HomeMy WebLinkAboutSelection of Electric Generation Alternatives for Consideration in Railbelt, Vol. II 1982Selection of Electric Energy
Generation Alternatives
for Consideration in Railbelt
Electric Energy Plans
Volume II
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
()Battelle
Pacific Northwest Laboratories
; I 4 i i; ,j "
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SELECTION OF ELECTRIC ENERGY GENERATION
ALTERNATIVES FOR CONSIDERATION IN
RAILBELT ELECTRIC ENERGY PLANS
Vol ume II
J. C. King
December 1982
Prepared for the Office of the Governor
State of Alaska
Division of Policy Development and Planning
and the Governor1s Policy Review Committee
under Contract 2311204417
Battelle
Pacific Northwest Laboratories
Richland, Washington 99352
Volume I
Volume II
Vol ume I II
Vol ume IV
Volume V
Vol ume V I
Volume VII
RAILBELT ELECTRIC POWER ALTERNATIVES STUDY
-Railbelt Electric Power' Alternatives Study: Evaluation of
Railbelt Electric Energy Plans
-Selection of Electric Ener~t Generation Alternatives for
Cons1derat1on 1n Ra11belt ectr1c Energy Plans
-Executive Summary -Candidate Electric Energy Technologies
for Future Appl1cat10n 1n the Ra11belt Reglon of Alaska
-Candidate Electric Energ~ Technologies for Future Application
in the Railbelt Region 0 Alaska
-Preliminary Railbelt Electric Energy Plans
-Existing Generating Facilities and Planned Additions for the
Railbelt Region of Alaska
-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
Vol ume IX
Volume X
Volume XI
Volume XII
Vol ume XI II
Volume XIV
Vol ume XV
Volume XVI
Vol ume XVII
-Alaska Economic Projections for Estimating Electricity
Requirements for the Railbelt
-Community Meeting Public Input for the Railbelt Electric
Power Alternatives Study
-Over/Under (AREEP Version) Model User's Manual
-Coal-Fired Steam-Electric Power Plant Alternatives for the
Railbelt Region of Alaska
-Natural Gas-Fired Combined-Cycle Power Plant Alternative for
the Railbelt Region of Alaska
-Chakachamna Hydroelectric Alternative for the Railbelt Region
of Alaska
-Browne Hydroelectric Alternative for the Rai"lbelt Region of
Alaska
-Wind Energy Alternative for the Railbelt Region of Alaska
-Coal-Gasification Combined Cycle Power Plant Alternative for
the Railbelt Region of Alaska
iii
SUMMARY
A major task of the Railbelt Electric Power Alternatives Study was to
identify electric power generating alternatives that are potentially applicable
to the Railbelt region and to examine their technical and economic feasibility
and environmental and socioeconomic effects. Technologies that appear best
suited for future application in the region were subject to additional study
and incorporated into alternative electric power plans for the Railbelt region
(Volume I). This report describes the selection of these alternatives.
A set of alternatives was selected for consideration in each of the four
Railbelt Electric Energy Plans. The four plans included the Present Practices
Plan, (a) the High Conservation and Renewables Plan, the High Natural Gas plan
and the High Coal Plan.
The selection of alternatives for each plan was based on the following
considerations:
• energy resource availability
• available unit sizes of candidate alternatives
• operating characteristics of candidate alternatives
• commercial availability of candidate alternatives
• estimated cost of power from candidate alternatives
• likely environmental effects of candidate alternatives
• public acceptance
• on-going studies of specific alternatives.
Alternatives selected for each plan are listed in Table S.l.
(a) Known as the ItBase Case" in Volume V.
v
TABLE S.l Alternatives Selected for Each Plan
Plan
Present High High
Alternative Practice Renewable Coal --
Coal Steam Electric X X X
Coal Gasification -X
Combi ned-Cyc 1 e
Natural Gas Combi ned-Cyc 1 e X X X
Natural Gas Combustion X X
Turbines
Natural Gas Fuel Cell
Stations
Natural Gas Fuel Cell -
Combi ned -Cyc 1 e
Natural Gas Cogeneration
Di st ill ate Combi ned -Cyc 1 e X X
Retrofit
Distillate Fuel Cell Station
Diesel Electric X X X
Bradley Lake Hydro X X X
Grant lake Hydro X X X
Chakachamna Hydro X X X
All i son Hyd ro X X X
Browne Hydro X
Snow Hydro X
Keetna Hydro X
Strandline lake Hydro X
Refuse Fired Steam Electric X
large Wind Energy X
Conversion Systems
Tidal Power X
Upper Susitna X{ a) X (a)
tal Assessed as speclfic variations to the Present Practices and High
Renewables plans.
vi
High
Natural Gas
X
X
X
X
X
X
X
X
X
X
SUMMARY
FIGURES
TABLES •
TABLE OF CONTENTS
1.0 INTRODUCTION.
2.0 THE CANDIDATE ALTERNATIVES •
3.0 APPROACH TO THE SELECTION OF ALTERNATIVES •
3.1 RAILBELT ELECTRIC ENERGY PLANNING THEMES.
3.2 SELECTION CRITERIA •
Resource Availability
Available Plant Sizes •
Operating Characteristics.
Commercial Availability
Cost of Power •
Environmental and Socioeconomic Effects
Public Attitudes.
Ongoing Electric Power Planning Activities
4.0 SELECTION OF ALTERNATIVES
4.1 PRESENT PRACTICES PLAN •
Anchorage Load Center •
Fairbanks Load Center •
Glennallen-Valdez Load Center
4.2 HIGH CONSERVATION AND RENEWABLES
Anchorage Load Center •
Fairbanks Load Center •
Glennallen-Valdez Load Center
4.3 THE HIGH COAL PLAN ALTERNATIVES.
Anchorage Load Center
Fairbanks Load Center •
Glennallen-Valdez Load Center
4.4 HIGH NATURAL GAS.
Anchorage Load Center •
Fairbanks Load Center •
Glennallen-Valdez Load Center
vii
• v
x
• 1.1
• 2.1
3.1
3.1
• 3.2
3.3
• 3.3
• 3.4
• 3.6
• 3.6
3.7
• 3.8
• 3.8
• 4.1
• 4.1
• 4.6
• 4.10
• 4.11
• 4.12
• 4.14
• 4.23
• 4.23
• 4.23
• 4.25
• 4.30
• 4.31
• 4.31
• 4.35
• 4.39
• 4.42
5.0 CONCLUSION . . . . . . . .. . . .. . . . . .. . .. • 5.1
APPENDIX A: TECHNICAL DATA SHEETS FOR ELECTRIC ENERGY GENERATION AND
CONSERVATION OPTIONS • • • A.1
REFERENCES • • • • • • • • • • • • . . . • • R.1
viii
FIGURES
1.1 Procedure Used to Select Generating Alternatives for Inclusion in the
Railbelt Electric Energy Plans. 1.3
4.1 Cost and Availability of Fossil-Fired Present Practice Alternatives
for the Anchorage Load Center 4.2
4.2 Cost and Availability of Hydroelectric Alternatives for the Anchorage
Load Center • 4.3
4.3 Cost and Availability of Present Practice Alternatives for the
Fairbanks Load Center.
4.4 Cost and Availability of Present Practice Alternatives for the
Glennallen-Valdez Load Center
4.5 Cost and Availability of Non-Hydro Renewable Alternatives for the
Anchorage Load Center •
4.6 Cost and Availability of Renewable Alternatives for the Fairbanks
Load Center •
4.7 Cost and Availability of Renewable Alternatives for the
• 4.4
• 4.5
• 4.15
• 4.16
Glennallen-Valdez Load Center • 4.17
4.8 Cost and Availability of High Coal Plan for the Anchorage/Fairbanks
Load Center • 4.27
4.9 Cost and Availability of Conventional and Advanced Natural Gas
Alternatives for the Anchorage Load Center.
4.10 Cost and Availability of Natural Gas Alternatives for the Fairbanks
Load Center
ix
• 4.36
4.40
TABLES
2.1 Energy Resources Available in the Rai'lbelt Region 2.2
2.2 Energy Conversion, Generation and Storage Technologies Available for
Commercial Order by Year 2000 2.3
2.3 Electric Energy Alternatives Available to the Railbelt Region. 2.4
4.1 Alternatives Recommended for Consideration in the Present Practices
Plan 4.13
4.2 Summary of Alternatives Recommended for Consideration in the High
Conservation and Renewables Plan 4.24
4.3 Alternatives Recommended for Inclusion in the High Coal Plan. 4.32
4.4 Alternatives Recommended for Inclusion in the High Natural Gas Plan 4.44
5.1 Alternatives Selected for Consideration in Rai'lbelt Electric Energy
Plans 5.3
16.1 Estimated Economic Limits to Microhydroelectric Development in the
Railbelt A.42
19.1 Estimated Economic Limits to Small Wind Energy Conversion System
Development in the Railbelt •
25.1 Capital Cost Real Escalation Series
25.2 Operation and Maintenance Cost Real Escalation Series
26.1 Fuel Prices Used for the Railbelt Electric Power Alternatives Study
x
• A.54
A.77
• A.78
A.80
1.0 INTRODUCTION
The Railbelt region of Alaska, as defined in this project, includes
Anchorage, Fairbanks, the Kenai Peninsula and the Valdez-Glennallen areas. The
region has a total population of approximately 260,000. about two-thirds of the
state's population. Currently installed generating capacity for the region is
approximately 1080 MWe (Volume VI).
A variety of energy resources is potentially available for producing
electric power in the Railbelt. Those currently used include natural gas,
coal, petroleum-derived fuels (distillate and residual oils), and hydropower.
Several additional resources, including peat, refuse-derived fuel. geothermal
power, wind, solar and tidal power. offer potential as future sources of
electric power. Numerous technologies are currently available to generate
electric power from these resources. Additional technologies. currently under
development. will become available in the future for producing electricity from
these resources.
To date several organizations, including the Corps of Engineers. the
Alaska Power Administration, the Alaska Power Authority. the Institute of
Social and Economic Research. and the existing Railbelt utilities have engaged
in various aspects of electric power planning. Several individual proposals
for electric power development are currently under study. including the Upper
Susitna hydroelectric project (Devil Canyon and Watana Dams) (Acres American
1981b), Cook Inlet tidal power development (Acres American 1981a). the Bradley
Lake hydroelectric project, the Grant Lake hydroelectric project (CH 2M-Hill
1980), the Allison hydroelectric project (U.S. Army Corps of Engineers 1981)
and the Chakachamna hydroelectric project (Bechtel 1981). To date, however,
no comprehensive electric power plan has been prepared for the Railbelt region.
The State of Alaska. Office of the Governor, contracted with Battelle-
Northwest to perform a Railbelt Electric Power Alternatives Study. A major
objective of this study was to develop and analyze alternative long-range plans
for electrical energy development for the Railbelt region. These plans will be
used as the basis for recommendations to the Governor and legislature for
Railbelt electric power development, including whether the state should
1.1
concentrate its efforts on developing the hydroelectric potential of the
Susitna River or pursue other alternatives.
Because of the variety of potential electric generating options available
to the Railbelt, one of the study's major tasks was to identify electric power
generating alternatives potentially applicable to the Railbelt region and to
examine their technical and economic feasibility and prospective environmental
and socioeconomic effects. Those alternatives that appear best suited for
future application to the region were studied further and were incorporated
into one or more electric power plans that were developed and assessed as part
of this project (Volume I).
The procedure used to select generating alternatives for inclusion in the
Railbelt electric energy plans is shown in Figure 1.1. A broad set of
potential alternatives was first defined. These were screened for technical
feasibility in the Railbelt region and for commercial availability by year
2000. This screening process and the resulting set of candidate alternatives
are described in Volume IV. The technical performance, fuel and siting
requirements, costs, environmental and socioeconomic effects and potential
Railbelt applications of each candidate alternative was assessed. The
resulting technical profiles are provided in Volume IV.
Using the information developed in the technical profiles, a set of
preferred alternatives was identified. The selection of these preferred
alternatives is the subject of this volume. The preferred alternatives were
then divided into two groups to determine whether additional information should
be compiled on each prior to incorporation into the electric energy plans. One
group consisted of alternatives for which substantial information was available
on the cost and performance of the alternatives in the Railbelt. This group
included alternatives for which feasibility or engineering studies had been
recently performed, as well as alternatives for which cost and performance
characteristics are well documented in the resource profiles. Key cost and
performance characteristics of these alternatives were compiled into technical
data sheets (Appendix A).
The second group of alternatives consisted of alternatives for which
cost and performance characteristics were less well understood. Individual
1.2
W
POTENTIAL
ALTEPNATIVES
IV
FEASIBILITY
STUDIES
XII
XIII
XIV
XV
XVI
XVII
EXISTING
I NFORMA TlON
IV
ACRES (I 981a)
ACRES (198Ib)
BECHTAL (19al)
CH2 M-HILL (l9aO)
USACE (1981)
SCREENING
OF
POTENTIAL
ALTERNATIVES
IV
CANDIDATE
AL TER~IATIVES
IV
PRESENT
ASSESSMENT
OF
CANDIDATE
ALTERNATIVES
IV
PRACTICES
PRESENT
PRACTICES
W/SUSITNA
HIGH CONSERV-
ATION AND
RENEWABLES
HIGH CONSERV-
ATION AND
RENEWABLES
W/SUSITNA
HIGH COAL
HIGII GAS
RAILBELT
ELECTRIC
ENERGY
PLAN
ASSESSMENT
I
SELECTION
OF
PREFERRED
ALTERNATIVES
II
FIGURE 1.1. Procedure Used to Select Generating Alternatives
for Inclusion in the Railbelt Electric Energy Plans
PREFERRED
ALTERNATIVES
II
feasibility studies were performed on these alternatives (Volumes XII through
XVII). Key cost and performance data were extracted from these feasibility
studies and compiled on technical data sheets. The technical data sheets
(included as Appendix A to this report) were used as the source of generating
alternative cost and performance information for operation of the capacity
addition model (AREEP, Volume XI) used to assess the six Railbelt electric
energy plans considered in the study (Volumes V and I).
This report consists of four chapters following this introduction and a
major appendix. The second chapter includes an overview of the candidate
electric power generating alternatives potentially applicable to the Railbelt
region. Chapter 3.0 contains a discussion of the approach to the selection
process. Chapter 4.0 discusses the selection of alternatives and the merits of
individual candidates. Chapter 5.0, Conclusion, includes the list of
alternatives selected for consideration in the development of Railbelt electric
power plans. Also included is a discussion of the approaches taken to develop
additional information on the alternatives required to compare alternative
Railbelt electric energy plans. This volume concludes with an appendix of
technical data sheets on the preferred generating and conservation alternatives
selected for consideration in the Railbelt electric power plans.
1.4
2.0 THE CANDIDATE ALTERNATIVES
Candidate electric generating alternatives were selected based on two
considerations: 1) energy resources available in the Railbelt and 2) gener-
ating technologies using these resources likely to be available for commercial
order by year 2000. Year 2000 was selected as a cut-off date because tech-
nologies becoming available for commercial order beyond year 2000 would not
significantly contribute to meeting the Railbelt's electric energy demand
before the end of the planning period (2010). Moreover, uncertainties in the
introduction date, technical performance and cost of technologies becoming
available beyond 2000 are so great that plans based on their use would be
highly speculative at best.
Primary energy resources available or potentially available in the
Railbelt in sufficient quantity to support electric power generation are listed
in Table 2.1. In addition to the indigenous resources listed in Table 2.1,
fabricated nuclear fuel could be imported from manufacturers in the "lower 48"
states.
Twenty electrical generating technologies using these resources were
identified as currently available or forecasted to be available for commercial
order by year 2000. These are listed in Table 2.2. Discussion of these
technologies is provided in Volume IV.
The 38 specific electric energy alternatives listed in Table 2.3 are
combinations of energy resources and generating technologies that could be used
to produce electric power based on energy resources available in the Railbelt
region. This table also indicates when these alternatives would be available
for service in the Railbelt region. The estimated earliest in-service dates
consider availability of the technology for commercial order; design,
construction and licensing lead times; and availability of fuels.
2. 1
Resource
Coa1
Natural gas
Petroleum products
Peat
Municipal Refuse
Wood Residue
Geothermal Energy
Hydro
Tidal power
Wind
Solar
TABLE 2.1. Energy Resources Available
in the Railbelt Region
Principal Sources
Beluga Field (north of Cook Inlet)
Nenana Field (Healy)
Cook Inlet Fields and Kenai
Peninsula
North Slope Fields
Cook Inlet Fields, Cook Inlet
and Kenai Peninsula, refined at
Kenai
North Slope Fields, refined at
North Pole
Kenai Peninsula
Lower Susitna Valley
Tanana Valley
Anchorage
Fairbanks
Kenai/Soldatna
Anchorage area
Nenana area
Fai rbanks area
Wrangell Mountains
Chigmit Mountains
Kenai Mountains
Chigmit Mountains
Susitna River system
Nenana River system
Other Locations
Cook Inlet
Isabell Pass area
Offshore
Throughout region
Primary Transportation Options(a}
Barge or collier transport to tidewater
locations
Al aska Rai 1 road
Natural gas pipelines to Anchorage
Proposed North Slope natural gas pipeline
to Fairbanks and through Tanana Valley.
Proposed liquefaction of North Slope gas
with LNG pipeline transport to Fairbanks
and Anchorage
Product pipeline to Anchorage; rail
or truck tanker transport; barge (to
tidewater locations)
Rail or truck tanker transport
Truck Transport
Alaska Railroad; truck transport
Alaska Railroad; truck transport
Truck transport; railroad; barge (to
tidewater locations)
Truck transport; Alaska Railroad
TrUCk transport
Truck transport; Alaska Rail road
Truck transport; A 1 ask a Ra 11 road
Truck transport; Alaska Railroad
Transport generally not feasible
Transport generally not feasible
Transport not feasible
Not app 11 cab 1 e
Not applicable
Not applicable
Not app 11 cab 1 e
(a) Transportation options available for synthetic fuels derived from coal, peat, wood residue or
refuse-derived fuel not included.
2.2
TABLE 2.2. Energy Conversion, Generation and
Storage Technologies Available for
Commercial Order by Year 2000
Technology
Coal-Fired Steam-Electric
Gas or Distillate-Fired
Steam-Electric
Biomass(a)or Peat-Fired
Steam-Electric
Nuclear Light Water Reactor
Geothermal Steam Electric
Molten Carbonate Fuel Cells
Combined-Cycle
Combustion Turbines
Diesel Generators
Hyd roe 1 ect ri c
Phosphoric Acid Fuel Cells
Tidal Electric
Wind Energy Systems
Solar Photovoltaic
Hi crohydro( d)
Solar Thermal
Coal Gasification
Coal Liquefication
Peat Gasification
Pumped Hydroelectric
Compressed Air Storage
Storage Batteries
Typical Application
Baseload Generation
Baseload Generation
Baseload Generation
Baseload Generation
Baseload Generation
Baseload Generation
Baseload Load-Following Generation
Base10ad Load-Following or Resource
Generation
Baseload Load-Following or Resource
Generation
Baseload Load-Following Generation
Base10ad or Cycling Generation
Fuel-Saver Generation
Fuel-Saver Generation
Fuel-Saver Generation
Fuel-Saver Generation
Fuel-Saver Generation
Fuel Synthesis
Fuel Synthesis
Fuel Synthesis
Energy Storage
Energy Storage
Energy Storage
(al Wood residue or municipal waste.
Estimated Availability
for Commercial Order
Currently available
Currently available
Currently available
Currently available
1990-2000(b)
1990-1995
Currently available
Currently available
Currently available
Currently available
1985-1990
Currently available
1985-1990
1985-1990( c)
Currently available
1995-2000
1985-1990
1985-1990
1990-2000
Currently available
Currently available
1985-1990
(b) Dates given are for hot dry rock technology applicable to Rai1be1t geothermal resources
as currently understood. Hydrothermal technology is currently available.
(c) Photovoltaic technology is currently available though not cost competitive with other
technologies. Dates given are estimates for low-cost large arrays.
(d) Hicrohydroelectric units are generally defined as those of 0.1 MW capacity or less.
2.3
TABLE 2.3. Electric Energy Alternatives
Available to the Railbelt Region
Estimated
Earliest
Typical In-Service
Resource Alternative Apol;eation Date
Coal Coal Steam-Electric Baseload 1989
Coal Gasification -Baseload or Load 1991
Combined-Cycle Following
Coal Gasification -
Fuel Cell Combined-Baseload 1995
Cycle
Peat 'Peat Steam-Electric Baseload 1990
Peat Gasification -Baseload or Load 1995-2000
Comb; ned-Cye 1 e Foll owing
Peat Gasification -Baseload 1995-2000
Fuel Cell Combined-
Cycle
Natural Gas Natural Gas Combustion Baseload or Load 1984
Turbine Fo 11 owing
Natural Gas Combined-Baseload or Load 1985
Cycle Foll owing
Natural Gas Fuel Cell Baseload or Load 1987
Stations Following
Natural Gas Steam-Baseload 1988
Electric
Natural Gas Fuel Cell Baseload 1995
Combi ned-Cyc 1 e
Fuel Oil Distillate Combustion Baseload, Load 1984
Turbine Following, or
Reserve
Di ese 1 El ectri c Baseload, Load 1984
Following, or
Reserve
Distillate Combustion-Baseload or Load 1985
Cycle Following
Distillate Fuel Cell Baseload or Load 1987
Stations Following
Distillate Steam-Baseload 1988
Electric
2.4
TABLE 2.3. (contd)
Distill ate Fuel Cell Baseload 1995
Combi ned-Cycl e
Geothermal Geothermal Steam-Baseload 1995-2000
Electric
Biomass Wood Residue/Municipal Refuse Baseload i987
Steam-Electric
Hydro Grant Lake Hydroelectric Baseload or Load 1988
Foll owing
Bradley Lake Hydroelectric Base load or Load 1988
Following
Devil Canyon Hydroelectric Baseload or Load 1993
Following
Watana Hydroelectric Baseload or Load 1993
Following
Snow Hydroelectric Baseload or Load 1990-1995
Following
Tustumena Hydroelectric Baseload or Load 1990-1995
Foll owing
Allison Hydroelectric Base load or Load 1990
Foll owing
Strandline Lake Hydroelectric Base load or Load 1990-1995
Foll owing
Bruskasna Hydroelectric Baseload or Load 1990-1995
Foll owing
Silver Lake Hydroelectric Base load or Load 1990-1995
Foll owing
Cache Hydroelectric Baseload or Load 1990-1995
Following
Johnson Hydroelectric Baseload or Load 1990-1995
Following
Browne Hydroelectric Base load or Load 1990-1995
Following
Tokachitna Hydroelectric Baseload or Load 1990-1995
Foll owing
Talkeetna II Hydroelectric Baseload or Load 1990-1995
Following
Hicks Hydroelectric Base load or Load 1990-1995
Following
2.5
Tidal
Wind
Solar
Nuclear
TABLE 2.3. (contd)
Lane Hydroelectric Baseload or Load
Fo 11 owing
Chakachamna Hydroelectric Baseload or Load
Following
Lower Chulitna Hydroelectric Baseload or Load
Following
Microhydroelectric
Cook Inlet Tidal Power
Project
Large Wind Energy
Conversion Systems
Small Wind Energy
Conversion Systems
Solar Photovoltaic
Stations
Solar Thermal Electric
Nuclear Steam-Electric
Fuel Saver
Fuel Saver(a)
Fuel Saver(a)
Fuel Saver
Fuel Saver(a)
Fuel Saver(a)
Baseload
(a) Could be base load or cycling if coupled with energy storage.
2.6
1990-1995
1990
1990-1995
1984
2000-2005
1990
1984
1995
2000
1994
3.0 APPROACH TO THE SELECTION OF ALTERNATIVES
The selection of alternatives for the Railbelt electric energy plans was
based on planning themes established for the preliminary Railbelt electric
energy plans (Volume V) and a set of specific criteria that were considered to
be important in selecting generating alternatives for further consideration.
This chapter first reviews the four planning themes selected for Railbelt
electric energy plans. Following this is a discussion of criteria pertinent to
the comparison and selection of alternatives to be considered within each
planning theme.
3.1 RAILBELT ELECTRIC ENERGY PLANNING THEMES
Four basic Railbelt electric energy plans were developed for comparison in
this study. Each represents an "energy future" that appears possible for the
Railbelt. The plans were developed to represent a range of reasonable
conservation and generation alternatives available to the region, including the
alternatives that are currently receiving the greatest interest within the
region.
A set of planning objectives was developed to serve as the basic framework
for developing the Railbelt electric energy plans. The planning objectives
were based on cited objectives of the State of Alaska (State of Alaska 1980),
current utility planning practice, and responses received from a public
participation effort conducted in conjunction with this study (Volume X). The
objectives included the following: 1) plans should endeavor to minimize the
cost of power; 2) one or more plans should emphasize conservation and the use
of renewable resources; 3) plans should endeavor to minimize adverse
environmental effects, including effects on fish and wildlife habitat, air-
quality effects, aesthetic effects and health and safety effects; 4) each
project under active consideration should be incorporated in one or more plans;
and 5) plans should incorporate a realistic extension of current Railbelt
electric power utility characteristics and planning. Based on these
objectives, the following Railbelt Electric Energy Plans were developed and
assessed (Volume I):
3. 1
PLAN 1: PRESENT PRACTICES. This plan would involve continued
development of generating capacity consistent with current trends. Two
cases are considered:
A. no development of the Upper Susitna project
B. eventual development of the Upper Susitna project.
Plan 2: HIGH CONSERVATON AND USE OF RENEWABLE RESOURCES. This plan
would emphasize the development of generating capacity based on renewable
resources plus tempering of demand by promotion of conservation
alternatives. As in Plan 1, two cases are considered:
A. no development of the Upper Susitna Project
B. eventual development of the Upper Susitna Project.
PLAN 3: HIGH COAL. This plan would involve a transition from current
generating practice to a substantial use of coal as a primary energy
resource.
PLAN 4: HIGH NATURAL GAS. This plan would involve continued use of
natural gas as a primary energy resource in the Cook Inlet area and
possible conversion to natural gas use in the Fairbanks area. As natural
gas supplies were depleted. eventual transition to other energy resources
may be required.
3.2 SELECTION CRITERIA
Several criteria weighed in the selection of electric power generating
alternatives for consideration in the development and analysis of a given
Railbelt electric energy plan. These criteria include the following:
• the availability of suitable energy resources
• available plant sizes
• operating characteristics
• commercial availability
• estimated cost of power
• likely environmental and socioeconomic effects
• public acceptance
• on-going electric power planning activities.
3.2
These issues are discussed below.
Resource Availability
The primary energy resources currently used for power production in the
Railbelt include coal, natural gas, petroleum-derived liquids' and hydro power.
Energy resources that are not currently used but could be developed for the
generation of electric power include peat, tidal power, wind, solar energy,
municipal refuse and wood residue. Nuclear fuel could be imported to the
Railbelt if desired. Important considerations in the use of energy resources
include abundance, transportability and cost. Each of the resources cited
above appears to be available in sufficient quantities to potentially support
utility-scale generating facilities. Some of the renewable resources are
available only cyclically or intermittently and cannot be stored in their "as-
received" forms. These resources, which include wind, solar and tidal
resources, must be used when received or converted to a storable form of
energy.
The transportability of the various resources controls the potential
locations of power-generating facilities based on these resources. Renewable
resources, with the exception of wood residue and municipal refuse, are not
transportable and must be used onsite. Coal is economically transported in the
quantities used by typical coal-fired power plants only by barge or rail.
Natural gas and petroleum products may be readily transported in bulk
quantities using pipeline. The transportability of Railbelt energy resources
is summarized in Table 2.1.
Finally, the cost of energy resources ;s an important factor in
determining the cost of power produced by the associated generating
alternatives. For example, over the lifetime of a coal-fired generating plant
located in the Railbelt, approximately 40% of the cost of power generated by
the plant is attributable to fuel cost. Because fuel is purchased throughout
the lifetime of the plant, it affects the sensitivity of the alternative to
inflation.
Available Plant Sizes
Certain alternatives are available only in large plant sizes.
Construction of generating alternatives having large unit sizes compared to
3.3
electrical demand in the Railbelt may not be desirable for several reasons.
First, development of a unit having large rated capacity in comparison with
demand may result in surplus capacity for a prolonged period following initial
plant operation. This will increase power production costs. Secondly,
development of a system consisting of relatively few large units may reduce
system reliability and may require greater reserve capacity to provide an
acceptably low loss-of-load probability, again increasing costs. Finally,
provision of large baseload units in a small system with substantial seasonal
peaking may require additional load-following capacity to be installed or the
baseload units to be operated in a less efficient cycling mode.
Operating Characteristics
Inherent operating characteristics of alternatives govern their
application to electric energy systems. Of particular significance are the
load-following characteristics of power plants. Three typical load-following
characteristics are recognized: baseload, peaking (load following) and fuel
saver.
Baseload plants provide large amounts of power at a steady production rate,
generally at a relatively low cost. Certain generating alternatives are best
suited to steady-state operation. Examples include most steam-electric
facilities (coal, gas, oil, nuclear, and geothermal). These plants are
generally operated in a baseload mode for much of their lives. As this type of
plant ages and lower cost alternatives become available for baseload service,
they may be shifted to intermediate cycling operation to meet seasonal peak
demands, often at a sacrifice of operating efficiency. An additional and
important factor motivating the use of certain alternatives as baseload
alternatives is the ratio of fixed to variable costs. Alternatives having high
fixed and low variable costs may be economical only if operated at or near
maximum capacity. This is true of nuclear, geothermal and many hydroelectric
facilities.
Peaking (load-following) plants are capable of rapid adjustment of power
level to meet demand. In addition, these alternatives often have relatively
low fixed costs compared to variable costs. For these reasons, these
alternatives are used for load following to meet daily or seasonal peaks. Most
alternatives capable of load following are technically capable of being used in
3.4
baseload operation as well. Low conversion efficiencies or high fuel costs of
these alternatives may, however, render them undesirable baseload service.
Fuel-saver alternatives are available intermittently. These include
alternatives relying on solar, wind or tidal power. Alternatives based on
these resources typically operate in a "fuel-saver" mode. Because the fuel for
these alternatives is essentially free, their variable costs of operation are
less than baseload plants. Thus, when available, they generally operate at
baseload capacity, thus saving variable costs of the baseload or cycling plants
being displaced. Energy-storage devices may be installed in conjunction with
alternatives based on intermittent resources to store any surplus energy
produced during daily low load periods and to shift power output of these
devices to the peak load periods of the day. Thus equipped, these plants are
capable of offsetting the variable costs of peaking facility operation
(generally greater than the variable costs of baseload facilities).
Energy-storage technologies may be used in conjunction with fuel-saver
options, as discussed above. Alternatively, energy-storage options may be
charged using low cost power from baseload alternatives, then discharged to
meet peak power demands. This type of operation is especially desirable in
systems having a high daily load factor.(a} Because of the high capacity
(fixed) costs of storage options, they can generally be economically justified
only for meeting short duration (e.g. daily) peaks.
A final operational consideration is startup capability. Rapid startup
capability is needed for emergency reserve units. Certain generating
alternatives are slow to bring on-line, notably the steam-electric
technologies. Other technologies, including hydroelectric facilities,
combustion turbines, and diesel generators can be brought on-line quickly from
a cold start and thus serve well as emergency reserve capacity.
Generating alternatives having baseload and cycling capability must be
provided in any electric power system. Reserve capacity is also required,
either as normally operating units with surplus capacity or as units dedicated
(a) Load factor is the ratio of peak load to baseload. Baseload is the minimum
system load during a given period of time.
3.5
to reserve service. Fuel-saver plants may be desirable, if a good fuel-saver
resource is available and if the variable costs of baseload or peaking plants
are relatively high. Energy storage facilities may be useful to utilities
characterized by high daily load factors.
Commercial Availability
The time frame of Railbelt Electric Power Planning Study is a 30-year
planning period extending from 1980 to 2010. During this period, several
electric power production technologies currently in the development or
demonstration stage most likely will attain commercial maturity. Examples of
such technologies include synthetic fuels production from coal or peat, fuel
cells, advanced combustion turbines, and solar thermal and photovoltaic
devices. Although generally not presently competitive with conventional
generating alternatives, and in many cases not fully developed, some of these
advanced technologies may be competitive within the planning period. With the
exception of the Present Practices plan, which considers proven technologies
only, the potential desirability of advanced technologies is considered at the
time they are anticipated to be available for commercial operation.
Cost of Power
The power costs used for selection of alternatives is busbar power cost
based on the net revenue requirement of alternatives. The net revenue
requirement includes recovery of capital costs, fixed and variable operating
and maintenance expenses, fuel costs, and return on investment. The net
revenue requirements used in this report for comparison of alternatives are
levelized lifetime unit costs of power, expressed in 1980 dollars.(a} Use of
levelized lifetime costs for cost comparison provides a way of comparing
alternatives that may have quite different cost profiles over their operating
lives. For example, use of levelized costs permits comparison of a
hydroelectric facility having a fairly uniform power cost throughout its
operating life with a distillate-fired generating plant subject to increases in
fuel and operating costs. Levelized costs, however, can be misleading as they
{a} Note that the costs cited in the technical data sheets of Appendix A are in
January 1982 dollars to conform to the convention established for
comparison of Railbelt electric energy plans (Volume I).
3.6
do not correspond with the actual power costs to be expected early in plant
life, except for facilities such as hydroelectric plants, which are not greatly
subject to escalation or general inflation. For most alternatives levelized
costs will be greater than first-year power costs. Further discussion of net
revenue requirements and levelized costing methodology is provided in Volume IV.
The cost comparisons drawn in this document are largely independent of
application of alternatives in the power system in which they may be
installed. It is important to recognize that complete cost comparison of
electric power generating alternatives should consider the value of the
alternative to the system. For example, a fuel-saver alternative is worth more
to a system having baseload capacity using expensive fuel (for example,
distillate) than to a system having baseload capacity using relatively low cost
fuel, such as coal. As a second example, a hydroelectric facility having
substantial installed capacity but relatively low annual energy production
capability may be worth more to a utility needing reserve capacity than to a
utility having abundant reserve capacity. The costs of alternatives in a
systems context were compared during the analysis of Railbelt electric energy
plans (Volume I).
Environmental and Socioeconomic Effects
If equipped with appropriate environmental controls, each of the
alternatives of Table 2.3 is capable of complying with current environmental
standards applicable to Railbelt installations. Moreover, none of the
alternatives are thought to result in profound environmental or socioeconomic
effects of regional consequence. Some of the alternatives, such as those
requiring mining of coal or peat and certain hydroelectric alternatives, are
likely, however, to result in local impacts of considerable significance.
Consideration of environmental and socioeconomic effects beyond those
controlled by state and federal regulations is important in the selection of
alternatives for future application in the Railbelt, as evidenced by the high
level of public interest in the environmental ramifications of the proposed
Upper Susitna Project.
3.7
Public Attitudes
A survey of public preferences of electric power system planning
objectives and electric energy supply and conservation alternatives was
conducted in conjunction with this study (Volume X). The objectives of this
survey were to gain understanding of public attitudes relative to electric
power system planning objectives and to obtain measures of citizen attitudes on
issues relating to the selection of electric power supply and conservation
alternatives. Responses to the questions on planning objectives were used in
developing the overall framework of the preliminary Railbelt electric energy
plans, as discussed in Volume V.
Ongoing Electric Power Planning Activities
An appraisal of future electric power conditions in the Railbelt must
recognize effects of current planning activities, if implemented. Recent power-
related planning studies in the Railbelt region include the Anchorage-Fairbanks
electric intertie study. the Upper Susitna hydroelectric study. the Bradley
Lake hydroelectric study, the Grant Lake hydroelectric study, the Chakachamna
hydroelectric study, the Cook Inlet tidal project study, and various power-
related resource development studies. These latter studies include the North
Slope natural gas pipeline. the Pacific Alaska Liquified Natural Gas (LNG)
development, the Dow-Shell petrochemical study, and studies relating to
development of the Beluga coal field. In general, any project for which
planning is in progress was included in one or more electric energy plans, as
appropriate.
3.8
4.0 SELECTION OF ALTERNATIVES
The purpose of this chapter is to discuss the selection of electric power
generating alternatives for inclusion in the four Railbelt electric plans.
Candidate alternatives were first organized into groups corresponding to the
four Railbelt electric energy planning themes. The alternatives were compared
based on the planning criteria discussed in the previous chapter, and a set of
preferred alternatives was selected for inclusion in each of the four plans.
4.1 PRESENT PRACTICES PLAN
Candidate alternatives for the Present Practices plan included those based
on demonstrated technologies with emphasis on energy resources and technologies
currently in use in the Railbelt. Resources considered included coal, natural
gas, fuel oil, hydro, and nuclear. Conversion technologies included combustion
turbines, combined-cycle plants, direct-fired steam-electric plants,
hydroelectric plants, and light water reactors. Future use of these
technologies for electric power production in the Railbelt would minimize risk
from the perspective of technology and resource development. Costs and
performance of these technologies are relatively well understood compared to
developing technologies. The principal uncertainties relative to use of these
technologies include the licenSing and construction lead times of large-scale
coal, nuclear and hydroelectric projects, global environmental impacts of
combustion-based technologies and long-term operational reliability of light
water reactors.
The relative costs of energy production using the Present Practices
alternatives are given in Figures 4.1 through 4.4. Plotted in Figure 4.1 are
levelized lifetime energy costs for fossil fuel alternatives available to the
Anchorage load center, brought on-line at various times during the planning
period. Similar costs are presented in Figure 4.2 for hydroelectric
alternatives available to the Anchorage load center. Costs of nonhydroelectric
resources are calculated using a 65% capacity factor; hydroelectric costs are
based on forecasted annual average energy production.
Electrical interconnection of the Anchorage and Fairbanks load centers was
assumed for this study. However, additional generating capacity could be
4. 1
III
l-
to 200
..-
0
"C
0
00
0\ .. ..c:
:JI:
~ .......
III 150
.--.--
.....
III
0 u
-Po >, . 0'1
N s.... 100
QJ
C
1..1.1
QJ
E
.....
QJ ..... . ,...
-.J
"C
QJ 50
N
.--
QJ > QJ
-.J
1980
o Earliest Conlnercial Service Date
Inferred Costs
0-----;..=
Ga s Combu s t i on o-:~;;;::::::~~:::-----====:::=:::::::::::::::::::..
Turbine (70 r·tW) __ --.. ---r;r'*o:-----
0--------------------------
(31 mills)
(a) Beluga Coal
1990 2000
Fi rs t Year of COllli1erci a 1 Servi ce
l istillate Combustion Turbine
(70 r>1~J)
Distillate Steam Electric
(200 HW)
Diesel Electric (12 11W)
Distillate Combined Cycle
(200 t1W)
Gas Steam Electric (200 1·1W)
Gas Combined Cycle (200 i'11~)
Coal Steam Electric (200 IIW) (a)
Light ~Jater Reactor
2010
FIGURE 4.1. Cost and Availability of Fossil-Fired Present Practice
Alternatives for the Anchorage Load Center
1980 19 0 20 0
First Year of Co~nercial Service
FIGURE 4.2. Cost and Availability of Hydroelectric Alternatives
for the Anchorage Load Center
20 0
........,
I/) s...
ro
0 200
-c
Cl co m .. ..c;
3:
..lol
"'-I/)
150
.j..J
VI
0
U
>,
01 s...
QJ
.po c: . lJ.J 100 .po QJ
E .,...
.j..J
QJ
'+-.,...
....I
-c
QJ
N
,... 50 QJ
> QJ
....I
0 Earliest Commercial Service Date (North Slope) Gas Steam
Electric (10 MW) ---Inferred Costs
---
0--0-----
(North Slope) Gas Combustion
Turbine (50 MW)
Uistillate Steam Electric
(10 1·1W)
Distillate Combustion
T u rb 1 ne (50 ~1W)
/
(North Slope) Gas Combined
Cycle (90 MW)
Diesel Electric (12 MW)
Distillate Combined Cycle
o----:::;111"'.......::::~--~:::::::_OO.......::::~:::::=__.......:::::;;.--., (90 ,·tW)
Johnson (210 '·1W)
..,-tIIIfIIIIII"'''-:' __
o-t:J=.----cll==---------'------------Urowne (90 I·IW)
_-f 0-----0-
~Retrofit Distillate
__ ----....:..--------------Coal Steam Electric (20 I1W)
Combined Cycle (90 In~)
1990 2000
First Year of Commercial Service
FIGURE 4.3. Cost and Availability of Present Practice
Alternatives for the Fairbanks Load Center
2010
VI L-
tG
.-
0
"0 200
0 co en .-..
.J::.
3: ..:..: .......
VI
=: 150
.....
VI
0
U
>, c:n
L-a;
-I::> s::: . LLI
U1 a;
E 100 ..... ..... a; .... ....
...J
"0 a;
N .... .-a;
> a; 50
...J
o
0--
0--
Earliest Commercial Service Date
Inferred Cos ts
--
---
o
/
Disti11ate Steam Electric
(10 r1W)
Distillate Combustion Turbine
(50 MW)
....... Coa 1 S team-E 1 ec tri c (20 r.n~)
Diesel -Electric (12 MW)
0----------------------------------
All i son (8 f1W)
Silver Lake (10 MW)
19 0 2000 20 0
First Year of Commercial Service
FIGURE 4.4. Cost and Availability of Present Practice Alternatives
for the Glennallen-Valdez Load Center
required in the Fairbanks load center if the Fairbanks load increased beyond
intertie capacity, if it is needed for reliability. The costs of Present
Practices alternatives available to meet prospective needs within the Fairbanks
load center are shown in Figure 4.3.
Finally, the Copper River Valley is electrically independent of the other
load centers. Future capacity needs in this subregion could be met by
constructing a transmission tie from the Anchorage load center, or by
developing generating capacity within the Copper River subregion. The costs of
Present Practices alternatives available to this subregion are shown on Figure
4.4. (Costs in Figures 4.1 through 4.10 before 1990 are inferred or
extrapolated.)
Not shown in Figures 4.1 through 4.4 are the Watana or Devil Canyon dams
of the Upper Susitna project. These alternatives were included and a specific
variation of the Present Practices plan was separately assessed.
The principal criteria used for selecting alternatives for consideration
in the Present Practices plan included availability of the energy resource,
availability and maturity of generating technologies and cost effectiveness.
Also considered were the prospective environmental effects of technologies.
Anchorage Load Center
Alternatives available to the Anchorage load center in the near-term
(present to 1990) include combustion turbines and combined-cycle plants, firing
either fuel oil or natural gas; steam-electric plants, firing coal, fuel oil or
natural gas; and the Bradley Lake and Grant Lake hydroelectric projects.
Of the available alternatives, natural gas combined-cycle power plants are
the most cost-effective alternative available in the near-term with large
potential for capacity expansion ( 1000MW) relative to the current installed
capacity (711 MW) of the Anchorage load center. Natural gas combined-cycle
plants are a mature technology currently in use in the Railbelt with flexible
operating characteristics (both baseload and load-following operation are
feasible) and modest environmental effects. Because of these favorable
characteristics and because of the potential need for capacity and energy in
advance of or in addition to that potentially provided by the hydro plants
available in the near-term, natural gas fixed combined-cycle plants will be
considered for use in the Present Practices plan.
4.6
Development of natural gas combined-cycle capacity for baseload operation
would require an exemption from the Fuels Use Act. If such an exemption cannot
be obtained, the next most cost-effective alternative having large developable
capacity in comparison with current Railbelt requirements is coal steam-
electric plants. Environmental impacts of these plants are more severe than
for natural gas-fired facilities; however, mining impacts would likely be
incremental only as coal would be supplied from the existing Healy mine, or
from Beluga mines opened to supply an export market. Estimated energy costs of
coal plants include allowance for emission controls meeting current federal
standards. Use of these controls should not result in significant regional
impact, although questions remain concerning global effects of CO 2 and
residual SOx emissions.
Alternatives available in the near-term and having greater cost-
effectiveness than new natural gas combined-cycle plants include the Bradley
Lake and Grant Lake hydro projects. The 90 MW Bradley Lake project has been
authorized and will thus be included in the Present Practices plan (as well as
the other plans).
The proposed Grant Lake hydro project is a small (7.3 MW) lake-tap project
at Grant Lake, north of Seward. The level of Grant Lake would be raised by use
of main dams and cofferdams, and the flow of Grant Creek diverted through a
conveyance pipe and penstocks to a powerhouse at Trail Lake. The principal
environmental impact would be dewatering Grant Creek, destroying the anadromous
fishery of this stream. Mitigation potential exists, either by locating the
powerhouse on lower Grant Creek or by developing new spawning sites elsewhere.
Because of the apparently favorable economics of this project and because
mitigation of environmental impacts appears to be possible, consideration of
the Grant Lake project in the Present Practices plan is recommended.
Alternatives available to the Anchorage load center in the mid-term (1990
to 2000) include, in addition to the alternatives available in the near-term,
light water reactor plants, and several hydroelectric projects (Figure 4.2).
During the first part of the mid-term period, the most cost-effective
alternative with large potential for capacity expansion continues to be natural
gas-fired combined-cycle plants; however, by 1994, a light water reactor could
4.7
be in-service with estimated busbar energy cost of 31 mills/kWh (if the output
of the plant were fully used).(a) This alternative is not, however,
recommended for consideration in the Present Practices plan primarily because
the smallest available unit size (800 MW) approximates the current combined
capacity of the Anchorage and Fairbanks load centers (926 MW). A single unit
of this size would be inappropriate for the Rai"lbelt due to reliability and
scheduled outage reserve requirements. In addition, existing Alaska statutes
do not permit the use of state funds for promoting of nuclear electric
generating plants. For these reasons and because of the general public
opposition to the nuclear alternative, further consideration of light water
reactors is not recommended.
Alternatives that are more cost effective than natural gas combined-cycle
or coal steam-electric plants during the mid-term period include the
Chakachamna and Lower Chulitna hydroelectric projects. The proposed
Chakachamna project is a transmountain diversion hydroelectric project drawing
upon Lake Chakachamna, northwest of Cook Inlet about 85 miles west of
Anchorage. Proposed installed capacity ranges from 330 to 480 MW depending
upon the minimum flow to be retained in the natural lake outlet stream, the
Chakachatna River. The principal environmental impact of the project would be
potential disruption or destruction of the anadromous fishery of the
Chakachatna River. This impact can be mitigated by retaining Chakachatna
flow. This, however, would reduce the capacity and energy available from the
project (330 MW capacity/1446 GWh annual firm energy vs. 480 MW/1845 GWh).
Because of the potential cost effectiveness of this project and because
environmental effects can potentially be lessoned, it is recommended for
inclusion in the Present Practices plan.
The Lower Chulitna project is a proposed dam and reservoir hydroelectric
project located on the Chulitna River north of Talkeetna. The potential
capacity of this project has been estimated as 90 MW, producing 394 GWh
annually. Levelized life-cycle costs, based on very preliminary estimates,
appear to be competitive with natural gas combined-cycle plants about 1995.
Environmental impacts are potentially severe, including blockage of anadromous
fish runs of the Chulitna and inclusion of the site within an area considered
(a) See Figure 4.1 for the estimated busbar cost of a natural gas-fired
combined-cycle plant. 4.8
for wilderness designation. Because of the apparently significant
environmental impacts of this project, it is not recommended for consideration
in the Present Practices plan.
Alternatives available to the Anchorage load center in the long-term (2000
to 2010) under the Present Practices plan are essentially similar to those
available during earlier periods. Coal steam-electric plants remain the most
cost-effective option having the potential for large capacity in relation to
potential electrical demand. Because of forecasted escalation in coal prices,
two additional hydroelectric projects, the Tokichitna project and the Lane
project, become more cost effective than coal.
The Tokichitna project is a proposed high dam and reservoir located on the
Chulitna River above the Lower Chulitna site. The potential capacity of the
site is estimated to be 184 MW with annual firm energy production of 806 GWh.
Based on very preliminary information, the busbar energy cost is estimated to
be 64 mills/kWh. The principal environmental impact would be blockage of the
anadromous fish run of the Chulitna River; in addition, the project borders a
primitive area. Because of the potential impact on anadromous fisheries and
the insignificant cost advantage compared to coal steam electric plants, this
project is not recommended for consideration in the Present Practices plan.
The Lane project is a proposed high dam and reservoir located on the
Susitna River north of Talkeetna. The potential capacity of the site is 240 MW
with annual firm energy production of 1052 GWh. Estimated busbar energy cost
is 65 mills/kWh, based on very preliminary information. The principal
environmental effects would be blockage of the anadromous fish runs of this
section of the Susitna River. Because of this potential impact, and the
insignificant cost advantage of this project compared to coal steam-electric
plants, the project is not recommended for inclusion in the Present Practices
plan.
By 2000, the existing combustion turbine plant in the Anchorage load
center will have reached retirement age. Construction of additional combined-
cycle plants and hydroelectric facilities by this time should provide capacity
for meeting peak load. If, however, additional peaking capacity is required,
4.9
or if capacity having short lead time is needed, combustion turbines using
natural gas appear to be the most cost-effective demonstrated technology
throughout the planning period.
Fairbanks Load Center
The Fairbanks load center is assumed to be electrically interconnected
with the Anchorage load center in the assessment of electric energy plans.
Moreover, the Fairbanks load center is presently characterized by surplus
capacity and high operating costs due to the extensive use of fuel oil for
electric power generation. However, additional generating capacity may be
required for the Fairbanks load center to meet load requirements in excess of
combined intertie and installed capability, or to meet reserve requirements.
Alternatives available to Fairbanks in the near-term include combustion
turbine, combined-cycle diesel, electric and steam-electric plants fired with
fuel oil and retrofit of existing combustion turbines for combined-cycle
operation. North Slope gas may become available as early as 1987 and could be
used to fuel combustion turbine, combined-cycle or steam-electric plants.
However, as indicated in Figure 4.3, at forecasted prices North Slope gas does
not appear to be competitive with continued use of fuel oil. Also available
late in the near-term period would be additional steam-electric plants using
Nenana coal.
An attractive alternative for obtaining additional power at Fairbanks
during the near-term is retrofit of the existing Golden Valley Electric
Association North Pole combustion turbines for combined-cycle operation.
Busbar power costs of a combined-cycle retrofit to existing combustion turbines
are estimated to be 86 mills/kWh in 1990. The incremental environmental
impacts of such a plant would be relatively minor. Moreover, the resulting
plant could be adapted to natural gas operation if North Slope natural gas
prices became competitive with fuel oil. Because of the age of the North Pole
turbines, this alternative would not be feasible much beyond 1990.
Additional coal steam-electric capacity based on Nenana (Healy) coal could
be brought on-line late in the near-term period. Costs of even a small plant,
as shown in Figure 4.3, are more competitive than any other alternative
available to Fairbanks, including the combined-cycle retrofit. Construction of
4.10
the Anchorage-Fairbanks intertie would make larger units feasible~ further
reducing energy costs. Incremental environmental effects would be minor since
the Healy mine is currently in operation, and the plant would include full air
emission controls as required by federal standards.
During the mid-term, two hydroelectric alternatives become available to
Fairbanks -the Johnson project on the Tanana River and the Browne project on
the Nenana River. Neither is economically competitive with the coal steam-
electric alternative.
No additional alternatives become available in the long-term, and coal
steam electric plants remain as the most cost-effective alternative for
Fairbanks.
By 2000, the existing combustion turbine capacity of the Fairbanks load
center will have reached retirement age. At this time additional low capital
cost capacity may be required for peaking, load-following and reserve
applications. The most cost-effective alternative for these applications
appears to be diesel-electric units. Consequently, these will be considered in
the Present Practices plan.
Glennallen-Valdez Load Center
The Glennallen-Valdez load center may remain electrically independent of
the Anchorage load center throughout the planning period. The costs of
alternatives available to the Glennallen-Valdez load center are shown in Figure
4.4. Available in the near-term are the Solomon Gulch hydro project (12 MW)
(under construction and not plotted in Figure 4.4), distillate oil-fired
combustion turbines and diesel-electric plants, and small fuel oil or coal-
fired steam-electric plants. The most cost-effective alternative available in
the near-term (following the Solomon Gulch project) would be diesel-electric
plants.
Alternatives available in the mid-and long-term include the Allison and
Silver Lake hydroelectric projects and various alternatives fired by fossil
fuels.
The Allison project is a proposed lake-tap hydroelectric project located
on Allison Creek near Valdez. Installed capacity would be 8 MW~ with an annual
firm energy production of 32.2 GWh. Estimated busbar power cost is 58
4.11
mills/kWh. The potential impact on the Allison Creek anadromous fishery would
be alleviated by tailrace discharge to Allison Creek during critical periods.
Because of the cost effectiveness and modest potential environmental impact of
this project, it is recommended for consideration in the Present Practices Plan.
The Silver Lake project is a proposed lake-tap hydroelectric project
located at Silver Lake near Valdez. This site was selected by Acres American
as a potential alternative to the proposed Upper Susitna Project (Acres
American 1981b) on the basis of potential environmental impacts (rated IIgood")
and cost. Busbar power costs, based on very preliminary information, were
estimated for this study to be 46 mills/kWh, competitive with other options for
the Copper River Valley. However, a Corps of Engineers feasibility study of
power for the Copper River Valley (USACE 1981) rejected Silver Lake in favor of
the Allison hydro project and pressure-reducing turbines on the Trans-Alaska
Pipeline descent. Further study of the Silver Lake project within the scope of
this project was not believed warranted due to its relatively minor potential
contribution in the context of the Railbelt as a whole. Because of the
uncertain information available on the Silver Lake project, it was not selected
for consideration in the Railbelt electric power plans. Further assessment of
the potential role of the Silver Lake project and pressure-reducing turbines
within the Copper River load center may be justified.
A summary of the generating alternatives recommended for inclusion in the
Present Practices plan is provided in Table 4.1.
4.2 HIGH CONSERVATION AND RENEWABLES PLAN
The candidate alternatives for the High Conservation and Renewables plan
("High Renewables ll
) are those based on geothermal, hydro, biomass, solar, wind
and tidal energy resources. The technology for power generation using these
resources is well demonstrated for hydro, and less so for biomass, wind, and
tidal resources. Technologies for using solar and the hot dry rock geothermal
resources that are believed to be characteristic of the Railbelt are in the
early stages of development or demonstration. Because the amount of power
available at reasonable cost from renewable resources using proven technology
(hydro) is relatively finite, cost-effective nonrenewable resources were also
considered in the selection set of alternatives for the High Renewables plan.
4.12
Period
Near-Term
(Present-1990)
Mid-Term
w (1990-2000)
Long-Term
(2000-2010)
TABLE 4.1 Alternatives Recommended for
Consideration in the Present
Practices Plan
Anchorage
Grant Lake Hydro
Bradley Lake Hydro
Natural Gas Combined Cycle
Coal Steam Electric
Renewable Options not
Developed in Near-Term
Chakachamna Hydro
Natural Gas Combined Cycle
Coal Steam Electric
Renewable Options not
Developed Earlier
Coal Steam Electric
Natural Gas Combustion Turbines
Load Center
Fairbanks
Coal Steam Electric
Retrofit Distillate
Combined Cycle
Coal Steam Electric
Coal Steam Electric
Diesel-Electric
(a) If not developed in the mid-term.
Glennallen-Valdez
Solomon Gulch Hydro
Diesel-Electric
Allison Hydro
Diesel-Electric
Allison Hydro(a)
Diesel-Electric
The cost and availability of renewable generating alternatives to the
Railbelt is shown in Figures 4.2, 4.5, 4.6 and 4.7. Nonhydro renewables
available to the Anchorage load center are shown in Figure 4.5. Also shown in
Figure 4.5 are the level;zed lifetime costs of natural gas-fired combined-cycle
plants - a possible supplement to renewable-based resources in the Anchorage
load center if sufficient renewable resources cannot be developed to meet
forecasted demand. Shown in Figure 4.2 are the costs of hydroelectric
resources available to the Anchorage load center during the planning period.
Not shown are the Watana and Devil Canyon dams of the Upper Susitna
hydroelectric project, as these alternatives will be included in a variation of
the High Conservation and Renewables plan to be separately assessed. Provided
in Figure 4.6 are the costs of renewable alternatives available to the
Fairbanks load center during the planning period. Finally, Figure 4.7 shows
the renewable resources available to the Copper River load center.
In the selection of alternatives for consideration in the High
Renewables plan, emphasis is placed upon the renewable character, environmental
compatibility and cost effectiveness of alternatives, in accordance with the
philosophy underlying this plan. Because of the somewhat limited availability
of renewable resources using proven technology on possible future Railbelt
electric demand, "backup" alternatives based on nonrenewable resources were
also chosen for consideration. These latter alternatives can also typically
be brought into service earlier than many of the renewable alternatives and
thus could provide power, if needed, in the near-term period prior to the
availability of longer lead time renewable alternatives. The primary criteria
used for selecting the backup nonrenewable resources were environmental
compatibility and cost effectiveness.
Anchorage Load Center
Nonhydroelectric renewables available to the Anchorage load center in the
near-term (present to 1990) include small wind energy conversion systems and a
steam-electric plant fired by municipal refuse. Hydroelectric alternatives
include microhydro plants and the Grant Lake hydro project (Figures 4.5 and
4.6). The 90 MW Bradley Lake hydro project ;s authorized and will be included
in the High Renewables plan.
4.14
III
L 200 OU
r-
r-
0
-0
0 co
0'\ ..
.J::
3:
~ 150 .......
III
r-
r-
or--.....
~
+-'
III
0
U
>,
~ 0'> 100 ~ . II!
I::
U1 I-LI
~
or-
+-' II!
'+-or-
-'
-0 50 II!
N
,....
II! > II!
-'
1980
. t
00 0 Earliest Commercial Service Date
+.>c'\J
O<D ---Inferred Costs .J::
Q.U
or-
LOU
ou+-'
r-r-
00 VI>
((d 100 Mills) 0
Large Wind (High)
0---------f1icrohydro (low)
0-----8 ~Tidal (High)
-So 1 ar Therma 1
(@ 60 I·1i 11 s ) ~ 6±i :: -Tidal (low) 0--------"-Refuse
Small Wind (Low) ~ ---=:::0 -Geotherma 1
--Large Wind ( lo~1)
~-..
Natural Gas Combined Cycle (200 f4W)
From Fia. 4.1
19 0 20 0 20 0
First Year of Commercial· Service
FIGURE 4.5. Cost and Availability of Non-Hydro Renewable
Alternatives for the Anchorage Load Center
111
I-
10 ..... ..... 200 0
"0
0 co
0'1 .....
~
3:
~ -.......
111 .-150 -
+-I
VI
0 u
>,
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41 c::
.j:::o. UJ 100 . 41 e en .....
+-I
41 4-
.....J
"0
41
N
.-50
QJ
>
41
.....J
1980
r 0 Earliest C~nmercia1 Service Date
I Inferred Costs 00
+-IN ----
01.0 ..r::
Q..U
or-
1-10
10+-1
..... r-oo
V'l>
0 Johnson (2lD r~W)
......... Large Wind (High)
0 ......... t1icrohydro (Low) 0-------Browne (90 MW) 0
_ Coal Steam Electric
0---= -----~olar Therma Q e use 0--
0---------Small Wind (Low)
0 Large Wind (Low)
1990 2000 tOlD
first Year of Commercial Service
FIGURE 4.6. Cost and Availability of Renewable Alternatives
for the Fairbanks Load Center
(20 I'Ivl)
VI
~
10 200
r-
0
-0
0
ex)
0'1 ..... ..
..c:: :::
~
........ 150 VI
...... -..-
....
VI
0 u
>.
C'l
~ 100 (IJ
+=> c: . UJ .......
(IJ -....J e .,... ....
(IJ
'+-
-I
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(IJ 50 N
(IJ
> (IJ
-I
19130
1
I
00
.... N
0'-0 ..c::
Q,.U .....
~IO
10 ....
r-.....
00
VI>
o Earliest Commercial Service Date
Inferred Costs
Diesel Electric (12 MW)
()L~
0-- --- - -~-.",....--..:::::::::...---------------
Large Wind (High)
tH crohydro (Low) --0-----
0------Solar Thermal
____ Small Wind (Low) 0---------()~===============-= Allison (B '·1W)
o Large Wind (Low)
o Silver Lake (10 MW)
1990 2000
First Year of Commercial Service
FIGURE 4.7. Cost and Availability of Renewable Alternatives
for the Glennallen-Valdez load Center
2010
The 7.2 MW Grant Lake project, discussed in the preceeding section, is
economically competitive with other renewable alternatives and will be included
in the High Renewables plan.
No microhydro capacity is anticipated to be available at energy costs less
than 100 mills/kWh. Thus, this alternative will not be included in the High
Renewables plan. At no point during the planning period does microhydro appear
to become competitive with other major sources of energy (Figure 4.5). Further
study of the microhydro alternative should receive low priority.
Approximately 28 MW of installed small wind capacity, producing 71 GWh
annual energy is estimated to be available in the Anchorage load center. This
would be a dispersed resource with development largely dependent upon
individual initiative. This would be a significant constraint to development,
perhaps limiting penetration of small wind to 10% of potential installations.
Because the resulting capacity is less than 5 MW and not significant in the
context of overall Rai1be1t electric energy plans, the potential contribution
of small wind was excluded from the High Renewables plan. The more favorable
small wind sites, however, appear to become economically competitive with least-
cost thermal resources during the 1990s (Figure 4.5). Further study of the
potential of this option is therefore recommended.
Sufficient municipal waste is forecasted to be available from the
Anchorage metropolitan area to support a steam-electric plant of approximately
50-MW installed capacity producing approximately 285 GWh of energy.
Supplemental firing with wood residue and coal would be required until 2010
when forecasted municipal refuse production rates would be sufficient to fully
fire a plant of this size. Estimated energy costs (Figure 4.5) decrease over
time as supplemental fuel requirements decline; further reduction in energy
production costs could be achieved by imposition of refuse tipping fees.
Because the estimated costs of power of refuse-fired steam-electric plants lie
within the range established for consideration in the High Renewab1es plan,
this alternative will be considered in that plan. Constraints possibly
restricting development of this alternative include its cost effectiveness
relative to other methods of refuse disposal, operational reliability, public
acceptance and atmospheric emissions.
4.18
The capacity and energy available from renewable resources selected for
the High Renewables plan in the near-term is 147 MW and 619 GWh, respectively.
Additional energy may be required. If so, natural gas combined-cycle plants
are the most cost-effective nonrenewable alternative available to the Anchorage
load center in the near-term. Coal steam-electric plants would be the next
most cost-effective thermal option if Fuel Use Act exemptions could not be
obtained for baseload application of natural gas.
Renewable alternatives available to the Anchorage load center in the mid-
term (1990 to 2000) include (in addition to alternatives available in the near-
term) large wind energy conversion systems, solar photovoltaic systems,
geothermal, and the Chakachamna, Lower Chulitna, Tokichitna, Lane, Snow,
Keetna, Strandline Lake, Browne, Johnson, Tustumena, Bruskasna, Hicks,
Tulkeetna II and Cache hydro sites (Figure 4.2).
Large wind energy conversion systems, probably similar to the DOE Mod-2
wind turbines currently being tested at Goodnoe Hills, Washington, could be
available for commercial operation in the Railbelt by 1990. A promising wind
resource in the area of Isabell Pass south of Big Delta has estimated annual
average wind power density of 400 to 2000 watts/m 2 at large wind turbine hub
height. Of additional significance is the seasonality of this wind resource.
Average wind power is greatest in fall, winter and spring, corresponding with
peak electrical load.
Estimated busbar cost of power from large wind turbines ranges from 54 to
100 mills/kWh, depending upon the quality of the wind resource. This cost
compares favorably with other renewable (and conventional) alternatives
available in 1990 and beyond. However, questions relating to the appropriate
capacity credit to be granted wind machines do not make it possible for this
cost to be directly compared to the busbar energy cost of alternatives having
firm capacity. Because of the promising wind resource of the Railbelt and
favorable environmental effects of wind machines, they will be considered in
the development of the High Renewables plan. Constraints potentially impacting
the development of this alternative include the technology's reliability,
especially under cold climate conditions, and its cost effectiveness in the
power system context.
4.19
If current prospects for future cost reductions in the manufacture of
large-scale solar photovoltaic arrays materialize, this alternative will have
the potential for producing power at costs competitive with other renewable
alternatives, even considering the seasonal limitations on sunlight of Railbelt
latitudes. However, current costs of production remain very high (greater than
600 mills/kWh) and the projected cost reductions rely on major breakthroughs in
production methods or cell efficiency. Moreover, seasonal correlation of
photovoltaic production with load would be unfavorable. Because of the great
uncertainty regarding future photovoltaic capital costs, the limited
information regarding solar insolation in the Railbelt, and the unfavorable
correlation of photovoltaic production with load, this alternative is not
recommended for further consideration within the scope of this study.
Future study may be warranted if significant reduction in photovoltaic costs
materialize.
Geothermal resources possibly suitable for generation of electric power
are known to exist near Mt. Drumm in the Wrangell Mountains and at several
locations in the Chigmit Mountains. These resources are thought to be hot dry
rock resources, although hydrothermal resources may be present. Information on
the quantity or quality of these resources is insufficient to support
estimates of the amount or cost of power, or the environmental effects likely
to result from development of these resources. Because of the lack of
information on the resource and the immaturity of hot dry rock technology, the
geothermal alternative is not recommended for further consideration in this
study. Because the estimated cost of power for geothermal power appears to be
potentially competitive with other alternatives, further study of Railbelt
geothermal resources is recommended.
Because of its cost effectiveness and potentially modest environmental
impacts, the Chakachamna hydroelectric project will be considered in the High
Renewables plan. Further discussion of this alternative appears in Section 4.1
of this report.
For reasons discussed in Section 4.1, the Lower Chulitna, Tokichitna and
Lane hydroelectric projects are not recommended for consideration in the High
Renewables plan.
4.20
The Snow project is a proposed high dam and reservoir located on the Snow
River north of Seward. Installed capacity would be approximately 50 MW with
estimated annual firm energy production of 278 GWh. The project could be in-
service in the 1990 to 1995 period. Estimated busbar power costs are 74
mills/kWh. The principal environmental impact would be potential conflict with
a proposed ecological reserve at this site. Because of the cost effectiveness
of this project relative to other renewable resources and its potentially
modest environmental impact, it will be considered in the High Renewables plan.
The Keetna/Talkeetna-II/Cache projects on the Talkeetna River are being
considered as a system. The total installed capacity of the three dams would
be approximately 200 MW (100 MW for Keetna, and 50 MW each for Cache and
Talkeetna II). Annual firm energy production is estimated to be 759 GWh (324
GWh for Keetna, 220 GWh for Cache and 215 GWh for Talkeetna II). These
projects could be in-service in the 1990 to 1995 period. Estimated busbar
energy costs are 77 mills for Keetna, 179 mills for Cache and 158 mills for
Talkeetna II. Environmental impacts could potentially be significant,
including blockage of the anadromous fish runs of the Talkeetna River and
impacts on primitive lands. It is thought, however, that development of the
three sites on one river would result in a more favorable project than
equivalent capacity developed on separate streams because of improved economic
potential of the integrated project and better downstream regulation (Acres
American 1981b). The most cost effective of the three sites, Keetna, was
selected for consideration in the High Renewables plan. Additional capacity,
if needed, could be obtained at little environmental impact by developing the
remaining two sites.
The proposed Strandline Lake project would consist of a diversion
structure and powerhouse located on the Beluga River northeast of Cook Inlet.
Installed capacity would be 20 MW and annual firm energy production would be
81 GWh. Estimated busbar power costs are 94 mills/kWh. The potential
environmental impact of this project appears to be minor, consisting
principally of possible effects upon scenic and primitive lands. Because of
energy costs within the 100 mill constraint established for the High Renewables
plan and because of potentially minor environmental effects, Strandline Lake
was selected for consideration in the High Renewables plan.
4.21
The Browne project is a proposed dam and reservoir on the Nenana River
north of Healy. Installed capacity would be approximately 100 MW, annual firm
energy 385 GWh. Estimated busbar energy cost is 95 mills/kWh. Potential
environmental impacts appear to be minor. Delivery of energy from this project
to the Anchorage load center would require completion of the Anchorage-
Fairbanks intertie. This project was selected for consideration in the High
Renewables plan due to its potentially modest environmental impact, fair cost-
effectiveness and location near the Fairbanks load center.
The four remaining hydroelectric projects, Johnson, Tustumena, Bruskasna,
and Hicks have estimated energy costs significantly higher than the 100
mills/kWh cutoff chosen for the High Renewables plan. Additional power, if
required, could be supplied by natural gas-based thermal resources.
Additional renewable resources becoming available to the Anchorage load
center in the long-term (2000 to 2010) include Cook Inlet tidal and solar
thermal.
A variety of tidal-electric power plants for Cook Inlet were assessed in
the Acres American study of this resource (Acres American 1981a). One site,
Eagle Bay, was recommended for further study. Two site designs were proposed,
one of 720-MW installed capacity producing 2050 GWh annual energy (with re-
timing), and one of 1440-MW installed capacity producing 3200 GWh of annual
energy (with retiming). Estimated energy costs are 70 mills/kWh for the
smaller facility and 73 mills/kWh for the larger facility. The facility could
greatly affect the tidal patterns and marine ecology of Knik Arm. Because of
the current interest in this alternative, the Cook Inlet Tidal project was
considered in the High Renewables plan
Forecasted production costs of solar-thermal plants are competitive with
other renewable resources. Energy production from these plants would be
intermittant unless energy storage were provided. In addition,coincidence of
seasonal production to load is poor for the Railbelt. For these reasons and
because of current uncertainty regarding the cost, availability and performance
of solar-thermal plants, this alternative was not considered.
4.22
The Fairbanks Load Center
Renewable alternatives available to the Fairbanks load center are shown in
Figure 4.6. Where available, renewable alternatives chosen for the Anchorage
load center were also selected for the Fairbanks load center. These included
large wind energy conversion systems, refuse-fired steam-electric plants, and
the Browne hydroelectric project. No microhydro power appears to be available
at costs less than 100 mills/kWh, and small wind potential at 100 mills/kWh or
less is less than one MW, assuming a 10% penetration. These alternatives were
consequently not included. If demand is greater than available renewable
resources, retrofit of the North Pole combustion turbines for combined-cycle
operation, followed by coal steam-electric plants, are the most cost-effective
options for Fairbanks.(a) Additional peaking or reserve requirements would
be met by most cost effectively using diesel-electric plants.
Glennallen-Valdez Load Center
With the exception of large wind energy systems, the alternatives
available to the Glennallen-Valdez load center for the High Renewables plan are
those available for the Present Practices plan (Figure 4.7).
A summary of the generating alternatives recommended for inclusion in the
High Renewables plan ;s provided in Table 4.2.
4.3 THE HIGH COAL PLAN ALTERNATIVES
Because of the abundance of the coal resource, its potential for
development for export markets, the forecasted relatively low cost of fuel on a
Btu basis and the prospects for sUbstantial improvement in operational
flexibility and environmental characteristics of coal-based technologies,
examining the possibility of emphasizing coal use for future electric power
development in the Railbelt was thought to be appropriate.
In the selection of alternatives for the High Coal plan, emphasis was
placed upon the use of coal or peat resources, cost effectiveness, and adoption
of advanced coal combustion technologies promising fewer environmental effects
(a) The combustion turbine retrofit would likely not be feasible after 1990 due
to the age of the North Pole units.
4.23
~
Period
Near-Term
(Present-1990)
N Mid-Term ~ (1990-2000)
Long-Term
(2000-2010)
TABLE 4.2 Summary of Alternatives Recommended for
Consideration in the High Conservation
and Renewables Plan
Anchorage
Grant-Lake Hydro
Bradley Lake Hydro
Natural Gas Combined-Cycle
Coal Steam-Electric
Renewable Options not
Developed in Near-Term
Chakachamna Hydro
Large Wind
Snow Hydro
Keetna Hydro
Strandline Lake Hydro
Browne Hydro
Natural Gas Combined-Cycle
Coal Steam-Electric
Renewable Options not
Developed Earlier
Cook Inlet Tidal
Coal Steam-Electric
Load Center
Fairbanks
Retrofit Distillate
Combined-Cycle
Coal Steam-Electric
Refuse Steam-Electric
Renewable Options not
Developed in Near-Term
Browne Hydro
Large Wind
Coal Steam-Electric
Renewable Options not
Developed Earlier
Coal Steam-Electric
Diesel-Electric
Glennallen-Valdez
Solomon Gulch Hydro
Diesel-Electric
Allison Hydro
Large Wi nd
Diesel-Electric
Renewable Options not
Developed Earlier
Diesel-Electric
and greater operating flexibility than conventional coal-based technologies.
Using advanced coal-based technologies may lesson concern for the environmental
effects of coal use expressed in the opinion surveys conducted in conjunction
with this study (Volume X). Additional benefit may be gained from the
increased operating flexibility promised by technologies using coal
gasification. These alternatives may provide load-following characteristics
superior to conventional coal steam-electric plants, reducing or eliminating
the need for natural gas or distillate-fired combustion turbine or diesel load-
following units.
Incorporating advanced technologies into the High Coal plan introduces
uncertainty relative to the availability of these technologies for commercial
order. Therefore, the technologies currently available to meet forecasted
demand should be considered in case the availability of advanced technologies
does not materialize as forecasted.
The High Coal plan most likely will rely upon alternatives selected for the
Present Practices plan for the near-term (Present to 1990), primarily due to
the long lead time requirements for coal-based technology. The only coal-based
option potentially available prior to 1990 would be conventional coal-fired
steam-electric plants. Given a 1982 decision to proceed, this type of plant
could be in commercial service by 1989.
Other coal-based options, currently under development, could become
available in the mid-term (1990 to 2000). These include coal gasifier combined-
cycle plants (1990) and coal gasifier fuel cell combined-cycle plants (1994).
Peat-based alternatives were also considered for the "High Coal" plan.
Most advanced are direct-fired steam-electric plants using peat as fuel. This
type of plant is in commercial service in Europe and the Soviet Union and could
be available for commercial operation in the Railbelt by 1990.
No additional coal-based generation technologies are expected to become
available for commercial operation during the long-term period (2000 to 2010).
Anchorage Load Center
The estimated energy costs and time of availability of alternatives
available to the Anchorage and the Fairbanks load centers for the High Coal
4.25
plan are shown in Figure 4.8. With the exception of coal steam-electric
plants, the costs shown are based on use of Nenana coal. If Beluga coal
becomes available, energy costs would be two to three mills/kW lower, as
evidenced by the cost curves for coal steam-electric plants. Note that
estimated costs for coal gasifier combined-cycle plants and coal gasifier fuel
cell combined-cycle plants are essentially identical. The gasifier combined-
cycle plant, however, should become available for service in 1991, five years
prior to the gasifier fuel cell combined-cycle alternative.
Coal steam-electric is the only coal-based alternative available to the
Anchorage load center in the near-term period. If additional resources are
required prior to the 1989 earliest availability of new coal-steam electric
capacity, the noncoal alternatives selected for the Present Practices plan are
recommended for consideration in the High Coal plan. These include the Bradley
Lake and Grant Lake hydro projects and natural gas fired combined-cycle plants
(see Section 4.1 for discussion of these alternatives). These noncoal
alternatives would also provide good load-following characteristics
complementary to coal-steam plants.
If coal is emphasized as a primary energy resource, coal steam-electric
plants most likely will be considerably larger than those currently in use in
the Railbelt, perhaps 200 MWe in rated capacity. Operation would be base load.
The Nenana or Beluga fields would be the most likely source of coal; plant
sites would be mine mouth if Beluga coal is used or along the Alaska Railroad
if Nenana coal is used. Location of a large plant at Healy may not be feasible
because of the proximity of the Denali National Park Class 1 nondegradation
area. Because the coal steam-electric alternative is the sole coal-fired
alternative available prior to the 1990 to 1995 period and because estimated
power costs are competitive in comparison with other technologies available
during this period {see Table 4.2}, this alternative was considered in the High
Coal plan.
Becoming available in the mid-term would be coal gasifier combined-cycle
plants, coal gasifier fuel cell combined-cycle plants and peat-fired steam-
electric plants.
Coal gaSification combined-cycle plants would use low or medium Btu
synthesis gas obtained from coal gasification to drive an integrated combustion
4.26
11\
1-co
.-
0 200
"U
C>
00 m
~
..c: ::;:
.><: -......
11\
150 .,....
...;.. -
.j.J
11\
0
U
>, m
1-
IV
C
1.1.1 100
+>-. IV
N E
-....J .j.J
IV ..... .....
-'
"U
IV
N
r-50
IV >
IV
-'
1980
o Earliest Con~ercial Service Date
Inferred Costs
----0--
Peat Steam Electric (High)
Gas Combustion Turbine
Peat Steam Electric (low)
Gas Combined Cycle
Coal Steam Electrjc lNeoana} Coal Steam Electrlc (Beluga)
... ~~~~e:::~==~~=====-__________ -==-==~-Bradlev lake -.... _ Chakachamna
0"'" 6--;".L ....... urant lake ~c £{;oal Gasifier-Fuel Cell-Combined Cycle (Nenana)
Coal Gasifier-Combined Cycle (Nenana)
1990 2000
First Year of Con~ercial Service
FIGURE 4.8. Cost and Availability of High Coal Plan
for the Anchorage/Fairbanks Load Center
2010
turbine combined-cycle plant. These plants would use either Beluga or Nenana
coal and would likely be located at mine mouth if Beluga coal is used or along
the Alaska Railroad if Nenana coal is used. A Cook Inlet location would be
preferred if surplus synthesis gas were to be converted into an exportable
energy product, such as methanol. Surplus production from an Interior plant
might be used to produce a synthetic natural gas for space heating. Plant
sizes would likely be 200 MWe or larger. Several gasification processes are
currently under development, including Lurgi fixed bed, British Gas Corporation
(BGC) slagger, Texaco pressurized slurry feed and Combustion Engineering
atmospheric-pressure entrained flow. Recent studies sponsored by EPRI have
indicated that gasifier combined-cycle units might function satisfactorily as
load-following units. Entrained flow gasifiers appear to be particularly
suitable for load-following duty.
Gasification-based power plants offer environmental advantages in
comparison with conventional direct-fired steam-electric plants. Sulfur and
particulate removal occurs in the product gas stream - a more benign
environment than that faced by flue gas cleanup processes. This allows for
more effective and less costly cleanup and results in a cleaner exhaust gas.
Heat rejection is lower than for steam-electric plants because of the lower
heat rates of combined-cycle plants.
Because of the favorable cost of power estimates, flexibility, and superior
operational environmental characteristics potentially offered by integrated
gasifier combined-cycle plants, this alternative was considered in the High
Coal plan.
The coal gasifier fuel cell combined-cycle plant would consist of coal
gasifiers integrated with molten carbonate fuel cells. Reject heat would be
captured in waste heat recovery boi 1 ers. Because the fue 1 ce 11 is an
electrochemical energy conversion device, it is free from the thermodynamic
limitations of the Carnot cycle. Moreover, because "combustion" is limited to
the oxidation of hydrogen, the cells produce no oxides of nitrogen. Potential
advantages of fuel cell use include enhanced conversion efficiency and reduced
environmental emissions.
The fuel cells contemplated in this alternative are of the molten carbonate
type, a design that operates at higher temperatures (600 to 800 oC) than
4.28
phosphoric acid cells (70 to 175 0 C). The elevated temperature regime of the
molten carbonate cells should allow the coupling of waste heat boilers to the
fuel cell section of the plant~ further increasing overall conversion
efficiency and reducing heat rejection requirements. Anticipated heat rates of
these plants are about 7100 Btu/kWh~ compared to rates of 7900 to 8500 Btu/kWh
for "conventional" integrated gasifier combined-cycle plants. Molten carbonate
cells are in an early stage of development, and the availability of plants
using these cells for commercial operation is not anticipated until the mid
1990s. Current versions of molten carbonate fuel cells are susceptable to
damage from thermal cycling. This may limit power plants using molten
carbonate fuel cells for baseload operation.
Despite the favorable heat rates forecasted for coal gasifier combined-
cycle power plants~ the estimated electric energy costs for these plants do not
appear to be significantly lower than for the integrated gasifier combined-
cycle plant described above. This is due to the relatively low cost of
Railbelt coal and the greater capital costs forecast for gasifier fuel cell
combined-cycle plants. Coal gasifier fuel cell combined-cycle plants are not
recommended for further consideration because of the lack of clear cost-of-
power advantages~ relatively minor environmental advantages and more limited
operational flexibility in comparison with coal gasifier combined-cycle power
plants in the High Coal plan.
In the United States, peat lands are estimated to cover 52.6 million acres,
making the United States second only to the Soviet Union in peat land area.
Approximately 51% of the U.S. resources are located in Alaska. The
characteristics and extent of fuel-grade peat resources are, however~ poorly
understood at present and have only recently begun to be investigated. The
better peat resources appear to be located in the Anchorage load center.
Peat can be used to generate electricity either by direct-firing in steam-
electric plants or by gasification and firing in combined-cycle plants. Direct-
fired steam-electric plants using peat as fuel could be available for
commercial operation in the Railbelt as early as 1990.
Although the quantity of fuel-grade peat in the Railbelt is not presently
defined~ it appears that sufficient resources are present to support electric
energy generation. At current costs, however~ peat-based generation does not
4.29
appear to be cost competitive with coal (Figure 4.3). For this reason, and
because the quantity of available peat resource and processing requirements
are not well-understood, peat-based generation was included in the Railbelt
electric energy plans. However, because a substantial peat resource capable of
supporting electric power generation appears to be present within the Railbelt,
this resource should be explored further.
The Chakachamna hydroelectric project becomes cost competitive with
conventional coal steam electric plants in the mid-term and is recommended for
development if the more cost-effective advanced coal-based technologies do not
become available for commercial order as anticipated.
Additional coal-based electric power generation options beyond those
discussed above are not expected to become available for commercial application
in the Railbelt in the long-term period. The Chakachamna hydroelectric project
becomes cost competitive with advanced coal-based technologies in the long-term
and is recommended for development at this time if not developed earlier.
Sufficient combustion turbine capacity from existing turbines will be
available until well into the mid-term period to provide peak load-following
complementary to baseload coal plants. Following the retirement of existing
combustion turbines. load following could be provided by new natural gas
combustion turbines, hydro, or coal gasifier combined-cycle plants. The
capital costs of the latter may be sufficiently great to warrant baseload
application only. If these advanced technologies do not become available for
commercial order as expected, natural gas combustion turbines could provide
load following, peaking and reserve capacity.
Fairbanks Load Center
The coal-based alternatives available to the Fairbanks load center are
essentially the same as those available to the Anchorage load center. Nenana
coal would be used in lieu of Beluga coal, resulting in slightly higher busbar
energy costs (Figure 4.7). Construction of the Anchorage-Fairbanks intertie is
assumed, allowing construction of plants in the 200-MW unit size range. Peat
is found in the Fairbanks-Tanana Valley area. The quality and quantity of the
resource is poorly understood but appears to be inferior to the peat resources
of the Anchorage-Cook Inlet area.
4.30
Because of the current surplus of capacity in the Fairbanks load center, it
is unlikely that additional capacity would be required prior to the 1989
availability of new coal capacity. Should new capacity be required prior to
this time, alternatives similar to those selected for the Present Practices
plan (Section 4.1) would be appropriate. These include distillate combined-
cycle retrofit and diesel-electric. Load-following, peaking and reserve
capacity requirements in the mid-term and long-term appear to be most
economically met by diesel units (Section 4.1).
Glennallen-Valdez Load Center
Coal resources, although present near the Glennallen-Valdez area, are more
limited and inferior to those of the Beluga and Nenana fields. Coal, if used
for electric power generation would likely be imported from one of these
fields, resulting in energy costs substantially greater than for competing
alternatives (Figure 4.4). Electrical demand in this load center is
insufficient to support more advanced and efficient coal conversion
technologies. The peat resource of the area is insufficiently known to permit
estimates to be made of availability and cost of peat-based electricity
generation. Therefore, the High Coal alternatives recommended for the Copper
River Valley load center are those selected for the Present Practices plan.
Additional investigation of the peat resources of the area might be desirable
to establish the potential for electric power generation.
A summary of the generating alternatives recommended for inclusion in the
High Coal plan is provided in Table 4.3.
4.4 HIGH NATURAL GAS
Natural gas is used to fuel 655 MW of the 983 MW of generating capacity
presently installed in the Railbelt (Volume VI). All gas-fired capacity is
located in the Cook Inlet area, as gas is not presently available to the
Fairbanks or to the Copper River Valley load centers.
Where available, natural gas has been an economical choice for power
generation. Supplies have been abundant and prices low, largely due to limited
natural gas export capability. Environmentally, as well as economically, gas
has proven to be an attractive resource for electric power production.
4.31
.j::l.
Period
Near-Term
(Present-1990)
~ Mid-Term
(1990-2000)
Long-Term
(2000-2010)
TABLE 4.3 Alternatives Recommended for
Inclusion in the High Coal Plan
Anchorage
Grant Lake Hydro
Bradley Lake Hydro
Natural Gas Combined-Cycle
Coal Steam-Electric
Hydro Alternatives not
Developed in Near-Term
Coal Steam Electric
Coal Gasifier -Combined-Cycle
Chakachamna Hydro
Hydro Alternatives not
Developed Earlier
Coal Steam-Electric
Natural Gas Combustion Turbines
Load Center
Fairbanks
Coal Steam-Electric
Retrofit Distillate
Combined-Cycle
Glennallen-Valdez
Solomon Gulch Hydro
Diesel-Electric
Coal Steam-Electric Allison Hydro
Coal Gasifier Combined-Cycle Diesel Electric
Coal Steam-Electric
Coal Gasifier Combined-Cycle
Diesel-Electric
A 11 i son Hydro (a)
Diesel Electric
(a) If not developed in the mid-term.
Extraction of the resource produces few environmental effects; air emissions
are low in compounds of sulfur and particulates; and water consumption of the
combustion turbines and combined-cycle units predominately used for electric
power production is typically low. The combined-cycle technology currently
used for electricity production using natural gas is mature, inexpensive,
reliable and efficient.
Because of the compelling economic, technical and environmental
characteristics of electric power generation using natural gas, it was thought
appropriate to develop a Railbelt electric energy plan based on continued
reliance upon this energy resource. Additional motivation for a natural gas
plan included the generally favorable public perception of natural gas-based
electricity generation (Volume X) and the prospect of future availability of
emerging and advanced generating alternatives using natural gas, which promise
efficiencies and environmental effects superior to technologies currently in
use.
Continued use of natural gas for electric power generation is not without
potential problems. Principal among these is the future availability and price
of gas. Natural gas prices have traditionally been low and supplies abundant
in the Cook Inlet area, chiefly due to the lack of a significant export
market. However, without additional discoveries, the availability of Cook
Inlet reserves will be constrained within the planning period (Volume VII). To
forestall future price increases and constraints on gas availability, proposals
have been advanced for state purchase of a block of Cook Inlet gas reserves to
ensure continued availability of gas for electricity production and direct
heating applications.
Ultimately, and perhaps within the planning period, a shift to other
resources for electricity generation would be required. At this time two
options are available: 1) development of conventional and advanced
technologies based on renewable resources, or 2) development of conventional
and advanced technologies based on the use of coal or peat. These options are
represented by the High Renewables and High Coal plans, respectively. A High
Natural Gas plan may thus be viewed as an interim plan, ultimately leading to
an energy plan based on resources of greater availability. However, the High
Natural Gas plan may be the option of least environmental and economic cost as
4.33
advanced renewable or coal-based technologies of superior economic and
environmental characteristics are developed.
A second factor impacting a "High Natural Gas" electric energy plan ;s
geographic restrictions on natural gas availability. The resource is currently
found in Cook Inlet and on the North Slope. A distribution system provides
Cook Inlet gas to the Anchorage metropolitan area; however, Cook Inlet gas is
not available to the Fairbanks or to the Copper River Valley load centers. The
proposed North Slope natural gas pipeline, primarily intended to transport
North Slope gas to the Lower 48 States, would pass through the Tanana Valley,
making gas available to the Fairbanks load center. Unlike the Trans-Alaska
pipeline, the gas pipeline would continue southeast along the Alaska highway
and would not enter the Copper River Valley. Pipeline gas is likely to remain
unavailable to the Copper River Valley during the planning period.
The North Slope gas pipeline may be completed to Fairbanks as early as
1987. Fairbanks gas prices, however, are forecasted to be substantially
greater than distillate on an equivalent Btu basis (Volume VII). Since similar
technologies are used to generate electricity with the two fuels, distillate
would continue to be the cost-effective fuel choice at Fairbanks. The
estimated future cost of either distillate or natural gas-based generation at
Fairbanks is sufficiently higher than natural gas generation at Anchorage to
suggest that natural gas-based electricity could be most cost effectively
supplied to Fairbanks via the proposed Anchorage-Fairbanks, intertie. The High
Natural Gas plan will thus focus on continued use of gas at Anchorage.
transmission of gas-based electricity from Anchorage to Fairbanks,and use of
the most cost-effective available alternatives in the Copper River Valley.
Emphasis will be placed on emerging and advanced technologies promising
enhanced conversion efficiencies of available natural gas supplies. With the
exception of coal, nonnatural gas technologies will be incorporated where cost
effective.
The final factor impacting the High Natural Gas plan ;s the constraint
upon natural gas usage for electricity generation presented by the Fuels Use
Act. Exemption to the Act may be available, as discussed in Volumes I and IV.
4.34
Anchorage Load Center
"Conventional" natural gas alternatives available in the Anchorage load
center in the near-term (present to 1990) include combustion turbines, combined-
cycle plants, and steam-electric power plants. Advanced technologies using
natural gas include fuel cells and cogeneration steam topping plants.
Economically competitive hydro alternatives include the Grant Lake, Chakachamna
and Bradley Lake projects (Figure 4.9).
Natural gas combined-cycle plants are the least cost, mature technology
offering the potential for large-scale, near-term capacity expansion relative
to the Railbelt demand. Due to modular design, combined-cycle plants also
offer the flexibility of operation under all load conditions plus high
reliability. This alternative thus establishes the upper bound of cost
effectiveness in the near-term. Alternatives of equal or greater potential for
cost effectiveness in the near-term include cogeneration, fuel cell stations
and the Grant Lake hydro project.
Although not as cost effective in the near-term as natural gas combined-
cycle plants, construction of the Bradley Lake hydro project has been
authorized; hence, Bradley Lake will be included in the High Natural Gas plan.
Where opportunity exists for use of by-product steam, natural gas-fired
cogeneration plants are the most cost-effective alternatives in the near-term.
The estimated energy costs shown in Figure 4.9 are based on a steam topping
cycle. This type of plant would consist of a natural gas-fired boiler
producing steam used to drive a steam turbine-generator. Exhaust steam from
the turbine 9 rather than being condensed as in a conventional steam-electric
power plant, is used for process or space heating. Other cogeneration plant
configurations include combustion turbine and diesel generation topping cycles
and in the future, perhaps fuel cell topping plants. The configuration
selected depends upon specific applications. While steam topping cycles are
suited for many industrial applications, diesel-electric plants may be better
suited for building cogeneration installations.
Because of its apparent cost effectiveness well into the mid-term (Figure
4.9), natural gas-based cogeneration is recommended for consideration for the
High Natural Gas plan. The industrial, commercial and multifamily residential
end-use sectors each offer potential opportunities for cogeneration
4.35
\I)
f-
lO 200 .-
0
"'0
0
CO
0'1 .-..
..r:: ::::r;
~ ......
\I) 150
or-
::E -
+-'
\I)
0 u
>,
0\ f-
.~ QJ c: 100
UJ
W
0"1 QJ e
'r-
+-'
QJ
4-
....J
"'0
QJ
N 50 . ,...
r-
QJ >
QJ
....J
1980
o Earliest Canmercial Service Date
Inferred Costs
Steam Electric/
Combustion Turbine
~Pho~utlOrit A,id Fuel Cell ~~~~§~;;=~§~~;:::==:~~::o-~~y 1 ~tgamyr1~ctri c( a) Steam Electric Molten Carbonate Fuel Cell ----_~ l k -0:: /Bradleg a e
Fuel Cell -~=:::::::::=~~~~~~::::==::_rhakac amna . ~ ~Cogen team Topplng
CY 0:---n-Fuel Cell-Comb. Cycle o _ -=== --Grant lake. --0--
(a) Nenana Coal
1990 2000
First Year of COlllllercial Service
FIGURE 4.9. Cost and Availability of Conventional and Advanced Natural Gas
Alternatives for the Anchorage Load Center
2010
applications. This potential is, however, imperfectly understood at present.
Because of the diversity of potential applications and potential sponsors,
cogeneration costs are only approximated by the estimates depicted in Figure
4.9. It is likely, moreover, that much cogeneration would be developed under
provision of PURPA, resulting in a cost equivalent to the avoided power cost.
Because of these uncertainties, this alternative was not specifically
incorporated into the High Natural Gas plan. Because of its apparent cost
effectiveness in comparison with all but the lowest cost hydro alternatives, it
is recommended that the potential for cogeneration receive further study.
Fuel cell stations based on the use of phosphoric acid fuel cells are an
emerging technology forecasted to become generally available for commercial
order about 1984, with subsequent availability for commercial service in 1987.
Demonstration units are currently undergoing testing for both cogeneration and
noncogeneration applications. The costs of Figure 4.9 are predicated on the
production of commercial quantities of fuel cells. Whether these production
levels will be achieved in the near-term is uncertain. The low energy
production costs of fuel cells are attributable to forecasted low capital
costs and high conversion efficiency. In addition to these attributes, the
fuel cell stations should have highly desirable environmental qualities and
short design and construction lead time. 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. For these reasons fuel cell stations were considered
in the High Natural Gas plan.
The 7-MW Grant Lake hydro project (described in Section 4.1) is
anticipated to produce power at lower cost than the most cost-effective natural
gas alternatives having large-scale capability for expansion (combined-cycle
plants and fuel cells) and therefore was considered in the High Natural Gas
plan.
Combined-cycle plants remain the most cost-effective currently mature
natural gas-based alternative in the mid-term (1990 to 2000). New alternatives
of equal or greater cost effectiveness during this period include molten
4.37
carbonate fuel cell stations, fuel cell combined-cycle plants, and the
Chakachamna hydro project. The Lower Chulitna project, though economically
competitive with natural gas combined-cycle plants during this period, is not
included in the High Natural Gas plan because of its potential impact upon
anadromous fisheries.
Molten carbonate fuel cells are a second generation fuel cell, currently
in an earlier stage of development than the phosphoric acid cell. The molten
carbonate cell will offer a higher conversion efficiency than the phosphoric
acid cell and will likely supersede use of the phosphoric acid cell except for
load-following applications for which the phosphoric acid cell appears to be
better(a) suited. In addition to having a higher conversion efficiency than
phosphoric acid cells, the molten carbonate cell operates at much higher
temperatures. Reject heat could be used to raise steam in heat recovery
boilers to drive steam turbine-generators. The resulting fuel cell combined-
cycle plant could operate at efficiencies of nearly 60%. Limited natural gas
supplies would be more efficiently used and energy costs lowered, depending
upon the capital costs of the fuel cell combined-cycle plant.
Fuel cell stations using molten carbonate fuel cells are anticipated to
become available for commercial service about 1993. Because the capital costs
of the two types of cells are expected to be similar, and the efficiencies of
molten carbonate cells higher, the molten carbonate cells most likely would
supersede the phosphoric acid cells except in applications involving frequent
changes in load.
Because molten carbonate cells operate at a much higher temperature than
phosphoric acid cells, they appear to be suitable for operation as the topping
cycle of a combined-cycle plant. Heat recovery boilers and steam turbines
would comprise the bottoming cycle. Combined plant efficiencies as high as 60%
are expected to result in lower costs of power, if capital costs are
comparable. Natural gas supplies would also be significantly extended. These
plants should exhibit very favorable environmental characteristics because the
by-products of operation would be only CO 2 and water. Given a 1990
(a) The molten carbonate cells appear to be subject to damage under cycling
conditions.
4.38
availability for order, such plants may be in operation by 1995. Because of
their early stage of development, the costs of these plants are not well
understood at present; however, because of their potentially attractive
economic and environmental character, natural gas, fuel cell combined-cycle
plants were considered in the High Natural Gas plan.
The Chakachamna hydroelectric project could be available for service by
1990. It is economically competitive with natural gas alternatives available
at this time, although less cost effective than fuel cell combined-cycle plants
forecasted to becoming available in 1995. Because it is economically
competitive with natural gas combined-cycle plants, it was considered in the
High Natural Gas plan.
Additional natural gas technologies are not foreseen as becoming available
in the long-term period (2000-2010). Limitations on the availability of
natural gas at this time may require development of renewable or coal resource-
based generation as in the High Renewables or High Coal plans.
Fairbanks Load Center
The cost and availability of natural gas resources for the Fairbanks load
center are shown in Figure 4.10. Available natural gas-fired options using
mature technology include combined-cycle plants, steam-electric plants and
combustion turbines. Options using advanced technology include phosphoric acid
and molten carbonate fuel cells and fuel cell combined-cycle plants. Also
included in Figure 4.10 is the Browne hydro project, which becomes cost
competitive with the most cost-effective North Slope natural gas alternative
(fuel cell combined-cycle plants) in the long-term period. Shown in Figure
4.10 for comparative purposes are the cost and availability information for
distillate combined-cycle plants and combined-cycle plants fired with Cook
Inlet natural gas.
Because of persistently lower forecasts of distillate prices on equivalent
Btu basis, at no point during the planning period do alternatives fired by
North Slope natural gas appear to be cost effective with equivalent
technologies supplied by distillate. For example, the costs of equivalent
combined-cycle plants fired by distillate oil and by North Slope gas are
plotted in Figure 4.10. Costs of the natural gas plant are about 16% greater
4.39
200
II) s..
to
r-
0
-0
a co
C'\
.. ..c: 150
3
~ ......
II) ....
... -+>
II)
0
~ U 100
~ @ ;:) "-OJ c::
W
OJ
E .,...
+>
OJ .... ......
-I 50
-0
OJ
N ......
r-
OJ >
OJ
-I
o Earliest Commercial Service Date
I nferred Cos ts
/
(North Slope) Gas Combustion
Turbine (70 MW)
(North Slope) Gas Steam
Electric (200 f4W)
/
(North Slope) Gas Ph, Acid
Fuel Cell
(North Slope) Gas Combined
Cyc1 e (200 f4W)
~(North Slope) Gas C~nbined
Cycle Retrofit (200 r'1W)
Carbonate Fuel Cell
Q;:::.-:::""!:. ·Browne (100 f4W) ~::::;~;::::::::::=:'(North Slope) Gas Nolten
0-- --~ C~(North Slope) Gas Fuel Cell
0-- - - - - -Combined Cycle (200 MW)
.............. .. .... ~."
.. oo ...... .. " .... .. ' .' . • * • ...... -' . " . . ' . " . . -. 0'" .
1990 2000
Fi rs t Year of Convnerd a 1 Serv i ce
.. .. .. .. . . ., ....... . (Cook Inlet) Gas Combined
Cyc 1 e (200 ~1W)
2010
FIGURE 4.10. Cost and Availability of Natural Gas Alternatives
for the Fairbanks Load Center
throughout the planning period. Because most technologies using natural gas
are adaptable to operation using distillate fuel oil, the use of North Slope
gas for electricity generation would not be economically competitive with
distillate fuel oil during the planning period, based on current fuel price
forecasts.
An alternative source of electricity based on natural gas usage would be
generating plants located in the Cook Inlet region using Cook Inlet gas. Power
would be transmitted to Fairbanks via the intertie. The busbar cost of a
combined-cycle plant using Cook Inlet gas is plotted in Figure 4.10. The
estimated cost of this option is 49 mills/kWh in 1990, compared to 95 mills/kWh
for distillate combined-cycle plants and 110 mills/kWh for North Slope gas
combined-cycle plants. The cost savings appear to be more than sufficient to
justify transmission of power from the Cook Inlet area to Fairbanks if a High
Natural Gas plan is adopted.
Because base10ad power for the Fairbanks area under a High Natural Gas
plan appears to be most economically obtained from Anchorage, generating
resource requirements for the Fairbanks areas under the High Natural Gas plan
are limited to those required for peaking or reliability considerations. From
a purely cost-effectiveness standpoint, these should be based on the use of
distillate fuel oil. Candidate alternatives for reserve and peaking duty are
those having good load-following characteristics and low capital costs. These
include combustion turbines, phosphoric acid fuel cells and diesel electric
plants. The 1evelized lifecycle costs for these three types of plants, fired
with distillate fuel oil, for four different in-service dates, are shown below.
Alternative
Diesel Electric (12 MW)
Phosphoric Acid Fuel
Cell Station(b)
Combustion Turbine (70 MW)
Levelized Cost of Energy Under Peaking Duty
for In-Service Dates Shown
(mills/kWh, 1980 dollars)(a)
1990 1995 2000 2005
173 182 192 203
192 201 210 220
204 215 228 242
(a) 10% capacity factor
(b) Unit costs are relatively insensitive to plant capacity.
4.41
Oiesel electric units appear to be consistently more cost effective
throughout the planning period and were recommended for inclusion in the High
Natural Gas plan for peaking and reserve duty at Fairbanks.
Fuel cell stations were also recommended for consideration in the High
Natural Gas plan. Because fuel cell technology is not fully developed,
estimated costs for this technology are less certain than for turbines or
diesels.(a) Fuel cell plants may provide better fuel switching capability
than diesel electric units. The capability is further reason to incorporate
fuel cells into the High Natural Gas plan.
Glennallen-Valdez Load Center
Because natural gas is not expected to be available in the Glennallen-
Valdez load center during the planning period, the alternatives available to
Glennallen-Valdez are basically those selected under the Present Practices
plan. In conformance with the philosophy underlying the High Natural Gas plan
relative to advanced technologies, the cost effectiveness of advanced
technologies suitable for the Glennallen-Valdez area was also examined.
Advanced technologies suitable for the Glennallen-Valdez load center are
those available in small unit sizes and capable of operating on distillate fuel
oil. These include fuel cell stations using phosphoric acid fuel cells and
fuel cell stations using molten carbonate fuel cells. A cost comparison of
these alternatives with mature technologies suitable for use in the Glennallen-
Valdez area is provided below.
Fuel cell stations. especially those based on molten carbonate fuel cells
are clearly more cost effective than conventional alternatives under the
assumed operating conditions. Prior to the availability of fuel cells. diesel
electric units are the most cost-effective nonrenewable option for the
Glennallen-Valdez area.
A summary of the generating alternatives recommended for inclusion in the
High Natural Gas plan is provided in Table 4.4.
(a) Past experience has indicated that the actual cost of new technologies when
commercially available is typically higher than that estimated during
development.
4.42
Alternative
Phosphoric Acid Fuel
Cell Station (b)
Cell Station (b)
Diesel Electric (12 MW)
Combustion Turbine (50 MW)
NA = Not Aval1able
(a) 65% capacity factor
Levelized Cost of Energy Under General
Service for In-Service Dates Shown
(mills/kWh, 1980 dollars){a)
1990 1995 2000 2005
97 106 115 125
NA 90 97 106
100 110 120 131
127 139 151 166
(b) Unit costs relatively insenstive to size.
4.43
TABLE 4.4 Alternatives Recommended for inclusion
in the High Natural Gas Plan
Period
Near-Term
(Present-1990)
-J:::> Mid-Term
t (1990-2000)
Long-Term
(2000-2010)
Anchorage
Combined-Cycle
Cogeneration
Bradl ey Lake
Fuel Cell Stations
Grant Lake
Combined-Cycle
Cogeneration
Fuel Cell Stations
Fuel Cell Combined-Cycle
Chakachamna
Hydro not Developed in Near-Term
Cogeneration
Fuel Cell Stations
Fuel Cell-Combined Cycle
Hydro not Developed in
Earl ier Periods
Note(d)
(a) Using distillate fuel oil.
Load Center
Fairbanks
Diesel-Electric
Fuel Cell Stations(a)
Combined-Cycle(b)
Cogeneration(b)
Diesel-Electric
Fuel Cell Stations(a)
Combined-Cycle(b)
Cogeneration(b)
Fuel Cell Combined-
Cycle(b)
Diesel-Electric
Fuel Cell Stations(a)
Cogeneration(b)
Fuel Cell Combined-Cycle(b)
Note(d)
(b) Imported baseload power from Cook Inlet appears to be more cost effective
than local use of North Slope natural gas.
(c) If not developed in earlier periods.
(d) Additional nonnatural gas resources maybe required during the long-term
period due to possible depletion of Cook Inlet natural gas supplies.
Glennallen-Valdez
Solomon Gulch Hydro
Diesel-Electric
Fuel Cell Stations(a)
Allison Hydro
Fuel Cell Stations(a)
Allison Hydro(c)
Fuel Cell Stations(a)
Note(d)
5.0 CONCLUSION
Twenty-two electric power generating alternatives were selected for
consideration in the development of Railbelt electric energy plans. The
alternatives are shown in Table 5.1. The second column of the table lists the
Railbelt electric energy plans for which use of each alternative will be
considered. Consideration of alternatives is not technically limited to the
plans shown and combinations other than those indicated may be investigated.
A description of the "typical" Railbelt facility to be considered in the
development of more detailed information on each alternative is provided in the
third column of Table 5.1. The plant sizes, locations and fuel sources shown
are considered to be the most likely for these technologies. Some flexibility
will exist for scaling costs and performance information to other plant sizes,
locations and fuel sources.
In the right hand column of Table 5.1 are listed the principal sources of
cost, performance and environmental information for analysis of the selected
alternatives. Information sources are of three general types. First,
information was obtained from feasibility studies where these existed. These
included the Upper Susitna, Allison, Bradley Lake, and Grant Lake hydroelectric
projects, and the Cook Inlet Tidal project.
Second, in-depth "Task 3B"
meeting the following criteria:
contributing to future Railbelt
studies were prepared on alternatives generally
1) having the potential for significantly
generating capacity; 2) not currently existing
in the Railbelt or for which significant Railbelt experience in likely future
configurations or sizes does not exist; and, 3) sufficiently mature to allow
significant information to be developed beyond the existing technology
profile. These alternatives include coal steam-electric, coal gasifier-
combined cycle, natural gas fuel cell stations, the Chakachamna, hydroelectric
project,(a) the Browne hydroelectric project and large wind energy conversion
systems.
(a) A separate feasibility study of the Chakachamna hydroelectric project was
initiated by the Alaska Power Authority following the selection of this project
for Task 3B study. Both references are included in Table 5.1.
5.1
Finally. further study on certain alternatives was limited to a review and
update of the existing technical profiles (Volume IV) with consideration of
likely plant sizes. locations and fuel sources. These alternatives generally
include those for which a good understanding of Railbelt cost and performance
exists. or those that do not appear to have the potential to significantly
contribute to meeting demand in the context of total load center demand.
Further study. beyond the scope of this project, is recommended for
several options. Most promising are cogeneration applications, especially
those using natural gas. Also promising, based on very preliminary estimates
of the cost of power, is geothermal generation. The Railbelt geothermal
resource, however, is not sufficiently well understood to permit estimates of
availability to be made. Moreover, the resource appears to be of the hot dry
rock type for which conversion technology is not developed. Additional
exploration of the resource potential appears prudent, however. Finally, the
peat resources of the Railbelt appear to warrant additional study to determine
their potential for electric power generation. Current estimates of the cost
of peat-based generation are based on very preliminary information and could
change given better understanding of the resource.
The performance and economic characteristics of each alternative used in
the assessment of the Railbelt Electric Energy plans are provided in the
technical data sheets of Appendix A.
5.2
TABLE 5.1 Alternatives Selected for Consideration
in Railbelt Electric Energy Plans
Alternative
Coal Steam-Electric
Coal Gasification -
Combi ned-Cycl e
Natural Gas Combined-
Cycle
Natural Gas Combustion
Turbines
Natural Gas Fuel Cell
Station
Natural Gas Fuel Cell
Combi ned-Cycl e
Applicable
Plan(a)
I,I1,III
I I I
I , I I , I I I , IV
I, I II
IV
IV
5.3
Nominal
Railbelt Plant
200-MW pulverized
coal-fired power
plant. Two locations
considered -Beluga
and Nenana.
200-MW integrated
gasifier combined-
cycle power plant;
gasifier dedicated
to power plant
operation. Located
at Beluga, supplied
with Beluga coal.
200-MW natural gas-
fired combined-cycle
power plant located
at Beluga, supplied
with Cook Inlet gas.
70-MW natural gas-
fired combustion
turbine. Cook Inlet
location, supplied
with Cook Inlet gas.
25-MW fue 1 ce 11
station with phos-
phoric acid fuel
cells. Located in
Cook Inlet area,
supplied with Cook
Inlet natural gas.
200-MW natural gas
fuel cell combined-
cycle plant using
molten carbonate
fuel cells. Located
in Cook Inlet area,
supplied with Cook
Inlet natural gas.
Source of
Planning Information
Task 38 Study
(Vol ume XI I)
Task 38 Study
(Volume XVII)
Task 38 Study
(Vol ume XII I)
Technology
Profile
(Volume IV)
Technology
Profile
(Vol ume IV)
Technology
Profile
(Volume IV)
Alternative
Natural Gas Steam
Topping Cogeneration
Plant
Distillate Combined-
Cycle Retrofit
Distillate Fuel Cell
Station
Diesel Electric
Bradl ey Lake
Grant Lake
Chakachamna
Allison
TABLE 5.1. (contd)
Applicable
Plan(a)
IV
I, II
IV
I , II , II I , IV
I,II,III,IV
I,II,III,IV
I, II, III, IV
I,II,III,IV
5.4
Nominal
Ra i1 be lt Pl ant
Insufficient cost
and information
available to
permit incorporation
of this alternative
into Railbelt
electric energy plans.
Retrofit of Golden
Valley Electric
Association North
Pole combustion
turbines for
combined-cycle
operation.(b)
25-MW fuel cell
station with
phosphoric acid
fuel cells.
Located in Glenn-
allen-Valdez area.
12-MW diesel elec-
tric plant. Located
either in Fairbanks
or Glennallen-Valdez
load centers.
90-MW Bradley Lake
hydro project
7-MW Grant Lake
hydro project
330/480 MW
Chakachamna
hydro project
8-MW Allison hydro
project
Sou rce of
Planning Information
Further study
recommended
Technology
Profile
(Volume IV)
Technology
Profile
(Volume IV)
Technology
Profil e
(Volume IV)
Alaska Power
Admi ni strat ion
1977
CH 2 M-Hi 11
1981
Task 3B Study
(Volume XIV)(c)
u.S. Army Corps
of Eng; neers
1981
TABLE 5.1. (contd)
Applicable Nominal
Alternative Plan{a} Railbelt Plant
Browne II 100-MW Browne hydro
project
Snow II 50-MW Snow hydro
project
Keetna II 100-MW Keetna hydro
project
Strandline Lake II 20-MW Strandline
hydro project
Refuse-Fi red II 50-MW refuse-fired
Steam-Electric steam-electric
plant at Anchorage
20-MW refuse-fired
steam-electric
plant at Fairbanks
Large Wind Energy II 25-MW wind farm
Conversi on Systems consisting of 10
2.5-MW units -
located near Isabell
Pass
Tidal Power II 720-MW tidal electric
power plant or Knik
Arm at Eagle Bay
Upper Susitna I(d),II(d) The Upper Susitna
hydroe 1 ect ri c
project consisting
of the two-stage
Watana dam (680 MW
plus a 340-MW
expansion) and the
600-MW Devil Canyon
dam.
( a ) Plan I -Present Practice
Plan II -High Conservation and Renewables
Plan III -High Coal
Plan IV -High Natural Gas
Source of
Planning Information
Task 3B Study
(Vol ume XV)
Acres American
Inc. , 1981b
Acres Ameri can
Inc. , 1981b
Acres American
Inc. , 1981b
Technology
Profiles
(Volume IV)
Task 3B Study
(Volume XVI)
Acres American
1981a
Acres American
1981b
(b) Additional capacity was not required in the Fairbanks load center until the
North Pole units were 15 years of age, beyond the point in life at which
retrofit was considered feasible.
(c)
(d)
Later supplemented with Bechtel Civil and Minerals, 1981 (330 MW
a 1 ternati ve).
Separate version of Plans I and II, were assessed specifically
incorporating the Upper Susitna project.
5.5
APPENDIX A
TECHNICAL DATA SHEETS FOR
ELECTRIC ENERGY GENERATION AND
CONSERVATION OPTIONS
APPENDIX A
TECHNICAL DATA SHEETS FOR
ELECTRIC ENERGY GENERATION AND
CONSERVATION CPTIONS
The purpose of this appendix is to provide in one location the technical
perfonnance and cost data used in the AREEP capaCity addition model for new
generating options and in the demand forecasting models for conservation
opti ons •
Each generating and conservation option is sLJ11ll1arized on one technical
data sheet. Each sheet consi sts of a general descri pti on of the opti on,
folla.ved by tal:xJlated technical perfonnance, schedule, fuel and cost data.
Also provided are references to source documents from which the infonnation on
the data sheets was taken.
The i nfonnati on on many generati ng and conservati on opti ons was taken from
Volume IV of this series of reports, Candidate Electric Energy Technologies for
Future Application in the Railbelt Region of Alaska. Costs given in Volume IV
are expressed in 1980 dollars. Costs used in theAREEP model are in January
1982 dollars. The methods of escalating Volume IV costs to January 1982 are
documented in the appropri ate techni cal data sheets. Separate data sheets are
provided for fuel price and escalation infonnation common to several options.
A. 1
TECHNICAL DATA SHEET 1.0
COAL-FIRED STEAM-ELECTRIC POWER PLANTS(a)
Two pulverized coal-fired steam-electric power plants were considered.
The first plant would be a 200-MW nominal capacity pulverized coal-fired steam-
electric station located in the Beluga area on the northeast side of Cook
Inlet. The plant would be of conventional design, using dry lime slurry flue-
gas desulphurization (FGD) scrubbers, baghouse particulate removal and wet/dry
mechanical draft cooling towers. The facility would be supplied with Beluga
coal by truck or conveyor from the mine mouth. Power would be supolied to
Anchorage-Fairbanks intertie by a 345-kV tie line, approximately 75 miles in
length and terminating in a substation at Willow.
The second plant would be a 200-MW nominal caoacity pulverized coal-fired
steam-electric plant located in the Nenana area, southwest of Fairbanks. This
plant also would be of conventional design, using dry lime slurry FGD
scrubbers, baghouse particulate removal and wet/dry mechanical draft cooling
towers. The facility would be supplied with coal from the Nenana field at
Healy via the Alaska Railroad. Power would be supplied at Nenana, at 138 kV if
supply to Fairbanks is intended, and at 345 kV if supply to Anchorage is
intended.
TECHNICAL PERFORMANCE DATA
Nominal Plant Size (MW)
Size Range for Which Data
Are Generally Valid (MW)
Capacity Credit
Capacity Limit in Railbelt (MW)
Typical Operation
Heat Rate (Btu/kWh)
Forced Outage Rate (%)
200
150-250
Full
Large relative to prospective demand
Baseload
10,000
4.8 (150 MW)
5.7 (200 MW)
6.6 (250 MW)
(a) All data in this data sheet are taken from Volume XII unless otherwise
indicated.
A.3
Scheduled Outage Rate (%)
Equivalent Availability (%)
SCHEDULE
FUEL
Availability for Order
Preconstruction Studies and
Licensing (years)
Construction (years)
Startup (years)
Earliest Commercial Service
Plant Life (years)
Heating Value (Btu/lb)
COST DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)(b)
Working Capital ($/kW)(c)
Fixed O&M ($/kW/yr)
Variable O&M (mills/kWh)
F ue 1 ($/MM3tu)
(a) 1982 decision to proceed.
8
88 (150 MW)
87 (200 MW)
86 (250 MW)
Current
3
4
0.25
1989 (a)
35
8000
Beluga Nenana
2051 2110
34 41
16.71 16.71
0.6 0.6
See Table 26.1
(b) Does not include land or land rights, client charges, taxes or transmission
costs beyond the substation or switchyard.
(c) Includes 9O-day coal pile plus one month O&M.
A.4
Payout Schedule
Beluga Station
Year $ %
1 72,006,000 17.6
2 119,372 , 000 29.1
3 121,096,000 29.5
4 97,687,000 23.8
Escalation Factors (%/Year, 1981-2010)
Capita 1
O&M
Fuel
Economics of Scale
A.5
Nenana Station
$ %
76,920,600 18.2
121,283,000 28.8
126,740,000 30.1.
96,622,200 22.9
Beluga Nenana
See Ta b 1 e 25.1
See Table 25.~
See Table 26.1
Negligible in 150-250 MW range
TECHNICAL DATA SHEET 2.0
INTEGRATED CflIl.L GASIFIER COM3INED-CYCLE POWER PLANTS(a)
The proposed pl ant would consist of coal gasifi ers producing a medi urn Btu
synthetic fuel gas. The synthetic fuel gas would be used to drive a combined-
cycle power plant of 220-toW nominal capacity. The prototypical plant selected
for study would be located in the Beluga area northwest of Cook Inlet and would
use coal from the proposed Chuitna Field surface mines. Alternatively, plants
of the proposed design could be sited along the Alaska Railroad and could use
coal fran the Usibelli mine at Healy.
Pulverized coal would be supplied to high-pressure, oxygen-blown,
entrained-flow gasifiers of Shell design to produce a medium Btu synthesis
gas. The raw product gas woul d be passed through parti cul ate remova 1 cyelones
and then would be directed to gas cool ers that contri bute saturated steam to
the steam bottoming cycle. Gas exiting from the gas cooler would be passed
through a quench scrubbing column and then a sulfur removal section conSisting
of a COS conversion unit and a H2S absorber unit.
Cl ean gas woul d be suppl ied to two combusti on turb; ne-generators rated at
74.5 toW each. Exhaust from the combustion turbines would be directed to heat
recovery steam ~nerators that woul d produce superheated steam for a 100-MW
steam t ur bi ne-gener ator plus au x il i ar y steam at lower press ures for i n-plant
use. Waste heat would be rejected by a wet/dry mechanical draft cooling tower.
Power would be transmitted to a substation at Willow on the proposed
Anchorage-Fairbanks intertie by a single circuit 345-kV line ",75 miles in
1 ength.
TECHNICAL PERFORMANCE DATA
Nominal Plant Size (MW)
Size Range for Which Data
Are Generally Valid (MW)
Capacity Credit
220
150-250
Full
(a) All data in this data sheet are taken from Volume XVII unless otherwise
; ndi cated.
A.7
Capacity Limit in Rail belt (MW)
Typical Operation
Heat Rate (Btu/kWh)
Forced Outage Rate (%)
Schedul ed Outage Rate (%)
Equivalent Availability (%)
SCHEDULE
FUEL
Ava il abil ity for Order
Preconstruction Studies and
Licensing (years)
Construction (years)
Startup (years)
Earl i es t CCl11ITlerc i a 1 S er vi ce
Plant Life (years)
Heati ng Val ue (Btu/lb)
Ca:;T DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)(b)
Working Capital ($/kW)(d)
Fixed 0u.1 ($/kW/yr)
Variable 08101 (mills/kWh)
Fuel ($/MM3tu)
Lar ge re 1 at; ve to pros pe ct i ve dem and
Baseload/Load F 0 11 ow; ng
92~
8
7
7
1985
3( a)
2.5
1/3
1991
25
0000
Be lug a
3280
65
16.87
0.7
See Table 26.1
(a) Estimated based on pu 1 veri zed coal steam-el ectri c pl ant of simil ar
capacity.
(b) Does not include land or land rights, client charges, taxes or transmission
costs beyond the substati on or switchyard.
(c) Costs for a Nenana 1 ocati on were not separately estimated.
(d) 5X)-day coal pile plus 3O-day 08101 costs. Assumes 1990 coal prices.
A.8
Pa,Y:out Schedu le
Year 10 6 $ %
1 167.2 23
2 331.8 46
3 223.6 31
Escalation Factors (%/Year, 1981-2010)
Capit a 1
0&1-1
Fuel
Economics of Scale
Capita 1
Fixed 0&1-1
Variable O&M
Fuel
A.9
Be lug a Nenana
See Table 25. 1
See Table 25.2
See Table 26.1
Can be realized by using larger
component sizes; however, this is
not documented.
Can be realized by using larqer
component sizes; however, this is
not documented.
Not documented
Not documented
TECHNICAL DATA SHEET 3.0
NATURAL GAS COM3USTION TURB INE POWER PLANTS( a)
Natural gas combusti on power pl ants consist of a combusti on turbi ne
driving an electric generator. A typical plant consists of an air compressor,
a combustor section, the gas turbine unit, an electric generator, and
appurtenant facilities. Combustion turbines can also be fired with distillate
or residual oil for emergency operation in case of qas supply failure.
TECHNICAL PERFORMANCE DATA
Nominal Plant Size (MW)
Size Range for Which Data
Are Generally Valid (MW)
Capacity Credit
Capacity Limit in Railbelt (MW)
Typical Operation
Heat Rate (Btu/kWh @ HHV)
Forced Outage Rate (%)
Scheduled Outage Rate (%)
Equivalent Availability (%)
SCHEDULE
Ava i1 abil ity for Order
Preconstruction Studies and
Licensing (years)
70
50-100
Full
'1,,1000 (b)
Load Followinq (Peakinq)(c)
13 ,800 (d) -
8
3.2
89.1
Ava il abl e
1
(a) All data in this data sheet are taken from Volume IV unless otherwise
i ndi cated.
(b) Using Cook Inlet qas.
(c) Currently in use throughout the Railbelt in baseload and load-following
service; future installations would likely be used primarily in peaking
duty.
(d) Current technoloqy under average duty. Advanced machines may have average
annual heat rates of 12,400 Btu/kWh.
A.ll
FUEL
Construction (years)
S tart up (years)
Earliest Commercial Service
Plant Life (Y,ears)
Heating Value (Btu/lb)
COST DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)
Working Capital ($/kW)
Fixed O&M ($/kW/yr)
Variable O&M (mills/kWh)
Fuel ($/MMBtu)
Payout Schedule
Escalation Factors (%/Year, 1981-2010)
Capital
O&M
Fuel
Economics of Scale
1
<1
1984
20
21,500
638(a)
88(b)
48( c)
(Included in Fixed O&M)
See Table 26.1
One Shot
See Table 25.1
See Table 25.2
See Table 26.1
No infonnation available.
(a) Based on costs reported in Volume IV escalated to January 1981 usinq Handy
Whitman index; line 30 then escalated to January 1982 using annual
inflation rate of 9% plus 1981 capital cost escalator of Table 25.1.
(b) Includes 3O-day emergency distillate supply (1990 or;ces) and 3O-day O&M
costs.
(c) Escalated to January 1981 using Handy Whitman index, line 1; then escalated
to January 1982 using 9% annual rate of inflation plus 1981 O&M escalator
from Table 25.1.
A.12
TE CHN I CAL DATA SHEET 4.0
NATURAL GAS-FIRED COM3 INED-CYCLE PLANT( a)
The proposed plant would be a conventional combined-cycle power plant of
200-MW nominal rated capacity, located in the Beluga area northwest of Cook
Inl et. Natural gas to fire the pl ant would be taken from the Cook In1 et
natural gas fields. The plant would consist of gas compressors and fuel
forwarding facilities, two combustion turbine units driving generators rated at
75 M..J each, a heat recovery steam generator operati ng from combusti on turbi ne
exhaust and a steam turbine driving a generator rated at 59 MW. A wet/dry
mechanical draft cooling tower would be provided for waste heat rejection.
Power would be transmitted by 345 kV single circuit line to a substation
located near Wi110tl on the proposed Anchorage-Fairbanks intertie.
TECHNICAL PERFORMANCE DATA
Nominal Plant Size (MW)
Size Range for Which Data
Are Generally Valid (MW)
Capacity Credit
Capacity Limit in Railbelt (MW)
Typical Operation
Heat Rate (Btu/kWh)
Forced Outage Rate (%)
Schedu 1 ed Outage Rate (%)
Equivalent Availability (%)
SCHEDULE
Ava i 1 abi 1 ity f or Order
Preconstructi on Studi es and
Licensing (years)
Constructi on (years)
Startup (years)
Earl iest Commercial Service
Plant Life (years)
200
200-300
Full
'\;1000 (b)
Baseload
8200
8
7
85
Ava i 1 abl e
3
3
1/4
1988
25
(a) All data in this data sheet are taken from VollJT1e XIII unless otherwise
; ndi cated.
(b) Using Cook Inlet gas. A.13
FUEL
Heating Value (Btu/lb)
C(l)T DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)
Working Capital ($/kW)
Fixed O&M ($/kW/yr)
Variable O&M (mills/kWh)
Fuel ($/MM3tu)
Payout Schedu le(c)
Year 10 6 $ %
1 51. 5 26
2 102.2 51
3 46.5 23
Escalation Factors (%/Year, 1981-2010)
Capita 1
O&M
Fuel
Economics of Scale
Capi ta 1
Fixed O&M
V ari abl e O&M
Fuel
21,500
1001 (a)
52 (b)
7.25
1.7
See Table 26. 1
See Table 25.1
See Tabl e 25.2
See Table 26.1
Can be realized through use of
1 ar ge canponent si zes, but not
documented.
Can be real i zed through use of
larger canponent sizes, but not
document ed •
Not documented
Not documented
(a) Does not include land or land rights, ONner costs, or transmission costs
beyond the sUbstation.
(b) Includes 30-day emergency distillate supply (19ro prices) plus 30-day O&M
costs.
(c) Based on Phung (1978) weak sinusoidal payout schedule.
A.14
TECHNICAL DATA SHEET 5.0
NATURAL GAS FUEL CELL STATIONS(a)
Fuel cell stations would be relatively small (5 to 25 MW), dispersed
generating plants consisting of phosphoric acid fuel cells supplied with a
hydrogen-rich fuel refonned from natural gas. A typical station would consist
of a fuel conditioner, which converts the natural gas fuel to hydrogen and
carbon dioxide; phosphoric acid fuel cells, which generate DC power by
electrolytic oxidation of hydrogen; a power conditioner, which converts the DC
fuel cell output to AC power for distribution; and appurtenant facilities.
TECHNICAL PERFORMANCE DATA
Nominal Plant Size (MW)
Size Range for Which Data
Are Generally Valid (MW)
Capacity Credit
Capacity Limit in Railbelt (MW)
Typical Operation
Heat Rate (Btu/kWh)
Forced Outage Rate (%)
Scheduled Outage Rate (%)
Equivalent Availability (%)
SCHEDULE
Ava il abi 1 ity for Order
Preconstruction ~tudies and
Licensing (years)
Constructi on (years)
Startup (years)
Earliest Ccrnmercial Service
Plant Life (years)
(a) All data in this data sheet are taken
i ndi cated.
(b) Assuming use of Cook Inlet gas.
A.15
25
Not Applicable
Full
"'1000 (b)
Baseload or Load Following
9200
6
4
91
1985
1
1
<1
1987
20
from Volume IV unless otherwise
FUEL
Heating Value (Btu/lb, HHV)
COST DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)
Working Capital ($/kW)
Fixed O&M ($/kW/yr)
Variable O&M (mills/kWh)
Fue 1 ($/MMB tu)
Payout Schedu le
Escalation Factors (%/Year, 1981-2010)
Capit a 1
O&M
Fuel
Economics of Scale
21,500
830 (a)
60(b)
42(c)
(Included in Fixed O&M)
See Table 26.1
One Shot
See Table 25.1
See Table 25.2
See Table 26.1
No infonnati on avail abl e.
(a) Escalated to January 1981 using Handy Whitman index, line 30; escalated to
January 1982 using 9% annual rate of inflation plus 1981 capital cost
es ca 1 ator of T abl e 25.1.
(b) Includes 30-day emergency distillate supply (19~ prices) and 30-day O&M
costs.
(c) Midpoint value of Volume IV (35 $/kW/yr) escalated to January 1981 using
Handy Whi'bnan index; line 1 then escalated to January 1982 using 9% annual
rate of inflation plus 1981 O&M escalator from Table 25.1.
A.16
TECHNICAL DATA SHEET 6.0
NATURAL GAS FUEL CELL COM) INED-CYCLE POWER PLANTS (a)
Natural gas fuel cell combined-cycle power plants would be relatively
large ('1-200 MW), central generating stations consisting of molten carbonate
fuel cells, with waste heat recovery boilers driving a steam turbine-
generator. A typical plant woulrl include a fuel conditioner to convert natural
gas to hydrogen and carbon dioxide; molten carbonate fuel cells pror1ucing DC
power by el ectro lyti c oxi dati on of hydrogen; heat recovery boi 1 ers usi ng re5 ect
heat from fuel-cell operation to raise steam; a turbine-generator driven by
steam from the heat recovery boiler; a power conditioner to convert the DC fuel
cell output to AC power; and appurtenant facilities.
TECHNICAL PERFORMANCE DATA
Nominal Plant Size (MW)
Size Range for Which Data
Are Generally Valid (MW)
Capacity Credit
Capacity Limit in Railbelt (MW)
Typical Operation
Heat Rate (Btu/kWh)
Forced Outage Rate (%)
Schedul ed Outage Rate (%)
Equivalent Availability (%)
SCHEDULE
Ava il abi 1 ity for Order
Preconstruction Studies and
L i cens i ng (years)
Constructi on (years)
Startup (years)
Earliest Commercial Service
Plant Life (years)
200
Not known
Full
'1-1000 (b )
Baseload
5700
4
11
83
19~
3
3
1/2
1996
25
(a) All data in this data sheet are taken from Volume IV unless otherwise
; ndi cated.
(b) Assuming use of Cook Inlet gas.
A.17
FUEL
Heating Value (Btu/lb)
COST DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)
Working Capital ($/kW)
Fixed O&M ($/kW/yr)
Variable O&M (mills/kWh)
F ue 1 ($/MM3tu)
Payout Schedu le{b)
Year 10 6 $ %
1 100 25
2 200 50
3 100 25
Esc al ati on Factors (%/Year, 1981-2010)
Capita 1
O&M
Fuel
Economic s of Sc ale
21.500
2000
39 (a)
50
Inc 1 uded in Fixed O&M
See Table 26. 1
See Table 25. 1
See Table 25. 2
See Table 26.1
No i nfonnati on avail abl e.
(a) Includes 30-day emergency distillate supply (19~ prices) and 30-day O&M
costs.
(b) Based on Phung (1978) weak sinusoidal payout schedule.
A.18
TECHNICAL DATA SHEET 7.0
BRA DLEY LAKE HYDROELECTRIC PROJECT( a}
The proposed Bradley Lake hydroelectric project would be located at
Bradley Lake near Haner, Alaska, at the head of Kachemak Bay. The project
would use Bradley Lake as a reservoir, with the natural water supply of the
lake supplenented by diversion of North Banks Creek into Bradley Lake. A
concrete gravity dam would raise the elevation of the lake to 1170 feet from
its natural elevation of 1Q!:(l feet. A power tunnel, tapping the lake, would
convey water to an underground powerhouse located near ti dewater. The
preferred pl an involves install ati on of !:(l-MW capacity, although 60-and 135-MW
a lternati ves have been ; nvesti gated. (b)
TECHNICAL PERFORMANCE DATA
Naninal Plant Size (MW)
Si ze Range for Whi ch Data
Are Generally Val id (MW)
Capacity Credit
Capacity Limit in Railbelt (MW)
Typi ca 1 Operati on
Forced Outage Rate (%)
Schedul ed Outage Rate (%)
Annual Firm Energy (GWh)
Average Annual Energy (GWh)
Equivalent Capacity Factor (%)
!:(l
Not Appl i cabl e
Full
Not Ap P 1 i ca b 1 e
Baseload/cycling
5( c)
1.5(d}
315( b)
34 7( b )
44.0
(a) All data in this data sheet are taken from Alaska Power Administration
(APA) (1977) unless otherwise indicated.
(b) Reported in a telephone conversation with John Denniger of the Alaska Power
Administration.
(c) Based on estimates prepared for the Chakachamna Hytlroelectric project,
Vol ume XIV.
(d) Estimate.
A.19
SCHE DULE
Availability for Order
Preconstructi on Studi es and
Licensing (years)
Construction (years)
Startup (years)
Earliest Corrmercial Service
Plant Life (years)
C(1;T DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)
Working Capital ($/kW)
Fixed O&M ($/kW/yr)
Variable O&M (mills/kWh)
Payout Schedu le (f)
Year $ %
1 20,070,000 7.0
2 51,600,000 18.0
3 71,660,000 25.0
4 71,660,000 25.0
5 51,600,000 18.0
6 20,070,000 7.0
Escalation Factors (%/Year, 1981-2010)
Capital
O&M
Economics of Scale
(a) Estimate.
(b) Inferred from APA (1977).
Ava 11 abl e
2(a)
6(b)
<1(a)
1990
50
3184 (c)
1 (d)
9(e)
None
See Table 25.1
See Tabl e 25.2
Not Appl icabl e
(c) Corps of Engineers January 1981 estimate (2roO $/kW), escalated to January
1982 using weighted escalation rates of Table 25.1 olus 9% general
i nf 1 at i on r at e •
(d) Based on 3D-day O&M costs.
(e) Estimate of APA (1977), escalated to January 1981 using Handy Whitman
index; !Scal ated to January 1982 as in (c) above.
(f) Based on Phung (1978) weak sinusoidal payout schedule.
A.20
TECHNICAL DATA SHEET 8.0
GRANT LAKE HYDROELECTRIC PROJECT(a)
The proposed Grant Lake hydroelectric project would use Grant Lake as a
reservoir. Grant Lake is about 25 miles north of Seward and east of the Seward-
Anchorage Highway. The project would consist of a main and a saddle dam, a low-
pressure water conveyance pipe, a surge tank, a penstock and an aboveground
powerhouse of 7.3-MW installed capacity. Water would be drawn from Grant Lake
at an elevation of 705 to 740 feet and discharged to Upper Trail Lake on the
Trail River at 472 feet elevation. The aboveground concrete powerhouse,
located on Trail Lake, would be equipped with two turbine-generators rated at
3640 kW each with a total installed capacity of 7250 kW. The tailrace would
discharge to Upper Train Lake.
TECHNICAL PERFORMANCE DATA
Installed Capacity (MW)
Size Range for Which Data
Are Generally Valid (MW)
Capacity Credit
Capacity Limit in Railbelt (MW)
Typical Operation
Forced Outage Rate (%)
Scheduled Outage ~ate (%)
Equivalent Availability (%)
Annual Firm Energy (GWh)
Average Annual Energy (GWh)
Equivalent Capacity Factor (%)
SCHEDULE
Availability for Order
Preconstruction Studies and
Licensing (years)
7.3
Not Applicable
Full
Not Applicable
Baseload/Cycling
5
1.5
94
19
27
42.2
Available
2
(a) All data in this data sheet are based on CH 2M-Hill (1980) unless
otherwise indicated.
A.2l
Construction (years)
Startup (years)
Ear 1 i est Canmerc i al Servi ce
Plant life (years)
CUST DATA
Estimated Costs (January 1982)
Overn i ght Capital ($/kW)
Working Capital ($/kW)
Fixed O&M ($/kW/yr)
V ari abl e 0&\1 (mill s/kWh)
Payout Schedule(c)
Year $ %
1 10,360,000 50.0
2 10,360,000 50.0
Escalation Factors (%/Year, 1981-2010)
Capita 1
0&\1
Economics of Scale
2
. «1
1986
50
2838(a)
4(b)
44
None
See Table 25.1
See Table 25.2
Not Appl icabl e
(a) CH,M-Hill capital costs escalated from January 1980 to January 1981 using
Handy Whitman index. Costs escal ated from January 1981 to January 1982
usin~ weighted escalation rates of Table 25.1 plus 9% general inflation
rate.
(b) Based on 30-day 0&\1 costs.
(c) Based on Phung (1978) weak sinusoidal payout schedule.
A.22
TECHNI CAL DATA SHEET 9.0
ALLISON HYDROELECTRIC PROJECT(a)
The proposed Allison hydroelectric project would be located on Allison
Lake and Allison Creek, which discharges to Valdez Inlet near the Port of
Valdez. The proposed project would use Allison Lake as a reservoir and would
consist of a power tunnel, penstock and an aboveground powerhouse. The 10,200-
foot power tunnel would tap Allison Lake and lead to the penstock. The
penstock woul d drop to the powerhouse, located near the discharge of Allison
Creek to Valdez Inlet. The project would have an installed capacity of8 MW.
A dual tailrace would be provided, allowing discharge to Allison Creek during
wann seasons to protect the Allison Creek anadrOO1ous fishery.
TECHNICAL PERFORMlI.NCE DATA
Installed Capacity (MW)
Si ze Range for Whi ch Data
Are Generally Valid (MW)
Capacity Credit
Capacity Limit in Railbelt (MW)
Typical Operation
Forced Outage Rate (%)
Schedul ed Outage Rate (%)
Equivalent Availability (%)
Annual Finn Energy (GWh)
Average Annual Energy (GWh)
Equ iva 1 ent Capac ity Factor (%)
8
Not Applicable
Full
Not App 1 i ca b 1 e
Baseload/Cycling
S(b)
l.S(c)
94
32.2
37.3
53.2
(a) Unless otherwise specified, all data in this data sheet are based on a 1982
telephone con vers ati on with Loren Baxter frOO1 the U.S. Anny Corps of
Engineers in Anchorage, Alaska.
(b) Based on estimates prepared for the Chakachamna hydroelectric project,
Vol ume XIV.
(c) Estimate.
A.23
SCHEDULE
Ava i 1 abil ity for Order
Preconstruction Studies and
Licensing (years)
Constructi on (years)
Startup (years)
Earliest COOIIT1ercial Service
Plant Life (years)
CffiT DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)
Working Capital ($/kW)
Fixed 08M ($/kW/yr)
Variable O&M (mills/kWh)
Payout Schedu le(d)
Year $
1 5,785,000
2 13,500,000
3 13,500,000
4 5,785,000
%
15.0
35.0
35.0
15.0
Escalation Factors (%/Year, 1981-2010)
Capita 1
08M
Economics of Scale
Available
2(c)
4
«1
1988
50
4817( a)
4( b)
44 (c)
None
See Table 25. 1
See Table 25.2
Not Appl icabl e
(a) Corps of Engineers October 1980 estimate (4288 $/kW), escalated to January
1981 using Handy Whi tman index. Costs escal ated from January 1981 to
January 1982 using escalation rates of Table 25.1 plus 9% general inflation
rate.
(b) Based on 30-day 08M costs.
(c) Based on Grant Lake estimate (CH M-H ill 1981).
(d) Based on Phung (1978) weak sinus6idal payout schedule.
A.24
TECHNICAL DATA SHEET 10.0
C HAKACHAMNA HYDROELECTRIC PROJECT( a)
The proposed Chakachamna hydroel ectric project would be a transmountai n
diversion project located near Chakachamna Lake, which ;s northwest of Cook
Inl et and about 85 air mil es west of Anchorage. Chakachamna Lake, with an
average natural water level of 1083 ft, would be used as a storage reservoir
for the project. Other facilities would include a power tunnel, surge tank,
power shaft. penstock, powerhouse and appurtenant structures. The 26-ft
diameter power tunnel, 10.8 miles in length. would extend in a southeasterly
direction from a water intake structure with an invert elevation of 894 ft to a
surge tank located to the north bank of the McArthur River. An OO-ft-diameter,
500-ft-high surge tank would be excavated in rock at the downstream end of the
power tunnel. A 26-ft diameter vertical power shaft would extend from the
bottom of the surge tank to the powerhouse elevation (",185 ft). From the base
of the power shaft, a steel penstock would lead to a surface powerhouse on the
north bank of the McArthur River. Four turbogenerator un its of 480-MW total
i nsta 11 ed capacity would be provi ded. The 185-ft ta il race el evati on woul d
provi de a net average head of 875 ft. PaNer waul d be transmitted over a 230-kW
double circuit line, ",115 miles in length. to Anchorage. (b)
TECHNICAL PERFORMANCE DATA
Installed Capacity (MW)
Size Range for Which Data
Are Generally Valid (MW)
Capacity Credit
Ebasco (1982)
480
Not App 1 i cabl e
Full
Bech te 1 (I 981)
330
Not Appl icabl e
Full
Capacity Limit in Railbelt (MW) Not Applicable Not Applicable
Typical Operati on Baseload/Cycl ing
(a) All data in this data sheet are taken from Volume XIV unless otherwise
i ndi cated.
(b) The above description is taken from Volume XIV. The design proposed by
Bechtel (1981) differs primarily in that water would continue to be
discharged to the Chakachatna River to support anadromous fish passage.
This results in a reduction in finn and average power output. installed
capacity. and power ttrme 1 di ameter.
A.25
Forced Outage Rate (%)
Schedul ed Outage Rate (%)
Equ;valent Avail abil ity (%)
Annual Firm Energy (GWh)
Average Annual Energy (GWh)
Equi val ent Capacity Factor (%)
SCHEDULE
Ava i 1 abil ity f or Order
Preconstruct; on St ud; es and
L i cens; ng (years)
Constructi on (years)
Startup (years)
Earliest CClT1IT1ercial Service
Plant Life (years)
CasT DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)
Working Capital ($/kW)
Fixed 0&1-1 ($/kW/yr)
Variable O&M (mills/kWh)
Payout Schedule
Ebasco Proposal(b)
Year 10 6 $ 1
1 111. 7 11
2 128.0 13
3 170.7 17
4 375.3 37
5 224.5 22
6
5
1.5
94
1845
1923
45.7
Ava i1 abl e
4
5
1/2
1991
50
2100(a)
Nil
4
Nil
Bechtel Proposal (c)
10 6 $ %
89.1 7
229.3 18
318.5 25
318.5 25
229.3 18
89.1 7
Not Appl i cabl e
Not Appl; cabl e
Not App 1 i ca b 1 e
1446
1570
54.3
Ava i 1 abl e
2.5
6
1/2
1991
50
3860(a)
N ;1
Not Appl icabl e
Not Applicable
(a) Does not include land or land rights, owner's cost or transmission system.
( b) Vol ume X IV •
(c) Based on Phung (1978) weak sinusoidal payout schedule.
A.26
Escalation Factors (%/Year, 1981-2010)
Capital
O&M
Economics of Scale
See Table 25.1
See Table 25.2
Not Applicable
A.27
TECHNICAL DATA SHEET 11.0
SNOW HYDROELECTRIC PROJECT(a)
The proposed Snow hydroelectric project would lie on the Snow River, which
is about 15 miles north of Seward and east of the Anchorage-Seward highway. An
earth-fill dam approximately 200 ft in height would be constructed across the
Snow River about 2 miles east of the Anchorage-Seward highway. This
construction would form a storage reservoir with a normal maximum water level
of 11~ ft. A power tunnel woul d 1 ead from an intake structure adj acent to the
main dam to a surge shaft approximately 7000 ft west of the main dam. A
penstock tunnel would lead an additional 2000 ft to a 50-MW installed capacity
underground powerhouse. A subsurface/surface tailrace would discharge to the
Snow River at a tailwater elevation of 500 ft slightly upstream of the 5unct i on
of the south fork of the Snow River (Acres American 1981b).
TECHNICAL PERFORMANCE DATA
Installed Capacity (MW)
Size Range for Which Data
Are Generally Valid (MW)
Capacity Credit
Capacity Limit in Railbelt (MW)
Typical Operation
Forced Outage Rate (%)
Schedu 1 ed Outage Rate (%)
Equivalent Availability (%)
Annual Firm Energy (GWh)
Average Annual Energy (GWh)
Equivalent CapaCity Factor (%)
50
Not Applicable
Full
Not Appl icabl e
Baseload/Cycling
5(b)
12.5 (c)
94
278 (d)
220
50
(a) All data in this data sheet are taken from Acres American (1981b) unless
otherwise indicated.
(b) Based on estimates prepared for the Chakachamna hydroelectric project,
Vol ume XIV.
(c) Estimate.
(d) Alaska Power Administration 1980.
A.29
SCHEDULE
Availability for Order
Preconstruction Studies and
Licensing (years)
Construct; on (years)
Startup (years)
Earliest COl11Tlercial Service
Plant Life (years)
can DATA
Estimated Costs (January 1982)
Overn i ght Capi ta 1 ($/kW)
Work; ng Capital ($/kW)
Fixed 08M ($/kW/yr)
Variable O&M (mills/kWh)
Payout Schedule(e)
Year $ %
1 29,300,000 10.0
2 73,100,000 2S.0
3 87,800,000 30.0
4 73,100,000 2S.0
5 29,300,000 10.0
Esca 1 at;on Factors (%/Year, 1981-2010)
Capita 1
08/t1
Economics of Scale
(a) Estimates.
Ava i1 abl e
2(a)
S( a)
«1 (a)
1989
SO
None
See Table 2S.1
See Table 2S.2
Not App 1 i ca b 1 e
(b) Acres American (1981b) estimate (S092 $/kW) in July 1980 dollars,
es cal ated to January 1981 using Handy-Whi tman index; escal ated to January
1982 using 9% annual rate of inflation plus 0.8% real escalation (Table
2S.1).
(c) Based on 30-day 08M costs.
(d) Based on estimates prepared for Browne hydroelectric project (Volume XV).
with powerhouse 0&101 (ass umed to constitute 50% of 08/t1 costs) taken at SO%
of Browne costs.
(e) Based on Phung (1978) weak sinusoidal payout schedule.
A.30
TECHNICAL DATA SHEET 12.0
STRANDL INE LAKE HYDROELECTRIC PRO~IECT( a)
The proposed Strandline Lake hydroelectric project would consist of a
diversion structure and powerhouse of 20-MW installed capacity on the Beluga
River, which is northeast of Cook Inlet.
TECHNICAL PERFORMANCE DATA
Install ed Capacity (MW)
S; ze Range for Whi ch Data
Are Generally Valid (MW)
Capacity Credit
CapaCity Limit in Railbelt (MW)
Typical Operation
Forced Outage Rate (%)
Schedul ed Outage Rate (%)
Equivalent Availability (%)
Annua 1 F inn Energy (GWh)
Average Annual Energy (GWh)
Equivalent Capacity Factor (%)
SCHEDULE
Availability for Order
Preconstruct; on Stud; es and
Licensing (years)
Constructi on (years)
Startup (years)
Earl iest Crnmerci al Service
Plant Life (years)
20
Not Applicable
Full
Not App 1 i ca b 1 e
Baseload/Cycling
5(b)
1.5(c)
94
81
85
99
Ava i 1 abl e
2(c)
4( d)
<1
1988
50
(a) All data in this data sheet are taken from Volume IV unless otherwise
i ndi cated.
(b) Based upon estimates prepared for the Chakachamna hydroe 1 ectri c proj ect,
Vol ume XIV.
(c) Estimate.
(d) Estimate based on Allison hydroelectric project (see Technical Data
Sheet 9.0).
A.3l
COST DATA
Estimated Costs (January 1982)
Overn i ght Capital ($/kW)
Working Capital ($/kW)
Fixed 08M ($/kW/yr)
Variable O&M (mills/kWh)
Payout Schedule(d)
Year $ %
1 21,700,000 15.0
2 50,700,000 35.0
3 50,700,000 35.0
4 21,700,000 15.0
Escalation Factors (%/Year, 1981-2010)
Capita 1
081-1
Economics of Scale
7240(a)
4( b)
44 (c)
None
See Table 25.1
See Table 25.2
Not Applicable
(a) Acres American (1981b) estimate (6300 $/kW) in July 1980 dollars,
escal ated to January 1981 using Handy Whi1man index; escal ated January 1982
using 9% annual rate of inflation plus 0.8% real escalation (weighted
capital cost escalation (60% material and equipment 40% labor) from Table
25.1.
(b) Based on 30-day 081-1 costs.
(c) Based on Grant Lake estimate. See Technical Data Sheet 8.0.
(d) Based on Phung (1978) weak sinusoidal payout schedule.
A.32
TECHNI CAL DATA SHEET 13.0
KEETNA HYDROELECTRIC PROJECT( a)
The proposed Keetna hydroel ectri c project woul d be located on the
Talkeetna River several miles east of the community of Talkeetna upstream of
the confl uence of the Sheep Ri ver. This project has been proposed as part of
an integrated system project that includes the proposed Cache and Talkeetna-2
hydroelectric facilities located upstream. The Keetna project would consist of
an earthfill dam approximately 350-ft high and 1200 ft in length. The
resul ting reservoir would have a normal maximum water level of ahout 945 ft.
The tailwater elevation of 615 ft would result in a maximum gross head of
330 ft. A separate rock cut channel, a spillway control structure and a
spillway would be provided. An intake and power tunnel would lead to a
penstock dropping to an aboveground powerhouse of 100-~ i nsta 11 ed capacity.
TECHNICAL PERFORMANCE DATA
Installed Capacity (MW)
Size Range for Which Data
Are Generally Valid (MW)
Capacity Credit
Capacity Limit in Railbelt (MW)
Typical Operation
Forced Outage Rate (%)
Schedul ed Outage Rate (X)
Equivalent Availability (%)
Annual Firm Energy (GWh)
Average Annual Energy (GWh)
Equivalent Capacity Factor (%)
100
Not Applicable
Full
Not Appl i cabl e
Base 1 oad/Cyc 1 in 9
S( b)
l.S(c)
94
324
395
45
(a) All data in this data sheet are taken from Acres American (1981b) unless
otherwise indicated.
(b) Based upon estimates prepared for the Browne hydroelectric project
(Technical Data Sheet 14.0).
(c) Estimate. A.33
SCHE DULE (a)
Ava i1 abil ;ty f or Order
Preconstruct; on Stud; es and
L; cens; ng (years)
Constructi on (years)
Startup (years)
Earliest Canmercial Service
Plant Life (years)
COST DATA
Estimated Costs (January 1982)
Overn i ght Capi ta 1 ($/kW)
W orki ng Capita 1 ($/kW)
Fixed O&M ($/kW/yr)
Variable O&M (mills/kWh)
Payout Schedu le(e)
Year 10 6 $ %
1 54.8 10.0
2 137.0 25.0
3 164.0 30.0
4 137.0 25.0
5 54.8 10.0
Esc alation Fac tors (%/Year, 1981-2010)
Capital
O&M
Economics of Scale
Ava il abl e
4
4.5
"'1/2
1991
50
5476{b)
<1 (c)
5( d)
Negligible
See Table 25.1
See Table 25.2
Not Appl icabl e
(a)
(b)
Based upon estimates prepared for the Browne hydroelectric project
(Technical Data Sheet 14.0).
(c)
(d)
(e)
Acres American (1981b) estimate in July 1980 dollars (4767 $/kW), escalated
to January 1981 using Handy Whitman index, line 22; escal ated to January
1982 using 9% annual inflation rate plus 0.8% real escalation.
Based on l)-day O&M costs.
Based on Browne hydroelectric project (Technical Data Sheet 14.0).
Based on Phunq (1978) weak sinusoidal payout schedule.
A.34
TECHNICAL DATA SHEET 14.0
BROWNE HYDROELECTRIC PROJECT(a)
The proposed Browne hydroel ectri c project woul d be located on the Nenana
River approximately two miles downstream of the Alaska Railroad sidinq of
Browne, which ;s approximately 65 air miles southwest of Fairbanks. The
proposed proj ect woul d cons i st of a dam, spi 11 way, reservo; r, aboveground
powerhouse and appurtenant structures. A zoned earth and rockfill dam is
proposed, 200 ft in height and 3000 ft lonq. A reservoir would be formed with
maximum pool elevation of 975 ft extending 11 miles south of the damsite. The
average tailwater elevation of 780 ft would provide a maximum gross head of
195 ft and an average operating head of 170 ft. A spillway would be prov; ded
at the left aootment of the dam. A water intake would be constructed in the
right abutment of the dam. A water intake would be constructed in the right
abutment at an invert elevation of 850 ft. A high-pressure power tunnel would
convey water to the penstoc k, whi ch woul d drop to the abovegound powerhouse
located on the ri ght bank downstream of the dam. Four turbogenerators of 100-
MW total rated capacity would be provided. 138 kV transmission lines would
lead to the proposed Anchorage-Fairbanks intertie.
TECHNICAL PERFORMANCE DATA
Install eel Capacity (MW)
Size Range for Which Data
Are Generally Valid (MW)
Capacity Credit
Capacity Limit in Rail belt (MW)
Typical Operation
Forced Outage Rate (%)
Schedul ed Outage Rate (%)
Equivalent Availability (%)
Annual Firm Energy (GWh/yr)
100
Not Applicable
Full
Not Applicable
Baseload/Cycling
5
1.5
94
298
(a) All data in this data sheet are taken from Volume XV unless otherwise
i ndi cated.
A.35
Average Annual Energy (GWh) 430
Equivalent Capacity Factor (%) 48
SCHEDULE
Availability for Order
Preconstruction Studies and
Licensing (years)
Construction (years)
Startup (years)
Earliest Commercial Service
Plant Life (years)
COST DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)
Working Capital ($/kW)
Fixed O&M ($/kW/yr)
Variable O&M (mills/kWh)
Payout Schedule (b)
Year 10 6 $ 1...
1 69.4 16
2 97.5 22
3 126.0 28
4 115.9 26
5 41.9 9
Escalation Factors (%/Year, 1981-2010)
Capital
O&M
(a) Based on 30-day O&M costs.
Available
4
4-1/2
'\,1/2
1991
50
4470
d(a)
5
Negligible
See Table 25.1
See Table 25.2
(b) Based on Phung (1978 weak sinusoidal payout schedule.
A.36
TECHNICAL DATA SHEET 15.0
UPPER SUS ITNA HYDROELECTRIC PROJECT(a)
The Upper Susitna hydroelectric project would consist of two major
hydroelectric dam and reservoir facilities located on the Upper Susitna River.
The Watana Dam and reservoir would be located near Watana Creek approximately
35 miles east of the A 1 as ka R ai 1 road (G 01 d Creek). The proposed dam woul d be
rockfill with an impervious core with a crest elevation of 2225 ft and a length
of 5400 ft. Maximum height above the foundation would be about 880 ft. A
small saddle dam would be located above the ri ght abutment. A spillway with
crest elevation of 2115 ft would be located on the riqht bank. A water intake
would be provided upstream of the left abutment and would lead to four
penstocks, whi ch waul d convey water to an underground powerhouse below the 1 eft
abutment. Initial plans called for four turbine generators of 200 MIl each to
be istalled in two stages; however, revised plans call for a total of 1020 MW
of installed capacity installed in two stages of 680 MN and 340 MW. A tailrace
tunnel would discharge to the river downstream of the dam. (b)
The Devil Canyon Dam and reservoir would be located in Devil Canyon approx-
imately 10 mil es northeast of Gol d Creek. A proposed dam woul d be a thi n arch
concrete structure with an overall hei ght of 650 ft, a crest el evati on of
1420 ft and a crest length of 1230 ft. A small saddle dam would be constructed
on the left abutment. A main gate-controlled spillway would be located on the
right abutment and a secondary gated spillway in the center section of the
dam. An emergency spillway with fusible plug would be located in the right of
the saddle dam. A water intake would be located upstream of the right
a butment; four concrete penstocks woul d 1 ead to an underground powerhouse below
the right abutment. Initi al pl ans called for 400 MW of installed capacity;
however, revised plans call for 600-MW of installed capacity.(b) Draft tubes
would discharge to a tailrace tunnel discharging downsteam.
(a) All infonnation in this data sheet is taken from Acres American (1981b)
unless otherwise indicated.
(b) Obtained from a letter: J.D. L1!.'Irence, Acres American, Inc., to J.J.
Jacobsen of Battelle, Pacific Northwest Laboratories, December 22, 1981.
A.37
The Devil Canyon Dam would be constructed to follow the Watana Dam, whi ch
would provide for sufficient storage capacity to allow optimal operation of
Devil Canyon. Prior to canpl etion of Devil Canyon, a small re-regul ating dam
woul d be cons tructed at the Devi 1 Canyon si teo Power woul d be transmitted from
the develo!lT1ent by up to four 345-kV 1; nes connecting to the proposed Anchorage-
Fairbanks intertie at Gold Creek.
TECHNICAL PERFORMANCE DATA
Installed Capacity (MW)
Si ze Range for Whi ch Data Are
Generally Valid (MW)
Capacity Credit (MW)
Capacity Limit in Railbelt (r-TW)
Typical Operati on
Forced Outage Rate (%)
Schedul ed Outage Rate (%)
Equ iva 1 ent A va il abil ity (%)
Annua 1 Firm Energy (GWh)
Annual Average Energy (GWh)
Equivalent Capacity Factor (%)
SCHEDULE
Ava i 1 abi 1 ity for Order
Preconstruction Studies and
Li cens i ng (years)
Cons truct i on (years)
Startup (years)
Earl iest Canmerci al Servi ce
Pl ant Life
Watana
1st Stage
680(a)
680
S(b)
l-l/2(b)
94 (b)
2631 (a)
34S9(a)
58
Watana
1st Stage
Ava il abl e
3
8
1/4
1993
50
Watana
2nd Stage
340 (a)
Not Applicable
340
Not Applicable
Baseload/Cycl ing
S(b)
l-l/2(b)
94 (b)
0
O(a)
0
Watana
2nd Stage
Ava; 1 abl e
(c)
2
1/2
1995
50
(a) Obtained from a letter: J.D. Lawrence, Aces American, Inc., to J.J.
Devil
Canyon
600(a)
600
5 (b)
1-1/2(b)
94 (b)
2763(a)
3334(a)
63
Devil
Can~on
Ava il abl e
(c)
8
1
1996
50
Jacobsen of Battelle, Pacific Northwest Laboratories, December 22, 1981.
(b) Typical, taken from Volume XIV.
(c) Schedul es for 2nd stage of Watana and Devi 1 Canyon depend upon compl eti on
of Watana access. A.38
COST DATA
Estimated Costs (January 1982)
Watana Watana
J.st Stage 2nd Stage
Overnight Capital ($/KW)(a) 4669 168
Working Capital ($/kW) Nil Nil
Fixed O&M ($/kW/yr) 5 (b) 5(b}
Variable O&M Nil Nil
Pay ou t Sc h edu 1 e ( c )
Watana Watana
1 st Stage
10 6 $
2nd Stage Dev i 1 Canyon
10 6 % Year % 10 6 $
1 127 4 29
2 239 11 29
3 508 16
4 603 19
5 603 19
6 508 16
7 349 11
8 127 4
Escalation Factors (%/year 1981-2010)
Capita 1
O&M
Economics of Scale
(a) Transmi ssi on costs are excluded.
(b) Battelle estimate.
%
50 95
50 571
794
794
571
95
See Table 25. 1
See Table 25.2
Not Appl icabl e
(c) Based on Phung (1978) weak sinusoidal payout schedule.
A.39
%
7
18
25
25
18
7
Dev; 1
Canyon
2263
Nil
5(b)
Nil
TE CHNI CAL DATA SHEET 16.0
M ICROHYDROELECTRIC PLANTS (a)
Microhydroelectric projects are typically defined as hydroelectric
projects of less than 100-kW (O.l-MW) installed capacity (Noyes 1980). A
typical microhydroelectric facility includes a water intake structure, a
penstock, a turbi ne-genertor un it, and a powerhouse. A dam and storage
reservoir may be used in scrne install ati ons; however, many mi crohydro
installations operate on run-of-the-stream. Off-grid installation may provide
for energy storage, generally in the form of lead-acid storage batteries. On-
grid installations will require a reversing meter, circuit breaker and
disconnect. For most of the utility-connected installtions, the utility line
at primary distribution voltage will have to be brought to the irrrnediate
vicinity of the microhydro generator, with connection to be made via a
di stri buti on transf ormer.
TECHNICAL PERFORw\NCE
Installed Capacity (typical) (MW)
Size Range for Which Data Are
Generally Valid (MW)
Capacity Credit
Capacity Limit in Railbelt (~)
T yp i ca 1 Oper at ion
Forced Outage Rate (%)
Schedul ed Outage Rate (%)
Ann ua 1 Firm E ner gy (GWh)
Aver age A nnua 1 E ner gy (GWh)
Typical Capacity Factor (%)
0.05
0.001 to 0.1
None
See Table 16.1
Fuel Saver
Variable
Variable
None
0.26(b)
60 to 100
(a) Data in this data sheet are taken from VolL8l1e IV unless otherwise indicated.
(b) Based on capacity factor of 60%, which ... !=~ the 10\A! end of 60% to 100% range
suggested in Alward, Eisenbart and Volkman (1979). Selected due to
presumed significant reduction in stream flow during cold seasons.
A.4l
TABLE 16.1. Estimated Economic Limits to Microhydroe1ectric
Development in the Rai1be1t
Anchorage Fa; rbanks Glennallen-
Load Center Load Center Load Center Total
Cost of Installed Installed Installed Installed
Power Capacity (nerr Capacity (ner1y Capacity Energy Capacity Energy
{$/kWh} {MW) GWh (MW) GWh (MW) (GWh} (MW} (GWh)
0.09
0.10 <1 1 <1 <1 1 1 <1 2
» 0.15 1 8 <1 <1 1 6 2 14 .
.p..
N 0.20 3 14 <1 <1 2 11 5 25
0.25 4 21 <1 1 3 17 7 39
0.30 5 27 <1 1 4 22 9 50
SCHEDULE
Ava i 1 abi 1 ity for Order
Preconstruction Studies and
Licensing (years)
Constructi on (years)
Startup (years)
Earliest Camlercial Service
Plant Life (years)
CC6T DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)
Local Plant (b)
Remote Plant
Worki ng Capital ($/kW) (c)
Loca 1 Plant
Remote Pl ant
Fixed 08lv1 ($/kW/yr)
Loca 1 Plant
Remote Pl ant
Variable 08lv1 (mills/kWh)
Payout Schedu le
Escalation Factors
Cap; ta 1
O&M
Economics of Scale
Ava il abl e
1t02{a)
:-::1
<1
1983
20
Low
5,000
12,000
6
20
75
240
Negl igi bl e
One shot
High
29,000
36,000
48
59
580
720
See Table 25.1
See Table 25.2
No i nf ann at i on ava il able.
(a) Upper end of range is based on t.wical small-scale ( 15 MW) hydro project
schedule (Corps of Engineers 1979).
(b) Five miles of transmission 1ine and access road required.
(c) Based on 3O-day 08lv1 cost.
A.43
TE CHNI CAL DATA SHEET 17.0
COOK INLET TIDAL ELECTRIC PROJECT(a)
Tidal electric power plants typically consist of a barrier (barrage)
across a bay or inlet that is subject to high tides. Intake (sluice) gates are
provided to admit water on incoming tides; horizontal axis turbine-generators
are provided to generate power as the outgoing tide drops below the level of
water retai ned behi nd the ti dal barrage. Appurtenant structures may i ncl ude
substations, transmission lines, navigational locks and vehicular crossinq
f ac i 1 iti es •
Examination of candidate sites in Cook Inlet resulted in the
recommendation of a potential site at Eagle Bay on Knik Arm for further study
(Acres American 1981a). The proposed Eagle Bay installation would consist of a
tidal barrage extending across Knik Ann at the narrowing of the channel above
Eagle and Goose Bays. The barrage would consist of an access dike from
shoresi de to the 1 ocati on of the fi rst powerhouse unit; 60 powerhouse modul es,
each containing a bulb turbine-generator unit of 24-MW rated capacity for a
total of 1440-MN of rated capacity; 36 sl ui CeNay modul es, and a closure di ke to
the far shore. A substati on and 230-kV or 345-kV transm;ss; on t; e woul d be
provided. A vehicular causeNay would be optional. An alternative (720-r+l)
design would use 30 turbine-generators.
Pumped storage capacity could be used to retime energy derived from tidal
power. Complementary pumped storage retiming projects were considered for each
Eagle Bay tidal electric project alternative.
(a) All data in this data sheet are taken from Acres American (1981a) unless
otherwise indicated.
A.45
TECHNICAL PERFORMANCE DATA
720-MW Plant 1440-MW Plant
Tidal Retiming Tidal Retiming
Facil it~ Facil it,~ Facilit~ Facilit~
Installed Capacity (MW) 720 450(a) 1440 1200(a)
Size Range for Which Data NA NA NA NA
Are Generally Valid
Capacity Credit (MW) None 225(b) None 600(b)
Capacity Limit in NA NA NA NA
Ra; 1 be lt (MW)
Typical Operation Intermittent Baseload Intermittent Baseload
Forced Outage Rate (%)(c) 5 5 5 5
Sch~d~led Outage Rate 1.5 1.5 1.5 1.5
(%) c
EQu,v1lent Availability 94 94 94 94
(%) c
Annual Raw Energy (GWh) 2300 4000
Annual
(GWh)
Usable Energy 1530{d~e) 2050{e~f) 1600{d~f) 3200{e~f)
Equivalent{C,pacity 24.3 32.5 12.7 25.4
Factor (%) g
NA = Not Applicable
(a) Installed pumping capacity.
(b) Installed generating capacity. Value shown for 720-MW alternative is an
assumption.
(c) Outage data taken from Volume XV. ,
(d) Approximately 10% of total system load could be directly absorbed without
retiming. These figures therefore vary with future system load.
(e) Estimated~ given Acres American (1981a) data on fraction of usable energy
and pumped storage efficiency.
(f) Total usable energy includes direct and retimed contribution.
(g) Based on tidal plant installed capacity.
A.46
SCHE DULE
720 -MW Plant 1440-MW P1ant
Tidal Retiming Tidal Retiming
Fac il it~ Fac il it~ Fac il it~ Fac il it~
Ava i 1 abil ity for Order Ava i 1 abl e Ava i 1 abl e Ava il abl e Ava il abl e
Preconstruction Studies 7 4(a) 7 4(a)
and Licensing (years)
4 (b) 5(b) Constr-ucti on (years) 11 11
Startup (years) (Included in constructi on )
Ear 1 i est Ccmnerci a 1 2000 2000( d) 2000 2000{ d)
Servi ce
Pl ant Life 50 50 50 50
COST DATA{e)
Estimated Costs (January 1982)
720 -MW Plant 1440-MW Plant
Overni r?f)Capital
($/kWh)
Work; ngd1 ~pi ta 1
($/kWh) J
Fixed 08M
Vari abl e O&M (mill s/kWh)
( a) Ass lITlp ti on .
Tidal Retiminq
F ac il ity F ac i 1 ity
3710 1150{g)
Nil Nil
22.20 10.60
Tidal
Fac i 1 ity
2690
Nil
16.20
(Included in Fixed 08M)
(b) Pumped storage data from Volume IV.
Ret imi ng
Fac il ity
1150( g)
Nil
10.60
(c) Constructi on peri od for 720-MW al ternati ve is assumed to be comparabl e to
1440-r1Il alternat1 ve.
(d) Pumped storage projects are assumed to be timed to come on-line with
associ ated ti da 1 power f ac i 1 it y.
(e) Costs were provided in June 1981 dollars in original report (Acres American
1981a). All costs have been escalated to January 1982 dollars using 9%
annual rate of inflation plus the 1981 capital cost escalator from Table
25.1.
(f) Does not include land or land rights, causeway or transmission
facilities. Owner's costs included.
(g) Based on kW of.pumping capacity.
(h) Incl udes 3D-day 08M costs.
A.47
Payout Schedule(a)
720-MW Alternative 1440-MW Alternative
No With No With
Retiming Retiming Ret imi nq Retiminq
Year 10(6)$ % 10 (6)$ % 10 (6) $ % 10 ( 6) $ %
1 107 4 107 3 154 4 155 3
2 214 8 214 7 310 8 310 6
3 294 11 294 9 426 11 426 8
4 347 13 347 11 504 13 504 10
5 374 14 374 12 542 14 542 10
6 374 14 374 12 542 14 542 10
7 374 14 374 12 542 14 680 13
8 347 13 425 13 504 13 849 16
9 294 11 475 15 426 11 840 16
10 214 8 395 12 310 8 655 12
11 107 4 184 6 154 4 293 6
Escalation Factors (%/year 1981-2010)
Capita 1 See Table 25. 1
081-1 See Table 25.2
Economics of Scale As prov; ded in 720-MW and 1440-MW
estimates.
(a) Based on Phung (1978) weak sinusoidal payout schedule.
A.48
TECHNICAL DATA SHEET 18.0
LARGE WIND ENERGY CONVERSION SYSTEr.fi(a)
Large wind energy conversion systems would consist of several
multimegawatt wind turbines configured as a wind farm. The prototypical system
examined in this study consists of ten 2.5-MW MOD-2, horizontal axis wind
turbines, arrayed in an integrated wind farm in the Isabell Pass area south of
Big Delta. In addition to the wind turbines, the prototypical wind farm
includes control, maintenance, substation and transmission facilities. Power
transmission from the prototypical site would be by a 138-kV single-circuit
line to the existing GVEA line at Fort Churchill and upgrading of the existing
15.8/24.4-kV Fort Churchill-Fairbanks line to 138 kV. Additional areas of
favorable wind resource are found in the Railbelt, and several wind farms of
the confi gurati on exami ned in the prototype coul d be constructed.
TECHNICAL PERFORMANCE DATA
Nominal Plant Size (MW)
Size Range or Which Data Are
Generally Valid (MW)
Capacity Credit
Capacity Limit in Railbelt (MW)
Typical Operation
Forced Outage Rate (%)
Schedul ed Outage Rate (%)
Equivalent Avail abil ity
Average Annual Energy
Equ i va 1 ent Capacity Factor (%)
25
Multi pl e Wi nd F arms of 25 tIW each
None
100 _ 1000 (b )
I ntermittent Baseload (fuel saver)
6
5
89
7.8
35.5
( a ) All data in thi s data sheet are taken from Vol ume XV I un 1 ess otherwi se
i ndi cated.
(b) Possibly limited to lONer levels because of system stability considerations.
A.49
SCHEDULE
Avail abil ity for Order
Preconstruction Studies and
Licensing (years)
Construction (years)
Startup (years)
Earliest Canmercial Service
Pl ant Life (years)
can DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)
Worki ng Capita 1 ($/kW)
Fi xed O&M ($/kW/yr)
Variable 0&'>1 (mills/kWh)
Pay ou t Sc h edu 1 e (f )
Year 10 ( 6) $ %
1
2
13.5
48.7
21.8
78.2
Escalation Factors (%/year 1981 -2010)
Capita 1
0&'>1
( a) EP RI (1979).
1-3/4
1/4
1988(c)
30
24!XJ (d)
<1 (e)
3.68
3.3
See Table 25.1
o
(b) A 11 CPNS one year f or site select i on and one year of site mon itori ng.
Additi onal monitoring may be desirabl e.
(c) Assumes site monitoring and licensing corrmences after commercial
availability ;s announced.
(d) Does not include land or land rights, CPNner's costs or transmission costs
beyond the pl ant switchyard.
(e) Inc 1 udes 30-day 0&'>1 cos t.
(f) Based on Phung (1978) sinusoidal payout schedule.
A.50
Economics of Scale
Capital
08J.1
A.51
• none for additional wind farms at
other sites
• shared transmissi on costs for up
to OO-M,.I capacity at Isabe 11 Pass
area
• shared maintenance, control
system, access and substation costs
for additional machines at proposed
site
• some fixed 08J.1 economies would
result from additional capacity in
Isabell Pass area.
TECHNICAL DATA SHEET 19.0
Sw\LL WIND ENERGY CONVERISON SYSTEMS(a)
Small wind energy conversi on systems (S\o.ECS) are wi nd turbi nes rated at
100 kW or less, of horizontal or vertical axis design. Machines currently in
production range in size from 0.1 to 37 kW. Typically, the siting of these
machines \lK)uld be dispersed, at the individual residence, commercial,
industrial, or small comnunity level.
SWECS may be operated independently of a util ity grid or interfaced with
the grid. Only grid-connected installations are considered in this study.
TECHNICAL PERFORw\NCE
Nom i na 1 Plant Size (MW)
Size Range for Which Data are
Generally Valid (MW)
Capacity Credit
Capacity Limit in Railbelt (MW)
Typical Operation
Forced Outage (%)
Schedul ed Outage (%)
Equivalent Availability
Average Annual Energy
0.0005 to 0.1
0.005 to 0.1 unless
noted
None
See Tabl e 19.1
Fue 1 Saver
1 (b)
1 (b)
98
A function of wind resource
avail abil ity. Pl ant capacity
f actor and corres pondi ng average
annual energy is estimated to be as
follC7NS for the various wind
resource cl asses of Wise et al. (1980):
(a) All data in this data sheet are taken from VollJl1e IV unless indicated
otherwise.
(b) Bonneville Power Administration (BPA). 1981 (draft). Technical Assessment
of the Potential for Conservation and End Use Renewable Resources in the
West Group Area. Bonneville Power Administration, Division of Power
Requirements/Division of Conservation, Portland, Oregon.
A.53
):> .
(JI
~
TABLE 19.1. Estimated Economic Limits to Small Wind Energy
Conversion System(a) Development in the Rai1belt
Anchorage Fairbanks Glennallen
Load Center Load Center Load Center Total
Insta l1ed Installed Insta lled Installed
Capacity Energy Capacity· (neryy Capacity Energy Capacity Energy
1 $/kWh) (MW) (GWh) (MW) GWh (MW) (GWh) (MW) (GWh)
0.05
0.06 5 16 <1 <1 <1 <1 5 16
0.07 10 31 3 7 <1 1 13 39
0.08 14 41 5 13 <l 2 19 56
0.09 14 41 5 13 <1 2 19 56
0.10 28 71 9 22 <1 3 37 96
0.15 34 81 16 34 4 9 54 124
(a) Assumes full penetration of SWECS whenever economically feasible for cost of power shown.
In practice, penetration will likely be substantially less due to constraints such as
limitation on installation of SWECS in urban areas and reluctance of many homeowners to
deal with a SWECS.
Average
Wi nd Resource Capacity Factor E ner gy (a)
Class (%) GVl1/yr
1 10 0.009
2 15 0.013
3 20 0.018
4 25 0.022
5 30 0.026
6 35 0.031
7 40 0.035
SCHE DULE
Earliest Canmercial Service(b) 1983
Preconstruction Studies and l(c)
Licensing (years)
Cons tr uct i on (years) < 1
Startup (years) <1
Pl ant Life (years) 20
can DATA
Estimated Costs (January 1982}(d)
2 kW 10 kW
Overn i ght Capital ($/kW) (e) 2960 2378
Wor ki ng Ca pita 1 ($/kW)
Fixed 081>1 ($/kW/yr) 30 24
V ari abl e O&M (mill s/kWh)
(a) 10 kW (0.01 MW) machine.
(b) Machines could be production limited if demand were to increase
substanti ally.
(c) Minimum recommended time for wi nd resource survey.
(d) Base costs from Volume IV~ escal ated from July 1980 to January 1981~ using
Handy Whitman distribution plant escalation indices; and escalated from
January 1981 to January 1982 using a 9.0% annual rate of i nfl at; on pl us the
1981 weighted (60% material~ 40% labor) capital cost escalator (0.8%) of
Table 25.1 and the 0% 081>1 cost escal ator of Table 25.2.
(e) Does not include land or land rights.
A.55
Payout Schedule
Escalation Factors (%/yr 1981 to 2010)
Capital
O~
Economics of Scale
A.56
One shot
See Table 25.1
See Table 25.2
As provided in estimates for 2-kW
and lO-kW machi nes.
TECHNICAL DATA SHEET 20.0
REFUSE-DERIVED FUEL STEAM-ELECTRIC POWER PLANTS
Two steam-electric generating facilities using municipal refuse may be
feasible for the Railbelt region. One plant, constructed near Anchorage, would
be fired with municipal refuse from the Anchorage area, supplemented with wood
waste as available and coal transported by rail from the Nenana field. A plant
of 50-MW rated capacity probably could be supported; the proportion of refuse-
derived fuel would increase over time with greater Anchorage population
growth. A 50-MW plant coming on-line in 1990 could accommodate the average
municipal waste production of the Anchorage area until approximately year 2010.
A second plant of smaller size could be constructed near Fairbanks to use
refuse from the Fairbanks area and possibly wood waste from sawmills near
Fairbanks and Nenana. Supplemental firing by coal from the Nenana field would
be required during the early years of plant operation. A plant of 20-MW rated
capacity coming on-line 1990 could accommodate municipal waste production from
the Fairbanks area until approximately 2010. Either mass-burning or refuse-
derived fuel plant designs could be used.
TECHNICAL PERFORMANCE DATA
Anchorage Fairbanks
Nominal Plant Size (MW) 50 20
Size Range for Which Data As Given As Given
Are Generally Valid (MW)
Capacity Credit Full(a) Full(a)
Capacity Limit in Railbelt (MW) 50 50
Typical Operation Baseload Baseload
Heat Rate (Btu/kWh) 14,000 14,800(b)
Forced Outage Rate (%) Not Applicable Not Applicable
Scheduled Outage Rate (%) Not Applicable Not Applicable
Equivalent Availability (%) 85(c) 85(c)
(a) With supplemental firing of coal or wood residHe.
(b) Obtained by fitting a curve of the form y = ax to data of Volume IV.
(c) Average of values in Volume IV.
A.57
SCHEDULE
FUEL
Avail abil ity for Order
Preconstruction Studies and
L; cens; ng (years)
Construction (years)
Startup (years)
Earliest Canmercial Service
Plant Life (years)
Can pos i t i on
RDF Availability
Heat Val ue
COST DATA
Estimated Costs (January 1982)
Overni ght Capital ($/kW) (c)
Working Capital ($/kW)(d)
(a) Estimate.
Ava il abl e
3( a)
1-1/2 - 3
<1
1987
30
Municipal refuse supplenented by
coal delivered from Nenana as
required.
See Table 20.1
Nenana Coal: 8,000 Btu/lb(b)
RDF: 6,700 Btu/lb
Anchorage
2890
93
Fairbanks
3230
94
(b) As received, mlllicipal solid waste would have a heat value of approximately
4500 Btu/lb if direct-fired to a mass burner.
{c} Costs of Volt.me IV escalated to January 1981 using Handy Whitman steam
production pl ant index; escal ated to January 1982 using 9% annual infl at; on
rate plus real capital cost escalation rate of Table 25.1.
(d) q)-day coal pil e pl us 3O-day O&M.
A.58
Fixed O&M ($/kW/yr)
Variable 081>1 (mills/kWh)
Fuel ($/MMBtu): ROF(b)
Coa 1 (c)
Payout Schedu le (d)
Anchorage
Year 10( 6)$ %
1 37.3 25
2 74.6 50
3 37.3 25
Fairbanks
10 (6)$ %
16.6 25
33.2 50
16.6 25
Escalation Factors (%/year, 1981-2010)
Capital
081>1
F ue 1 ( % ) : R OF
Coal
Economies of Scale
Capital
Fi xed O&M
V ari abl e O&M
Fuel
Anchoraoe
136( a)
14.8(a)
Fai rbank s
136 ( a )
14.8(a)
See Table 26.1
1. 28 1. 21
Anchorage Fairbanks
See Tab 1 e 25. 1
See Table 25.2
See Table 26. 1
See Tabl e 26.1
20-50 MW: as est; mated above
50-150 MW: 1 i near
None identified
None i dent i fi ed
None i dentifi ed
(a) Estimates based on fixed and variable fractions of SRI (1979), escalated in
accordance with Table 20.1.
(b) Unprocessed municipal solid waste could have a negative cost (tipping fee),
(c) Nenana coal, delivered.
(d) Based on Phung (1978) weak sinusoidal payout schedule.
A.59
TABLE 20.l. Estimated RDF Ava il abil ity
(average tons/day)
Year Anchorage Fa i rb ank s
1985 396 150
1990 502 190
1995 640 240
2000 777 290
2005 890 330
2010 1010 380
A.60
TECHNI CAL DATA SHEET 21. 0
RES IDE NT IAL BUILDING CONSERVATION
Building energy conservation projects encompass a variety of techniques
for reducing the electri cal load of resi denti al structures heated with
electricity. Electricity heated structures currently comprise about 21% of
Anchorage households, 9% of Fairbanks households, and 1% of Glennallen-Valdez
households.(a) Energy savings and choice of these techniques depend on the
size and age of structure and on the cl imate at the location of the structure.
The cost-effective techniques on new structures include extra insulation in the
ceiling (R-60), insulated doors, triple pane windows, and extensive care in
sealing and caulking to reduce air changes from 1.0 down to 0.25 (Barkshire
1981a). Cost-effecti ve meas ures for retrofittin~ exi sting buil dings i ncl ude
adding insulation to the floors and ceilinq to bring their insulatinq value up
to R-40 and R-60, respectively. The walls are left at current R-values. Other
assumed improvements include a third pane of glass on all windows, R-8
insul ated doors, and sufficient caulking and sealing to bring air infiltration
down to 0.5 air changes per hour (Barkshire 1981b). Insulation;s assumed to
be applied by contractors, whereas glazing, caulking, and weatherstripping are
appl i ed by the owner. For new construct; on, energy II savi ngsll of new
constructi on improvements over standard practi ces are 289.1 Btu/hr-of.
TECHNICAL PERFORMANCE
Nominal Plant Size
Size Range for Which Data Are
Generally Valid (MW)
1500 square foot house
1000 to 2500 square feet
(a) Obtained from a Battelle-Northwest Railbelt energy end-use survey conducted
in April 1981.
A.6l
Capacit,v Credit
Capacity Limit in Railbelt (MW)
Typical Operation
Forced Outage
Schedul ed Outage (%)
Typical Capacity Factor (%)
Annual Firm Energy (kWh)
Average Annual Energy (kWh)
SCHEDULE
Availability for Order
Preconstruction Studies and
L i cens i ng (years)
Constructi on (years)
Startup (years)
Earliest Canmercial Service
Pl ant Life (years)
C(ET DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)
Anchorage
Fairanks
Gl enna 11 en-Val dez
Working Capital ($/kW)
Fixed 08M ($/kW/yr)
See Table 21.1(a)
Not estimated
Conservati on with capacity credit.
(seasonal peaking offset)
o
o
100
(a' Same as annual energy j
See Tabl e 21.1 (a)
Ava i 1 abl e
<1
<1
<1
1982
30 (b)
New Construction
652
566
605
0
0
Retrofits
501
435
464
0
0
(a) Equals difference in load between superinsulated house and current best
standard practice. See Barkshire 1981a; Barkshire 1981b.
(b) New construction. For retrofit applications, the caulking required to seal
the structure may have to be replaced at 20 years.
A.62
TABLE 21.1. Performance and Capital Cost of ReH~ential
Bu i1 di ng Conser vat i on Improvements
New Bu i 1 d; n9 Anchorage Fairbank s Glennallen-Valdez
Heat Loss Improvement per 21,974 29,300 25,637
Installation (kWh/yr)
Install ed Cost of Improvements $4,885 $5,180 $6.158
Conserved Energy at Peak ( kW) 7.49 9.15 8.32
(-20 F) (-40 F) (-30 F)
I nsta 11 ed Cost per kW $652.20 $566.12 $740.14
Retrofit Standard Practi ce
Building
Heat Loss Improvement per 14,503 19,103 16,803
Install ation (kWh/yr)
Ins ta 11 ed Cost of Improvements $2,500 $2,651 $3,152
Conserved Energy at Peak ( kW) 4.99 6.10 5.55
(-20 F) (-40 F) (-30 F)
Installed Cost per kW $501.00 $434.59 $567.93
(a) 1500 square feet of living space. Improvements are improvements over late
1970's standard building practice as follows:
Walls: R-19 (6" fiberglass batt, 2 x 6 wall)
Floors: R-19 (6" fiberglass batt)
Doors: R-8 (met ali ns ul ated )
Roof: R-30 (9" fiberglass batt)
Air changes per hour: 6.0
Base Heat Loss: 503 Btu/hr-F. In Anchorage, 131 MMBtu per year; in
Fairbanks, 173 Mr.t3tu per year. Glennallen-Valdez savings are asslfTled to be
the average of Anchorage and Fairbanks values.
(b) Costs mul ti pl i ers were estimated as follows by an Anchorage cost-estimating
firm for Alaska Renewable Energy Associates:
-Anchorage (base) = 100.0
-Anchorage zone (up to 50 mil es) = 110.03
-Anchorage zone (beyond 50 miles) = 122.43
-Fa i r banks = 106. 04
-Fairbanks zone (up to 50 mil es) = 117.71
-Fairbanks zone (beyond 50 miles) = 129.69.
Glennallen-Valdez cost is an average of Anchorage and Fairbanks zones,
beyond 50 mil es.
A.63
TECHNICAL DATA SHEET 22.0
RES IDE NT IAL PASS IVE SOLAR SPACE HEAT
The proper placement and use of windows in housing in the Railbelt region
have consi derabl e potenti al for reducing the space heat demand of these
structures on an annual basis. However, the ability of the h011eowner to use
the solar resource depends on the building's location and orientation. Also,
passive solar applications are generally restricted to neN buildings or
additi ons because of the diffi cul ty of retrofitti ng an exi sti ng struct urea The
most popular form of retrofit applications of passive solar is to add a
greenhouse to the south wall of an existing structure, although this is a
relatively inefficient way to reduce heating bills (Barkshire 1981a and
1981b). (a) A site survey of the Alternative Energy Technical Assistance
Program during the s urrmer of 1981 showed about one si xth of 1200 Anchorage
sites had open access to the sun the year round. 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. Sunlight;s not generally available during the peak
heating periods of December and January to make a net contribution.
Consequently, this technology is given no credit for peak demand.
The assumptions made in the Railbelt Electric Power Alternatives Study for
passive solar are as follows. A basic 1500 square foot house is assumed to be
oriented so that it has 200 square feet of south-facing gl ass. No thermal
storage is assumed. About 19.3 MMBtu of net solar gain is assumed, (about
(a) Retrofits are generally difficult because existing structures have not
generally been oriented with sol ar in mind. Costs of sol ar greenhouses
approach those of regular construction, whereas direct gain (windows) or
conservation alone is more cost effective in most cases. The upper assumed
limit of market penetration for solar retrofits is 5 to 10% of the building
stock.
A.65
13.8 MM3tu more than a standard house). The assumed solar retrofit is an 8-
foot by 2O-foot solar greenhouse, which supplied 10 to 15% of the heat required
by the basic 1500 foot house. (a)
Technical considerations (site characteristics) limit penetration of
passi ve sol ar space heat appli cati ons to about 35 to 50% of the new building
stock, whereas solar greenhouses designed for heat supplenent are expected to
be 1 ;mited to 10 to 15% of the exi sting housing stock.
TECHNICAL PERFORMANCE
Nan ina 1 Plant Size
Size Range for Whi ch Data Are
Gener all y Val i d
Capacity Credit
Capacity Limit in Railbelt (MIN)
Typi ca 1 Operati on
Forced Outage (%)
Scheduled Outage (%)
Typical Capacity Factor
Annual Firm Energy (kWh)
Average Annual Energy (kWh)
200 square feet of south glazing
60-200 square feet
o
Not assessed
Conservation without capacity
credit (fuel saver).
o
o
Not applicable
Unknown
4 043(b) ,
(a) The solar greenhouse performace is estimated by Barkshire (1981b) at 10 to
15% of the base house's heat loss of 131 MM3tu per year in Anchorage. The
greenhouse costs are estimated in the same sources at $30 to $40 per square
foot. Because the estimates are for a rel ati vely el aborate greenhouse, the
top end of the cos t range is used.
(b) Equals difference from standard practi ce home, assl.Jl1ed to have 32.5 square
feet of south glazing, about 13.8 MM3tu/yr.
A.66
SCHE DULE
Ava i1 abil ity f or Order
Preconstruction Studies and
Licensing (years)
Constructi on (years)
Startup (years)
Earliest Carmercial Service
Plant Life (years)
CCBT DATA
Estimated Costs (January 1982)
Overni ght Capital
Working Capital
Fixed aRM ($/kW/yr)
Available
<1
<1
<1
1982
30+( a)
See Tabl e 22.1
o
o
(a) Life of the dwelling for new construction. About 10 years for solar
greenhouse retrofit.
A.67
TABLE 22.1. Performance and Capital COH)of Residential
Pass; ve Sol ar Improvements
New Bu ilding Fairb ank s Glennallen-Valdez
Heat Equi val ent Improvement
Over Standard House (kWh/yr)
Anchorage
4,043 4,043 4,043
Installed Cost of Improvement
Energy Available at Peak (kW)
Ins tall ed Cos t per kW
$1,330
o
NA
$1,410
o
NA
$1,677
o
NA
Retrofit
~~:; ~i~~~:~~n~o~~~r(~~~i~)(b) 4,600 4,600 4,600
Installed Cost of Improvement(c)
Energy Available at Peak (kW)
$6,400
o
$6,787
o
$8,067
o
Ins ta 11 ed Cost per kW NA NA NA
(a )
(b)
(c)
New construction based on 200 square feet of south-facing glass, no thermal
storage. Retrofits based on sol ar greenhouse.
Assumes for Anchorage 34.4 MMBtu solar radiation, and a heat load
(shuttered R-30 greenhouse) of 18.7 MM3tu. Net gain to structure equals
15.7 tJMBtu or 4600 kWh/yr in Anchorage. Heat loss in Fairbanks asslJ11ed 32%
hi gher for any gi yen R-val ues, but greenhouse is R-50 rather than R-30.
Sunlig,t is also 15 to 20% greater. Net gain ;s still 1B.7 I'M3tu.
Glennallen-Valdez is assumed to be the average of Anchorage and Fairbanks.
Greenhouse is 8 feet by 20 feet with 130 square feet of south-facing
qlass. See Volume IV.
AsslJ11es sol ar greenhouse 8 ft wi de x 20 ft long:: 160 square feet at $40
per square foot. R-30 ins ul at; on, shuttered 130 square feet of south-
facing glass. For multipliers, see Technical Data Sheet 21.0.
A.68
TECHNICAL DATA SHEET 23.0
RESIDENTIAL ACTIVE SOLAR HOT WATER
Active solar technology has some potential in the Railbelt to reduce the
load on the conventional hot water systems. The effectiveness of the system
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 1981a).(a) New
and retrofit units selected for the study assume 80 square feet of collector
using Sola Roll -type technology because this appears to be the most cost
effective.(b) About 50% of the annual water-heating load of a family of four
can be met with such an installation, at about 80 gallons per day use. The
proportion of such use, which can be met by solar during the year, varies by
month~ from about zero in November through February~ to about 85% in April
through June.(c)
Limitations on market penetration are expected because of very long
payback caused by high installation costs, holding the total market to 5 to 10%
of hot water users (Barkshire 1981a).
TECHNICAL PERFORMANCE
Nominal Plant Size
Size Range for Which Data Are
Generally Valid
80 square feet of flat collector
80 to 120 square feet
(a) For a more complete description of systems, see Volume IV, Chapter 8.
(b) A trademark from Bio-Energy Systems, Inc., Ellenville, New York.
(c) Although Railbelt households tend to be smaller, more water-using
appliances are available than in typical U.S. homes. This was a finding in
Battelle-Northwest's residential end-use survey. The 50% figure is from
Barkshire (1981b).
A.59
Capacity Cred it
Capacity Limit in Railbelt (MIl)
Typi ca 1 Oper ati on
Forced Outage Rate (%)
Schedul ed Outage Rate (%)
Typi cal Capacity Factor
Annual Firm Energy (kWh)
Average Annua 1 Energy (kWh)
SCHEDULE
Avail abil ;ty for Order
Preconstruct; on Studi es and
li cens; ng (years)
Construct; on (years)
Startup (years)
Earliest Canmercial Service
Pl ant Life
can DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)
Anchorage
Fairbanks
Glennallen-Valdez
Worki ng Capital
Fixed C&M ($/kW/yr)
o
Not assessed
Conservati on without capacity
credit (fuel saver)
Low
Low
Not appl i cabl e
Unknown
3,3~(a)
Ava il abl e
<1
<1
<1
1982
20 years
New Construe tion Retrofits
Not comparabl e with
generation systems
NA NA
Not comparable with
generation systems
{a} Equals energy savings for the collector on an annual basis for a system
that uses the heated medium (water) directly. This estimate is based on
matching loads of a fanily of 4 persons by month, for 11.57 t+1Btu/year.
Load is assumed to be 80 ga 11 ons/day of hot water.
A.7D
TABLE 23.1. Performance and Costs of ~a~idential
Acti ve Sol ar Improvements
Anchorage Fairbanks Glennallen-Valdez
Heat Equi val ent Improvement 3,390 3,390 3,390
Over Standard House (kWh/yr)
Ins ta 11 ed Cost of Improvement (b) $3, 000 $3, 000 $3, 000
Energy Available at Peak (kW) a a a
Ins ta 11 ed Cost per kW NA NA NA
Operati ons and Mai ntenance Costs $25/yr $25/yr $25/yr
(a) Based on 00 square feet of Sola Roll-type collector, tanks and piping.
(b) Based on $25 per square foot average for Ra il belt, pl us $1000 other system
costs.
A.71
TECHNICAL DATA SHEET 24.0
RES IDENTIAL WOOD SPACE HEAT
Wood is already a supplementary fuel of choice in many Railbelt·
communities. Unlike other dispersed technologies, it is not resource or
weather 1 imited at this time. The analysis of wood stoves in the Railbelt
Electric Power Alternative Study was done on the presumption that at maximum
penetrati on, one fifth of s pace heat requi red by hones heated with passi ve
solar of the supplemental technology, and one fifth of the space heat required
by nonsolar hones would be provided by wood. This is equivalent to more than
a doubl ing of the current market penetrati on of wood space heat--or 20% of the
total market (Barkshire 1981b). Inconvenience, fuel cost, and difficulty in
using wood in multif<rnily units should limit maximum market penetration, even
at low capital cost.
Many types of wood stoves and firepl ace inserts are on the market. The
cost and perfonnance assumed in the study are for a high-quality airtight stove
of heavy-gauge steel and soapstone. Stoves are available in sizes with heating
capabilities ranging fran 15,000 to over 100,000 Btu per hour with conversion
efficiencies of 20 to 65%. The top end of the conversion efficiency range is
chosen, a down-draft stove of about 50,000 Btu/hr capacity, 65% efficiency,
lasting 20 years, and costing $2700 completely installed. Installation takes
about two days (Barkshire 1981a).
TECHNICAL PERFORMANCE
Nan ina 1 Plant Size
Size Range for Which Data Are
G ener ally Val i d
Capacity Credit
Capacity Limit in Railbelt (MW)
Typi ca 1 Operati on
Forced Outage Rate (%)
A.73
50,000 Btu/hr
40-50,000 Btu/hr
14.65 kW
Not assessed
Conservati on with capacity
credit (seasonal peak offset)
°
Scheduled Outage Rate (%)
Typical Capacity Factor
Annual Firm Energy (kWh)
Average Annual Energy (kWh)
SCHEDULE
Availability for Order
Preconstruct;on Studies and
Licensing (years)
Construction (years)
Startup (years)
Earliest Commercial Service
Pl ant Life
COST DATA
Estimated Costs (January 1982)
Overnight Capital ($/kW)
Working Capital
Fixed O&M ($/kW)
A.74
o
Not applicable
Unknown
See Table 24.1
Available
<1
<1
<1
1982
20 years
$177
o
$6.82
TABLE 24.1. Performance and Costs of Residential
Wood Space Heat
Anchorage Fairb ank s Glennallen-Valdez
Heat Equi val ent Improvement (kWh/yr )
New ( 50%)
With Sol ar (25%) 12.365 17,346 14,855
Without Solar (25%) 16,408 21,389 18,898
Retrofit (5ax;)
With Solar (15%) 11,808 16,789 14,298
Without Sol ar (35%) 16.408 21,389 18,898
Average (a) 14,707 19,688 17,197
Installed Cost of Improvement ( $) 2,700 2,700 2,700
Capacity Offset at Peak (kW) 14.65 14.65 14.65
Installed Cost per kW ($) 177 177 177
Oper at i on an~b~ai ntenance 431 540 486
Costs ($/yr)
( a) Ass !Jl1es new homes com pr i se about 5ax; of the stock in each area.
Penetrati on is ass!Jl1ed to be 20% of all types at maxim!Jl1 and proceeds
proportionately for all tj1)es.
(b) Ass!Jl1es 65% conversion efficiency. Wood at $80/cord, 12.5 M'v1Btu/cord
effective heat (about 19,300 Btu/cord for birch heat content). Annual
maintenance at $100/yr.
A.75
TECHNI CAL DATA SHEET 25.0
ES CALA TI ON SE R IES
The escalation series used for this study are given in Table 25.1 (capital
cash) and Table 25.2. All projects used the "standard ll series except as
indicated. All escalation factors are ureal", and do not include general
inflation.
TABLE 25.1 Capital Cost Real Escalation Series
Escalation Factors
"Standard" Chakachamna
Year %/year(a) %/year(b)
1981 0.8 0.9
82 1.4 1.4
83 1.4 1.4
84 1.0 0.9
1985 0.0 0.0
86 -0.1 -0.1
87 0.3 0.3
88 0.8 0.8
89 1.0 1.0
1990 1.1 1.1
91 1.6 1.6
92 2.0 2.0
93 2.0 2.0
94 2.0 2.0
1995-on 2.0 2.0
( a) From Volume XI I; 40% 1 abor, 60% materi ale
(b) F rom Vol ume XIV; 30% 1 abor, 70% materi a 1.
(c) From Volume XV; 25% labor, 75% material.
(d) From Volume XVI; 7% labor, 93% material.
A.77
Browne
%/year(c)
0.9
1.3
1.3
0.9
0.0
-0.1
0.3
0.8
1.0
1.1
1.6
2.0
2.0
2.0
2.0
Wind Energy
%/year (d)
0.9
1.2
1.2
0.7
0.0
-0.1
0.3
0.8
1.0
1.1
1.6
2.0
2.0
2.0
2.0
TABLE 25.2. Operation and Maintenance Cost
Real Escalation Series
Standard(a) Wind Energy
Year %/'t.r %/yr
1981 1.5 0.0
1982 1.5 0.0
1983 1.6 0.0
1984 1.6 0.0
1985 1.7 0.0
1986 1.8 0.0
1987 1.8 0.0
1988 2.0 0.0
1989 2.0 0.0
1990 2.0 0.0
1991 2.0 0.0
1992 2.0 0.0
1993 2.0 0.0
1994 2.0 0.0
1995-on 2.0 0.0
(a) Includes Chakachamna and Browne hydro.
A.78
TECHNICAL DATA SHEET 26.0
FUEL PRICE SERIES
Fuel prices used for the Railbelt Electric Power Alternatives Study are
given in Table 26.1. Background information is provided in Volume VII. Note
that Table 26.1 ;s given in 1982 dollars. Fuel prices used for the cost
estimates of Volumes II and IV were in 1980 dollars.
A.79
):> . co
0
TABLE 26. I. Fuel Prices Used for the Railbelt Electric
Power Alternatives Study ($/MMGtu}(a)
Cook Inlet
Belug~ ) Nenana Natural Gas (d)
Year Coal b Coal (c) AGSeS
1982 1.67 1.75 1.12
83 1.73 1.79 1.10
84 1.76 1.82 1.11
1985 1.80 1.86 1.12
86 1.84 1.90 1.41
87 1.88 1.94 1.63
88 1.91 1.98 1.73
89 1.95 2.02 1.95
1990 2.00 2.07 2.20
91 2.04 2.11 3.80
92 2.08 2.15 3.89
93 2.12 2.20 3.97
94 2.17 2.25 4.06
1995 2.21 2.29 4.16
96 2.26 2.34 4.25
97 2.31 2.39 4.35
98 2.36 2.44 4.47
99 2.41 2.49 4.57
2000 2.46 2.54 4.70
2000+ 2.1%/yr 2.fJi/yr (1)
escalation
January 982 dollars, fJi inflation.
Minemouth.
fOB rail, Nenana.
Cook Inlet
Dist 111 ate (g) Natural Gas(e)North Slope(f)
CEA Natural Gas fuel Oil Peat
0.46 6.90 1. 75-5.25
0.46 7.04 1. 77-5. 30
0.46 7.19 1.79-5.36
0.51 7.34 1.80-5.41
0.54 7.50 1.82-5.46
0.66 7.66 1.84-5.52
0.70 5.92 7.82 1.86-5.57
0.78 5.41 7.98 1.88-5.63
0.90 4.97 8.15 1.89-5.68
1.53 4.58 8.32 1.91-5.74
1.66 4.25 8.49 1.93-5.80
1.87 3.97 8.67 1.95-5.86
2.00 3.72 8.85 1.97-5.92
2.17 3.50 9.04 1.99-5.97
4.46 3.32 9.23 2.01-6.03
4.56 3.16 9.42 2.03-6.10
4.68 3.02 9.62 2.05-6.16
4.78 2.90 9.82 2.07-6.22
4.91 2.80 10.03 2.09-6.28
(1) (j) 2.fJi/yr l%/yr
Weighted average price to Alaska Gas and Service Co. (without Pacific Alaska LNG project).
Weighted average price to Chugach Electrical Association.
fairbanks city gate.
De livered.
Cost of RDf processing offset by tipping fees.
Availabiity of Cook Inlet gas is uncertain following year 2000.
Price is expected to stabilize at about $2.70/MMBtu.
Refuse-Deri~ed
fuel(h
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
REFERENCES
Acres American Incorporated. 1981a. Preliminary Assessment of Cook Inlet
Tidal Power. Prepared for Office of the Governor, State of Alaska, Juneau,
Alaska.
Acres American Incorporated. 1981b. Susitna Hydroelectric Project Development
Selection Report. Prepared for the Alaska Power Authority, Anchorage,
Alaska.
Alaska Power Administration (APA). 1977. Bradley Lake Project Power Market
Analysis. U.S. Department of The Interior, Alaska Power Administration,
Juneau, Alaska.
Alaska Power Administration. 1980. Hydroelectric Alternatives for the Alaskan
Railbelt. U.S. Department of Energy, Alaska Power Administration, Juneau,
Alaska.
Alward, R., S. Eisenbart, and J. Volkman. 1979. Microhydro Power: Reviewing
an Old Concept. Prepared by the National Center for Appropriate Technology
for the U.S. Department of Energy, Washington, D.C.
Barkshire, J.A. 1981a. Energy Conservation, Solar, and Wood for Space and
Water Heatin l : A Preliminarf Report on Costs and Resource Requirements in
Alaska's Rai belt Region. A aska Renewable Energy Associates, Anchorage,
Alaska.
Barkshire, J.A. 1981b. Maximum Possible Technological Market Penetration of
Selected Renewable Energy Technologies in Alaska's Railbelt Region. Alaska
Renewable Energy Associates, Anchorage, Alaska.
Bechtel Civil and Minerals, Inc. 1981. Chakachamna Hydroelectric Project
Interim Report. Prepared for the Alaska Power Authority, Anchorage, Alaska.
CH 2M-Hill. 1981. Feasibility Assessment: Hydropower Development of Grant
Lake. CH 2M-Hill, City of Seward, Alaska.
Ebasco Services Incorporated. 1982a. Browne Htdroelectric Alternative for
the Railbelt Region of Alaska. Prepared by basco Services Incorporated
and Battelle, Pacific Northwest Laboratories for the Office of the Governor,
State of Alaska, Juneau, Alaska.
Ebasco Services Incorporated. 1982b. Chakachamna Hydroelectric Alternative for
the Railbelt Region of Alaska. Prepared by Ebasco Services Incorporated
and Battelle, Pacific Northwest Laboratories for the Office of the Governor,
State of Alaska, Juneau, Alaska.
Ebasco Services Incorporated. I982c. Coal-Fired Steam-Electric Power Plant
Alternatives for the Railbelt ReTion of Alaska. Prepared by Ebasco
Services Incorporated and Battel e, Pacific Northwest Laboratories for the
Office of the Governor, State of Alaska, Juneau, Alaska.
R.I
Ebasco Services Incorporated. 1982d. Coal Gasification Combined Cycle Power
Plant Alternative for the Railbelt Regions of Alaska. Prepared by Ebasco
Services Incorporated and Battelle, Pacific Northwest Laboratories for the
Office of the Governor, State of Alaska, Juneau, Alaska.
Ebasco Services Incorporated. 1982e. Natural Gas-Fired Combined Cycle Power
Plant Alternative for the Railbelt Region of Alaska. Prepared by Ebasco
Services Incorporated and Battelle, Pacific Northwest Laboratories for the
Office of the Governor, State of Alaska, Juneau, Alaska.
Ebasco Services Incorporated. 1982f. Wind Energy Alternative for the Railbelt
Region of Alaska. Prepared by Ebasco Services Incorporated for Battelle,
Pacific Northwest Laboratories, Richland, Washington.
Electric Power Research Institute (EPRI). 1979. Technical Assessment Guide.
PS-1201-SR, Electric Power Research Institute, Palo Alto, California.
Noyes Data Corporation. 1980. Small and Micro Hydroelectric Power Plants
Technology and Feasibility. Noyes Data Corporation, Park Ridge, New Jersey.
Phung, D. L. 1978. A Method of Estimating Escalation and Interest During
Construction. Institute for Energy Analysis, Oak Ridge Associated
Universities, Oak Ridge, Tennessee.
SRI International. 1979. Mission Analtsis for the Federal Fuels from Biomass
Program. Volume IV, Thermochemical onversion of Biomass to Fuels and
Chemicals. U.S. Department of Energy, Division of Distributed Solar
Technology, Washington, D.C.
U.S. Army Corps of Engineers. 1979. Feasibility Studies for Small Scale Hydro-
power Additions. The Hydrologic Engineering Center, Davis, California.
U.S. Army Corps of Engineers. 1981. Electrical Power for Valdez and the
Copper River Basin. Alaska District, Anchorage, Alaska.
R.2