region in the years 1990 to 2000 (compared to 72,000 in the moderate
case and 62,000 in the low case). Statewide government employment was reduced
proportionately and the size of the Railbelt and statewide economies were re-
estimated for the moderate and low-case forecasts. The revised results for the
Railbelt region are summarized in the following table.
Without using the ISER econometric models it is not possible to state
whether reducing government employment as assumed here would balance the State
budget. However, if government employment in the Railbelt in 1990 were reduced
to 40,000 and low-case government spending of $72,726 per worker for 1990 were
maintained, General Fund expenditures would be about $4.5 billion in 1990.
This about equals petroleum revenues for 1990, as shown in the initial table,
and results in a substantial current General Fund surplus. It appears that the
xiii
Revised Year 2000 Forecast of Railbelt Employment and Population
(Thousands of Persons)
Revised Government Revised Revised
Government Basic Plus Total (a) Total (b)
Case Em~loyment Em~loyment Basic Em~loyment Population
Moderate 40.0 56.5 96.5 178.5 385.6
(MM)
Low (LL) 40.0 39.0 79.0 146.2 315.7
(a) Based on the low case ratio (1.85) of total employment to basic plus
government employment.
(b) Based on the low case ratio (2.16) of population to employment.
(c) See Figure 3.3.
budget would be in approximate balance for the level of population and
employment shown above.
Previous
Total
Population( c)
484
405
The results indicate that reduced oil prices, through their effects on
State government spending alone, could reduce .Railbelt populaton by 80,000 to
100,000 persons by the end of the century. Population of the Railbelt would
not reach 400,000 (in the moderate case) until about the year 2000 to 2005,
instead of 1990. This could delay by about ten years when new electric
generating facilities are needed.
The effect of reduced prices for oil on private sector development
activity is more difficult to judge. It seems clear at this time (June 1982)
that some North Slope activities will be delayed or not undertaken at all. The
construction effects of the Alaska Natural Gas Transportation System (ANGTS)
will be deferred until 1990 at least, and other projects such as coal or
liquified natural gas (LNG) developments may experience delay or cancel-
lation. Except for ANGTS deferral, this 11 future 11 looks very much like the low
case described in the body of the report. The most likely forecast of the
Railbelt economy based on present information probably lies between the revised
moderate and low cases. This forecast can be expected to change as oil prices
and the economy in general change.
The effect of this revised 11 future 11 on electricity consumption for the low
and moderate cases is shown in the following table, given two additional
riv
:)
1980
1985
1990
1995
2000
2005
2010 .
1980
1985
1990
1995
2000
2005
2010
Revised Moderate and Low Case Electricity Forecasts, Railbelt
Revised (a) Old
Annual Energy Annual Energy
(GWh) (GWh)
Moderate Low Moderate Low ----
2551 2551 2551 2551
3000 2560 3136 3028
3391 3001 4256 3853
3884 3164 4875 4063
4010 3106 5033 3988
4319 3332 5421 4278
4986 3844 6258 4936
Revised ( ) Old
Peak Demand b Peak Demand
(MW) (MW)
Moderate Low Moderate Low ----
531 521 521 521
615 525 643 621
701 621 880 797
791 652 993 837
810 673 1017 815
870 678 1092 870
1003 780 1259 1001
(a)
(b)
Revised downward based on low case annual consumption of 9.84 MWh per
capita and moderate case annual consumption of 10.40 HWh n~r capita in the
year 2000. See Appendix B, Tables B.3, B.4, B.12, and B.18. Other years
consumption reduced proportionately. 1985 figures was adjusted upward
judgmentally for moderate case; 1985-1995 adjusted upward for low case.
Based on the ratio of peak demand to annual energy from Appendix B, Tables
B.12 and B.18.
assumptions: 1) that per capita annual electricity consumption and 2) the
ratio of peak demand to annual energy each year are the same as in the
corresponding cases in the body of this report.
Reducing electrical load in proportion to the lowered population (as is
done in the preceding table) probably overestimates electrical use, since at
lower oil prices, more oil/gas and less electricity will likely be used (even
though the cost of electricity generated with oil and gas decreases somewhat).
The reduction in demand might be greater than that shown. However,
historically, electricity demand in the Railbelt and other regions of the
country has grown faster than population and might be expected to continue to
do so because of rising real incomes, among other reasons. Moderate and low-
case annual energy consumptions for the year 2000 based on the revised 11 future 11
and the assumptions stated above were calculated. Then the other years•
figures shown in the above table were estimated on an equal proportional
reduction from the corresponding case in the body of the report, but with some
adjustments. The year 2010 peak dem~nd for the moderate case decreases from
1259 MW in the old case to 1003 MW in the revised case, and for the low case
from 1001 to 780. The revised moderate case does not include State spending as
a major economic driver, but ·it does allow for private economic growth. It
approximately tracks the old low case. The revised low case is about 20% less,
and shows only modest growth in consumption, because neither State government
growth nor private sector growth is available to stimulate consumption. The
most likely case as viewed at present probably lies between the revised low and
moderate cases.
The major change in the study conclusions relates to the Upper Susitna
Project. A lower growth rate makes that project less attractive. While still
the most resistant to inflation once it is completed, its power output would be
larger than the Railbelt region could readily accommodate.
xvi
CONTENTS
EXECUTIVE SUMMARY
ADDENDUM TO EXECUTIVE SUMr~ARY: THE EFFECT OF LOWER OIL PRICES
FIGURES
TABLES
1.0 INTRODUCTION
2.0 FUEL PRICE AND AVAILABILITY
2. 1 COOK INLET NATURAL GAS
2.2 COAL
2.3 PEAT
2.4 NATURAL GAS INTERIOR
2.5 NATURAL GAS LIQUIDS/METHANOL
2.6 FUEL OILS .
2.7 MUNICIPAL SOLID WASTE
3.0 ANNUAL PEAK LOAD AND ENERGY REQUIREMENTS FORECASTS .
3.1 OVERVIEW OF DEMAND FORECASTING PROCESS
3.2 ECONOMIC SCENARIOS .
3.3 ECONOMIC MODELS
3.4 FORECASTS OF ECONOMIC AND INDUSTRIAL ACTIVITY,
POPULATION AND HOUSEHOLDS .
3.5 END USE MODEL (RAILBELT ELECTRICITY DEMAND MODEL)
3.6 ELECTRIC ENERGY DEMAND FORECASTS
4.0 ELECTRICAL ENERGY GENERATING AND CONSERVATION ALTERNATIVES
4.1 GENERATING ALTERNATIVES
4.1~1 Coal-Fired Steam-Electric Plants
4.1.2 Coal. Gasifier-Combined-Cycle Plants
4.1.3 Natural Gas Combustion Turbines .
xvii
iii
xi
1.1
2.1
2.4
2.4
2.5
2.6
2.6
2.6
2.7
3. 1
3.1
3.3
3.6
3.7
3.7
3.9
4.1
4.1
4.4
4.5
4.6
4.1.4 Natural Gas -Combined-Cycle Plants 4.6
4.1.5 Natural Gas -Fuel-Cell Stations 4.7
4.1.6 Natural Gas Fuel-Cell -Combined-Cycle Plants 4.7
4.1.7. Large and Intermediate-Scale Hydroelectric Plants 4.8
4.1.8 Small-Scale Hydroelectric Plants 4.10
4.1.9 Microhydroelectric Systems 4.10
4.1.10 Large Wind Energy Conversion Systems 4.11
4.1.11 Sma 11 Wind Energy Conversion Systems 4.11
4. 1 . 12 Ti da 1 Power . 4. 12
4.1.13 Municipal Solid Waste Fuel Steam Electric Plants 4.13
4.2 CONSERVATION ALTERNATIVES 4. 14
4. 2.1 Residential Building Conservation
4.2.2 Residential Passive Solar Space Heating
4.2.3 Residential Active Solar Hot Water Heating
4.2.4 Residential Wood Space Heating
4.2.5 Cogeneration and Waste Heat Utilization
5.0 ELECTRIC ENERGY PLANS
6.0 COMPARATIVE EVALUATION OF ELECTRIC ENERGY PLANS .
6.1 DEVELOPMENT OF DETAILED ALTERNATIVE ENERGY PLANS
6.2 DETAILED DESCRIPTIONS OF PLANS .
4.1 6
4.16
4.18
4.18
4.1 9
5.1
6. 1
6.1
6.4
6.2.1 Plan lA 11 Present Practices 11 Without Upper Su'Sitna 6.4
6.2.2 Plan lB 11 Present Practices 11 ~Jith Upper Susitna 6.5
6.2.3 Plan 2A 11 High Conservation and Renewables 11
Without Upper Susitna 6.6
6.2.4 Plan 2B 11 High Conservation and Renewables 11
With Upper Susitna 6.7
6.2.5 Plan 3 11 High Coal 11 6.7
6.2.6 Plan 4 11 High Natural Gas 11 6.8
xviii
6.3 ELECTRICAL DH1AND .
6.4 COST OF POWER .
6.5 POTENTIAL ENVIRONMENTAL AND SOCIOECONOMIC IMPACTS
6.6 SUMMARY OF PLAN EVALUATIONS
Plan lA: 11 Present Practices .. Without Upper Susitna
Plan 18: 11 Present Practices .. With Upper Susitna
Plan 2A: 11 High Conservation and Renewables 11 Without
Upper Susitna
Plan 28: 11 High Conservation and Renewables 11 With
Upper Susitna
Plan 3: 11 High Coal 11
Plan 4: 11 Hi gh Natura 1 Gas 11
7.0 SENSITIVITY ANALYSIS
Plan lA: 11 Present Practices .. Without Upper Susitna
Plan -18: 11 Present Practices 11 ~Jith Upper Sus itna
Plan 2A: 11 High Conservation and Renewables 11
Without Upper Susitna
Plan 28: 11 High Conservation and Renewables 11
With Upper Susitna
Plan 3: 11 High Coal 11
Plan 4: 11 High Natural Gas 11
7.1 UNCERTAINTY IN FOSSIL FUEL PRICE ESCALATION
7.1.1 Effects of Uncertainty in Fossil Fuel Price
Escalation on Cost of Power .
7.1.2 Effects of Uncertainty in Fossil Fuel Prices
on Demand for Electricity
7.1.3 Consumer Reaction to Changes in the Price
6.9
6.9
6.14
6.16
6.16
6.16
6.17
6.17
6.17
6.18
7.1
7.2
7.2
7.2
7.3
7.3
7.3
7.3
7.3
7.5
of Electricity Relative to Other Forms of Energy 7.6
7.2 UNCERTAINTY IN ELECTRICITY DEMAND FORECASTS
7.2.1 High-High Economic Scenario .
xvix
7.10
7.10
7.2.2 Low-Low Economic Scenario 7.13
7.2.3 Effects of Electrical Load Growth Higher and
Lower Than Forecasted After 1990 7.14
7 .2.4 Load Growth Begins as Projected in the f1edium Economic
Growth Scenario But Levels Off After 1990 7.16
' 7.2o5 Load Growth Begins as Projected in the Medium
Economic Growth Scenario But Increases After 1990 7 01.7
7o3 UNCERTAINTY IN COST AND AVAILABILITY OF MAJOR ALTERNATIVES o 7.18
7.3ol Capital Cost of Upper Susitna Project -20% Lower
and Higher Than Estimated 7 018
7o3.2 Capital Cost of Coal Steam-Electric Power-Capital
Costs -20% Higher and Lower Than Estimated . 7.19
7.3.3 Penetration of Conservation Alternatives Higher
and Lower Than Estimated 7.20
7.3o4 Effects of Increased Thermal Generating Efficiency 7o2l
7o3.5 Impact of Using Fuel-Cell Combined-Cycle
Generation Rather Than Fuel-Cell Stations 7o22
7.3.6 Impact of 50% Higher Fuel-Cell Station and
Coal-Gasifier Combined-Cycle Capital Costs 7.23
7o3.7 Capital Cost of Chakachamna Hydroelectric -
20% Lower and Higher Than Estimated . 7.24
7.3.8 Use of Healy Coal in the Anchorage Area . 7.25
7.3.9 Delay in Upper Susitna Project from 1993 to 1998 7.26
7.4 EFFECTS ON ELECTRICITY DEMAND OF STATE SUBSIDIES TO COVER
CAPITAL COSTS OF NEW GENERATING FACILITIES . 7.27
7.5 SENSITIVITY TEST IMPLICATIONS 7.28
8.0 CONSIDERATIONS FOR IMPLEMENTING ELECTRIC ENERGY PLANS 8.1
8o 1 FEDERAL CONSTRAINTS 8.1
8.2 A HISTORICAL PERSPECTIVE OF POWER PLANNING IN ALASKA 8.2
8.3 THE CURRENT STATUTORY FRAMEWORK IN ALASKA 8.8
REFERENCES R. 1
XX
APPENDIX A: SUPPORTING REPORTS . A.l
APPENDIX B: DEMAND ASSur~PTIONS AND FORECASTS B .1
APPENDIX C: LEVELIZED COST OF POWER . C.l
APPENDIX D: DETAILED DESCRIPTION OF RAILBELT ELECTRIC ENERGY PLANS . D.l
APPENDIX E: LIST OF ASSUMPTIONS . E.l
xxi
1.1
1.2
2. 1
3.1
3.2
3.3
3.4
3.5
3.6
6.1
6.2
6.3
6.4
7.1
7.2
7.3
c. 1
C.2
C.3
D. 1
FIGURES
Comparison of Annualized Cost of Power for Railbe1t
Electric Energy Plans
Railbelt Area of Alaska Showing Electrical Load Centers
Study Flow Diagram
Projected Fuel Prices to Railbelt Utilities, 1980-2010
Electric Power Forecasting Process
Economic Scenarios
Railbelt Population
Railbelt Electricity Demand (RED) Model
Railbelt Annual Electricity Consumption, 1980-2010
Railbelt Annual Peak Demand, 1980-2010
Electrical Demand and Supply Interactions
AREEP Diagram
Peak Electrical Demands for Medium-Medium Economic Scenario .
Comparison of Annualized Cost of Power for Railbelt
Electric Energy Plans
Effect of Energy Price Changes on Electricity Demand .
Sensiti:vity Test of Peak Demand:· Monte Carlo Simulation
with Varying Price Elasticities and Load Factors
Electrical Load Growth for Increased and Reduced Growth
Beyond 1990
Annual Cost of Power and Total Levelized Cost
Use of Levelized Cost to Select Lowest Life Cycle-Cost Plan
Levelized Cost Methodology for 2010-2050 Time Period .
Typical Costs for Alternative Reserve Margins
xxii.
v
1.3
1.4
2.3
3.2
3.4
3. -a
3 .10
3.11
3.12
6.2
6.3
6.10
6.11
7.7
7.11
7.17
c. 1
C.3
C.4
0.6
2. 1
4.1
4.2
5.1
6.1
6.2
7. 1
7.2
7.3
7.4
7.5
7.6
7.7
7.8
7.9
TABLES
Levelized Cost of Power for the Period 1981-2010 .vi
Levelized Cost of Power for the Period 1981-2050 . vii
Alaska Revised State Revenues and Low Case Expenditures xii
Revised Year 2000 Forecast of Railbelt Employment and
Population . xi i
Revised Moderate and Low Case Electricity Forecasts, Railbelt. xiv
Fossil Fuel Availability and Price
Candidate Electric Energy Generating Technologies
for the Railbelt
Summary of Cost and Performance Characteristics
of Selected Alternatives
Summary of Electrical Energy Alternatives Included as
Future Additions in Electric Energy Plans
Levelized Costs of Power for Electric Energy Plans
Summary of Potential Environmental and Socioeconomic
Impacts of Railbelt Energy Plan
Effect of Alternate Fossil Fuel Escalation Rates
on Levelized Cost of Power .
Effect of Alternate Fossil Fuel Price Escalation Rates
on Peak Electricity Demand in 2010
Default Values Used in the RED Model .
Range of Elasticities of Demand and Load Factors
Used in the RED Model
Peak Demand and Annual Energy Use in 2010 for the Medium
and High Economic Scenarios
Levelized Costs of Power for Medium and High Economic
Growth Scenarios
Peak Demand and Annua 1 Energy in 2010 for r4edi urn
and Low Economic Scenarios .
Levelized Costs· of Power for Medium and Low Economic
Growth Scenarios
Levelized Costs of Power for Reduction in Electrical
Demand After 1990
xxiii
2.2
4.2
4.15
5.6
6.13
6.15
7.4
7.5
7.8
7.12
7 .L2
7.13
7.14
7.16
7.10
7.11
7.12
7.13
7.14
7.15
7.16
7.17
7.18
7.19
7.20
7.21
8. l
8.2
8.3
8.4
8.5
8.6
8.7
Levelized Costs of Power for Increase in Electrical
Demand After 1990
Levelized Costs of Power for Upper Susitna -Capital
Costs 20% Lower and Higher Than Estimated
Levelized Costs of Power for Coal Steam Turbine Plant
Capital Costs 20% Lower and Higher Than Estimated
Levelized Costs of Power for Penetration of Conservation
Alternatives 20% Higher and Lower Than Estimated
Assumed Improvements in Heat Rates
Levelized Cost of Power for Lowered Heat Rates
in Thermal Generation
Levelized Cost of Power for Using Fuel-Cell Combined-Cycle
Units Rather Than Fuel-Cell Stations -Plan 4
Levelized Costs of Power for Increased Capital Cost
of Fuel-Cell Stations and Coal-Gasifier Combined-Cycle .
Levelized Cost of Power for Chakachamna, Capital Costs
20% Lower and Higher Than Estimated
Levelized Cost of Power Assuming Healy Coal is Used
in Anchorage Area
Levelized Cost of Power Assuming Watana Dam
Delayed Until 1998 .
Levelized Cost of Power and Peak Demand Assuming No
Capital Recovery
Assumptions Used in Railbelt Power Alternatives Study
Large Industrial Additional Sales and Peak Demand
Population and Total Employment, Medium Scenario
~Ji thout Susitna
Population and Total Employment, Low Scenario
Without Susitna
Population and Total Employment, High Scenario
Without Susitna
Population and Total Employment, Medium Scenario
With Susitna
Population and Total Employment, Low Scenario
Wit.h Susitna
xxiv
7.18
7.19
7.20
7.21
7.22
7.22
7.23
7.24
7.25
7.26
7.26
7.27
8.2
8.5
8.6
8.6
8.6
8.7
8.7
B.8 Population and Total Employment, High Scenario
With Susitna B.7
B.9 Population and Total Employment, Nonsustai nab 1 e
Government Spending B.8
B .1 0 Population and Total Employment, Industrialization
Scenario B.8
B .11 Population and Total Employment, Superhigh Economic
Scenario B.8
B. 12 Peak Demand and Annual Energy, Medium Economic
Scenario, Plan lA . B.9
B.l3 Peak Demand and Annual Energy, Medium Economic
Scenario, Plan lB B.9
B. 14 Peak Demand and Annual Energy, t~edi urn Economic
Scenario, Plan 2A B~9
B.l5 Peak Demand and Annual Energy, Medium Economic
Scenario, Plan 2B B .10
B .16 Peak Demand and Annual Energy, Medium Economic
Scenario, Plan 3 B .10
B. 17 Peak Demand and Annual Energy, Medium Economic
Scenario, Plan 4 B .10
B .18 Peak Demand and Annual Energy, Low Economic
Scenario, Plan lA . B.ll
B. 19 Peak Demand and Annual Energy, Low Economic
Scenario, Plan lB 8.11
8.20 Peak Demand and Annual Energy, Low Economic
Scenario, Plan 2A . 8.11
8.21 Peak Demand and Annual Energy, Low Economic
Scenario, Plan 28 8.12
8.22 Peak Demand and Annual Energy, Low Economic
Scenario, Plan 3 8.12
B.23 Peak Demand and Annual Energy, Low Economic
Scenario, Plan 4 B .12
8.24 Peak Demand and Annual Energy, High Economic
Scenario, Pla·n lA B. 13
8.25 Peak Demand and Annual Energy, High Economic
Scenario, Plan lB B .13
XXV
8.26 Peak Demand and Annual Energy, High Economic
Scenario, Plan 2A B. 13
8.27 Peak Demand and Annual Energy, High Economic
Scenario, Plan 28 B .14
8.28 Peak Demand and Annual Energy, High Economic
Scenario, Plan 3 B. 14
B.29 Peak Demand and Annual Energy, High Economic
Scenario, Plan 4 8.14
8.30 Peak Demand and Annual Energy, Nonsustainable
Government Spending, Plan lA B o 15
8.31 Peak Demand and Annual Energy, Nonsustainable
Government Spending, Plan lB 8.15
8.32 Peak Demand and Annual Energy, Industrialization
Scenario, Plan lA . B o 15
8.33 Peak Demand and Annual Energy, Industrialization
Scenario, Plan 1 B 8.16
8.34 Peak Demand and Annual Energy, Superhigh Economic
Scenario, Plan lA . 8.16
B.35 Peak Demand and Annual Energy, Superhigh Economic
Scenario, Plan lB B. 16
8.36 Peak Demand and Annual Energy, No Capital Recovery,
Plan lA B o 17
8.37 Peak Demand and Annual Energy, No Capital Recovery,
Plan lB B .17
B.38 Peak Demand and Annual Energy, Low Fuel Prices,
Plan 1 A B. 17
8.39 Peak Demand and Annual Energy, Low Fuel Prices,
Plan lB 8.18
8.40 Peak Demand and Annual Energy, Low Fuel Prices,
Plan 2A B .18
8.41 Peak Demand and Annual Energy, Low Fuel Prices,
Plan 28 B o 18
Bo42 Peak Demand and Annual Energy, Low Fuel Prices,
Plan 3 B. 19
B. 43 Peak Demand and Annual Energy, Low Fuel Prices,
Plan 4 8.19
xxvi
8.44
8.45
8.46
8.47
8.48
8.49
D. 1
D.2
D.3
D.4
D.5
D.6
D.7
D.8
D.9
D. 10
D.ll
D. 12
D.l3
Peak Demand and Annual Energy, High Fuel Prices,
Plan lA
Peak Demand and Annual Energy, High Fuel Prices,
Plan 18
Peak Demand and Annual Energy, High Fuel Prices,
Plan 2A
Peak Demand and Annual Energy, High Fuel Prices,
Plan 28
Peak Demand and Annual Energy, High Fuel Prices,
Plan 3 .
Peak Demand and Annual Energy, High Fuel Prices,
Plan 4 .
Existing Capacity (1980) and Capacity Additions
and Retirements (1981-2010) -Plan lA .
Electricity Demand and Generation by Type of Capacity -
Plan lA
Integration of Potential Environmental and Socioeconomic
Impacts for Plan lA
Existing Capacity (1980) and Capacity Additions
and Retirements (1981-2010) -Plan 18
Electrical Generation by Type of Capacity -Plan 18 .
Integration of Potential Environmental and Socioeconomic
Impacts for Plan 18
Existing Capacity (1980) and Capacity Additions
and Retirements (1981-2010) -Plan 2A .
'
Electrical Generation by Type of Capacity -Plan 2A .
Estimated Number of Homes Using the Conservation
Techniques .
Integration of Potential Environmental and Socioeconomic
Impacts for Plan 2A
Existing Capacity (1980) and Capacity Additions
and Retirements (1981-2010) -Plan 28 .
Electrical Gene·ration by Type of Capacity -Plan 28
The Estimated Number of Homes Using the Conservation
Technique~ in the Year 2010
xxvii
8.19
8.20
8.20
8.20
8.21
8.21
D.3
D.4
D.l9
D.25
D.26
D.33
D.36
D.37
D. 41
D.47
D.48
D.49
D.50
D.l4
D.15
D.l6
0.17
D.l8
D. 19
D.20
Integration of Potential Environmental and Socioeconomic
Impacts for Plan 2B
Existing Capacity (1980) and Capacity Additions and
Retirements (1981-2010) -Plan 3
Electrical Generation by Type of Capacity -Plan 3
Integration of Potential Environmental and Socioeconomic
Impacts for Plan 3 .
Existing Capacity {1980) and Capacity Additions and
Retirements (1981-2010) -Plan 4
Electrical Generation by Type of Capacity -Plan 4
Integration of Potential Environmental and Socioeconomic
Impacts for Plan 4 .
xxviii
D. 51
0.53
D.54
D. 5.9
0.60
0.61
D.64
1.0 INTRODUCTION
One of Alaska•s broad goals is to assure an adequate, long-term supply of
electricity and other energy forms to its citizens and industries at the lowest
cost consistent with environmental and socioeconomic considerations. Finding
the 11 best 11 set of electrical generation and conservation options to meet this
goal is not a simple undertaking. Many potential generation and conservation
alternatives exist. Each has different costs, operating characteristics,
availability, and environmental and socioeconomic impacts. The future
requirements for electrical power and other energy forms are uncertain, and
long lead times are often involved in increasing capacity to meet these
requirements. The amount of electrical power required depends on the supply
and price of other fuels as well as the extent of conservation. Electrical
power alternatives cannot be analyzed outside the context of this interaction.
Finally, even if a 11 best 11 solution is identified, many barriers, including
institutional factors, may impede implementation.
Ultimately, the citizens and elected officials within Alaska must decide
which set of electrical generation and conservation options comprise the 11 best 11
solution to the problem of assuring adequate electricity supplies in the
future. The long-term consequences of committing to any one or a mix of
gene~ating alternatives may profoundly affect how the State of Alaska develops.
To assist in this planning process, the Office of the Governor, State of
Alaska, Division of Policy Development and Planning and the Governor•s Policy
Review Committee contracted with Battelle, Pacific Northwest Laboratories to
investigate potential strategies for future electric power development in the
Railbelt region of Alaska. The major effort in this project was the
development of models, forecasting methodologies, and data bases that would
permit the State of Alaska to make its own forecasts to account for changing
economic conditions and technologies. This report (Volume I of a series of
seventeen reports listed in Appendix A) illustrates the use of the models and
methodologies for a selected set of assumptions appropriate in late 1981 to
early 1982. It is not a purpose of this report to recommend a single plan or
11 best 11 solution for the Railbelt region•s electric power future. Rather it is
a technical, economic, environmental and institutional analysis of a set of
1.1
strategic development plans. These plans are compared with respect to cost of
power, impact on the physical and human environment, and uncertainty of
planning assumptions.
The Railbelt region, shown in Figure 1.1, contains three electrical load
centers: the Anchorage-Cook Inlet Area, the Fairbanks-Tanana Valley area, and
the Glennallen-Valdez area. The peak electrical load of these areas in 1980
was about 500 MWe. The generating capacity is comprised primarily of gas/oil-
fired turbines with some coal steam and hydroelectric facilities. Because of
the relatively small electrical requirements of the Glennallen-Valdez load
center (ru2% of the demand of the Anchorage-Cook Inlet area) it is not
specifically analyzed as an individual load center, but is considered to be
part of the Anchorage-Cook Inlet load center.
The study was comprised of four major tasks or activities, as illustrated
in Figure 1.2:
• fuel supply and price analysis
• electrical demand forecasts
• generation and conservation alternatives evaluation
• development of electric energy themes or "futures 11 available to the
Railbelt (Part 1), and systems integration/evaluation of electric energy
plans (Part 2).
Each of the tasks contributed data and information to the final results of
the project, but they also developed important results on the alternative
electric generating technologies. These results are included in the reports
listed in Appendix A.
The first task evaluated the price and availability of fossil fuels that
could be used for electrical generation or for end-use applications, such as
space or water heating, which compete with electricity. The results of this
task influence the analysis-of-alternatives task and the electrical-demand
forecasting task (Figure 1.2). Fuel supply and price help determine the
selection of alternatives, since fuel prices often are a major determinant of
the cost of power generation, and some fuels are competitors with electricity
for various end applications. For example, if the price of electricity is high
1.2
FIGURE 1.1. Railbelt Area of Alaska Showing Electrical Load Centers
1.3
__, .
.j:::o
PUBLIC
ATIITUDE
• HYDRO
• FOSSIL
ONGOING
POWER
PLANNING
ACTIVITIE_S
• CONSERVATION
• GEOTHERMAL
• SOLAR
• WIND
ENERGY
RESOUR~E
AVAILABILITY
FIGURE 1.2. Study Flow Diagram
J COMPARATIVE
EVALUATION
-
OF ELECTRIC
ENERGY PLANS rl
FOR THE RAILBEL T
relative to the price of natural gas, then more new applications will use
natural gas than if the price of electricity were low relative to the price of
natural gas.
The second task, electrical-demand forecast, is important in determining
both the size of generating units for the system and the number of generating
units (or the total) generating capacity required.
Several generation and conservation alternatives are available to the
Railbelt to meet forecasted electrical demand. The purpose of the third task
was to identify electric power generation and conservation alternatives
potentially applicable to the Railbelt region and to examine their feasibility,
considering such factors as cost of power, environmental and socioeconomic
effects, and public acceptance. Alternatives best suited to the region were
then studied in depth and incorporated into one or more of the electric energy
themes or plans.
The fourth task was performed in two parts. Part 1, the development of
electric energy themes or plans, presents possible electric energy "futures"
for the Railbelt. These plans, selected from the analysis-of-alternatives
task, encompass a wide range of viable alternatives available to the region.
They also include those futures currently receiving the greatest interest
within the Railbelt (e.g., the Upper Susitna River Project). Each plan is
defined by a set of electrical generation and conservation alternatives
sufficient to meet· the peak demand and annual energy requirements over the time
horizon of the study (1981 to 2010). Cost-of-power analyses also are done for
the 1981 to 2050 time period.
Part 2, the system integration/comparative analysis task, compared the
electric energy plans. The major criteria used to evaluate and compare the
plans were cost of power, environmental and socioeconomic impacts, and the
1.5
susceptibility of the plan to future uncertainty in assumptions and
estimates.(a)
Sections 2 through 5 of this report describe the results of each of the
four tasks. The results of the comparative analysis are presented in Section 6;
sensitivity analyses in Section 7; and consideration for implementing electric
demand plans in Section 8.
(a) The assumptions used in this study are listed in Appendix E. Common
financial premises used in this study were as follows: Cost estimates are
expressed in January 1982 dollars, though costs cited in other volumes may
be on other bases. Project financing was assumed to be public, at 3%
(real) cost of debt, 100% debt financing. These assumptions are consistent
with those used in recent studies sponsored by the Alaska Power Authority,
including the Upper Susitna studies and to Cook Inlet tidal power studies.
To assist the reader in identifying the content of each plan, a foldout
sheet containing the titles of the plans is included at the end of this
report.
1.6
2.0 FUEL PRICE AND AVAILABILITY
One of the key components in electric power costs in the cost of fuel for
generating the electricity. Some fuels are free, or essentially free, such as
water for hydroelectric facilities, wind for wind turbines, and sunlight for
solar generating devices. Some fuels comprise only a small part of the
generating cost, such as uranium for nuclear power plants. Fossil fuels
typically comprise a large fraction of generating costs. Their costs and long-
term availability are very important considerations in developing a long-range
electric energy supply strategy.
In this section the availability and price of fossil fuels over the
forecast period 1980 to 2010 are estimated for the Railbelt region. Additional
detail can be found in the Task I final report for the Railbelt Electric Power
Alternatives Study (Volume VII-Fossil Fuel Availability and Price Forecasts for
the Railbelt Region of Alaska).
In the assessment of fuel availability, only the in-state resource base is
considered. If the fossil fuel resource is insufficient to supply Alaska•s
needs, the cost of transporting fuels to Alaska•s markets causes in-state
substitutes to become competitive. For example, the Cook Inlet natural gas
resource may be inadequate to supply the needs of the southern part of the
Railbelt region over the time horizon of the study, given no additional major
finds. This gas could be supplemented with higher-cost liquified natural gas
(LNG) imports, but then coal, oil, and North Slope gas become competitive
substitutes.
When a current price for a fuel is not available, the concept of
opportunity cost is used to develop the base price and forecast. This concept
provides that the resource price is equal to the price that the resource will
command in an alternative market, less appropriate transportation and handling
costs. Alaska is familiar with this netback method of price determination,
which is currently used for valuation of their royalty gas and oil resources.
Table· 2.1 and Figure 2.1 summarize fossil fuel availability and price faced by
Alaska electric utilities for the forecast period.
The cost and availability of light water reactor fuel are not discussed
because the present generation of light water reactors are too large to be
2.1
incorporated in the Railbelt electrical system, and state statutes preclude
nuclear power use in Alaska.
TABLE 2.1 Fossil Fuel Availability and Price
Estimate
Annual Re
Estimated Price/MMBtu Esca 1 ati 01
Fuel TlQe Reserves Availabilitl (Januarl 1982 $) Rate
Coal
Beluga/Cook Inlet 350xl0(6) tons 1988 1.48 Mine Mouth 2.1%
Nenana/Interior 240x10(6) tons Present 1. 75 FOB Ra i 1 2.0%
Natural Gas
Cook Inlet(a) 3,900 Bcf Present 0.86 City Gate 6.6% avg.
North Slope/Interior 21,500 Bcf 1987 5.92 City Gate(b) 0
Liquids 3,800 Bcf 1995
No. 2 (Distillate) Adequate Present 6.90 Delivered 2%
Fue 1 Oi 1
Peat (c) 1988 (d) 1%
Municipal Solid Waste
Anchorage Present
Fairbanks Present
(a}
{b)
(c)
(d)
Volume weighted average price to Alaska Gas and Service and Chugach
Electric Association.
The price of North Slope gas to the interior is probably a range of prices,
of which $5.92 is a maximum. It is expected to decrease over the period of
this study {1981-2010) as the pipeline tariff decreases. This table shows
the constant price used in calculations supporting this study. Volume VII
contains the most current thinking on expected price. The net effect of
the lower gas price is not expected to change electrical consumption in the
Fairbanks region, (space heating would be done primarily with natural gas,
even at the constant $5.92 gas price). However, the use of electricity is
expected to increase somewhat in the Anchorage region under Plan 4 11 High
Natural Gas 11
, since electricity generated with lower price gas might be
able to compete successfully with gas at high and rising prices in
Anchorage.
Estimates of the peat resource in the Railbelt region are not currently
available.
Estimates range from 1 to 2.5 times the price of coal.
2.2
14.00
12.00
10.00
::I -a:!
== == 8.00 ~
N
00
$!:
6.00
4.00
2.00
1980 1990 2000
YEAR
NO.2 FUEL OIL
(2% REAL ESCALATION)
2010
FIGURE 2.1. Projected Fuel Prices to Railbelt
Utilities, 1982 $/MMBtu, 1980-2010
2.3
2.1 COOK INLET NATURAL GAS
The supply and price of Cook Inlet natural gas is the most complex of all
the Railbelt fuels to analyze because contracts have established the quantity,
current price, and price escalation rate for various portions of the gas, and
the terms of these contracts differ. In addition, new or incremental supplies
used to meet demand in excess of the contracted supply can be expected to be
priced by their opportunity value, which is the net-back from liquid natural
gas (LNG) sales to Japan. Determining the price for Cook Inlet gas requires a
forecast of both price and quantity from each contractual source to develop the
weighted average gas price for the region. The results of this forecasting is
a price escalation that is not continuous over the forecast period. This
uneven price escalation is evidenced in Figure 2.1 by the gas•s constant price
from 1980 to 1985 and its escalation over the rest of the period, with stepped
increases occurring in 1990 and 1995 when major contracts expire. After 1995,
the gas•s price and escalation rate are determined by its opportunity value
because current purchase contracts will have expired. The price of natural gas
is assumed to escalate at approximately 2% faster than general inflation -the
same real annual rate as for oil. Current information about Cook Inlet natural
gas reserves and total demand on those reserves indicates that availability to
the Alaskan market could become a major problem as early as 1990 and most
certainly by the year 2000.
2.2 COAL
Two sources of coal are available to the Railbelt. One is the Usibelli
mine located at Healy, the only commercial mine currently producing coal in
Alaska. The second source is the Beluga coal field, which has been targeted as
a potential source of supply for the Anchorage area and as an export to
markets on the Pacific Rim. As discussed below, the Beluga coal field may
enter production about 1988. The cost of Healy coal is assumed to escalate in
real terms at the historical rate. Beluga coal is expected to escalate at the
same rate as other coal supplies serving the Pacific Rim export market, or
about 2.1% annually in real terms.
There is uncertainty about w~en the Beluga coal field will be devloped.
These coal fields are now in the exploratory and predevelopment phase. They
2.4
have yet to produce in significant quantity and thus, from an availability
standpoint, must be considered prospective. These fields, while containing
very large reserves, may require an export market for financing initial
developement.
If coal-fired power generation becomes a significant factor in the
Railbelt, generation capacity most likely would be added in increments of 200
or 400 MW. While mine mouth coal-fired generation stations of 400 MW or larger
may be a large enough source of demand to justify opening the mine, a single
200 MW increment is a doubtful incentive, taken by itself. A firm take-or-pay
contract for two million tons per year (an amount which could support 600 MW
generating capacity) would be adequate incentive, as would a lesser amount,
combined with firm contracts for 2 to 4 million tons of export. (The rela-
tively large export market is needed to pay for shipping facilities.) Given
the timing of additions to generation under the various plans, an export market
may be a necessary precursor to the availability of Beluga coal for in-state
use. While the Beluga fields could be developed for electrical generation
only, the timing of such an operation would be critical (see Volume VII).
2.3 PEAT
Alaska has substantial peat reserves, although these reserves have not
been comprehensively assessed. The peat resource is a~sumed not to be
developed before Beluga coal. Although information for peat development in
Alaska is lacking, a preliminary feasibility study (EKONO 1980) estimates a
range of likely prices from about 1 to 2.5 times the price of coal on a Btu
basis, depending upon the harvesti~g and ,processing method used. The only real
escalation likely to occur is that associated with transportation and handling,
set at less than 1% real annual rate.
Based upon current resource information and existing steam-electric
generating technology, peat does not appear to be a competitive fuel for
electrical generation in the Railbelt at present. However, because of the
potential peat resources available within the area, it appears to warrant
further investigation as technologies to use peat are further developed.
2.5
2.4 NATURAL GAS/INTERIOR
The North Slope reserves of natural gas are sufficient to supply the
Alaska Natural Gas Transportation System (ANGTS) to capacity (2 to 2.4 Bcf/day}
for the forecast period. This gas was assumed to begin flowing in 1987. If
only Alaska's royalty share is diverted to serve the Fairbanks area, the supply
of gas would be about 100 Bcf per year. A current estimate of the delivered
price of gas to the "Lower 48" is about $10/MMBtu in 1982 dollars with the
January 1982 maximum wellhead price of $2.13/MMBtu. The net-back provides a
"city-gate" price to Fairbanks of about $5.92/MMBtu, declining to about $2.71
as the pipeline tariff declines. This gas is not scheduled to decontrol under
existing law and escalates only with the rate of inflation, its price remains
constant in real terms.
2.5 NATURAL GAS LIQUIDS/METHANOL
The delivery of natural gas liquids (NGL) to the Railbelt depends on the
construction schedule for the ANGTS and the real price of crude oil. Current
plans call for construction of an NGL pipeline following the ANGTS if a crude
oil price in the range of $40 to $52/barrel (1982 dollars) is reached. This
schedule provides for delivery of NGL in the mid to late 1990s.
Methanol production is tied closely to the ANGTS because the natural gas
from that system would serve as the feedstock, but the timing of methanol
production appears to be tied to petrochemical production that may accompany
the NGL pipeline. Current methanol prices have been in the range of $0.90 to
$1.00/gal. The net-back price at Alaska tidewater would range from $0.85 to
$0.95/gal or $13.29 to $14.86/MMBtu. This price must incorporate Fairbanks
city-gate price for the methane feedstock ofN$5.92/MMBtu, suggesting that
production and transportation costs from Fairbanks to tidewater can be no
greater than $7.34 to $8.91/MMBtu. Currently, methanol production is not cost
competitive with other fuels in the "Lower 48" and is not projected to become
cost competitive until after the year 2000.
2.6 FUEL OILS
Refined petroleum products are the only fuels in which Alaska is currently
not self-sufficient. Alaska's royalty share of crude oil production is
2.6
sufficient to meet in-state consumption at least through the year 2000, but
refined products are imported because of insufficient refinery capacity. The
supply of No. 2 fuel oils is not believed to be a problem through the forecast
period, however. The current price of~$6.90/MMBtu for fuel oil is a good
indicator of its current opportunity value, especially in view of the recent
price decontrol on oil. Fuel oil (and crude oil) are expected to escalate at a
2% annual real rate, as shown in Table 2.1. Figure 2.1 also shows the price of
No. 2 fuel oil over the forecast period for real annual escalation rates of 1%
and 3%.
2.7 MUNICIPAL SOLID WASTE
The municipal solid waste (MSW), in sufficient quantities to support
electricity generation, is limited to the two municipalities of Anchorage and
Fairbanks. The resource has three problems: 1) limited availability,
requiring MSW to be mixed with other fuels for electricity generation, 2)
seasonal variations (more waste is generated in the summer than in the winter),
and 3) limited storage life. However, it has two offsetting factors: 1) zero
cost since there is no value placed on the waste, and disposal costs already
exist to waste producers(a), and 2) escalation is expected in only
transportation and handling. A limited amount of MSW-based generation appears
feasible.
To summarize, coal will be the least expensive fossil fuel for electrical
generation over the time span of the study, and beyond. There is an ample
reserve of coal, and if the Beluga coal field is opened, it will lower the
price even further. Natural gas is the next least expensive fuel. An adequate
supply for Railbelt purposes depends on the availability of North Slope
resources. The most expensive conventional fuel is No. 2 fuel oil. Other
fuels having potential for electricity generation include peat and municipal
solid waste.
(a) MSW as fuel might claim a negative price depending on the relative
magnitude of collection costs and the offset disposal costs.
2.7
3.0 ANNUAL PEAK LOAD AND ENERGY REQUIREMENTS FORECASTS
The second consideration in developing the electric energy plans for the
Railbelt region is a forecast of electrical demand. Forecasts typically take
into account the following factors:
• future economic and population growth
• future changes in the age, size, and energy-use characteristics of
households
• future growth in commercial building stock
• future price and availability of fuels that compete with electricity for
such end uses as space and water heating (e.g., fuel oil, natural gas, and
wood)
• application of conservation measures
• public policy actions directly affecting energy demand or the cost of
power
• potentially new, large uses of electric power in industrial applications.
Since groups of these factors may interact in complex ways to produce a range
of possible (but not equally plausible) forecasts, computer models were
developed to determine how these factors individually and jointly affect demand
estimates. The models, together with certain key assumptions concerning
Alaska•s economy and public policy and world prices for fossil fuels, produced
forecasts of electricity demand at five-year intervals beginning 1980.
3.1 OVERVIEW OF DEMAND FORECASTING PROCESS
The electricity demand forecasting process used in this study is
illustrated in Figure 3.1. It contains two steps. The first combines
scenarios (economic and policy assumptions) with economic models to produce
forecasts of future economic and industrial activity, population, and
households in the Railbelt region. The second step combines these forecasts
with data on current end .uses of electricity in the residential sector, the
size of the Railbelt commercial building stock, the cost and performance of
3.1
w .
rv
ECONOMIC SCENARIOS
• ECONOMIC ASSUMPTIONS __ --.
• POLICY ASSUMPTIONS
ECONOMIC MODELS
• STATEWIDE MODEL
FORECASTS OF ECONOMIC AND
INDUSTRIAL ACTIVITY
POPULATION AND HOUSEHOLDS
• REGIONALIZATION MODEL ____ ~
• HOUSEHOLD FORMATION MODEL
INPUT DATA AND ASSUMPTIONS
• RESIDENTIAL END USE OF
ELECTRICITY
• COMMERCIAL BUILDING STOCK
• COST AND PERFORMANCE OF
CONSERVATION
• FUEL COST PROJECTIONS
~
END USE MODEL
(Railbelt Electricity
Demand)
+ ELECTRIC ENERGY DEMAND
FORECASTS
• ANNUAL ENERGY
• PEAK DEMAND
FIGURE 3 .1. Electric Power Forecasting Process
conservation, assumptions concerning the future prices of electricity and other
fuels, and future new uses of electricity, to produce demand forecasts.
These data and assumptions are entered into a computer-based electricity
demand forecasting model called the Railbelt Electricity.Demand (RED)
Model.(a). The RED model generates forecasts of the amount of housing and
commercial floor space (including government buildings), their energy use as
affected by cost of the energy, and the proportion of energy used as
electricity. Major industrial and military electrical energy demand and
miscellaneous uses, such as street lighting, are estimated separately.(b)
These forecasts and estimates are adjusted for energy conservation policies and
combined by the model into forecasts of future annual demand for electric
energy for each of the Railbelt's load centers {Figure 1.1). Annual peak loads
are derived from the annual demand. The peak loads are added together and
multiplied by a diversity factor (to adjust for the fact that peak loads do not
coincide in time) to derive the peak demand for the Railbelt.
The projected cost of power affects these forecasts. The demand for power
affects the size, number, and cost of generating facilities, which in turn
affects the cost of power. Several interations through the RED model with a
single set of economic assumptions and varying costs of power are required to
produce a final forecast, as described in Section 6.0.
Each of the foregoing steps in the Demand Forecasting Process is described
in greater detail in the following sections.
3.2 ECONOMIC SCENARIOS
The economic scenarios used to produce the demand forecasts are shown in
Figure 3.2. The scenarios are characterized by combinations of assumptions
concerning private economic activity and State of Alaska fiscal policy. The
private economic assumptions are principally composed of assumed levels of
development in Alaska's basic or export sector. (A summary of the private
sector projects and growth rates is contained in Appendix B to this report.
(a) A complete description of the RED model is contained in Volume VIII.
(b) The forecasts produced for this report do not include military electrical
consumption or industrial self-generated electricity because neither is
assumed to be part of the electric utility load addressed in this study.
3.3
PRIVATE ECONOMIC ACTIVITY
HIGH MODERATE LOW
HIGH HH, SH
t!) z
Q z
I.U c.. MODERATE Vl
I.U
1-
~
Vl
LOW
HH-HIGH ECONOMIC GROWTH,
HIGH STATE SPENDING
SH-HIGH ECONOMIC GROWTH,
HIGH STATE SPENDING,
PLUS EXTRA
INDUSTRIALIZATION
PROJECTS
MM-MODERATE ECONOMIC
GROWTH, MODERATE STATE
SPENDING
FIGURE 3.2.
MM, IM, CC
LL
IM-MODERATE ECONOMIC
GROWTH, MODERATE STATE
SPENDING, PLUS EXTRA
INDUSTRIALIZATION
PROJECTS
CC-MODERATE ECONOMIC
GROWTH, NON-SUSTAINABLE
SPENDING
LL-LOW ECONOMIC GROWTH,
LOW STATE SPENDING
Economic Scenarios
3.4
Additional detail can be found in Goldsmith and Porter (1981), Volume IX, a
report on the Railbelt economy done for this study by the University of Alaska
Institute of Social and Economic Research.) The future spending of the State
of Alaska is expected to be a major driving force in the Alaskan economy during
the time horizon for this study (1980 to 2010). Different levels of State
spending in each forecast year were assumed. The following assumptions are
made for the three basic scenarios:
• High -State spending (basic operating and capital budget) grows at 1.5
times thetgrowth rate of real per capita income in Alaska.
• Moderate -State spending grows at the same rate as real per capita
income.
• Low -State spending is constant in real per capita terms (falls as a
percent of real per capita income).
Combinations of private economic activity and State fiscal policy were chosen
for analysis (Figure 3.2). The combinations of high economic growth and high
State spending, moderate growth and spending, and low growth and spending
constitute the basic scenarios. The high case (case HH) has been given a
subjective probability of 0.05 to 0~10; that is, there is a 5 to 10% chance
that economic growth will exceed this level. The moderate case (case MM) is
given a subjective probability of 0.5. There is a 50% chance that growth will
be at least this large, and a 50% chance that it will be less. The low case
(case LL} is given a subjective probability of 0.9 to 0.95. There is a 90 to
95% chance that economic growth will be at least this large, with a 5 to 10%
chance that it will be less.
Several additional cases were selected to test the sensitivity of the
assumptions. The first two cases, Cases SH and IM, measure the effect of major
industrialization projects on the Railbelt's economy, population, and
electrical demand.(a) Several large industrial energy users were added to
(a) One school of thought believes that major manufacturing activity could be
drawn to Alaska by the prospect of abundant and perhaps relatively
inexpensive energy. Previous work by Battelle-Northwest and others (Swift
et al. 1978; Dow-Shell 1981) suggests that currently this is not very
likely; however an ongoing study on this specific question is being done
for the State of Alaska by SRI, International.
3.5
moderate and high scenarios assuming that they would be located in the Railbelt
and they purchase the bulk of their electric power from the utilities in the
region. The third case (CC) assumes that State spending will not be sustained
if Prudhoe Bay oil production begins to decline in the .1990s. This scenario
assumes very high capital spending in the 1980s. Details on the assumptions
are contained in Goldsmith and Porter (1981).
Several other sensitivity tests that did not involve changes in economic
activity were also analyzed (Section 7.0). One includes the effect of a major
state direct cash investment to defray part or all of the capital cost of
electrical generation facili·ties. This has the effect of reducing the price of
power to the consumer with large increases in demand. For purposes of this
sensitivity test, reducing the price of power was assumed not to affect the
level of economic growth. (Such price-induced economic growth may occur, but
sufficient research has not been done on the question to say how large the
growth response might be.) The effects of recent lower oil prices are
summarized in the addendum to the Executive Summary.
3.3 ECONOMIC MODELS
The scenarios described above were analyzed by three economic models
modified by the Institute of Social and Economic Research (ISER) for this
study. The first was an ISER economic and population model of Alaska, usually
called MAP.(a) MAP calculates statewide employment by broad sectors (basic,
support, and government) and statewide population. The results from MAP are
entered into a second model, a regionalization model that allocates economic
growth to census division and then reaggregates the results to the Railbelt 1 S
electrical demand (load) centers. The third model (now a part of MAP)
calculated the total number of households in the State for each year and for
each estimate of population growth.
(a) MAP is an acronym for Man in the Arctic Program. Several key parameters in
the MAP modeling framework underwent extensive testing in this study, and
econometric equations of the model were re-estimated based on actual data
through 1979 (and where data were available, through 1980). Details of the
research conducted by ISER on the models are contained in Volume IX.
3.6
3.4 FORECASTS OF ECONOMIC AND INDUSTRIAL ACTIVITY, POPULATION AND HOUSEHOLDS
The population forecasts for the Railbelt region produced by these codes
are summarized in Figure 3.3. The solid-line forecasts to the year 2000 were
produced by the MAP model. The forecasts were then extrapolated to the year
2010 (dashed lines). The detailed employment, population, and household
forecasts for the Railbelt and its load centers from which these projections
are derived, are reported in Appendix B. Population growth rates vary
considerably among cases, but most cases show decelarating growth during the
period. The base case (moderate growth-moderate State spending -MM) shows an
annual rate of population growth averaging 3.4% during the 1980s and 2.1% per
year for the 30-year average. This compares with 3.4% in the 1970s, with 6.7%
from 1970 to 1975 and 0.1% from 1975 to 1980. Railbelt population is forecast
to grow from 286,000 to about 539,000. The high growth, high State spending
case (HH) shows an average growth rate of 3.8%, resulting in a population of
about 870,000 in year 2010. The low-low case (LL) shows 1.5% growth and a
population of 448,000. The cases that include large projected industrial-
ization add about 0.3% to 0.9% to growth rates in the high and moderate cases,
respectively.
The nonsustainable spending case (CC), which is based on moderate private
sector economic growth but very high initial State government spending, shows
growth rates in the 1980s comparable to those in the high case. As State
spending declines in the 1990s, population growth stagnates and then falls as
employment declines. Population falls below the low case about year 2003 and
continues downward to about the same as the 1985 level (about 363,000).
3.5 END USE MODEL (RAILBELT ELECTRICITY DEMAND MODEL)
The Railbelt Electricity Demand (RED) forecasting model was described
briefly in Section 3.1. In addition to the capabilities previously described,
the RED model includes a mechanism for handling uncertainty in some of the
parameters, a method for explicitly including programs designed to subsidize
or mandate conservation, and the ability to forecast peak electric demand by
load center. The model recognizes the three load centers: Anchorage-Cook
Inlet (including the Matanuska-Susitna Borough and the Kenai Peninsula);
3.7
MAP MODEL PROJECTIONS
900 EXTRAPOLATIONS
800
700
600
500
400
300
ANNUAL GROWTH RATES:
(%)
200 CASE --
YEARS SH HH IM MM LL cc
1980-1990 5. 3 5.1 4.2 3.4 2.5 4.8
100 1990-2000 3.6 3.2 2.5 2.0 LO 0.0
2000-2010 3.5 3.2 2.4 Ll LO 2.2
1980-2010 4.1 3. 8 3.0 2.1 L5 0.8
1980 1985 1990 1995 2000 2005 2010
FIGURE 3.3. Railbelt Population
3.8
Fairbanks-Tanana Valley and Glennallen-Valdez. It produced forecasts for each
five-year period from 1980 to 2010.
The RED model operates as shown in Figure 3.4. A simulation begins with
the Uncertainty Module (1) by selecting a trial set of model parameters. These
parameters include demand-price elasticities, appliance saturations, housing
stock demand coefficients, load factors, peak demand correction factors, and
penetration rates for conservation. Exogeneous forecasts {2) of economic
activity, population, and retail prices for fuel oil, gas, and electricity are
used with the trial parameters to produce forecasts of housing stock (3) and
electricity consumption in the residential {4) and business (5) modules. These
latter forecasts, along with additional trial parameters, are used in the
conservation module (6) to model the effects on consumption of subsidized
conservation activities. The revised forecasts of residential and business
(commercial and government) consumption are used to estimate future
miscellaneous consumption (7). Assumed large industrial consumption (8) is
added to produce total electricity sales (9). Finally, the initial and the
revised consumption forecasts are used with a trial forecast of system load
factor to estimate peak demand (10) in each load center. The model then
returns to start the next trial. The model usually reaches a consistent
forecast in about two iterations.
3.6 ELECTRIC ENERGY DEMAND FORECASTS
A summary of the RED model forecasts of electricity consumption and demand
for the Railbelt is shown in Figures 3.5 and 3.6.(a) In the moderate case
(MM), future consumption of electric energy (Figure 3.5) is forecasted to
(a) Since the supply plan chosen to generate electricity in the Railbelt can
itself influence energy consumption, the forecasts in Figures 3.5 and 3.6
are based on electric energy plan 1A, which assumes the addition of about
400 MWe of gas combined-cycle and coal steam plants, and 430 MWe of
hydroelectric generation. The electric energy plans are described in
Section 6, and the effect of supply plans on demand in Section 7. The
electricity demands for the other economic scenarios and electric energy
plans are presented in Appendix B.
3.9
FORECAST
• ECONOMY
• POPULATION
2• FUEL PRICES
~~fif~ ou /::
HOUSING
~ STOCK
3 MODULE
' ~ RES I DENTI AL
CONSUMPTION
4 MODULE
, t"-e BUSINESS
CONSUMPTION
5 MODULE
~
__.. CONSERVATION
-~ MODULE 6 ..
LARGE MISCELLANEOUS
INDUSTRIAL CONSUMPTION
8 DEMAND ~ 7 MODULE
"'
TOTAL
ANNUAL
9 SALES
' ~ PEAK
10 DEMAND
FIGURE 3.4. Railbelt Electricity Demand (RED) Model
3.10
::c
3:
(.J
M'
0
~ z
0
1-
Q. ::
::::>
Ill z
0 u
u
0:::
1-u w
.J w
17
16
15
14
13
12
11
10
9
1980
YEARS
1980-1990
199Q-2000
200Q-2010
198Q-2010
ANNUAL GROWTH RATES
(%)
SH
9. 8
5. 7
l8
5. 7
1985
CASE
1M.
7. 9
6.2
1.4
5.1
1990
HH
7.8
l6
3.5
4.3
MM U
5. 3 4. 2
l7 0.3
2.2 2.2
3.0 2.2
1995
YEARS
cc
6.3
-l4
-l8
lO
2000 2005 2010
FIGURE 3.5. Railbelt Annual Electricity Consumption. l980-2010(a)
(a) Excluding military and industrial self-supplied electricity.
3.11
3:
:E
Q z < :E
'""" Q
~ <
'""" c..
YEARS
1980-1990
1990-2000
2000-2010
1980-2010
1980 1985
ANNUAL GROWTH RATES
(%)
CASE
SH IM
8. 0 6. 7
3.8 3.8
2.4 1.9
4. 7 4.1
1990
HH MM LL
7.0 TI 4.0
1.5 1.5 0. 2
3.6 2.2 2.1
4.0 2.9 TI
1740
1995
YEARS
cc
TI
-1.5
-1.8
0. 9
2000 2005
FIGURE 3.6. Railbelt Annual Peak Demand, 1980-2010(a)
(a) Excluding military and industrial self-supplied-electricity.
3.12
2010
averageN3.0% between 1980 and 2010, from 2500 gigawatt hours {GWh) to 6300
GWh. This results in a per capita increased use of~0.9% per year. As
previously stated, there is about a 50% probability that the growth rate will
be greater for this case, and about a 50% probability that it will be less.
The low {LL) case grows at 2.2% per year to 4900 GWh in year 2010. Only a 2.5%
to 5% probability exists that growth in electricity use will be less than this
rate.(a) The high {HH} case shows an average growth rate of 4.3% per year to
9000 GWh. There is a 95% to 97.5% probability that growth will be less.
Substantial industrialization (cases SH and IM) add 1.4 and 2.1 percentage
points to the 30-year growth rates in the high and moderate cases,
respectively, and result in year 2010 use that is 50% to 81% above the
corresponding high and moderate cases. The near-term growth (through 1995) is
very large. The industrialization scenarios are unlikely to occur, however,
with projected power costs in the 60 to 80 mills/kWh range.
The unsustainable spending case (CC) shows only 1.0% average annual growth
during the period, with a 1980 to 1990 rate of 6.3% and 2000 to 2010 rate of
minus 1.8%. Per capita use, which grows at 0.9% in the MM case and as high as
2.1% annual in the IM case, grows in the CC case at only 0.2% annual average
over the forecast period. The CC case results in demand that is about 400GWh
above the MM case in 1990, but about 290 GWh per year below the MM case in the
year 2010. Because the unsustainable spending (CC) case is so heavily
dependent on State fiscal policy, no probability estimate is attached to it.
' The peak demands for electric power-are shown in Figure 3.6. The present
peak demand of 540 MW increases to 1760 MW for the high case, 1260 MW for the
medium case, and 1000 MW for the low case by the year 2010.(a) In the
industrialization cases, SH and IM, major industrial electricity users are
assumed to have constant loads, thereby contributing proportionately less to
(a) Economic growth assumed in this case is such that only a 5% to 10%
probability exists that it would be lower. The LL projection forecasts
median demand given the economic scenario. The probability of a forecast
being below the LL line is then 0.05 to 0.10 (the probability of the
economic scenario) times 0.5 (the probability of a forecast being below
the median), or 0.025 to 0.005.
3.13
system peak than to annual consumption. Peak demand average growth rates in
these cases are 1.0% less than annual energy growth rates. The industriali-
zation cases result in a net increase of 400 MW over the high case (to 2160 MW)
and 530 MW over the moderate case (1260 MW) in the year 2010. The unsus-
tainable spending case (CC) again results in the lowest demand by the year
2010, a decline of 28% from 1990 demand, and 560 MW below the moderate case MM.
To summarize, the estimated growth in electric power peak demand, based on
econometric modeling studies, is expected to increase from 540 MW at present to
about 1260 MW in 2010, with a range of 700 to 2160 MW, depending on economic
activity and State spending.
(a) The growth rates in peak demand in the three cases (HH, MM, LL) average
0.1% greater than the corresponding growth rates in annual energy demand;
e.g., moderate case peak demand averages 2.9% per year. These growth
rates are greater because the ratio of system peak load to annual
electrical load is assumed to remain constant through the forecast period,
except for specific energy conservation effects and large industrial use
for which demand information was available. This assumption is replaced
in Section 7, where the load factors are allowed to vary. As a part of
the study, an attempt was made to determine the impact of changing energy
uses on peak load. However, Railbelt utilities were unable to break out
the effect of end uses in current (1981) peak demand.
3.14
4.0 ELECTRICAL ENERGY GENERATING AND CONSERVATION ALTERNATIVES
Having established the bounds of electrical generation growth in the
Railbelt region to the year 2000--from the present 540 MW peak to between 700
and 2160 MW--the electric power generation and conservation alternatives were
selected and analyzed. The first portion of this section describes the
selection of generating alternatives, including a brief technical description,
the rationale for selection, and the prototypical plants and sites used to
develop the data required for assessing Railbelt electric energy plans. It
concludes with a summary of cost and performance characteristics of the
selected generation alternatives. The second portion describes conservation
alternatives and technologies, and the rationale for their selection.
4.1 GENERATING ALTERNATIVES
The generating alternatives required for the Railbelt electric energy
plans were selected by identifying a broad set of candidate technologies,
constrained only by the availability of suitable resource bases in the Railbelt
and the ability to place them in commercial service prior to year 2000. The
candidate technologies were evaluated based on several technical, economic,
environmental, and institutional considerations. Using the results of this
evaluation, a set of more promising technologies was then identified. Finally,
prototypical generating faciliti·es (specific sites in the case of hydroelectric
generation) were identified and analyzed in greater detail.
Resources currently used in the Railbelt for electricity generation
include coal, natural gas, petroleum-derived liquids, and hydropower. Energy
resources that could be developed within the planning period of this study
include peat, wind power, solar energy, tidal power, geothermal, municipal
solid waste fuels, and wood waste. While light water reactor fuel could be
readily supplied to the Railbelt, economic considerations and state statutes
preclude the use of nucler power reactors.
Candidate electric generating technologies using these resources and
available for commercial .order prior to year 2000 are listed in Table 4.1. The
37 generation technologies and combinations of fuel conversion-generation
4.1
TABLE 4.1. Candidate Electric Energy Generating TechnoloQies for The Railbelt
Resource Principal Sources Fue 1 Generation Typical Availability for Base for Railbelt Conversion Technolog:t A[!!:! llcation r.onmercial Orrler
Coal Beluga Field. Cook Inlet Crush Direct-Firer! Steam-Electric Base load Currently Available
Nenana Field, Healy
Gasification Direct-Firer! Steam-Electric Base load 1985-1990
Combined Cycle Base 1 oad /C.vc l i nq 1985-1990
Fuel-Cell -Combined-Cycle Base load 1990-1995
Liquefaction Direct-Fired Steam-Electric Base load 1985-1990
Combined Cycle Base load/Cycling 1985-1990
Fuel-Cell Station Base 1 oad /Cyc 1 ing 1985-1990
Fuel-Cell -Combined-Cycle Baseloacl 1990-1995
Natural Gas Cook Inlet None Direct-Fired Steam-Electric Base load Currently Available
North Slope Combined Cycle Base load/Cycling Currently Available
Fuel-Cell Station Base load /Cyc 1 i ng 1985-1990
Fue 1-Ce 11 -Combined-C.vc le Base load 1990-1995
Combustion Turbine Base load/C.vc 1 i ng Currently Available
Petroleum Cook Inlet Refine to Direct-Fired Steam-Electric Base load Currently Ava i1 able
North Slope distillate and Combined Cycle Base load/Cycling Currently Available
,j:::. residual fractions Fuel-Cell Stations Base load/Cycling 1985-1990
0 Fuel-Cell -Combined-Cycle Base load · 1990-1995 N Combustion Turbine Base 1 oad /Cyc 1 ing Currently Available
Diese 1 Electric Base load/Cycling Currently Available
Peat Kenai Peninsula None Direct-Fired Steam.,Electric Base load Currently Available
lower Susitna Valley
Gasification Direct-Fired Steam-Electric Base load 1990-2000
Combined Cycle Base 1 oad /Cyc 1i OQ 1990-2000
Fue 1-Ce 11 -Comb i ned-Cyc 1 e Base load 1990-2000
Municipal Solid Anchorage Sort & Classify Direct-Fired Steam-Electric Base load( a) Currently Available Waste Fairbanks
Wood Waste Kenai Hog Direct-Fired Steam-Electric Base load( a) Currently Available Anchorage
Nenana
Fairbanks
~ .
w
Resource
Base
Geothermal
Hyd roe 1 ec tri c
Tida 1 Power
Wind
Solar
Uranium
Principal Sources
for Railbelt
Wrangell Mountains
Chigmit Mountains
Kenai Mountains
A 1 ask a Range
Cook Inlet
Isabell Pass
Offshore
Coasta 1
Throughout Region
Import
TABLE 4.1. ( contd)
Fuel Generation
Conversion Techno log~
Hot Dry Rock-Steam-Electric
Hydrothermal-Steam-Electric
Conventional Hydroelectric
Small-Scale Hydroelectric
Microhydroelectric
Tidal Electric
Tida 1 Electric w/Retime
Large Wind Energy Systems
Small Wind Energy Systems
Solar Photovoltaic
So 1 ar Therma 1
Enrichment & Light Water Reactors
Fabrication
(a) Supplemental firing (e.g. with coal) would be required to support
baseload operation due to cyclical fuel supply.
(b) May be baseload/cycling or fuel saver depending upon reservoir capacity.
Typical Availahi lity for
A~~lication Commercial Order
Base load 1990-2000
Base load CurrPnt ly Avail ah le
Base 1 oad /C.vc 1 i nq Currently Available
(b) -Currently Available
Fuel Saver Currently Avail ah le
Fuel Saver Currently Available
Base load/Cycling Currently Available
Fuel Saver l985-1g9Q
Fuel Saver 1985-1990
Fuel Saver 1985-1990
Fuel Saver 1995-2000
Base load Currently Available
technologies shown in the table comprised the candidate set of technologies
selected for additional study.(a)
11 Technology profiles 11 were prepared describing the technical performance
and cost, environmental and socioeconomic characteristics, and potential
Railbelt applications of the candidate technologies (Volume IV). The profiles
were used in the analysis of the candidate technologies to determine which
should be included in Railbelt electric energy plans. This selection was based
on the following considerations:
• the availability and cost of energy resources
• the likely effects of minimum plant size and operational characteristics
on system operation
• the economic performance of the various technologies as reflected in
estimated busbar power costs
• public acceptance, both as reflected in the framework of electric energy
plans within which the selection was conducted and as impacting specific
technologies
• ongoing Railbelt electric power planning activities.
From this analysis(a) 13 generating technologies were selected.
each nonhydroelectric technology, a prototypical plant was defined.
For
For the
hydro-electric technologies, promising sites were selected for further study.
In the following paragraphs, each of the 13 preferred technologies is briefly
described, along with some of the principal reasons for its selection. Also
described are the prototypical plants and hydro sites selected for further
study.
4.1.1 Coal-Fired Steam-Electric Plants
Coal-fired steam-electric plants combust coal in a boiler, producing steam
that is used to drive a steam turbine-generator. Coal-fired steam-electric
generation was selected because it is a commercially mature and economical
technology that potentially is capable of supplying all of the Railbelt•s
(a) Further discussion of the selection process and technologies rejected from
consideration at this stage are provided in Volume IV.
4.4
baseload electric power needs for the indefinite future. An abundance of coal
in the Railbelt should be mineable at costs allowing electricity production to
be economicaly competitive with all but the most favorable alternatives
throughout the planning period.
The sulfur content of Railbelt coal is low. Commercially tested devices
for controlling sulfur and particulate emissions to levels mandated by the
Clean Air Act are available. Principal concerns using this technology are
environmental impacts of coal mining, possible ambient air-quality effects of
residual oxides of sulfur (SO ), oxides of nitrogen (NO ), and particulate X X
emissions, long-term atmospheric buildup of co 2 (common to all combustion-
based technologies) ~nd the long-term susceptibility of busbar power costs to
inflation.
Two prototypical facilities were chosen for in-depth study: a 200-MW plant
in the Beluga area that uses coal mined from the Chuitna Field; and a plant of
similar capacity at Nenana that uses coal delivered by Alaska Railroad from the
Nenana field at Healy. The results of the prototypical study are documented in
Volume XII.
4.1.2 Coal Gasifier -Combined Cycle Plants
These plants are comprised of coal gasifiers that produce synthetic gas for
combustion turbines that drive electric generators. Heat-recovery boilers use
the combustion turbine exhaust heat to raise steam to drive a steam turbine-
generator. These plants are expected to be commercially available in the 1985
to 1990 time frame.
These plants should use Alaskan coal resources at costs comparable to
conventional coal steam-electric plants, while providing environmental and
operational advantages compared to conventional plants. Environmental
advantages include less waste-heat rejection and water consumption per unit for
output due to higher plant efficiency. Better control of NOx, SOx, and
particulate emission is also afforded. From an operational standpoint, these
plants offer a potential for load-following operation, broadening their
application to intermediate loading duty.(a) Because of superior plant
(a) However, much of the existing Railbelt capacity most likely will be
available for intermediate and peak loading during the planning period.
4.5
efficiencies, coal gasifer-combined-cycle plants should be somewhat less
susceptible to inflation of fuel costs than conventional steam-electric
plants. Principal concerns with these plants include environmental impacts of
coal mining, co 2 production, and uncertainties in plant performance and
capital cost due to the current state of technology.
A prototypical plant was selected for in-depth analysis. This 200-MW plant
would be located in the Beluga area and use coal mined from the Chuitna Field.
The plant would use oxygen-blown gasifiers of Shell design, producing a medium
Btu synthesis gas for combustion turbine firing. The plant would be capable of
load-following operation. The results of the study of the prototypical plant
are described in Volume XVII.
4.1.3 Natural Gas Combustion Turbines
These plants consist of combustion turbines fired by natural gas to drive
electric generators. Although of relatively low efficiency, natural gas
combustion turbines serve well as peaking units in a system dominated by steam-
electric plants. The short construction lead times characteristic of these
units also offer opportunities to meet unexpected or temporary increases in
demand. Except for production of co 2 and potential local noise problems,
these units produce minimal environmental impact. The principal economic
concern is the sensitivity of these plants to escalating fuel costs.
The costs and performance of combustion turbines are well understood.
However, because a major component of future Railbelt capacity additions most
likely would not consist of combustion turbines, no prototype was selected for
in-depth study. Analysis of this technology within the context of Railbelt
electric energy plans was based on data compiled in the technology profiles
(Volume IV).
4.1.4 Natural Gas -Combined-Cycle Plants
These plants consist of combustion turbines fired by natural gas to drive
electric generators. Heat recovery boilers use combustion turbine-exhaust heat
to raise steam to drive steam turbine generators.
Natural gas -combined-cycle plants were selected for consideration because
of the current availability of low-cost natural gas in the Cook Inlet area and
the possible future availability of North Slope supplies in the Railbelt
4.6
(although at prices higher than those currently experienced). Combined-cycle
plants are the most economical and environmentally benign method currently
available to generate electric power using natural gas. The principal economic
concern is the sensitivity of busbar power costs to increases in natural gas
costs. The principal environmental concern is co 2 production and possible
local noise problems.
A nominal 200-MW prototypical plant was selected for further study. The
plant, located in the Beluga area, would use Cook Inlet natural gas. The
results of the analysis of this prototype are documented in Volume XIII.
4.1.5 Natural Gas Fuel-Cell Stations
Natura 1 gas fue l-ee 11 stations are expected to be ava i 1 ab 1 e for commercia 1
order in the 1985 to 990 period. These plants consist of a fuel conditioner to
convert natural gas to hydrogen and co 2 , phosphoric acid fuel cells to
produce de power by electrolytic oxidation of hydrogen, and a power conditioner
to convert the de power output of the fuel cells to ac power. Fuel-cell
stations most likely would be relatively small and sited near load centers.
Natural gas fuel-cell stations are considered for the Railbelt primarily
because of their superior load-following characteristics. Plant efficiencies
are likely to be far superior to combustion turbines and relatively unaffected
by partial power operation. Capital costs are likely to be comparable to
combustion turbines. These cost a~d performance characteristics should lead to
significant reduction in busbar power costs and greater protection from
escalation of natural gas prices compared to combustion turbines. Construction
lead time should be comparable to combustion turbines. Because environmental
effects most likely will be limited to co 2 production, load-center siting
will be possible and transmission losses and costs will be reduced.
No prototypical plant was selected for further study. Data for the
analysis of these facilities were taken from the technology profiles
(Volume IV).
4.1.6 Natural Gas Fuel-Cell -Combined-Cycle Plants
Thes plants are expected to be available in the 1990 to 1995 period. They
consist of a fuel conditioner that converts natural gas to hydrogen and carbon
dioxide, molten carbonate fuel cells that produce de power by electrolytic
4.7
ALASKA RESOURCES LTP~ARY
U.S. DEP'l'. OF INTERIOR
oxidation of hydrogen, and heat recovery boilers that use waste heat from the
fuel cells to raise steam for driving steam turbine-generators. A power
conditioner converts the de fuel cell output to ac power for distribution. If
they attain commercial maturity as envisioned, fuel-cell combined-cycle plants
should demonstrate a substantial improvement in efficiency over conventional,
combustion turbine-combined-cycle plants. The reduction in fuel consumption
promised by the forecasted lower heat rate of these plants could result in a
baseload plant less sensitive to inflating fuel costs and less consumptive of
limited fuel supplies than conventional combined-cycle plants (and may be
limited to baseload operation). Likely capital costs are not well-understood,
however, due to the immaturity of this technology.
Because of the early stages of development of these plants, additional
study was believed to yield little additional useful information.
Consequently, no prototypical plant was selected for study. Information to
support analysis of Railbelt electric energy plans was drawn from the
technology profiles (Volume IV).
4.1.7 Large and Intermediate-Scale Hydroelectric Plants
Substantial hydro resources are present in the Railbelt region. Much of
this could be developed with large-or intermediate-scale hydroelectric plants
(i.e., those larger than 15 MW). Several sites have the potential to provide
power at first-year costs competitive with thermal alternatives and have the
added benefit of long-term resistance to inflation. Hydroelectric options
produce no atmospheric pollution or solid waste, but they can destroy or
transform habitat in the area of the reservoir, impact wilderness value and
associated recreational opportunities, and have negative impacts on downstream
and anadromous fisheries. High capital investment costs render many sites
noncompetitive with alternative sources of power.
Several large-scale hydroelectric projects were selected for consideration
in Railbelt electric energy plans:
4.8
• Bradley Lake
• Chakachamna
• Upper Susitna (Watana and Devil Canyon)
• Snow
• Keetna
• Standline Lake
• Browne.
Bradley Lake was selected for consideration because of its advanced stage
of p·lanning. Information was taken primarily from its power market analysis
(Alaska Power Administration 1977). The Chakachamna project is a lake tap
project with relatively modest capital costs and environmental effects. The
proposed project is of sufficient size (up to 1923 GWh average annual energy
production) to make a significant contribution to meeting future Railbelt
electric energy demand, yet not so large as to result in underutilization when
operational. Data were obtained from two sources, an investigation
commissioned as part of this study (Volume XIV) and the ongoing Bechtel
feasibility study (Bechtel Civil and Minerals 1981). The Upper Susitna Project
was selected for consideration because of its importance in the Alaska energy
picture. Data were obtained from Acres American Incorporated (1981).(a)
Based on environmental and economic considerations, the Snow, Keetna,
Standline Lake, and Browne hydroelectric projects were among several
hydroelectric projects (along with the Chakachamna Project discussed above and
the Allison Project discussed in the subsequent section) identified by Acres
American (1981) as preferred hydroelectric alternatives to the Upper Susitna
Project. Snow, Keetna, Strandline Lake, and Browne were selected from this set
as having the most favorable costs and environmental effects. Data on the
Snow, Keetna, and Strandline Lake projects were taken from the Upper Susitna
Development Study (Acres American 1981). A study of the Browne project was
commissioned, partly because of its estimated capacity and energy projection,
(a) Information superseding that provided in Acres American (1981) was
supplied by a letter from J. D. Laurence of Acres American to
J. J. Jacobsen of Battelle, Pacific Northwest Laboratories.
4.9
which was somewhat greater than the others, but also because of its apparently
modest environmental impact (Volume XV).
4.1.8 Small-Scale Hydroelectric Plants
Small-scale hydroelectric plants include facilities having rated capacity
of 0.1 MW to 15 MW. Several small-scale hydro sites have been identified in
the Railbelt region and two currently undeveloped sites (Allison and Grant
Lake) have been subject to recent feasibility studies. Although typically not
as economically favorable as conventional hydro because of higher capital costs
per installed kw, small-scale hydro affords similar long-term protection from
inflation and may be of more appropriate size for small load centers than large
projects. The environmental effects of small-scale hydro tend to be
proportionally less than for conventional hydro development, especially since
many of these projects are run-of-the-river or lake tap designs and do not
involve development of a reservoir. Run-of-the-river projects, however, may be
intermittent producers of power due to seasonal variation in streamflow.
Two small-scale hydroelectric projects were selected for consideration in
Railbelt electric energy plans: the Allison hydroelectric project at Allison
Lake near Valdez and the Grant Lake hydroelectric project of Seward. These two
projects appear to have relatively favorable economics compared with other
small hydroelectric sites and relatively minor environmental impact (each is a
lake tap project). Information to support analysis of these alternatives was
taken from the feasibility study recently completed on each (Corps of Engineers
1981; CH 2M-Hill 1981).
4.1.9 Microhydroelectric Systems
Microhydroelectric systems are hydroelectric installations rated at 100
kW or less. They typically consist of a water-intake structure, a penstock and
turbine-generator. The units typically operate on run-of-the-stream without
reservoirs. The technology is commercially available.
Microhydroelectric systems were chosen for analysis because of public
interest, their renewable character and potentially modest environmental
impact. Information on typical power production costs was not available when
the preferred technologies were selected. Further analysis indicated that few
microhydroelectric resources could be developed for less than 80 mills/kWh.
4.10
Their contribution would likely be minor. Because of the limited potential of
this resource it was dropped from consideration. However, installations at
certain sites, for example residences remote from distribution systems, may be
justified.
4.1.10 Large Wind Energy Conversion Systems
Large wind energy conservation systems consist of machines of 100 kW
capacity and greater. These systems typically would be installed in clusters
in areas.of favorable wind resource and would be operated as central generating
units. Operation is primarily in the fuel-saving mode because of the
intermittent nature of the wind resource. The technology is in the
demonstration stage.
Large wind energy conversion systems were selected for several r-easons.
Several areas ~f excellent wind resource have been identified, notably.in the
Isabell Pass area of the Alaska Range, and in coastal locations. The winds in
these areas are strongest during fall, winter, and spring months, coinciding
with the winter-peaking electric load of the Railbelt. Furthermore, developing
wind energy projects in the Railbelt would prove complementary to hydroelectric
systems. Surplus wind-generated electricity could be readily "stored" by hydro
reservoirs. Hydro operation could be used to assume loads during periods of
wind insufficiency. Wind machines could provide additional energy, whereas
excess installed hydro capacity could provide capacity credit. Finally, wind
systems have few environmental effects with the exception of their visual
presence; they appear to have widespread public support.
A prototypical large wind energy conversion system was selected for further
study. The prototype consisted of a wind farm located in the Isabell Pass area
comprised of ten 2.5 MW-rated capacity, Boeing MOD-2, horizontal axis wind
machines. The results of the prototype studied are provided in Volume XVI.
4.1.11 Small Wind Energy Conversion Systems
Small wind energy conversion systems are small wind turbines of either
horizontal or vertical axis design, rated at less than 100-kW capacity.
Machines of this size wouJd generally be installed at dispersed locations. The
technology is commercially available but still developing.
4.11
Small wind energy conversion systems were selected for consideration for
several reasons. Within the Railbelt, selected areas have been identified as
having superior wind resource potential. The resource is renewable. Finally,
power produced by these systems could be marginally economically competitive
with generating facilities currently operating in the Railbelt. As previously
stated, these machines operate in a fuel-saver mode because of the intermittent
nature of the wind resource. Their economic performance can be analyzed only
by comparing their busbar power cost to the energy cost of power they displace.
Data on small wind energy conversion systems were taken from the technology
profiles (Volume IV). Analysis of this alternative indicated that 20 MW of
installed capacity producing 40 GWh of electric energy annually could be
economically developed at 80 mill energy costs, under the rather unlikely
assumption of full penetration of the available market (all households). These
machines were given parity with firm generating alternatives for cost of power
comparisons. Because the potential contribution of this alternative is
relatively minor to future Railbelt needs, even under the rather liberal
assumptions of this analysis, the potential energy production of small wind
energy conversion systems was not included in the analysis of Railbelt electric
energy plans.
4.1.12 Tidal Power
Tidal power plants typically consist of a 11 tidal barrage 11 extending across
a bay or inlet that has substantial tidal fluctuations. The barrage contains
sluice gates to admit water behind the barra.ge on the incoming tide, and
turbine-generator units to generate power on the outgoing tide. Tidal power is
intermittently available, and requires a power system that can complement the
output of the tidal plant. Hydro capacity is especialy suited for this
purpose. Alternatively, energy storage facilities (pumped hydro, compressed
air, storage batteries) can be used.
Tidal power was selected for consideration because of the substantial Cook
Inlet tidal resource, the renewable character of this energy resource, and the
substantial interest in the resource as evidenced by the recently completed
first-phase assessment of Cook Inlet tidal power development (Acres American
Incorporated 1981a).
4.12
The specific alternatives considered for this study were four variations on
the Eagle Bay alternative recommended for further study in the Cook Inlet tidal
power study preliminary assessment:
• 720-MW Eagle Bay tidal electric project without retiming
• 720-MW Eagle Bay tidal electric project with pumped storage
• 1440-MW Eagle Bay tidal electric project without retiming
• 1440-MW Eagle Bay tidal electric project with pumped storage.
Estimated production costs of a tidal power facility without retiming would
be competitive with alternative sources of power, such as coal-fired power
plants, if all power production could be used effectively, e.g., by a
specialized industry able to accommodate to the predictable, but cyclic output
of the plant. Otherwise the costs would not be competitive. Alternatively,
only the portion of the power output that could be absorbed by the Railbelt
power system could be used. The cost of this energy would be high relative to
other power-producing options because only a fraction of the·potential energy
production could be used. An additional alternative would be to construct a
retiming facility, such as a pumped storage plant. Due to the increased
capital costs and power (pumping) losses inherent in the retiming option,
busbar power costs would still be substantially greater than for nontidal
generating alternatives.
4.1.13 Municipal Solid Waste (MSW) Fuel Steam Electric Plants
These plants consist of boilers, fired by the combustible fraction of
municipal refuse, that produce steam for the operation of steam turbine-
generators. Rated capacities typically are small due to the difficulties of
transporting and storing waste, a relatively low energy density fuel.
Supplemental firing by fossil fuel may be required to compensate for seasonal
variation in waste production. The technology is mature, though not widely
used at present.
Enough MSW appears to be available in the Anchorage and Fairbanks areas to
support small MSW fuel-fired steam-electric plants if supplemental firing
(using coal) were provided to compensate for seasonal fluctuations in waste
availability. The cost of power from such a facility appears to be
competitive, although this competitiveness depends upon receipt of w~ste-
4.13
derived fuel at little or no cost. Advantages of disposal of municipal waste
by combustion may outweigh the somewhat higher power costs of such a facility
compared to coal-fired plants. The principal concerns relative to this type of
plant relate to potential reliability, atmospheric emission and odor problems.
Data for MSW-derived fuel steam electric plants were taken from the technology
profiles (Volume IV).
Cost and performance characteristics of the alternatives discussed above
are summarized in Table 4.2. Additional information on each is available in
the references cited; completed tabulations of the characteristics of these
alternatives are provided in Vo 1 ume I I.
4.2 CONSERVATION ALTERNATIVES
Two general classes of conservation measures were selected for study. The
first class, residential building conservation, includes several specific
measures for improving the insulation and weather tightness of residential
structures. The objective of the measures is to improve the end-use efficiency
of fuel used for space heating, e.g., wood, oil, natural gas, or other fuels,
as well as electricity. Also include in the residential class are measures
designed to improve the thermal insulation and efficiency of hot water heating
systems. Again, the fuel conserved may be natural gas, oil or wood, in
addition to electricity.
The second class of conservation measures considered were those involving
substitution of a nonelectric fuel for electricity. Consideration was given to
measures involving the substitution of a renewable resource for electricity and
included passive solar space heating systems, active solar hot water and space
heating systems, and wood as a residential space heating fuel.
The effects of conservation alternatives in the Railbelt region were
accounted for in the Railbelt electric energy plans by assessing the effects of
these measures in reducing electric demand. Technical limits on market
penetration were established first. The performance and cost characteristics
of promising measures then were assessed. Based on the costs and value of
energy savings of the various conservation measures, the levels of adoption
were then established using the demand forecasting model. Thus, the
contribution of conservation measures to meet future power needs in the
4.14
TABLE 4.2. Summary of Cost and Performance Characteristics of
Selected Alternatives (Jan. 1982 dollars)
Average
Annual
Capacity Heat Rate Availability Energy
Alternative (MW) (Btu/kWh) (%) ..l§l:!hL
Coal Steam-Electric (Beluga) 200 10,000 87 (f)
Coal Steam-Electric (Nenana) 200 10,000 87 (f)
Coal Gasifier-Combined Cycle 220 9,290 85 (f)
Natl. Gas Combustion Turbines 70 13,800(a) 89 (f)
Natl. Gas Combined Cycle 200 B,200(b) 85 (f)
Natl. Gas Fuel Cell Stations 25 9,200 91 (f)
Natl. Gas Fuel Cell Comb. Cyc. 200 5,700 83 (f)
Bradley Lake Hydroelectric 90 94 347
Chakachamna Hydroelec. (330 MW) (c) 330 94 1570
Chakachamna Hydroelec. (480 MW)(d) 480 94 1923
Upper Susitna (Watana I) 680 94 3459
Upper Susitna (Watana II) 340 94
Upper Susitna (Devil Canyon) 600 94 3334
Snow Hydroelectric 63 94 220
Keetna Hydroelectric 100 94 395
Strandlinf Lake Hydroelec. 20 94 85
Browne Hydroelectric 100 94 430
Allison Hydroelectic 8 94 37
Grant Lake Hydroelectric 7
Isabell Pass Wind Farm 25 36 8
Refuse-Derived Fuel
Steam Electric (Anchorage) 50 14,000 N/A
Refuse-Derived Fuel
Steam Electric (Fairbanks) 20 14,000 N/A
(a) A heat rate of 12,000 Btu/kWh was used in analysis of Railbelt electric
energy plans. 13,000 Btu/kWh is probably more representative of partial
Capita 1
Cost
..(!@_
2090
2150
730
1050
890
3190
3860
2100
4669
168
2263
5850
5480
7240
4470
4820
2840
2490
2980
3320
load operation characteristic of peaking duty. ,
(b) An earlier estimate of 8500 Btu/kWh was used in the analysis of Railbelt ~~
electric energy plans.
(c) Configuration selected in preliminary feasibility study (Bechtel Civil and
Minerals 1981).
(d) Configuration selected in Railbelt alternatives study (Volume XIV).
(e) Variable O&M included in fixed O&M estimate. ~
(f) Depends on capacity factor. r-"
4.15
Fixed o&M
($/kW/:a:)
16.70
16.70
14.80
48
7.30
42
50
9
4
4
5
5
5
7
5
44
5
44
44
3.70
140
140
Variable
O&M
(mills/kWh)
0.6
0.6
3.5
(e)
1.7
(e)
(e)
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
3.3
15
15
Railbelt was expressed as a reduction in forecasted demand from levels of
demand that might be experienced without conservation. Overviews of the
conservation measures considered in the study are provided in the following
paragraphs.
4.2.1 Residential Building Conservation
Building energy conservation encompasses a variety of measures for reducing
the electrical load of residential structures heated with electricity.
Electrically heated structures currently comprise about 21% of Anchorage
households, 9% of Fairbanks households, and 1% of Glennallen-Valdez house-
holds.(a) Choice of conservation measures and resulting energy savings
depend on the size and age of structure and the climatic region. The cost-
effectiveness techniques on new structures include extra insulation in the
ceiling (R-60), double-wall construction (R-40), heavily insulated floors (R-
40), insulated doors, triple pane windows, and careful sealing and caulking to
reduce air changes from 1.0 to 0.25 per hour (Barkshire 1981b). Cost-effective
measures for retrofitting existing buildings include adding insulation to the
floors and ceiling to bring their insulating value up to R-40 and R-60,
respectively. The walls are left at current R-values because of the expense of
retrofitting. Triple-glazed windows, R-8 metal insulated exterior doors, and
sufficient caulking and sealing to bring air infiltration down to 0.5 air
changes per hour round out the assumed improvements (Barkshire 1981b). For
purposes of cost estimating, insulation is assumed to be applied by
contractors, whereas glazing, caulking, and weatherstripping are applied by the
owner. Energy savings of new construction improvements over standard practices
are 289 Btu/hr per degree Fahrenheit below 70° outside temperature for the
prototypical -structure. For retrofits, improvements are projected to yield 189
Btu/hr per °F.
4.2.2 Residential Passive Solar Space Heating
Passive solar space heating is accomplished by using south glazing to
capture solar energy in .combination with a thermal mass to store captured
energy for release at night or during cloudy periods. These design features
(a) Calculations taken from a residential end-use survey conducted by Battelle-
Northwest for this study (March-April 1981).
4.16
generally are combined with a thermally efficient building envelope such as
those described above. Passive solar housing design in the Railbelt region has
considerable potential for reducing the space heat demand of these structures.
However, the homeowner's ability to use the solar resource depends on the
building's location and orientation. Also, passive solar applications are
generally restricted to new buildings or additions to existing structures.
Retrofitting an existing structure is a relatively inefficient way to reduce
heating bills (Barkshire 1981a and 1981b). A site survey of the Alternative
Energy Technical Assistance program during the summer of 1981 showed about one
sixth of 1200 Anchorage sites had open access to the sun the year round and
thus would be candidates for effective passive solar retrofit. Preliminary
study by Alaska Renewable Energy Associates indicates that from one third to
one half of building sites in the Railbelt will have solar access during the
heating season. Late winter and early spring are the primary months when
sunlight in the Railbelt region is both needed and available in sufficient
intensity to provide a net heat gain. Because sunlight is not generally
available during the peak heating periods of December and January, this
technology is assumed to operate in a fuel-saver mode and is given no credit
for reducing peak demand.
The prototypical dwellings used for analysis of passive solar space
heating were as follows. The new structure was a 1500 square foot house with
200 square feet of south-facing glass. No thermal storage was assumed. About
19.3 MW Btu annual net solar ga~n resulted {about 13.8 MM Btu per year more
than a standard house). The prototypical solar retrofit was an 8 by 20 foot
solar greenhouse, which supplied 10 to 15% of the heat required by the basic
1500 foot house used in the calculations.
Site characteristics limit penetration of passive solar space heat
applications to about 35 to 50% of the new building stock, while solar
greenhouses designed for heating purposes in existing buildings are expected to
be limited to 10 to 15% of the existing housing stock •.
(a) Although active solar space heating designs have been advanced, they did
not appear to be particularly advantageous for the Railbelt and thus were
not considered in this analysis.
4.17
4.2.3 Residential Active Solar Hot Water Heating (a)
Active solar technology has some potential in the Railbelt to reduce hot
water heating load. The effectiveness of these systems depends upon the amount
of solar radiation available and the water heating load of the household, which
in turn depends on the size and characteristics of the household. Final
installed costs will vary with the type of system (draindown, antifreeze, one
or two tanks), as will performance (Barkshire 198la). Prototypical new and
retrofit units examined in the study assume 80 square feet of collector using
Solar Roll®type technology because this appears to be the most cost
effective.(a) About 50% of the annual water-heating load of a family of four
can be met with such an installation, at 80 gallons per day use. Th~
proportion of such use, which can be met by solar during the year, varies by
month from near zero in November through February to about 85% in April through
June.
Limitations on market penetration are expected to result from very long
payback caused by high installation costs and unavailability of adequate
sites. These limitations will probably hold the total market to 5 to 10% of
hot water users (Barkshire 1981a).
4.2.4 Residential Wood Space Heating
Wood is already a supplementary fuel choice in many Railbelt communities.
Unlike other dispersed technologies, wood-fired space heating is not resource
or weather limited at this time. The analysis of wood-fired heating was done
on the presumption that at maximum penetration, one fifth of the space heat
required by homes heated with passive solar technology and one fifth of the
space heat required by nonsolar homes would be provided by wood. This is
equivalent to more than a doubling of the current market penetration of wood
space heat. Inconvenience, fuel cost, and difficulty in using wood in
multifamily units would deter market penetration, even at zero capital
cost.(b)
(a)
(b)
Solar Roll® is a trademark of Bio Energy Systems, Inc. of Ellenville, New
York.
Wood space heating costs are dominated by fuel costs even for the most
expensive types of stoves.
4.18
Stoves are available in sizes with heating capabilities ranging from 15,000
to over 100,000 Btu/hr, with conversion efficiencies of 20 to 65%. The costs
and performance characteristics used in the study are based on a high-quality
airtight stove of heavy-gage steel and soapstone.
4.2.5 Cogeneration and Waste Heat Utilization
Cogeneration and use of waste heat were considered and rejected as major
future sources of electric energy in the Railbelt. The most logical candidates
for cogeneration in the Railbelt are the existing Kenai Peninsula and Fairbanks
oil refineries, the existing (and possible future) liquefaction facilities for
natural gas on the Kenai Peninsula, and the ammonia-urea fertilizer plant on
the Kenai Peninsula. However, inquiries to plant managers and industry sources
turned up the following information: 1) None of these large process heat users
is considering cogeneration plants to sell or trade electricity to the utility
grid; 2) The Dow-Shell consortium came to the conclusion that utility power
would be cheaper than self-generated power in the new petrochemical plant;
3) There are severe technical problems with recovering additional high-grade
heat for cogeneration turbines at LNG facilities; 4) The Fertilizer Institute
was aware of no cogeneration projects in the ammonia-urea industry, even where
prices for electricity are higher than Alaska's expected price. Based on these
considerations, cogeneration from these sources appeared to be unlikely as a
major future contributor of electric power in the Railbelt as long as the cost
analysis used by the potential sponsor is based on average power costs as seen
by industry and not marginal power costs as seen by electric utilities.
Commercial and residential users might 'undertake smaller scale cogeneration.
To summarize, conservation measures for residential buildings were
selected, and their performance and cost characteristics were assessed as a
basis for reducing electric demand. These conservation measures and the
generating technologies previously described were major inputs to developing
the alternative electric energy plans for the Railbelt region. Cogeneration
and waste heat utilization are unlikely sources of electric energy for the
Railbelt region.
4.19
5.0 ELECTRIC ENERGY PLANS
Six plans were developed to provide a comparison of electric power development
strategies for the Railbelt region. The plans were selected to encompass the
full range of viable generation and conservation alternatives available to the
Ra i 1 be 1 t . ( a)
Plan lA, "Present Practices" Without Upper Susitna. Generation additions
are conventional coal and/or gas-fired steam plants and other hydro-
electric generation. Plan lA is considered the base case against
which the others are compared.
Plan lB, "Present Practices" With Upper Susitna. Generation additions are
primarily by the Upper Susitna Project with some gas-fired generation.
Plan 2A, "High Conservation and Renewables" Without Upper Susitna. Generation
additions include six small hydroelectric dams, wind power, refuse-
derived fuels, and some gasified generation.
Plan 28, "High Conservation and Renewables" With Upper Susitna. Generation
additions are primarily the Upper Susitna Project and lesser amounts
-
of the resources of Plan 2A.
Plan 3, "High Coal". Generation additions are primarily fueled with coal
either directly or indirectly.
Plan 4, "High Natural Gas". Generation additions are primarily fueled with
natural gas.
Five major factors were considered when developing these plans:
• natural resources available in the Railbelt region
• current generating facilities and utility plans
• performance characteristics and availability of alternative
generation technologies
• current and forecasted requirements for electricity
• input from public meetings
(a) To assist the reader in identifying the content of each plan, a foldout
sheet containing the titles of the plans is included at the end of the
report.
5.1
With these factors a subjective process was used to develop the electric
energy plans. As noted above, the plans were developed to encompass the full
range of conservation and generation alternatives available to the region
rather than to select the "best" plans based upon a formal selection and
evaluation process.
A major concern of the State of Alaska is whether the Upper Susitna
hydroelectric project should oe developed or whether other alternatives should
be pursued; thus, two electric energy plans are immedi'ately logical choices.
Plan lA does not include the Upper Susitna project, whereas Plan lB does.
The former provides the conditi'ons for the "oase case"; that is, the case
against which the alternattves will be compared. Plan lA and Plan lB provide
a direct comparison between conti-nued development of conventional generating
resources and development of conventi'ona1 generating resources with the
addition of the Upper Susitna project,
The public meetings held as part of this project, as well as other inputs,
pointed to widespread interest in both conservation and rene\'Jable energy
resources. While significant electric energy conservation will take place
as a result of price increases in all of the electric energy plans, a specific
plan in which conservation alternatives receive greater emphasis than in any
other plan is possible. Thus, Plan 2A, High Conservation and Renewables
without Upper Susitna, and Plan 2B, High Conservation and Renewables with
Upper Susitna, were selected. These two plans include the conservation tech-
nologies explicitly analyzed as well as a variety of other measures that
generally have low initial cost and quick payback periods. Among the unidentified
conservation measures are weatherstripping, setback thermostats, water heater
jackets, and energy-conserving lighting. Also assumed are price-induced
conservation savings, those which change peoples' behavior patteTns; such,
as taking shorter showers, turning off lights,and turning back thermostats.
Low initial investment, quick payback conservation is assumed to be adopted
as a matter of course.
To achieve the maximum contribution from conservation, the conservation
program assumed in this study goes beyond this market-induced conservation.
The State of Alaska is assumed to provide a grant program to residential
electricity consumers to offset the initial investment cost of four technologies
with higher initial cost and high energy payoff. Those four technologies are
5.2
superinsulation of buildings, passive solar designs for space heating, active
solar hot water heating, and wood-fired space heating. Because much less
information is available about specific end uses of electricity in the business
sector, the conservation supply plans relied on estimates of maximum average
electrical conservation of about 35% in the business sector and corresponding
estimates of minimum life cycle energy costs. (a) The initial capital cost of
achieving this maximum saving was assumed to be provided by a business sector
grant program so that the full savings could be realized.
Finally, the market penetration of the conservation technologies described
above for the residential sector and the general measures for the business
sector was estimated for market conditions without subsidies. The difference
between the subsidized and unsubsidized case was the impact of the conservation
supply program.
Plan 3 is based on increased use of coal. Coal is an attractive
fuel for electrical generation in the Railbelt area for several reasons:
• It is abundant.
• Good, easily mined coal deposits are close to the load centers.
• The technologies for both mining and burning coal are well
established.
• Projections indicate that coal will continue to be competitively priced
relative to alternative fuels.
Further, an export mine will probably be developed at Beluga and thereby
could provide the Cook Inlet area with a good source Qf coal.
Plan 4 is based on increased use of natural gas. Natural gas
is currently the mainstay fuel for electric generation in the Anchorage-Cook
Inlet area and may become available in the Fairbanks area if production and
transmission of North Slope natural gas occurs. The major favorable attributes
associated with natural gas are its relatively low environmental impact compared
(a) T~e basis for these assumptions is from work done in support of the Oak
R1dge Laboratory commercial model (DOE 1979).
5.3
to other fossil fuels, the lower capital cost per unit of.generating capacity,
and the short lead time involved in making capacity additions. Natural gas
is a clean and flexible fuel readily adapted to conditions of uncertain future
demand.
Further, considerable known reserves of natural gas [~3,900 billion cubic
feet (BCF)] exist in the Cook Inlet region. Some of this gas is committed
(or dedicated) under contract to gas and electric utilities (620 BCF), some
is committed to industrial applications (ammonia and urea production), and
some to export (~730 BCF). About 980 BCF is tentatively committed to the
proposed (but currently uncertain) Pacific Alaska LNG project for export to
the Lower 48 states. A significant amount (~1600 BCF) of the known reserves
appears free of current commitments. However, current industrial and export
uses will probably compete with the gas and electric utilities for commitment
of this gas to their operations and, thus, the future price is subject to
considerable uncertainty. Current reserves in the Cook Inlet do not appear
sufficient to allow expanded gas use beyond 1990. Additional resources might
be discovered, however.
Several assumptions were made which are common to all plans:
• Current utility plans for generating additions will proceed as planned.
• Generating units will be retired based on typical economic lifetimes.
• An interconnection between the Anchorage-Cook Inlet and Fairbanks-
Tanana Valley load centers will be completed in 1984 and strengthened
as necessary to allow economical power exchanges between Fairbanks
and Anchorage.
• The Glennallen-Valdez load center electrical loads and generating
capacity will be combined with Anchorage-Cook Inlet loads and
generating capacity.
• All load centers will maintain sufficient peaking capacity to provide
peak requirements in the event of interconnection failure.
• The Bradley Lake hydroelectric project will be completed and will
come on-line in 1988.
5.4
The approach and rationale for the selection of the preliminary electric
energy plans, as well as descriptions of the assumptions and features in each
plan, are contained in Volume V~
The detailed electrical generation and conservation alternatives that
were selected for each of the electric energy plans are summarized in TabTe 5.1.
I~ each plan, the costs of constructing the transmission systems to
connect the various generating facilities to the intertied system are included
in the analysis. For example, Plan lA includes the costs of constructing a
transmission system to connect the Chakachamna project and the coal steam-
electric generating plants located at Beluga with the Anchorage-Fairbanks
transmission intertie and the Anchorage-Cook Inlet transmission system. Costs
also are included for the transmission facilities that are assumed to be built
in conjunction with the first coal-fired steam plant added in the Beluga area.
Similarly, the cost of the transmission system necessary to connect the
additional generating facilities at Nenana to the intertie and the Fairbanks
area is also included. In Plan lA other generating facilities are assumed to
be built near existing transmission lines, and the costs of connecting them to
the transmission are ignored.
Because of the large size and location of the Upper Susitna project
(included in Plans lB and 2B), approximately midway between Anchorage and
Fairbanks, a relatively extensive transmission system is required. The costs
of the transmission system necessary to connect the various stages of the
project with the Anchorage and Fairbanks area are included with capital costs
of those stages.
While there are differences in transmission systems for Plans 3 and 4,
they are sufficiently similar to the transmission system in Plan lA that similar
costs can be ascribed to them. In Plan 3 the additional coal-based generating
facilities are assumed to be added in the Beluga area and in the Nenana area,
allowing much the smae system to be used. In Plan 4 the additional gas
generating facilities in the Anchorage area are assumed to be added in the
Beluga area. The exact location for the gas-fired capacity in the Fairbanks
area is not specified, but there are costs of connecting these facilities to
Fairbanks and to the intertie. These are assumed to be the same as for Plan lA.
5.5
TABLE 5.1. Summary of Electrical Energy Alternatives Included as
Future Additions in Electric Energy Plans
Electric Energy Plan(a)
lA lB 2A
BASE LOAD ALTERNATIVES
Coal Steam Electric X X X
Refuse-Derived Fuel Steam Electric X
Natural Gas -Fuel-Cell Combined-Cycle
CYCLING ALTERNATIVES
Coal Gasifier -Combined-Cycle
Natural Gas -Fuel Cell-Stations
Natural Gas -Combined-Cycle X X X
Natural Gas -Combustion Turbine X X X
Bradley Lake Hydroelectric X X X
Grant Lake Hydroelectric X X
Lake Chakachamna Hydroelectric X X
Upper Susitna Hydroelectric X
Allison Hydroelectric X X
Browne Hydroelectric X
Keetna Hydroelectric X
Snow Hydroelectric X
Strandline Lake Hydroelectric X
FUEL SAVER (INTEffi~ITTENT) ALTERNATIVES
Large Wind Energy Conversion System X
ELECTRIC ENERGY SUBSTITUTES
Passive Solar Space Heating X
Active Solar Hot Water Heating X
Wood-Fired Space Heating X
ELECTRIC ENERGY CONSERVATION
Building Conservation X
(a) Plan lA, "Present Practices 11 without Upper Susitna (Base Case)
Plan lB, "Present Practices" with Upper Susitna
2B
X
X
X
X
X
X
X
X
X
X
X
Plan 2A, "High Conservation and Renewables" without Upper Susitna
Plan 2B, "High Conservation and Renewables" with Upper Susitna
Plan 3, "High Coal"
Plan 4, "High Natural Gas"
5.6
3
X
X
X
X
4
X
X
X
X
X
6.0 COMPARATIVE EVALUATION OF ELECTRIC ENERGY PLANS
Having selected the alternative electric plans to be considered, the next
steps were to describe them in greater detail and then evaluate their impact on
the Railbelt region. A schedule of plant additions was developed; i.e., the
type, size, timing, and location of each plant were specified. The schedule
was developed using two computer codes: RED (described briefly in Section 3)
and AREEP (described in this section). A major output of this computer
analysis was the costs of electric energy for each plan, and these were
compared. Qualitative evaluations of environmental and socioeconomic impacts
were made for each plan. This section concludes with a qualitative evaluation
of the strengths, weakness, and uncertainties of each plan.
Detailed information on generation system reliability, environmental and
economic effects for each plan is presented in Appendix D. The effects of
other growth scenarios can be estimated from this information.
6.1 DEVELOPMENT OF DETAILED ALTERNATIVE ENERGY PLANS
As previously stated, the demand for electricity is partially determined
by the price of electricity, which is determined largely by the types and
performance of the facilities used to generate electricity. Thus, electricity
demand forecasts require some interaction between the demand and supply
forecasting methodologies. These interactions were performed as shown in
Figure 6.1 and led to a schedule of capacity additions and the present worth
for each plan.
To start the process, a price of electricity is assumed as input to the
electrical demand model (RED model). Using this price, as well as other input
data and assumptions, the RED model produces forecasts of peak demand and
annual energy consumption for the Railbelt. The AREEP model uses these
forecasts of peak demand and annual energy consumption as input data and
produces a schedule of plant additions to the electrical generation system, as
well as price of electricity to the consumer. The resulting demand under the
new price is compared to the demand with the original price assumption, and if
6.1
INPUT DATA
AND ASSUMPTIONS
INPUT DATA
AND ASSUMPTIONS
START
• . PEAK DEMAND
• ANNUAL ENERGY
• SCHEDULE OF CAPACITY ADDITIONS
• PRESENT WORTH OF PLAN
FIGURE 6.1. Electrical Demand and Supply Interactions
the two demands are relatively close, then supply and demand are said to be in
equilibrium and the process is halted. If the two demands are not relatively
close, the process is repeated until the demand estimates for two successive
iterations for RED are relatively close.
AREEP requires capital and O&M cost data (developed in the preceding
sections), financial assumptions, fuel costs, and the desired set of generation
alternatives from which the model will select specific generating plants.
The general computational procedure used by AREEP to determine the price
of electricity for a particular case is presented in Figure 6.2.
The first step (1) is to adjust the consumption forecast (peak demand and
annual energy) developed by the RED model for transmission line losses and
unaccounted energy. This adjustment determines the amant of energy that must
be generated. The peak demands and annual energy from each of the three load
centers are added together and a single annual load duration curve is developed
for the combined Railbelt region.
The next step (2) is to develop a schedule for new additions to the
generating capacity. Generating capacity additions are based upon the need to
meet the forecasted annual peak demand, with allowances for line losses and
reserve margin. The model accounts for retirement of existing plants. The
type of generating alternative added is selected from a general set of
alternatives that is input by the model operator.
6.2
DATA INPUT
AND ASSUMPTIONS
• DESCRIPTION OF GENERATING
ALTERNATIVES
· • EARLIEST AVAILABILITY
OF ALTERNATIVES
• FINANCIAL ASSUMPTIONS
• CAPITAL, O&M, FUEL COSTS
• DES IRED MIX OF ALTERNATIVES
• PLANNING RFSERVE MARGIN
• PEAK DEMAND } • ANNUAL ENERGY
1 {
2{
3{
4{
ANNUAL COST OF POWER
TO CONSUMER
.From RED
• ADJUST FOR LOSSES AND UNACCOUNTED
ENERGY
• COMBINE DEMANDS FROM LOAD CENTERS
• DEVELOP LOAD-DURATION CURVES
• MAKES CAPACITY DECISIONS BASED
UPON
-DESIRED MIX OF ALTERNATIVES (INPUT)
-PLANNING RESERVE MARGIN (INPUT)
• DISPATCHES GENERATING ALTERNATIVES
BASED UPON VARIABLE OPERATING COST
• LOSS OFLOAD PROBABILITY
• COMPUTES ANNUAL COST OF POWER
• LEVELl ZED COST OF POWER
• PRESENT WORTH OF PLAN
FIGURE 6.2. AREEP Diagram
Once the schedule of new plant additions is established, the capital cost
and fixed cost portion of the electricity production cost can be computed. As
indicated in Figure 6.2, this information is computed and used to forecast the
production cost of electricity.
The next step (3) in the computational procedure is the selection of
available generating alternatives to generate electricity during any particular
year. The model selects the resource based upon the relative variable
operating costs of the alternatives. The alternative with the lowest operating
costs is selected (dispatched) first, followed by the alternatives with the
next lowest variable cost. Th~ generating alternatives are dispatched in this
order until the annual energy demand is satisfied.
Finally, the information on the amount of electricity produced by each
generating technology is then used to compute the annual variable costs of
producing electricity for the Railbelt region (4). As Figure 6.2 shows, adding
6.3
the total annual fixed costs, which were computed earlier, to the total annual
variable costs produces the total annual cost of power to the consumer. The
levelized cost of power(a) of the plan is then calculated from the annual
costs of power over the time horizon 1980 to 2010.
6.2 DETAILED DESCRIPTIONS OF PLANS
The types of generating plants to be constructed, their size, location,
and timing for each of the electric energy plans were developed in greater
detail. For clarity purposes, the medium-medium (MM) economic scenario
(moderate economic growth, moderate State spending) was selected as the basis
for comparing the six plans.·
The peak electrical demand for the Railbelt region was 540 MW in 1980. By
the year 2010 the peak demand is expected to be slightly larger than double
this amount (for the MM case). Capacity additions of about 1200 MW will be
required to meet the load growth, to replace older units, and to provide
adequate reserve margins.
6.2.1 Plan 1A "Present Practices" Without Upper Susitna
In Plan 1A 400 MW of gas combined-cycle, 400 MW of coal steam turbine, and
430 MW of hydroelectric capacity would be added during the 1981 to 2010 time
period. The hydroelectric capacity includes the following projects:
• The Bradley Lake hydroelectric project (90 MW) would come on-line in 1988.
• The Chakachamna hydroelectric project (330 MW) would come on-line in 2002.
1 The Allison (7 MW) and Grant Lake (7 MW) hydroelectric projects would come
on-line in 1992 and 1995, respectively.
In the Anchorage-Cook Inlet area:
• Coal steam turbines {200 MW in 1992) and gas combined-cycles (178 MW in
1982 and 200 MW in 1996) would be installed to supplement the hydroelectric
projects.
(a) The procedure used to compute the levelized cost of power is presented in
Appendix C.
6.4
In the Fairbanks-Tanana Valley area:
• Oil combustion-turbine units would be used for peaking until retirement
occurs in the mid-1990s.
• Gas combined-cycles (100 MW) each in 1991 and 2010) would be added to
provide peaking generation and partly to replace oil combustion units that
will be retired.
• Coal steam-electric capacity (200 MW) would be added for baseload in 1997.
During the 1981 to 1991 time period, electrical generation in Anchorage
would be largely supplied by gas combustion/turbine and combined-cycle with
some hydroelectric generation. During the next 20 years, generation in the
Anchorage area would be largely hydroelectric with some gas combined-cycle and
coal steam turbine generation.
In Fairbanks, coal steam turbine capacity would be used for generation
throughout the time horizon. Oil combustion turbines would be used during the
first 10 years while some gas combined-cycle capacity would be used during the
remainder of the period.
6.2.2 Plan 1B "Present Practices" With Upper Susitna
In Plan 1B almost all of the additional capacity added results from the
construction of the Watana (680 MW) and Devil Canyon (600 MW) dams of the Upper
Susitna Project. The Watana Dam would come on-line in 1993 and the Devil
Canyon Dam would come on-line in 2002. The Bradley Lake project {90 MW) would
come on-line in 1988. The only other capacity added would be 70 MW of gas
combustion turbine capacity and 200 MW of gas combined-cycle capacity brought
on-line in 1990 and 1991, respectively, in the Anchorage area.
During the 1981 to 1992 time period, electrical generation in Anchorage
'would be largely by gas combustion turbines and combined-cycle capacity with
some hydroelectric generation. In Fairbanks, oil combustion turbines and
diesel capacity would be used until 1990-1991, and coal steam turbine until
2002 when the Devil Canyon Dam would come on-line. From 2002 until 2010 the
majority of electrical generation in the Railbelt would be supplied by hydro-
electric power, largely from the Upper Susitna project.
6.5
Basically, this plan is a continuation of present generating technologies
with a transition to Upper Susitna hydropower as required. Additional capacity
required would be supplied by conventional coal-steam turbine or combined-cycle
f ac i 1 it i es •
In the Anchorage-Cook Inlet area:
• If required by load growth, combustion turbine and gas combined-cycle
capacity would be added until Upper Susitna is available.
• After the Upper Susitna Project is completed, coal-steam turbine units
would be added if required by load growth.
In the Fairbanks-Tanana Valley area:
• Combustion turbine and gas combined-cycle capacity would be added as
required prior to the Upper Susitna Project, and coal-steam turbine units
would be added as required after the Upper Susitna Project is completed.
6.2.3 Plan 2A 11 High Conservation and Renewables 11 Without Upper Susitna
Plan 2A emphasizes conservation to reduce electrical energy demand and the
use of renewable energy sources to provide for a significant portion of the
electrical energy groWth. A continuing State grant program is assumed that
encourages the installation of conservation alternatives (passive solar space
heating, active solar water heating, wood space heating, and building
conservation). The conservation program is estimated to supply the equivalent
of 40 to 75 MW in generating capacity.
Additional capacity required would be provided by conventional generating
alternatives as in Plan 1A. The hydroelectric projects include:
• The Bradley Lake project (90 MW), the Allison project (7 MW), the
Chakachamna and Grand Lake projects (337 MW), and the Keetna hydroelectric
project (100 MW) would come on-line in 1988, 1991, 1995, and 2008,
respectively.
• The Browne hydroelectric project (80 MW) would come on-line in 2005.
In the Anchorage-Cook Inlet area:
• A 50-MW municipal solid waste-derived fuel plant would come on-line in 1993.
6.6
• Additional generation would be supplied by natural gas combined-cycle
(178 MW in 1982 and 200 MW in 1987) and combustion turbine (70 MW in each
of the years 2006 and 2009.
In the Fairbanks-Tanana Valley area:
• 175 MW of large wind turbine generation would be added in the Isabell Pass
area during the period 1992 to 1996.
• A 20-MW refuse-derived fuel plant will come on-line in 1994, and be
supplemented with an additional 20 MW in 1996.
6.2.4 Plan 2B "High Conservation and Renewables" With Upper Susitna
Plan 2B is similar to Plan 2A except that the Upper Susitna project would
be constructed. A number of the smaller dams would not be built and lesser
amounts of fossil fuel-fired generation would be required. The hydroelectric
projects include the following:
• The Bradley Lake project (90 MW) would come on-line in 1988.
• The first stage of Watana (680 MW) would come on-line in 1993; Devil Canyon
(600 MW) in 2002.
In the Anchorage-Cook Inlet area:
• A 50 MW municipal solid waste-derived fuel plant would come on-line in 1992.
In the Fairbanks-Tanana Valley area:
• 50 MW of large wind-turbine generation would be added in the Isabell Pass
area in 1992.
6.2.5 Plan 3 "High Coal"
Plan 3 assumes a transition from existing generating technologies to
alternatives that use coal, directly or indirectly, as a fuel. As previously
stated, coal is currently available in the Railbelt from the Healy area; it is
also expected to be available from the Beluga area in 1988. This plan assumes
that coal-fired generation in the Anchorage-Cook Inlet load center would be
located in the Beluga area. Baseload generation for the Fairbanks area will
depend on the costs of facilities located at Beluga compared to costs of
facilities located in the Nenana area. With the exception of Bradley Lake (90
MW), which would come on-line in 1988, no additional hydroelectric facilities
would be built. 6.7
In the Anchorage-Cook Inlet area:
1 Two 200 MW coal steam turbine power plants would come on-line in 1992 and
2005.
• A 200 MW coal-gasifier combined-cycle would come on-line in 1995.
1 Three 700 MW gas combustion turbines would come on-line in 1991, 2009, and
2010.
In the Fairbanks-Tanana Valley area:
1 A 200 MW coal steam turbine power plant would come on-line in 1997.
6.2.6 Plan 4 "High Natural Gas"
Plan 4 is based upon continued use of natural gas for generation in the
Anchorage-Cook Inlet area and a conversion to natural gas in the
Fairbanks-Tanana Valley area. The key assumptions for this plan are that
sufficient gas will be continually available in the Cook Inlet area in the
amounts required for electrical generation, and that natural gas will be
available for the Fairbanks area from the North Slope beginning in 1988. Gas-
fueled alternatives in this plan include fuel-cells, gas combined-cycle,
combustion turbine, and fuel-cell combined cycle. As in Plan 3, with the
exception of the Bradley Lake project (90 MW), which would come on-line in
1988, no additional hydroelectric facilities would be built.
In the Anchorage-Cook Inlet area:
• A 178 MW and a 200 MW gas combined-cycle plants would come on-line in 1982
and 1998.
1 A 200 MW gas fuel-cell station would come on-line in 1995.
In the Fairbanks-Tanana Valley area:
• Three 100 MW gas combined-cycle plants would come on-line in 1991, 2005,
and 2006.
1 Two 200 MW gas fuel-cell stations would come on-line in 1993 and 2008.
6.8
6.3 ELECTRICAL DEMAND
The peak electrical demand in all plans is very similar, ranging from
1120 MW to 1350 MW by year 2010 (Figure 6.3).
Plan lA, the base case, results in a peak demand of about 1260 MW in the
year 2010.
Plan lB, which includes the Susitna hydroelectric project, has a higher
electricity demand to the year 1995 because of the population and employment
impacts of construction of this project. Since the Upper Susitna project
results in a slightly higher cost of power than Plan lA between 1993 and 2005,
demand is reduced until after 2005, when a lower cost of power results in a
higher demand.
Plans 3 and 4 are less sheltered from fuel price escalation than the other
plans since they include a limited amount of hydroelectric capacity. While the
effect of escalation is not significant compared to Plan lA up to about the
year 2000, the lower reliance on hydroelectric power in these cases increases
the cost of power and reduces demand below that in Plan lA.
As previously stated, all plans include substantial electricity
conservation due to the cost of power. However, in Plans 2A and 2B the demand
for electricity is reduced st.ill further by using a grant program to cover the
investment costs of the four conservation alternatives specifically analyzed in
this study (building conservation, passive solar space heating, active solar
water heating, and wood stoves), plus commercial conservation initiatives. The
peak demand in these plans is from 100 to 140 MW less than Plans lA and lB.
6.4 COST OF POWER
The annualized cost of power for all of the electric energy plans is
similar (Figure 6.4). The major differences in the cost of power are in the
plans that include the Upper Susjtna project (Plans lB and 2B). A relatively
rapid increase in the cost of power occurs in 1993 when the Watana Dam would
come on-line and another rapid increase in 2002 when the Devil Canyon Dam would
come on-line. However, the annualized cost of power falls rapidly beyond 2002
1980 1985 1990 1995
Years
.. ~ 1350 1B
2000 2 05 2010
FIGURE 6.3. Peak Electrical Demands for Medium-Medium Economic Scenario
6.10
90~------------------------------------------~
85
80
75
.c 70 s:
~
V1
-' -1 65 ~
c:::
u.J s:
0 60 c..
u..
0
1-
V1
0 55 u
50
45
40
.-,
I • . ' -·' \
1980 1985 1990 1995 2000 2005 2010
FIGURE 6.4. Comparison of Annualized Cost of Power for Railbelt
Electric Energy Plans (1982 dollars)
(a) Plan lA "Present Practices" Without Upper Susitna
lB "Present Practices" With Upper Susitna
2A "High Conservation and Renewables" Without Upper Susitna
2B "High Conservation and Renewables" With Upper Susitna
3 "High Coal"
4 "High Natural Gas"
6.11
and is significantly lower than any of the other plans by the year 2010. Plans
1A, 2A, 3, and 4, which rely on fossil fuels, all show the effects of the
continued escalation of fuel prices throughout the time period to 2010.
Little difference exists in the annualized cost of power for three primary
reasons:
1) As part of the selection process described earlier, generating alternatives
with high generating costs were screened out from further analysis. Since
the alternatives with relatively high power costs were not included in any
of the plans, one would expect that the plans would have similar power
costs.
2) Over much of the 1980 to 2010 time period, the electrical supply systems
(and thus the costs) are the same for all plans. During the first 10 years
(1980 to 1990), the same capacity additions are included in all of the
plans. As a result, the costs are the same over this time period.
3) The costs presented in Figure 6.4 include distribution and utility general
and administrative costs as well as generation and transmission costs.
While the latter vary from plan to plan, the distribution and utility
general and administrative costs are assumed proportional to the electrical
consumption and, as a result, vary relatively little from plan to plan.
Choosing the plan with the lowest cost of power is difficult if only annual
power costs are considered, as in Figure 6.4. For example, Plan 1A provides a
lower cost of power than Plan 18 during the 1993 to 2003 time period, whereas
Plan 18 has the lower cost of power from.2004 to 2010. To compare the costs of
power for the various plans, unit power costs can be expressed as levelized
costs. The levelized cost of power is computed by estimating a single annual
payment, the present worth of which is equivalent to the present worth of the
forecasted stream of annual costs.(a)
The levelized costs of power for the six p~ans over the two periods of
analysis are presented in Table 6.1. The most striking aspect of these data is
that there is essentially no difference in the levelized cost of power among
the plans within each period of analysis.
(a) The procedure used to levelize the cost of power is explained in Appendix C.
6.12
TABLE 6.1. Levelized Costs of Power for Electric
Energy Plans (mills/kWh)
Period of Analysis
1981-2010 1981-2050
Plan 1A "Present Practices"
Without Upper Susitna 58 64
Plan 1B "Present Practices"
With Upper Susitna 58 59
Plan 2A "High Conservation and
Renewables" Without Upper Susitna 59 66
Plan 2B "High Conservation and
Renewables" With Upper Susitna 58 61
Plan 3 "High Coal" 59 65
Plan 4 "High Natural Gas" 59 66
As previously noted, an important observation from Figure 6.4 is that the
plans including the Upper Susitna project have higher cost power during the
1993 to 2004 time period, but they have a lower cost power in the latter
years. Since the service-life of the Upper Susitna project extends beyond
2010, this difference in power costs can be expected to be maintained because
Plans 1A, 2A, 3, and 4 are more reliant on fossil fuels, which are expected to
continue to escalate.
To evaluate this aspect of power costs, the levelized costs were also
computed for the period 1981 to 2050 (Table 6.1), assuming that no escalation
will occur in fuel costs or capital replacement costs over the 2010 to 2050
time horizon (and no generating capacity is added). This assumption
understates the relative advantages of the plans that include the Upper Susitna
project, but it does indicate the longer-term power cost advantage of the
larger hydroelectric projects.
Over the longer time horizon the plans, including the Upper Susitna
project, provide the lowest cost of power. But even here the difference is
only about 10%. As stated above, the assumption of no escalation in fuel and
capital replacement costs does not favor the plans that rely on those fuels.
In Section 7, the effect of changes in the key assumptions leading to these
results are evaluated.
6.13
6.5 POTENTIAL ENVIRONMENTAL AND SOCIOECONOMIC IMPACTS
The environmental and socioeconomic impacts were evaluated by examining the
following major concerns for each plan.
• air and water quality: Do pollutants that degrade these resources for
other uses exist?
• terrestrial, aquatic, and marine ecology: Will any changes that reduce the
habitat and production of animal and fish life occur?
• noise, visual, and odor: Are these effects present to such an extent as to
constitute a nuisance?
• health and safety: Do any effluents exist that may affect the health of
workers and/or population?
• jobs in Alaska: Does this technology provide new jobs?
• boom/bust effects: Are new construction communities built and then left
afterwards with impacts on existing community structure?
• land-use effects: To what extent will large areas of land be precluded for
other uses by this technology?
• susceptibility to inflation: To what extent is the power cost closely tied
to the cost of fuels such as coal, oil, and gas?
• spending in Alaska: Will a major portion of the total cost of this project
be spent in Alaska?
The environmental and socioeconomic information has been integrated into a
qualitative evaluation, summarized in Table 6.2. The six plans are listed on
the vertical axis of this table, and the various environmental and
socioeconomic sectors are listed on the horizontal axis. Each item has been
designated with "+", "-", or "N". The "+" indicates the impact of the change
is positive or desirable. The "-" indicates a negative or undesirable change.
The neutral "N" means that some change may occur, but it is not perceived to be
particularly desirable or undesirable.
This system of evaluation does not measure the degree of impact; that is,
some "minuses" may be more detrimental than other "minuses... Thus, the fact
6.14
TABLE 6.2 Summary of Potential Environmen(aJ & Socioeconomic
Impacts of Railbelt Enerqy Plan a
Potential Environmental and Socioeconomic lmJ!acts
Suscepti-
Terres-Aquatic/ Noise, Health Boom/ land-bility
Air Water trial Marine Visual and Jobs in Bust Use to Spending
Energl Plan gualitl gualitl Ecologl Ecologl & Odor. Safety Alaska Effects Effects Inflation in Alaska
Plan lA: Base
Case Without
Upper Susitna N N N N + N
Plan lB: Base
Case With
Upper Susitna + N N N + + ) + N +
Plan 2A: High
Conservation &
Use of Renew-
able Resources,
Without Upper
Susitna N N N N + + N +
"' . Plan 2B: High 1-'
Ul Conservation &
Use of Renew-
able Resources,
With Upper
Susitna + N N N + + + + +
Plan 3:
Increased Use
of Coal N N N N N +
Plan 4:
Increased Use
of Natural Gas + + + + + + N N N
(a) Key: + positive or desirable
-negative or undesirable
N neutral
that Plans lA and 3 have the most negative or undesirable notations does not
mean that overall they have substantially greater environmental and/or socio-
economic impacts. Some perspective might be gained by recognizing that the
amount of new capacity (about 1200 MW) in the Railbelt is not large for the
area over which it is distributed. One might expect the major impacts to arise
from the Susitna projects, which are large and concentrated. New fossil-fueled
plants can be designed to reduce environmental impacts to very low levels.
None of the power plants which might be added to the system are larger than 2-
00 MW, apart from the Susitna project, and should not create significant socio-
economic impacts. Even Susitna-size projects have been constructed elsewhere
in settings that are not unlike the Railbelt region, and without unacceptable
socioeconomic effects. The conclusion is that none of the plans need result in
unacceptable environmental or socioeconomic impacts. A more detailed analysis
of environmental and socioeconomic impacts is presented in Appendix D.
6.6 SUMMARY OF PLAN EVALUATIONS
Plan lA: 11 Present Practices .. Without Upper Susitna is not significantly
different from past practices in the Railbelt. Jobs will result from the
construction of coal plants and the Chakachamna hydroelectric project. No
major problems are expected from water quality ecology, health and safety,
boom/bust effects or spending outside the State.
Some impacts arising from air quality and land-use consideration are
possible. From a cost-of-power standpoint, inflation effects due to fossil
fuel use are possible. A potential exists for some boom/bust impacts at the
Bradley Lake and Chakachamna hydroelectric projects.
A major uncertainty in this plan is whether the export coal mine at Beluga
will be developed on the schedule assumed in this plan.
Plan lB: 11 Present Practices 11 With Upper Susitna avoids impacts
associated with the burning of fossil fuels; i.e., those related to air
quality, visibility, health, waste disposal, etc. New jobs are created and
significant spending occurs within the State. Construction of hydroelectric
facilities is a well-established technology. Relatively good information is
available on capital costs and environmental impacts. The plan is resistant to
inflation once the Upper Susitna projects are constructed.
6.16
Significant boom/bust and land-use effects can be associated with the Upper
Susitna projects. Capital costs are high. The Upper Susitna project may delay
development of coal resources in the State.
Improper river flow control may be detrimental to anadromous fish species,
especially salmon. Considerable experience exists in the "lower 48" states to
evaluate these potential effects and proposed mitigation measures.
Plan 2A: "High Conservation and Renewables" Without Upper Susitna will
create jobs and stimulate significant spending within the State. The heavy
reliance on hydroelectric generation, wind generation, and natural gas
minimizes the problems related to air quality, water quality, and ecology
impacts. The plan is relatively insensitive to inflation effects. The
Railbelt comm_unity is thoroughly involved in conservation activities with its
resultant increase in energy-use awareness.
Some problems are associated with the local boom/bust effects of the six
hydroelectric projects.
This plan assumes that a State conservation grant program is created and
maintained. Potential health effects arising from increased indoor air
pollution caused by conservation activities may need to be dealt with.
Plan 28: "High Conservation and Renewables" With Upper Susitna has
similar advantages to Plan 2A with respect to air and water quality, noise,
odor and visual effects, health and safety, new jobs, and spending in the
State. Relatively good information ~xists on capital costs and environmental
impacts. Power costs will be resistant to inflation once the hydroelectric
projects are constructed.
The disadvantages are similar to Plan lB; boom/bust and land-use impacts
and high capital costs are associated with the construction of the Upper
Susitna project.
As with Plan 2A, this plan assumes an extensive and continuing State
conservation grant program. As before, potential effects arising from
increased indoor air pollution may need to be dealt with.
Plan 3: "High Coal" results in considerable spending within the State to
construct coal-related facilities. It may accelerate development of coal
6.17
resources in the State. No major problems are associated with health and
safety or boom/bust effects.
Some potential problems could occur in such areas as air quality, water
quality, visual impacts and land-use. Coal use is susceptible to inflation
effects. Constraints due to the Prevention of Significant Deterioration (PSD)
program air-quality regulations are possible. Incremental coal mining and
reclamation activities may occur in Beluga and Nenana areas.
The development of the export coal mine at Beluga with its effect of
reducing coal costs is a major uncertainty.
Plan 4: "High Natural Gas 11 has very little effect on the environment.
No major problems are associated with boom/bust effects or land use.
Due· to high technology of fuel cells and to a lesser extent gas combined-
cycle units, a substantial amount of spending will occur outside of the State.
Inflation effects are potentially significant because power costs are very
sensitive to the price of natural gas.
The major uncertainty with this plan is that natural gas reserves in the
Cook Inlet area may not be adequate for expanded generation beyond 1990 to
1995. Additional reserves will be required and their source, timing, and cost
are not certain. Also, North Slope gas was assumed available at Fairbanks, and
this availability is uncertain.
6.18
7.0 SENSITIVITY ANALYSIS
This section evaluates the sensitivity of the levelized cost of power
to changes in several key parameters; that is, what is the effect on the cost
of power if costs, projections, or schedules are incorrectly estimated. In any
analysis, such as that presented in the previous section, considerable data are
required to describe the systems being analyzed. If the data and procedures
used in these (or any) analyses were accurate estimates of the 11 real world .. ,
the evaluation results would be exact, and therefore no uncertainty regarding
the results would exist.
Unfortunately, some level of uncertainty is associated with all data; that
is, the 11 Correct 11 value for a parameter may be either larger or smaller than
the value selected. For example, the capital cost of coal steam turbine
generating units located in the Beluga area has been estimated to be $2090/kW,
expressed in 1982 dollars. The only way to be completely certain of the
capital costs of such units is to build one. Otherwise, the cost estimate has
some uncertainty associated with it; that is, the correct cost estimate may be
either higher or lower than the estimated $2090/kW.
Furthermore, the methods used in analyzing the plans are not exact
representations but rather simplifications of the real world. Because of these
two factors, the results have an uncertainty associated with them. In some
cases the uncertainties are relatively small, and therefore their effects on
the overall results may be relatively minor. In other cases, the uncertainties
in a parameter or calculation may be relatively large, but the impact of the
uncertainties on the overall results may still be relatively minor. In both of
these cases, the overall effects of uncertainty could perhaps be neglected.
However, in some cases the effects of the uncertainties do have a significant
impact on analyses results.
Because uncertainty is associated with most data and computational
procedures, it is necessary to test how changes in a parameter or an analysis
would affect the results. Parameter values that are either higher or lower
than the 11 best guess 11 estimate are selected and the analysis is redone to see
how much the results change. If the change is significant, the results are
said to be sensitive to the parameter estimate. If little change oc~urs, the
results are said to be insensitive. The change in the results necessary for
7.1
the analysis to be deemed sensitive to an input parameter varies depending upon
the analysis. In some analyses, a change of 1% in the result may be quite
significant, whereas in other analyses, much larger changes could be
negligible.
In the context of this study, perhaps the best determination of whether
the results are sensitive to a parameter is whether the ranking of the electric
energy plans is cha·nged. Many computer runs were made to estimate the
sensitivity of the models to various parameters. The results of several
important parameters are presented in this section, including fuel price
escalation rates, forecasted demand, capital cost estimates, and generation
efficiency. In general, the levelized costs of power changed by less than 5%
in all the sensitivity tests. The most sensitive estimate analyzed is the
Upper Susitna capital cost estimates (in Plan 1B and 2B) with variations of
about plus or minus 9% in electrical energy costs. Based upon these analyses,
the following general conclusions can be drawn regarding the relative costs of
the various plans.
Plan 1A: "Present Practices" Without Upper Susitna has relatively stable
levelized costs of power among the various sensitivity tests. Generally, Plan
1A is neither the highest nor lowest cost. The costs are stable because this
plan includes a more diverse mix of supply options than the other plans.
Rapidly increasing demand during the 1981 to 2010 time period causes its cost
to be relatively high.
Plan 1B: "Present Practices" With Upper Susitna has relatively low power
costs over the 1981 to 2010 time period, ~xcept for the case assuming higher
than anticipated capital costs for the Upper Susitna Project. Also, this plan
provides either the lowest or nearly the lowest cost of power in all
sensitivity tests over the extended time period. It does relatively less well
in cases with lower demand growth.
Plan 2A: "High Conservation and Renewables" Without Upper Susitna has
relatively high power costs in most cases because of the plan•s reliance upon
hydroelectric projects that have high capital costs relative to the Upper
Susitna Project, and because it does not have lower cost fossil fuel
alternatives as an option. This plan has the highest cost of power in the case
where electrical demand increases rapidly after 1990.
7.2
Plan 28: "High Conservation and Renewables" With Upper Susitna has much the
same behavior as Plan 18, since both include the Upper Susitna Project. It has
slightly higher costs of power than Plan 18 over the extended time horizon.
Plan 3: "H.igh CoaP generally produces relatively high costs of power over
the 1981 to 2050 time period •. As expected, it is more attractive in the case
of lower fuel price escalations.
Plan 4: "High Natural Gas" behaves similarly to Plan 3. It provides the
lowest cost of power over the 1981 to 2010 time period for lower escalation
rates and for reduced demand beyond 1995. It is one of the higher cost
alternatives over the extended time horizon.
7.1 UNCERTAINTY IN FOSSIL FUEL PRICE ESCALATION
Although a considerable effort was made in this study to forecast the
future prices and availability of fossil fuels and electricity in the Railbelt
region, these forecasts are subject to a high degree of uncertainty.
International political events affecting both the prices of oil and coal,
national policies affecting the pricing and delivery of natural gas and oil,
and national and state policies affecting both the prices of electricity and
energy conservation create the uncertainties. Also, because economic behavior
of individuals, businesses, and government in response to future fuel price
changes must be extrapolated from past behavior, the degree of substitution
among fuels and the degree of energy conservation are also uncertain.
7.1.1 Effects of Uncertainty in Fossil Fuel Price Escalation on Cost of Power
As discussed in Section 2, a long-term world oil price escalation rate 2%
faster than inflation is assumed over the study•s time horizon. The escalation
of natural gas and oil with respect to general inflation is a subject on which
there is little agreement. Some believe that escalation rates in the range of
1 to 3% over the time period covered by this report (to year 2010} are
realistic; others believe that the experience of the past year or two will
prevail, and there will be no net escalation results in a doubling of cost in
35 years, roughly the time period covered by this study (1% has a doubling
period of 70 years; 3% about 23 years). A limited resource such as natural gas
and oil in a growing economy has considerable price leverage. In a stagnant
ecnnomy such as the world has experienced over the past year or two, a limited
resource has much less leverage.
7.3
In this series of sensitivity tests, world oil prices are assumed to
escalate at rates of 1% and 3% to evaluate the effects of lower and higher fuel
price escalation rates on the cost of power and electricity demand. Because
other fossil fuel price escalation rates are assumed to be linked to world oil
prices, the long-term escalation rates of other fuel prices are modified to be
consistent with the price of oil. In Table 7.1 the levelized costs of power
for the 1% and 3% fuel price escalation rates are compared with the costs of
power for the 2% fuel price escalation rate case (presented in Section 6.0}.
TABLE 7.1 Effect of Alternate Fossil Fuel Escalation Rates
on Levelized Cost of Power (mills/kWh}
Base Case
2% Escalation 1% Escalation 3% Escalation
1981- 1981-1981-1981-1981- 1981-
2010 2050 2010 2050 2010 2050
Plan 1A 58 64 56 61 60 67
Plan 1B 58 59 57 61 57 58
Plan 2A 59 66 57 64 61 69
Plan 2B 58 61 58 63 57 58
Plan 3 59 65 58 62 62 71
Plan 4 59 66 55 62 61 68
In the 1% real escalation rate case, levelized power costs generally
dropped in the cases using relatively high amounts of fossil fuels for
generation {Plan 1A, 3, and 4} over both periods of analysis. This drop
reflected the reduced cost of generation. The plans using relatively less
fossil fuels for generation (Plans 1B, 2A, and 2B) have a slight cost reduction
over the 1981-2010 time period, but show a slight increase in power costs over
the longer time period. This increase occurs because the price of fossil fuels
relative to electricity gradually decreases, causing consumers to switch
fuels. This switch reduces demand for electricity, which slightly increases
the cost of electricity over the longer time period for these plans. The
impacts of lower and higher fuel price escalation on the demand for electricity
are discussed later.
A 1% fuel price escalation rate reduces the relative advantage of the plans
that include the Upper Susitna project. If fuel escalation rates were further
reduced, the relative advantage of those plans would be reduced further.
7.4
In the case assuming a 3% escalation rate in fuel prices, power costs
significantly increased in those plans u~ing relatively high amounts of fossil
fuels and decreased in the plans less reliant on fossil fuel for generation.
In the cases using relatively large amounts of fossil fuel for generation, the
higher costs of fuel increased the cost of generation. In the plans less
reliant on fossil fuels, the costs declined because the price of electricity
declined relative to fossil fuels. This decline caused a switch to
electricity, which increased demand. The increased demand, in turn, reduced
the costs. (The consumer reaction to changes in relative prices is discussed
in greater detail in Section 7.1.3.)
7.1.2 Effects of Uncertainty in Fossil Fuel Prices on Demand for Electricity
The effects of the alternative fossil fuel price escalation rates on the
peak demand for electricity in the year 2010 are presented in Table 7.2.
TABLE 7.2 Effect of Alternate Fossil Fuel Price Escalation Rates
on Peak Electricity Demand in 2010 (MW)
Peak Demand (MW)
Base Case
2% Escalation 1% Escalation 3% Escalation
Plan 1A 1260 1160 1310
Plan 1B 1350 1160 1560
Plan 2A 1130 1040 1160
Plan 2B 1250 1050 1450
Plan 3 1190 1130 1200
Plan 4 1220 1180 1260
For the 1% fuel escalation rate case, the plans that rely relatively
heavily upon fossil fuels (Plans 1A, 3, and 4) generally show a slight decline
in demand, whereas those less dependent upon fossil fuels show a more
significant decline. In the former cases, both electricity and fossil fuel
prices are lower than in Plan 1A, causing the overall energy demand for both
fossil fuels and electricity to increase. However, the effects of fuel
switching away from electricity appears to outweigh the overall energy demand
effects of lower electricity prices.
7.5
The plans that are 1 ess reliant on fossil fuels (Plans lB, 2A, and 2B)
show a larger decline in demand. In these cases, the price of fossil fuels
decreases relative to the price of electricity because the price of electricity
is not heavily influenced by the drop in fossil fuel prices. This relative
price advantage of fossil fuels causes fuel switching to take place away from
e 1 ectri city and toward fossil fue 1 s.
In the 3% fuel escalation case the demand for electricjty goes up in all
cases for the same reasons it declined in the previous case. In these cases
the price of electricity goes down relative to fossil fuels, causing fuel
switching to electricity. Again, the greatest amount of fuel switching takes
place in those cases that are less reliant on fossil fuels.
7 .1.3 Consumer Reaction to Changes in the Price of Electricity Relative to
Other Forms of Energy
The effects of fue 1 and e 1 ectri city price changes depend on consumer
reactions to the changes. These reactions were sunmarized in the RED model in
a set of short-and long-run demand "elasticities" for electricity. An
elasticity is the ratio of two percentage changes. Own-price elasticity is the
percentage change in quantity of electricity demanded divided by a given
percentage change in the price of electricity. Cross-price elasticity is the
percentage change in quantity demanded of electricity for a given percentage
change in the prices for substitute fuels such as natural gas and oil. The own-
price and cross-price el asti cities of demand are usually 1 arger the 1 onger the
period of time over which the consumer has to react to a given change in
prices. The consumer is able to make more costly changes in fuel-using
equi pnent over the 1 onger time period.
For example, Figure 7.1 shows the effect of price changes in the base
case. In the figure, the 1 i ne marked "No Price Effects .. shows what the
forecast electricity demand would have been had real prices of electricity,
fuel oil, and natural gas ranai ned constant over the forecast period, and if
present trends in sizes of bu i 1 dings and app 1 i ances had continued. However,
the actual forecast assumes that the price of electricity more than doubles in
1982 dollars in Anchorage, while in Fairbanks it first falls by 50%, then
slowly rises again to its 1980 value. Fuel oil about doubles in price over the
forecast period in both areas, while natural gas quadruples in price in
7.6
~ -
"'0 s:: n::
E
Cll
Q
....:
n::l
Cll
0.
3000
2500
2000
1500
1000
500
No price effects
\sao
1020
Note: Real electricity price increases
2.5 times in Anchorage. It falls
by 50 percent in Fairbanks, then
increases to 1980 value.
1995
Years
. I
2000
FIGURE 7.1. Effect of Energy Price Changes on Electricity Demand
7a7
Anchorage and falls by 50% or more in Fairbanks. With such significant price
changes in the cost of energy and significant changes in the relative prices of
fuels, actual forecasted electricity demand is considerably reduced from the
value it would have had, had there been no changes in price. This is shown as
the line 11 Base Case .. in Figure 7.1. The difference is substantial by the year
2010--about 620 MW--and represents price-induced conservation and fuel
switching.
The RED model relies on price elasticities derived from a review of
econometric estimates of demand for electricity in the United States to
forecast the effects of fuel price changes on the demand for electricity. The
11 best guess .. elasticities used when the model is run in its certain mode
(default values) are shown in Table 7.3.
Because various sources estimated the elasticities in different contexts,
using a variety of data sets, and producing different estimates, the RED model
TABLE 7.3. Default Values Used in the RED Model
Short-Run (1 Year) Elasticity
Percentage Change in Electricity Demanded
for a One Percent Increase in the Price of:
Sector Electricity Fue 1 Oi 1 Natura 1 Gas
Residential
Business
Residential
Business
All Sectors Combined
-. 15
-.30
.01
.03
.05
.05
Long-Run (7 Year) Elasticity
Percentage Change in Electricity Demanded
for a One Percent Increase in the Price of:
Electricity Fuel Oil Natural Gas
-1.50 . 13 .50
-1.00 .20 .30
Load Factors
Electricity Fuel Oil Natura 1 Gas
.5573 .4899 .5216
Source: Volume VIII -Railbelt Electricity Demand (Red) Model Specifications
7.8
also contains a range of values for elasticities that can be selected randomly
by the model •s Monte Carlo routine. As consumers change their uses of
electricity in response to changing energy prices, the pattern of use during
the year also will change. Very little data are available to quantitatively
link the changes in the pattern of electrical energy use in Alaska to changes
in the ratio of average annual load to peak demand when relative prices
change. To reflect this uncertainty in the ratio of average annual load to
peak demand -the so-called 11 load factor .. -the RED model allows the annual
load factor to vary. The historic average in each load center is used as the
load factor when the model is run in its certainty-equivalent mode. In each
load center, the load factor is allowed to range from the highest to the lowest
value recorded for any utility in the load center during the 1970s. The
assumed range of elasticities and load factors for each load center are shown
in Table 7.4.
Sector
Residential
Business
Residential
Business
TABLE 7.4 Range of Elasticities of Demand and Load
Factors Used in the RED Model
Short-Run (1 Year) Elasticity
Percentage Change in Electricity Demanded
for a One Percent Increase in the Price of:
Electricity Fuel Oil Natural Gas
-.08 to -0.54
--.20 to -.54
.01 to .03
.01 to .05
Long-Run (7 Year) Elasticity
.05 to . 10
.01 to .10
Percentage Change in Electricity Demanded
for a One Percent Increase in the Price of:
Electricity Fuel Oil Natural Gas
-1.02 to -2.00
-.87 to -1.36
.05 to .21
• 15 to . 31
Load Factors
. 17 to . 81
• 18 to .41
Natural Gas
All Sectors Combined
Electricity
.492 to .634
Fuel Oi 1
.416 to .591 .454 to .612
Source: Volume VIII-Railbelt Electrici~v Demand (Red) Model Specifications
7.9
Figure 7.2 shows the effect on peak demand of allowing price elasticities
and load factors to vary. The shaded zones on the figure are the 50%
11 COnfidence intervals .. for the high, medium, and low economic scenarios
combined with the Plan lA and 2% world oil price escalation. The probability
is 25% that it is lower than the lower bound in each case and 25% that it is
higher than the upper bound. The probability is therefore 50% that the true
value lies between those values. As Figure 7.2 shows, the peak demand•s
central value for year 2010 is 1280 MW, with a 50% probability of lying between
1150 and 1400 MW. Using the default value for elasticity of demand and load
factors in the moderate case, demand was 1260 MW. The figures differ for Monte
Carlo and certainty-equivalent cases because only 20 iterations were performed
to generate the distributions in Figure 7.2. Increasing the number of
iterations to 100 reduces the mean demand to 1260 MW. In the figure shown,
1280 MW is the median demand. The figure indicates that a reasonable rule-of-
thumb for the forecasts is that, given the economic scenario, the forecast
demand is the central (default) value, plus or minus about 100 MW with 50%
confidence. If higher confidence levels were required, the confidence interval
would widen somewhat. Therefore, as Figure 7.2 shows, the forecast cases are
virtually indistinguishable until late in the forecast period because of
uncertainty concerning consumer response to energy prices.
7.2 UNCERTAINTY IN ELECTRICITY DEMAND FORECASTS
7.2.1 High-High Economic Scenario
As discussed in Section 3, electrical demand forecasts were made for six
economic scenarios. The analysis and discussion presented in Section 6 assumed
the medium or base case, load growth scenario (MM, medium economic growth and
medium state spending). In this section the effects of higher load forecasts
on the levelized cost of power are presented and discussed. The analysis was
conducted for the high economic scenario (HH, high economic growth and high
state spending). The peak demand and annual energy consumption for the year
2010 for the medium (base case) and high economic scenario are presented in
Table 7.5
7.10
2000
1500
-~
"'C
s:::
flj
E 1000 Q)
Cl
.::.1:.
flj
Q)
c...
500
1980
FIGURE 7.2.
1800 HH
1280 MM
1000 LL
1985 1990 1995 2000 2005 2010
Years
Sensitivity Test of Peak Demand: Monte Carlo Simu)ation
with Varying Price Elasticities and Load Factors(a)
(a) Shad~d areas eq~al 50% confidence intervals.
7.11
Plan 1A
P 1 an 1B
Plan 2A
P 1 an 2B
Plan 3
Plan 4
TABLE 7.5 Peak Denand and Annual Energy Use in 2010
for the Medi urn and High Economic Scenarios
Base Case
Medium Economic Scenario High Economic Scenario
Peak Annual Peak Annua 1
J11ill. Energy ( GWH) (MW) Enerqy ( GWH}
1260 6260 1760 9010
1350 6690 1890 9630
1130 5520 1510 7650
1250 6100 1820 9160
1190 5910 1610 8280
1220 6060 1650 8470
The levelized costs of power for each plan for the medium economic
scenario are compared to the levelized costs of power for the high economic
scenario in Table 7.6 for the time periods 1981 to 2010 and 1981 to 2050.
Plan 1A
P 1 an 1B
Plan 2A
P 1 an 2B
Plan 3
Plan 4
TABLE 7.6 Levelized Costs of Power for Medium and High
Economic Growth Scenarios (mills/Kwh)
Base Case
Medium Economic Scenario High Economic Scenario
1981-1981-1981-1981-
2010 2050 2010 2050
58 64 60 66
58 59 58 60
59 66 58 66
58 61 57 59
59 65 62 68
59 66 61 68
As shown in Table 7.6, in the high economic scenario Plan 2B has the
1 owes t 1 eve 1 i zed cost of power over both periods of ana 1 ys is (57 m i 11 s/ kWh over
the 1981-2010 time period and 59 mills/kWh over the 1981-2050 time period).
Plans 1B and 2A both yield 58 mill/kWh power over the 1980-2050 time horizon.
7.12
However, over the extended time horizon Plan 1 B gives a cost of power of 60
mills/kWh compared with 66 mills/kWh for Plan 2A. Plans 1A, 3, and 4 all have
higher costs of power over both time horizons. This analysis indicates that
the plans including the Upper Susitna project become more attractive for higher
electrical energy demands.
7.2.2 Low-Low Economic Scenario
In this sensitivity test, the effects of lower forecasted electrical
demand on the levelized costs of power are evaluated for each of the electric
energy plans. For this comparison the low private economic growth and low
state spending economic scenario is used •. The peak demand annual energy
forecasted for the year 2010 for the medill11 and low economic scenarios is
presented in Table 7.7.
Plan 1A
Plan 1B
Plan 2A
P 1 an 2B
Plan 3
Plan 4
TABLE 7.7 Peak Demand and Annual Energy in 2010
for Medi urn and Low Economic Scenarios
Base Case
Medium Economic Scenario High Economic Scenario
Peak Annual Peak Annual
( MW) Energy ( GWH) ( MW) Energy ( GWH)
1260 6260 1000 4940
1350 6690 990 4880
1130 5520 920 4490
1250 6100 900 4760
1190 5910 960 4730
1220 6060 1010 4900
The low economic scenario results in a 20% decrease in annual energy use
and a similar decrease in peak demand.
The levelized costs of power for the medill11 and the low economic scenarios
are presented in Table 7.8 for the two periods of analysis, 1981-2010 and 1981-
2050.
7.13
TABLE 7.8 Level ized Costs of Power for Medi LRn and Low
Economic Growth Scenarios (mills/Kwh)
Base Case
Medium Economic Scenario Low Ec onorriic Scenario
1981-1981-1981-1981-
2010 2050 ·2010 2050
Plan 1A 58 64 58 65
Plan 18 58 59 58 63
Plan 2A 59 66 58 66
P 1 an 28 58 61 57 61
Plan 3 59 65 58 67
Plan 4 59 66 57 64
For the low economic forecast and 30-year time frame, the lowest levelized
costs of power result from Plans 28 and 4 (57 mills/kWh). Plans 1A, 18, 2A and
3 have slightly higher costs of power {58 mills/kWh). Over the longer time
period Plans 18 and 28 have slightly 1 ower costs. P 1 an 18, including Upper
Susitna, is the most adversely affected by low growth, while Plan 4 is most
favorably affected.
7 .2.3 Effects of Electrical Load Growth Higher and Lower Than Forecasted
After 1990
As mentioned earlier there is a relatively large amount of uncertainty
regarding growth in electrical denand in the Railbelt. Unforeseen events may
cause damage to be significantly higher or lower than expected. Factors
contributing to this uncertainty include the following:
1. The uncertainty in world crude oil prices. Crude oil prices affect
electrical denand in the Railbelt in two ways. Firstly, since the State is
. ' heav1ly dependent upon royalty and severance tax revenues from the North Slope
oil fields, lower world oil prices reduce State revenue which, in turn, reduces
the amount of money available to be expended in the State. Since state
government spending accounts for a rel ati vel y 1 arge amount of total
expenditures in Alaska, world crude oil prices have a major impact on econanic
growth in the State.
7.14
Secondly, since fuel oil and other fossil fuels canpete with electricity
in many end uses such as space heating, water heating and cooking, and si nee
all fossil fuel prices tend to be influenced by world crude oil prices, crude
oil prices affect the decision by the consumer on which energy source to use.
If fossil fuel prices are low relative to electricity prices, then consumers
will tend to use more fossil fuels and less electricity. Conversely, if fossil
fuel prices are high relative to electricity prices, then consumers will tend
to use more electricity and less fossil fuels.
2. The uncertainty in large private economic development projects.
Construction of 1 arge private developnent projects such as the ANGTS pipeline
can have relatively large impact on population and emplo}111ent and as a result
can significantly influence electrical demand.
Perhaps the best strategy to deal with such uncertainty is to retain as
much flexibility as possible when planning future electrical generation
additions. Policies on strategies can be designed to reduce the risk of
having either too much or too little generating capacity at any point in
time. Such policies are also referred to as hedging strategies.
The key to maintaining maximum flexibility in electric power planning is
to add generating facilities that are relatively small and have short licensing
and construction times. However, in most cases, long-term electricity
generation costs from generating technologies available in small units and
·having short construction periods is higher than generation costs from
technologies available in larger sizes with longer construction periods.
( ExCITlpl es of generating technologies available in small units with rel ati vel y
short construction periods include combustion turbine and combined-cycle
units. While historically these technologies have offered low generation costs
in the Anchorage area because of the availability of low cost natural gas, this
situation is not expected to continue in the future. Examples of technologies
available in large sizes with longer construction periods include coal-fired
steam-electric units and large hydroelectric facilities.) These considerations
1 ead to trade-offs between generally 1 ower cost generation technologies that
require longer lead times but that reduce flexibility to respond to changes in
demand, and generally hi gh er cost ge ner at i on techno 1 ogi es that all ow shorter
lead times and thus provide more flexibility in planning.
7.15
In the context of the present power planning situation in the Railbelt
with the relatively high amount of uncertainty associated with future load
growth in the region, consideration of hedging strategies tends to favor
generating technologies that have relatively short construction periods and
that can be added in relatively small units. Therefore, technologies such as
combustion turbine units and other small technologies would be attractive
canpared to technologies such as large hydroelectric projects or coal-fired
steam turbine generation.
Because of the relatively large size of the Upper Susitna project (600 MW
for the first stage of Watana ), the f easi bil ity of this project must be
carefully evaluated with respect to the considerations of hedging strategies
outlined above.
To eva 1 uate the impact of incorrect initial forecasts of demand on cost of
power, two cases were examined. The first case assumes that the state begins
to build for demand that never materializes because of post-19~ events. The
second case assumes that post-1990 demand is initially underestimated, and
shorter term solutions (at higher cost) must be formed to meet higher demand.
-7.2.4 Load Growth Begins as Projected in the Medtum Economic Growth Scenario
but Lev e 1 s Off After 1990
In this case electrical demand is assuned to grow as projected in the base
case medium-medium (r.t-1) economic scenario but levels off and declines slightly
beyond 19~. This case is similar to the load growth in the nonsustainable
spending scenario (CC). The electrical demand for this case is shown in Figure
7.3, and the levelized costs of power are given in Table 7.9.
TABLE 7.9 Levelized Costs of Power for Reduction in
Electrical Demand after 1990 (mills/kWh)
Base Case
Medium Economic Scenario Reduced Growth Scenario
1981-1981-1981-1981-
2010 2050 2010 2050 --
Plan 1A 58 64 58 67
P 1 an 1B 58 59 59 67
Plan 2A 59 66 58 67
P 1 an 2B 58 61 60 69
Plan 3 59 65 59 70
Plan 4 59 66 57 66
7.16
As shown in Table 7.9, the reduced denand has relatively little impact on
the levelized costs of power over the 1981 to 2010 time period. Over the
1 onger time period the costs of power of all the plans go up; however, the
costs of power for Plans 1B and 2B, which include the Upper Susitna Project, go
up more than the costs of power for the other plans. This increase results
because the Watana Dam is l:x.Jil d and comes on-line in 1993, about the time when
the den and begins to taper off. The Devil Canyon Dam is not built in either
Plan 1B or 2B in this test.
1900 INCREASED GROWTH
1700
1500
~ 1300 MEDIUM GROWTH
0 / z
<C
:2:
u.J
0 1100 -~ ~
L5 c.. ~ 900 ~REDUCED GROWTH
700 ·---
500
1980 1985 1990 1995 2000 2005 2010
FORECAST YEAR
FIGURE 7 .3. Electrical Load Growth for Increased and Reduced
Growth Beyond 1990
7 .2.5 Load Growth Beg ins As Projected in. the Medium Economic Growth Scenario
but Increases After 1990
In this sensitivity test the electrical demand is assumed to grow as
projected in the base case medium-medium economic scenario but increases after
7.17
19ro. Demand increases are asstJned to be same as the industrialization case by
2010. The electrical demand for this case is shown in Figure 7.3 and the
levelized costs of power for this case are shown for the two periods in Table
7.10.
Plan 1A
P 1 an 1B
Plan 2A
Plan 2B
Plan 3
Plan 4
TABLE 7.10 Levelized Costs of Power for Increase in
Electrical Demand After 1990 (mills/kWh)
Base Case
Medium Economic Scenario Increased Growth Scenario
1981-1981-1981-1981-
2010 2050 2010 2050 --
58 64 66 74
58 59 63 68
59 66 71 80
58 61 62 67
59 65 69 79
59 66 68 78
In the increased growth scenario the costs of power increase substantially
in both time periods. The cases including the Upper Susitna projects (1B and
2B) provide the lowest cost of power in both time periods.
7.3 UNCERTAINTY IN COST AND AVAILABILITY OF MAJOR ALTERNATIVES
7 .3.1 Capital Cost of Upper Susitna Project-20% Lower and Higher Than
Estimated
The large size and capital intensive nature of the Upper Susitna project
makes the capital cost estimates for this project an important determinant of
the overall power costs within the region. The capital cost estimates for the
Upper Susitna Project were developed by Acres American Incorporated (1981b) as
part of the Susitna hydroe 1 ectri c project feasibility study and are presented
in Section 4.
To evaluate the possible effects of lower and higher capital costs,
sensitivity tests were done assuming that the capital costs of the project are
20% lower and 20% higher than shown. Because the Uoper Susitna project is
7.18
included only in Plans 1B and 2B, only those cases were rerun. The results of
these sensitivity tests are presented in Table 7.11 for the periods 1981-2010
and 1981-2050.
Plan 1A
Plan 1B
Plan 2A
P 1 an 2B
Plan 3
Plan 4
TABLE 7.11 Level ized Costs of Power for Upper Susitna -Capital
Costs 20% Lower and Higher Than Estimated (mills/kWh)
Base Case 20% Lower 20% Higher
1981-1981-1981-1981-1981-1981-
2010 2050 2010 2050 2010 2050 --
58 64 58 64 58 64
58 59 54 54 61 64
59 66 59 66 59 66
58 61 54 55 62 66
59 65 59 65 59 65
59 66 59 66 59 66
The 1 evel i zed costs of power. are relatively sensitive to the changes in
these capital cost estimates. If the capital costs are 20% lower than
estimated, Plans 1B and 2B provide significantly lower power costs than the
other plans in both periods of analysis (especially in the 1981-2050 time
period). If the capital costs are 20% higher than estimated, Plans 1B and 2B
become relatively high-cost plans relative to other plans in the 1981-2010 time
period and about equal over the longer time period.
7.3.2 Capital Cost of Coal Steam-Electric Power Capital Costs-20% Higher
and Lower Than Estimated
Capital costs were estimated for 200-MW coal-fired steam-electric power
plants 1 ocated in both the Beluga and Nenana areas. As pvoesented in Section 4,
these costs are $2070/kW for a plant located at Beluga and $2150/kW for a plant
located at Nenana. New coal steam-electric plants are included in Plans 1A and
3. The results of these sensitivity tests are presented in Table 7.12 for the
two periods of analysis, 1981 to 2010 and 1981 to 2050.
7.19
TABLE 7.12 Levelized Costs of Power for Coal Steam Turbine Plant-Capital
Costs 20% Lower and Higher Than Estimated (mills/kWh)
Base Case 20% Lower· 20% Higher
1981-1981-1981-1981-1981- 1981-
2010 2050 2010 2050 2010 2050 ----
Plan 1A 58 64 57 62 59 65
P 1 an 1B 58 59 58 59 58 59
Plan 2A 59 66 59 66 59 66
P 1 an 2B 58 61 58 61 58 61
Plan 3 59 65 57 63 60 67
Plan 4 59 66 59 66 59 66
As shown in Table 7 .12, the effects of higher and 1 ower coal plant capital
costs have little effect on the relative costs of the various plans.
7.3.3 Penetration of Conservation Alternatives Higher and Lower Than
Estimated
In this case the maximun penetration of_ conservation alternatives was
increased and decreased by 20% to test their impact on the cost of power. The
conservation alternatives included in this plan are building conservation,
passive solar space heating, active solar hot water heating, and wood-fired
space heating. To test the sensitivity of subsidized conservation on the cost
of power, the number of installations of all conservation options was
simultaneously increased or decreased by .20%. The subsidized market was not
all owed to exceed 100% of households in any case. However, if the decreased
amount fell below the level of conservation predicted with no subsidies, the
nonsubsidized market penetration rate was also decreased by 20% to permit the
lower number. Because these alternatives are dealt with explicitly only in
cases 2A and 2B, only those cases were rerun.' The results are shown in Table
7.13 for the two periods of analysis.
7.20
TABLE 7.13 Levelized Costs of Power for Penetration of Conservation
Alternatives 20% Higher and Lower Than Estimated (mills/kWh)
Base Case 20% Lower 20% Higher
1981-1981-1981-1981-1981- 1981-
2010 2050 2010 2050 2010 2050
Plan 1A 58 64 58 64 58 64
Plan 1B 58 59 58 59 58 59
Plan 2A 59 66 60 68 59 65
Plan 2B 58 61 59 62 57 60
Plan 3 59 65 59 ~ 59 65
Plan 4 59 66 59 66 59 66
As shown in Table 7.13, changes in the penetration rates have relatively
little effect on the cost of power. In general, lower penetration rates tend
to increase the costs of power, whereas higher penetration rates tend to
decrease cost of power. This situation reflects the fact that the conservation
alternatives analyzed in the study generally cost less per kWh saved than the
cost of generation and delivery displaced by the conservation alternatives.
7.3.4 Effects of Increased Thermal Generating Efficiency
One of the factors that influences the cost of generating electricity
using fossil fuels is the heat rate. The heat rate is a measure of the
efficiency with which a generating unit converts Btus of fuel into kWhs of
electricity. As newer materials and designs for thermal generating plants are
developed, the heat rates for these plants are expected to go down; i.e., they
are expected to become more efficient. In this test the heat rates for new
thermal options added after 1980 were lowered, as shown in Table 7.14, to
reflect such improvements in performance. Because some of this added capacity
is already under construction or on order, these assumptions may overstate the
overall savings that result from lowered heat rates.
7.21
TABLE 7.14 Assumed Improvements in Heat Rates (Btu/kWh)
Generating Base Case Improved
Alternative Heat Rate Heat Rate
Combustion Turbine 12,200 10,000
Combined Cycle 8,500 8,000
Coal Steam Turbine 10,000 9,500
Fuel Cells 9,200 8,500
Coal Gasification 9,300 8,700
Combined-Cycle
The effects of these improvements were evaluated in Plans 3 and 4 and
presented in Table 7.15 for the two periods of analysis.
TABLE 7.15 Levelized Costs of Power for Lowered Heat Rates
in Thermal Generation (mills/kWh)
Base Case Im(!roved Heat Rates
1981-1981-1981-1981-
2010 2050 2010 2050
P.l an 1A 58 64 58 64
Plan 1B 58 59 58 59
Plan 2A 59 66 59 66
Plan 2B 58 61 58 61
Plan 3 59 65 58 64
Plan 4 59 66 56 63
As shown, these changes in thermal efficiency make Plan 4 the lowest cost
alternative over the shorter time period. However, the effects of these
changes are relatively small. The longer-term ranking of Plans is virtually
unaffected.
7.3.5 Impact of Using Fuel-Cell Combined-Cycle Generation Rather Than Fuel-
Cell Stations
Because the number of alternative generating technologies that can be
included in any single model run is limited, the fuel-cell combined-cycle
alternative was not included in Plan 4. To test the effect of this technology
7.22
on the cost of power, the fuel-cell was replaced with the fuel-cell combined-
cycle alternative in one test. Although the fuel-cell combined-cycle has a
higher capital cost than fuel-cell station, the combined-cycle operates
more efficiently. The impact on the levelized cost of power of this
sensitivity test is shown in Table 7.16 for the two periods of analysis.
Plan
Plan
Plan
Plan
Plan
Plan
TABLE 7.16 Levelized Costs of Power for Using Fuel-Cell Combined-Cycle
Units Rather Than Fuel-Cell Stations -Plan 4 (mills/kWh)
Base Case Fuel-Cell Combined-C_ycle
1981-1981- 1981-1981-
2010 2050 2010 2050
1A 58 64 58 64
1B 58 59 58 59
2A 59 66 59 66
2B 58 61 58 61
3 59 65 59 65
4 59 66 61 69
As shown, the 1 evel ized cost of power increases if fuel-cell combined-
cycle units are used. The increase in efficiency does not offset the increase
in capital cost.
7.3.6 Impact of 50% Higher Fuel-Cell Station and Coal-Gasifier Combined-
Cycle Capital Costs
In general, the cost of emerging technologies tends to be higher when they
become commercially available than initially estimated. To test the impact of
such possible increases, the capital cost of fuel-cell stations and coal-
gasifier combined-cycle alternatives was increased by 50%. Plan 3 includes
coal-gasifier combined-cycle facilities and Plan 4 includes fuel-cell
stations. The results of these tests are presented in Table 7.17 for the two
periods of analysis. These capital cost increases raise the levelized cost of
power by 1 to 2 mills in both time periods.
7.23
Plan 1A
Plan 1B
Plan 2A
Plan 2B
Plan 3
Plan 4
7~3.7
TABLE 7.17 Levelized Costs of Power for Increased Capital
Cost of Fuel-Cell Stations and Coal-Gasifier
Combined-Cycle (mills/kWh)
Base Case Increased Ca[!ital Cost
1981-1981-1981-1981-
2010 2050 2010 2050 ----
58 64 58 64
58 59 58 58
59 66 59 66
58 .61 58 61
59 65 61 67
59 66 59 67
GaQital Cost of Chakachamna H_ydroelectric -20% Lower and Higher Than
Estimated
The Lake Chakachamna project is a relatively large hydroelectric project
that would be located on the west side of Cook Inlet. It is a key alternative
included in Plans 1A and 2A. Two cost estimates have recently been prepared
on two different concepts of developing the project. As part of this study, a
cost estimate was prepared for a project with a peak capacity of 480 MW. The
total cost of this concept is $1.01 billion or $2100/kW. In another project
being conducted for the Alaska Power Authority, a preliminary cost of $3860/kW
was estimated for a 330-MW project (excluding transmission costs). The
capacity in the 330-MW concept was reduced to allow minimum stream flow in the
Chakachamna River to maintain the fish runs existing in the river. The 330-MW
project concept was used in this report since the 330-MW concept reflects more
research concerning the possible environmental impacts of the projects.
However, to test the impact of the lower capital cost estimate on the cost
of power, a sensitivity test was run assuming that the total project cost was
$1.01 billion for a capacity of 330-MW ($3060/kW). This estimate is 21% lower
than the Bechtel estimate for the same project. Another sensitivity test was
performed by increasing the capital cost of the project by 20%. The results of
these tests are shown in Table 7.18 for the two periods of analysis.
7.24
TABLE 7.18 Leveli.zed Costs of Power for Chakachamna, Capital Costs
20% Lower and Higher Than Estimated (mills/kWh)
Lower Higher
Base Case carital cost car ita 1 cost
1981-1981-198 -1981-198 -l98l-
2010 2050 2010 2050 2010 2050 --
Plan 1A 58 64 57 62 59 65
Plan 1B 58 59 58 59 58 59
Plan 2A 59 66 57 64 60 68
Plan 2B 58 61 58 61 58 61
Plan 3 59 65 59 65 59 65
Plan 4 59 66 59 66 59 66
The changes in the capital costs of the Chakachamna project have a
relatively small impact on the levelized cost of power over both time
horizons. Little change occurs in the relative ranking of the plans in either
the lower or higher capital cost test.
7.3.8 Use of Healy Coal in the Anchorage Area
The development of the Beluga coal field is uncertain at this time.
Because development of this coal field is a key assumption in several electric
energy plans, this uncertainty must be recognized and taken into account in the
decision process. One possible alternative to using Beluga coal at minemouth
plants is to transport coal via the Alaska Railroad from the Healy area to
steam-electric plants located in the greater Anchorage area. This option would
be quite different in· several ways from the concept of using Beluga coal at
minemouth generating stations (e.g., there would be differneces in environ-
mental impacts). In this sensitivity test the only difference is assumed to be
the price of coal, which is assumed to be the price at Healy plus transpor-
tation costs to Anchorage. Sensitivity analyses were run for Plans 1A and 3.
The impacts of this assumption are shown in Table 7.19 for the two periods of
analysis.
7.25
Plan lA
Plan 1B
Plan 2A
Plan 2B
Plan 3
Plan 4
TABLE 7.19 Levelized Costs of Power Assuming Healy Coal
is Used in Anchorage Area (mills/kWh)
Base Case Heal~ Coa·l in Anchorare
l98l-1981-1981-198 -
2010 2050 2010 2050
58 64 59 65
58 59 58 59
59 66 59 66
58 61 58 61
59 65 61 68
59 66 59 66
As shown, this test indicates that the levelized cost of power would
increase by 1 to 2 mills/kWh over the 1981 to 2010 period and by 1 to 3
mills/kWh over the longer time period.
7.3.9 Delay in Upper Susitna Project from 1993 to 1998
For large construction projects, such as the Upper Susitna, the
possibility of delays always exists. To test the potential impact of delays on
the cost of_power, runs were made assuming that Watana does not come on-line
until 1998. Devil Canyon was assumed not to come on-line within the time
horizon. The effects of this delay for plans 1B and 2B are presented in Table
7.20 for the two periods of analysis.
Plan 1A
Plan 1B
Plan 2A
Plan 2B
Plan 3
Plan 4
TABLE 7.20 Levelized Costs of Power Assuming Watana Dam
Delayed Until 1998 (mills/kWh)
Base Case Dela,Y in Watana
1981-1981-1981-1981-
2010 2050 2010 2050 --
58 64 58 64
58 59 59 64
59 66 57 63
58 61 58 63
59 65 59 65
59 66 59 66
7.26
Delaying the Upper Susitna project by 5 years and providing short
construction time generation alternatives in the interim has relatively little
impact on the levelized cost of power over the 1981 to 2010 time period. The
delay slightly increases the costs of power over the 1981 to 2050 periode
7.4 EFFECTS ON ELECTRICITY DEMAND OF STATE SUBSIDIES TO COVER CAPITAL COSTS
OF NEW GENERATING FACILITIES
As discussed in Section 8, the State of Alaska has the legal framework in
place to provide subsidies and/or loans to finance electrical generation
projects. If the State does not require market rate of return on these funds,
the cost of power from projects financed this way would be lower than if
' capital costs were fully recovered. One potential major impact of reduced
. costs of power would be an increase in the demand for electricity. Two
sensitivity runs were made assuming that extreme forms of a policy were
implemented: the State was assumed a) to pay the capital costs for all new
generating facilities and b) not to require any capital recovery in electric
energy Plans lA and lB. Only recovery of operating and maintenance costs were
assumed to be required.
The levelized cost of power and peak demand for the medium economic
scenario and the no-capital-recovery assumption are presented in Table 7.21.
Plan lA
Plan lB
TABLE 7.21 Levelized Cost of Power and Peak Demand Assuming
No Capital Recovery (mills/kWh)
Medium Economic Scenario
Levelized
Cost of
Power
1981-2010
58
58
Peak
Demand
2010 .1!:00.
1260
1350
No-Capital-
Cost Recovery
Levelized
Cost of
Power
1981-2010
42
36
Peak
Demand
2010 .1!:00.
2302
2964
As the table shows, the resulting very low price of power to the consumer
causes large-scale fuel switching to electricity and few incentives to conserve
in existing uses. Demand in the year 2010 increases by about 1.8 times in Plan
lA and by about 2.2 times in Plan lB. A greater increase occurs in Plan lB
7.27
because the costs of power from hydroelectric facilities consist almost
entirely of capital charges that are now abso~bed by the State in these cases.
The real financial resources the state must spend to generate the power in
the no-capital-recovery case are higher than the 42 or 36 mills shown, although
the consumer sees only the 42 or 36 mill charge. These real resource costs
most likely will be higher than the 58 mills in the unsubsidized case because
demand is higher and will require that some higher cost generating capacity be
built.
These sensitivity tests indicate the State•s influence over demand for
electricity with capital subsidy policies. Less ambitious approaches requiring
either repayment of the capital costs or some positive rate of return will tend
to force the demand and prices in Table 7.21 toward the base case.
7.5 SENSITIVITY TEST IMPLICATIONS
To summarize the effects of the sensitivity tests, it may be useful to
distinguish between a change in absolute power costs and a change in the
ranking of the plans. For example, the unexpected reduced growth scenario had
little effect on absolute power costs for most plans, but moved the high
natural gas plan from near last place to first place. On the other hand, an
unexpected increase in demand after 1990 sharply increased the absolute costs
of all plans with very little effect on ranking. Capital cost overruns on
Susitna both adversely affected absolute costs of plans that included Susitna
and dropped plans that included Susitna from first place to last. The effects
of the two experiements with fuel price escalation were less profound, both in
absolute and relative terms. However, with the exception of unexpectedly high
demand none of the changes in either absolute power costs or ranking of plans
over the 1980 to 2010 time period can be considered large, since changes in
absolute levels of costs were 2 to 3 mills per kWh, and rank was determined by
a spread of 2 to 3 mills. Only over the extended time period were the results
more profoundly influenced, with plans that included Susitna more adversely
affected by capital cost overruns and the high natural gas plan helped the most
by low demand. This suggests that individual events• impacts on power costs,
by themselves, do not clearly favor one plan over another. While combinations
7.28
of events damaging or favoring the case for certain plans are possible, one
should carefully consider the combined probabilities of those events before
deciding which alternative truly has the lowest power costs.
7.29
8.0 CONSIDERATIONS FOR IMPLEMENTATING ELECTRIC ENERGY PLANS
When this study was started, the intended purpose of this section of the
report was to identify 11 iristitutional constraints .. that might prevent
implementation of any of the electric energy plans. This section also was to
include recommendations for legislation that would facilitate implementation of
a preferred electric energy plan. However, with the passage of Senate Bill 25
during the 1981 state legislative session, the approach was changeQ. SB 25
amended substantially the institutional framework previously in place and
established a new set of standards that must be followed by the Alaska Power
Authority (APA) before undertaking construction of a power generating facility.
In this section the electric energy plans are evaluated in light of this
legislation and the following subjects are discussed: 1) a review of federal
legislation to determine if any federal statutes are preventing the state from
undertaking any of the electric energy plans; 2) a brief review of the history
of the planning and implementation of power generation, transmission and
distribution in Alaska, with particular attention to the State's involvement in
these areas; and 3) a review of the recently enacted state statute to determine
if the electric energy plans can be implemented under it.
8.1 FEDERAL CONSTRAINTS
No federal statutes, rules or regulations absolutely prohibit
implementation of any of the alternatives discussed in this report. The
closest thing to a federal constraint upon state implementation may be the Fuel
Use and Power Plant Act (FUA) of 1978, which initially might be perceived as a
bar to using natural gas for generating electricity in new power plants.
However, a more extensive analysis indicates that FUA is not an absolute bar,
but rather only a legal obstacle that must be negotiated if the State chooses
to pursue a natural gas alternative such as Plan 4. This situation is true for
several reasons. First, the general proscription against using natural gas has
several exceptions. Most likely one or more of these exceptions will be
applicable to power generation in Alaska and therefore FUA would not be the
absolute constraint it appears to be. Second, FUA may be amended or repealed
8.1
in the near future because of-changing attitudes towards natural gas
availability for power generation and the general effort to reduce regulation
on the natural gas industry. If the FUA is not repealed or amended, and if
none of the exceptions ultimately could apply, FUA would be a bar to the natural
gas alternative. However, the application for an exception must be developed and
pursued before this situation can be determined. A more complete discussion of
FUA implications relative to specific technologies is contained in Volume IV.
Certain environmental laws also could impose a constraint. For example,
air-quality standards might prevent adoption of the increased coal-use
alternative. Again, however, before this constraint can be determined a
substantial amount of baseline data and engineering design work must be
accomplished. At this stage in the analysis of that alternative, the more
reasonable conclusion is that environmental standards can be met and that such
standards do not pose a constraint that absolutely cannot be satisfied. Under
special or unique circumstances, other environmental laws likewise could
prevent implementation of a particular option. For example, dam construction
was halted on a major hydro project in Tennessee following the discovery of a
species of fish protected by the Endangered Species Act. However, complete and
detailed studies must be completed before such unique events can be predicted
to preclude one or more of the alternatives.
8.2 A HISTORICAL PERSPECTIVE OF POWER PLANNING IN ALASKA
In Alaska, state involvement in planning and directly providing generating
capacity and transmission facilities is a n~.w undertaking. Prior to 1976,
planning and construction of facilities were performed either by the individual
municipal or cooperative utility, or by various federal government agencies.
For example, the Alaska Power Administration (now within the U.S. Department of
Energy) has owned and operated the Eklutna hydroelectric project since 1955.
Chugach Electric Association has planned and assumed responsibility for both
constructing hydroelectric projects such as Cooper Lake (1961) and installing
gas-fired generating capacity, as well as the transmission and distribution
systems associated with these projects. Other local utilities also assumed
responsibility for constructing facilities and conducting various feasibility
studies. Federal agencies also undertook a variety of feasibility and planning
studies.
8.2
In the mid seventies, however, these factors began to give way to other
forces. Project costs escalated significantly. Additionally, state revenues
were rising. In 1976 these forces resulted in passage of a bill creating the
Alaska Power Authority. The legislative findings and declaration of purpose
in the enabling legislation reveal the broad purposes and objectives that the
legislation sought to address.
Lack of direct state involvement in the first fifteen years after
statehood can be explained by several factors. Perhaps most significantly.
is that little need for such involvement was perceived. Another major factor
was that the local utilities were able to plan and manage the projects they
required. Furthermore, federal funds were available and state funds were not.
Legislative Finding and Policy
(a) The legislature finds, determines and declares that
(1) there exist numerous potential hydroelectric and fossil
fuel generating sites in the state;
(2) the establishment of power projects at these sites is
necessary to supply lower cost power to the state•s
municipal electric, rural electric, cooperative electric,
and private electric utilities, and regional electric
authorities, and thereby to the consumers of the state, as
well as to supply existing or future industrial needs;
(3) the achievement of the goals of lower consumer power costs
and long-term economic growth and of establishing,
operating and development power projects in the state will
be accelerated and facilitated by the creation of an
instrumentality of the state with powers to incur debt for
constructing, and with powers to operate, power projects.
{b) It is declared to be the policy of the state, in the interests
of promoting the general welfare of all the people of the state,
and public purposes, to reduce consumer power costs and
otherwise to encourage the long-term economic growth of the
stat~, including the development of its natural resources,
through the establishment of power projects by creating the
public corporation with powers. duties and functions as provided
in this chapter {Sec.l Ch/ 278 SLA 1976).
To accomplish its objectives the Power Authority was given broad power~,
including the power to issue bonds, to enter into contracts for the
construction, acquisition, operation and maintenance of power projects, and to
8.3
transmit and sell such power. It was also authorized to conduct feasibility
studies for hydroelectric and fossil fuel power generating projects.
The same legislation that created the Power Authorjty also created the
Power Project Revolving Loan fund. The Power Author-Ity administered this fund,
which was set up as a 11 trust fund 11 to make loans to municipal or public
utilities for feasibility studies, preconstruction engineering and design, and
construction of hydroelectric and fossil fuel plants. For example, in 1977
$1.6 million was appropriated for the Green Lake Hydroelectric project at Sitka
and $540,000 was appropriated to the Power Project Revolving Loan Fund.
Through the fund, loans also could be made to cities, boroughs, village
corporations, village councils and nonprofit marketing cooperatives for meeting
their 11 energy requirements ...
In 1978 the legislature significantly amended its 1976 legislation. The
findings were changed to state that the legislature's policy was to foster
power projects to supply power at "the lowest reasonable cost ••• , 11 whereas
the earlier findings had referred onlyto "lower cost .. power. The provision
relating to pricing of power was amended to make certain that the prices at
which power was sold covered the 11 full cost of the electricity and services .....
In ~978 the legislature also adopted resolutions approving the sale of
$300,000,000 in revenue bonds for constructing a _cga_l-fired electric generating
plant at Healy and authorizing the Power Authority to incur indebtedness
($25,000,000) for Phase I studies for the Susitna Hydroelectric Project.
Additionally, the state Senate adopted a resolution directing its Special
Committee on the Permanent Fund to investigate the use of money from the
permanent fund as a source of revenues for financing hydroelectric projects.
In 1979 the legislature adopted two resolutions related to power. One
asked the Army Corps of Engineers to use funds from the Small Hydroelectric
Plants program to investigate the feasibility of small-scale hydroelectric
projects in rural Alaska as an alternative to the high cost of deisel-generated
electricity. The other resolution approved issuance of $120 million in revenue
bonds for the Terror Lake Hydroelectric project and $20 million for the Solomon
Gulch project.
8.4
The 1980 session of the legislature passed substantial legislation
relating to the Power Authority. Approximately $50 million was appropriated
for some 35 projects. The major appropriations were $15 million for the
Tyee Lake project at Wrangell and an $18 million loan for the Swan Lake
project. Most other projects received funds ranging from~$40,000 to
~$2 mi 11 ion.
In addition to these direct appropriations, two resolutions authorized the
issuance of a variety of revenue bonds. The revenues from those bonds would be
use~ for constructing or acquiring generating facilities or for financing
expansion of distributions systems by local utilities. The revenues used
included the following:
• $70 million toward construction of the Tyee Lake project
• $120 million for the Swan Lake project
• $110 million for waste heat power generation facilities to be
constructed by Golden Valley Electric Association
o $15 million to finance the Lake Elva (Dillingham) project
o $30 million for the Bear Lake project (Prince of Wales Island)
e lesser amounts for Homer Electric Association, Naknek Electric
Associ at ion, Matanuska Electric Associ at ion, Glacier Highway Electric
Association and Cordova Electric Association.
In addition to this legislation relating to funding, two bills were passed
that again amended substantially the legislation creating the Power
Authority. The first bill was a major piece of legislation on the general
subject of energy. One part of this bill contain2d the provisions relating to
amendment of the Power Authority statute. These amendments gave the Power
Authority the power to recommend power project financing through the use of
general obligation bonds--a financing approach that earlier legislation had not
contemplated. This bill also amended substantially the provisions creating the
Power Project Revolving Loan Fund. One change converted the fund from a
revolving loan fund to a direct loan program, with funds for loans appropriated
by' the legislature to the. fund and revenues from repayment deposited in the
8.5
state • s Genera 1 Fund rather than in the Power Project Fund. The purposes for ..
which loans could be granted were expanded. A provision that permitted the
Power Authority to make unsecured loans in some instances also was added. The
right to forgive loans was transferred from the Power Authority to the
legislature itself.
A new section was added requiring the Authority to undertake
reconnaissance studies to identify power alternatives for communities. Under
this addition reconnaissance studies must be reviewed by the Division of Budget
and Management and submitted to the legislature. The Susitna Hydroelectric
project was addressed directly in subsequent 1980 legislation.
In 1981 the legislatur~ again passed electric power legislation, known as
SB 25 and SB 26. The legislation, discussed in Section .3, relates to the
Power Authority.
The above discussion is not intended as either a comprehensive review of
history of electrical power planning and development in the State of Alaska or
a detailed review of the legislation relating to the Power Authority •
. Nonetheless, several relevant observations can be drawn. First, involvement by
legislative and executive branches of the state government in the planning,
analysis, financing, and direct ownership of power generation and distribution
facilities is a recent phenomenon. Second, although recently involved, the
State has clearly assumed a major role in these activities. It has preempted
significantly most other efforts by federal agencies and 'by individual
utilities. Third, almost yearly the state's involvement has been expanding
significantly, in terms of dollar volum~, complexity, and geographic area.
Fourth, the specific means and parameters that define that involvement have
changed frequently •.
These observations suggest that the analysis of the 1981 legislation and
its impact upon alternative energy projects, which follows, must be viewed with
some skepticism. Most likely, these laws will be changed before either the
Susitna Project or some alternative can be implemented. Furthermore, because
the State's involvement has been so fluid, if an alternative is perceived
publicly as preferable to the Susitna Project, the alternative most likely
could be implemented directly by changes in the current statutes.
8.6
Federal, state, or local governments have become involved in the
construction and ownership of power generating facilities for four general
reasons. First, government involvement in the decision making process and
ownership of production facilities may be appropriate where mark.et
imperfections prevent a utility from building the generating capacity it needs
to meet demand. Such imperfections do exist in the capital markets ~nd also
may be caused by regulatory risks. To address such imperfections, the simplest
approach is for the government to make available to the utility a grant or loan
to provide a direct source of capital. Normally, the government entity would
not have to take over the decision making process or own the facility simply to
correct capital market imperfections.
A second reason for government involvement is to give recognition to
11 externalities 11 that result in public benefits but which are not factored into
an individual utility's decision making process. Many projects undertaken by
the federal government ar~ justified on this basis. For example, construction
of Tennessee Valley Authority dams was undertaken when public sentiment viewed
the creation of construction jobs as a public benefit in itself. In·this
instance, the government was wi 11 ing to spend money to put people to work on a
construction project even if a private entity was not willing to build the
project. For dams built in the West, the externalities that constitute public
benefits justifying the expenditure of public dollars include making water
available for irrigation and for protection against flooding. Although a
private utility might not chose construction of a hydroelectric plant if
cheaper energy sources are available, the hydroelectric plant may be the 11 best 11
plant when consideration is given to the additional public benefits it creates.
A third reason for government involvement is the decision to effect income
transfers through the distribution and consumption of power. If the government
wishes to subsidize the consumption of power, it may construct a plant and sell
the power below its free market price. The result will be a subsidy to
electricity users. Such a subsidy can result in income transfer either to end-
use consumers, to the utility distribution companies, or to both.
8.7
A fourth reason for government intervention in the decision making or
production production process is simply to alter the free market result for
political or policy reasons. Thus, if a private utility will generate
electricity using methods 11 A11 and 11 8 11 and the government prefers methods ucn
and 11 011 , it can intervene to ensure u-se of methods 11 C11 and 11 0.11 The
government•s preference for ncn and non might result from objectives already
discussed (such as income redistribution) or it might be the result of
noneconomic objective. For one example, a noneconomic objective might be the
desire to create a local market for coal. If this were a government objective,
the government might wish to encourage coal-fired power generation even if that
method was not the least-cost method.
8.3 THE CURRENT STATUTORY FRAMEWORK IN ALASKA
The legal authority for the state to implement the electric energy plans
is contained in the recently adopted legislation that revises the legislation
creating the Alaska Power Authority. The provisions creating the Alaskan
Energy Program, A.S. 44.83.380 et ~ (SB 25), are especially important. This
statute creates a fund, the revenues of which may be used for, among other
things, reconnaisance, feasibility and construction of power projects
(including all related costs of such construction). The fund may not be used
for operation and maintenance which, as discussed below, creates a significant
bias in planning. Before the revenues can be used for constructing a project,
the project must satisfy the following conditions:
1. The project must be economically feasible and after construction
must be able to provide revenue sufficient to return annually to the
State five percent {5%) of the amount that the Power Authority has
spent from the fund for the project.
2. The project must provide the lowest reasonable power cost to the
utility in the market area for the estimated life of the power
project, whether operated by itself or in conjunction with other
power projects in the market area.
8.8
3. The .project must operate either on renewable energy resources such as
hydroelectric, wind, biomass, geothermal, tidal, solar, temperature
differentials of the ocean, or coal, peat, waste heat, or fossil
fue 1.
4. The project must be approved by the legislature and funds
appropriated by the legislature.
Because these limitations are defined primarily in economic and political
terms and not in terms of engineering or hardware, the statute appears to have
enough flexibility to permit the Power Authority to adopt any of the four
alternative electric energy plans, provided that the plan meets the tests of
the statute. The exception to this conclusion is the plan option that requires
large expenditures for conservation of electrical energy. The statute appears
to contemplate construction of facilities that will generate electricity. The
statute may be interpreted so that certain types of conservation programs could
be classified as 11 projects;11 however, this approach is doubtful.
Implementating the conservation option appears to require new authorizing
legislation.
Although the requirements of A.S. "44.83.384 et ~· do not preclude
implementing any of the energy option plans (except perhaps conservation as
mentioned above), the circumstances under which the requirements dictate a
particular option as the only authorized option cannot be determined with
certainty. Lack of certainty results because the requirements are too general
and sometimes contradictory to judge definitively how the courts will interpret
the statute.
The relationship between the requirements set forth in A.S. 44.83.384
(conditions 1-3 above) and the requirement of legislative approval contained in
A.S. 44.83.380 is not clear. Legislative approval appears to be a separate,
independent requirement and therefore should not be sufficient to authorize
construction of a project that does not also satisfy the requirements of
A.S. 44.83.384. On the other hand, the legislative approval must be in
accordance with A.S. 44.83.185, which requires passage of a law authorizing the
project. Most likely the legislation authorizing approval will either make
explicit or implied amendments, or if necessary, repeal the requirements of
A.S. 44.83.384 as to the project the legislation authorizes. If the
8.9
legislature takes this action, then any of the options are possible if it is
approved· by enactment of a law. While this analysis seems logical, it renders
the requirements of A.S. 44.83.384 illusory, and for that reason, a court might
conclude that a project is not properly before the leg.islature for approval
until the requirements of A.S. 44.83.384 are met.
Application of the standards set forth in the statutes requires
interpretation by the Power Authority. For example, the requirement that a
project "be able to provide revenue sufficient to return annually to the State
five percent (5%) of the amount that the (Power Authority) has spent from the
fund ••• " is ambiguous. If this requirement is interpreted to mean that a
project must return five percent (5%) of the amount spent, almost no project
could qualify because the price the Power Authority charges for power pursuant
to section .490 expressly excludes capital recovery. This provision must mean
that five percent (5%) would be returned if a full price is charged. However,
even this interpretation raises questions. What price and demand assumptions
should be made to determine if the project meets the requirement? Is it
realistic that a project large enough to meet demand at a low price will also
be able to sell enough power at a much higher price to return five percent (5%)
per year? What rate of return should be assumed for invested capital? Also,
if the State has a 100% equity position in the project, this requirement
necessarily implies a 20-year amortization of the project.
The statute requires that a project must provide the lowest price by
itself and when operated in conjunction with other power projects in the market
area. However, a project may be lowest in only one situation, not· both. All
of these uncertainties are problems that ar·e frequently encountered and
handled by planners and engineers when making decisions about future generating
additions. Once assumptions are made about market area, future demand, project
lifetime and other parameters, conclusions can be drawn about which project
will provide the "lowest" cost. In the current statute uncertainty exists,
however, because it authorizes projects only when certain criteria, such as
"lowest cost," are met. It does not provide guidance on the assumptions that
are to be used when arriving at the final determination.
8.10
Because the statutory requirements are technical and require the Power
Authority in determining whether they are met, its determination should be
final unless a court finds that no reasonable basis exists for the their
fi~ding. This standard maximizes the Power Authority's flexibility to evaluate
alternatives, but does not give the Power Authority complete freedom to select
whatever .option it wants. If the option or base case is not justified in terms
of the statutory requirements, interpreted in a reasonable manner, the option
or base case could not be implemented under the existing statute.
In the statute, other provisions that seemingly are unrelated to the
statutory standards create bias in favor of a particular generation option.
Because the Power Authority obtains the needed funds for a project from the
legislature and because the project is expected to be subsidized partially with
General Fund revenues, no direct market accountability exists for whatever
option the Power Authority undertakes. On the other hand, the Power Authority,
as an agency of the state, must be accountable to the legislature, the governor
and the people of the state and, to the extent this political accountability is
a direct substitute for market accountability, the Power Authority can be
expected to seek out the least_-cost approach just as a private utility would.
Conversely, if the least-cost objective conflicts with other political
objectives, the Power Authority may seek to accommodate both the economic and
political goals to the maximum extent feasible.
Section .490(b)(2) of SB 25 states that if the legislature has not
appropriated $5 billion to the fund, the wholesale power rate shall be the
higher of either 10% of the amount the Power Authority has invested in power
projects or the amount of revenues necessary to pay operation and maintenance
(O&M) costs plus debt service plus safety inspections. If O&M costs, debt
service and safety inspections are less than 10% of investment, which is quite
likely, then purchasing utilities will want the legislature to appropriate the
$5 billion to satisfy the condition contained in (b)(2) since they th~n will
avoid the risk of the higher wholesale power costs. To meet the $5 billion
appropriation requirement, the legislature will have to select those power
projects and energy options that have the greatest initial capital cos.t. Of
the option plans identified in this study, only those· including construction of
8.11
Susitna appear to meet that requirement. The purchasing utilities can be
expected to work aggressively, in their own self interest, to persuade the
Power Authority to choose an energy option that includes construction of
Susitna, even if Susitna is not the least-cost approach.
The pricing provision also creates a second kind of bias. Assuming the
legislature does appropriate $5 billion, the wholesale price the Power
Authority charges to purchasers is a function of O&M cost~, safety inspections
and the financing approach used by the Power Authority. Under this provision,
the price to the purchasing utilities will be lowest for those projects having
lowest o&M and safety inspection costs, regardless of capital cost, when the
project is funded by direct appropriation. If the least-cost approach is one
that includes projects with higher overall long-term O&M costs but less initial
capital investment, the least-cost approach will not be favored by the
purchasing ut·ilities because it results in greater power costs to them (and
less cost to the State). This bias in· favor of the facility with the lowest
O&M is significant when considering alternatives. Those facilities, such as
hydroelectric projects, with high initial capital investment but low O&M costs,
will be favored by purchasing utilities because the c~pital costs are
subsidized by the State but O&M costs are not. On the other hand, projects,
such coal-fired plants, which have lower front end costs but higher O&M
costs, might be the least-cost project (in present dollars) but will not be
favored by the purchasing utilities because it could result in higher cost
power to them and to their customers because the State subsidy will be less.
The extent to which the statute's pricing provisions create, for the
purchasing utilities, objectives that conflict with the criteria contained in
other parts of the statute cannot be known until additional economic analyses
of the options are undertaken. Likewise, the extent to which the Power
Authority's analysis will be directly or indirectly inflenced by the desires of
purchasing utilities is unknown. Note that the Power Authority is required to
average prices statewide for all projects. This requirement means that all
purchasing utilities, not just Railbelt utiliti~s, will be impacted by the
Power Authority's decisions. All utilities which do, or may, purchase power
from the Power Authority, therefore, will have the same objectives of
preferring those projects that receive maximum State subsidy whether they
purchase power from a particular project or not.
8.12
REFERENCES
REFERENCES
Acres American Incorporated. l981a. Preliminary Assessment of Cook Inlet
Tidal Power. Prepared by Acres American Incorporated for Office of The
Governor, State of Alaska, Juneau, Alaska.
Acres American Incorporated. 1981b. Upper Susitna Project Development
Selection Report. Prepared by Acres American Incorporated for Alaska Power
Authority, Anchorage, Alaska.
Alaska Power Administration. 1977. Bradley Lake Project Power Market
Analysis. United States Department of The Interior, Alaska Power Adminis-
tration, Juneau, Alaska.
Alaska Power Administration. 1980. Hydroelectric Alternatives for the Alaska
Railbelt. Alaska Power Authority, Juneau, Alaska.
Backshire, J. A. ·1981a. Energy Conservation, Solar and Wood for Space and
Water Heating. Alaska Renewable Energy Associates, Anchorage, Alaska.
Backshire, J. A. 1981b. Maximum Possible Technolooical Market Penetration
of Selected Renewable Energy Technologies in Alaska•s Railbelt Region.
Alaska Renewable Energy Associates, Anchorage, Alaska.
Bechtel Civil and MineraJs, Incorporated, 1981. Chakachamna Hydroelectric
Project Interim Report. Prepared for The Alaska Power Authority, Anchorage,
Alaska.
CH2M-Hill. 1981. Feasibility Assessment: Hydropower Development of Grant
lake. Prepared for City of Seward, Alaska by CH2M-Hi11, Anchorage, Alaska.
Dow-Shell. 1981. Report to the State of Alaska: Feasibility of a Petro-
chemical Industry. Dow-Shell, Anchorage, Alaska.
EKONO, Inc. 1980. Peat Resource Estimation in Alaska-Final Report, Volume II.
Prepared by EKONO, Inc. for the Division of Fossil Energy, the U.S.
Department of Energy, Washington, D.C.
Electric Power Research Institute (EPRI). 19 78. Costs and Benefits of Over/
Under Capacity in Electric Power System Plannin[. EA-927. Prepared by
Decision Focus, Inc. for EPRI, Palo Alto, Californi-a.
Goldsmith S. and E. Porter. 1981. Alaska Economic Projections for Estimatino Electri~ity Requirements for the Railbelt. University of Alaska Institute
of Social and Economic Research, Juneau, Alaska.
Swift, W. H. et al. 1978. Energy Intensive Industry for Alaska. Battelle,
Pacific Northwest laboratories, Richland, Washington.
U.S. Army Corps of Engineers. 1981. Electrical Power for Valdez and the
Copper River Basin. U.S. Army Corps of Engineers, Alaska District,
Anchorage, Alaska.
R.l
U.S. Department of Energy. 19i9. Economic Analysis-Energy Performance
Standards for New Buildings. Office of Conservation and Solar Energy and
Office of Buildings and Community Systems, U.S. Department of Energy,
Washington, D.C. ·
R.2
APPENDIX A
SUPPORTING REPORTS
RAILBELT ELECTRIC POWER ALTERNATIVES STUDY
Volume I -Railbelt Electric Power Alternatives Study: Evaluation of
Railbelt Electric Energy Plans
Volume II -Selection of Electric Energy Generation Alternatives for
Consideration in Railbelt Electric Energy Plans
Volume III -Executive Summary -Candidate Electric Energy Technologies
for Future Application in the Railbelt Region of Alaska
Volume IV -Candidate Electric Energy Technologies for Future Application
in the Railbelt Region of Alaska
Volume V -Preliminary Railbelt Electric Energy Plans
Volume VI -Existing Generating Facilities and Planned Additions for the
Railbelt Region of Alaska
Volume VII -Fossil Fuel Availability and Price Forecasts for the Railbelt
Region of Alaska
Volume VIII -Railbelt Electricity Demand (RED) Model Specifications
Volume VIII -Appendix -RED Model User's Guide
Volume IX -Alaska Economic Projections for Estimating Electric-ity
Requirements for the Railbelt
Volume X -Community Meeting Public Input for the Railbelt Electric
Power Alternatives Study
Volume XI -Over/Under (AREEP Version) Model User's Manual
Volume XII -Coal-Fired Steam-Electric Power Plant Alternatives for the
Railbelt Region of Alaska
Volume XIII -Natural Gas-Fired Combined-Cycle Power Plant Alternative for
the Railbelt Region of Alaska
Volume XIV -Chakachamna Hydroelectric Alternative for the Railbelt Region
of Alaska
Volume XV -Browne Hydroelectric Alternative for the Railbelt Region of
Alaska
Volume XVI -Wind Energy Alternative for the Railbelt Region of Alaska
Volume XVII -Coal-Gasification Combined Cycle Power Plant Alternative for
the Railbelt Region of Alaska
A.l
APPENDIX B
DEMAND ASSUt~PTIONS AND FORECASTS
APPENDIX B
DEMAND ASSUMPTIONS AND FORECASTS
This appendix contains tables summarizing electrical demand assumptions
and results for the three Railbe.lt load centers -Anchorage and vicinity,
Fairbanks and vicinity, and Glennallen-Valdez. The demand totals include only
utility-provided energy at the consumer level. Military consumption, self-
supplied industrial electricity, and residential and commercial ·consumption of
electrical power by small users not connected to utilities are excluded. Line
losses and spinning reserve requirements are considered part of supply
requirements, but are not shown as part of demand.
The appendix is organized as follows. Table B.l summarizes the
assumptions used to generate forecasts of the Railbelt's economy and population
for use in the MAP model. Table B.2 summarizes the assumptions used in the
study for large industrial demand. Tables B.3 through B.ll show the forecasts
of total employment and population for each load center used throughout the
study. Tables B.l2 through B.37 show total energy and peak demand forecasts
for each load center for each combination.of economic growth and supply plan
analyzed in the study.(a) Finally, Tables B.38 to B.49 summarize the impact
of 1% and 3% growth in fossil-fuel prices above inflation as a sensitivity
test of the base case fuel escalation rate of 2%.
(a) The sum of peak demands for the three load centers will exceed that for the
Railbelt because the peak loads are assumed not to coincide. A diversity
factor of .971 is multiplied times the sum of the load center peak demands
to derive Railbelt peak demand.
B.l
TABLE B.l. Assumptions Used in Rail belt Power Alternatives Study
Industr~ Project! s) Assum(!tfon Low Case(a) Moderate Case(b) High Case(c) Industrialization Case(d) ~erhlgh Case(e)
Agri'cu 1 ture Various levels of Slow decline Employment growth Major agr1-Employment growth at fola.ior agrlcu1-deve 1 opment depend! ng in activity ~t 8% annual rate cultrual 8% annua 1 rate cultural on State & Federal developments; developments; policies, combined 16% annual 16% annual with market conditions growth qrowth
Fisher! es Constant emp 1 oyment 1 n No develop-50% replacement 100% rep 1 ace-50% rep hr. P.ment lOll% reJ)lace-existing fishery. ment ment ment Development of bottom
f lshing to replace
foreign fishing in 200
mine limit varies.
on, Gas and Trans-Alaska Pipeline Construction of 4 addi-Yes Yes Yes Yes Yes
Mining tional pumping stations
Northwest Gas P 1 pe 11 ne Construction of natural Yes Yes Yes Yes Yes
gas pipeline from
Prudhoe Bay and asso-
elated facilities
1983-87
Prudhoe Bay Oil and Product! on from exist-Yes Yes Yes VI!~ Yes
Gas ing and newly devel-
ttl oped fields result! ng
0 in increased permanent
IV employment
Upper Cook Inlet Dec 1 hrl ng emp 1 oyment Yes Yes Yes l'e5 Yes on and Gas 1 n oil production off-
set by emp 1 oyment
growth in gas production
National Petroleum Development & product-Exploration Slow Rapid Slow Rapid
Reserve in Alaska ion from 5 oil fields but no deve 1-development development development rlevelopment.
and construction of ment
of 525 miles of pipe-
line
Outer Continental Exploration, devel-Beaufort Sea 3 lease sales 7 lease sales 3 lease sales 7 lease sales
Shelf (OCS) petro-ment & product i on production; after 1985; after 1985; after 191l~; after lfl!l~;
leum and gas based on current OCS no sales 7 billion bbl 17 billion bbl 7 billion bbl l7 billion hhl lease schedule with after 1985.; discovered & d 1 scovered & discoverer! ~ discoverPrl &
additional sales billion bbl developed developed developed developer! after 1985 discovered
Coa 1 Development Development of Beluga No Eventua 1 pro-Eventua 1 pro-Eventual pro-Eventual pro-
coal reserves for ductton of 4.4 duct! on of 11 duct ion of 4.4 duction of 11 export and synfue 1 million tons ml111 on tons mill ion tons million tons
production per year per year per year per year
TABLE B.l. (contd)
_!_ndustr_.L_ Project( s) --~sumption __ Low_Case(a) J:!!!!lerate Case(b) _f!!..!l!!_la se ( ~ Industria 1 lzat ion Case(d) ~erhfgh Cas~(P)
U.S. Borax Development of mining
operation by 1993
No No Yes No Yes
Other Mining Hardrock and other Constant at 1% annual ~ annual 1% annual 2% annual
petroleum activities cur·rent levels growth of growth of growth of growth of
employment employment emp 1 o.ymen t emp 1 o.yment
Manuf act uri ng Aluminum Smelting 180,000 ton smelter No No No Yes Yes
Synfuels Construction and No No No Yes Yes
manufacturing by 1990
Petroleum Refining Construction of No Yes Yes Yes Yes
100,000 barrel per day
refinery at Valdez
Pacific LNG Project Development of liquid No Yes Yes Yes Yes
natural gas project in
the Anchorage area
between 1985-87
Petrochemicals Development of a pro-No No Phase 1 Phase 1 & Phase 1 &
ject similar in con-Phase II Phase II cept the Dow-Shell
proposal
1Jj Food Processing Development based on Grows to accommodate growth in fishing industry. .
w and correspondent to
growth of fisheries
Timber, Lumber, Pulp Expansion to accom-960 million 960 million 1.3 billion 960 million 1.3 billion
modate annual cut of board feet board feet board feet board feet board feet
960 million to 1.3
billion board feet
by 2000
Manufacturing for Local Expansion of existing 1% of total 2% of total 3% of total 5:C of total 5% of total
Alaskan Use production as well as employment employment employment employment employment
new manufacturing as
a proportion of total
employment
Government State Capital Move State capital move to No No Yes No Yes
Willow beginning in
1983
Federal Government Increases in civilian Growth at Same as low Growth rate Growth at historical r.rowth at
employment; military rate of of 1% annually rate of 0.5% of 1% annually
remains constant 0.5%
Tourism
Project(~
State Government(f)
TABLE B.l.
Assumption
Spending grows with
population, prices
and incomes
Annual growth rate of
tourism employment
Low -~!!_se(a)
Per capita
spending
unchanged
(contd)
~1oderate Case(b) High Case(c) Industrialization Case(d)
Per capita
spending in-
creases at
same rate as per
capita income
4%
Per capita
spending in-
creases at
same rate as
per capita
income
6%
Per capita spending
increases at same
rate as per capita
income
4%
~crhiqh Cas~(e)
Per capita
spending in-
creases at
same rate as
per capita
income
6%
(a) Has 90-95% probability that actual developments will equal or exceed this projection
(b) Has 50% probability that actual developments will equal or exceed this projection
(c) Has 5-10% probability that actual developments will equal or exceed this projection
(d) Same as moderate case with addition of a series of industrial developments: 1) petrochemical developments; 2) aluminum; 3) s.vnfuels; and 41 local
manufacturing
!e) Same as high case plus: 1) petrochemical; 2) synfuels; 3) aluminum; and 4) local manufacturing.
f) In the unsustainable spending case, private sector assumptions in the moderate case are maintained. State Revenues are reduced to the levels oredicte~
in October 1981 by the Department of Revenue. Operating expenditures grow by the same rule as in the moderate case. Capital expenditures are assumP.rl
to equal 90% of the accumulated Generdl Fund balance in the 1980's, equalling $5 billion per .vear b.v 1990. Operatin(l and capital expenditures are therP-
after limited by the exhaustion of the General Fund balances with the dPcline in oil revenues. After 1997, capital expenditures are financerl at a
reduced level of $200 million per year, entirely out of borrowing.
Sources: Vo 1 ume r X.
TABLE 8.2. Large Industrial Additional Sales and Peak Demand
Medium Economic Scenario (MM)
Anchorage Glennallen-Valdez
Pro6a6, 1 itx Pro6a61 htx
.25 .7S .s .25 .75 .5
Forecast Peak Sales Peak Sales Peak Sales Peak Sales Peak Sales Peak Sales
Year MW ~ ~ _§!!!!.._ MW ~ MW GWH MW _§!!!!.._ I-'ll GWH
1990 0 0 0 0 0 0 0 0 7.75 33.05 15.5 66.1
1995 5 43.8 13.5 118.25 22 196.7 0 0 7.75 33.05 15.5 66.1
Accelerated In~ustrial Develooment Economic Scenario (IM)
1990 0 0 125 1095 250 2190 0 0 7.75 33.05 15.5 66.1
1995 245 2103.8 428.5 3699.75 612 5273.7 245 2146 252.75 2179.05 260.5 2212.1
High Economic Scenario (HH)
1990 0 0 0 0 0 0 75 648 82.75 681.05 90.5 714.1
1995 5 43.8 13.5 118.25 22 196.7 75 648 82.75 681.05 90.5 714.1
Superhigh Economic Scenario (SH)
1990 0 • 0 125 1095 250 2190 75 648 82.75 681.05 90.5 714.1
1995 245 2103-.8 428.5 3689.75 612 5273.7 320 2794c 327.75 2827.05 335.5 2860.1
Note: Fairbanks has zero large project de~and in all cases. Low scenario has zero large project demand
for all areas.
The figures for 1980 and 1985 are zero, whereas the 1995-2010 numbers will remain at the 1995 level.
B.5
:t:at!le ~.J. Population and Total Employment,
Medium Scenario Without Susitna
Anchorage-Fairbanks-Glennallen-Total
eoo~ Iolet :tanana Vgll~ va1cez P.ID J belt
-Xear ~ .flili;?L. ~ ~ ~ .EmpL. 1:op... ~
1980 218564 93936 58671 23300 8100 2691 285335 119927
1985 264424 122621 75785 34015 12539 4450 352748 161086
1990 306886 141906 77969 35053 13144 4602 397999 181561.
1995 335010 151398 83911 37168 14430 4933 433351 193499
2000 374779 171546 92804 42168 16103 5547 483686 219261
2005 398115 186172 99351 45637 17112 6031 514578 237840
2010 417505 205017 103957 50203 17957 6635 539419 261855
!able a.~. Population and Total Employment,
Low Scenario Without Susitna
Anchorage-Fairbanks-Glennallen-Total
eoo~ IrJ.et !avar.a Vallev Yalcez p.g;i,J belt
~r ~ ~ ~ ~ 1:op... ~ ~ ~
1980 218913 93645 58926 23292 8095 2677 285934 119614
1985 253808 114303 75945 32778 9340 3197 339093 150278
1990 282101 122593 74100 306J2 10581 3474 366782 156679
1995 292968 123311 76736 30664 11103 3526 380807 157501
2000 312575 132422 81012 32763 11776 3742 405363 168927
2005 327848 139991 84521 34497 12414 3929 424783 178417
2010 346001 148836 88557 36512 13114 4141 447672 189489
l'.a.Cle a.s. Population and Total Employment,
High Scenario Without Susitna
Anchorage-Fairbanks-Glennallen-Total
Cook IDlet :tanana· VsU.l~ ~alcez Rail belt
.....lear ~ .fmL7L. ~ ~ ~ ~ ~ ~
1980 218482 94426 58530 23376 8101 2705 285113 120507
1985 275788 130809 76292 35982 17320 6418 369400 173209
1990 358872 180554 86056 43966 22016 8508 466944 233028
1995 413988 205937 99293 50680 24579 9321 537860 265938
2000 491123 245945 117976 61841 27843 10610 636942 318396
2005 572944 285692 138009 72878 31339 11786 742292 370356
2010 672846 3352i0 162136 86901 35307 13199 870289 435370
B.6
~ble ~.2-Population and Total Employment,
Medium Scenario With Susitna
Anchorage-Fairbanks-Glennallen-Total
Coo~ Inl~ l:aoar'.a. Valle!l Valge:z: F.ailbelt
~r ~ ~ ~ .fnmL. ~ .fmpL_ ~ ~
1980 218564 93936 58671 23300 8100 2691 285335 119927
1985 268115 124260 75237 34069 12442 4453 355794 162782
1990 336799 155615 75677 36505 12679 4733 425155 196853
1995 354350 160211 84271 38456 14386 5041 453007 203708
2000 383049 174255 94050 42683 16272 5589 493371 222527
2005 420595 190667 103938 45498 18290 6003 542823 242168
2010 457904 207822 115608 49180 20667 6519 594179 263521
~ble ;e.:z. Population and Total JZployment,
Low Scenario With Susitna
Anchorage-Fairbanks-Glennallen-Total
eoo~ Inlet I~nana ~lall~ Valce:z: p.gj J belt
--Xear ~ ~ ~ ~ ~ ~ ~ ~
1980 218913 93645 58926 23292 8095 2677 285934 119614
1985 257584 115916 75319 32819 9262 3200 342165 151935
1990 311233 134943 70789 31648 10092 3566 392114 170157
1995 311340 131141 76471 31698 11023 3610 398834 166449
2000 320716 135274 82209 33340 11942 3794 414867 172408
2005 327736 141290 87859 34598 12883 3938 428478 179826
2010 334379 146616 94485 36081 13973 4105 442837 186802
~able a. a. Population and Total Employment,
High Scenario With Susitna
Anchorage-Fairbahks-Glennallen-Total
Coo~ Inlet :rar.ana Vall~ VaJ.ce:z: &gjJbelt
...:Iear ~ lmPL. ~ ~ ~ ~ ~ ~
1980 218482 94426 58530 23376 8101 2705 285113 120507
1985 279346 132446 75807 36042 17194 6421 372347 174909
1990 388802 195619 84987 45902 21378 8686 495167 250207
1995 435592 217122 100815 52678 24606 9513 561013 279313
2000 502335 250680 120081 62943 28166 10715 650582 324338
2005 571444 289582 .142268 73121 32275 11826 745987 374529
2010 651904 334113 169023 85749 37000 13141 857927 433003
B. 7
Tabl!; a.2. Population and Total Employment,
Nonsustainable Government S~nding
Anchorage-Fairbanks-Glennallen-Total
Cools. Inl~t !aoana Ya'Ll~ Valg~z Railb~lt
-Year ~ .EmP.L. ~ ~ ~ ~ ~ .f:mpl...
1980 218564 93936 58671 23300 8100 2691 285335 119927
1985 272705 128927 77518 35570 12578 4528 362801 169025
1990 351654 175499 88789 43872 14008 5216 454451 224587
1995 353143 159188 88122 39094 15060 5118 456325 203400
2000 350448 144939 85749 34508 15430 4846 451627 184293
2005 313275 129565 74838 30117 14930 4689 403043 164371
2010 282679 116911 65793 26477 14335 4502 362807 147890
lsabl ~ s.lo. Population and Total Employment,
Ir~ustrialization scenario
Anchorage-Fairbanks-Glennallen-Total
~QQis. Inl~t !ar_ana Ysall~ Val!.l~z P.ailb~lt
.J.ear ~ .-.L. ~ ~ ~ ~ ~ ~
1980 218614 94048 58714 23350 8092 2691 285420 120089
1985 267427 125943 77072 35380 17311 6259 361810 167582
1990 324973 156423 82221 39259 24106 8846 431300 204528
1995 363129 170487 90410 42769 26178 9399 479717 222655
2000 417435 199128 104453 51006 27944 10122 549832 260256
2005 469011 221905 116505 56724 30279 10815 615795 289444
2010 531132 250652 131586 64656 32651 11593 695369 326901
!abl~ :a.ll. Population and Total Employment,
Superhigh Economic Scenario
Anchorage-Fairbanks-Glennallen-Total
Cools. Inlet !apana Vall~ valc~;z; Railb~lt
-1ea,r ~ ~ ~ ~ ~ .Em1?L. ~ ~
1980 218510 94489 58554 23405 8097 2705 285161 120599
1985 276860 131646 76731 36331 17287 6420 370878 174397
1990 366002 185893 88100 45886 24533 9617 478635 241396
1995 433643 219292 103946 54769 27649 10730 565238 284791
2000 524260 268112 127396 69247 30961 12103 682617 349462
2005 623899 319180 149238 83859 33837 13091 806974 416130
2010 747245 383833 178311 103084 37241 14359 962797 501276
B.8
Iable s.12. Peak Demand and Annual Energy,
Medium Economic Scenario, Plan lA
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet Tanana Vall~ Val de~ Rail belt
Peak Sales Peak Sales Peak Sales Peak Sales
~ .il:'Hl. (G;'lb) .!00. J.OOl}_ .ill1l ..LGllil Jml_ 1illhl.
1980 415 2026 113 487 9 39 521 2551
1985 496 2424 155 665 10 47 643 3136
1990 616 3009 269 1155 21 93 880 4256
1995 728 3608 270 1157 25 110 993 4875
2000 811 4011 208 893 29 130 1017 5033
2005 906 4477 185 793 34 151 1092 5421
2010 1073 5288 185 794 39 175 1259 6258
l:able :§.13. Peak Demand and Annual Energy.
Medium Economic Scenario, Plan lB
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~sll~ Val.Q.e.~ ~jJbelt
Peak Sales Peak Sales Peak Sales Peak Sales
~ mn. .m:lhl. 1MW.. (GWbl 1mL .!.Gillil. 1Wl ~
1980 415 2026 113 487 9 39 521 2551
1985 502 2450 154 662 10 47 647 3160
1990 667 3254 265 1136 21 92 924 4482
1995. 737 3651 264 1133 25 110 996 4894
2000 760 3763 195 835 29 130 955 4728
2005 888 4387 183 786 34 155 1073 5327
2010 1140 5617 206 883 41 186 1347 6686
l:able &1.14. Peak Danand and Annual Energy.
Medium Economic Scenario, Plan 2A
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~ ValQeZi Rail belt
Peak Sales Peak Sales Peak Sales Peak Sales
Xea.r. lWl.. 1.GNbl. ..coo. ..LG:ful. Jltil. .lll:lhl ..um 1Wbl.
1980 415 2026 113 487 9 39 521 2551
1985 437 2075 143 605 10 46 573 2726
1990 532 2522 262 1121 21 92 791 3734
1995 672 3287 264 1134 25 110 933 4530
2000 724 3533 196 841 29 130 921 4503
2005 802 3909 173 742 34 151 979 4802
2010 946 4604 173 744 39 175 1125 5523
B.9
Table B.l5. Peak Demand and Annual Energy,
Medium Economic Scenario, Plan 2B
Anchorage-Fairbanks-Glennallen-Total
Cook IrJ.et ~anana, Vall~ Vals:ie:z; RaiJbelt
Peak Sales Peak Sales Peak Sales Peak Sales
~ 1Wl. ~ .1Wl. ~ lWl. ~ JMW.. ~
1980 415 2026 113 487 9 39 521 2551
1985 442 2099 142 602 10 46 577 2746
1990 579 2741 258 1105 21 91 832 3937
1995 703 3438 267 1144 25 110 966 4692
2000 735 3590 200 857 29 130 936 4576
2005 848 4130 187 800 34 155 1038 5085
2010 1041 5056 201 860 41 185 1245 6101
Table a.lfi. Peak Danand and Annual Energy.
f.1edium Economic Scenario, Plan 3
Anchorage-Fairbanks-Glennallen-Total
Cock Inle..t__ ~anar..a ValleY. Va.l&ie:z; Rail belt
Peak Sales Peak Sales Peak Sales Peak Sales
~ lWl. ~ J..rtil. ~ 100 ~ 100. ~
1980 415 2026 113 487 9 39 521 2551
1985 496 2424 155 665 10 47 643 3136
1990 616 3009 269 1155 21 93 880 4256
1995 720 3569 267 1146 25 110 983 4826
2000 781 3865 200 858 29 130 981 4853
2005 862 4262 175 753 34 151 1040 5166
2010 1012 4991 173 744 3'9 175 1188 5910
~able 12.11-Peak Demand and Annual Energy§
Medium Economic Scenario, Plan 4
Anchorage-Fairbanks-Glennallen-Total
Cook lnle..t__ Xaoana Va.J.l~ Va.lgeZi Bail belt
Peak Sales Peak Sales Peak Sales Peak Sales
.¥.ear.: 100 lGlhl. 1Wl. {Gt;yh) Mil. lWhl. lWl lGmll
1980 415 2026 113 487 9 39 521 2551
1985 496 2424 155 666 10 47 643 3136
1990 616 3007 269 1156 21 93 880 4256
1995 722 3578 268 1148 25 110 985 4837
2000 792 3921 203 869 29 130 994 4919
2005 884 4369 180 771 34 151 1066 5291
2010 1038 5120 179 767 39 175 1219 6062
B.lO
Table .a.:+8. Peak Demand and Annual Energy.
Low Economic Scenario, Plan lA
Anchorage-Fairbanks-Glennallen-Total
Cook IDlet ~anana. Vall~ Vg!Cie~ P..ailbelt
Peak Sales Peak Sales Peak Sales Peak Sales
leal: mil. 1Wbl 1.Wl. ~ JWl ~ 1W1. .mful.
1980 415 ·2027 114 488 9 39 522 2554
1985 476 2325 154 661 9 42 621 3028
1990 557 2721 251 1078 12 54 797 3853
1995 609 2971 239 1023 is 69 837 4063
2000 647 3157 174 746 18 84 815 3988
2005 721 3520 153 655 22 102 870 4278
2010 852 4157 153 655 27 124 1001 4936
~able ~.19. Peak Demand and Annual Energy,
Low Economic Scenario, Plan lB
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~anana Val ley. Val!Jez B&!jlbelt
Peak Sales Peak Sales Peak Sales Peak Sales
~ ..lliNl (Gful lltil. (Gjh) Jllil. ..LWlll. 1Wl. ~
1980 415 2027 114 488 9 39 522 2554
1985 482 2353 153 657 9 42 626 3052
1990 610 2978 245 1051 12 54 841 4083
1995 629 3070 236 1012 15 69 854 4150
2000 609 2971 163 700 19 85 767 3756
2005 668 3261 146 627 23 104 812 3991
2010 831 4055 162 696 28 128 991 4878
~bJe B.2Q. Peak Danand and Annual Energy.
La-1 Economic Scenario, Plan 2A
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet Tanana ~alle~ Valge~ Railbelt
Peak Sales Peak Sales Peak Sales Peak Sales
leal: ..lliHL J.GYhl. lWl. (Glh) lWl. .1.GYhl 1Wl. lWhl
1980 415 2027 114 488 9 39 522 2554
1985 419 1988 142 600 9 41 553 2629
1990 478 2269 243 1040 12 54 712 3362
1995 565 2717 235 1008 15 68 791 3793
2000 604 2908 173 740 18 84 772 3732
2005 674 3244 153 654 22 102 825 4000
2010 775 3724 149 638 27 124 923 4486
B.ll
Table a.2le Peak Danand and Annual Energy g
La-1 Economic Scenario, Plan 2B
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~anana Vall~ Valgez Rail belt
Peak Sales Peak Sales Peak Sales Peak Sales
Xeat .mn. ~ lWl. CGWbl ..!Wl. ..mful 100.. 1ruhl.
1980 415 2027 114 488 9 39 522 2554
1985 424 2013 141 597 9 41 557 2651
1990 525 2486 237 1016 12 53 751 3554
1995 591 2846 235 1008 15 68 816 3922
2000 587 2824 167 718 19 85 750 3627
2005 646 3109 151 647 23 104 796 3859
2010 811 3905 169 726 28 127 979 4758
~able ;e.22e Peak Demand and Annual Energy.
La-1 Economic Scenario, Plan 3
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet !anana ValleY. Val~ F..all~lt
Peak Sales Peak Sales Peak Sales Peak Sales
Xear. J1W. (Gih.) jJ:til (Gih) .1Wl J.GWhl. 1Wl. .llmll.
1980 415 2027 114 488 9 39 522 2554
1985 476 2325 154 661 9 42 621 3028
1990 557 2721 251 1078 12 54 797 3853
1995 618 3018 242 1038 15 69 850 4125
2000 675 3293 182 781 18 84 850 4158
2005 723 3530 154 659 22 102 873 4291
2010 815 3981 146 627 27 124 960 4732
:I:able B. 23. Peak Demand and Annual Energy.
La-1 Economic Scenario, Plan 4
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet !anana ~all~ VaJgez F.ailbelt
Peak Sales Peak Sales Peak Sales Peak Sales
I.ea1: lWl. 1W1ll. .Wil (GWbl lWl. ..mmu. 1Wl (GWh)
1980 415 2027 114 488 9 39 522 2554
1985 476 2325 154 661 9 42 621 3028
1990 557 2721 251 1078 12 54 797 3RI)3
1995 610 2978 239 1026 15 69 839 4073
2000 657 3206 177 758 18 84 827 4048
2005 739 3607 157 674 22 102 892. 4383
2010 859 4194 154 662 27 124 1010 4980
B.l2
Ta.ble :a.2~. Peak Demand and Annual Energy.
High Economic Scenario, Plan lA
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~anana ~a.ll~ Vg,lQeZ Rail belt
Peak Sales Peak Sales Peak Sales Peak Sales
~ lWl. ~ .iltil. 1Whl .rum. ~ jH:il. ..I.Gffi:U.
1980 415 2025 113 486 9 39 521 2550
1985 515 2512 157 671 12 55 663 3238
1990 696 3400 293 1257 100 758 1057 5414
1995 811 4012 294 1264 105 782 1175 6058
2000 922 4552 237 1015 111 808 1232 6375
2005 1133 5585 235 1009 118 840 1443 7434
2010 1425 7008 262 1122 126 881 1760 9011
~a.ble B.25. Peak Demand and Annual Energy.
High Economic Scenario, Plan lB
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~anana Va.ll~ Valgez F.ailbelt
Peak Sales Peak Sales Peak Sales Peak Sales
~ ..lliHl. J2lhl J.Wl. <GWb> 1Wl. .fiEll. . lltil l.Gmll.
1980 415 2025 113 486 9 39 521 2550
1985 520 2536 156 668 12 55 667 3259
1990 744 3630 292 1252 99 757 1102 5639
1995 831 4107 298 1278 105 782 1198 6168
2000 872 4311 226 971 111 809 1174 6092
2005 1081 5332 233 1000 118 844 1391 7175
2010 1513 7440 303 1300 128 887 1888 9627
TabJ e a.26. Peak Demand and Armual Energy.
High Economic Scenario, Plan 2A
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~anana ~all~ Va.l!iez Rail bell
Peak Sales Peak Sales Peak Sales Peak Sales
~ Jm}_ <GWb> .am. .filYhl. .100.. J2lhl M:ll. .mihl.
1980 415 2025 113 486 9 39 521 2550
1985 454 2153 144 610 12 53 592 2816
1990 608 2880 286 1223 99 757 964 4860
1995 764 3724 294 1261 105 781 1129 5767
2000 814 3960 220 944 111 808 1112 5711
2005 962 4669 211 902 118 840 1253 6411
2010 1195 5783 230 984 126 880 1506 7647
B.l3
Te,bl~ B.21. Peak Demand and Annual Energy.
High Economic Scenario, Plan 2B
Anchorage-Fairbanks-Glennallen-Total
Cook lnl~t ~anana V9J.J_ey: VaJ.g~~ P.ailbelt
Peak Sales Peak Sales Peak Sales Peak Sales
.Xe,ar. Jml. <GWb> Jml. .mful ..!W}_ CGWhl JHi}_ ~
1980 415 2025 113 486 9 39 521 2550
1985 458 2175 144 607 12 53 596 2835
1990 648 3069 285 1219 99 755 1002 5043
1995 793 3864 301 1291 105 782 1164 5937
2000 840 4090 231 990 111 809 1148 5888
2005 1036 5031 238 1018 118 843 1352 6892
2010 1438 6964 305 1305 128 887 1816 9156
~able B,28. Peak Demand and Annual Energy,
High Economic Scenario, Plan 3
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~anana VruleY-Valde~ RailbeJt
Peak Sales Peak Sales Peak Sales Peak Sales
Xea.t: 100 CGWhl ..llim. (GWh) lWl JaM Jml. 1Wll.
1980 415 2025 113 486 9 39 521 2550
1985 515 2512 156 671 12 55 663 3237
1990 697 3403 293 1255 100 758 1058 5416
1995 810 4007 294 1262 105 782 1174 6052
2000 892 4408 229 984 111 808 1196 6201
2005 1040 5128 215 920 118 840 1332 6889
2010 1297 6386 236 1011" 126 881 1611 8278
Table B,2~. Peak Demand and Annual Energy.
High Economic Scenario, Plan 4
Anchorag~ Fairbanks-Glennallen-Total
Cook Inlet ~ Val,Qe~ P.ailbelt
Peak Sales Peak Sales Peak Sales Peak Sales
~ ~ ~ Jml_ (GWh) lWl' lWlll. ..!Mil. lGful.
1980 415 2025 113 486 9 39 521 2550
1985 515 2512 156 671 12 55 663 3237
1990 697 3401 292 1254 100 758 1057 5413
1995 804 3975 292 1252 105 782 1165 6009
2000 887 4382 227 973 111 808 1189 6163
2005 1076 5305 223 955 118 840 1375 7100
2010 1330 6545 243 1041 126 881 1650 8467
B.l4
Table s.Jo. Peak Demand and Annual Energy.
Nonsustainable Government Spending, Plan lA
Anchorage-Fairbanks-Glennallen-Total
Coo~ Inlet ~nana Vall~ VaJ.!Jez; f.Q,j lb.el:t
Peak Sales Peak Sales Peak Sales Peak Sales
~ JWl. Jrubl. JWl_ (GWh) lml 1.G'llil. .illil. ~
1980 415 2026 113 487 9 39 521 2551
1985 505 2466 156 671 10 47 652 3184
1990 691 3373 299 1281 14 62 974 4716
1995 713 3482 273 1170 17 79 974 4730
2000 664 3242 180 772 21 94 839 4108
2005 600 2930 129 552 24 108 731 3590
2010 584 2851 106 456 27 124 697 3431
~able ~.:u. Peak DeP.and and Annual Energy,
Nonsustainable Government Spending, Plan lB
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~anana Vall~ Valgez E9.ilbel:t
Peak Sales Peak Sales Peak Sales Peak Sales
~ lWl. ~ 1W1. CGi'Dll 1Wl. ~ lWl. 1Whl.
1980 415 2026 113 487 9 39 521 2551
1985 506 2469 157 673 10 47 653 3189
1990 694 3390 301 1290 14 62 979 4741
1995 703 3434 270 1160 17 79 962 4672
2000 618 3017 168 719 21 94 783 3830
2005 543 2651 117 500 24 108 663 3259
2010 523 2551 95 407 27 124 626 3082
XSble B.J2. Peak Demand and Annual Energy.
Industrialization Scenario, Plan 1A
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet Tanana YS:Uley: Valgez Rail belt
Peak Sales Peak Sales Peak Sales Peak Sales
:xea.r. .m:n. .ffi"lbl. 100 CGWbl lW.l. .mmll. ..il*U. ~
1980 415 2026 113 487 9 39 521 2551
1985 501 2447 157 672 12 55 650 3174
1990 755 4170 272 1169 25 114 1022 5453
1995 1084 6890 247 1060 276 2284 1560 10235
2000 1081 6874 172 737 281 2306 1489 9917
2005 1181 7361 156 668 287 2334 1576 10363
2010 .1382 8343 169 726 294 2367 1791 11436
B.l5
Tabl~ B.33. Peak Danand and Annual Energy,
Industrialization Scenario, Plan lB
Anchorage-Fairbanks-Glennallen-Total
Cools IDl~t !anana V~ley: Valgez Rail belt
Peak Sales Peak Sales Peak Sales Peak Sales
Xea1: .1mL (Qfu) lr:lll. (Qfu} .JHil. ~ .1l:ti}_ ~
1980 415 2026 113 487 9 39 521 2551
1985 501 2446 157 671 12 55 650 3172
1990 756 4175 273 1171 25 114 1023 5459
1995 1083 6882 247 1061 276 2284 1559 10227
2000 1065 6797 167 717 281 2306 1469 9820
2005 1200 7457 159 682 287 2334 1598 10472
2010 1503 8934 192 823 294 2367 1931 12124
~able :e .• J~. Peak Demand and Annual Energy,
Superhigh Economic Scenario, Plan lA
Anchorage-Fairbanks-Glennallen-Total
Cook IDlet !aruma Y:all~ Val!Jez Rail belt
Peak Sales Peak Sales Peak Sales ·Peak Sales
~ .!Wl (GWbl JWl. ~ lrtil. 1Wbl. lWl. ~
1980 415 2025 113 486 9 39 521 2550
1985 516 2518 157 672 12. 55 665 3245
1990 814 4460 290 1244 101 763 1170 6467
1995 1163 7275 273 1172 352 2936 1736 11382
2000 1191 7413 203 873 358 2963 1701 11249
2005 1354 8205 196 840 364 2994 1858 12039
2010 1624 9527 223 956 373 3034 2156 13516
Table B.J5. Peak Danand and Annual Energy.
Superhigh Economic Scenario, Plan lB
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet !anana Y:al.J ey: ValrJ..ez Rail belt
Peak Sales Peak Sales Peak Sales Peak Sales
.Ieal: 1Wl.. .fiEll Jltil (GWbl JOO. 1Whl. .lW)_ ~
1980 415 2025 113 486 9 39 521 2550
1985 516 2518 157 672 12 55 665 3245
1990 820 4489 292 1251 101 763 1177 6503
1995 1171 7314 277 1187 352 2936 1747 11437
2000 1166 7291 196 841 358 2963 1670 11095
2005 1356 8214 195 837 364 2994 1859 12046
2010 1739 10089 245 1052 373 3034 2289 14174
Bo16
Table B.32. Peak Demand and Annual Energy.
No Capital Recovery, Plan lA
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~ar.ana Vg].l~ Val !lei:~ Rail belt
Peak Sales Peak Sales Peak Sales Peak Sales
Iea.t. mn. 1W1ll. J.MW.. .ffi:lbl. 100 JSaful_ 1l:til ~
1980 415 2026 113 487 9 39 521 2551
1985 511 2495 160 687 10 47 662 3229
1990 693 3385 307 1317 21 93 991 4795
1995 897 4433 338 1449 25 110 1223 5993
2000 1185 5836 312 1339 29 130 1482 7305
2005 1519 7466 322 1380 34 151 1819 8997
2010 1971 9675 361 1550 39 175 2302 11401
Table ~.31. Peak Demand and Annual Energy.
No Capital Recovery, Plan lB
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~anana ~gJ,l~ ~alde'l Railbelt
Peak Sales Peak Sales Peak Sales Peak Sales
~ mn. {Gfu) 1Wl. {GWh) Jml. ..llEll. ...u:m ~
1980 415 2026 113 487 9 39 521 2551
1985 511 2495 160 688 10 47 662 3230
1990 699 3412 311 1334 21 93 1001 4839
1995 971 4793 366 1571 25 110 1322 6475
2000 1464 7197 393 1684 29 . 130 1830 9012
2005 1928 9463 416 1787 34 151 2308 11400
2010 2538 12442 477 2048 39 175 2965 14665
~able ;e .• Ja. Peak Demand and Annual Energy,
I..cM Fuel Prices, Plan lA
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~ar.ana ValJ ~ ~alcez Rail belt
Peak Sales Peak Sales Peak Sales Peak Sales
Iea1: ..!.ffil. ~ lWl. {Gfu) Jllil. ..ll.mlL lWl ~
1980 415 2026 113 487 9 39 521 2551
1985 498 2430 156 667 10 47 644 3144
1990 634 3093 278 1191 21 91 904 4375
1995 758 3753 289 1240 24 107 1040 5100
2000 784 3879 210 901 27 122 991 4902
2005 848 4192 185 793 31 139 1033 5124
2010 981 4842 183 786 35 157 1164 5785
B.l7
Table :a. 3 9. Peak Demand and Armual Energy.
LCM Fuel Prices, Plan lB
Anchorage-Fairbanks-Glennallen-Total
Cook. Inlet !a!Jill1a Vall~ Val!Je~ E&tiJbeJ t
Peak Sales Peak Sales Peak Sales Peak Sales
Xear.: lWl.. ~ J11W_ J.OOll_ 1l:tll. .1.GMll. .ll:til. J.GYbl
1980 415 2026 113 487 9 . 39 521 2551
1985 503 2457 155 664 10 47 649 3168
1990 686 3346 273 1172 20 90 951 4609
1995 786 3889 290 1243 24 107 1067 5238
2000 777 3846 210 900 27 123 985 4870
2005 830 4105 184 789 32 142 1015 5037
2010 968 4780 190 815 37 166 1160 5761
Tsble ~.40. Peak Demand and Annual Energy.
Low Fuel Prices, Plan 2A
Anchorage-Fairbanks-Glennallen-Total
Cook. Inl~.t.._ ·~ Valdez; RailbeJt
Peak Sales Peak Sales Peak Sales Peak Sales
~ 1Wl. .1.Whl. ..ww.. CGVhl 100. ~ 100 1Whl
1980 415 2026 113 487 9 39 521 2551
1985 438 2079 144 606 10 46 574 2731
1990 545 2584 269 1153 20 90 810 3827
1995 702 3430 284 1217 24 106 980 4753
2000 707 3450 201 860 27 122 908 4433
2005 752 3666 174 744 31 139 928 4549
2010 863 4201 172 736 35 157 1038 5094
~bl~ B,1 4l. Peak Demand and Annual Energy.
Low Fuel Prices, Plan 2B
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~anana ~all~ VaJ.gez: F.gj,lbelt
Peak Sales Peak Sales Peak Sales Peak Sales
Xeai. JM:il. ~ lWl. .mful. mil. lGYhl. JWl 100ll.
1980 415 2026 113 487 9 39 521 2551
1985 443 2104 143 604 10 46 579 2753
1990 598 2834 268 1146 20 90 860 4069
1995 757 3698 295 1266 24 106 1045 5070
2000 734 3582 209 898 27 123 942 4603
2005 769 3749 181 777 32 142 954 4668
2010 867 4217 181 775 37 166 1053 5158
B.l8
:I:able B.~~ • Peak Danand and Annual Energy.
LcM Fuel Prices, Plan 3
Anchorage-Fairbanks-Glennallen-Total
Coo~ Inlet Ianana Vg],ley: :slaJ.gez HajJ belt
Peak Sales Peak Sales Peak Sales Peak Sales
~ JMil. ~ lW.l. ~ JWl.. ~ ..Util. (GW1J)
1980 415 2026 113 487 9 39 521 2551
1985 498 2431 156 668 10 47 645 3146
1990 634 3093 278 1191 21 91 905 4375
1995 754 3733 287 1232 24 107 1034 5072
2000 759 3757 204 874 . 27 122 961 4753
2005 792 3917 171 733 31 139 965 4789
2010 955 4713 178 762 35 157 1133 5632
~able B.4J. Peak Demand and Annual Energy.
LcM Fuel Prices, Plan 4
Anchorage-Fairbanks-Glennallen-Total
Coo~ Inlet !anat"'.Q Valley: Valdez Rail belt
Peak Sales Peak Sales Peak Sales Peak Sales
Xeai: lWl. 1Wbl. ..{,00_ (<Mb) J.Wl. ~ J1til. ~
1980 415 2026 113 487 9 39 521 2551
1985 498 2430 156 667 10 47 644 3144
1990 634 3093 278 1191 21 91 904 4375
1995 765 3785 291 1250 24 107 1048 5141
2000 805 3983 216 928 27 122 1018 5033
2005 870 4300 190 815 31 139 1059 5254
2010 990 4886 186 798 35 157 1176 5841
Xable B.4~. Peak Demand and Annual Energy,
High Fuel Prices, Plan lA
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet Tanana Valley: :slaJ.{iej1; EgjJbelt
Peak Sales Peak Sales Peak Sales Peak Sales
Ie.ar. lWl. .mm:u. Jl:til. ~ 1Wl. .1Whl. JWL J.Gful.
1980 415 2026 113 487 9 39 521 2551
1985 498 2432 156 668 10 47 645 3147
1990 641 3127 279 1195 21 94 913 4417
1995 793 3922 289 1239 26 llA 1075 5275
2000 848 4191 209 896 31 138 1056 5225
2005 942 4653 183 786 36 164 1128 5602
2010 1126 5549 182 783 43 196 1312 6527
B.l9
Tg,Qle B.45. Peak Demand and Armual Energy.
High Fuel Prices, Plan lB
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet Tanana, ~sll~ Vrugez Rail belt
Peak Sales Peak Sales Peak Sales Peak Sales
Xear. JMiil. lGml1. ..wm.. ((ijh) JWl. lWhl lWl. ..LGrlbl.
1980 415 2026 113 487 9 39 521 2551
1985 504 2459 155 665 10 47 649 3171
1990 693 3383 274 1175 21 93 959 4652
1995 814 4027 287 1233 26 114 1094 5374
2000 830 4103 205 881 31 138 1035 5122
2005 978 4826 192 826 37 168 1173 5820
2010 1330 6547 228 979 46 208 1558 7734
~able :a. ~6 • Peak Demand and Armual Energy.
High Fuel Prices, Plan 2A
Anchorage-Fairbanks-Glennallen-Total
Coot Inlet :I:avana Vall~ Vru!Jez l?.a;i lbel:t;
Peak Sales Peak Sales Peak Sales Peak Sales
~ 1Wl. CG1hl Jl1W.. (Gjhl ..ll'Hl. ~ .w&l. ~
1980 415 2026 113 487 9 39 521 2551
1985 438 2081 144 607 10 46 575 2734
1990 552 2618 270 1158 21 93 819 3869
1995 736 3593 284 1219 26 114 1015 4926
2000 759 3702 198 847 31 138 958 4687
2005 826 4024 . 170 728 36 164 1002 4916
2010 979 4761 168 721 43 195 1156 5677
~able ;§. ~1. Peak Demand and Annual Energy~
High Fuel Prices, Plan 2B
Anchorage-Fairbanks-Glennallen-Total
Coot Inlet :I:anat'\a VgJ.l~ Vsligez Bail belt
Peak Sales Peak Sales Peak Sales Peak Sales
~ 100. ~ .mil CGWhl .m:n. ..LWhl. 1f1il_ J.Gillll.
1980 415 2026 113 487 9 39 521 2551
1985 444 2106 143 604 10 46 579 2756
1990 602 2850 268 1146 21 92 864 4088
1995 781 3815 292 1252 25 114 1067 5180
2000 809 3948 213 911 31 138 1022 4997
2005 936 4553 197 844 37 168 1136 5566
2010 1227 5953 223 956 46 207 1452 7116
B.20
Table B.48. Peak Demand and Arnmal Energy.
High Fuel Prices, Plan 3
Anchorage-Fairbanks-Glennallen-Total
Cook Inlet ~anana Yall~ Valge.z; Rail belt
Peak Sales Peak Sales Peak Sales Peak Sales
Xe£r.. J.Wl. .m:n:u_ 1ml. 1Whl. JW}_ (G\Yh) .1ml. ~
1980 415 2026 113 487 9 39 521 2551
1985 498 2432 156 668 10 47 645 3147
1990 641 3129 278 1194 21 94 913 4417
1995 787 3894 287 1231 26 114 1068 5240
2000 807 3992 199 854 31 138 1007 4983
2005 861 4256 166 712 36 164 1032 5131
2010 1031 5084 166 712 43 196 1204 5991
~able ~.~9. Peak Danand and Annual Energy.
High Fuel Prices, Plan 4
Anchorage-Fairbanks-Glennallen-Total
Cook IDle:t ~ Val!Jez ~-Peak Sales Peak Sales Peak Sales Peak Sales
~ ...!l:lill. J.(Ell_ lWl. CGWhl 1Wl. ~ Jllil. .mw.
1980 415 2026 113 487 9 39 521 2551
1985 498 2432 156 668 10 47 645 3147
1990 640 3125 278 1193 21 94 912 4412
1995 787 3893 287 1230 26 114 1067 5237
2000 824 4077 203 871 31 138 1028 5086
2005 898 4436 174 747 36 164 1076 5347
2010 1076 5303 173 743 43 196 1254 6241
B.21
APPENDIX C
LEVELIZED COST OF POWER
APPENDIX C
LEVELIZED COST OF POWER
In this report the levelized cost of power is used to compare the costs of
power from the various electric energy plans. The levelized cost of power is
computed by estimating a single level annual payment, which would be equivalent
to the present worth, given assumptions about the time value of money. The
procedure used to levelize the cost of power is explained in this appendix.
The relationship between the annual cost of power and the levelized cost of
power over a certain time horizon is shown in Figure C.l.
The total capital costs for a particular power plan (assuming no
generating facility or additions or retirements for this example) are fixed by
the initial financing and are typically constant over the life of the
facility. Operation and maintenance and fuel costs typically increase over
time as affected by inflation and as real fuel price increases. As a result,
the annual cost of power progressively increases over time.
Tl ME (YEARS l
FIGURE C.l. Annual Cost of Power and Total Levelized Cost
c. 1
Figure C.2 illustrates the use of the levelized cost of power to select
the alternative with the lower power cost. Alternative A represents a plan
with lower initial annual costs of power but with high annual costs of power in
later years. Alternative B represents a plan with higher initial costs of
power but with lower costs of power in later years. Without the use of a
present worth analysis, the selection of the lower cost plan would be unclear.
Initially, Plan A looks more attractive, whereas alternative B looks more
attractive in later years. Using levelized costs, however, Plan B is clearly
the lower cost plan over the time horizon.
As indicated in the report, the time horizon for this study extends from
1980 to 2010. However, because the economic lifetime of the Upper Susitna
project (assumed to be 50 years) will extend beyond 2010, a longer time period
was also used in the evaluation to compare the costs of power. The longer time
period runs from 1980 to 2050 and roughly corresponds to the economic life of
the Upper Susitna project.
The methodology used to compute the levelized cost of power over the 1980-
2050 time period is represented graphically in Figure C.3. In Figure C.3
typical annual costs of power computed using the AREEP model are presented for
the 1980-2010 time period. The case represented by the dashed line has
slightly higher power costs over the 1993-2000 time period but lower costs over
the 2002-2010 time period. This case corresponds to the cases including the
Upper Susitna project. The case represented by the solid line corresponds to
cases not including the Upper Susitna project such as Plans 1A or 3.
To compute the levelized cost of power over the extended 1980-2050 time
period, the annual costs of power from 2010 to 2050 were assumed to be the same
as in 2010 and constant over the time period.
This method does not account for replacement costs of thermal generation
changes in electrical demand or possible escalation in fuel costs over the 2010-
2050 time period. While it would be desirable to include these factors in the
analysis, it would require detailed analyses over the entire 1980-2050 time
horizon. The decision to compute and include the levelized costs over the 1980-
2050 time period was not made until late in the project when it became clear
that there was not going to be any clear price difference among the various
plans over the 1980-2010 time horizon.
C.2
LEVELIZED COST
OF PLAN A
ANNUAL COST
PLANA
ANNUAL COST
PLAN B
TIME IYEARSl
FIGURE C.2. Use of Levelized Cost to Select Lowest
Life Cycle-Cost Plan(a)
(a) See Volume IV, Candidate Electric Energy Technologies for Future
Application in the Railbelt Region of Alaska, Appendix C, for a
general discussion of levelized cost. For specific calculational
procedures, see Volume XI, Over/Under (AREEP Version) Model User's
Manual.
C.3
:I:
3 ;:,..::: -(/)
r-
.,.....
('") :a;: .
-!=» s....
QJ :::
0
0..
4-
0
+->
(/)
0 u
I
I I
'-------------~
I I
I I
I I
'' I I \ I I i...._ _______________ ..
I .
I
I
I
I
I
I
I
I
Cases not including Upper Susitna
-Project
Cases including Upper Susitna Project
Years
FIGURE G.3. Levelized Cost r.1ethodology for 2010-2050 Time Period
I
I
I
I
I
I
I
APPENDIX D
DETAILED DESCRIPTION OF RAILBELT ELECTRIC ENERGY PLANS
APPENDIX D
DETAILED DESCRIPTION OF RAILBELT ELECTRIC ENERGY PLANS
Appendix D contains a more detailed description of the electric energy
plans. In addition to a brief summary of the major features of each plan and
its potential impacts~ the generation system reliability~ and the environmental
and socioeconomic considerations are discussed in detail.
D.1 PLAN 1A: 11 PRESENT PRACTICES 11 WITHOUT UPPER SUSITNA
Plan 1A and 18 are both based on a transition from existing generating
technologies to alternative conventional generating technologies.
The following are the primary generating alternatives included in Plan 1A:
1 combustion turbines (gas or distillate)
• combined-cycle (gas or distillate)
1 hydroelectric (other than Upper Susitna)
1 conventional cost steam-electric
Hydroelectric plants include the following:
1 the Bradley Lake hydroelectric project~ which comes on-line in 1988
• the Chakachamna hydroelectric project~ which comes on-line in 2002
1 the Grant Lake project, which comes on-line in 1995
1 the Allison hydroelectric project, which come on-line in 1992
Other generating capacity includes the following:
Anchorage -Cook Inlet
1 Coal steam turbines and gas combined-cycles are installed as necessary to
supplement the hydroelectric projects.
Fairbanks -Tanana Valley
1 Oil combustion-turbine units are used for peaking until retirement.
• Gas combined-cycles are added to provide peaking generation when existing
oil combustion units are retired.
• Coal steam-electric capacity is added for baseload.
D. 1
0.1.1 Capacity and Generation for Plan 1A
In Plan 1A 400 MW of gas combined-cycle, 400 MW of coal steam turbine,
and 430 MW of hydroelectric capacity are added during the 1981 to 2010 time
span. Table 0.1 shows the existing capacity in 1980 and the capacity additions
(positive numbers) and retirements (negative numbers). Table 0.2 shows the
amount of electricity generated by each of the generating alternatives during
the 1981 to 2010 time period.
As shown, during the 1981 to 1991 time period, electrical generation in
Anchorage is largely supplied by gas combustion, turbine and combined-cycle
with some hydroelectrtc generation. During the later 20 years, generation in
the Anchorage area is largely hydroelectric with some gas-combined cycle and
coal steam turbine generation.
In Fairbanks, coal steam turbine capacity is used for generation
throughout the time horizon. Oil combustion turbine capacity is used during
the first 10 years while some gas combined cycle capacity is used during the
latter period.
0.1.2 Generation System Reliability
The loss-of-load probability (LOLP) is an indication of the reliability of
an electrical generation system. The LOLP indicates the probability that an
electrical generating system will not be able to meet the electrical demand.
The LOLP is expressed as the number of times a generation system will not be
able to meet demand over a specified time period. For example, a LOLP of one
day in 10 years indicates that the system would not meet load one time in 10
years. A LOLP of one day in 10 years is a r.elatively common design goal in the
u.s.
An indirect method of measuring system reliability is the reserve margin.
The reserve margin indicates the amount of generating capacity an electrical
generating system has in excess of the annual peak demand. Extra capacity is
required to allow the system to meet the peak demand in the event of scheduled
or unscheduled outages of certain generating units. A system with a peak
demand of 1000 MW and a total generating capacity of 1200 MW would have a
reserve margin of 20%. In general, a higher reserve margin indicates a greater
amount of system reliability.
0.2
TABLE D.J. Existing Capacity (1980) and Capacity Additions and Retirements
(1981-2010) -Plan 1A (MW)
Anchorage-Cook Inlet Fairbanks-Tanana Valle~
011
Gas Gas Coal Combustion Coal Gas
Combust ion Combined-Steam Turbine & Steam Combined-
Year Turbine C~cle Turbine Diesel Turbine ~l.L Hydroelectric
1980 461 139 0 266 69 0 46 (Eklutna & Cooper Lake)
1981 0 0 0 0 0 0 12 (Solomon Gulch)
1982 -20 178 0 0 0 0 0
1983 0 0 0 -8 0 0 0
19fl4 0 0 0 0 0 0 0
1985 0 0 0 0 0 0 0
1986 0 0 0 -1 0 0 0
1987 0 0 0 -8 -4 0 0
1988 0 0 0 -6 0 0 90 (Bradley Lake)
1989 0 0 0 0 -5 0 0
1990 0 0 0 0 0 0 0
1991 0 0 0 -18 0 100 0
0 1992 -16 0 200 -19 0 0 7 (Allison) . 1993 -9 0 0 0 0 0 0 w 1994 -30 0 0 0 0 0 0
1995 -14 0 0 -33 0 0 7 (Grant Lake)
1996 0 200 0 -102 0 0 0
1997 0 0 0 -65 200 0 0
1998 -50 0 0 0 0 0 0
1999 0 0 0 0 0 0 0
2000 -18 0 0 0 0 0 0
2001 0 0 0 0 0 0 0
2002 -51 0 0 0 -25 0 330 (Chakachamna)
2003 -53 0 0 0 0 0 0
2004 0 0 0 0 0 0 0
2005 -58 0 0 0 -21 0 0
2006 0 0 0 0 0 0 0
2007 0 0 0 0 0 0 0
2008 -26 0 0 0 0 0 0
2009 0 0 0 0 0 0 0
2010 0 0 0 0 0 100 0
TABLE D. 2.. Electricity Demand and Generation by Type of
Capacity -Plan lA (GWh)
Anchorage-Cook Inlet on Fairbanks-Tanana Valley
Gas Gas Coal Combustion Coal Gas
Combu.st ion Combined-Steam Turbine & Steam Combined-
Year Turbine Cycle Iurbine Diesel Turbine Cycle Hydroelectric
1981 2017 46 0 27 537 0 254
1982 765 1386 0 66 537 0 254
1983 839 1400 0 104 537 0 254
1984 941 1386 0 143 537 0' 254
1985 409 2265 0 0 458 0 254
1986 1345 1465 0 27 537 0 254
1987 1440 1505 0 133 537 0 254
1988 1244 1445 0 238 537 0 648
1989 1355 1469 0 386 496 0 648
1990 998 2490 0 3 457 0 648
1991 1878 1655 0 1 496 51 648
1992 749 1429 1578 0 427 2 679
1993 858 1438 1584 0 436 3 679 0 1994 965 1428 1611 0 443 5 679 .j:::. 1995 91 2162 1611 0 496 197 710
1996 10 2444 1611 0 496 29 710
1997 1 995 1611 0 2013 3 710
1998 1 1024 1611 0 2019 4 710
1999 1 1057 1611 0 2020 4 710
2000 1 1085 1611 0 2026 4 710
2001 1 1159 1611 0 2034 5 710
2002 0 169 1611 0 1668 0 2155
2003 0 182 1611 0 1738 0 2155
2004 0 196 1611 0 1809 0 2155
2005 0 372 1611 0 1716 1 2155
2006 0 547 1611 0 1722 1 2155
2007 0 722 1611 0 1727 1 2155
2008 0 899 1611 0 1730 2 2155
2009 1 1059 1611 0 1732 20 2155
2010 0 1225 1611 0 1734 33 2155
The AREEP model adds capacity such that the reserve margin never drops
below a selected value. The model then computes the resulting LOLP. Several
model runs were made to insure that when analyses are done with AREEP, the
reserve margin would yield a LOLP of about one day in 10 years. Different
electric energy plans and electrical demands slightly change the reserve margin
required to maintain a LOLP of about one day in 10 years. In most cases a
planning reserve margin of between 34% to 32% yielded a LOLP of about one day
in 10 years during most of the time horizon. As shown by the typical results
presented in Figure 0.1, there is little effect on the cost of power of
alternative reserve ma.rgins within this range (EPRI 1978). For the results
presented in this report, a planning reserve margin of 30% was used in all
cases.
0.1.3 Environmental Considerations of Plan 1A
The hallmark of Plan 1A is the increased use of fossil fuels (coal and
gas) to produce electricity. The main environmental impacts are therefore
associated with the combustion gases, waste products and cooling water required
to operate the plants. In addition, the potential impacts of the 90-MW Bradley
Lake and 330-MW Chakachamna hydroelectric facilities must be considered.
This section discusses some of the general environmental concerns of
Plan 1A. Specific impacts of this plan are discussed.
Air Pollutants
Several kinds of air pollutants are normally emitted by fuel-burning power
plants. These include particulate matter, sulfur dioxide (so 2 ), nitrogen
oxides, carbon monoxide, unburned,;hydrocarbons, water vapor, noise, and odors.
Particulate matter consists of finely divided solid material in the air.
Fuel combustion power plants produce particulate matter in the form of unburned
carbon and noncombustible minerals. Particulate matter is emitted in large
quantities if high-efficiency control equipment is not used. Particulates are
removed from flue gas by electrostatic precipitators or fabric filters
(baghouses). These precipitators or filters are routinely required, however,
and collection efficiencies can be very high (in excess of 99%).
0.5
COST TO
CONSUMERS
(M/kWh)
50
45
40
35
30
25
VARIABLE COST
...._,_...
REGION OF
LOWEST COSJ
COST TO
CONSUMERS
($MILLIONNEAR)
7000
6000
5000
4000
20 ~-----------i~--------------------~3000
15 2000
10 FIXED COST
1000
5
0 ~------~----~~--------~------~--~
0 10 20 30 40 45
PLANNING RESERVE MARGIN(%)
FIGURE D.l. Typical Costs for Alternative Reserve
Margins (EPRI 1978, p. 6-11)
0.6
Sulfur dioxide is a gaseous air pollutant that is emitted during
combustion of fuels that contain sulfur. Sulfur dioxide, like particulate
matter, has been identified as being harmful to human health, and it appears to
be particularly serious when combined with high concentrations of particulate
matter.
Nitrogen oxides (N0 2 and NO, primarily) are gaseous air pollutants that
form as a result of high-temperature combustion or oxidation of fuel-bound
nitrogen. Nitrogen oxides damage plants and play an important role in
photochemical smog. Fuel combustion plants and automobiles are significant
contributors to these_emissions.
Pollution control technology for nitrogen oxides has developed more slowly
than for most other air pollutants. Lack of chemical reactivity between NOx
and conventional scrubbing compounds is the main difficulty. Thus, current
control strategies focus on control of NOx production. Principal strategies
include control of combustion temperatures (lower combustion temperatures
retard formation of NOx) and control of combustion air supplies to minimize
introduction of excess air (containing 78% nitrogen).
Carbon monoxide (CO) emissions result from incomplete combustion of carbon-
containing compounds. Generally, high CO emissions result from poor combustion
conditions and can be reduced by using appropriate firing techniques. However,
CO emissions can never be eliminated completely, even if the most modern
combustion techniques and clean fuels are used. CO emissons are regulated
under the Clean Air Act because of their toxic effect on humans and animals.
Plumes of condensed water vapor come from wet cooling towers and
combustion cases. When it is cold, the plumes are particularly long because
the ambient air can hold little added moisture. Formation of these plumes is
particularly hazardous during 11 fogging 11 conditions when a high wind speed
causes the plume to travel along the ground. During freezing conditions, such
plumes may lead to ice formation on nearby roads and structures. Dry cooling
towers can be used to reduce fogging and icing.
The S02 and NOX emissions from major fuel-burning facilities have been
related to the occurrence of acid rainfall downwind of major industrial areas.
Congress may soon enact laws to restrict these emissions because of the effects
of acid rain. The theoretical framework for explaining acid rain formation,
D.7
the acidification of lakes, the effects on soils, vegetation, wildlife and
structures, and the tracing of problems to specific source emissions is not yet
fully understood. Much research is in progress, and recent research indicates
that some remote areas of the western United States have been affected by acid
rain.
Emissions from Power Plants
;
Combustion Turbines. One of the primary siting constraints of the
combustion turbine technology is environmental. The exhaust from combustion
turbines typically contains oxides of sulfur (SOx) as well as NOx. These
constituents comprise ~he main pollutants of greatest regulatory concern. CO,
unburned hydrocarbons, and particulate matter can also be present. The
quantity of each particular contaminant emitted is a function of the size of
the machine, the manufacturer, the type of fuel burned, and the extent to which
emission control techniques are used. The suitability of a particular site
will depend upon the degree to which these contaminants can be controlled.
Combined Cycle. Like the simple-cycle combustion turbine plant, a
combined-cycle plant has siting constraints related to air emissions. In
addition, the combined-cycle plant has further constraints imposed by the steam
cycle, which requires water for condenser cooling and boiler make-up. However,
because the combustion turbine portion of the total combined-cycle plant
{approximately two thirds) requires essentially no cooling water, water
requirements are much less than a similar sized, conventional steam-electric
plant. Air-quality impacts are similar to those associated with combustion
turbines.
Coal-Fired Power Plants. Coal-fired power plants generate large
quantities of solid waste derived from both the combustion process (fly ash and
bottom ash) and from atmospheric emissions (flue-gas desulfurization wastes).
These wastes require more extensive environmental monitoring and waste
characterization studies, and generally more sophisticated treatment
technologies than other steam-cycle technologies. Water resource impacts
associated with these solid wastes are generally mitigated through appropriate
plant siting and a water, wastewater, and solid waste management program.
0.8
The combustion of large amounts of coal leads to a potentially significant
deterioration of the surrounding air quality. The major pollutants include
particulate matter, SOx and NOx. Federal New Source Performance Standards
govern these emissions.
Other significant effects from coal-fired steam plants are associated with
water supply and wastewater discharge requirements. Water withdrawal may
result in impingement and entrainment of aquatic organisms. Chemical and
thermal discharges may produce acute or chronic effects to organisms living in
the discharge plume area. Thermal discharges can also cause lethal thermal
shock for some organi~ms in the Railbelt region.
Many potentially suitable development areas for coal-fired plants border
important aquatic resource areas (salmon in streams like the Copper and Susitna
Rivers and other marine fish and shellfish in Cook Inlet); plants located in
these areas would have to be designed to mitigate effects on these resources.
The greatest impact on the terrestrial biota is the loss or alteration of
habitat due to the large amounts of land required for both construction and
operation. These land requirements are generally greater than those for other
types of fossil-fueled power plants.
Other impacts to the terrestrial ecology could result from gaseous and
particulate air emissions, fuel or waste storage discharges, human disturbance,
and the power plant facilities themselves. Biological impacts are best
mitigated by siting plants away from important wildlife areas and by
implementing appropriate pollution control procedures. Although certain
impacts can be controlled, land losses are irreplaceable.
Air-Quality Regulations
In 1970 the federal Clean Air Act established the national strategy in
air pollution control. The Act established New Source Performance Standards
(NSPS) for new stationary sources, including fuel combustion facilities.
Levels of acceptable ambient air quality (National Ambient Air Quality
Standards) were also established, and the regulations were promulgated to
maintain these standards or to reduce pollution levels where the standards were
exceeded.
0.9
New source performance standards (NSPS) have been promulgated for coal-
fired steam-electric power plants and for combustion turbines. In addition,
any combustion facility designed to burn coal or coal mixtures is subject to
the coal-fired power plant standards.
Major changes were made to the Clean Air Act in 1977 when the Prevention
of Significant Deterioration (PSD) program was added by, Congress. The PSD
program has established limits of acceptable deterioration in existing ambient
air quality, so 2·and total suspend particulates (TSP) throughout the United
States. Pristine areas of national significance, called Class I areas, were
set aside with very small increments in allowable deterioration. The remainder
of the country was allowed a greater level of deterioration.
The PSD program, currently administered by the U.S. Environmental
Protection Agency (EPA), applies to so 2 and suspended particulates. In the
near future, PSD control over other major pollutants, including NOx, CO,
oxidants, and hydrocarbons may be promulgated. Obtaining a PSD permit
represents one of the largest single obstacles to constructing a major fuel-
burning facility.
Water Quality Effects
Hydroelectric Facilities. A hydroelectric facility can have several
hydroelectric impacts because of 1ts physical configuration and operation. The
most obvious impact is the creation of an impoundment. The change from a
flowing-water to a still-water environment is a fundamental modification of the
hydrologic system. Development of the reservoir also increases evaporation and
groundwater seepage. Both of these phenomena increase water losses to the
watershed. In the low-runoff regions of the Railbelt area, these losses, if
substantial, could incur significant impacts by reducing downstream flow,
especially during the summer months.
Important hydrologic impacts are also associated with operating a
hydroelectric plant. Large daily fluctuations in river flow can result when
hydropower is used for peaking power or when it closely follows load. If the
fluctuations are too large and rapid, adverse impacts to aquatic biota can
occur, and for the more accessible small river projects, they can be hazardous
to downstream recreationists. On a seasonal time scale, the reservoir level
D.lO
can vary greatly, again h,aving the potential for adverse impacts to aquatic
biota and for making the reservoir unattractive for recreation (especially when
the reservoir is low). The reservoir can be operated to have positive impacts
by attenuating flood flows and thereby helping to prevent flood damage to
property downstream. By augmenting low river flows, the reservoir can improve
water quality and aquatic habitat. Because many rivers in the Railbelt region
exhibit wide natural flow variations, attenuation can be a significant positive
impact.
Reservoir operation primarily impacts four parameters in terms of water
quality: temperature,_ dissolved oxygen (00), total dissolved gases, and
suspended sediment. Adverse impacts from temperature and 00 can occur during
the summer months when the reservoir is stratified. The large water surface
area of the reservoir allows the upper layer of water to be heated to
temperatures higher than those experienced in the natural free-flowing river.
If all water released from the reservoir is from the upper layer of water,
elevated river-water temperatures downstream can result, causing adverse
impacts on aquatic biota (especially cold water fish). If all water released
from the reservoir is from the lower layer of water, the 00 in the river will
be depressed until it can be replenished by natural reaeration. Intake
structures can be designed to take water from different levels in the reservoir
to help avoid some of these impacts.
If the water released from the reservoir goes over the spillway, gas
supersaturation sometimes occurs. Because of the turbulent nature of the water
as it falls over the spillway, atmospheric gases (nitrogen and oxygen) are
entrained. If these gases are carried to depth (e.g., in a deep plunge pool),
the gases are readily dissolved and the water becomes supersaturated relative
to surface conditions. This situation can result in injury or mortality to
aquatic organisms, particularly fish. The effects are most pronounced in
organisms that inhabit shallow areas or surface levels. Supersaturation can be
minimized by various spillway designs and operating measures.
As water flows into a reservoir, its velocity is reduced, and it deposits
much of its suspended sediment. Therefore, when the water is released from the
reservoir, it is relatively free of sediment load. A potential exists, then,
for this water to initiate scour downstream to re-establish equilibrium between
D.ll
the erosive energy of the flowing water and its sediment loads. Given that
many of the Railbelt rivers are glacier-fed with very high suspended sediment
loads, sediment deposition and downstream scouring will be important siting
considerations. Scour can also occur near the outlet works and spillway of the
hydropower plant if the water is discharged with a high velocity. The latter
scour problem can be mitigated by proper engineering design.
Hydroelectric projects alter the streamflow characteristics and water
quality of streams. These changes result in corresponding changes in the
aquatic biota. Although impacts occur on all levels of the food chain, the
impacts on fish are us_ually of most concern. Potential major effects in the
Railbelt that will be most difficult to mitigate include the following:
1. loss of spawning areas above and below the dam
2. loss of rearing habitat
3. reduced or limited upstream access to migrating fish
4. increased mortalities and altered timing of downstream migrating fish.
Construction activities can result in elevated stream turbidity levels and
gravel loss, and expanded public fishing in the area from increased access.
Other potentially significant impacts could include altered nutrient movement,
which could affect primary production; flow pattern changes, which can modify
species composition; and temperature regime alteration, which could affect the
timing of fish migration and spawning, and insect and fish emergence.
Competition and predation among and within species may also be changed.
Mitigative procedures are possible for many impacts and are frequently
incorporated into the design of the facility. Fish hatcheries are commonly
used to replace losses in spawning habitat. Screening or diversion structures
are used to direct fish away from critical areas. Depending on the height of
dam and the availability of spawning areas upstream of the created reservoir,
fish ladders are frequently incorporated into the design. Controlled release
of water (including both flow and temperature regulation by discharging from
various depths in the reservoir) can be used to improve environmental
conditions during spawning, rearing, and migration.
Steam-Electric"Plants. The construction and operation of steam-electric
plants have three potential areas of impacts on aquatic ecosystems: water
0.12
quality effects from construction stormwater runoff, water withdrawal for power
plant use, and process water discharge. The degree of each potential impact
depends on the plant•s size, location, and operating characteristics.
Construction area runoff can increase turbidity and siltation in receiving
waters adjacent to site construction. For inland waters where steam-cycle
facilities could potentially be sited, the main effect of this siltation could
be the destruction of these productive aquatic ecosystems. Spawning areas
could be eliminated by inundating gravel with fine sediment particles that
smother eggs or inhabit fry emergence (especially for salmonids); benthic
organisms could be smQthered and light penetration reduced, thereby inhibiting
the growth of aquatic plants. Salmon, trout, char, grayling, burbot, sheefish,
and whitefish species, which are common in many of the major rivers of the
Railbelt region, could be affected.
The impact from construction runoff depends on the efficiency of erosion
control measures and location of the site. Potential problems in both the
fresh and marine waters can be minimized or eliminated by implementing
appropriate site runoff and erosion control measures, such as runoff collection
systems, settling ponds, and other runoff treatment facilities.
Withdrawing water in significant amounts from inland streams can alter
flow patterns and reduce aquatic habitat downstream. These effects may be
partially offset by the amount of water discharged, if both the intake and
discharge are on the same body of water. The loss of habitat is highly
dependent on the size, type, and location of the steam plant.
Attraction of organisms to thermal discharges may interfere with normal
migration patterns. A particular concern is that marine organisms are
attracted and become acclimated to a heated discharge from a once-through
cooling·water system, which is then interrupted or stopped; the almost
instantaneous temperature change back to ambient levels can result in thermal
shock and subsequent mortalities to these organisms. Proper plant siting and
cooling system design could reduce or eliminate thermal impacts. With other
factors constant, the plant that uses the most water would have the greatest
impact.
0.13
The chemical composition of the intake water is altered during its passage
through the steam plant. Changes in the composition generally depend on the
specific steam cycle and its capacity, but chemical additions include the
following:
1. chemicals, such as chlorine, added to control biological fouling and
deposit of materials on cooling system components
2. constituents of the intake water concentrated during recirculation
through evaporative cooling systems
3. corrosion products from structural components of the cooling system.
Other potential pollutants from steam cycles include low pH, high metal
concentrations, biochemical oxygen demand, radionuclides, and petroleum
products. When discharged in sufficent quantity, these can cause immediate
impacts such as death of organisms or long-term changes in the aquatic
ecosystem. Of particular concern would be the effects on the commercial and
recreationally important fish and shellfish species that reside in both the
fresh and marine systems of the Railbelt region.
Some effluents, like heavy metals and radionuclides, could have negative
effects far from the site of their initial discharge, whereas others like low
pH and biological oxygen demand (BOD) will have the most impact close to the
discharge. Some of these effluents would have less impact on marine systems
than on fresh water systems. Total dissolved solids (TDS) can be especially
high in geothermal plants. High TDS would have little effect on the marine
environment because TDS is already much higher in seawater than in fresh
water.
systems.
Low pH discharges would be more easily neutralized in the marine
Most other discharges could have negative effects on both fresh water
and marine systems, but the marine environment's much larger area for dilution
more easily reduces impacts.
Ecological Effects
Steam-electric and hydroelectric energy projects require large amounts of
land. The amount of land required varies with the energy-producing capacity of
a plant. Because hydroelectric plant requirements generally exceed those of
other energy types, an important impact is the inundation of large areas of
wildlife habitat.
D. 14
Impacts from hydroelectric energy projects result not only from inundation
of land but also from the operation of the dam and the dam itself. Inundation
of flood plains, marshes, and other important wildlife habitat can negatively
affect big game animals, aquatic furbearers, waterfowl, shorebirds, and
raptors·. Big game animals can be impacted by loss of seasonal ranges and
interruption of migratory routes. Winter ranges in particular are critical
habitats for migratory big game animals. The flood control provided by dams
may significantly reduce the extent of wetland habitats resulting from the
elimination of seasonal inundation of large areas downstream of dam sites.
This factor may signi~icantly impact moose and other wetland species. Aquatic
furbearers can be adversely affected by the loss of habitats. Correspondingly,
waterfowl and shorebird nesting, loafing, and feeding areas can be eliminated
by the flooding of these habitats. The re-establishment of high-quality
habitats is generally prevented by the constantly fluctuating water levels
of plant operation. Fluctuating water levels can also destroy trees and other
natural structures used by birds for perching, nesting, and roosting sites.
Birds and bears can further be impacted by the loss of fish if fish passage is
prevented or reduced by the dam.
Steam-electric and hydroelectric projects located in remote areas cause
other impacts. Access roads to remote locations cause extensive disturbance to
wildlife. Not only will habitat be replaced by roads, but isolated wildlife
populations will be adversely affected by increased human activity and
numbers. These impacts could result in disturbance of wilderness species like
grizzly bears. Also, other wildlife could be impacted from increased hunting
pressure, poaching, and road kills. The magnitude of these and other potential
• impacts will depend on the wildlife population densities at each specific site.
Mitigative measures could be taken to relieve some wildlife impacts
·resulting from dam developments. The habitats flooded by a reservoir would be
largely irreplaceable. However, other habitats, such as islands used by
waterfowl for nesting, could be created by placing spoils or channels in the
affected area. Trees and other natural features used by raptors could be
retained instead of removed as is usually done prior to inundation. Whereas
these relief measures are somewhat specific, wildlife impacts, in general, can
0.15
be minimized by selecting only those sites where wildlife disturbances would be
the least.
0.1.4 Socioeconomic Considerations of Plan lA
This section covers the general socioeconomic concerns of Plan 1A.
Combustion Turbines. Because of the relatively small workforce and
acreage requirements for combustion turbine development, impacts can be
expected to vary more with location than with plant scale. The absence of
major siting constraints allows flexibility in locating a combustion-turbine
facility. Construction of a 170-MW plant would require 30 persons for a period
of 9 months. To minimize impacts, combustion turbines should not be sited in
very small towns, although installing a construction workcamp would lessen the
demand for housing and public services. Primary plant sites would be
Anchorage, Soldatna, and Fairbanks. Secondary sites would include Kenai,
Seward, Wasilla, Palmer, and North Pole.
Since a combustion turbine is a capital-intensive facility, 20% of the
project expenditures would be invested within Alaska, while 80% would be spent
outside Alaska.
Combined Cycle. Construction of a 200-MW combined-cycle plant requires
45 persons for a period of 2 years. The operating and maintenance requirements
would be approximately 15 persons. Since the construction work force is
relatively small, impacts should vary more with site location than with plant
capacity. Severe construction-related impacts could occur in very small
communities along the distribution pipeline or railroad where the
infrastructure is insufficient to meet new demands. These impacts can be
lessened by siting a combined-cycle plant in a community with a population
greater than 500. Primary sites would include Anchorage, Fairbanks, and
Soldatna. Secondary locations adjacent to the railroad or major highway
corridor include Kenai, Seward, Wasilla, Palmer, and North Pole.
Since combined cycle is a capital-intensive technology, the largest
portion of expenditures outside the region would be attributed to equipment.
Approximately 70% of the project expenditures would ·be spent in the lower 48
states, while 30% would be spent within the Railbelt.
0.16
Steam Electric. The construction and operation of a coal-fired plant
has the potential to seriously affect smaller communities and cause a boom/bust
cycle. These effects are due to the remoteness of prospective sites. The
magnitude of these impacts is a function of plant scale. A major contributing
factor to this relationship is the variation in size of the construction work
force with plant size. Construction times, exclusive of licensing and
permitting, will vary according to the size, type of equipment, and external
factors such as weather and labor force. Construction schedules for coal-fired
plants in the Railbelt will vary depending upon whether the boiler is field-
erected. A 200-MW plant requires 3 to 5 years to construct.
Impacts would be most severe at the Beluga coal fields since the
surrounding communities are small and transportation facilities are poorly
developed. Power plant components would most likely be shipped by barge and
then transported overland to the site. Secondary impacts would be caused by
the construction of haul roads. The largest community in the area is Tyonek,
an Alaskan native village with a population of 239. The influx of a
construction work force would disrupt the social structure of a community of
this size. The construction of a work camp would not substantially reduce
these impacts.
Impacts from developing a plant along the railroad corridor would depend
on a plant scale. Exi'sting communities may be able to accommodate the
requirements for constructing a 10-to 30-MW plant, but would be severely
affected by a large-scale plant.
The flow of capital expenditures both outside and within Alaska is
expected to balance for a 200-MW coal-fired steam~electric plant. The flow of
operating and maintenance expenditures is expected to be 10% spent outside the
region and the balance spent in the region.
Hydroelectric~ The construction and operation of a large hydroelectric
plant has a high potential to cause a boom/bust cycle, but a small-scale
project will have a minor to moderate impact on community infrastructure. The
primary reason large projects will create adverse effects is the remoteness of
the sites. The sites are located at or near communities with a population of
less than 500. An in-migration of 250 to 1,000 workers, depending on the scale
of plant in the range of 100 to 1,000 MW, would be necessary for construction.
D. 17
In these remote communities, the population could more than quadruple. The
installation of a construction camp would not reduce the impacts on the social
and economic structure of a community.
A small-scale hydro project may be compatible with remote communities.
For example, a 2.5-MW project would require a construction workforce of 25.
The length of construction time would be 2 years in comparison to 5 to 10 years
for completion of a large-scale project.
The expenditures that flow out of the region account for investment in
equipment and supervisory personnel. For a large-scale project, a larger
proportion of the expenditures is attributed to civil costs. Approximately 35%
of an investment in a large project would be made outside the region, whereas
65% would be made within the Railbelt. Sixty-five percent of the investment in
a small-scale hydro project would be made in the lower 48 states, whereas 35%
would be contained within the Railbelt. The breakdown of operating and
maintenance expenditures for a hydroelectric project would be N11% spent
outside the Railbelt and N89% spent within the region.
0.1.5 Integration of Potential Impacts
The overall environmental and socioeconomic impacts of Plan lA are
presented in Table 0.3. The impacts mainly are minor to moderate. However,
the following points represent prominent concerns:
1. air-quality impacts of coal-fired units
2. boom-bust impacts of coal and hydroelectric projects
3. water-quality and ecological impacts of construction and operation.
Air-Quality Impacts of Coal-Fired Units
The increased use of coal-fired steam turbines will require large amounts
of land. The major facilities that will alter the landscape include
smokestacks, cooling towers, coal stockpiles, the boiler plant, and the ash
ponds. Of course, the smokestack and cooling tower plumes will be highly
visible, especially in the winter months. The combustion emissions will
contribute to decreased visibility. Also, locating the fossil fuel power
plants such that their plumes do not violate the PSO air quality regulations
may be a problem.
0.18
TABLE 0.3. Integration of Potential Environmental & Socioeconomic
Impacts for Plan lA
Potential Environmental and Socioeconomic lmQacts
Suscepti-
Energy Terres-Aquatic/ Noise, Health Boom/ Land-bility Spending
Facilities Air Water trial Marine Visual and Jobs in Bust Use to in Alaska
Added gual it~ gualit~ Ecolog~ Ecolog~ & Odor Safety Alaska Effects Effects Inflation (% Total)
Anchorage-
Cook Inlet
Gas Turbine
Combustion 2 1 1 1 2 1 1 1 ' 2 3 20
Combined
Cycle 2 2 2 2 2 1 2 2 3 3 30
Coal-Fired
Steam Turbine 3 2 2 2 3 2 2 2 3 3 40
Fairbanks-
0
Tanana Valley
__. Coal-Fired
1.0 Steam Turbine 3 2 2 2 3 2 3 2 3 3 40
Gas Turbine
Combustion 2 1 1 1 2 1 1 1 2 3 20
H~droelectric
Bradley Lake 1 2 2 2 2 1 3 3 3 1 65
Chakachamna 1 2 2 2 2 1 3 3 3 1 65
A 11 i son 1 2 2 2 1 1 2 2 2 1 35
Grant Lake 1 2 2 2 1 1 2 2 2 1 35
Rating Scale: 1 -minor
2 -moderate
3 -significant
Two permanent Class I (Pristine Air) areas, Denali National Park and the
pre-1980 areas of the Tuxedni Wildlife Refuge, are in or near the Railbelt
region. The new National Parks and Wildlife Preserves have not been included
in the original designation, but the state may designate additional Class I
areas in the future. New major facilities located near Class I areas must not
cause a violation of the PSD increment. This requirement presents a
significant constraint to developing nearby facilities.
A potentially important aspect of the PSD program to developing electric
power generation in the Railbelt region is that Denali National Park (Mt.
McKinley National Par~ prior to passage of the 1980 Alaska Lands Act) is Class
I, and it lies close to Alaska's only operating coal mine and the existing coal-
fired electric generating unit (25 MWe) at Healy. Although the PSD program
does not affect existing units, an expanded coal-burning facility.at Healy
would have to comply with Class I PSD increment for so 2 and suspended
particulates. Bec·ause of this regulation, any coal plants in the Fairbanks-
Tanana Valley are assumed to be located in the Nenana area. Decisions to
permit increased air pollution near Class I areas can only be made after
careful evaluation of all the consequences of such a decision. Furthermore~
Congress required that Class I areas must be protected from impairment of
visibility resulting from man-made air pollution. The impact of visibility
requirements on Class I areas is not yet fully known.
Based on information on emissions and regulations, several general
conclusions can be drawn that bear on the siting of major fuel-burning
facilities. First, these facilities should be located well away from Class I
areas. A minimum distance would probably be 20 miles, but each case should be
carefully analyzed to reliably choose a site. The forthcoming visibility
regulations may require a greater distance. Also, because of regulatory
constraints, any of these facilities should be located well away from the non-
attainment areas surrounding Anchorage and Fairbanks. In addition, the major
fuel-burning facilities should be located away from large hills and outside of
narrow valleys or other topographically enclosed areas. Facilities should be
developed in open, well-ventilated sites in which atmospheric dispersion
conditions will contribute to minimizing impacts on air quality.
D.20
Many acceptable sites should exist for coal-fired power plants in the
Beluga, Kenai, Susitna, arid Nenana areas and near the available coal fields.
Since Alaska coal is generally low in sulfur content, the siting constraints
will be less stringent than those normally encountered in the eastern United
States. Generally, emissions from natural gas combustion are of less
significance, and the siting of such facilities is therefore less critical.
For this study, the coal plants in Anchorage-Cook are assigned to be in Beluga
and near Nenana in the Fairbanks-Tanana Valley.
An initial assessment indicates that Alaskan lakes are not so sensitive
to acid rain as lakes in eastern Canada and the northeastern United States.
Furthermore, the total emissions into the Alaskan environment are.much less
than emissions from industrialized areas of the midwest and northeastern United
States. In Alaska acid rainfall most likely never will present problems
similar to those in the eastern portion of the continent. Currently no basis
exists for assessing the impacts of acid rainfall that might develop because of
increased fuel combustion in Alaska.
Boom/Bust Impacts of Coal and Hydroelectric Projects
The construction activities for the larger coal-fired steam-turbine units
and the Bradley Lake and Chakachamna hydroelectric facilities will require
substantial labor forces. For the more remote areas, the population could
quadruple. In these situations, installing a construction camp would not
reduce the impacts on the social and economic structure of the community.
Water-Quality and Ecological Impacts of Construction and Operation
Both the coal-fired steam turbine units and the hydroelectric facilities
will significantly alter water quality and the surrounding habitat for
wildlife. For example, the configuration of the Chakachamna hydroelectric
project will have some significant, irreversible impacts on the local water
resources. Creation of the power tunnel, together with the concrete overflow
structure, will greatly reduce flows in the Chakachatna River. In addition,
the lake will be subject to significant fluctuations in elevation, perhaps as
much as 180 feet. The McArthur River will experience an increase in flow,
corresponding roughly to the loss in the Chakachatna River. Should the water
qualities of the ~ake and McArthur River differ significantly, the river will
0.21
experience a change in water quality as well. Parameters most likely to
experience a change include temperature, dissolved oxygen, total dissolved
gases, and suspended sediment.
During the design phase, actions can be taken to· reduce the impacts on
fish and wildlife. For example, a prime alternative for the Chakachatna
project provides for flow from the lake into the Chakachamna River to maintain
minimum flow requirements. This trade-off means a reduction in capacity from
400 MW to 330 MW and a 16% increase in the subsequent cost of power. But even
with this increase, the cost of power is significantly less than the most
competitive coal-fire~ power plant.
Potential aquatic ecological impacts of hydropower project construction on
Chakachamna Lake center on la~e level fluctuations as a result of reservoir
drawdown (exposure of fish spawn and elimination of spawning habitat) and
possible entrainment and impingement problems (fish eggs, larvae, and food
organisms) associated with diversion of lakewater through the generators.
Potential aquatic ecological impacts to the lake inlet streams may result from
decreased lake access due to reservoir drawdown during certain periods of the
year.
The primary inlet to the lake, the Chilligan River, serves as a spawning
area for red (sockeye) salmon. Known spawning areas for Chinook (King) and
pink (humpback) salmon exist in the lower tributaries of the Chakachatna (lake
outlet) and McArthur Rivers.· The McArthur River will receive the tailrace
flows from the project. The annual adult escapement for these species is
unknown, as is their contribution to the Cook Inlet runs. Lake trout are
resident within Lake Chakachamna; Dolly Vard@n (Arctic char), whitefish, and
rainbow trout are present in the lower tributaries of the Chakachatna and
McArthur Rivers. Nonsalmonid fish species that probably are found within
project area waters include sculpins, blackfish, and northern pike. Most
likely all of the above species will be disturbed because of the project.
Aqu·atic impacts on the Chakachatna and McArthur Rivers will be the most
severe due to potential changes in existing flow regimes. For example, the
design will essentially dewater the upper Chakachatna River and divert the lake
outflow via a tunnel to the McArthur River. This scenario will most likely
eliminate fish access to the upper Chakachatna River and Chakachamna Lake and
D.22
will alter the existing flow regimes and chemical makeup of the McArthur River,
thus potentially altering fish production in that river as well.
The primary potential wildlife impacts of hydroelectric development in the
project area will be from river level fluctuations and habitat loss. River
level fluctuation may change the character of the riverine vegetation, which is
used by moose in the winter, and marshes, which are used by waterfowl during
the spring, summer, and fall. Changes in the river level may also affect the
fish populations used by brown and black bear and habitat used by beaver.
Unexpected drawdown will expose beaver-inhabited lodges to predation.
The hydroelectric facilities and access roads will eliminate some wildlife
habitat and open up the project area to increased hunting pressure. Whereas
increased hunting is detrimental to some populations, it is beneficial to
others and provides additional hunting opportunity to Alaskans. Increased
access and the associated use by people will also create more poaching and
human/bear conflicts. The Chakachamna project will impact wildlife in two
river drainages. However, wildlife impacts resulting from alteration of Lake
Chakachamna are expected to be small.
0.2 PLAN 18: 11 PRESENT PRACTICES 11 WITH UPPER SUSITNA
This plan is based upon a continuation of present generating technologies
with a transition to Upper Susitna hydropower as required. Any additional
capacity required is to be supplied by conventional coal-steam turbine or
combined-cycle facilities.
Hydroelectric plants include the following:
1 The Lake project which comes on-line in 1988
1 The Upper Susitna Project: Watana (680 MW) which comes on-line in 1993;
Devil Canyon (600 MW) which comes on-line in 2002.
Other generating capacity includes the following:
Anchorage-Cook Inlet
1 If required by load growth, combustion turbine and combined capacity
is added to fill in until Upper Susitna is available.
0.23
• If required by load growth, coal-steam turbine units are added after
the Upper Susitna project is completed.
Fairbanks-Tanana Valley-
• If necessary, combustion turbine and combined cycle capacity is added
to fill in until the Upper Susitna project is available.
• If necessary, coal-steam turbine units are added after the Upper
Susitna project is completed.
D.2.1 CapacitY and Generation for Plan 18
As shown in Tabl~ D.4, almost all the additional capacity added in this
plan is the first stage of Watana (680 MW) and Devil Canyon (600 MW) dams of
the Upper Susitna project. The Watana dam comes on-line in 1993 and the Devil
Canyon dam comes on-line in 2002. The only other capacity added is 70 MW of
gas combustion turbine capacity and 200 MW of gas combined-cycle capacity
brought on-line in 1990 and 1991, respectively, in the Anchorage area.
As shown in Table D.5, during the 1981-1992 time period, electrical
generation in Anchorage is largely by gas combustion turbines and combined-
cycle capacity, with some hydroelectr1c generation. In Fairbanks, oil
combustion turbines and diesel capacity are used until 1990-91, whereas coal
steam turbine continues to be used to a significant amount until 2002 when the
Devil Canyon dam comes on-line. From 2002 until 2010 the majority of
electrical generation in the Railbelt is supplied by hydroelectric power,
largely from the Upper Susitna project.
D.2.2 Environmental Constderations of Plan 1B
The principle environmental considerations for this plan are associated
with the development of the Upper Susitna River, with dams at Watana and Devil
Canyon. In this section, descriptions of ambient biological and vegetation
conditions are presented.
Fisheries. The Susitna 'Basin is inhabited by resident and anadromous
fish. The anadromous group includes five species of Pacific salmon: sockeye
(red), coho (silver), chinook (king), pink (humpback), and chum (dog) salmon.
Dolly Varden are also present in the lower Susitna Basin with both resident and
D.24
TABLE 0.4. Existing Capacity (1980) and Capacity Additions and Retirements
(MW) (1981-2010) -Plan 18
Anchorage-Cook Inlet Fairbanks-Tanana Valle~
Oil
Gas Gas Combustion Coal
Combustion Combined-Turbine & Steam
Year Turbine Cycle Diesel Turbine Hldroelectric
1980 461 139 266 69 46 (Eklutna & Cooper Lake)
1981 0 0 0 0 12 (Solomon Gulch)
1982 -20 178 0 0 0
1983 0 0 -8 0 0
1984 0 0 0 0 0
1985 0 0 0 0 0
1986 0 0 -1 0 0
1987 0 0 -8 -4 0
1988 0 0 -6 0 90 (Bradley Lake)
1989 0 0 0 -5 0
1990 70 0 0 0 0
0 1991 0 200 -18 0 0
1'\) 1992 -16 0 -19 0 0
c.n 1993 -9 0 0 0 680 (Watana)
1994 -30 0 0 0 0
1995 -14 0 -33 0 7 (Grant lake)
1996 0 0 -102 0 0
1997 0 0 -65 0 0
1998 -50 0 0 0 0
1999 0 0 0 0 0
2000 -18 0 0 0 0
2001 0 0 0 0 0
2002 -51 0 0 -25 600 (Devil Canyon)
2003 -53 0 0 0 0
2004 0 0 0 0 0
2005 -58 0 0 -21 0
2006 0 0 0 0 0
2007 0 0 0 0 0
2008 -26 0 0 0 0
2009 0 0 0 0 0
2010 0 0 0 0 0
TABLE 0.5. Electrical Generation by Type of Capacity -Plan 1B (GWh)
Anchorage-Cook Inlet Fairbanks-Tanana Vallel
Oil
Gas Gas Combustion Coal
Combustion Combined Turbine & Steam
Year Turbine Cycle Diesel Turbine !!.Y.droe 1 ectri c_ ---
1981 2021 46 26 537 254
1982 773 1389 64 537 254
1983 851 1403 102 537 254
1984 958 1389 140 537 254
1985 425 2275 0 455 254
1986 1403 1482 20 537 254
1987 1528 1541 123 537 254
1988 1391 1470 226 537 648
1989 1529 1515 370 496 648
1990 1234 2494 2 468 648
1991 1945 1855 0 496 648 0 1992 1969 1928 1 496 648 .
N 1993· 1 1022 0 11 4103 m
1994 2 1110 0 19 4103
1995 0 733 0 496 4103
1996 0 688 0 496 4103
1997 0 643 0 496 4103
1998 0 597 0 496 4103
1999 0 553 0 496 4103
2000 0 508 0 496 4103
2001 0 626 0 496 4103
2002 0 0 0 0 5349
2003 0 0 0 23 5436
2004 0 0 0 0 5611
2005 0 0 0 0 5698
2006 0 0 0 1 5961
2007 0 0 0 5 6224
2008 0 0 0 9 6487
2009 0 0 0 14 6750
2010 0 0 0 18 7013
anadromous populations. Anadromous smelt are known to run up the Susitna River
as far as the Deshka River about 40 miles from Cook Inlet.
Salmon are known to migrate up the Susitna River to spawn in tributary
streams. Surveys to date indicate that salmon are unable to migrate through
Devil Canyon into the Upper Susitna River Basin. To varying degrees spawning
is also known to occur in freshwater sloughs and side channels. Principal
resident fish in the basin include grayling, rainbow trout, lake trout,
whitefish, sucker, sculpin, burbot and Dolly Varden.
Because the Susitna is a glacially fed stream, the waters are silt laden
during the summer months. This condition tends to restrict sport fishing to
clear water tributaries and to areas in the Susitna near the mouth of these
tributaries.
In the Upper Susitna Basin grayling populations occur at the mouths and in
the upper sections of clear water tributaries. Between Devil Canyon and the
Oshetna Rivers most tributaries are too steep to support significant fish
populations. Many terrace and upland lakes in the area support lake trout and
grayling populations.
Big Game. The project area is known to support species of caribou,
moose, bear, wolves, wolverine and Dall sheep.
The Nelchina caribou herd, which occupies a range of ~20,000 square miles
in southcentral Alaska, has been important to hunters because of its size and
proximity to population centers. The herd has been studied continuously since
1948. The population declined from a high of ~71,000 in 1962 to a low of
between 6,500 and 8,100 animals in 1972. From October 1980 estimates, the
Nelchina caribou herd contained ~18,500 animals.
The proposed impoundments would inundate a very small portion of apparent
low-quality caribou habitat. Concern has been expressed that the impoundments
and associated development might serve as barriers to caribou movement,
increase mortality, decrease use of nearby areas and tend to isolate subherds.
Moose are distributed throughout the Upper Susitna Basin. Studies to date
suggest that the areas to be inundated are used by moose primarily during the
winter and spring. The loss of their habitat could reduce the moose population
for the area. The areas do not appear to be important for calving or breeding
D.27
purposes; however, they do provide a winter range that could be critical during
severe winters. In addition to direct losses, displaced moose could create a
lower capacity for the animals in surrounding areas.
Black and brown bear populations near the proposed reservoirs appear to be
healthy and productive. Brown bears occur throughout the study area, whereas
black bears appear largely confined to a finger of forested habitat along the
Stisitna River.
The proposed impoundments are likely to have little impact on the
availability of adequate brown bear den sites; however, the extent and utility
of habitats used in the spring following emergence from the dens may be
reduced. Approximately 70 brown bears inhabit the 3,500-square-mile study
area.
Black bear distribution appears to be largely confined to or near the
forests found'near the Susitna River and the major tributaries. The forest
habitat appears to be used the most in the early spring. In late summer black
bears tend to move into the more open shrublands adjacent to the spruce forest
because of the greater prevalence of berries in these areas.
Five known and four to five suspected wolf packs have been identified in
the Upper Susitna Basin. Project impacts on wolves could occur indirectly due
to reduction in prey density, particularly moose. Temporary increases could
occur in the project area due to displacement of prey from the impoundment
areas. Direct inundation of den and rendezvous sites may decrease wolf
densities. Potential increased hunting and trapping pressure could also
increase wolf mortality.
Wolverines are found throughout the study area, although they show a
preference towards upland shrub habitats on southerly and westerly slopes.
Potential impacts would relate to direct loss of habitat, construction
disturbance and increased competition for prey.
Dall sheep are known to occupy all portions of the Upper Susitna River
Basin, which contains extensive areas of habitat above the 4,000 foot
elevation. Three such areas near the project area include the Portage-Tusena
Creek drainages, the Watana Creek Hills and Mount Watana. Since Dall sheep are
0.28
usually found at elevations above 3,000 feet, impacts will likely be restricted
to potential indirect disturbance from construction activities and access.
·Furbearers. Furbearers in the Upper Susitna Bas·in include red fox,
coyote, lynx, mink, pine marten, river otter, short-tailed weasel, least
weasel, muskrat and beaver. Direct inundation, construction activities and
access can be expected generally to have minimal impact on these species.
Birds and Nongame Mammals. One hundred and fifteen species of birds
were recorded in" the study area during the 1980 field season. The most
abundant species were Scaup and Common Redpoll. Ten active raptor/raven nests
have been recorded anfr of these, two Bald Eagle nests and at least four Golden
Eagle nests would be flooded by the proposed reservoirs, as would about three
currently inactive raptor/raven nest sites. Preliminary observations indicate
a low population of waterbirds on the lakes in the region; however, Trumpeter
Swans nest on several lakes between the Oshetna and Tyone Rivers.
Flooding would destroy a large percentage of the riparian cliff habitat
and forest habitats upriver of Devil Canyon dam. Raptors and ravens using the
cliffs could be expected to find alternative nesting sites in the surrounding
mountains, and the forest inhabitants are relatively common breeders in forests
in adjacent regions. Lesser amounts of lowland meadows and fluvial shorelines
and alluvia, each important to a few species, will also be lost. None of the
water bodies that appear to be important to waterfowl will be flooded, nor will
the important prey species of the upland tundra areas be affected. Impacts of
other types of habitat alteration will depend on the type of alteration.
Potential impacts can be lessened by avoiding sensitive areas for construction
sites.
In the project area, thirteen small mammal species were found during 1980,
and the presence of three others was suspected. During the fall survey, red-
backed voles and masked shrews were the most abundant species trapped, and
these, plus the dusky shrew, appeared to be habitat generalists, occupying a
wide range of vegetation types. Meadow voles and pygmy shrews were least
abundant and the most restricted in their habitat use; the former were found
only in meadows and the latter in forests.
D.29
Vegetation. The Susitna River drains parts of the Alaska Range on the
north and parts of the Talkeetna Mountains on the south. Many areas along the
east-west portion of the river, between the confluences of Portage Creek and
the Oshetna River, are steep and covered with conifer., deciduous and mixed
conifer, and deciduous forests. Flat benches occur at the tops of these banks
and usually contain low shrub or woodland conifer communities. Low mountains
rise from these benches and contain sedge-grass tundra and mat and cushion
tundra.
The Devil Canyon and Watana reservoirs will inundate a total of 44,729
acres of vegetation. Jhe access road or railroad will destroy an additional
371 to 741 acres of vegetation, which is roughly equal to 0.02% of the
vegetation in the entire basin. The primary vegetation types to be affected
are mat and cushion tundra, sedge-grass tundra, birch shrubland· and woodland
spruce.
Land Use. Existing land use in the Susitna area is characterized by
broad expanses of open wilderness areas. Those areas where development has
occurred often include small clusters of several cabins or other residences.
Many single-cabin settlements are located throughout the basin. Most of the
existing structures are related to historical development of the area,
initially involving hunting, mining, and trapping and later guiding activities
associated with hunting and to a lesser extent fishing. Today a few lodges can
be found, mostly used by hunters and other recreationalists. Many lakes in
the area also included small clusters of private year-round or recreational
cabins.
Perhaps the most significant use activity for the past 40 years has been
the study of the Susitna River for potential hydro development. Hunting,
boating, and other forms of recreation are also important uses. Numerous
trails throughout the basin are used by dog sled, snowmobile and all-terrain
vehicles. Air use is significant for many lakes, providing landing areas for
planes on floats.
D.2.3 Socioeconomic Considerattons of Plan 18
The construction and operation of the Watana and Devil Canyon dams have
the potential for both positive and adverse socioeconomic effects. The
0.30
positive effects will be employment opportunities and revenues that will be
generated by the project and which will stimulate growth of the local economy
in the short term and, in the long term, will contribute to the expansion of
the regional economy. The adverse effect is the in-migration of temporary
workers to a community, potentially causing a boom/bust cycle.
The primary effect of a boom/bust cycle is a temporarily expanded
population with insufficient infrastructure to support the new demands. The in-
migration of workers to a community will have an impact on land availability,
housing supply, commercial establishments, electric energy availability, roads,
public services such as schools, hospitals, and police force, and public
facilities such as water supply and domestic waste treatment facilities. The
magnitude of these impacts will depend on the population of the area, the size
of the construction work force, and the duration of the construction period.
The bust occurs with the out-migration of a large construction work force,
which leaves the community with abandoned housing and facilities.
The magnitude of the boom/bust cycle is determined by the duration of the
construction and the relative size of the work force to the community. A
construction force of a thousand or more workers will be required for a period
of 5 to 10 years for the Upper Susitna project. Yet, as revealed by the 1981
Census, only 18,000 people or 6% of the State's population lives in the
Matanuska-Susitna Burough where the project is located. This area is already
experiencing rapid growth because its southern part is influenced by the
Anchorage labor market. The 1970 population of the Matanuska-Susitna Burough
was 6,500. Smaller cities along the Railbelt, especially Talkeetna, would be
directly impacted by the Upper Susitna project, whereas Fairbanks and Anchorage
would be less affected due to their size and distance from the project area.
While much of the work force may be drawn from the Fairbanks and Anchorage
labor market areas, they most likely will not be commuting the distance
involved. Installing a construction camp would not substantially reduce the
social and economic impacts in the community.
The secondary effect of the construction may be the growth of the local
and regional economies. _The increase in the number of permanent residents will
cause the introduction of new businesses and jobs to the community. This
effect may be perceived as either positive or negative, depending on individual
D. 31
points of view. The expenditures on capital and labor during both the
construction and operation phases will increase regional income as well as
local income. Increased regional income would be caused by the expansion of
construction firms and related industries. A parameter of expansion of the
regional economy is flow of expenditures within the region and can be measured
in terms of percentage.
The expenditures that flow out of the region account for investment in
equipment and supervisory personnel. For a large-scale project, such as the
Upper Susitna, a larger proportion of the expenditures is attributed to civil
costs. Approximately 35% of an investment in a large project would be made
outside the region, while 65% would be made within the Railbelt. The breakdown
of operating and maintenance expenditures for the project would be N11% spent
outside the Railbelt and N89% spent within the region.
0.2.4 Integration of Potential Environmental and Socioeconomic Impacts for
Plan 18
The integration of potential environmental and socioeconomic impacts are
presented in Table 0.6. The impacts are directly related to nature of this
plan; that is, future demands for electricity are largely met by developing the
Upper Susitna project, and thereby precluding the use of other alternatives
such as coal-fired steam-turbine power plants. In this plan, concerns related
to air pollution are almost nonexistent because all existing oil combustion
turbines, diesels and coal steam turbine units in Fairbanks are phased out. In
Anchorage, a substantial amount of the existing gas combustion turbine capacity
is phased out and only 70 -MW of new capacity is added; however, about 400 MW of
gas combined-cycle capacity is added. Even with this, in 2010 the amount of
electricity derived from fossil-fuel resources would be less than it is today.
The principle integrated impacts of this plan are, therefore, related to the
construction and operation of Bradley Lake, Watana and Devil Canyon
hydroelectric projects. Therefore, the main concerns are 1) changes in water
quality and subsequent impact on fisheries, 2) loss of habitat area for
animals, and 3) the boom/bust impacts of construc~ion.
0.32
TABLE 0.6. Integration of Potential Environmental & Socioeconomic
Impacts for Plan lB
Potential Environmental and Socioeconomic Im~acts
Suscepti-
Energy Terres-Aquatic/ Noise, Health Boom/ Land-bility Spending
Facilities Air Water trial Marine Visual and Jobs in Bust Use to in Alaska
·Added gualit~ gual itl Ecologl Ecoiog~ & Odor Safetl Alaska Effects Effects Inflation (% Total}
Anchorage-
Cook Inlet
Gas Turbine
Combustion 2 1 1 1 2 1 1 1 1 3 20
Gas ·combined
Cycle 2 1 2 2 2 1 2 1 2 3 30
H>::droelectric
Grant Lake 1 2 2 2 1 1 2 2 2 1 35
0 Bradley Lake 1 2 2 2 1 1 3 3 3 1 65
w w Watana 1 2 2 2 1 1 3 3 3 1 65
Dev i 1 Canyon 1 2 2 2 1 1 3 3 3 1 65
Rating Scale: 1 -minor
2 -moderate
3 -significant
0.3 PLAN 2A: HIGH CONSERVATION AND RENEWABLE$ WITHOUT UPPER SUSITNA
Plan 2A emphasizes the use of conservation to reduce electrical energy
demand, as well
fuel and wind.
center and they
as the use of renewable energy sources such as refuse-derived
Increasing levels of conservation are included for each load
are assumed to be encouraged through state grant programs.
Under this plan, conservation and alternatives relying on renewable
resources, excluding the Upper Susitna project, will be developed to the
maximum extent feasible. Additional capacity required will be provided by
conventional generating alternatives as in Plan 1A.
Hydroelectric plants include the following:
• the Bradley Lake project, which comes on-line in 1988
• the Allison project, which comes on-line in 1991
• the Chakachamna and Grant Lake projects, which come on-line in 1995
• the Keetna hydroelectric project, which comes on-line in 2008
• the Browne hydroelectric project, which comes on-line in 1995.
Other generating capacity includes the following:
Anchorage-Cook Inlet
• A 50-MW refuse-derived fuel plant is added in 1993.
• Additional generation is supplied by natural gas combined-cycle and
combustion turbine.
• A state grant program to encourage the installation of conservation
alternatives (passive solar space heating, active solar water heating,
wood space heating, and building conservation) exists for 1981 onward.
Fairbanks-Tanana Valley
• A 100 MW of large wind turbine generation is added in the Isabell Pass
area.
• A 20-MW refuse-derived fuel plant is added in 1994.
• A state grant program to encourage the installation of conservation
alternatives exists.
0.34
0.3.1 Capacity and Generation for Plan 2A
As shown in Table 0.7, this plan is highly reliant on hydroelectric-and
other renewable generating resources. The amount of reduction in the peak load
due to a conservation grant program is shown in the last column. As shown, the
reduction varies between 40 MW and 60 MW, depending upon the year.
The electrical production for each of the generating capacities in the plan
is shown in Table 0.8.
7.4.2 Environmental Considerations of Plan 2A
Technologies used in this plan and not included in earlier plans are
refuse-derived fuel and wind turbine generators. In addition, Allison, Brown
and Snow and hydroelectric projects are used, as well as several energy
conservation methods.
Refuse-Derived Fuel
Refuse-fuel plants are distinct from fossil fuel-fired units in that
maximum plant capacities are achieved at much lower power ratings in refuse-
fuel plants. Also, refuse-fuel plants have specialized fuel handling
requirements. The generally accepted limits for refuse-fired power plants are
~s to 60 MW. The moisture content of the fuel, as well as the scale of
operation, introduces thermal inefficiencies into the power plant system. In
both Anchorage's and Fairbanks• refuse-derived fuel plants, supplemental firing
with coal is required to compensate for seasonal fluctuations in refuse
availability.
Siting and Fuel Requirements. Siting requirements are dictated by the
condition of the fuel, location of the fuel source, and the cycle employed.
Because the fuel is high in moisture content and low in bulk density,
economical transport distances do not exceed 50 miles. The power plants are
thus typically sited at, or near the fuel source. Sites must be accessible to
all-weather highways since biomass fuels are usually transported by truck.
Approximately 4 trucks per hour would be required for a 50-MW plant.
While proximity to the fuel source may be considered most limiting, sites
also must be accessible to water for process and cooling purposes. Land area
requirements are a function of scale, extent of fuel storage, and other design
0.35
TABLE 0.7. Existing Capacity (1980) and Capacity Additions
and Retirements (1981-2010) -Plan 2A (MW)
Anchorage-Cook Inlet
U1l
Fairbanks-Tan~na Valley
Gas Gas Refuse-Combustion Coal Refuse-Total
Combustion Combined-Derived Turbine & Steam Wind Turbine Derived Total Conservation
Year Turbine ~.k__ Fuel Diesel Jurbine Generators I!&_ Hydroelectric Du~ to Subsidy
1980 461 139 0 266 69 0 0 46 ( Ek lutna & 0
_cooper Lake)
1981 0 0 0 0 0 0 0 12 (Soloman Gulch) 13
1982 -20 178 0 0 0 0 0 0 26
1983 0 0 0 -8 0 0 0 0 39
1984 0 0 0 0 0 0 ,o 0 52
1985 0 0 0 0 IJ 0 0 0 65
1986 0 0 0 -1 0 0 0 0 67
1987 0 0 0 -8 -4 0 0 0 69
1988 0 0 0 -6 0 0 0 90 (Bradley lake) 71
1989 0 0 0 0 -5 0 0 0 73
1990 0 0 0 0 0 0 0 0 75
1991 0 0 0 -18 0 0 0 7 (Allison) 68
1992 -16 0 0 -19 0 25 0 0 62
.993 -9 0 50 0 0 25 0 0 56
1994 -30 0 0 0 0 50 20 0 49
1995 -14 0 0 -33 0 0 0 337 (Grant lake & 43
0 Chakachamna) . 1996 0 0 0 -102 0 75 20 0 43 w
0"1 1997 0 200 0 -65 0 0 0 0 44
1998 -50 0 0 0 0 0 (j 0 44
1999 0 0 0 0 0 0 0 0 45
2000 -18 0 0 0 0 0 0 0 45
2001 0 0 0 0 0 0 0 0 47
2002 -51 0 0 0 -25 0 0 0 48
2003 -53 0 0 0 0 0 0 0 50
2004 0 0 0 0 0 0 0 0 51
2005 -58 0 0 0 -21 0 0 80 (Brown} 53
2006 70 0 0 0 0 0 0 0 55
2007 0 0 0 0 0 0 0 0 57
2008 0 0 0 0 0 0 0 100 (Keetna) 54
2009 70 0 0 0 0 0 0 0 61
2010 0 0 0 0 0 0 0 0 63
TABLE 0.8. Electrical Generation by Type of Capacity -Plan 2A (GWh)
Anchorage-Cook Inlet
Oil
Fairbanks-Tanana Valley
Gas Gas Refuse-Combustion Coal Refuse-Total
Combustion Combined-Derived Turbine & Steam Wind-Turbine Derived Total Conservation
Year Turbine Cycl_e_ Fuel J!iesel ___ Turb1illl_ Generators f.!!.tl_ Hydroelectric Due to Subsidy
1981 1936 35 0 14 537 0 0 254 77
1982 636 1364 0 39 537 0 0 254 155
1983 652 1359 0 65 537 0 0 254 233
1984 673 1351 0 90 537 0 0 254 310
1985 195 2101 0 0 393 0 0 254 378
1986 995 1406 0 0 504 0 0 254 401
1987 1090 1417 0 78 537 0 'o 254 414
1988 824 1394 0 189 537 0 0 648 427
1989 918 1405 0 342 496 0 0 648 440
1990 495 2466 0 0 416 0 0 648 453
1991 1532 1489 0 0 496 0 0 677 415
1992 1594 1509 0 1 496 0 0 677 377
1993 1360 1441 394 0 487 85 0 677 339
1994 1216 1436 394 0 476 171 158 677 302
19!:15 9 1317 394 0 496 342 158 2153 264
1996 8 1311 394 0 492 342 158 2153 268
1997 1 1313 394 0 496 342 158 2153 272
t::J 1998 1 1307 394 0 496 342 158 2153 275 . 1999 1 1300 394 0 496 342 158 2153 279 w 2000 1 1294 394 0 496 342 158 2153 283 -....J 2001 1 1376 394 0 496 342 158 2153 292
2002 2 1662 394 0 289 342 158 2153 300
2003 2 1743 394 0 289 342 158 2153 309
2004 3 1823 394 0 289 342 158 2153 317
2005 2 1685 394 0 124 342 158 2539 325
2006 3 1823 394 0 124 342 158 2539 338
2007 4 1960 394 0 124 342 158 2539 350
2008 3 1776 394 0 124 342 158 2863 363
2009 4 1913 394 0 124 342 158 2863 375
2010 5 2051 394 0 124 342 158 2863 387
parameters. A 50-MW plant would require 50 acres of land. This large area is
needed to accommodate fuel-receiving facilities, fuel-storage piles, materials
handling and preparation systems, boilers, feedwater treatment systems, turbine
generators, and associated pollution control systems for such activities as
stack gas cleaning and ash disposal. Also, because of the refuse, substantial
buffer zones may be required.
Power Plant Characteristics and Emissions. The core of the power plant
is the boiler and the turbine generator. However, like the coal-fired power
plant, ancillary systems exist for fuel receiving, storage and processing, for
stack gas cleanup, bottom and fly ash handling and condenser cooling purposes.
Fuel processing equipment is particularly critical if spreader-stocker firing
is used. Metallic and other noncombustible objects must be removed from the
fuel. Preferably, municipal waste will be shredded and classified to minimize
contamination by metals and glass objects. Combustion with minimal fuel
preparation, while practical in some cases, results in less efficient operation
of the equipment.
Potentially significant impacts from refuse plants are similar to other
steam-cycle f)lants and result from 1) the water withdrawal and effluent
discharge, 2) atmospheric emissions of particulate matter, NOx, SOx and
others, 3) disposal of solid waste and ash, and 4) ecological effects.
The major impact affecting the terrestrial biota and resulting from refuse-
fired power plants is the loss or modification of habitat. Land requirements
for refuse-fired plants are similar to those of coal-fired plants and are
generally greater than those for other steam-cycle power plants on an acres-
per-MW basis. The primary locations of refuse-fired power plants in the
Railbelt region are adjacent to lands that contain seasonal ranges of moose,
waterfowl and other animals. Impacts on these animal populations will depend
on the characteristics of the specific site and the densities of the wildlife
populations in the site area. Because of the relatively small plant capacities
involved, however, impact~ should be minimized through the plant siting process.
Wind Energy
Until the mid-1930s wind energy supplied a significant amount of energy
to rural areas. With the advent of the Rural Electrification Administration
0.38
and the abundance of oil and coal, wind energy ceased to be competitive with
other power alternatives. Renewed interest in the development of wind
resources has occurred, however, as fuel costs have risen and have increased
the cost of power from competing technologies.
This alternative consists of large wind energy conversion systems (wind
turbines) configured as a wind farm, located in the Isabell Pass wind resource
area. The wind farm consists of ten 2.5-MW horizontal axis wind turbines, for
a tot a 1 25-M\~ rated capacity.
Wind turbine generators located at Isabell Pass would have small impacts
on the atmospheric or meteorological conditions around the site. The impacts
relate to small microclimatic changes and interference with electromagnetic
wave transmission through the atmosphere. No effects on air quality are
generated.
Wind turbines extract energy from the atmosphere and, therefore, have the
potential of causing slight modifications to the surrounding climate. Wind
speeds will be slightly reduced at surface levels and to a distance equivalent
to 5 rotor diameters, which would be ~1500 feet for a single 2.5-MW facility.
Small modifications in precipitation patterns may be expected, but total
rainfall over a wide area will not be impacted. Nearby temperatures,
evaporation, snowfall, and snow drift patterns will be affected only slightly.
The microclimatic impacts will be qualitatively similar to those noted around
large isolated trees or tall structures.
The rotation of the turbine blades may interfere with television, radio,
and microwave transmission. Interference has been noted within 0.6 miles (1
km) of relatively small wind turbines. This distance is expected to be greater
for the relatively large 2.5 MW machines considered in this study. The nature
of the interference depends on signal frequencies, blade rotation rate, number
of blades, and wind turbine design. A judicious siting strategy could help to
avoid these impacts if they seem to be a problem.
Stream siltation effects from site and road construction are the only
potential impacts associated with wind-energy technology since process water is
not required. Silt in streams may adversely affect feeding and spawning of
fish, particularly salmonids, which are common in the Railbelt region. These
0.39
potential problems can be avoided by proper construction techniques and should
not be· significant unless extremely large wind farms are developed.
Wind-powered energy requires varying amounts of land area for
development. The area required will _depend on the number, spacing, and type of
wind-powered unit. This requirement can range from 'V2 acres for a 2.5-MW
generating unit to 100 square miles for numerous units generating up to 1000
MW. Because of operational requirements for persistent high-velocity winds,
these developments may be established in remote areas.
Be tau se of the 1 and requirements i nvo 1 ved and the potentially remote
siting locations, the greatest impact resulting from wind-energy projects on
terrestrial biota would be loss or disturbance of habitat. Wind-generating
structures can furthermore impact migratory birds by increasing the risk of
collision-related injury or death. Other potential impacts include low-
frequency noise emanating from the generators and modification of local
atmospheric conditions from air the turbulence created by the rotating blades.
The impacts of these latter disturbances on wildlife, however, are presently
unclear.
Hydroe·l ectr i c
The environmental considerations associated with hydroelectric projects
such as Allison, Brown, Keetna, Grant Lake, Snow, Bradley Lake and Chakachamna
are all similar and previously described in Section 0.1.3.
Conservation
In this plan, the State of Alaska is assumed to provide grants to those
homeowners who wish to implement high-cost conservation techniques. In the
absence of a subsidy program, a substantial amount of electrical conservation
would exist because of increases in electricity and fossil fuel prices.
Through grants to homeowners Plan 2A increases this situation by 11 investing 11
in additional conservation that reduces the consumer's investment cost (but not
his operating and maintenance costs) to zero for selected high-investment
homeowner energy-saving technologies. At the prices of power projected in
these supply plans, consumers are assumed to undertake on their own such low-
investment, high-payoff strategies as set-back thermostats, water heater
blankets, storm windows, weatherstripping, etc. The specific techniques for
0.40
which grants are assumed to be available are superinsulation, passive solar
heating, active solar hot water heating and wood-fired space heating. The
subsidies bring the housing stock electric-use efficiency up to technical and
market limits imposed by siting considerations, operating costs, and consumer
convenience.
The limits on market penetration of the four residential high-investment
technologies are assumed to be affected in the following way. For
superinsulation, the price-induced market penetration is substantial -50% of
the total housing stock (and a much higher percentage of new homes). The
payback period is alre.ady very short for conservation and is only slightly
reduced by grant programs. Market penetration is increased to 55% by
subsidies. Passive solar is restricted in the existing housing stock by siting
and architectual considerations, and in the new housing stock by building
sites. However, the long payback period in the nonsubsidized case implies that
a state grant program would increase market penetration from about zero to up
to 33% of the whole housing market (more in new houses). Active solar hot
water heating has very long paybacks, but siting and technical considerations
are expected to restrict the market penetration to ~10% of all households.
Wood stoves are already very popular as supplemental heat. Payback periods are
quite 1 ong; however, if the wood fue 1 must be purchased at $80 to $90. a cord,
this will be a fair market test of the technology. Because fuel costs are
important, a grants program is expected to have little incremental impact on
use of wood stoves as primary heating units. An estimated equivalent of 20% of
all households would heat exclusively with wood, but none would do this because
of the subsidy.
Little is known about commercial electrical uses in the Railbelt. Based
on investment and engineering calculations contained in the Oak Ridge National
Laboratories• commercial energy model (DOE 1979), commercial electrical use was
estimated to be reduced in the commercial sector by ~35% on the average. In
the absence of subsidies, ~69% penetration is assumed. With grants, this is
increased to 100% penetration, and 35% full technical savings are achieved.
Table 0.9 shows the estimated number of homes using these techniques in the
year 2010.
0.41
TABLE E.9 Estimated Number of Homes Using the Conservation Techniques
Super Passive Solar Active Hot
Insulation Space Heating Water Heat
Anchorage 8,384 54,498 16,769
Fairbanks 1,975 12,835 3,949
Glennallen/Valdez 3~ 2,389 735
Superinsulation. This includes several measures such as specialized
construction techniques for floor and foundations systems, wall systems, roof
systems, windows and doors, plus movable insulation such as shudders and a wide
range of measures to reduce air infiltration. Caulking and weatherstripping
plus air-to-air heat exchangers are features commonly included. All of these
measures reduce the direct loss of thermal energy from the home.
Passive Solar· Space Heating. In the purest sense, passive solar uses
no mechanical means such as fans or pumps to distribute heat from the sun into
the living space. It relies on a combination of a thermally efficient building
envelope to contain heat, south glazing to capture solar energy, some form of
thermal mass to store this energy for release at night or during cloudy
periods, and design techniques to distribute heat by convection. Essentially,
the building is the system.
Environmental impacts from passive solar technologies are minimal, almost
nonexistent. No traceable air or water pollution has been recorded in
dispersed application. For the environment solar is almost ideally benign fuel
source.
The potential detriments of solar on the environment center on two
factors: aesthetics and reflected glare. Aesthetic appeal is, of course,
subjective, and not quantifiable. It is, however, an important factor. Since
the concept of passive solar centers on the building and its components, the
designers must ensure an aesthetically pleasing structure. Many examples of
passive sol~ buildings throughout the United States are considered "ugly" by
their critics. On the other hand, just as many or more examples of successful
installations can be found. Entire solar subdivisions such as those in the
city of Davis, California, are both pleasing to look at and pleasant to live
0.42
in. Passive solar housing does not have to look different from the more
11 traditional 11 buildings, except for the expanse of south-facing glass.
Reflected glare off south glazing is a potential problem in solar
application. The extent of the problem in the Railbelt is not known at this
point. Glare is more prevalent when the sun strikes the glazing at an acute
angle; i.e., the less perpendicular the sun's rays to the collector surface,
the more glare encountered. During the winter, vertical glass will not cause
excessive glare problems. In the summer proper design of the roof overhangs
will ensure that enough glass is shaded to alleviate most glare~ During the
spring and fall the phenomenon could cause problems to passing motorists and
pedestrians. The small number of solar system installations in the Railbelt
region precludes answers to these potential problems at this time.
Consumer safety poses no real problem with passive solar. Because most
systems are simple and benign, danger to the consumer is far less than a
central fuel-fired furnace system, for example. Workers certainly face higher
percentage of danger when installing systems, but potential injury and death
are limited to those risks that the worker might encounter in standard
construction.
Active Solar Water Heating. 11 Active 11 solar systems require auxiliary
pumping energy to function properly. These systems differ from 11 passive 11 solar
energy application, which requires very little or no auxiliary energy. Active
solar energy use is an accepted technology; thousands of systems have been
installed throughout the United States.
Three varieties of dispersed active solar systems are currently available
for use in Alaska: liquid-based flat-plate collector systems for space
heating, liquid-based flat-plate collector systems for hot water heating, and
hot-air systems for space heating.
The high cost of initial investment seems to preclude solar energy use for
space heating but for heating water it is feasible in the Railbelt. On an
annual average, ~so% of the hot water needs can be met by active solar
collectors.
D.43
0.3.3 Socioeconomic Considerations for P·lan 2A
The socioeconomic considerations for this plan stem from a wide range of
activities, including construction of fossil power plants, use of refuse as a
fuel, wind energy, hydroelectric facilities and energy conservation techniques
which include insulation, passive solar heating, and active solar hot water
heating.
Refuse Fuel
Impacts of refuse-fired plants will vary among the primary locations
identified, as well as with scale. For Anchorage 50-MW and for Fairbanks
20-MW plants can be constructed with minimal impacts to the social and
economic structure of those communities. The construction staff of 65 could
come from the regional labor force, reducing or eliminating the need to
transfer workers from other areas of the Railbelt to these sites.
The breakdown of capital expenditures is expected to be 60% outside the
Railbelt and 40% within the region. Expenditures due to a large capital
investment will be offset by an Alaskan labor force. Approximately 10% of the
operating and maintenance expenditures would be spent outside the Railbelt
region.
Wind Systems
A wind turbine requires a small construction work force of 10 to 15
persons, no operating work force, and minimal maintenance requirements. In
comparison to the other fuel-saver techologies, wind power would create very
few demands on community infrastructure. Installing a 100-MW wind farm would
require a construction work force of ~60 over a period of a few years. The
peak work force would be ~140. The addition of incremental capacity to the
system would permit a test period during which necessary design and siting
modifications could be made. The impacts of constructing a wind farm on small
communities may be significant due to the increase in work force size and
length of construction period. However, the impacts should decrease as the
population of the communities near the site increases.
The cost breakdown for a wind turbine investment is based on the
assumption that the monitoring field work, site preparation, and installation
would be performed by Alaskan labor and that all components would be imported
0.44
from outside manufacturers. Therefore, ~aO% of the capital expenditures would
be sent outside the region and 20% would remain within Alaska. The allocation
of operating and maintenance expenditures would be 15% spent outside the
Railbelt and 85% within the region. The high percentage of costs allocated to
outside maintenance would be offset to some extent by the small requirements
for supplies.
Hydroelectric
See Section 0.3.4 for a description of the socioeconomic considerations
associated with hydroelectric power facilities.
Conservation
Passive Solar. Virtually no work on capital costs for passive solar has
been done in the Railbelt, mainly because so few system actually have been
installed. In addition, most solar buildings in the region rely on heavy
insulation and efficient thermal envelopes to first reduce heat load, and
often, differentiating between costs for solar and those general building
costs is difficult. Preliminary studies show an increase in a range of 6% to
10% above normal construction costs for a passive solar, superinsulated home.
Passive solar will create jobs and new capital ventures at a local as
well as at a regional level. Because the skills required to design and install
systems are relatively straightforward if standard materials and techniques
are used, most likely the needed human resource exists in the region. If
pursued on a fairly widespread scale, the potential for long-lasting jobs in
new and existing businesses is promising.
An increase in employment and business at the regional level would very
likely result in an increase in the amount of capital staying in the region,
further providing economic benefits outside the construction sector. Certainly
the extra income available to the consumer by reduced fuel expenditures will
find its way into the region's economy. Whereas an in-depth economic analysis
cannot be done until the degree of penetration of the solar technologies in the
marketplace can be better assessed, preliminary study and common sense indicate
that solar will have a positive impact on the economy.
0.45
0.3.4 Integration of Potential Environmental and Socioeconomic Impacts for
Plan 2A
The integration of potential environmental and socioeconomic impacts for
Plan 2A is presented in Table 0.10. The potential impacts on air quality,
water quality, and ecology are moderate, and the use of refuse-derived fuel at
plants in Anchorage and Fairbanks is not a major concern because the plants are
of fairly small capacity compared to typical fossil fuel plants.
The construction of hydroelectric projects at Bradley Lake, Browne,
Chakachamna and Snow present the jobs and boom/bust impacts associated with
hydroelectric construction projects. The local labor markets in Anchorage and
Fairbanks will be able to handle the demands created by conservation activities
such as construction of refuse-power facilities.
This plan would create a moderate demand for jobs, require a substantial
portion of spending within Alaska and yet, due to the emphasis on conservation
activities and use of hydroelectric facilities, a great inflation effect from
the rising cost of fuel would not result.
-·
0.4 PLAN 2B: HIGH CONSERVATION AND USE OF RENEWABLE RESOURCES WITH
UPPER SUSITNA
Plan 2B is similar to Plan 2A except that the Upper Susitna project is
built. The other hydroelectric facility to be built is the Bradley Lake
project, which comes on-line in 1988.
Other generating capacity includes the following:
Anchorage-Cook Inlet
1 A 50-MW refuse-derived fuel plant comes on-line in 1992.
Fairbanks-Tanana Valley
1 Wind-energy resources in the Isabell Pass area are developed {50 MW)o
0.4.1 Capacity and Generation for Plan 2B
The capacity additions and retirements for Plan 2B are shown in Table
0.11, and the electrical generation for each of these capacities is shown in
Table 0.12. In general, the capacity additions and electrical generation are
0.46
TABLE 0.10. Integration of Potential Environmental & Socioeconomic
Impacts for Plan 2A
Potential Environmental and Socioeconomic lm~acts
Suscepti-
Energy Terres-Aquatic/ Noise, Health Boom/ Land-llility Spending
Facilities Air Water tria 1 · Marine Visual and Jobs in Bust Use to in Alaska
Added Quality ~ Ecology Ecology & Odor Safety Alaska Effects Effects Inflation (%Total)
Anchorage-
Cook Inlet
Gas Turbine
Combustion 2 1 2 1 2 3 20
Gas Combined
Cycle 2 2 2 2 2 2 1 3 3 30
Refuse Derived
Fuel 3 2 2 2 3 2 2 2 40
Fairbanks-
Tanana Valley
Wind Turbine
a Generators 2 2 2 1 20 .
.j:::o Refuse Derived ....... Fuel 3 2 2 2 3 2 2 1 2 40
Hydroelectric
Allison 1 2 2 2 1 2 2 2 1 35
Bradley Lake 1 2 2 2 2 1 3 3 3 65
Grant Lake 2 2 2 2 2 2 35
Brown 1 2 2 2 2 3 3 3 1 65
Keetna 2 2 2 2 3 3 3 65
Chakachamna 2 2 2 2 1 3 3 3 65
Snow 1 2 2 2 2 3 3 3 1 65
Conservation(a) 2 2 2 2 3 1 1 80-90
-----Rating Scale: 1 -minor
2 -moderate
3 -significant
(a) Includes building conservation, passive solar heating, and active solar hot water heating.
TABLE D.ll. Existing Capacity (1980) and Capacity Additions
and Retirements (1981-2010) -Plan 2B (MW)
Anchorage-Cook Inlet Fairbanks-Tanana Valle~
~·1uni ci pa 1 Oil
Gas Gas Combustion Coal Wind-Total
Combustion Combined-· Solid Turbine & Steam Turbine Total Conservation
Year Turbine C~cle Naste Diesel Turbine Generators H~droelectric Due to Subsidy
1980 461 139 0 266 69 0 46 (Eklutna & 0
Cooper Lake)
1981 0 0 0 0 0 0 12 (Solomon Gulch) 13
1982 -20 178 0 0 0 0 0 26
1983 0 0 0 -8 0 0 0 39
1984 0 0 0 0 0 0 0 52
1985 0 0 0 0 0 0 0 65
1986 0 0 0 -1 0 0 0 68
1987 0 0 0 -8 -4 0 0 71
1988 0 0 0 -6 0 0 90 (Bradley Lake) 74
1989 0 0 0 0 -5 0 0 77
1990 0 0 0 0 0 0 0 79
1991 0 0 0 -18 0 0 0 72
1992 -16 0 50 -19 0 50 0 65
0 1993 -9 0 0 0 0 0 680 (Watana) 58 .
+:> 1994 -30 0 0 0 0 0 0 51
00 1995 -14 0 0 -33 0 0 0 44
1996 0 0 0 -102 0 0 0 44
1997 0 0 0 -65 0 0 0 45
1998 -50 0 0 0 0 0 0 45
1999 0 0 0 0 0 0 0 45
2000 -18 0 0 0 0 0 0 45
2001 0 0 0 0 0 0 0 47
2002 -51 0 0 0 -25 0 600 (Devil Canyon) 49
2003 -53 0 0 0 0 0 0 51
2004 0 0 0 0 0 0 0 52
2005 -58 0 0 0 -21 0 0 54
2006 0 0 0 0 0 0 0 57
2007 0 0 0 0 0 0 0 59
2008 -26 0 0 0 0 0 0 62
2009 0 0 0 0 ·o 0 0 65
2010 0 0 0 0 0 0 0 68
TABLE 0.12. Electrical Generation by Type of Capacity -Plan 28 (GWh)
Anchorage-Cook Inlet Fairbanks-Tanana Vallel
~1uni ci pa 1 oil
Gas Gas Combustion Coal Wind Total
Combustion Combined-SoHd Turbine & Steam Turbine Total Conservation
Year Turbine Cycle Haste Diesel Turbine Generators Hldroelectric Due to Subsidy
1981 1955 36 0 13 537 0 254 78
1982 641 1366 0 37 537 0 254 156
1983 662 1362 0 62 537 0 254 234
1984 685 1354 0 86 537 0 254 311
1985 202 2114 0 0 388 0 254 389
1986 1045 1413 0 0 494 0 254 408
1987. 1169 1423 0 64 537 0 254 427
1988 943 1408 0 171 537 0 648 446
1989 1068 1425 0 319 496 0 648 465
1990 654 2474 0 1 424 0 648 484
1991 1689 1537 0 2 496 0 648 441
1992 1350 1484 394 1 496 171 648 398
1993 0 95 394 0 0 171 4103 355
1994 0 214 394 0 0 171 4103 312
0 1995 0 44 394 0 320 171 4103 269 . 1996 0 42 394 0 299 171 4103 272 ·~ 1997 0 40 394 0 279 171 4103 274
1998 0 38 394 0 259 171 4103 277
1999 0 31 394 0 248 171 4103 279
2000 0 29 394 0 231 171 4103 281
2001 0 43 394 0 311 171 4103 292
2002 0 0 0 0 0 19 5098 303
2003 0 0 0 0 0 18 5273 313
2004 0 0 0 0 0 17 5361 324
2005 0 0 0 0 0 16 5448 334
2006 0 0 0 0 0 9 5624 351
2007 0 0 0 0 0 33 5800 368
2008 0 0 0 0 0 30 6063 385
2009 0 0 0 0 0 5 6239 402
2010 0 0 0 0 0 20 6415 419
similar to Plan 2A except that the Watana and Devil Canyon dams are added in
Plan 2B, replacing several of hydroelectric projects added in Plan 2A.
D.4.2 Environmental and Socioeconomic Considerations for Plan 2B
The main environmental and socioeconomic considerations for Plan 2B stem
from 1) the development of the Upper Susitna dams at Watana and Devil r.anyon,
2) construction of Bradley Lake dam, 3) construction of a refuse plant and gas
combined plant in Anchorage, 4) construction of a wind-turbine generator in
Fairbanks and 5) the implementation of energy conservation measures, including
insulation, passive solar space heating, and active solar hot water heating.
These considerations have been presented previously in the following sections:
Bradley Lake in Sections D.2.3 and D.2.4; Watana and Devil Canyon in Sections
D.3.2 and D.3.3; and Refuse-Derived Fuel, Wind-Turbine Generators, and
Conservation irr Sections D.4.2 and 0.4.3.
An important feature of Plan 2B is that after 1982 no more fossil-fuel
electrical-generating capacity is added and most of the existing gas, oil, coal
and diesel electric capacity is phased out by 2010. The penetration of
conservation activity for this plan is given in Table D.13; these estimates
--
differ from Plan 2A because the penetration is determined by the cost of power,
which is different for the two plans.
TABLE D.13. The Estimated Number of Homes Using the
Conservation Techniques in the Year 2010
Super Passive Solar Active Hot
Insulation Space Heating Water Heating
Anchorage 9,211 59,872 18,422
Fairbanks 2,213 14,385 4,426
Glennallen/Valdez 423 2, 750 846
D.4.3 Integration of· Potential Environmental and Socioeconomic· Iinpact·s for
Plan 28
The integrated potential environmental and socioeconomic impacts of
Plan 2B are presented in Table D.14. The air-quality and water-quality impacts
for this plan are low to moderate. With the use of the Upper Susitna projects
D. 50
TABLE 0.14. Integration of Potential Environmental & Socioeconomic
Impacts for Plan 28
Potential Environmental and Socioeconomic Im!!acts
Suscepti-
Energy Terres-Aquatic/ Noise, Health Boom/ Land-bility Spending
Facilities Air Water trial Marine Visual and Jobs in Bust Use to in Alaska
Added gualit~ gualit~ Ecolog~ Ecolog~ & Odor Safety Alaska Effects Effects Inflation 1!_ Total)
Anchorage-
Cook Inlet
Gas Combined
Cycle 2 2 2 2 2 1 2 1 3 3 20
Refuse-Derived
Fuel 3 2 2 2 3 2 2 1 3 1 40
Fairbanks-
Tanana Valle~
Wind Turbine
0 Generator 1 1 2 1 2 1 1 1 2 1 20
(Jl
-'
H~droelectric
Bradley Lake 1 2 2 2 1 1 3 3 3 1 65
Watana 1 2 2 2 1 1 3 3 3 1 65
Devil Canyon 1 2 2 2 1 1 3 3 3 1 65
Conservation(a) 2 1 2 1 2 2 3 1 1 1 80-90
Rating Scale: 1 -minor
2 -moderate
3 -significant
la) Includes building conservation, passive solar heating, and active solar hot water heating.
at Watana and Devil Canyon, almost all fossil-fuel plants, including gas
combination turbines, coal steam turbines, oil com6ustion turbines and diesel
electric units, are phased out. These projects would represent a significant
amount of spending within the state and inflation impacts would be low because
the fossil-fuel use is phased out and replaced by hydroelectric.
The main environmental and socioeconomic concerns for this plan stem from
the potential for large land-use and boom/bust effects. Significant labor
forces will be necessary to build the dams. However, in this plan the
construction of the Watana and Devil Canyon dams are separated by nine years,
which would tend to distribute the boom/bust effects over a time period of
about 15 years.
D.5 PLAN 3: INCREASED USE OF COAL
This plan is based on a transition from existing generating technologies
to alternatives that either directly or indirectly use coal as a fuel. All new
generation is either coal-fired steam turbines or combined-cycle units using
coal-based synthetic fuels. In the Railbelt, coal is currently available from
the Healy area; it is also expected to be available from the Beluga area in
1988. This plan assumes that coal-fired generation in the Anchorage-Cook Inlet
load center will be located at the Beluga area. Baseload generation for the
Fairbanks area depends on the costs of facilities located in the Nenana area.
With the exception of Bradley Lake, no additional hydroelectric facilities are
built.
0.5.1 Capacity and Generation for Plan 3
The capacity additions and retirements for this plan are shown in
Table D.15. The generation by type of capacity is shown in Table ·D.16.
D.5.2 Environmental Considerations for Plan 3
In Plan 3 the main environmental consideration that has not been addressed
in previous plans is the use of coal-gasifier combined-cycle technology. This
consideration is the focus of this section. The following energy facilities
are a part of this plan, but their environmental considerations have been
discussed in a previous section: Gas Combustion Turbine, Gas Combined-Cycle,
Coal Steam Turbine, and Bradley Lake Hydroelectric in Section D.2.3.
0.52
TABLE D. 15. Existing Capacity (1980) and Capacity Additions and Retirements
(1981-2010) -Plan 3 (MW)
Anchorage-Cook Inlet Fairbanks-Tanana Valle~
Coal Oi 1
Gas Gas Coal Gasifier Combustion Coal
Combustion Combined-Steam Combined Turbine & Steam Total
Y,ear Turbine C~cle Turbine C~cle Diesel Turbine H~droelectric
1980 461 139 0 0 2.66 69 46 (Eklutna & Cooper Lake)
1981 0 0 0 0 0 0 12 (Solomon Gulch)
1982 -20 178 0 0 0 0 0
1983 0 0 0 0 -8 0 0
1984 0 0 0 0 0 0 0
1985 0 0 0 0 0 0 0
1986 0 0 0 0 -1 0 0
1987 0 0 0 0 -8 -4 0
1988 0 0 0 0 -6 0 90 (Bradley Lake)
1989 0 0 0 0 0 -5 0
1990 0 0 0 0 0 0 0
0 1991 70 0 0 0 -18 0 0 . 1992 -16 0 200 0 -19 0 0 U1 w 1993 -9 0 0 0 0 0 0
1994 -30 0 0 0 0 0 0
1995 -14 0 0 200 -33 0 0
1996 0 0 0 0 -102 0 0
1997 0 0 0 0 -65 200 0
1998 -50 0 0 0 0 0 0
1999 0 0 0 0 0 0 0
2000 -18 0 0 0 0 0 0
2001 0 0 0 0 0 0 0
2002 -51 0 0 0 0 -25 0
2003 17 0 0 0 0 0 0
2004 0 0 0 0 0 0 0
2005 -58 0 200 0 0 -21 0
2006 0 0 0 0 0 0 0
2007 0 0 0 0 0 0 0
2008 -26 0 0 0 0 0 0
2009 70 0 0 0 0 0 0
2010 70 0 0 0 0 0 0
TABLE 0.16. Electrical Generation by Type of Capacity -Plan 3 (Gwh)
Anchorage-Cook Inlet Fairbanks-Tanana Valley
Coal Oil
Gas Gas Coal Gasifier Combustion Coal
Combustion Combined-Steam Combined-Turbine & Steam Total
Year Turbine Cycle Turbine --Cycle Diesel Turbine Hydroelectric
'1981 2017 46 0 0 27 537 254
.1982 766 1386 0 0 66 537 254
1983 840 1400 0 0 105 537 254
1984 942 1386 0 0 143 537 254
1985 411 2266 0 0 0 459 254
1986 1347 1465 0 0 28 537 254
1987 1433 1506 0 0 134 537 254
1988 1248 1445 0 0 240 537 648
1989 1358 1471 0 0 387 496 648
1990 1005 2490 0 0 3 457 648
1991 1934 1660 0 0 1 496 648
1992 787 1431 1580 0 0 428 648
0 1993 902 1440 1584 0 0 436 648
<..T1 1994 1015 1430 1611 0 0 442 648
..j:::.
1995 52 1028 1611 1506 0 435 648
1996 55 1043 1611 1509 0 437 648
1997 5 195 1611 1506 0 1356 648
1998 5 196 1611 1509 0 1370 648
1999 6 199 1611 1511 0 1385 648
2000 6 202 1611 1512 0 1399 648
2001 7 213 1611 1511 0 1428 648
2002 11 251 1611 1514 0 1420 648
2003 11 259 1611 1514 0 1448 648
2004 12 279 1611 1517 0 1462 648
2005 2 68 3199 1219 0 431 648
2006 2 97 3207 1264 0 532 648
2007 3 131 3211 1294 0 647 648
2008 4 164 3215 1326 0 760 648
2009 7 197 3218 1354 0 877 648
2010 10 231 3220 1379 0 997 648
Synthetic fuels processes such as oil shale and tar sands exist for other
hydrocarbons, but coal is the logical choice far Alaska because of the large
reserves in the Beluga coal fields and other coal deposits in the Railbelt
region. The principles used to produce synthetic fuels from coal are
conceptually simple and varied, depending upon the products sought. Coal is a
heterogeneous solid substance with hydrogen/carbon (H/C) ratios of about 0.5 to
0.8. To convert coal to gaseous or liquid fuels, the H/C ratio is increased
dramatically by carbon removal (pyrolysis, coking), hydrogen addition (direct
hydrogenation), or total reformation (indirect liquefaction through the
production and reaction of synthesis gas, a mixture of carbon monoxide (CO) and
H2 ). Simultaneously, the coal molecule is fragmented into smaller units.
Coal gasification systems employing these principles produce low Btu gas (e.g.,
150 Btu/ft3), medium Btu gas (e.g., 350 Btu/ft3), and high Btu gas or
substitute natural gas (e.g., 900-1000 Btu/ft3). Coal gasification plants
are, for the most part, large petrochemical-like complexes.
Land requirements for the plants must provide 30 to 90 days coal storage,
the primary facility itself, ancillary facilities such as an on-site power
plant and/or a cryogenic oxygen separation plant, and product storage. The
site must have transportation facilities for moving coal to the facility if
mine-mouth sites are not available and for transporting the product from the
facility.
The site must have access to copious quantities of water for process,
cooling, and other requirements. Water serves as a source of hydrogen for
altering the H/C ratio in the water gas shift reaction. Water also is the sink
for waste heat.
Water-quality problems can arise from leaching and surface runoff from
coal storage. These impacts are similar to those of a coal-fired steam-
electric facility. Other concerns include the disposal of ash from the
gasifier and the steam plant.
Coal gasification creates the potential for large amounts of emissions
into the atmosphere. These emissions are similar to those associated with
conventional combustion processes and include primarily particulate matter,
sulfur oxides, nitrogen oxides, hydrocarbons, and carbon monoxide. In
addition, emissions similar to those from a coal-fired boiler can come from the
steam plant.
The effects most difficult to mitigate from a coal gasification plant are
similar to those from steam-cycle facilities because they are associated with
water supply and wastewater discharge requirements. In addition, the large
land-area requirement could impose large construction runoff effects. Water
withdrawal is associated with impingement and entrainment of aquatic
organisms. Chemical and thermal discharges may have acute or chronic effects
on organisms living in the discharge plume area. Thermal discharges can also
cause lethal thermal shock effects in the Railbelt region when the discharge is
stopped. The degree of these impacts will depend on many factors, such as the
location of the intake and discharge structure in the water body, the chemical
composition of the water supply source and discharged effluent, the plant's
water and wastewater management plan, and the type and quantity of aquatic
organisms present in the receiving water. In general, however, the magnitude
of impacts can be related to a plant's makeup water requirements.
The major impact affecting the terrestrial biota and resulting from a coal
gasification plant is the loss of habitat. The plants require land areas that
are two to five times that of coal-fired plants for a given energy-generating
capacity. The gasification plant, electrical generating facility, and support
facilities can occupy ~1000 to 3000 acres. In addition, the work force needed
to support this facility will create further disturbances to local terrestrial
ecosystems.
Terrestrial impacts can also result from the release of harmful air
emissions. These impacts will be similar to those of gas-and oil-fired
plants. While sulfur and nitrogen oxides are generally retained as a plant
product, particulates and other pollutants are released into the environment.
Such particulates can have adverse effects on local soils, vegetation, and
anima 1 s.
0.5.3 Socioeconomic Considerations for Plan 3
The main socioeconomic considerations related to Plan 3 are associated
with the use of fossil-fuel facilities. Most of these considerations, gas-
0.56
turbine combustion, gas combined-cycle, coal steam turbine, and Bradley Lake
hydroelectric, were discussed in Section 0.2.4.
In this section the socioeconomic concerns for coal gasification are
presented. The socioeconomic impacts are difficult to predict because no U.S.
experience exists from which to extrapolate employment levels. Due to the
large scale of these plants, however, the construction work force requirements
can be assumed to be at least equal to that of a large coal-fired power
plant. The work force requirements for mining the coal would increase the
impacts of a gasification plant by an order of magnitude of at least two. If
the product is used on-site, then the cumulative impacts of a coal mine,
gasification plant, and on-site power plant would be significant.
The construction and operation of a gasification plant (including the coal
mine and power plant) would cause a permanent boom due to the large cumulative
operating work force requirements. Whereas the construction work force would
be substantially larger than the operating staff, the impacts caused by the out-
migration of the construction work force would not be as great as the initial
boom. These effects would be caused by the large scale and intensity of a
plant development and the remoteness of sites.
Socioeconomic impacts would be severe at all potential sites, including
the Beluga and Healy area. The communities near all these coal'fields are
small in population. At the Beluga site, power plant components would most
likely be shipped by barge and then transported over land to the site.
Therefore, secondary impacts would be caused by the construction of haul
roads. The largest community in the Beluga area, Tyonek, is an Alaskan native
village with a population of 239. The influx of a construction work force
would disrupt the social structure of the community. Communities near the
Nenana would be severely impacted by the siting of a synthetic fuels plant as
well. All of these communities are very small, with population sizes of less
than 500. Installing a construction camp would not substantially reduce the
impacts in these communities.
0.57
0~5.4 Integration of Potential Environmental and Socioeconomic Impacts for
Plan 3
The integrated environmental and socioeconomic impacts for Plan 3 are
presented in Table 0.17. The main impacts are associated with the increased
use of coal. Environmental concerns include degradation of air quality and,
as discussed in Section 0.2.2, compliance with the current PSO regulations can
be a problem. The power plants are not aesthetically attractive and the plumes
from the smokestacks and cooling towers contribute to reduced visibility.
The addition of coal-based power facilities is distributed fairly evenly
throughout the time period. The Anchorage and Fairbanks labor markets will
probably be able to handle the job demands for construction and, therefore, a
significant boom/bust impact is not expected. Note that with the increased
dependency on coal, the potential for inflation effects is significant.
0.6 PLAN 4: 11 HIGH NATURAL GAS 11
This plan is based upon continued use of natural gas for generation in the
Cook Inlet area and a conversion to natural gas in the Fairbanks area. The key
assumption in this plan is that sufficient gas will be available in the Cook
Inlet area to allow utilities to continue to use it for electrical generation.
Natural gas also is assumed to be available for the Fairbanks area from the
North Slope beginning in 1988. Possible generating alternatives to be included
in this plan include fuel-cells, combined-cycle, combustion turbine, and fuel-
cell combined-cycle. The only hydroelectric project is the Bradley Lake
project, which comes on-line in 1988.
0.6.1 Capacity. and Generation for Plan 4
The capacity additions and retirements for this plan are shown in
Table 0.18. The generation by type of capacity is shown in Table 0.19.
0.6.2 Environmental and Socioec6nomic~Considerations for Plan 4
For Plan 4 the main environmental consideration that has not been
addressed in previous plans is the use of gas fuel-cell combined-cycle
technology. This consideration will be the focus in this section. The
following energy facilities are a part of this plan but were previously
0.58
TABLE 0.17. Integration of Potential Environmental & Socioeconomic
Impacts for Plan 3
Potential Environmental and Socioeconomic lm(!acts
Suscepti-
Energy Terres-Aquatic/ Noise, Health Boom/ Land-bi 1 ity Spending
Fac i 1 ities Air Water trial Marine Visual and Jobs in Bust Use to in Alaska
Added gua 1 it~ gualit~ Ecolog~ Ecolog~ & Odor Safety Alaska Effects Effects Inflation {%Total)
Anchorage-
Cook Inlet
Gas Turbine
Combustion 2 1 1 1 2 1 1 1 2 3 20
Gas Combined
Cycle 2 2 2 2 2 . 1 2 2 3 3 30
Coal-Fired
Steam Turbine 3 2 2 2 3 2 2 2 3 3 40
Coal Gasifier
0 Combined
Cycle 3 2 2 2 3 2 2 2 3 3
CJ1
1.0
Fairbanks-
Tanana Valle~
Coal-Fired
Steam-Turbine 3 2 2 2 3 2 2 2 3 3 40
H~droelectric
Bradley lake 1 2 2 2 1 1 3 3 3 1 65
Rating Scale: 1 -minor
2 -moderate
3 -significant
TABLE 0.18. Existing Capacity (1980) and
(1981-2010) -Plan 4 (MW)
Capacity Additions and Retirements
Anchorage-Cook Inlet Fairbanks-Tanana Valle~
Oil
Gas Gas Gas Fuel-Combustion Coal Gas Gas Fuel-
Combustion Combined-Cell Turbine & Steam Combined-Cell
Year Turbine C~cle Stations Diesel Turbine Cycle Stations Total H~droelectric
1980 461 139 0 266 69 0 0 46 (Eklutna & Copper lake)
1981 0 0 0 0 0 0 0 12 (Solomon Gulch)
1982 -20 178 0 0 0 0 0 0
1983 0 0 0 -8 0 0 0 0
1984 0 0 0 0 0 0 0 0
1985 0 0 0 0 0 0 0 0
1986 0 0 0 -1 0 0 0 0
1987 0 0 0 -8 -4 0 0 0
1988 0 0 0 -6 0 0 0 90 (Bradley lake)
1989 0 0 0 0 -5 0 0 0
1990 0 0 0 0 0 0 0 0
1991 0 0 0 -18 0 100 0 0
1992 -16 0 0 -19 0 0 0 0
1993 -9 0 0 0 0 0 200 0
1994 -30 0 0 0 0 0 0 0
0 1995 -14 0 200 -33 0 0 0 0
0'1 1996 0 0 0 -102 0 0 0 0
0 1997 0 0 0 -65 0 0 0 0
1998 -50 200 0 0 0 0 0 0
1999 0 0 0 0 0 0 0 0
2000 -18 0 0 0 0 0 0 0
2001 0 0 0 0 0 0 0 0
2002 -51 0 0 0 -25 0 0 0
2003 -53 0 0 0 0 0 0 0
2004 0 0 0 0 0 0 0 0
2005 -58 0 0 0 -21 100 0 0
2006 0 0 0 0 0 100 0 0
2007 0 0 0 0 0 0 0 0
2008 -26 0 0 0 0 0 200 0
2009 0 0 0 0 0 0 0 0
2010 0 0 0 0 0 0 0 0
TABLE 0.19. Electrical Generation by Type of Capacity -Plan 4 (GWH)
Anchorage-Cook Inlet Fairbanks-Tanana Vallel
Oil
Gas Gas Gas Fuel-Combustion Coal Gas Gas Fuel-
Combustion Combined-Cell Turbine & Steam Combined-Cell
Year Turbine Clcle Stations Diesel Turbine Cycle Stations Total Hldroelectric
1981 2007 44 0 26 537 0 0 254
1982 747 1382 0 63 537 0 0 254
1983 811 1394 0 100 537 0 0 254
1984 903 1378 0 137 537 0 0 254
1985 368 2250 0 0 452 0 0 254
1986 1264 1446 0 11 537 0 0 254
1987 1324 1467 0 108 537 0 0 254
1988 1080 1420 0 204 537 0 0 648
1989 1159 1434 0 342 537 0 0 648
1990 696 2481 0 1 496 0 0 648
1991 1685 1528 0 1 440 3 0 648
1992 1777 1528 0 0 496 1 0 648
1993 1781 1615 0 0 496 4 48 648
1994 1754 1731 0 0 496 8 84 648
1995 144 3434 1611 0 496 30 263 648
0 1996 14 1964 1611 0 496 29 267 648 .
0'1 1997 14 1973 1611 0 496 34 272 648 _,
1998 13 1982 1611 0 496 4 36 648
1999 13 1992 1611 0 496 4 37 648
2000 15 2002 1611 0 496 4 38 648
2001 15 2025 1611 0 496 5 46 648
2002 7 2248 1611 0 289 9 74 648
2003 1 2271 1611 0 289 10 85 648
2004 1 2293 1611 0 289 12 98 648
2005 1 2296 1611 0 124 21 667 648
2006 1 2341 1611 0 124 30 773 648
2007 1 2374 1611 0 124 39 883 648
2008 2 2398 1611 0 124 9 1240 648
2009 2 1283 1611 0 124 13 2886 648
2010 0 1293 1611 0 124 18 2910 648
discussed in the sections indicated: gas combined-cycle and Bradley Lake
hydroelectric in Sections 0.2.3 and 0.2.4.
Environmental Consideration. Fuel cells represent a technology that is
approaching commercialization and, therefore, should be considered in Alaska.
The fuel cell is fundamentally comprised of two electrodes, (an anode and a
cathode), separated by an electrolyte. Electrical energy is produced by the
cell when fuel and oxygen are electrochemically combined in the electrolyte.
The fuel and oxygen must be in the gaseous form, but the electrolyte may be an
aqueous acid such as phosphoric acid.
A complete fuel-cell plant typically consists of a fuel processor, a fuel-
cell section, and electrical equipment. The fuel processor converts natural
gas into hydrogen and clears the gas before it goes to the fuel cell.
The basic electrochemical process in the fuel-cell system is the
combination of hydrogen gas and oxygen to form water. Since the fuel-cell
system is hot while operating, ranging from approximately 20° to 1200°C
depending upon the electrolyte. product water will experience elevated
temperatures. A 10-MW plant would produce about 27,000 gal/day. This product
water can either be discharged from the plant, or if in the form of steam, used
either to drive a conventional steam turbine in a bottoming cycle or to reform
the hydrocarbon fuel in the fuel processor. Additional makeup water may also
be used to maximize the use of the reject heat in producing steam. The
quantity, however, would be very design specific. Regardless of the specific
facility application, an appropriate water and wastewater management plan
incorporating suitable waste-heat rejection technologies must be implemented to
ensure that thermal discharges comply with pertinent receiving stream standards.
Gaseous emissions from the operation of fuel cells are very low when
compared to alternative methods that use combustion techniques. Sulfur and
nitrogen will be gasified, not oxidized, and can easily be recovered from
process streams. Fuels that are essentially free of such pollutants, such as
hydrogen or natural gas, will not lead to any pollutant emissions. Carbon
dioxide and water vapor will be formed in large quantities, similar to that
associated ·with combustion. However, no detectable environmental impacts will
be associated With these emissions. Because of the high efficiences of fuel
0.62
cells and the ease of controlling potential pollutants, fuel cells represent a
dramatic improvement in air-quality impacts over combustion technologies.
The impacts of fuel-cell energy systems on terrestrial biota are
relatively slight since the air pollution potential is very low and small land
areas are required ( rvone acre for a 5-MW facility). Noise and other potential
disturbance factors are also relatively low. Furthermore, these plants will be
sited within or adjacent to developed areas where access road requirements are
minimal.
Socioeconomic Considerations. Sites for fuel-cell plants should be
constrained by the population size of the community since construction work
force requirements are relatively large and may cause significant impacts in
very small and small communities. Approximately 90 persons would be required
for a period of less than 1 year to construct a 10-MW plant. Impacts would be
minor to moderate in Anchorage, Fairbanks, Soldotna, Kenai, Valdez, Wasilla,
and Palmer.
Capital expenditures that would flow out of the region due to development
of a fuel-cell facility would include investment in high-technology equipment.
An expected 80% of the project expenditures would be made outside the region,
whereas 20% would be spent within the Railbelt. The allocation of operating
and maintenance expenditures spent outside the Railbelt is expected to be ~10%.
Advantages of fuel-cell stations include highly competitive energy costs,
short design and construction lead time, very favorable environmental
characteristics and favorable public acceptance (the latter largely because of
lack of adverse environmental effects). Use of local siting should minimize
transmission losses. Additionally, the units, being modular in nature, should
be insensitive to economics of scale; this combined with short lead time would
allow capacity increases to closely follow demand. The units may be operated
in either a baseload or load-following mode; unit efficiencies remain high at
partial power operation.
0.6.3 Integration of Potential Environmental and Socioeconomic'Impacts for
Plan 4
The integrated environmental and socioeconomic impacts are presented in
Table 0.20. The air-quality, water-quality, ecological and health impacts of
0.63
TABLE 0.20. Integration of Potential Environmental & Socioeconomic
Impacts for Plan 4
Potential Environmental and Socioeconomic 1m~ acts
Suscepti-
Energy Terres-Aquatic/ Noise, Health Boom/ land bi 1 ity Spending
Fac i 1 it i es Air Water trial Marine Visual and Jobs in Bust Use to in Alaska
Added gualit:i gualit:l Ecolog:i Ecolog_:i & Odor Safety Alaska Effects !_ffects Inflation (%Total)
Anchora~e-
Coo Inlet
Gas Combined
Cycle 2 2 2 2 2 1 2 2 3 3 30
Gas fuel
Cell Stations 1 1 2 2 2 l 2 2 1 3 20
Fairbanks-
Tanana Vallex
Gas Combined
0 Cycle 2 2 2 2 2 1 2 2 3 3 30
0'\
..j::. Gas Fuel
Cell Stations 1 1 2 2 2 1 2 2 1 3 20
H,:idroelectric
Bradley lake 1 2 2 2 1 1 3 3 3 1 65
Impact Rating Scale: l -minor
2 -moderate
3 -significant
this plan are low to moderate due to the use of hydroelectric and natural gas
power facilities. Furthermore, gas turbine combustion, oil turbine combustion
and diesel electric units are phased out. Bradley Lake is the only new
hydroelectric project used and, thus, local boom/bust impacts will be
associated with its construction.
Compared to the previous plans, this plan represents a large amount of
spending outside of the state. This situation is caused mainly by the 11 high
technologyn aspects of fuel-cell systems and, to a lesser extent, a similar
situation exists for gas combined-cycle units. The increased use of natural
gas would make inflation effects significant.
0.65
APPENDIX E
LIST OF ASSUMPTIONS
APPENDIX E
LIST OF ASSUMPTIONS
GENERAL ECONOMIC ASSUMPTIONS
1. Rate of Inflation -0%
2. Re.al Interest Rate (Cost of Capital) -3.0%
3. Consumer Discount Rate -3.0%
FUEL PRICE ESCALATION RATES
1. Escalation in World Crude Oil Prices -2.0%
2. Escalation in Fuel Oil in Alaska -2.0%
3. Escalation in Healy Coal Prices Delivered to Nenana -2.0%
4. Esc a 1 ati on in Beluga Coal Prices -2.1%
5. Escalation in Cook Inlet Natural Gas Prices Beyond 1995 -2.0%
6. Escalation in North Slope Natural Gas Prices -0%
FUEL AVAILABILITY ASSUMPTIONS
1. North Slope natural gas is available via ANGTS at Fairbanks by 1987.
2. A large-scale coal export mine (5 million tons per year) is developed
in the Beluga area, making coal available for electrical generation.
Without such a development, coal will not be available from Beluga.
3. The current reserves of natural gas in the Cook Inlet will not be
sufficient to support expanded gas-fired generation beyond 1990-1995.
Additional reserves will be available to allow expanded gas-fired
generation beyond 1995.
ECONOMIC SCENARIO AND ELECTRICAL DEMAND ASSUMPTIONS
This is a summary only. Full details are in Volume IX.
Medium Economic Scenario.
1. Alaska private basic sector employment, 1980-2000 -See Appendix B.
Appropriate average growth rate: 3.2%.
E.1
2. State government budget averaqe real growth rate, 1980 to 2000 -
1.0 times real income growth~a)
3. Railbelt basic sector employment average growth rate, 1980 to 2000 -
3.7%
4. Inflation rate, 1980 to 2000 -6.9%
5. Alaska average household size falls from 3.086 (1980} to 2.657
(2000).
6. Railbelt population average growth rate, 1980 to 2000 -2.7%
7. Resulting employment and population trends extrapolated to 2010.
Low Economic Scenario
1. Alaska private basic sector employment growth, 1980 to 2000 -See
Appendix B. Approximate average growth rate: 1.6%
2. State government budget average real growth rate, 1980 to 2000 -
Constant real per capita.(a)
3. Railbelt basic sector employment average growth rate, 1980 to 2000 -
1.9%
4. Inflation rate, 1980 to 2000-7.2%
5. Alaska average household size falls from 3.086 (1980) to 2.660 (2000)
6. Railbelt population average growth rate, 1980 to 2000 -1.8%
7. Resulting employment and population trends extrapolated to 2010.
High Economic Scenario
1. Alaska private basic sector employment growth, 1980 to 2000 -See
Appendix B. Approximate average real growth rate: 5.5%
2. State government budget avera{e real growth rates 1980 to 2000 -
1.5 times real income growth. a)
3. Railbelt basic sector employment average growth rate, 1980 to 2000 -
6.3%
4. Inflation rate, 1980 to 2000 -6.7%
(a) Basic operating and capital budget. Excludes some items such as debt
service and special capital project funds. See Volume IX for details.
E.2
5. Alaska average household size falls from 3.086 (1980) to 2.655 (2000).
6. Railbelt population average growth rate 1980 to 2000 -4.1%
7. Resulting employment and populaton trends extrapolated to 2010.
FIXED CHARGE RATES ASSUMPTIONS
The fixed charge rates cover the capital cost recovery for the generating
facilities. The fixed charge rates represent the annual costs required to
cover the initial capital cost of a capital cost item (such as generating
facility). The fixed charge rate depends upon the economic lifetime of the
item and the cost of capital. For the economic lifetimes presented above, a 3%
cost of capital and an annual insurance cost equal to .25% of the initial
capital costs, the following fixed charge rates are used:
Cost of Capital
-
Sinking Fund
Insurance
20 years
3.00
3.72
0.25
6.97
Fixed Charge Rates (%)
Project Life
30 years 40 years
3.00 3.00
2.10
0.25
5.35
1.65
0.25
4.90
COMMON ASSUMPTIONS TO ALL ELECTRIC ENERGY PLANS
50 years
3.00
0.89
0.25
3.99
1. Current utility plans for generating system additions proceed as
planned. The Bradley Lake hydroelectric project is built and comes on-
line in 1988.
2. Existing generating units are retired based on assumed economic
lifetimes.
3. The electrical transmission interconnection between Anchorage and
Fairbanks is completed in 1984 and strengthened as necessary to allow
economical power exchanges between Fairbanks and Anchorage.
4. The Glennallen-Valdez load center electrical loads and generating
capacity are combined with Anchorage-Cook Inlet loads and generating
capacity.
E.3
GENERATING CAPACITY COST ESCALATION ASSUMPTIONS (1981 TO 2010)
1. Variable O&M Costs Escalation -2.0%
2. Fixed O&M Costs Escalation -2.0%
3. Capital Cost Escalation -1.4%
PLANNING RESERVE MARGIN & LOSS ASSUMPTIONS
1. Planning Reserve Margin -30%
2. Loss and Unaccounted Energy -8%
E.4
Plan lA "Pr.esent Practices" Without Upper
Susitna
lB "Present Practices" With Upper
Susitna
2A "High Conservation and Renewables"
Without Upper Susitna
2B "High Conservation and Renewables"
With Upper Susitna
3 "High Coal"
4 "High Natural Gas"