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SUSITNA HYDROELECTRIC PROJECT �:199��"�s�A-- /
INTRODUCTION TO THE � � �`�
AMENDMENT TO THE LICENSE APPLICATION '�
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION �,C,
NOVEMBER 1985 � �
TABLE OF CONTENTS
Title
Page No.
i
I. THE HISTORY AND PRESENT STATUS OF Tf'�' SUSITNA PROJECT 1
II. THE DRAFT AMENDMENT 2
III. PROJECT DESCRIPTION 5
IV. ECONOMIC AND FINANCIAL ANALYSIS 7
,; Future Electric Generating Capacity Requirements 7
Electricity Demand Forecast 8
Retirement Schedules and Need for New Capacity 10
Cost Assumptions for the Primary Alternatives 11
'� Natural Gas -Fired Generation (Cook Inlet) 11.
Natural Gas -Fired Generation (North Slope) 15
i Coal— Fired Generation . `. 16
The Susitna Project 19
Economic Evaluation 20
ii
V . ENVIRONMENTAL ANALYSIS 24
Water Use and Quality 26
Flow . 26
Temperature 27
Sediment 28
Ice 28
Fish and Fish Habitat 30
Flow Related Impacts 30
Water Quality Impacts ... 32
Botanical and Wildlife Resources 33
Botanical . 33
Moose 34
Caribou 35
Bears . 35
Raptors . 35
Social Sciences 36
Socioeconomic Resources 36
Cultural Resources 37
Recreation Resources 38
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Alasl�a Resources
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ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
INTRODUCTION TO THE
AMENDMENT TO THE LICENSE APPLICATION
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NOVEMBER 1985
LIST OF EXHIBITS
Number Title
1 RESOURCE USE AREA
2 WATANA DAM GENERAL PLAN (STAGES I AND II)
3 DEVIL CANYON DAM GENERAL PLAN (STAGE II)
4 TOTAL EMPLOYMENT STATEWIDE
5 BASIC EMPLOYMENT
6 STATE AND LOCAL GOVERNMENT
7 SUPPORT EMPLOYMENT
8 STATE POPULATION
9 RAILBELT POPULATION
10 RAILBELT ELECTRIC ENERGY DEMAND
11 RAILBELT PEAK DEMAND
12 RAILBELT EXISTING EQUIPMENT RETIREMENT SCHEDULE
13 RAILBELT RETIREMENT SCHEDULE OF EXISTING -RESOURCES
AND FORECAST CAPACITY REQUIREMENTS
14 WORLD OIL PRICE FORECASTS
15 WORLD OIL PRICE
16 COOK INLET NATURAL GAS PRICE FORECAST
17 ASSUMPTIONS FOR COOK INLET NATURAL GAS AVAILABILITY
18 ESTIMATE OF UNDISCOVERED GAS RESOURCES IN PLACE FOR THE
COOK INLET BASIN
19 COAL PLANT COST ESTIMATES
20 COAL COSTS
21 HISTORICAL U.S. COAL PRICES
22 COAL PRICE FORECAST
23 COMPARATIVE FUEL PRICE FORECASTS
24 SUSITNA CAPITAL COSTS
25 FINANCING REQUIREMENTS SUSITNA HYDROELECTRIC PROJECT
26 BOND ISSUE SUMMARY SUSITNA HYDROELECTRIC PROJECT
27 THERMAL EXPANSION PLAN
28 THERMAL ALTERNATIVE PEAK DEMAND AND CAPACITY
29 SUSITNA EXPANSION PLAN
30 SUSITNA ALTERNATIVE PEAK DEMAND AND CAPACITY
31 COST OF ENERGY COMPARISON EXPRESSED IN 1985 DOLLARS
32 REAL COST OF ENERGY COMPARISON
33 COST OF ENERGY COMPARISON NOMINAL DOLLARS
34 COST OF ENERGY COMPARISON NOMINAL DOLLARS
35 POWER DEVELOPMENT FUND
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ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
INTRODUCTION TO THE
AMENDMENT TO THE LICENSE APPLICATION
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NOVEMBER 1985
LIST OF EXHIBITS (Cont'd)
Number Title
36 SUSITNA HYDROELECTRIC PROJECT ENERGY COSTS
37 ECONOMIC SENSITIVITY ANALYSIS
38 FINANCIAL SENSITIVITY ANALYSIS
39 SUSITNA RIVER FLOW
40 ENVIRONMENTAL FLOW REQUIREMENT CASE E-VI
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ALASRA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
INTRODUCTION TO THE
AMENDMENT TO THE LICENSE APPLICATION
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NOVEMBER 1985
This document provides an overview of the history and present status of the
i
Alaska Power Authority's application for a license to construct and operate
the Susitna Hydroelectric Project. In addition, the principal economic and
environmental issues relating to the licensing of the Project are addressed.
The reader should refer to the Draft Amendment for more detailed discussion
of these and other aspects of the Project, including engineering design,
construction and operation issues.
I. THE HISTORY AND PRESENT STATUS OF THE SUSITNA PROJECT
i
In February, 1983, the Alaska Power Authority (Power Authority) filed an
application with the Federal Energy Regulatory Commission (FERC) seeking a
license to construct and operate a two -dam hydroelectric project on the
Susitna River in south central Alaska. The Susitna Project is the
centerpiece of a long-term plan for meeting demand for electricity in the
"Railbelt" region of the State, relying primarily on hydroelectric
development, supplemented as necessary by additional thermal -fired
i
generation.
The Power Authority's decision to seek a license for the Susitna Project was
the product of over three decades of State and Federally -sponsored studies
of the potential for hydropower development in the Susitna River basin. In
1980, the Power Authority commissioned Acres American, Inc. (Acres) to
undertake a complete review and reassessment of the economic, engineering,
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environmental and financial feasibility of a number of potential Susitna
River development schemes. The Acres feasibility study, completed in 1982,
reaffirmed prior conclusions of the United States Army Corps of Engineers
(COE) that a two -dam project at the Watana and Devil Canyon sites represents
the preferred plan for the productive, economic and environmentally sound
development of the Susitna River's hydroelectric potential.
To further test the feasibility of the Susitna Project, the Governor,
pursuant to legislative direction, secured an independent, comparative
I
evaluation of the Susitna Project and various alternative means of meeting
future demand for electricity in the Railbelt. The resulting series of
reports prepared by Battelle Pacific Northwest Laboratories concluded that
the Susitna Project, over the long term, is the preferred means for
providing power to the Railbelt. Based on this consistent history of
analytic support for the Susitna Project, the Power Authority, acting on
express legislative authorization, filed its application with the FERC
seeking a license for the two -dam Project.
In May 1985, the Power Authority concluded that a number of substantial
benefits would derive from modification of the plan for construction of the
Project to provide for completion of construction in three stages, rather
than the two proposed in the February 1983 license application. While
"staging" will not alter the character of the fully completed Project, it
will reduce labor and material requirements for the initial Watana
development, thereby reducing the "upfront" costs of construction.
Moreover, staging will permit the development of generation capacity from
the Project to match more closely the Railbelt's load growth and need for
replacement of existing capacity.
The modification of the Project to incorporate the 3-stage development plan
requires the filing of a formal license application amendment (Amendment).
Co ensure that the views of State and Federal resource agencies and other
interested persons are meaningfully addressed in the Amendment, the Power
Authority is now circulating a draft Amendment for a 60-day comment period.
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2
After reviewing these comments, the Power Authority will revise the draft
Amendment as appropriate, and submit the formal Amendment to the FERC in
February or March 1986,
II. THE DRAFT AMENDMENT
Although the Amendment process has been undertaken primarily to reflect the
3-stage development plan, the Power Authority has substantially revised the
application in a number of other respects to reflect the wealth of
information that has evolved over the last 2-1/2 years. Both the economic
and environmental analyses have been re-examined and modified since the
initial filing in February 1983.
j The economic re-evaluation has again produced the conclusion that the
Susitna Project is, over the long term, the least expensive means for
meeting future Railbelt electricity requirements. The analysis presented in
the Amendment demonstrates that the "least cost" thermal alternative can be
expected to cost Railbelt ratepayers about 1.5 times as much as the "with
Susitna" alternative over the first 50 years of the project's life. In
terms of "present value", this would mean that, should Susitna not be built,
electricity costs associated with the construction and operation of the
"least cost" alternatives to Susitna would absorb an additional $2 billion
over this period, reducing disposable income and inhibiting economic
activity.
These conclusions are the product of a more conservative set of economic
assumptions than were set out in the February application. It is recognized
that analysis of the Project necessarily depends upon the ability to
forecast events into the next century. This means that any analysis of the
Project, whether favorable or unfavorable, is burdened with uncertainty. To
I
ensure that the Susitna Project is evaluated by reference to reasonable
forecasts, previous assumptions have been scrutinized and tested against the
mainstream of current opinion and in many instances have been revised. For
example, the present analysis presumes a lower rate of oil price increase
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than previously contemplated and does not assume any real price increase
after the year 2023, Similarly, the Power Authority has assumed that Cook
Inlet natural gas supplies will substantially exceed the levels of proven
reserves currently estimated by the Alaska Department of Natural Resources.
In addition, the forecasts of economic, population and electricity demand
I
growths have been reconsidered and reduced. Finally, a number of
"sensitivity analyses" have been undertaken to test the Project's viability
against a range of more conservative alternative assumptions.
On the basis of the revised economic analysis, the Power Authority remains
persuaded that the FERC license should be pursued. Since the filing of the
application, the data and analysis underlying the project have substantially
matured. This has occurred, in part, as a response to the FERC
environmental impact analyses and also as a result of extensive ongoing
consultations in Alaska with State and Federal resource agencies. Through
this process the Power Authority has identified appropriate studies and a
comprehensive list of environmental issues to be addressed in the FERC
proceeding and over the course of the Project's development. The Power
Authority's guiding policy objective has been, and continues to be, to
develop the hydropower potential of the Susitna River with no net loss of
beneficial habitat for fish and wildlife. Toward this end, the Power
Authority has developed plans for mitigation of possible adverse
environmental effects of project development. Recognizing the State's
commitment to prudent and environmentally sound use of its natural
resources, the mitigation measures outlined in the draft Amendment
contemplate an investment of over $300,000,000 over the life of the Project.
These include special design features in the project to accommodate water
quality concerns, habitat modification to facilitate fish migration and
spawning, as well as ongoing monitoring over the life of the Project to
ensure environmentally sound construction and operation.
The Power Authority has also used the ongoing consultation process to
re-examine its proposed flow regime against the rigors of the "no -net -loss"
standard. On the basis of comments and modeling studies suggested by
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4
resource agencies, the Power Authority has altered the originally proposed
flow regime to constrain the flow released from the Project within limits
designed to maintain river conditions necessary to support productive fish
habitat. In sum, the ongoing consultation process has significantly
improved the project and confirmed the Power Authority's earlier conclusion
that the Susitna Project is the environmentally preferred means for meeting
Railbelt power heeds.
The following sections provide a more detailed examination of the essential
aspects of the analysis contained in the Draft Amendment including:
o A brief Project Description
o Economic and Financial Analysis; and
o Environmental Analysis,
III. PROJECT DESCRIPTION
The Susitna Hydroelectric Project, as presented in the draft License
Amendment, is a two -dam hydroelectric development to be located on the
Susitna River some 116 air miles north-northeast of Anchorage and
approximately 144 air miles south of Fairbanks (See Exhibit 1).
The two dam sites are the Watana site, planned for a rockfill dam to be
located at river mile (RM) 184, and the Devil Canyon site, planned for a
concrete arch dam at RM 152, some 32 miles downstream from the Watana site.
The project development is proposed to be constructed in three stages as
described below.
Stage I of the development, planned for completion in 1999, would consist of
a 700 foot high rockfill dam at asite shown on Exhibit 2. This
structure, with a crest at el. 2,025 ft., would impound 4.3 million
acre-feet of water in a reservoir some 39 miles long with a surface area of
19,900 acres. Four turbine/generator units with a combined nominal capacity
of 440 Megawatts (MW) would generate an average annual energy of 2,400
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Gigawatt Hours (GWh). The dependable capacity of this installation would be
300 MW during the critical months of December and January when the
electrical demand of the Railbelt system is highest.
Stage II, to be completed in 2005, would be a 646 foot high double curvature
concrete arch dam at the Devil Canyon site shown on Exhibit 3. Devil Canyon
Dam, with a crest at el. 1,463 ft., would impound 1.1 million acre-feet of
water (0.35 million acre feet of live storage) in a 26-mile long reservoir
having a surface area of 7,800 acres. Four turbine/generator units at Devil
Canyon with a combined nominal capacity of 680 MW would generate an average
annual energy of 2,350 GWh; the December -January dependable capacity would
be 388 MW. The addition of the Devil Canyon facility will permit greater
flexibility in the operation of the Watana facility, thereby increasing its
dependable capacity to 417 MW.
Stage III of the project, to be completed in 2012, would consist of raising
the Watana Dam crest to el. 2,205 ft. (resulting in an 885 foot high dam)
shown on Exhibit 2. This raise would increase the storage to 9.5 million
acre-feet of water in a 48-mile long reservoir having a surface area of
38,000 acres. Two additional turbine/generator units would be installed and
this addition, in combination with the increase in turbine operating head
would raise the nominal capacity at Watana to 1,110 MW. The increased water
storage would raise the average annual energy of Watana to 3,500 GWh and
that of Devil Canyon to 3,400 GWh.
Completion of this final stage would bring the Susitna Hydroelectric Project
development to its final nominal capacity and energy levels of 1,790 MW and
6,900 GWh respectively. The 1,790 MW capacity is the average capacity under
average head of the two plants; during the critical months of December and
January, the project would have a dependable capacity of 1,620 MW.
Access for construction of all three stages would be via a 44-mi1e road
running south from about mile 23 of the Denali Highway (Milepost 112) to the
Watana site and, as Stage II begins, continuing for 39 miles west along the
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uplands north of the Susitna River to the Devil Canyon site. In addition, a
12-mile long extension of the railroad from Gold Creek (river mile 137 on
the Susitna River) east to Devil Canyon would be constructed to complete the
project access facilities.
Power from the two dams would be transmitted via power lines to a substation
to be built at Gold Creek, about 37 air miles east-southeast of the Watana
site. At that point the existing Anchorage -Fairbanks Intertie would carry
power to the two major Railbelt population centers with appropriate
upgrading of the system as the three stages come on-line.
IV. ECONOMIC AND FINANCIAL ANALYSIS
The following discussion provides an overview of the economic analysis that
has been performed by the Alaska Power Authority (Power Authority)
concerning the Susitna Hydroelectric Project. The starting point is the
forecast of new electric generating capacity that will be required in the
Railbelt over the course of the planning period. This is followed by review
of the primary alternatives identified in meeting those requirements. A
comparison of the costs of Susitna and those of the least cost alternatives
to Susitna is then presented, followed by consideration of State
contribution levels that would facilitate Susitna project financing.
Future Electric Generating Capacity Requirements
In order .to estimate the amount of new plant capacity that will have to be
provided in the future, two elements must be examined:
� 1. future electricity demand; and
29 the expected retirement schedule for existing plants. Even in the
absence of demand growth, new plant capacity will be required to
replace existing plants as they reach the end of their useful
lives.
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0
Electricity Demand Forecast. There are many factors that exert significant
influence on the forecast of electricity demand, including consumer income,
the price of electricity and competing forms of energy, industrial
development, commercial use and the number of residential households. Of
these, commercial demand and the number of households are the most
influential determinants of total demand in the Railbelt. The number of
households is related to the level of population, and both commercial use
and population are determined primarily by the level of employment.
Therefore, the employment forecast that underlies the Power Authority
electricity demand forecast is presented below. Statewide employment
figures are shown. Since about 70% of the state population lives in the
Railbelt, the statewide trends are closely indicative of Railbelt trends.
Exhibit 4 displays total employment from 1962 to 1984 and the Power
Authority forecast of employment from 1985 to 2010. Three categories are
shown: basic sector, support sector, and state and local government. Wages
and salaries in the basic sector are supported by payments from sources
outside the state, e.g., export revenues, tourist expenditures, federal
government outlays. The support sector is driven by the circulation of
funds in the local economy that were initially drawn through the basic
sector. State and local government has elements of both and is broken out
separately as a result. Of the three categories shown, the major
contributor to employment growth since statehood has been the support sector
followed by state and local government. Support sector growth has been
traceable primarily to a substantial increase in the ratio of support
employment to basic employment. The Power Authority forecast implies a
continued long -run increase in this ratio, though at a much reduced rate,
along with a moderate long -run decline in state and local government
employment. Basic sector employment in the aggregate is expected to
increase gradually.
Exhibit 5 displays the components of basic employment. Federal government
employment is expected to remain nearly constant during the planning period,
following years of gradual decline that occurred in the military segment.
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0
For the forecast of employment growth in mining and petroleum, it is assumed
that additional development of marginal North Slope fields such as Kuparuk,
Endicott, and Lisburne will take place, as well as additional exploration
and development of the Outer Continental Shelf. However, development of
heavy oil fields such as West Sak and construction of a North Slope natural
as pi gpeline are assumed not to occur prior to 2010.
Though the figures for hard rock mining are small in comparison with oil and
gas, it is also assumed that Beluga coal will be developed for export during
the 1990s, and that the Red Dog and Quartz Hill mining prospects will also
be developed.
In the Fisheries, Forest Products, and Agriculture category, the forecast
implies a very low rate of growth. The figures for Fisheries and Forest
Products dominate the category, and exhibit such low growth rates due
primarily to the assumption that biological resource constraints severely
limit any significant increase in the harvesting effort. It is assumed that
U.S. fishermen will successfully penetrate the bottomfish segment of the
industry. Finally, it is assumed that Tourism employment will continue to
grow at a fairly steady pace over the planning period.
State and local government employment is shown in Exhibit 6. It is assumed
that various revenue enhancement measures will allow current employment
levels to be maintained for several years. In addition, employment is
predicated on use of the Power Authority oil price forecast, which is higher
than the forecast developed by the Alaska Department of Revenue. However,
it is anticipated that declining North Slope oil production will eventually
force a reduction in employment. The Power Authority forecast anticipates
that state and local government employment in 2010 will be about the same as
it was in 1980.
The forecast for support sector employment is shown in Exhibit 7. As stated
earlier, it is anticipated that the ratio of support to basic employment
will continue to grow in the long run, though at a lower rate than
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experienced over the last 25 years. This is consistent with the assumption
that real per capita income will grow in the long run, and that real income
growth will generate a corresponding increase in domestic purchases of goods
and services. It is also consistent with national trends and expectations
for an economy that exhibits faster support sector growth than basic sector
growth.
The product of all these assumptions is a long run employment forecast that
is intended to provide a reasonable base case for planning. It is
recognized that there are plausible variations that would produce higher or
lower results.
The employment forecast leads to the statewide population forecast shown in
Exhibit 8. Regional allocation produces the forecast of Railbelt population
shown in Exhibit 9. As noted earlier, population (expressed as the number
of households) and employment are the most significant inputs to the load
forecasting model that produces the forecasts of electric energy demand and
peak demand shown in Exhibits 10 and 11. For comparison, the most recent
i
combined forecast of demand growth obtained from the Railbelt utilities is
also displayed.
Retirement Schedules and Need for New Capacity. Retirement schedules for
existing plants were obtained from the Railbelt utilities in summer 1985,
and are displayed in Exhibit 12. At present there are 1147 MW of generating
capacity installed in the Railbelt. It is expected that 510 MW of existing
plant capacity will be retired between now and 1999, and that approximately
1100 MW of existing capacity will be retired between now and 2010.
Given the Power Authority load forecast for the Railbelt combined with the
utilities' plans for retiring existing capacity, an estimate of requirements
for new plant capacity can be constructed.
Total required capacity for any year equals peak demand plus an allowance
for adequate reserves. Reserves are considered adequate if capacity is
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10
sufficient to preclude a loss of load in excess of one day in any 10-year
period. Exhibit 13 shows peak demand, estimated reserve requirements, and
existing resources net of retirements. The cumulative requirement for
capacity additions is the difference between "peak demand plus reserve" and
"existing resources net of retirements." Thus, the cumulative requirement
for capacity additions is approximately 650 MW by the year 2000, 1500 MW by
2010, and 1800 MW by 2020.
The question that remains for long-range planning is how best to meet the
requirements for new generating capacity. Prior studies have led to the
conclusion that the best alternatives to Susitna are natural gas -fired
generation and coal-fired generation. The expected costs of these
alternatives are therefore essential to the determination of an optimal,
long-range plan to meet the specified requirements.
Cost Assumptions for the Primary Alternatives
Natural Gas -Fired Generation: Cook Inlet. Electricity generation in the
southern portion of the Railbelt is presently based primarily on the
combustion of Cook Inlet natural gas. The single component that dominates
the total production cost for natural gas -fired generation is the price of
the fuel itself. Therefore, an important element of the analysis is the
price forecast for Cook Inlet natural gas.
The assumption that drives the Power Authority forecast of Cook Inlet
natural gas prices is that the price of natural gas and the price of oil are
tied together in the long run. That assumption is supported by two
considerations:
1. Natural gas and fuel oil are close substitutes for each other in
large-scale utility applications and industrial boilers.
I
Therefore, if the price of fuel oil goes up, natural gas should be
able to command a comparable price increase to the extent that
comparable markets are served.
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2. Three major contracts for the purchase of Cook Inlet gas presently
contain provisions that explicitly tie the price of natural gas to
the price of oil. In the Phillips contract for sale of Liquefied
Natural Gas (LNG) to Japan, the delivered price of the gas is
established as the British Thermal Unit (Btu) equivalent price of
crude oil delivered to Japan. In the 1982 Enstar contracts for
purchase of gas from Marathon and Shell, the price of gas is
adjusted annually based on changes in the posted price of fuel oil
at a local refinery.
Though relative prices of oil and natural gas may move independently in the
short run in response to particular market conditions, it is reasonable to
expect that relative prices of these two fuels will move in the same
direction at comparable long -run rates of change. Given this assumption,
the long run forecast of oil prices is a critical determinant of the long
run forecast of natural gas prices.
There is of course a wide spectrum of opinion regarding the long-term
outlook for world oil prices, as illustrated by the six price forecasts
displayed in Exhibit 14. In the past, the Power Authority has grounded its
analysis on a single forecast opinion of the future course of world oil
prices, namely that provided by Sherman H. Clark Associates (SHCA). The
Draft License Amendment puts forward two companion analyses: one based on
SHCA's 1985 forecast; the other based on a composite forecast of world oil
prices determined by averaging the six forecasts shown in Exhibit 14. In
devising this composite, the Power Authority's objective is to approximate
the mainstream of expert opinion for use as an alternative basis- for
analysis.
The analysis in this discussion will center on the "composite" forecast,
shown in Exhibit 15. Also shown in this Exhibit for comparison is the 1985
Sherman H. Clark forecast and the forecast from Wharton Econometrics. The
composite forecast is extrapolated from 2010 until 2023, the year in which
it reaches a level of $75/barrel ( in $1985) . It is capped at that level
based on the assumption that it will be possible to manufacture synthetic
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oil at approximately that price, and that therefore it will not be possible
to sell crude oil at a higher price.
Given an oil price forecast, the next step in the analysis is to define the
nature of the assumed price relationship between oil and natural gas. Two
methods have been examined for the present analysis: one based on netback
pricing of LNG delivered to Japan and the other based on extrapolation of
current Enstar contracts with Marathon and Shell.
The established practice of Japanese LNG buyers has been to pay a price that
is the Btu equivalent of the price of crude oil delivered in Japan. Given
an oil price forecast, it is therefore possible to construct a forecast of
the price of LNG delivered in Japan, assuming that the established pricing
mechanism is maintained. Further assuming that Cook Inlet gas producers
will, in the long run, have the opportunity to sell their gas as LNG to
Japan, it can be concluded that the gas will not be offered for sale on the
domestic market at a price that yields a lower wellhead value than could be
realized from export as LNG. The wellhead value that would be realized from
LNG export to Japan can therefore be used to construct an estimate of prices
the producers would require for sales in the domestic market in the long
run. The Power Authority forecast of Cook Inlet natural gas prices
delivered to the domestic market, based on the composite oil price forecast
and the netback methodology, is shown in Exhibit 16. While the price
forecast implies a substantial long -run rate of growth, it might also be
observed that the price estimated in the year 2000 is about $3.50/MMBtu (in
$1985), a price that is well within the range of prices commonly paid today
in the rest of the U.S.
The other method examined for defining the relationship between natural gas
and oil is the extrapolation of recent Enstar contracts that tie the price
of gas to the price of locally refined fuel oil. The result of that
extrapolation, again assuming the composite crude oil price forecast, is
also shown in Exhibit 16,
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The netback pricing methodology has been selected for the Power Authority
base case analysis, although a sensitivity test has been performed using the
Enstar contract extrapolation prices as well. The primary basis for that
selection is that the netback methodology rests on the established pricing
practice of the dominant LNG consumer on the Pacific Rim, and is built on a
base price that can be analytically understood and supported; i.e. a price
that is equivalent to the crude oil price on a Btu basis. The Enstar
contracts, on the other hand, represent the product of negotiations in a
much smaller market at a particular point in time, and are not built on a
base price that can be analytically derived. Future negotiations might well
result in particular contracts that are above or below the Enstar line.
Consequently, given a long run LNG export opportunity, the netback
methodology appears to provide a more reliable methodology for developing a
long run price forecast.
Given the Cook Inlet natural gas prices that are used in the base case in
concert with other base case assumptions discussed later in this overview,
Power Authority economic studies indicate that, on a life cycle cost basis,
coal-fired generation becomes the preferred choice over natural gas for new
plant capacity in the Railbelt by the year 2000, except for peaking
operation. Because of this shift to coal-fired generation, a Cook Inlet
natural gas supply limitation is not encountered in the present base case
analysis.
However, in sensitivity cases that assume lower gas prices (or higher
interest rates that penalize the coal alternative), natural gas -based
generation is selected on an economic basis for a longer period of time, and
in some instances it is selected indefinitely. The question raised by these
cases is whether the amount of natural gas in Cook Inlet is sufficient to
allow its continued use for electric generation over these longer time
spans.
The most recent estimates of Cook Inlet natural gas supplies from the Alaska
Department of Natural Resources are included in Exhibits 17 and 18. Proven
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reserves are estimated at 4.5 trillion cubic feet (TCF). The estimate of
the amount of undiscovered natural gas is presented in the form of a
probability distribution, ranging from an extreme low end of .5 TCF to an
extreme high end of 9 TCF. The mean estimate within this range is
approximately 3.5 TCF.
Current annual demand is approximately .2 TCF as shown in Exhibit 17.
Assuming continuation of the current pattern of use, with gradual growth in
retail sales and electric generation but no new commitments such as
additional LNG export, approximately 3.5 of the 4.5 TCF of proven reserves
will be consumed by the year 2000. What this means is that a long-range
plan that anticipates the use of Cook Inlet natural gas for base -load
operation well beyond the year 2000 depends on the future discovery of
substantially more gas. As the time frame for assumed reliance on Cook
Inlet natural gas is increased, the risk increases that the needed supplies
will not be discovered.
In view of the probability that a Cook Inlet natural gas supply constraint
will at some point be encountered, the primary assumption adopted by the
Power Authority is that base load plants fueled by Cook Inlet gas can be
installed until the year 2000. All such plants are assumed to burn Cook
Inlet gas for the duration of their useful lives, i.e. 25 years for
combustion turbines and 30 years for combined cycle plants. Only peaking
units (limited to 1,500 hours of operation per year) are assumed to be
installed after 2000. For sensitivity analysis, however, this supply
limitation is relaxed in some cases and eliminated in others.
Natural Gas -Fired Generation: North Slope. There are two ways in which
North Slope natural gas could be used as a primary fuel for Railbelt
electric power generation:
1. The gas could be burned in Railbelt power plants if made available
by pipeline, or
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2. The gas could be burned in power plants on the North Slope if tied
into the Railbelt via long distance transmission lines.
Previous studies have determined that a small diameter natural gas pipeline
from the North Slope to the Railbelt is not economically feasible. The
domestic market is too small to justify the expense. However, if a North
Slope natural gas pipeline such as the proposed Trans Alaska Gas System
(TAGS) were constructed in order to serve an export market, a portion of
I
that gas could become available in the Railbelt. In that event, the
appropriate method for estimating the price to Railbelt consumers would be a
netback calculation. In the case of the TAGS proposal for delivering gas
for export as LNG to Japan, the price of the gas in Anchorage would be equal
to the delivered price in Japan minus the costs of liquefaction,
transportation by tanker, and regasification. This would yield essentially
the same price estimate developed for Cook Inlet gas using a netback
methodology. As a result, the Power Authority assumption is that the
delivered price of North Slope natural gas would not be less than the price
forecast developed for Cook Inlet gas. To assume construction of a North
Slope natural gas pipeline would eliminate any assumed supply constraints
but would not reduce the estimated price of those supplies.
Previous studies have also indicated that the cost of installing a North
Slope generation and transmission system of sufficient reliability renders
that option uncompetitive, even if the gas is assumed to be available at a
zero wellhead price. Questions have been raised about the level of
confidence that can be placed in these cost estimates. However, based on
currently available information, the feasibility of the North Slope
generation alternative has not been demonstrated, and for that reason the
Power Authority has not accounted for this in its evaluation of alternative
means for meeting the Railbelt's future needs.
Coal -Fired Generation. The capital cost and operation and maintenance cost
(0&M) of coal plants are among the ILL influential factors that determine
the price of electric energy produced by coal-fired generation. These costs
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have been estimated at a feasibility level for hypothetical, site -specific
200 MW plants that would be, constructed either at Nenana or Beluga. The
sites are in close proximity to the two major sources of coal in the
Railbelt, either of which is sufficiently large to support all Railbelt
needs throughout the period of analysis and beyond.
The detailed derivation of these cost estimates is available in a technical
document recently published by the Power Authority. A rough comparison of
the Power Authority capital and 0&M costs with those estimated by sponsors
of the Matanuska Power Project and by Diamond Alaska is presented in Exhibit
19. Although there are undoubtedly a number of differences that distinguish
these plants, and although the Power Authority estimate is marginally higher
than the other two, the similarity of magnitude demonstrates that the Power
Authority cost assumptions are generally in line with estimates currently
produced for similar plants by private sector sponsors.
The other significant cost component is the price of coal itself. The Power
Authority has developed two distinct price forecasts: one for Nenana coal
delivered to a Nenana plant some distance away and one for Beluga coal to be
consumed at a minemouth plant. It is assumed that air quality
considerations stemming from proximity to Denali National Park would prevent
construction of a 200 MW coal plant directly adjacent to the Nenana coal
fields.
For Nenana coal, studies were performed to estimate the cost of production
that would be experienced for a mine extension dedicated to supplying a new
major coal-fired generating plant. As shown in Exhibit 20, a 1985 cost of
$1.45/MMBtu was estimated. This is within the range of current minemouth
prices in effect under existing contracts for Nenana coal, which vary from
$1.30/MMBtu for Golden Valley Electric Association to an estimated
$2.40/MMBtu for the U.S. Military. Adding an estimated transportation
charge to deliver the coal to the assumed plant site yields a delivered,
1985 cost of $1.84/MMBtu.
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A long -run real escalation factor of 1.5% per year is then applied to the
1985 price, an assumption that is consistent with historical trends and with
expectations for future costs and productivity. As shown in Exhibit 21, the
average U.S. coal price increased in real terms at an average rate of .8%
per year between 1900 and 1973, and by 1.2% per year between 1900 and 1980.
Principal causes of this trend included: (1) rising wages, (2) regulations
governing coal production, and (3) rising operating costs (including taxes).
coal costs rose despite increases in productivity associated with continuous
mining machines, large surface mines, and the introduction of other
technologies.
In addition, both Golden Valley Electric Association (GVEA) and the
Fairbanks Municipal Utilities System (FMUS) have experienced average real
escalation of coal prices in excess of 2% per year under existing contracts
during the last 10 years. GVEA has experienced an average real rate of
increase of 2.0% per year over the last 20 years.
The forecast that emerges from the Power Authority studies anticipates that
wages of mine employees will continue to climb in real terms over the long
run, but that productivity gains will level off due to a variety of
technological barriers. These expectations translate into the forecast of
rising real prices for Nenana coal displayed in Exhibit 22.
While Nenana coal is assumed to be available at its cost of production, the
forecast for Beluga coal is based on a different pricing theory. Assuming
Beluga coal is produced primarily for export in the Pacific Rim market, the
minemouth price for domestic sale is likely to equal the price that can be
obtained in the export market minus the costs of transportation from the
mine. The price forecast for Beluga coal is therefore driven by the assumed
market price of imported coal on the Pacific Rim, adjusted to yield a
minemouth value by use of a netback methodology.
It is anticipated that the Pacific Rim market for imported coal will grow at
a substantial rate throughout the period of analysis, and that increasingly
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costly mines will be brought into operation in order to satisfy the growing
demand. Assuming that the market price equals the cost of production from
the marginal source of coal, the real price of coal on the Pacific Rim
market is expected to grow. That is the primary phenomenon that drives the
Power Authority forecast of Beluga coal prices, shown in Exhibits 20 and
22. Although the pricing methodology is different for Beluga than for
Nenana, the average real rate of escalation estimated for Beluga coal prices
over the entire analysis period is again 1.5% per year.
It was assumed earlier that oil price escalation would be capped at
$75/barrel (in 1985 dollars). According to the composite oil price
forecast, this price level is reached in 2023. Since the price forecast for
natural gas is driven by the price of oil, it too is assumed to remain level
in real terms in the years beyond 2023. However, real price escalation for
coal escalation is assumed to occur throughout the analysis period (i.e.
until 2054). As shown in Exhibit 23, coal price escalation can be extended
well beyond 2023 without encountering the ceiling imposed by oil and gas
prices.
Finally, it should be noted that a sensitivity analysis has been performed
with the assumption that coal prices will remain constant in real terms
throughout the analysis period.
The Susitna Project. The costs of generation from Susitna are almost
entirely the result of the project's capital cost. The estimated
construction cost is $5.4 billion in 1985 dollars, and is displayed for each
of the three stages in Exhibit 24. Average annual energy generation is
estimated at 2400 GWh (millions of kilowatt-hours) from the first stage,
i
4750 GWh from both the first and the second stage, and 6900 GWh from the
completed project. Current annual electric energy demand served by Railbelt
utilities is approximately 3400 GWh.
The total estimated financing requirements for the project, including
interest during construction and other financing costs, are shown in Exhibit
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25, based on an average annual inflation rate of 5.5% and a nominal interest
rate on the bonds of 9%, Total estimated financing requirements (in nominal
dollars) are approximately $7.4 billion for stage one, $5.8 billion for
stage two, and 7.3 billion for stage three. An annual bond issue summary is
displayed in Exhibit 26.
Economic Evaluation
Based on the specified set of assumptions, two long-range plans are
developed for meeting the estimated electric generation requirements:
1. The "optimal" (i.e. lowest long -run cost) plan that can be devised
without Susitna; and
2. The "optimal" plan that can be devised that includes Susitna.
These plans are labeled the "thermal alternative" and the "Susitna
alternative". The annual costs (including fuel, 0&M, and capital cost) of
each plan are calculated during the optimization process. The capital costs
f or all new facilities, both Susitna and thermal plants, are equal to the
complete construction costs of each facility including an allowance for
interest during construction that is consistent with 100% debt financing.
The present value of each annual cost stream is then computed and compared.
The plan that entails the lower present value of future costs is deemed the
preferred alternative.
It is necessary to select a discount rate in order to calculate the present
value of future cost streams. The Power Authority policy is to set the real
discount rate equal to the real interest rate anticipated for market
financing. It is presently assumed that tax-exempt financing will be
available at a nominal 9% rate and that the inflation rate will average 5.5%
in the long run. This in concert with the historical record of real
interest rates supports the selection of a 3.5% real discount rate for the
Power Authority analysis.
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The least cost thermal alternative is characterized by the plant capacity
additions displayed in Exhibit 27. Note that a 90 MW hydroelectric project
at Bradley Lake is assumed to be on-line in 1990 in both the "thermal"
alternative and the Susitna alternative. Of particular interest is that the
thermal expansion plan with the lowest long -run cost, given all of the Power
Authority base case assumptions, provides for the installation of a 400 MW
i
coal plant in 1999 followed by additional 200 MW coal plants in 2005, 20073
2010, and 2025. (The gas -fired combustion turbines installed after the year
2000 are for peaking operation).
Coal-fired generation is highly capital intensive, and the impact of initial
debt service on consumer rates can be substantial. A sharp increase in
rates would be experienced by Railbelt consumers in 1999 if the plan
displayed in Exhibit 27 were implemented. In actual practice, it is likely
that Rallbelt utilities would explore alternatives that would be easier for
their consumers to face in the short run. However, such alternatives would
be more costly than the "optimal" thermal plan identified over the long run.
Exhibit 28 displays total installed capacity under the thermal alternative
in relation to the forecast of peak demand. Note that there is little
indication of 400 MW of coal capacity coming on-line in 1999. This is
because approximately 300 MW of existing capacity is scheduled for
retirement in the same year according to the Railbelt utility retirement
schedules presented in Exhibit 12.
The capacity additions that characterize the Susitna alternative are
displayed in Exhibit 29. The first stage of the Susitna Project (lower
height Watana) is brought u ht on-line in 1999 the second stage (Devil Canyon)
is on-line in 2005, and the third stage (raising Watana to full height) is
on-line in 2012. The December -January dependable capacity of stage one is
estimated at 300 MW, well below the full "installed capacity" of the project
at that time. Additional power can be generated at other times of the year
when the reservoir level is higher. In addition, Watana's range of
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21
operation is constrained within certain limits until Devil Canyon is built
downstream, at which time the flow through Watana, and therefore power
output can be varied to a much greater extent.
The 505 MW of additional capacity identified in 2005 in Exhibit 29
represents not only the December -January increment from the Devil Canyon
power plant but also the relaxation of constraints on the operation of
Watana. Exhibit 30 displays total dependable capacity in December -January
for the Susitna alternative in relation to the forecast of peak demand.
Note again that the addition of the first stage of the project in 1999 is
not discernible in this display due to the simultaneous retirement of
approximately 300 MW of existing capacity.
The annual production costs calculated for these two alternatives are
displayed in the first two columns of Exhibit 35 in nominal dollars for the
years 1985-2020. The two streams are identical through 1998 and begin to
diverge in 1999. For purposes of economic evaluation, the cost streams are
extended through 2054 assuming all cost factors are held constant beyond
2020 except for fuel costs as described earlier. The present value of each
cost stream from 1996-2054 was then computed with the following results:
Thermal Alternative
Susitna Alternative
Net Benefit
Benefit/Cost Ratio
Present Value of Costs For
Period 1996-2054 ($ Millions)
7,158
4,823
2,335
1.5
The "Benefit/Cost Ratio" is actually a "Cost/Cost Ratio", determined by
dividing the thermal alternative cost by the Susitna alternative cost. The
cost savings of proceeding with the Susitna alternative is defined as a net
benefit.
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he comparative cost of electric energy on a cents/KWh basis is presented in
Exhibits 31-343 in both 1985 dollars and nominal dollars for the years
1985-2020 (assuming 5.5% inflation and 9% nominal interest). As shown in
Exhibit 31, it is expected that average Railbelt production costs will
increase in real terms between 1985 and 1998, with a noticeable jump
occurring in 1994 due to the expiration of contracts that provide natural
gas from the Beluga field to Chugach Electric Association at very low
prices. The jump in 1999 under the thermal alternative represents the rate
increase that would be experienced if 400 MW of coal plant capacity were
brought on-line at that time. Average Railbelt production costs would be
higher yet under the Susitna alternative in 1999, assuming 100% debt
financing and level nominal debt service, and would remain higher until
2007.
The real cost of energy under the Susitna alternative declines in the long
run as a result of two factors.
1. The impact of continuing inflation on level nominal debt service,
resulting in declining real cost;
2. The impact of demand growth on the unit cost of energy, a factor
that is relevant for stages two and three due to their excess
energy potential in the initial years of operation.
The shaded area in Exhibits 31 and 33 represents the excess cost of energy
under the Susitna alternative relative to the defined thermal alternative
until the crossover point in 2007. The financing strategy that has been
under consideration for a number of years entails a State government
contribution sufficient to ensure that Railbelt ratepayers will at no time
pay more than they otherwise would under the thermal alternative. The
shaded area therefore represents the amount that must be paid out in order
to accomplish that purpose.
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The amount of that It from state government is calculated in Exhibit
35, and equals approximately $680 billion in nominal dollars. State funds
that are appropriated for this purpose are deposited in the Power
Development Fund. If the Power Authority were authorized to retain the
interest earnings of the Power Development Fund, it is estimated that State
appropriations of approximately $220 million would be adequate to generate
the necessary payout plus cover all pre -construction expenses between 1985
and 1990. It should be noted, however, that the Railbelt utilities might
i
have different forecasts of the thermal alternative costs for the early
years of project operation. To the extent that their forecasts are lower,
their estimate of the necessary "payout" from the Power Development Fund
would be correspondingly higher.
It should also be noted that the energy costs displayed in Exhibits 31-34
are blended costs, representing the average cost produced by all components
of the system. The expected cost of energy from the Susitna project itself
in both real and nominal terms is displayed in Exhibit 36.
Finally, the Power Authority has tested the validity of its base case
analysis by measuring the economic and financial implications of changing a
number of important variables. Exhibits 37 and 38 display these results.
V. ENVIRONMENTAL ANALYSIS
� The major environmental issues of importance for the Susitna Project
include.
o Project induced changes in the seasonal patterns of flow in the
river below the dams and the potential for resultant impacts on
fish habitat, particularly salmonid spawning and incubation
habitat.
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o Project induced changes in water quality and temperature below the
dams and the potential for resultant impacts to fish (primarily
salmonid) populations.
o Potential loss of terrestrial habitat, particularly winter browse
habitat for moose, and denning and foraging habitat for bear, due
to inundation of lands by the Reservoir.
o Potential loss of habitat and/or habitat degradation due to
construction of project facilities including the construction
camp, access road and borrow sites, particularly as it impacts
moose, and bear.
o Potential interference with caribou movements due to project
access road and Watana reservoir.
o Potential loss of bald and golden eagle nesting sites through
construction activities and/or inundation.
o Potential loss of cultural resources (historic and prehistoric
sites and artifacts) due to construction activities and/or
inundation.
o Potential socioeconomic impacts to local communities due to the
influx of project workers into these communities.
o Potential recreational impacts due to loss of the white water
resource of Devil Canyon through inundation.
Summarized below are the results of the technical investigations and
analyses which have been conducted for the purpose of resolving these
issues, along with brief descriptions of proposed mitigation programs.
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Water Use and Quality
Project effects on the seasonal pattern of flows in the Susitna River, as
well as on water temperature, ice formation and turbidity/suspended sediment
have been analyzed by a system of inter -linked computer simulation models
including reservoir operation, temperature and sediment models, and
downstream flow, temperature and ice models. Results of these models, along
with other baseline data collection and field observation studies have shown
that impacts to flow and water quality will be greatest in the middle
I
Susitna River (defined as the 50 mile reach of river between Devil Canyon
and the confluence of the Susitna River with the Talkeetna and the Chulitna
I
rivers, near the town of Talkeetna). From that point, the flow from the
basin above Devil Canyon constitutes only about 40 percent of the total flow
in the river, so that project impacts on flow, temperature and water quality
are largely masked and/or ameliorated by intervening flow from other sources
in the lower river. The proportional contribution of water from tributaries
of the Susitna River are depicted on Exhibit 39. Thus, lower Susitna River
impacts are generally considered to be less significant and very probably
not predictable given the natural range of variation in the complex lower
river ecosystem.
Flow. Average summer (May -September) flows in the middle Susitna River
(between Devil Canyon and Talkeetna) will be reduced as follows: for Stages
I and II from about 20,000 cfs to about 13,000 cfs; for early Stage III to
about 12,000 cfs; and for later Stage III to about 10,000 cfs. (All flows
given herein are as measured at the Gold Creek gaging station, 14 miles
downstream of Devil Canyon).
Average winter (October -April) flows for Stages I and II will be increased
from the natural flow of 2,200 cfs to about 7,400 cfs. Early Stage III
flows would increase to an average of around 8,000 cfs and later Stage III
flows to an average of about 9,500 cfs.
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In relation to natural conditions, flows would be more stable after project
development. The natural range of average monthly summer flows is from
13,500 cfs to 27,800 cfs. With Stage I this range would be from 6,000 cfs
to 18,000 cfs, for Stage II from 7,000 cfs to 20,000 cfs and for Stage III
from 9It cfs to 11,000 cfs.
Monthly average winter flows presently range from 1,200 cfs to 53800 cfs.
For Stage I this range would be from 4,000 cfs to 9,000 cfs, Stage II would
be from 6,000 cfs to 8,500 cfs, and Stage III would be from 8,000 cfs to
11,000 cfs.
i Additionally, flood peaks would be substantially reduced by the project.
The 50-year flood would be reduced from 98,000 cfs (natural) to about 46,000
cfs for Stages I and II and to about 43,000 cfs for Stage III. The mean
annual flood would be reduced from 44,000 cfs (natural) to 36,000 cfs for
Stages I and II and to 22,000 cfs for Stage III.
Temperature. The project reservoirs would cause river temperatures to lag
I
behind natural conditions, although annual average temperatures will remain
about the same. In Stage I, in the middle Susitna River, this lag would be
approximately 2 to 3 weeks. Temperatures in May and June would be slightly
less than natural and temperatures in September and October would be
slightly higher than natural. Winter temperatures would be the same as
natural (0°C) except in the 30-50 mile reach downstream of the Watana Dam
where temperatures would be up to 3°C above natural. In the lower river
temperatures would be much closer to natural than in the middle river,
generally differing by less than 1°C from natural temperatures.
In Stages II and III, with -project temperatures in the middle Susitna River
would lag behind natural temperatures by four to six weeks. Temperatures
would generally be less than natural in May through July, similar to natural
in August, and higher than natural in September through mid -November.
Winter temperatures would be similar to natural except in a 15 to 35 mile
reach of the river downstream of Devil Canyon Dam where the temperature
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would be up to 3°C higher than
increases in Stage III, the diffE
spring and summer temperatures
winter temperatures would increase.
natural. As project energy production
xences between with -project and natural
ouId decrease, and the differences in
In the lower river, temperature differences will be greater in Stage II than
in Stage I. Spring temperatures may be up to 2°C cooler than natural and
fall temperatures may be up to 2.5°C warmer than natural near Talkeetna.
Further downstream the differences would be less. During the summer and
winter, temperatures would be the same as natural. Stage III lower river
temperatures will at first be similar to Stage II but as energy production
increases, differences between natural and with -project summer temperatures
will decrease toward Stage I values.
Sediment. The simulations of reservoir suspended sediment behavior indicate
that between 80 and 90 percent of the sediment influent to the reservoir
would be trapped. This would include most of the larger sized particles,
which settle out more rapidly. Thus, after project development, material
with a size range of 0-3 microns would comprise the majority of sediment in
the middle river below the dams. The concentration of suspended sediment
would be reduced from summer natural levels which average 700 mg/1 to
approximately 100 mg/1 in Stage I, 80 mg/l in Stage II and 60 mg/1 in Stage
III. Average winter concentrations would increase from near 0 mg/1
naturally to approximately 70 mg/1 in Stage I, 60 mg/l in Stage II and 50
mg/1 in Stage III. Lower river suspended sediment concentrations would be
generally unaffected in the summer because of the large sediment inflow from
the Chulitna River. In the winter, lower river sediment concentrations
would also increase over natural values and the increase would be about
10 - 20 mg/1 less than in the middle river in all three stages, due to
dilution by the Chulitna and Talkeetna Rivers.
Ice. Under natural conditions the Susitna River first becomes ice -covered
near its mouth at Cook Inlet in late October or early November. The ice
cover then generally progresses upstream and reaches Talkeetna between
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mid -November and early December. The middle river becomes ice covered at
the confluence with the Chulitna River generally about the same time, and
the ice cover progresses upstream to Gold Creek by mid -December. The river
remains ice covered until late April to mid -May.
Under with -project conditions the lower river is expected to become ice
covered in generally the same manner as in natural conditions. However,
progression of the ice cover to Talkeetna is expected to be delayed by 2-4
weeks in Stage I, and 4-7 weeks in Stages II and III because of reduced
frazil ice production in the middle river. Progression of the ice front in
the middle river is expected to be delayed by comparable amounts.
i
Additionally, because of the warmer WC) reservoir releases, a section of
the middle river below the dams is not expected to become ice covered. In
Stage I, the ice cover is expected to reach near RM 140 and the area
upstream to Watana Dam would be open water. In Stage II, the ice cover is
expected reach near RM 135. In early Stage III the ice cover would extend
to near RM 125 and, as energy production increases, the ice cover would
extend only up to near RM 115.
The higher than natural winter releases would cause winter water levels to
be higher than natural within ice covered areas. In areas where an ice
cover existed under natural conditions but would not exist with -project, the
water level may be less than natural. The increase in water level in the
middle river is expected to be 2 to 6 feet in Stage I, 1 to 4 feet in Stage
j II and approximately 2 feet in Stage III.
These water level increases are of concern since they may cause overtopping
of natural berms at the upstream ends of peripheral habitat areas. This
could introduce cold mainstem water (near 0°C) into the slough or side
channel habitats (see discussion below) and could affect overwintering and
incubating salmonids. Therefore, the Applicant has proposed to protect the
important habitat areas by raising the berms above the expected maximum
winter water levels. The increase in winter water level in ice affected
areas may be beneficial by providing additional winter groundwater upwelling
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to the adjacent habitat areas. Upstream of the ice -affected area water
levels are expected to be lower than natural but similar to average summer
water levels. In all areas, upwelling, a major component of suitable
spawning and incubation habitat in these peripheral habitats, is expected to
be generally more stable all year than for natural conditions.
Fish and Fish Habitat
Twenty species of fish are known to inhabit the Susitna Basin. The most
important are five species of Pacific Salmon, rainbow trout, Dolly Varden
char, arctic grayling and burbot.
The majority of fish production in the system occurs in tributaries outside
the area of anticipated project affects. Devil Canyon acts as an effective
passage barrier to upstream mitigation so no salmon have been observed above
the Watana Dam site and only a few (less than 100) move past the Devil
Canyon damsite. Salmon production from the middle river, the reach expected
to experience the greatest project induced changes, is quite small compared
to total production from the Susitna system. Only approximately six percent
of the total Susitna salmon runs spawn in the middle river and less than one
percent spawn in the mainstem influenced, non -tributary habitats. Resident
fish populations in the middle river are relatively small and low density.
Based on the baseline fisheries studies over the past five years and
consultations with various fisheries agencies, it has been determined that
the most critical habitat and habitat use in the middle river vis a vis
project -induced flow, temperature and water quality impacts is largely
limited to chum (and sockeye) salmon spawning and incubation in side sloughs
and chinook (king) salmon rearing in side channels. Mitigation measures,
including flow constraints and design features have been proposed to
maximize the availability of these habitats.
Flow Related Impacts. Mainstem habitat is of little value to the salmonid
populations in the middle river.
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Upland sloughs and tributaries would be
30
essentially unaffected by the project. Thus, the species/habitat
combinations of chinook salmon rearing and chum salmon spawning and
incubation in side sloughs and side channels were chosen after consultation
for primary consideration in developing environmental flow requirements.
Secondary consideration was given to the other evaluation species for flow
allocations and all the species are treated in impact analyses and
mitigation planning.
A plan for regulating river flow (Flow Case E-VI) has been selected as the
preferred set of environmental flow constraints to mitigate flow related
fishery impacts. Briefly, this flow regime establishes seasonal minimum and
maximum flows for the project as depicted on Exhibit 40, as well as limits
on the rate of change in flow. As noted above, the primary focus of this
case is maintenance of rearing habitat for chinook salmon juveniles by
maintenance of high summer minimum flows. Project operation under Case E-VI
requirements would result in maintenance of or an increase in chinook
rearing habitat. The mean total available area for chinook rearing under
natural flows is approximately 6.1 million square feet. This is the
estimated area in all habitat categories that meet the derived suitability
criteria derived in consultation with interested agencies. Estimated
available habitat under Case E-VI flows, using the same suitability criteria
and all habitat categories, is approximately 6.0 million square feet. This
estimated slight decrease in rearing habitat would have no affect on chinook
juvenile survival and production. The area estimates include habitat
categories that rearing chinook do not use under natural conditions and may
not use under with -project conditions.
Chinook rearing habitat estimates in habitat types used extensively by
juvenile chinook under natural conditions show an increase in area available
under with -project flows. The mean total area available under natural
conditions is approximately 4.2 million square feet as compared to
approximately 4.3 - 4.6 million square feet under with -project conditions.
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Chum salmon spawning habitat and egg incubation success would be reduced by
Case E-VI flows without further mitigation. Since chum spawning in the
middle river is largely limited to a few side sloughs, however, this
potential loss can be easily rectified by structural habitat modifications
in appropriate side sloughs.
Evaluation of the distribution and timing of habitat utilization by the
other evaluation species produced no other expected negative impacts due to
altered flows. Most of the habitat use by other species is outside the area
that would be affected by changes in mainstem flow and use within the
affected area is similar to that of the primary evaluation species. Hence,
the mitigation measures to protect the habitat for the primary species would
also provide the secondary species sufficient protection.
Water Quality Impacts. Factors affecting habitat quality are less
predictable than habitat quantity. The major anticipated changes in
quality -related factors are increased flow stability and altered temperature
and suspended sediment regimes. Increased flow stability would have a
beneficial affect on habitat use by all the evaluation species.
With -project water temperatures are expected to be slightly cooler in the
early summer and warmer in the fall. Although the expected temperature
changes would alter timing of some annual cycles and behaviors, they are
well within documented ranges of tolerance for each species and are within
the range of temperatures that Susitna populations experience under natural
conditions. Thus, no significant impact is anticipated.
As dicussed above, project operation would reduce the total suspended
sediments in downstream habitats. Concentrations would be much less during
the summer and slightly greater during the winter. Most of the sediments
that would be transported downstream would be in the category of glacial
flour i.e. particles less than 3 microns in diameter. These small fines are
the major contributor to with -project turbidity. The annual pattern of
turbidity would follow the same trend as for suspended sediments. That is,
turbidity would be less in the summer and greater in the winter than natural
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conditions. The summer reduction in suspended sediment and turbidity would
improve habitat quality for juvenile chinook salmon and other species that
presently use turbid water habitats for rearing. The winter increase would
reduce mainstem habitat quality; however, winter sampling indicates limited
use of mainstem areas during the winter and most of the documented use is by
species known to be tolerant to turbidity, e.g., rainbow trout and burbot.
The effect that increased turbidity would have on observed periphyton blooms
during the spring and fall and, in turn, how that affect would influence
fish production from the system is not quantitatively predictable. However,
a decrease in the short spring and fall blooms would be offset, at least
partially, by lower rates of productivity over the entire summer season
given reduced summer turbidity levels.
The proposed monitoring plan includes components to measure these habitat
quality parameters and would detect unanticipated changes during project
operation. Monitoring would also detect any loss of fish production
occuring in the event proposed mitigation measures are not as effective as
expected.
In summary, the proposed mitigation plan would avoid, minimize or rectify
the anticipated impacts on aquatic habitats and species that would be caused
by operation of the project. The result would be maintenance of existing
levels of productivity from naturally reproducing populations. The proposed
monitoring plan would measure this productivity to show if refinement or
alteration of mitigation is needed.
Botanical and Wildlife Resources
I
Botanical. Stage I would result in the permanent removal through
g P � g
construction or inundation, of 15,762 acres of vegetation, 84 percent of
which would consist of forest (mostly spruce and spruce -birch) and almost 16
i
percent of which would consist mainly of dwarf tree scrub and low shrub
vegetation.
12665 33
851108
Stage II (Devil Canyon) would result in 6,020 acres of vegetation
permanently lost through inundation and construction. Almost all of this,
some 94 percent, is forest (spruce, spruce -birch, and spruce -poplar).
Construction of Stage III would result in the permanent loss of 163370 acres
of vegetation. Some 82 percent of this would consist of spruce and spruce -
birch forests and white spruce woodland. The remainder would consist mostly
of dwarf tree scrub and low shrub.
Much of the area to be affected by the project is classified as wetlands, as
in the case for most of Alaska. The areas of palustrine or lacustrine
wetlands permanently lost due to construction or inundation are 3,430 acres
for Stage I, 950 acres for Stage II, and 4,090 acres for Stage III.
However, only about 18 percent of these areas consist of emergent, pond, or
Lake wetland types which are considered to be of relatively high value for
waterfowl and other wildlife. The remainder consists of forested and
scrub -shrub wetlands which are usually of equal or lower value to wildlife
than are adjacent uplands.
Mitigation plans for botanical resources were developed primarily to
minimize vegetation losses and support the wildlife mitigation program.
Specific measures include the minimization and consolidation of project
facilities and the siting of these facilities in areas with low habitat
values and the prompt rehabilitation of disturbed areas when no longer
j needed for project construction.
Moose. From 2,000 to 3,000 moose inhabit the 1,400 square mile area which
includes and surrounds the project area. This represents about 10 percent
of the Alaska Game Management Unit 13 moose population and approximately 1-2
percent of the population in the State of Alaska. Winter habitat is the
critical habitat for these animals. The 38,152 acres of vegetation lost for
Stages I, II and III, would result in loss of winter habitat for some 300
moose (about 0.1 percent of the moose population of Alaska). This loss
would be mitigated by habitat enhancement on mitigation lands in both the
12665 34
851108
lower and middle Susitna Basin. Burning and clearing would increase browse
production and resultant carrying capacity sufficiently to over compensate
for moose habitat losses and would also provide out -of -kind mitigation for
other species.
Caribou. The Susitna Project lies within the northwestern portion of the
i
range of the Nelchina caribou herd, which currently numbers about 24,000
animals or about five percent of the statewide caribou population. Given
the low historic use of the impoundment zone, the habitat loss associated
with inundation is not expected to detectably reduce carrying capacity for
the Nelchina herd. The access road could locally affect caribou movements
and range use and public use of the road for hunting could result in a
redistribution of hunting pressure resulting in greater pressure on the
i
local subherd and less pressure elsewhere. However, significant impacts to
Nelchina herd numbers are not expected from these factors. The Watana
impoundment could alter caribou movements and may result in an increase in
the number of crossing -related mortalities over natural conditions; however,
significant population changes or reductions in carrying capacity due to
crossing mortalities or blockage of movements are not expected. A variety
of mitigation measures, including a worker transportation plan to reduce
traffic on the access road, have been incorporated into project plans to
minimize these impacts.
Bears. Brown bears will lose spring foraging habitat and black bears will
lose denning and foraging habitat, due to inundation. Increased human use
of the area will likely result in increased bear mortality, particularly for
brown bears. Mitigation measures have been incorporated into project design
and operation plans to minimize these impacts and both in -kind and
out -of -kind compensation through habitat preservation and through enhanced
moose production would mitigate residual impacts.
Raptors. Twenty-three golden eagles and ten bald eagle nesting locations
have been identified in or near the project area. Seven golden eagle and
three bald eagle nest locations would be inundated or significantly
12665 35
851108
disturbed and two golden eagle nest locations will be partially innundated.
A mitigation program which includes placement of artificial nests and the
enhancement of nesting sites is expected to fully mitigate for these
impacts.
Social Sciences
Socioeconomic Resources. The major socioeconomic impact identified for the
Susitna Project is project induced population influx into local impact area
communities and the effect of this influx on these communities' ability to
provide services' to their residents. In general, the analysis of impacts
show that only two communities, Talkeetna and Cantwell, are forecast to
receive a population increase of 10 percent or greater over levels expected
without the project (baseline). Project -related population increases in
Talkeetna are forecast to be 15 percent (71 people) above baseline in 1997
(peak employment for Watana Stage I) and 15 percent (87 people) in 2003
(Devil Canyon Stage II peak) and 5 percent (36 people) above baseline in
2009 (Watana-Stage III peak). This level of population impact would have
minor impacts on the primary school in Talkeetna and would reduce housing
vacancy rates in Talkeetna to almost zero in 2003.
Impacts in Cantwell would be greater, with population increases over
baseline of 166 percent (375 people) in 1992 (railhead construction peak),
47 percent (118 people) in 1997, 5 percent (113 people) in 2003, and 22
percent (69 people) in 2009. The community services in Cantwell most
affected by these population increases would be housing and the primary
school. Housing shortages would be mitigated during the railhead
construction by the provision of single -status housing. The impact on the
primary school would also be mitigated during years of impacts.
Other communities receiving moderate population impacts (from 5 to 10
percent over baseline) would be Trapper Creek (8 percent or 39 people at
peak in 2009) and Nenana (6 percent or 94 people percent at peak in 2009).
These levels of impact, when compared to changes in baseline, would have
12665 36
851108
little effect on the timing or magnitude of the communities' need to expand
their facilities or services.
Socioeconomic impact levels have been minimized by the Applicant's policies
to provide onsite worker housing at the project construction sites,
single -status worker housing at the railhead construction site, and a worker
transportation program for Watana-Stage I. These policies will help avoid
large population influxes into nearby small communities by decreasing
advantages that workers might perceive would come from living near the
construction sites.
Cultural Resources. Issues relating to the project involve the extent to
which construction and operation would adversely affect historic,
archeological, or architectural sites, properties and objects, and the
degree to which proposed measures would mitigate those adverse effects.
Cultural resources sites in the project area would be affected by ground
disturbance associated with construction activities, by inundation (sites
within permanent reservoir pools) and erosion (sites within drawndown areas
and at impoundment margins). In addition, as yet unidentified sites
(believed to be qualitatively similar in nature to those identified to date)
may be affected by construction of the project's linear features and the
creation of recreation areas and wildlife mitigation lands. However,
I
proposed mitigation measures should negate the majority of adverse project
effects to cultural resources.
To date, studies carried out in connection with the Susitna Project have
identified a total of 297 historic and prehistoric archeological sites. An
additional 22 sites, within or near the project area have been previously
recorded in the files of the State of Alaska Office of History and
Archeology.
No sites are located at the designated construction camps and villages,
permanent village, airstrips, intake structures, dams, spillways,
switchyards, powerhouses or cofferdams for any stages of the project.
12665 37
851108
However, six sites are located within 500 feet of these features and are
likely to be adversely affected.
i
i
A variety of mitigation measures would be implemented to address both known
and undiscoved sites. The most important of these would be data recovery at
archeological sites when avoidance of those sites is not feasible. The vast
majority of identified and anticipated cultural resource sites in the
project impact area are small-scale archeological sites important solely for
the scientific data they contain. For this reason, excavation and analysis
of a carefully selected representative sample of these sites would be
undertaken. Controlled burial, construction of protective barriers, and
restriction of access would also be employed when appropriate. A monitoring
program would be implemented to ensure that increased access to the project
vicinity does not result in any vandalism of cultural resource sites. A
public interpretation and education program designed to make available to
the public the results of cultural resources studies and to allow controlled
access to selected sites in the Project area would be implemented.
Finally, a procedure would be established to insure that any as yet
unidentified sites in portions of the project area where direct ground
disturbance limits cannot be identified on the basis of existing engineering
data would not be ignored. This would involve pre -construction field
surveys of these areas designed and executed in consultation with the State
Historic Preservation Officer,
Recreation Resources. To date, the project area has not been developed as a
recreational resource. Total recreational use in the 3,600 square -mile
encompassed in and surrounding the project area is currently estimated at
less that 7,000 user days. Predominant recreational activities in the
project area are fly -in hunting and fishing. The only public recreational
facilities that exist near the project area are roadside facilities on the
Denali Highway. In addition, three private lodges in the vicinity of the
project area are used primarily to support hunting and fishing trips. The
present level of use in the project area is very low because of the lack of
12665
851108
developed road access into the area. Current access is mostly by plane.
All -terrain vehicles are used in the areas near the Denali Highway. A small
number of boaters put in at the Denali Highway bridge and travel downstream.
Almost all boating stops above Vee Canyon rapids, however.
Construction of the proposed project would result in loss of the white -water
boating associated with Devil Canyon rapids. These rapids are dangerous and
only infrequently attempted by the most experienced of whitewater experts.
Yet, whitewater enthusiasts regard the loss of this resource to be a
significant impact of project development.
A recreation plan has been developed to accommodate increased public use of
project lands and waters, and to compensate for project -related impacts to
existing recreation resources and activities. In general, the plan provides
f or developed recreational activities near the damsites and adjacent to the
access roads; beyond these areas, trails and backcountry cabins are the
principle recreation facilities proposed.
12665 39
851108
SUSITNA HYDROELECTRIC PROJECT
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EXHIBIT 17
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COAL PRICE FORECAST
(1985 DOLLARS)
NENANA BELUGA
YEAR (DELIVERED) (MINEMOUTH)
($/MMBTU) ($/MMBTU)
1985 1®84
1990 1099
1995 2.14
2000 2.31 1 m78
2010 2.69 2,19
2020 3.13 2.57
2030 3o64 3.08
2040 4.24 3.22
2050 4e94 3e74
EXHIBIT 22
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FINANCING REQUIREMENTS
SUSITNA HYDROELECTRIC PROJECT
(MILLIONS OF DOLLARS)
DEVIL
WATANA I CANYON WATANA II TOTAL
January 1985 Costs ............... 2,561 (1) 1,394 1,321 5,276
Inflation (2).................... 11866 11935 35542 71343
Subtotal ....................... 42427 3,329 49863 12,619
Debt Service Reserve Fund........ 698 546 686 1,930
Working Capital Fund ............. 180 180 160 520
Discount and Financing Expenses.. 222 174 219 615
Interest During Construction (3). 2,525 21240 1,988 61753
Subtotal .............. ....... 8,052 6,469 71916 229437
Less Interest Earnings (4)....... (648) (669) (616) (1)933)
Total Bond Issue ................. 71404 53800 71300 203504
1—/ Includes licensing and other development costs for both Watana and Devil Canyon.
Does not include costs incurred prior to Fiscal Year 1986.
2_/ Based on an assumed average annual inflation rate of 5.5 percent.
3J Interest costs based on an assumed 9.0 percent interest rate.
4_/ Assumes a reinvestment rate of 10.0 percent.
401271 EXHIBIT 25
851107
BOND ISSUE SUMMARY
SUSITNA HYDROELECTRIC PROJECT
(MILLIONS OF DOLLARS)
WATANA I DEVIL CANYON II WATANA III TOTAL
NOMINAL 1985 NOMINAL 1985 NOMINAL 1985 NOMINAL 1985
YEAR DOLLARS DOLLARSV DOLLARS DOLLARSV DOLLARS DOLLARS1/ DOLLARS DOLLARS
19912/ 1,000 725 --- --- --- --- 19000 725
1992 1,000 687 --- --- --- --- 1,000 687
1993 --- --- --- --- ---
1994 11000 618 --- --- --- --- 19000 618
1995 1,200 703(3) 500 293 --- --- 12700 996
1996 19104 613(3) 500 277 --- --- 11604 890
1997 11500 789 --- --- --® --- 1,500 789
1998 800, 299 500 249 --- --- 1,100 548
1999 --- --- --- --- ---
2000 --- --- 1,000 448 --- --- 19000 448
2001 --- --- 1,000 425 --- --- 19000 425
2002 --- --- 19000 402 --- --- 19000 402
2003 --- --- 12300 496 --- --- 1,300 496
2004 --- --- --- --- --- --- ---
2005 --- --- --- --- --- --- ---
2006 --- --- --- --- 19000 325 11000 325
2007 --- --- --- --- 11000 308 11000 308
2008 --- --- --- --- 11500 438 11500 438
2009 --- --- --- --- 13500 415 19500 415
2010 --- --- --- --- 19500 393 1,500 393
2011 --- --- --- --- 500 124- 500 124
2012 --- --- --- --- 300 71 300 71
7,404 4,434 5,800 2,590 7,300 2,074
Average Annual Issue (1991-2012)
20,504
932
1—� Based on an assumed average annual inflation rate of 5.5 percent.
2—/ Expenditures incurred prior to 1991 are assumed to be funded through
continuing State appropriations.
3J Includes issues of $200,000,000 and $104,000,000 for 1995 and 1996,
respectively for 345 kV transmission upgrade.
9,098
3
41
401271 EXHIBIT 26
851107
YEAR
HYDRO-
ELECTRIC
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
20 24
2025
THERMAL EXPANSION PLAN
CAPACITY ADDITIONS
(MW)
COAL
FIRED
STEAM
TURBINE
400
200
200
200
GAS FIRED
COMBUSTION
TURBINE
GAS FIRED
COMBINED
CYCLE
OIL
FIRED
INTERNAL
COMBUSTION
45 2.5
2.5
E:37
174
87
174
2.5
90 1200 828 0 7.5
Note: Gas -fired turbines.installed after 1999 are for peaking operation.
401271
851107
EXHIBIT 27
YEAR
SUSITNA EXPANSION PLAN
CAPACITY ADDITIONS
(Mw)
HYDRO- COAL
GAS
GAS
OIL
ELECTRIC FIRED
FIRED
FIRED
FIRED
STEAM
COMBUSTION
COMBINED
INTERNAL
TURBINE
TURBINE
CYCLE
COMBUSTION
1985 45 2.5
1986 2.5
1987
1988
1989
1990 90 2.5
1991
1992 87
1993
1994
1995
1996
1997
1998
1999 3001/
2000
2001
2002 87
2003
2004 87
2005 5051/
2006
2007
2008
2009
2010 87
2011
2012 7261/
2013
2014
2015
2016
2017 87
2018
2019 87
2020
2021
2022
2023 87
20 24
2025
1,621 0 654 0 7.5
Note: Gas -fired turbines installed after 1999 are for peaking operation.
1—/ December/January Dependable Capacity
401271
851107
EXHIBIT 29
MW
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REAL COST OF ENERGY COMPARISON
(1985 DOLLARS)
THERMAL ALTERNATIVE SUSITNA ALTERNATIVE
YEAR /KWH /KWH
1985 3.4 3.4
1986 3.2 3.2
1987 3.2 3.2
1988 3.3 3.3
1989 3.4 3.4
1990 3.4 3.4
1991 3.3 3.3
1992 3.2 3.2
1993 392 3.2
1994 4.2 4.2
1995 4.4 4.4
1996 4.4 4.4
1997 4.4 4.4
1998 4.5 4.5
1999 8.1 9.1
2000 8.1 9.4
2001 7.9 8.8
2002 7.7 8.6
2003 7.7 8.4
2004 7.6 8a2
2005 8.5 9.1
2006 8.3 8.7
2007 9.4 8.5
2008 9.0 8.2
2009 8.8 7.3
2010 9.4 7.1
2011 9.1 6.9
2012 8.8 8.0
2013 8.5 7.7
2014 8.3 7.2
2015 8.0 6.7
2016 7.8 6.3
2017 7.8 5.9
2018 7.7 5.6
2019 7.3 5.2
2020 7.4 4.9
NOTE - COST IS PRODUCTION COST, AND EXCLUDES DISTRIBUTION AND
ADMINISTRATION COSTS.
401271 EXHIBIT 32
851105
Z
O
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OJ
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COST OF ENERGY COMPARISON
(NOMINAL DOLLARS)
THERMAL ALTERNATIVE SUSITNA ALTERNATIVE
YEAR /KWH /KWH
1985 3.4 3.4
1986 3.4 3.4
1987 3.6 3.6
1988 3.9 3.9
1989 4.2 4.2
1990 4.4 4 <4
1991 4.5 4.5
1992 4.7 4.7
1993 4.9 4®9
1994 6.8 6.8
1995 7.6 7.6
1996 7<9 7.9
1997 8.4 8.4
1998 9.0 9.0
1999 17.2 19.3
2000 18.1 20.3
2001 18.7 20.7
2002 19.2 21.4
2003 2002 21.9
2004 20.9 22.6
2005 24.9 26.6
2006 25.4 26.7
2007 30.4 27.6
2008 31.0 28.2
2009 31.9 26.5
2010 36.0 27.2
2011 36.7 27.7
2012 37 .4 34.0
2013 38.1 34.4
2014 39.0 33.9
2015 40.0 33.4
2016 41.2 32.9
2017 43.3 32.6
2018 44.9 32.9
2019 44.9 32.1
2020 48.5 31 .6
NOTE - COST IS PRODUCTION COST, AND EXCLUDES DISTRIBUTION AND
ADMINISTRATION COSTS.
401271 EXHIBIT 34
851107
POWER DEVELOPMENT FUND
(NOMINAL DOLLARS)
CONTRIBUTIONS TO
ANNUAL COST POWER DEVELOPMENT FUND
POWER POWER
THERMAL STATE BOND DEVELOPMENT DEVELOPMENT
ALTERNATIVE SUSITNA APPROPRIATION PROCEEDS FUND PAYOUT FUND BALANCES/
Year ($Mil) ($Mil) ($Mil) ($Mil) ($Mil) ($Mil)
1985 121 121 100 16.8 83.2
1986 124 124 118.7 28.0 181.9
1987 131 131 32.6 165.9
1988 145 145 39.3 141.3
1989 159 159 85.5 86.8
1990 167 167 91.0 0
1991 176 176 239.6 251.3
1992 187 187 276.4
1993 200 200 304.1
1994 286 286 334.5
1995 321 321 367.9
1996 336 336 404.7
1997 361 361 445.2
1998 390 390 489.7
1999 755 846 91 443.3
2000 802 900 98 384.8
2001 834 926 92 326.8
2002 868 969 101 253.5
2003 923 11001 78 197.1
2004 962 13043 81 131.8
2005 1,159 13239 81 60.1
2006 13212 11275 63 0
2007 11489 11353
2008 11555 13415
2009 11642 13364
2010 13899 19431
2011 13967 11487
2012 23042 1,857
2013 21117 11911
2014 21205 11914
2015 21302 1,919
2016 21409 13925
2017 21577 11941
2018 23722 1,996
2019 23769 19978
2020 31044 13985
218.7
239.E 6852/
1� At end of year. Assumes interest retention at 10 percent.
�-� Excludes costs incurred prior to 1991.
EXHIBIT 35
SUSITNA HYDROELECTRIC PROJECT ENERGY COSTS
ENERGY COST1/
(Nominal) (1985 Dollars)
YEAR /KWH /KWH
1999 28.3 13.4
2000 29.8 13.4
2001 29.7 12.6
2002 29.6 11.9
2003 29.5 11.2
2004 29.4 10.6
2005 27.6 9.5
2006 28.1 9.1
2007 28.0 8.6
2008 27.8 8.1
2009 26.9 7.4
2010 26.2 6.9
2011 25.7 6.4
2012 35.5 8.4
2013 35.9 8.0
2014 35.3 7.5
2015 34.7 7.0
2016 34.1 6.5
2017 33.4 6.0
2018 32.8 5.6
2019 32.2 5.2
2020 31.7 4.9
1/ Includes all associated
Energy cost is delivered
Inflation is assumed at
transmission line costs.
cost to Railbelt utilities.
5.5 percent.
401271
851107
EXHIBIT 36
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SUSITNA RIVER FLOW
WATANA SITE
TRIBUTARIES 1 % 16% 3% TRIBUTARIES
RIVER Ste\ IVI z 4
CHULITNA 19
YENTNA40%
RIVER _
DEVIL CANYON (FISH BARRIER)
GOLD CREEK
PARKS
HIGHWAY
ABRIDGE
COOK IfdLET
10% TALKEETNA
RIVER
11% TRIBUTARIES
SUSITNA STATION
Percentages indicate streams' contribution to total
Susitna River flow from Watana Dam Site to Cook Iniet.
EXHIBIT 39