HomeMy WebLinkAboutAPA138-------------------
----------------··----
SUS~Tt~A HYDf}t)ELECTR!C ?ROJECT
i
I
I I I I
I I I I
I
HARZA-EBASCO
Susitna Joint Venture
1.. Document Number
Please Return To
DOCUn1ENT crw --
· Preparf!O ;:y:
I !ail I ~
TASK 1"1: REFERENCE REPORT
ECONOMIC. MARKETI~JG AND
F~NANCIAL EVALUATION
------;
i !
I I
I
l
i
I
' I
I I
I
'
L ~---= ALASKI\ POVVER ·~l:THOR ITY ~~~--~_j
Tk
IC-(.:<S
,3B
~ ~-----------------=============================~1:~!g
CX)
co
l!)
co
l!)
M
0
0
0
l!)
l!) ,......
M
M
Prepared by:
[iii]
SUSITNA HYDROELECTRIC PROJECT
TASK 11: REFERENCE REPORT
ECONOMIC, MARKETING AND
FINANCIAL EVALUATION
ARLIS
Alaska Resources
Library & InfonnatJOn Servwes
Anchorage. ALaska
'---ALASKA POWER AUTHORITY __ __,
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
ECONOMIC,MARKETING AND FINANCIAL EVALUATION
TABLE OF CONTENTS
~)
I
j
1
!J
11
l-'
LIST OF TABLES
LIST OF FIGURES
LIST OF REFERENCES
18 -ECONOMIC AND FINANCIAL EVALUATION -------------------------
18.1 -Economic Evaluation -------------------------------------
18.2 -Probability Assessment and Risk Analysis ----------------
18.3 -Marketing -----------------------------------------------
18.4 -Financial Evaluation ------------------------------------
18.5 -Financial Risk
Page
18-1
18-1
18-23
18-50 .
18-62
18-78
ARLIS
Alaska Resources
Library &Informanon Services
AnchQr<.lge,Alaska
[1
I I LIST OF TABLES
11Ij
u
U
J
I
Number
18.1.1
18.1.2
18.1.3
18.1.4
18.1.5
18.1.6
18.1. 7
18.1.8
18.1.9
18.1.10
18.1.11
18.1.12
18.1.13
18.1.14
18.1.15
18.1.16
18.1.17
18.1.18
18.1.19
Titl e
Real (Inflation-Adjusted)Annual Growth
in World Oil Prices
Study Assumptions:Oil Prices
Japanese Import Prices (C.I.F.)of Alaskan LNG
Gas Price Escalation and Associated Conditional
Probabili ti es
Opportunity Value of Natural Gas at Cook Inlet,Alaska
1982-2040
Volume Weighted Cook Inlet Natural Gas Price to AMLP
and CEA
Coal Price Escalation and Associated Conditional
Probabili ti es
Steam Coal Imports by Japan,September and
October 1981
Current International Spot Prices of Steam Coal
Export Opportunity Value of Alaskan Coal -Sensitivity Case
Summary of Coal Opportunity Values
Summary of Fuel Prices used in the OGP Probability Tree
Analysis
Economic Analysis Susitna Project -Base Plan
Summary of Load Forecasts used for Sensitivity Analysis.
Load Forecast Sensitivity Analysis
Discount Rate Sensitivity Analysis
Capital Cost Sensitivity Analysis
Sensitivity Analysis -Updated Base Period Coal Prices
Sensitivity Analysis -Real Cost Escal ation
List of Tables - 2
Number
18.1.20
18.1.21
18.1.22
18.2.1
18.2.2
18.2.3
18.2.4
18.2.5
18.2.6
18.2.7
18.2.8
18.2.9
18.2.10
18.3.1
18.3.2
18.3.3
18.4.1
18.4.2
18.4.3
18.4.4
18.4.5
18.4.6
Title
Sensitivity Analysis -Non-Susitna Plan with Chakachamna
Sensitivity Analysis -Susitna Project Delay
Summary of Sensitivity Analysis - Indexes of Net Economic Benefits
Probability Assessment -Load Forecasts
Probability Assessment -Alternatives Capital Cost Analysis
Probability Assessment -Fuel Cost and Escalation Analysis
Probability Assessment -Susitna Capital Cost Analysis
Long-term Costs and Probability -Non-Susitna Tree
Long-term Costs and Probability -Susitna Tree
Net -Benefit Calculated Values
Case 1 -Positive Correlation Between Energy Demand and Prices
Case 2 - Negative Correlation Between Energy Demand and Pri~es
Summary of Probability Assessment
Railbelt Utilities Providing Market Potential
Energy Supply from Railbelt Utilities
List of Generating Plant Supplying Railbelt Region
Estimated Financial Parameters
Estimated Requirements for G.O.Bonds -Minimum State
Appropriation ($2.3 Billion)
Estimated Requirements for G.O.Bonds -50 Percent State
Appropriation ($3 Billion)
Relationship Between Consumer Price Index and Interest Rates
Financial Analysis with 100 Percent State Appropriation of
Total Capital Cost ($5.1 Billion 1982 Dollars)
Financial Analysis with $3 Billion (1982 Dollars)State
Appropriation with Residual Bond Financing
J
.J:
_]1
J
J
];
_J
J
1
1
r
J
t
~
1
t
]
1
I
1)List of Tables - 3
Number
18.4.7
-1 18.4.8
I
18.4.9
18.4.10
18.5.1
Title
Financial Analysis with Minimum State Appropriation of $2.3
Billion (1982 Dollars)with Residual Bond Financing
Financial Analysis with $1.8 Billion (1982 Dollars)State
Appropriation
Financial Analysis for 100 Percent State Appropriation
Under Senate Bill 646
Financial Analysis for Minimum State Appropriation of
$3 Billion Under Senate Bill 646 with Residual Bond Financing
Basic Parameters for Risk Generation Model
I
J
LIST OF FIGURES
I
j
Number
18.2.1
18.2.2
18.2.3
18.2.4
18.2.5
18.2.6-
18.2.7
18.2.8
18.2.9
18.2.10
18.2.11
18.2.12
18.2.13
18.2.14
18.2.15
18.2.16
18.2.17
18.2.18
Titl e
Probabil ity Tree -System with Al ternatives to Susitna
Probability Tree -System with Susitna
Susitna Multivariate Sensitivity Analysis -Long-term Costs
versus Cumulative Probability
Susitna Multivariate Sensitivity Analysis -Cumulative
Probability versus Net Benefits
Risk Analysis Study Methodology
Elements of the Risk Analysis
Structural Relationship for Handling Risk-Activity
Combinations,Damage Scenarios,and Criterion Values
Alternative Formats for Presenting the Analytical Results
Cumulative Probability Distribution for Watana Project Costs
Cumul ati ve Di stri buti on of Devi 1 Canyon Costs
Cumulative Probability Distribution for Susitna Hydroelectric
Proj ect
Historical Water Resources Project Cost Performance
(48 Proj ects)
Comparison of Susitna Risk Results with Historical Water
Resources Project Cost Performance (48 Projects)
Comparison of Susitna Risk Analysis Results with Historical
Data for Projects with 10 or tv10re Years Between "Int tf al"
Estimate and Completion
Comparison of Susitna Risk Analysis Results with Historical
Data for Dams and Reservoirs
Watana Schedule Distribution Exclusive of Regulatory Risk
Watana Schedule Distribution Including the Effects of
Regul atory Ri sks
Cumulative Probability Distribution for Days of Reduced
Energy Delivery to Anchorage
List of Figures - 2
Number
18.2.19
18.3.1
18.3.2
18.3.3 (a)
(b)
(c)
(d)
18.3.4
18.3.5
18.3.6
18.3.7
18.4.1
18.4.2
18.4.3
18.4.4
18.4.5
18.4.6
18.4.7
t 18.5.1
Titl e
Cumulative Probability Distribution for Days Per Year With No
Susitna Energy Delivery to Fairbanks
Railbelt Region Generating and Transmission Facilities
Service Areas of Railbelt Utilities
Energy Supply (based on net generation 1980)
Generation Facilities (based on nameplate generating
capacity 1980)
Net Generation by Types of Fuel (based on net generation 1980)
Relative Mix of Electrical Generating Technology -Railbelt
Utilities -1980
Energy Demand and Deliveries from Susitna
Energy Pricing Comparisons -1994
System Costs Avoided by Developing Susitna
Energy -Pricing Comparison -2003
Inflationary Financing Deficit Relationship to Long-term
Gain Under 0 and 7 Percent Inflation
Energy Cost Comparison 100 Percent Debt Financing,0 and
7 Percent
Energy Cost Compari son State Appropri ati on $3 Billion
(1982-dollars)
Energy Cost Comparison $2.3 Billion "Minimum"State
Appropriation
Energy Cost Comparison with Pricing Restricted 1994-1995
and 2003-2004 ($1.8 Billion State Appropriation)
Energy Cost Comparison Meeting Senate Bill 646 Requirements
with 100 Percent Financing
Energy Cost Comparison Meeting Senate Bill 646 Requirements
with $3 Billion Appropriation
Specific Risk I:Risk of Bond Financing Requirement Overrun
\
J
I
l
~'
}
l
l
1
l
I
List of Figures - 3
Number Title
u
\)~
18.5.2
18.5.3
18.5.4
Specific Risk II:Impairment of State Credit
Specific Risk III:Early Years Non-viability
Aggregate Risk:Potential Net Operating Earnings by 2001
18 -ECONOMIC AND FINANCIAL EVALUATION
18.1 -Economic Evaluation
(a)Introduction
This section provides a discussion of the key economic parameters used in
the study and develops the net economic benefits stemming from the Susitna
hydroelectric project.Section 18.1 (b) deals with those economic princi-
ples relevant to the analysis of net economic benefits and develops infla-
tion and discount rates and the Alaskan opportunity values (shadow prices)
of nil,natural gas and coal.In particular the analysis is focused on the
longer-term prospects for coal markets and prices.This follows from the
evaluation that,in the absence of Susitna,the next-best thermal
generation plan would rely on substantial and sustained exploitation of
Alaska's coal resources.The future coal price is therefore examined in
considerable detail to provide rigorous estimates of prices in the most
likely alternative markets and hence the market price of coal at the
mine-head within the state.
Section 18.1 (c)presents the net economic benefits of the proposed hydro-
electric power investments compared with this thermal alternative.These
are measured in terms of present-valued differences between Susitna and
non-Susitna system costs.Recognizing that even the most careful estimates
will be surrounded by a degree of uncertainty,the benefit-cost assessments
are also carried out in a probabilistic framework as shown in Section 18.2.
The analysis therefore provides both a most likely estimate of net economic
benefits accruing to the state and a range of net economic benefits that
can be expected with a likelihood (confidence level)of 95 percent or
more.
(b)Economic Principles and Parameters
(i)Economic Principles -Concept of Net Economic Benefits
Anecessary condition for maximizing the increase in state income
and economic growth is the selection of pUblic or private
investments with the highest present-valued net benefits to the
state.In the context of Alaskan electric power investments,the
net benefits are defined as the difference between the costs of
optimal Susitna-inclusive and Susitna-exclusive (predominantly
thermal)generation plans.
The energy costs of power generation are initially measured in terms
of opportunity values or shadow prices which may differ from
accounting or market prices currently prevailing in the state.The
concept and use of opportunity values is fundamental to the optimal
allocation of scarce resources.Energy investment decisions should
not be made solely on the basis of accounting prices in the state
18-1
if the international value of traded energy commodities such as coal
and gas diverge from local market prices.(This divergence may be
due in part to institutional and contractual constraints,or gaps
between marginal and average energy costs in Alaska.)
The choice of a time horizon is also crucial.If a short-term
planning period is selected,the investment rankings and choices
will differ markedly from those obtained through a long-term
perspective.In other words,the benefit-cost analysis would point
to different generation expansion plans depending on the selected
planning period.A short-term optimization of state income would,
at best,allow only a moderate growth in fixed capital formation;at
worst it would lead to underinvestment in not only the energy sector
but also in other infrastructure facilities such as roads,airports,
hospitals,schools,and telecommunications.
It therefore follows that the Susitna project,as other Alaskan
investments,should be appraised on the basis of long-run
optimization,where the long term is defined as the expected
economic life of the facility.For hydroelectric projects,this
service life is typically 50 years or more.The costs of a
Susitna-inc1usive generation plan will be compared with the costs of
the next-best alternative which is the all-thermal generation
expansion plan and assessed over a planning period extending from
1982 to 2051,using internally consistent sets of economic scenarios
and appropriate opportunity values of Alaskan energy.
Throughout the analysis,all costs and prices are expressed in real
(infl ati on-adjusted)terms usi ng January 1982 doll ars,~ence the
results of the.economic calculations are not sensitive to modified
assumptions concerning the rates of general price inflation.In
contrast the financial and market analyses,conducted in nominal
(inflation-inclusive)terms, will be influenced by the rate of
general price inflation from 1982 to 2051.
(ii)Price Inflation and Discount Rates
~.General Price Inflation
Despite the fact that the price level is generally higher in
Alaska than in the Lower 48,there is little difference in the
comparative rates of price changes;i.e.,price inflation.
Between 1970 and 1978, for example,the U.S.and Anchorage
consumer price indexes rose at annual rates of 6.9 and 7.1 percent
respectively.From 1977 to 1978,the differential was even
smaller:consumer prices increased by 8.8 percent and 8.7 percent
in the U.S.and Anchorage.(1)
Forecasts of Alaskan prices extend only to 1986. (2)These indi-
cate an average rate of increase of 8.7 percent from 1980 to 1986.
\
\
For the longer period between 1986 and 2010,it is assumed that
Alaskan prices will escalate at the overall U.S.rate,or at 5 to
7 percent compounded annually.The average annual rate of price
inflation is therefore about 7 percent between 1982 and 2010.As
this is consistent with long-term forecasts of the Consumer Price
Index (CPI)advanced by leading economic consulting organizations,
7 percent has been adopted as the study value.(3, 4)
- Discount Rates
Discount rates are required to compare and aggregate cash flows
occurring in different time periods of the planning horizon. In
essence the discount rate is a weighting factor reflecting that a
dollar received tomorrow is worth less than a dollar received
today. This holds even in an inflation-free economy as long as
the productivity of capital is positive.In other words,the
value of a dollar received in the future must be deflated to re-
flect its earning power foregone by not receiving it today.The
use of discount rates extends to both real doliar (economic)and
escalated dollar (financial)evaluations,with corresponding
inflation-adjusted (real)and inflation-inclusive (nominal)
values•
•Real Discount and Interest Rates,
Several ~pproaches have been suggested for estimating the real
.discount rate applicable to public projects (or to private pro-
jects from the pUblic perspective).Three common alternatives
include:
the social opportunity cost (SOC)rate,
••the social time preference (STP)rate,and
the government1s real borrowing rate or the real cost of debt
capi tal.(5, 6,7)
The SOC rate measures the real social return (before taxes and
subsidies)that capital funds could earn in alternative invest-
ments.
If,for example,the marginal capital investment in Alaska has
an estimated social yield of X percent,the Susitna hydroelec-
tric project should be appraised using the X percent measure of
"foregone returns"or opportunity costs.A shortcoming of this
concept is the difficulty inherent in determining the nature and
yields of the foregone investments.
The STP rate measures sociaty vs preferences for allocating re-
sources between investment and consumption.This approach is
also fraught with practical measurement difficulties since a
wide range of STP rates may be inferred from market interest
rates and socially-desirable rates of investment.
A sub-set of STP rates used in project evaluations is the
owner's real cost of borrowing;that is,the real cost of debt
capital.This industrial or government borrowing rate may be
readily measured and provides a starting point for determining
project-specific discount rates.For example,long-term indus-
trial bond rates have averaged about 2 to 3 percent in the US in
real (inflation-adjusted)terms.(3,8)Forecasts of real
interest rates show average values of about 3 percent and 2
percent in the periods 1985 to 1990 and 1990 to 2000,
respectively.The US Nuclear Regulatory Commission has also
analyzed the choice of discount rates for investment appraisal
in the electric utility industry and has recommended a 3 percent
real rate.(24)Therefore,a real rate of 3 percent has been
adopted as the base case discount and interest rate for the
period 1982 to 2040 •
•Nominal Discount and Interest Rates
The nominal discount and interest rates are derived from the
real values and the anticipated rate of general price inflation.
Given a 3 percent real discount rate and a 7 percent rate of
price inflation,the nomina\discount rate is determined as 10.2
percent or about 10 percent.
(iii)Oil and Gas Prices
- Oil Prices
• Opportunity Value of Fuel Oil
In the base period (January 1982), the Alaskan 1982 dollar price
of No.2 fuel oil is estimated at $8.65/MMBtu.
Long-term trends in oil prices will be influenced by events that
are economic,political and technological in nature,including
the following, to name only a few
••growth rates in the developed world's economies
••-~a-tes of-energy conservi'ition in the developed world
••rates of addition to currently-proven oil reserves
rate of economic development in the Third World and growth in
its per capita energy consumption
••rates of substitution from oil to non-oil energy sources,
depending on (among others)the cost competitiveness of
synthetic and biomass fuels and new energy conversion
technologies such as breeder reactors and laser fusion
1 (1 +the nominal rate)=(1 +the real rate)x (1 +the inflation rate).
=1.03 x 1.07,or 1.102
18-4
••political stability in OPEC and especially OAPEC countries
shifts in the balance of power in the Middle East,Southeast
Asia,North and West Africa,and South America.
A survey of forecasts has identified the following projections
for world oil prices
••Data Resources Incorporated,(9):2 percent (1981-1990)
••World Bank,January 1981 (10):3.2 percent (1981-1990)
US Department of Energy,Energy Information Administration,
Winter 1980 (11): 1.5 percent (low), 3.4 percent (medium),
5.6 percent (high)(1980-2000)
National Energy Board of Canada,Ottawa,Canada,October 1981
(12):Zero percent to 2 percent (1980-2000).
Clearly,a wide range of oil price futures may be postulated.
This uncertainty surrounding energy price projections calls for
the development of several scenarios in a probabilistic frame-
work.Recognizing that probabilistic analysis is required,
three oil price futures and associated probabilities have been
estimated for the period 1982 to 2040,as shown in Table 18.1.1.
The current softness in world oil markets reflects recessionary
conditions in the major oil importing nations.In view of
for~casts pointing to a mid-1982 recovery,and a sustained
growth in the economics of the industrialized world,Acres has
developed the following oil price scenario.
In the most likely (medium)scenario,real oil prices are
expected to escalate at 2 percent and 1 percent in the intervals
1982 to 2000 and 2000 to 2040 respectively.In the case of low
prices,there is zero escalation in the planning period,and in
the high price scenario,the real growth rates are 4 percent
(1982 to 2000)and 2 percent (2000 to 2040)•
•Battelle Analysis and Acres Study Values
The generation planning (OGP)analysis has adopted the Battelle
values for forecast oil prices as shown in Table 18.1.2.These
values reflect a 2 percent annual real growth in oil prices-from
1982 to 2010.
-Gas Prices
Alaskan gas prices have been forecast using both export oppor-
tunity values (netting back CIF prices from Japan to Cook Inlet)
and domestic market prices as likely to be faced in the future by
Alaskan electric utilities.
18-5
• Opportunity Value of Natural Gas
In 1980, 5 percent of Japan's imports of LNG were provided by
Alaska at prices competitive with Japan's three other suppliers
(13).Japan provides a relatively stable future market for LNG,
given its "lack of substantial domestic gas supplies and their
great distance from any possible pipeline routes".(14) Japan
also appears to be willing to agree to higher charges than most
importers for the guarantee of uninterrupted supply. (14)
The opportunity cost of Alaskan natural gas is determined by the
best alternative use for the gas,and the above factors indicate
that the Japanese market provides the best alternative,both
today and as a reliable future source of revenues to Alaska.It
should be noted however,that the opportunity value may not be
realized if current indications of limited Cook Inlet reserves
are confirmed.
Current Pricing Trends
Table 18.1.3 illustrates the prices paid for Alaskan LNG,CIF
Japan over the period 1975 to April 1980.These prices
indicate an average annual growth rate of 27 percent.Prices
vary \'iidely even from month to month."In May 1980,for
instance,Japan was paying CIF prices of $5.53 for Alaskan
LNG."(IS)As of May 1981,LNG deliveries in Japan could
command a price of $6.30/MMBtu (CIF). (16)
The opportunity value of Alaskan gas is based on the poten-
tial delivered price minus the costs of liquefying and trans-
porting the gas,that is,the plant-gate price.Based on
previous Acres studies of transporting LNG over a similar
distance,the Alaskan plant-gate price would be about
$4.65/MMBtu in January 1982 dollars,with liquefaction and
transportation representing about $2.10/MMBtu (1982
dollars)•
••Natural Gas Price Forecasts
Future international prices of natural gas will depend to a
large extent on the development of the supply market. Vari-
ous factors have been hindering this development,such as:
•• the high cost and long lead times involved in putting
export projects on-stream
•• the prohibitive cost of transport (as much as five times
that of oil)
••specific importers and markets must be identified and de-
pended on
limited flexibility in the network.(For example,some
LNG tankers may be incompatible with certain liquefaction
projects.)(15)
18-6
In order for the natural gas market to develop to its full
potential,prices must be high enough to stimulate the supply
market. Considering the long-term potential which is created
by higher prices,natural gas price forecasts should not be
unduly influenced by short-term slow growth demand patterns.
In fact,even in the short term prices are tending to
gravitate towards parity with crude oil.Algeria and Libya
have pushed for FOB parity with crude prices,while
Abu Dhabi, for example,has called for CIF equivalence.In
particular,deliveries of LNG to Japan from Alaska and Brunei
have both been officially set at parity with the average
landed cost of crude in Japan since April.(15)
Given these current trends,long-term forecasts of natural
gas prices tend to assume that future gas prices will grow at
approximately the same rate as crude oil prices.(9, 13)
Accordingly, the natural gas pricing and probability
scenarios developed in this section,follow closely the crude
oil prices scenarios.
Based on these considerations,Table 18.1.4 shows the
probabilities of low,medium,and high gas prices conditional
on the three oil price scenarios developed above.The most
likely (medium)price scenario,as well as the low and high
price cases and corresponding probabilities,are shown in
Table 18.1.5.In the most likely case,with a probability of
46 percent,the Alaskan opportunity values escalate at 2.7
percent (1982 to 2000)and 1.2 percent (2000 to 2040).This
results from CIF prices (in Japan)that grow at 2 percent
(1982 to 2000)and 1 percent (2000 to 2040)and from shipping
costs that are constant in real terms.The Cook Inlet
opportunity value rises from $4.65 (1982)to $12.26 (2040)
measured in 1982 dollars.
The low and high price cases have eQual probabilities of 27
percent.In the low case,the CIF prices remain constant in
real terms,and in the high case the CIF prices grow at real
rates of 4 percent (1982 to 2000)and 2 percent (2000 to
2040)•
•Domestic Market Prices (Supplied by Battelle)
In contrast to the shadow prices or opportunity values discussed
above, the gas prices estimated by Battelle and used in the base
case Optimized Generation Planning (OGP)analysis reflect actual
and forecast domestic market prices facing Alaskan electric
utilities.These year-by-year prices are shown in Table 18.1.6
based on volume-weighted prices applying to CEA and AMLP.The
differences between the opportunity values and domestic market
prices are significant;by 1990 and 2000 for example,the export
18-7
-Introduction
The shadow price or opportunity value of Beluga and Healy coal is
the delivered price in alternative markets less the cost of trans-
portation to those markets.The most likely alternative demand
for thermal coal is the East Asian market,principally Japan,
South Korea,and Taiwan.The development of 60-year forecasts of
coal prices in these markets is conditional on the substitution
potential of coal and the procurement policies of the importing
nations.These factors,in turn,are influenced to a large extent
by the price movements of crude oil.
Coal price forecasts which are based solely on production costs
overlook these important factors.In fact,there are indications
that "economic rents"(that is,a price that exceeds production
costs including a normal return on investment)may be earned by
the producers,mine labor and/or governments.For example,in the
interests of supply security,a coal importer may be willing to
pay a price much higher than actual coal production costs.In
addition,oil price increases induce increased demand for coal,
thus exerting upward pressure on coal prices.Market imperfec-
tions may exist which inhibit the long-term supply response ef-
fects on consumer coal prices.Therefore,coal price forecasts
cannot be based on production costs alone, they must also reflect
the influence of both oil price movements and procurement
policies.Historical trends support these observations.
-Historical Trends
Historically it has been observed that export prices of coal are
highly correlated with oil prices,and that production cost analy-
sis has~ot predi~_1:~_c!a~~J!r_gteJythe_le',-eL-o-f--coalp~ices.Even-
if the production cost forecast itself is accurate,it will estab-
lish a minimum coal price,rather than the market clearing price
set by both supply and demand conditions •
• In real terms export prices of U.S.coal showed a 94 percent and
92 percent correlation with oil prices 1950 to 1979 and 1972 to
1979.2 .
•Supply function (production cost)analysis,has estimated
Canadian coal at a price of $23.70 (1980 US $/ton)for S.E.
British Columbia (B.C.) coking coal,FOB Roberts Bank,B.C.,
2 Analysis is based on data from the World Bank.(17)
,I
Canada.(18, 23)In fact,Kaiser Resources (now B.C.Coal Ltd.)
has signed agreements with Japan at an FOB price of about $47.50
(1980 us $/ton).(19)This is 100 percent more than the price
estimate based on production costs.
•The same comparison for Canadian B.C.thermal coal indicates
that the expected price of $55.00 (1981 Can $)per metric ton
(2,200 pounds)or about $37.00 (1980 US $)per ton would be 60
percent above estimates founded on production costs.(18, 19,
23)•
• In longer-term coal export contracts,there has been provision
for reviewing the base price (regardless of escalation clauses)
if significant developments occur in pricing or markets. That
is,prices may respond to market conditions even before the ex-
piry of the contract.3
• Energy-importing nations in Asia,especially Japan,have a
stated policy of diversified procurement for their coal sup-
plies.They will not buy only from the lowest-cost supplier (as
would be the case in a perfectly competitive model of coal
trade)but instead will pay a risk premium to ensure security of
supply.
Observation of historical coal price trends reveals that FOB and
CIF prices have escalated at annual real rates of 1.5 percent to
6.3 percent as shown below:
•Coal prices (bituminous,export unit value,FOB U.S.ports)grew
at real annual rates of 1.5 percent (1950'to 1979)and 2.8
percent (1972 to 1979).(17)
• In Alaska, the price of thermal coal sold to the GVEA utility
advanced at real rates of 2.2 percent (1965 to 1978)and 2.3
percent (1970 to 1978).
• In Japan, the average CIF prices of steam coal experienced real
escalation rates of 6.3 percent per year in the period 1977 to
1981. (20, 21)This represents an increase in the average price
from approximately $35.22 per metric ton (mt)in 1977 to about
$67.63/mt in 1981.
-Survey of Forecasts
Data Resources Incorporated is projecting an average annual real
growth rate of 2.6 percent for U.S.coal prices in the period 1981
to 2000. (19)The World Bank has forecast that the real price of
steam coal would advance at approximately the same rate as oil
prices (3 percent per year) in the period 1980 to 1990. (10)
Canadian Resourcecon Ltd. has recently forecast growth rates of 2
percent
3 This clause forms part of the recently-concluded agreement between Denison
Mines and Teck Corporation and Japanese steel makers.
18-9
to 4 percent (1980 to 2010)for sub-bituminous and bituminous
steam coa1.(22)
Opportunity Value of Alaskan Coal
•Delivered Prices,CIF Japan
Based on these considerations,the shadow price of coal (CIF
price in Japan)was forecast using conditional probabilities
given low,medium and high oil price scenarios.Table 18.1.7
depicts the estimated coal price growth rates and their associ-
ated probabilities,given the three sets of oil prices.Combin-
ing these probabilities with those attached to the oil price
cases yields the following coal price scenarios,CIF Japan.
Scenario Probabi1 ity Real Price Growth
Medium 49 percent 2 percent (1982-2000)-(most likely)1 percent (2000-2040)
Low 24 percent o percent (1982-2040)
High 27 percent 4 percent (1982 -2000 )
2 percent (2000-2040)
The 1982 base period price was initially estimated using the
data from the Battelle Beluga Market Study. (18)Based on this
study,a sample of 1980 spot prices (averaging $1.66/MMBtu)was
escalated to January 1982 to provide a starting value of
$1.95/MMBtu in January 1982 do11ars.4
As more recent and more complete coal import price statistics
became available,this extrapolation of the 1980 sample was
found to give a significant underestimate of actual CIF prices.
By late 1981~Japan1s average import price of steam coal reached
$2.96/MMBtu.o An important sensitivity case was therefore
developed reflecting these updated actual CIF prices.The
updated base period value of $2.96 was reduced by 10 percent to
$2.66 to rec?gnize the price di ~<;QJlntgJcj;ateiLbyquality
-~--~differential s~-5-etween --A:laski-coa1 and other sources of Japanese
4 The escalation factor was 1.03 x 1.14,where 3 percent is the forecast real
growth in prices (mid-1980 to January 1982)at an annual rate of 2 percent,
and 14 percent is the 18-month increase if the CPI is used to convert from
mid-1980 dollars to January 1982 dollars..
5 As reported by Coal Week International in October 1981, the average CIF
value of steam coal was $75.50/mt.At an average heat value of 11,500 Btu/1b,
this is equivalent to $2.96/MMBtu.
coal imports, as estimated by Battelle.(18) Tables 18.1.8 and
18.1.9 illustrate the range of recent CIF and FOB prices of
steam coal imports to Japan•
• Opportunity Values in Alaska
Base Case -Battelle-based CIF Prices,
No Export Potential for Healy Coal
Transportation costs of $0.52/MMBtu were subtracted from the
initially estimated CIF price of $1.95 to determine the op-
portunity value of Beluga coal at Anchorage.In January 1982
dollars,this base period net-back price is therefore
$1.43/MMBtu.In subsequent years,the opportunity value is
derived as the difference between the escalated CIF price and
the transportation cost (estimated to be constant in real
terms).The real growth rate in these FOB prices is
determined residually from the forecast opportunity values.
In the medium (most likely)case the Beluga opportunity
values escalate at annual rates of 2.6 percent and 1.2
percent during the intervals 1982 to 2000 and 2000 to 2040
respectively.
For Healy coal,it was estimated that the base period price
of $1.75/MMBtu (at Healy)would also escalate at 2.6 percent
(to 2000)and 1.2 percent (2000 to 2040).Adding the esca-
lated cost of transportation from Healy to Nenana results in
a January 1982 price of $1.75/MMBtu.6
In subsequent years,the cost of transportation,of which ~O
percent is represented by fuel cost (which escal ates at 2
percent),is added to the Healy price resulting in Nenana
prices that grow at real rates of 2.3 percent (1982 to 2000)
and 1.1 percent (2000 to 2040).
Sensitivity Case -Updated CIF Prices,
Export Potential for Healy Coal
The updated CIF price of steam coal ($2.66/MMBtu after ad-
justing for quality differentials)was reduced by shipping
costs from Healy and Beluga to Japan to yield Alaskan oppor-
tunity values.In January 1982,prices are $2.08 and
$1.74/MMBtu at Anchorage and Nenana respectively.The
differences between escalated CIF prices and shipping costs
result in FOB prices that have real growth rates of 2.5
percent and 1.2 percent for Beluga coal and 2.7 percent and
1.2 percent for Healy coal (at Nenana).Table 18.1.10 shows
details of these CIF and FOB prices under the three coal
price scenarios.Table 18.1.11 summarizes the coal
opportunity values in each of the two cases and three
scenarios.
6 Transportation costs are based on Battelle.(18, 23)
18-11
(c)
(v) Generation Planning Analysis - Study Values
Based on the considerations presented in Sections (i)through (iv)
above, a consistent set of fuel prices was assembled for the base
case probabilistic OGP analysis,as shown in Table 18.1.12.The
study values include probabilities for the low,medium and high fuel
price scenarios.The probabilities are common for the three fuels
(oil,gas and coal)within each scenario in order to keep the number
of generation planning runs to manageable size.In the case of the
natural gas prices,domestic market prices were selected for the
base case analysis with the export opportunity values used in
sensitivity runs.The base period value of $3 was derived by
deflating the 1996 Battelle prices to 1982 by 2.5 percent per year.
Coal prices were also selected from the base case using Battelle's
1980 sample of prices as the starting point,with the updated CIF
prices of coal reserved for sensitivity runs. Oil prices have been
escalated by 2 percent (1982-2040).
Analxsis of Net Economic Benefits
(i)Modeling Approach
Using the economic parameters discussed in the previous section,and
the data relating to the electrical energy generation alternatives
available for the Railbelt,an analysis was made comparing the
costs of electrical energy production with and without the Susitna
project.The primary tool for the net present worth (PW)benefit
analysis was a generation planning model (OGP)which simulates
production costs over a planning period extending from 1982 to
2010..
The method of comparing the "with"and "without"Susitna scenarios
is based on the long-term PW of total system costs.The planning
model determines the total production costs of alternative plans on
a year-by-year basis.These total costs for the period of modeling
include all costs of fuel and operation and maintenance (O&M)for
all generating units included as part of the system,and the
annual ized investment costs of any generati ng 1'1 ant and system
______transmi-ssion-added-during theperiod-1993 t02010-~Factors which
contribute to the ultimate consumer cost of power but which are not
included in this model are:investment cost for all generating
plants in service prior to 1993, investment cost of the transmission
and distribution facilities already in service and administrative
costs of utilities.These costs are common to all scenarios and
therefore have been omitted from the study.
In order to aggregate and compare costs on a sufficiently long-term
basis,annual costs have been aggregated for the period 1993 to
2051.Costs have been computed as the sum of two components and
converted to a 1982 PW at a 3 percent real discount rate (see
Section 18.1 (b)).The first component is the 1982 PW of cost
output from the first 18 years of model simulation from 1993 to
2010.The second component is the estimated PW of long-term system
costs,from 2011 to 2051.
18;'12
,I
"
J
J
For an assumed set of economic parameters as a particular generation
alternative the first element of the PW value represents the amount
of cash (not including those costs noted above)needed in 1982 to
meet electrical production needs in the Railbelt for the period
1993-2010.The second element of the aggregated PW value is the
long-term (2011-2051)PW estimate of production costs.In consider-
ing the value to the system of the addition of a hydroelectric power
plant,which has a useful life of approximately 50 years,the
shorter study period would be inadequate.A hydroelectric plant
which is added in 1993 or 2002 would accrue PW benefits for only 17
or 9 years respectively using an investment horizon that extends to
2010.However,to model the system for an additional 40 years it
would be necessary to develop future load forecasts and generation
alternatives which are beyond the realm of any prudent projections.
For this reason,it has been assumed that the production costs for
the final study year (2010)would simply reoccur for an additional
41 years,and the PW of these was added to the 18 year PW
(1993-2010),to establish the long-term cost differences between
methods of power generation.
(ii)Base Case Analysis
-Pattern of Investments IIWith ll and IIWithout ll Susitna
The base case comparison of the II with ll and II withoutll Susitna plans
is based on an assessment of PW of production costs as outlined in
18 (c)(i)for the period 1993-2051,using mid-range values for
the energy demand and load forecast,fuel prices,fuel price
escalation rates,capital costs and capital cost escalation rates.
Load forecasts,fuel prices,and constructi09 costs are analyzed
in Chapter 5, 18.1 (b),and 16,respectively.As discussed in
Section 18.1 (b),a real interest and discount rate of 3 percent
is used.
The Susitna plan calls for 680 MW of generating capacity at Watana
to be available to the system in 1993.Although the project may
come on-line in stages during the year,for modeling purposes,
full load generating capability is assumed to be available for the
entire year.In the second stage of Susitna,the Devil Canyon
project is scheduled to come on-line in 2002.The optimum timing
for the addition of Devil Canyon was tested for earlier and later
dates.Addition in the year 2002 was found to result in the
lowest long-term cost.Devil Canyon will have 600 MW of installed
capaci ty..
The II without ll Susitna plan is discussed in Section 6.7 7 and
includes three 200 MW coal-fired plants added in Beluga in 1993,
7 References to Feasibility Report
18-13
1994,and 2007.A 200 MW unit is added at Nenana in 1996.In
addition,nine 70 MW gas-fired combustion turbines (GT's) are
added during the 1997-2010 period.
-Base Case Net Economic Benefits
The economic comparison of the base plan alternatives is shown in
Table 18.1.13.During the 1993-2010 study period the 1982 PW cost
for the Susitna plan is $3.119 billion.The annual production
cost in 2010 is $0.385 billion.The present worth of this level
cost which remains virtually constant,for a period extending to
the end of the life of the Devil Canyon plant,say 2051,is $3.943
billion.The resulting total cost of the "with"Susitna plan is
$7.06 billion (1982 dollars),present valued to 1982.
The non-Susitna plan modeled has a 1982PW cost of $3.213 billion
for the 1993-2010 period,with a 2010 annual cost of $0.491
billion.The total long-term cost has a PW of $8.24 billion.
Therefore,the net economic benefit of adopting the Susitna plan
is $1.18 billion.In other words,the present-valued cost
difference between the Susitna plan and the expansion plan, based
on thermal plant addition,is $1.8 billion (1982 dollars).This
is equivalent to a net economic benefit of $2,700 per capita for
the 1982 population of Alaska.Expressed in 1993 dollars (i.e.,
at the on-line date of Watana),the net benefits would have a
levelized value of $2.48 billion.8
It is noted that the magnitude of net economic benefits ($1.18
billion)is not PCirticularly sensitive to alternative assumptions
concerning the overall rate of price inflation as measured by the
CPl.The analysis has been carried out in real (inflation-
adjusted)terms.Therefore,the present-valued cost savings will
remain close to $1.18 billion regardless of CPI movements,as long
as the real (inflation-adjusted)discount and interest rates are
maintained at 3 percent.
-Test of Internal Rate of Return
The-Sus-i-tne-pt-oject 's-i nternal-rateor--r-etln"rr-{TRRTTr:e.~the-
real (inflation-adjusted)discount rate at which the "with"
Susitna plan has a zero net economic benefit,or the discount rate
at which the cost~of the "with"Susitna and the "alternative"
plans are equal) has also been determined.The IRR is about 4.1
percent in real terms,and 11.4 percent in nominal (inflation~
inclusive)terms.
8 $1.118 billion times 2.105,where 2.105 is the general price inflation index
for the period 1982 to 1993.
j
It is emphasized that these net economic benefits and the rate of
return stemming from the Susitna project are inherently conserva-
tive estimates caused by several assumptions used in the OGP
analyses for:
• Zero Growth in Long-term Costs
From 2010 to 2051,the OGP analysis assumed constant annual pro-
duction costs in both the Susitna and the non-Susitna plans.
This has the effect of excluding real escalation in fuel prices
and the capital costs of thermal plant replacements,and thereby
underestimating the long-term PW costs of thermal generation
plans.
•Loss of Load Probabilities
The loss of load probability in the non-Susitna plan is calcu-
lated at 0.099 in the year 2010.This means that the system in
2010 is on the verge of adding an additional plant,and would do
so in 2011.These costs are however not included in the analy-
sis which is cutoff at 2010.On the other hand,the Susitna
plan has a loss of load probability of 0.025,and may not
require additional capacity for several years beyond 2010.
•Long-term Energy from Susitna
Some of the Susitna energy output (about 350 GWh)is still not
used by 2010. This energy output would be available to meet
future increases in pr9jected demand in the summer months.No
benefit is attributed to this energy in the analysis.
•Equal Environmental Costs
The OGP analysis has implicity assumed equal environmental costs
for both the Susitna and the non-Susitna plans.To the extent
that the thermal generation expansion plan is expected to carry
greater economic cost savings from the Susitna project are
understated.It is conceivable that these so-called negative
externalities from coal-fired electricity generation will have
been mitigated by 1993 and beyond,as a result of the enactment
of new environmental legislation.Such government action would
simply internalize the externality by f'orc'tnq up the production
and market costs of thermal power.
(iii)Sensitivity Analysis
Rather than rely on a single comparison to assess the net benefit of
the Susitna project,a sensitivity analysis has been carried out to
identify the impact of modified assumptions on the results.The
sensitivity analysis addressed the following variables:
•Load Forecast
•Real Interest and Discount Rate
18-15
•Construction Period
• Period of Analysis
• Capital Costs
-Susitna
-Thermal Alternatives
·O&M Costs
Base Period Fuel Price
•Real Escalation in Capital and O&M Costs and Fuel Prices
System Reliability
·Chakachamna included in non-Susitna plan
• Planned delay in Susitna project timing.
-Load Forecast
Throughout the Susitna feasibility study,planning for the project
has been based on a medium growth range of capacity and energy
forecast.It has been realized that this forecast has been made
based on a centerpoint of a range of uncertainty,rather than the
actual expected occurrence.For this reason, the authorities
responsible for demand forecasting have bracketed the range with
high and low forecasts.
As part of the sensitivity analysis,the Susitna project has been
analyzed under scenarios that reflect these high and low
forecasts.The forecasts used in the analysis are the high,
medium and low demand forecasts provide~by Battelle based on the
ISER studies,as discussed in Section 5 and summarized in Table
18.1.14.
Since the load forecast is the major consideration which influ-
ences the timing and size of capacity additions for the system,
the nature of the systems varies greatly depending on the fore-
casts used•
•Low Forecast
In general,the adoption of a lower forecast requires the
install ati on of small er amounts of capacity to be added at
re 1 a tiVe1y~l~t<:rtlmjJlgs~~in.the.pedod~ofstudy.·····1n--the·
non~Susitna plan, only 600 MW of coal-fired units are added, in
the form of two 200 MW units in Beluga and one 200 MW unit at
Nenana.These units are added in 1995, 1997,and 2007.In
addition,8 GT's with a total capacity of 560 MW are added
periodically after 1996.The pattern of capacity additions is
close to that in the medium forecast or base case,but it lags
by several years.
The optimal timing for the addition of the Susitna units is also
changed from that adopted for the medium forecast.As shown in
Table 18.1.15,the selected staging for the project is 680 MW at
9 Reference to Feasibility Report
Watana in 1995,with the 600 MW Devil Canyon plant coming on-
line in 2004.The addition of Devil Canyon in 2007 was also
tested and resulted in a slightly higher long-term PW cost.
Watana,as a single project,was also examined,and long-term PW
costs found to be higher than those arising from the later
addition of Devil Canyon.It should be noted,however,that the
staging of the second project is not as critical as in the other
demand forecast.There is however a need for additional
capacity on the system in 2004 which Devil Canyon can satisfy.
If the project is added in that year,there is a sufficient
amount of energy (1000 GWh)which cannot be used by the system
for several years into the future.
The long-term cost of the non-Susitna plan is $6.878 billion and
that of the Susitna plan is $6.650 billion.Thus,the net
benefit to be released by proceeding with the Susitna project is
$0.228 billion •
•High Forecast
To meet the system demand under the high forecast,capacity is
needed long before 1993.Over the 10-year period prior to 1993,
it was found that an addition of nearly 500 MW of other capacity
would be needed. This could be met by the addition of a 200 MW
gas-fired combined cycle unit in 1987 and 1990,and a 70 MW gas
turbine unit in 1992.The selection of combined cycle units was
essentially the only choice available for system addition in the
1980s since the coal-fired thermal units could not be available
until 1990 because of site development and construction lead
time.
Note that the addition of these three units would be common to
both the "with"and "without"Susitna plans.Therefore,the
annual investment costs arising from capital costs expended on
these pre-1993 plans have not been included in the long-term PW
cost.
In the non-Susitna plan,1000 MW of coal units would be re~
qUired, with four 200 MW units at Beluga and one at Nenana.In
addition,eleven 70 MW GT units would be added.The long-term
cost of the non-Susitna plan is $10.859 billion.
For the "with"Susitna plan,Watana is added in 1993;the Devil
Canyon addition is advanced five years to 1997.In addition,a
70 MW GT unit is added in each of the years between 2006 and
2010.The long-term PW cost of the Susitna plan under the high
forecast is $9.247 billion.The Susitna plan therefore has a
net benefit of $1.612 billion.
-Real Interest and Discount Rate
The base case OGP runs have been made with the interest rates set
at 3 percent in real terms. This rate has been selected on the
18-17
basis of the analysis contained in Section 18.1 (e)above,and is
consistent with APA guidelines.
The required real return on investment will be a state policy
decision.It is realized that the state may require a rate of
return higher or lower than 3 percent.It has been considered
reasonable that the desired real rate of return could vary within
the range of 2 percent to 5 percent.The economic analysis of the
project has been carried out at real rates of 2, 3, 4 and 5
percent.The results of the evaluation are summarized in Table
18.1.15.At 2 percent,the net benefits of the Susitna project
are $2.617 billion.At the high end of the range, a 5 percent
real discount rate results in negative net benefits of $513
million.The "breakeven"discount rate or IRR is about 4.1
percent in real terms.
-Construction Period
Variability on the construction period has the impact of
increasing interest during construction charges.Using economic
parameters, the interest during construction is small and does not
increase significantly as the construction period is extended by
one or two years.Should a project be delayed several years,
alternative forms of generation may be required in place of the
planned unit.However,this change would not significantly impact
on the generation planning analysis since the alternative unit
would,most likely,be a 70 MW gas turbine which has little impact
on the long-term PW cost if only operated for a limited number of
years until the 1arger generati ng pl ant comes on,,:,1i neg The
construction schedule for Susitna has been analyzed in detail in
the study risk assessment described in Chapter 18.2.
- Peri od of Analysis
The system planning period over which the OGP model was used
extended from 1982 to 2010, the same period covered by the system
demand forecasti ng model.However,the Susitna project is added
to the system with Watana on-line in 1993 and Devil Canyon in
_~QQ2 •.Large hydroelectric projects of the·size and nature of
Susitna have a service life of at least 50 years.Therefore,the
analysi s of the project has taken into account system costs to a
period covering the 50 years from 2002,the service life of the
Devil Canyon stage.The conservative nature of this approach has
been reviewed in Section 18.1 (d)(ii)above.
The impact of truncated planning horizons may be determined by
reviewing the base case results shown in Table 18.1.13.The
shortest period for analysis may be considered to extend only to
2010.However,this would account for only 8 years operation for
Devil Canyon,well short of its 50-year economic life.In this
case,the Susitna project would provide PW net benefits of $93
million,compared with a value of $1.180 billion from the more
appropriate base case period extending to 2051.
18 ...18
)
.~
J
(,
'~
,/
~
}
'j
'~
J
"1"
,!
If an interim point were selected based on say 30 years of
operation for Devil Canyon,the net benefits of the Susitna
project would be $0.718 billion.This is derived as the
difference between the costs of the non-Susitna plan ($6.431
billion)and the Susitna plan ($5.713 billion).The net benefits
in this case are 60 percent of those calculated in the base case.
-Capital Costs
Capital costs have a considerable impact on the present worth
costs of the "with"and "without" Susitna scenarios.Capital cost
analysis has been approached by varying the costs of the non-
Susitna and the Susitna plans.
The capital costs for the alternative to Susitna have been esti-
mated by Ebasco,as part of the Battelle alternatives study.
There is some concern that these estimates are based on a less
detailed study and are at a lower level of confidence than those
pertaining to the Susitna project.Thus,the non-Susitna costs
were varied by using "high"and "low"costs of 120 percent and 90
percent of the base estimate.
The second test concerned Susitna capital costs.These were
varied using a "low"capital cost equal to the base estimate less
17 percent.For a "high"estimate,a 17 percent increase was
all owed.
Table 18.1.17 shows the results of this sensitivity analysis.
Note that the Susitna plan remains cost competitive in all cases
examined.In the low and high non-Susitna cases,the net benefits
of the Susitna project are 73 percent and 168 percent of the base
case value.The net benefits are also sensitive to modified
assumptions concerning the Susitna project costs.If the "low"
capital cost is used, the Susitna plan would provide net benefits
of $2.1 billion.In contrast,the "high" value results in net
benefits that drop to $264 million.
- Operation and Maintenance Costs
The O&M component of production costs is relatively low,repre-
senting only 8 percent to 12 percent of the total production costs
in any given year.Therefore,if the O&M estimates were varied in
a manner similar to capital costs,there would be only a 1 percent
to 2 percent impact on present worth costs.For this reason,the
sensitivity of the results to O&M costs was not tested by further
OGP analysi s,
-Base Period Coal Price
As shown in the earlier parts of this Chapter, Section 18.1 (b)
(iv),there is evidence that based on recent statistics,the base
price (opportunity value)for coal could be as high as
18-19
$2.08/MMBtu,compared to the initial estimate of $1.43/MMBtu
developed by Battelle.This updated starting price was tested in
the "with"and "without" cases as shown in Table 18.1.18.This is
a significant sensitivity case as the initial estimates of base
period (January 1982)prices were established by Battelle on the
basis of sample data for 1980.Net economic benefits in this case
are $1.968 billion,or 167 percent of the base case value.
-Real Escalation Rates
Capital and O&M Cost Escalation
It has been forecast that there could be real escal ati on in the
capital costs of power plants averaging 1.8 percent per year
until 1992 and 2 percent per year thereafter.These escalation
rates were incorporated into the base case.In order to test
the sensitivity of results to this assumption,tests were made
with zero real escalation in capital and O&M costs,double the
rate or about 4 percent real escalation,and 1.4 percent real
escalation from 1982 to 2010 as estimated by Battelle.Of these
three,the lower values appear to be more likely since,unlike
finite fuel reserves,construction labor and materials are not a
depletable resource and should not experience sustained real
cost escalation.
Results of this analysis are shown in Table 18.1.19.The
variance in these escalation factors changes the net benefits in
a manner similar to the analysis of variance in capital costs.
Zero real escalation in capital a.nd O&M costs raises net
benefits by one-third.Doubling the rate of escalation causes
the net benefits to fall one-third.In the high case,it should
be noted that the non-Susitna plan changes from four coal units
to two,with the capacity difference made up by GT and combined
cycle additions.In the "Battelle"case,net benefits are
increased by 10 percent relative to the base case•
• Fuel Price Escalation
As non-renewable resources;the pr-ices of coar~gas~and oil are
expected to increase at a rate greater than the general price
level,as discussed in Section 18.1 (b).The base case
escalation rates were 2.6,2 and 2.5 percent until 2000 and 1.2,
2 and 2 percent respectively until 2010.Model runs were also
carried out with high and low levels of fuel escalation.The
low rate was established as zero percent real escalation.The
upper limit was set at 5.2 percent for coal,4 percent for oil,
and 5 percent for gas from 1982 to 2000,and 2.2 percent,2
percent and 2 percent,respectively beyond 2000.The results
are summarized in Table 18.1.19.
1
)
J
J
J
l
(
In the low price escalation scenario,the Susitna plan results
in negative net benefits of $1.078 billion.In the case of high
energy price escalation,the net benefits rise to $2.070
billion.
-System Reliability
A generating system loss of load probability of one day in ten
years has been used in system modeling.Variation of this factor
would cause the system to add more or less capacity,thus poten-
tially changing the staging of alternatives.However,since this
is a predetermined criterion rather than an assumption or projec-
tion,no sensitivity analysis was carried out.
The Battelle AREEP model has the capability to calculate a target
reserve margin based on variable load forecast.It is possible
that given the load forecasts projected by Battelle,a reserve
margin would be recommended greater than that calculated using the
loss of load probability.
-Ch.akachamna
As discussed earlier,the Chakachamna project has not been
included in the base non-Susitna plan.It has been included as a
test case however,and found to lower the net benefits of the
Susitna plan to $837 million,as shown in Table 18.1.20.
- Planned Delay in Susitna Project Timing
As shown in Table 18.1.21,the Susitna project1s net benefits are
essentially insensitive to a planned one- or two-year delay in
timing. Aone-year postponement of the Watana stage to 1994 would
result in net benefits that are 4 percent below those in the base
case. Aone- or two-year delay in both the Watana and Devil
Canyon stages would provide net economic benefits that are 96
percent to 97 percent of the base case values.
(d)Conclusion
The preceding discussion of sensitivity analysis shows that in terms of
impacts on net benefits,the most sensitive variables are base period coal
prices,fuel escalation rates,discount rates,Susitna capital costs,and
load forecasts.As these assumptions are varied through a reasonable range
of values,the Susitna plan is shown to retain positive net economic
benefits relative to the costs of non-Susitna plans.Table 18.1.22
provides a summary of the various sensitivity analyses.
A multivariate analysis in the form of probability trees has also been
undertaken to test the joint effects of several assumptions in combination
rather than individually.This probabilistic analysis provides a range of
18-21
expected net economic benefits and probability distributions that identify
the chances of exceeding particular values of net benefits at given levels
of confidence.The results of the probabilistic analysis are presented in
Section 18.2.
18-22
)
1
)
}
1
j
I !
i
I
I
TABLE 18.1.1:REAL (INFLATION-ADJUSTED)ANNUAL
GROWTH IN WORLD OIL PRICES
(Percent)
Growth Rates
Low Case
Medium (most likely case)
High Case
1982-2000
o
2.0
4.0
2000-2040
o
1.0
2.0
Probability
0.3
0.5
0.2
(
)
u
TABLE 18.1.2:STUDY ASSUMPTIONS:OIL PRICES
Average Price of No.2
Fuel Oil
Year (1982 $/MMBtu)
1982 - 1985 6.70
1986 - 1990 7.33
°1991 - 1995
8.08
1996 - 2000
8.93
2001 - 2005 9.86
2006 - 2010 10.88
TABLE 18.1.3:JAPANESE IMPORT PRICES (C.loF.)OF ALASKAN LNG
1975
1976
'1977
1978
1979
January 1980
February 1980
March 1980
April 1980
Source:Segal &Niering,(15)
US$/MMBtu
1.40
1.70
2.01
2.26
2.37
3.51
3.44
3.48
4.63
TABLE '18.1.4:GAS PRICE ESCALATION AND ASSOCIATED
CONDITIONAL PROBABILITIES
Gas Price Escalat ion,Oil Price Escalation
.b2:::!,Medium High
Low (0 percent 1982 - 2040)
0.7 0.1 0.05
Medium (2 percent 1982 -2000~
1 percent 2000 - 2040 0.2 0.7 0.25
High (4 percent 1982 - 2000;
2 percent 2000 - 2040)0.1 0.2 0.7
\ I
TABLE 18.1.5:OPPORTUNITY VALUE OF NATURAL GAS AT
COOK INLET,ALASKA,1982 - 2040
Transportation Opportunity Value
ClF Price in Japan Costs Gas at Cook Inlet -
(1982 $/MMBtu)(1982 $/MMBtu)(1982 $/MMBtu)
Medium Low Hjgh Medium Low High
Probability ~27%2 ,.N/A ~27%27~~,.----
1982 6.75 6.75 6.75 2.10 4.65 4.65 4.65
1985 7.16 6.75 7.59 2.10 5.06 4.65 5.49
1990 7.91 6.75 9.24 2.10 5.81 4.65 7.14
2000 9.64 6.75 13.67 2.10 7.54 4.65 n.57
2010 10.65 6.75 16.66 2.10 8.55 4.65 14.56
2020 n.77 6.75 20.31 2.W 9.67 4.65 18.2-1
2030 rs.oo 6.75 24.76 2.10 W.90 4.65 22.66
2040 14.36 6.75 30.18 2.10 12.26 4.65 28.08
Annual Growth Rates
-1982 - 2000 2%0 4%0 2.7%o 5.2%
2000 - 2040 1%0 2%0 1•2~~0 2.2~~
TABLE 18.1.6:VOLUME WEIGHTED COOK INLET NATURAL
GAS PRICE TO AMLP AND CEA
Average Price
Period (1982 $/MMBtu)-----
1982 - 1985 0.84
"1986 - 1990 1..33
1991 -"1995 3.03
"1996 - 2000
4.56
2001 - 2005 5.10
)
2006 - 2010 5.63
J
TABLE 18.1.7:COAL PRICE ESCALATION AND ASSOCIATED
CONDITIONAL PROBABILITIES
Coal Price Escalation
Low (0 percent 1982 - 2040)
Medium (2 percent '1982 - 2000; 1 percent
High (4 percent 1982 - 2000; 2 percent
2000 - 2040)
Oil Price Escalation
Low Medium High
0.6 0.1 0.05
0.3 0.7 0.25
O.'I 0.2 0.7
I \U
TABLE 18.1.8:STEAM COAL IMPORTS BY JAPAN,
SEPTEMBER AND OCTOBER \981
CIF Prices
Volumes $/mt-($/MMBtu)*
Origin September October September October
(metric tons)
US 127 037 276 467 75.10 81.33
(2.97)(3.21 )
South Africa 53 709 92 448 65.95 55.90
(2.61)(2.21)
Australia 475 75'1 384 487 65.80 78.59
(2.60)0.11 )
China 125 476 99 912 65.00 72.25
(2.57)(2.86)
Soviet Union 33 805 25 826 65.47 73.68
(2.59) (2.91)
Canada 28 468 130 03.3 67.79 70.55
(2.68)(2.79)
TOTAL 826 246 009 173 67.'17 75.47
(2.65)(2.98)
* Based on an assumed heat value of 1'\500 Btu/lb.
Source:Coal Week International
L-
TABLE lB.l.9:CURRENT INTERNATIONAL SPOT PRICES OF STEAM COAL
1
FOB Price CIF Price Japan FOB Price CIF Pr ice Japan
Sulphur Ash US$/long ton US$/long ton US$/MMBtu US$/MMBtu
Port of Origin Btu/lb Percent Percent Jan.§,'I~B~_Jan.6,19B2 Jan.19B2 Jan.19B2
US 2
Hampton Roads/11 BOO 1.3 14.0 55.00 73 •00 -74.50 2.0B 2.76 - 2.B2·2
Norfolk (11 500)(1.5)(15.0)(52.5Oi (70.50 -72.00)(2.04)(2.74 - 2.BO)
BaIt imore 12 000
'1.0 15.0 57.00 3 75.00 -76.50 2.12 2.79 -2.B5
(12 000)('1.0)(U.5)(52.00)(70.00 -71.50)('109.5)(2.60 -2.66)
2
Mobile 12 000 "1.5 15.0 51.00 3 69.00 -70.50 '1.90 2•.')7 -2.62
('11 300)(1.3)(15.5)(50.00)(6B.00 -59.50)(1.9B)(2.69 -2.75)
South Africa 2
Richards Bay '1'1 900 1.0 '15.0 50.25 57.25 -61.25 1.B9 2.15 -2.303
(10 BOO)(1.0)(15.0)(47.75)(54.75 -5B.75)(1.97)(2.26 -2.43)
Australia
Newcastle 12 000 1.0 14.0 56.')0 66.50 -67.50 2.10 2.47 -2.512&3
Port Kembla (12 000)(1.0)(14.0)(53.00)(63.00 -64.00)(1.97)(2.34 -2.3B)
'1 Calculated using transportat ion rates from Coal Week Internat ional,December V,19B·I.Bracketed figures refer
to November 19B1 data.
2 Contract quotes.All other pr ices are spot prices defined by Coal Week Internat ional as single shipments to be
delivered within one year.
3 Coal Week Internat ional and Energy Economist,December '19B·I.
L--!--
TABLE °\8.1 .10:EXPORT OPPORTUNITY VALUES OF ALASKAN COAL -SENSITIVITY CASE 1
Medium (Most Likely)Coal Price Scenario Low Coal Price Scenario High Coal Price Scenario
Shlppmg
CIF FOB Cost Price CIF FOB Price CIF FOB Price
Price Shipping FOB Price Shipping Price Healy to At Price FOB Price Price At Price FOB Price Price At
Japan Cost Anchorage Cost Healy Nenana Nenana Japan Anchorage Healy Nenana Japan Anchorage Healy Nenana---
January
1982 2.66 0.58 2.08 0.65 1.43 0.31 1.74 2.66 2.08 1.43 1.74 2.66 2.08 \.43 1.74
'1985 2.82 0.58 2.24 0.66 1.58 0.32 1.90 2.66 2.08 °1.42 1.74 2.99 2.41 1.75 2.07
1990 3.12 0.58 2.54 0.68 1.86 0.33 2.19 2.66 2.08 1.40 1.7.3 .3.64 3.06 2.38 2.71
2000 3.80 0.58 3.22 0.74 2.48 0.35 2.83 2.66 2.08 °1.34 1.69 5.39 4.8°\4.07 4.42
2010 4.20 0.58 3.62 0.77 2.85 0.36 3.21 2.66 2.08 1.31 1.67 6.57 5.99 5.22 5.58
2020 4.64 0.58 4.06 0.80 3.26 0•.38 3.64 2.66 2.08 1.28 1.66 8.01 7.43 6.63 7.01
2030 5.12 0.58 4.54 0.84 3.70 0.39 4.09 2.66 2.08 1.24 1.63 9.76 9.18 8.34 8.7.3
2040 5.66 0.58 5.08 0.88 4.20 0.41 4.61 2.66 2.08 1.20 1.61 11.90 11.32 '10.44 10.8)
Annual Growth Rates
°1982 to
2000 2%0·'2.5%0.7%3.1%0.7%2.7%0·'0%-0.4%-0.2%4%4.8%6.m6 5•.3%,.,.
2000 to
2040 1%0%1.2%0.4%°1.3%0.4%°\.2%0%0·'-0.3%-0.°1%2%2.2%2.4~6 2.3%,.
°1982 to
2040 1.3%0%1.6%O.5~6 1.9%0.5%°\.7%0·'0%-0.3~6 -0.1%2.6%3.0%3.5%3.2%,.
1 CIF Prices based on updated (late 198°1)import pr ices of coal in Japa~.Assumes export potent ial for Healy coal.
L~r-.i ____J'--
TABLE 18.1 •II:SUMMARY OF COAL OPPORTUNITY VALUES
Base Period Annual Real Probabil ity Cond i.t ional Probability Given
Base Case
(Jan.<1982)Growth Rate of Low Oil Medium High
Battelle Base Value 1980-2000 2000-2040 Occurrence Pr ices Oil Prices Oil Pr ices
Period flF J:'O..ice ($/MMBtu)--(%)--u~)--(~)--un (%)__(%L_<_
Medium Scenario
CIF Japan 1.95 2.0 '1.0 49 30 70 25
FOB Beluga 1.43 2.6 1.2 49 30 70 25
Nenana 1.75 2.3 I.<I 49 30 70 25
Low Scenario
CIF Japan
1.95 0.0 0.0 24 60 <10 5
FOB Beluga <1.43 0.0 0.0 24 60 10 5
Nenana '1.75 O.<I 0.1 24 60 10 5
High Scenario
CIF Japan 1.95 4.0 2.0 27 10 20 70
FOB Beluga 1.43 5.0 2.2 27 10 20 70
Nenana <1.75 4.5 1.9 27 10 20 70
Sensitiv!lY Case
Updated Base <I
Period CIF Price
Medium Scenario
CIF Japan 2.66 2.0 1.0 49 30 70 25
FOB Beluga 2.08 2.5 1.2 49 30 70 25
FOB Nenana 1.74 2.7 1.2 49 30 70 25
Low Scenario
CIF Japan 2.66 0.0 0.0 24 60 10 5
FOB Beluga 2.08 0.0 0.0 24 60 10 5
FOB Nenana 1.74 -0.2 -0.1 24 60 W 5
High Scenario
CIF Japan 2.66 4.0 2.0 27 10 20 70
FOB Beluga 2.08 4.8 2.2 27 10 20 70
FOB Nenana <1.74 5.3 2.3 27 10 20 70
1 Assuming a 10 percent discount for Alaskan coal due to quality differentials
11
II
[1
[J
I]
I 1
I I
[J
u
u
(J
TABLE '18.1.12:SUMMARY OF FUEL PRICES USED IN THE
OGP PROBABILITY TREE ANALYSIS
Fuel Price Scenario
Low Medium High
Probability of occurrence 25%5m~25%
Base period January '1982 pr ices (1982$/MMBtu)
-Fuel Oil 6.50 6.50 6.50
-Natural Gas J.OO 3.00 3.00
- Coal·Beluga 1.43 1.43 1.43
• Nenana
1.75 1.75 1.75
Real escalat ion rates per year (percent)1
-Fuel Oil
·1982 - 2000 0.0 2.0 4.0
• 2000 - 2040
0.0 2.0 2.0
-Natur al Gas
• '1982 - 2000
0.0 2.5 5.0
• 2000 - 2040
0.0 2.0 2.0
-Beluga Coal
·1982 - 2000 0.0 2.6 5.0
• 2000 - 2040
0.0 1.2 2.2
-Nenana Coal
·1982 - 2000 0.1 2.J 4.5
• 2000 - 2040
0.1 1.1 1.9
'1 ;Beyond 20W,the OGP analysis used zero real escalat ion in all cases.
I
[1
i Io
LJ
u
u
TABLE '18.1.13:ECONOMIC ANALYSIS SUSITNA PROJECT -BASE PLAN
$x 10
6
1982 PRESENT-WORTH OF SUSlfNA COSTS
ESTIMATED
PLAN ID COMPONENTS 1993 - 2010
20'18 2010 -2051 1993 -2051
Non-Susitna A 600 MW Coal-Beluga 3213 491 5025 8238
200 MW Coal-Nenana
630 MW GT
Susitna C 680 MW Watana 3'119 385 3943 7062
600 MW Devil Canyor
'180 MW GT
Net Economic 1176
Benefit of
Susitna Plan
TABLE 18.'1.'14:SUMMARY OF LOAD FORECAST USED FOR SENSITIVITY ANALYSIS
ME D I U M LOW H I G H
YEAR MW GWh MW GWh MW GWh
1990 892 4456 802 3999
'1098 5703
2000 1084 5469 921 4641 1439 7457
2010 1537 779'1 1245 6303 2165 '11435
Source:Battelle,Railbelt Alternative Study,December 1981
fl
I I
1
J
u
u
TABLE 18.1.15:LOAD FORECAST SENSITIVITY ANALYSIS
$x 10
6
1982 PRESENT-WORTH OF SYSTEM COSTS
NET
ESTIMATED ECONOMIC
PLAN ID COMPONENTS 1993 - 2010 2010 2011 -2051 1993 -2051 BENEFIT
Non-Susitna K1 400 MW Coal-Beluga
Low Forecast 200 MW Coal-Nenana 2640 404 4238 6878
560 MW GT
Susitna
Low Forecast K2 680 MW Watana (1995)2882 360 3768 6650 228
600 MW Devil Canyon
(2004)
Non-Susitna J 1 800 MW Coal-Beluga 4176 700 6683 108591
High Forecast 200 MW Coal-Beluga
770 MW GT
430 MW Pre-1993
Susitna J 2 680 MW Watana (1993)3867 564 5380 9247')1612
High Forecast 600 MW Devil Canyon
(1997)
350 MW GT
430 MW Pre-1993
From 1993 to 2040
1\,
TABLE 18.1.16:DISCOUNT RATE SENSITIVITY ANALYSIS
$x 10
6
1982 PRESENT-WORTH OF SYSTEM COSTS
m:.f\L u teA I t.t.::,llMA ltV Nt.I
PLAN 10 (percent)1993 - 2010 2010 201'1 -2051 1993 -2051 BENEFIT
Non-Susitna Q1 2 370'1 465 7766 1'1167
Susitna Q2 2 3156 323 5394 8550 2617
Non-Susitna A 3 3213 491 5025 8238
Susitna C 3 3119 385 3943 7062 1176
Non-Susitna S1 4 2791 517 3444 6235
Susitna S2 4 3080 457 3046 6126 109
Non-Susitna P1 5 2468 550 2478 4946
Susitna P2 5 3032 539 2426
5459 (513)
II
u
TABLE 18.1.17:CAPITAL COST SENSITIVITY ANALYSIS
$ x 10
6
1982 PRESENT-WORTH OF SYSTEM COSTS
NET
REAL DISCOUNT RATE ESTIMATED ECONOMIC
PLAN ID (percent)1993 -2010 2010 2011 - 2051 '1993 - 2051 BENEFIT
Alternative Capital Costs +20%
Non-Susitna G 3460 528 5398
8858
Susitna C1 31'19 385 3943 7062 '1976
Alternative Capital Costs -'10%
Non-Susitna G1 3084 472 483'1 7915
Susitna C1 31'19 385 3943 7062 853
Susitna Capital Costs Less 17%
Non-Susitna A 3213 49'1 5025 8238
Susitna X2 27'lO 336 3441 6'151 2087
Susitna Capital Costs Plus 17%
Non-Susitna A 3213 49'1 5025 8238
Susitna Y2 3529 434 4445 7974 264
An adjustment calculat ion was made regarding the plus or minus capital cost of the 3 GT "n its added
in 2007 -20'lO since the difference was less than $10 x 'lO6.Beyond 20'lD,this effect was included.
I )
LJ
TABLE 18.1.18:SENSITIVITY ANALYSIS -UPDATED BASE PERIOD
(JANUARY 1982)COAL PRICES
$x 106
1982 Present Worth of Sustina Costs
Costs of Costs of Net
Base Period Coal Price Non-Susitna Susitna Economic
Base Case (1982 $/MMBtu)Plan Plan Benefits
Base Case 1.43 82.38 7062 1'17 6
Sensit iv ity 2.08 9030 7062 1968*
(Update)Use
*The value is produced by "forcing"the system to use the same coal fired
plants as in the base case.If the system is allowed to optimite,however,
combined cycle units are selected in lieu of coal fired plants and the net
economic beneFit is essentially the same as in the base case.
AlASKA RESOURCES l~BRAR't
u.s.Department of the Interior
TABLE 18.1.19:SENSITIVITY ANALYSIS -REAL COST ESCALATION
$x 10
6
1982 PRESENT-WORTH OF SYSTEM COSTS
ESTIMATED NET
PLAN 10 1993 - 2010 2010 2011 -2051 '1993 -205'1 BENEFIT
Zero Escalation in Caoital Costs and O&M
Non-Susitna 01 2838 422 4319 7157
Susitna 02 2525 299 3060 5585 '1572
Esca1at ion in Capital
Costs and O&M <a?ttelle)l
Non-Susitna X1 3142 477 488'1 8023 -
Susitna X2 2988 366 3745 6737 1286
Double Escalation in Caoital Costs and O&M
Non-Susitna P1 3650 602 6161 9811
Susitna R2 3881 503 5148 9029 782
Zero Escalation in Fuel Prices
Non-Susitna V1 2233 335 3427 5660
Susitna V2 3002 365 3736 6738 (1078)
Hioh Escalation in Fuel Prices
Non-Susitna W1 4063 643 6574 '10367
Sus rtria W2 3267 403 4121 7388 2979
1 Capital and O&M costs assumed to escalate at 1.4 percent '1982 to 2010
TABLE 18.1.20:SENSITIVITY ANALYSIS -NON-SUSITNA PLAN WITH CHAKACHAMNA
-
$x '\06
1982 PRESENT-WORTH OF SYSTEM COSTS
I:.:J liMA II:.U NI:.l
PLAN 10 COMPONENTS 1993 - 2010
20'10 2011 -2051 1993 -2051 BENEFIT
Non-Susitna B 3JO MW Chakachamna 3038 475 486'1 7899
with 400 MW Coal-Beluga
Chakachamna 200 MW Coal-Nenana
440 MW GT
Susitna C 680 MW Wat ana 3119 385 3943 7062 837
600 MW Devil Canyon
180 MW GT
TABLE 18.1.21:SENSITIVITY ANALYSIS -
PLANNED DELAY IN SUSITNA
PROJECT TIMING
Susitna Base Case
One-year delay for
Watana (1994)
$x '\06 $x '\06
1982 Present Worth Net Economic
10 of System Costs Benefit
C 7,062 1,'176
C3 7,'\05 1,133
I
i
One-year delay for
Watana and Devil
Canyon (1994, 2003)
Two-year delay for
Watana and Devil
Canyon (1995, 2004)
C4
C5
7,165
7,230
1,134
1,138
TABLE 18.1.22:SUMMARY OF SENSIfiVITY ANALYSIS -INDEXES
OF NET ECONOMIC BENEFITS
Index Value
BASE CASE ($1,176 MILLION)
Fuel Escalation -
-High
-Low
Discount Rates
- High-High (5%)
-High (4%)
-Low (2%)
Susitna Capital Cost
-High
-Low
Load Forecast
- Hlgh
-Low
Non-Susitna (fhermal)
Capital Costs
-High
-Low
Capital and O&M
Cost Escalation
- High
-Intermediate (Battelle)
-Low
Chakachamna (included in
Non-Susitna Plan)
Updated Base Coal Pr ice
Planned Delay in Susitna
Project
-One-year delay,Watana
- One-year delay,Watana and Devil Canyon
- Two-year delay,Watana and Devil Canyon
100
-44
9
223
23
178
1.37
"19
168
7.3
67
109
134
71
167
96
96
97
High fuel escalat ion case provides net benefits equal to 253 percent of the
base value,2.53 x $1,176,or $2,975.
2 Low fuel escalation case provides minus 92 percent of the base case net
benefits,-.92 x $1,176,or -$1,082.
I
j
18.2 -Probability Assessment and Risk Analysis
(a)Introduction to Multivariate Sensitivity Analysis
The feasibility study of the Susitna Project included an economic analysis
based upon a comparison of generation system production costs.The system
costs were estimated with and without the proposed project using a
computerized model of the Railbelt generation system. In order to carry
out this analysis,numerous projections and forecasts of future conditions
were made.In order to address these uncertain conditions,a sensitivity
analysis on key factors was done.This analysis focused on the variance in
each of a number of parameters and determined the impact of this variance
on the economic feasibility of the project.Each factor was varied
singularly with all other variables held constant.
The purpose of the analysis was served by constructing a probability tree
of future conditions for the Alaskan Railbelt electrical system, with and
without the Susitna project.Each branching of the tree represents three
values for a given variable which were assigned a high,medium and low
value as well as a corresponding high,medium and low probability of
occurrence.The three values represent the expected range and mid-point
for a given variable.In some cases,the mid-point represents the most
likely value which would be expected to occur.End limbs of the
probability tree represent scenarios of mixed variable conditions and a
probability of occurrence for the scenario.
The computer production cost model was then used to determine the PW cost
of the electric generation system for each scenario.Using the
probabilities assigned to each branch, the PW costs for each "wt th".and
II without" Susitna scenario were plotted agai nst the correspondi ng
cumulative probability.Net benefits of the project have also been
calculated and analyzed in a probabilistic manner.
(b)Approach to Probability Assessment
The method followed in the multivariate analysis involved four stages:
-Selection of key variables
-Probability tree development
-Modeling of system costs
- Analysis of results
(i)Selection of Key Variables
The sensitivity tests performed in the economic analysis (see
Section 18.1)identified a list of variables which could
significantly affect the economic feasibility.This list
incl uded:
18-23
•Construction Period
• Period of Analysis
· Capital Costs
-Susitna
-Thermal Alternatives
•O&M Costs
•Base Period Fuel Price
•Real Escalation in Capital and O&M Costs and Fuel Prices
•System Reliability
•Chakachamna included in non-Susitna plan
•Planned delay in Susitna project timing.
Of this list,several of the inputs are considered to be policy or
methodology decisions and are not included in the probabilistic
analysis.These include the interest and discount rate,the period
of analysis and system reliability criteria.The single variable
sensitivity analysis demonstrated that other criteria such as the
construction period and O&M costs had little or no impact on the
comparison of II withll and II without ll Susitna system costs.
Although sensi ti vity resul ts based on varying the real escal ati on of
capital and O&M costs had a measurable influence on PW costs,it was
not included in the probabilistic analysis.The range of capital
cost escalation rates tested in the sensitivity analysis extended
from 0 percent to 4 percent per year from 1982 to 2010.The
mid-range was approximately 2 percent.It is believed that this
range accurately covers the minimum and maximum rates anticipated
for construction cost escalation.Sensitivity of net benefits to
capital and O&M cost excalati ons was found to be moderate rel ative
to other variables.Therefore,this variable was excluded from the
probability assessments.
The three remaining variables were used in the probabilistic
analysi s.These are the load forecast,capi tal cost estimates,both
for generation al ternatives and for the Susitna Project,and real
escalation in fuel prices.The variable values and probabilities
are discussed in (ii)below.
~--~tiil·Probability Tree
Given the three selected "key"variables for the non-Susitna
analysis (four for Susitna),a probability tree was constructed
based on the high,medium and low value for each of the
variables.
The non ....Susitna tree consists of 3 variables and 3 values (high,
medium and low)for each,resulting in 27 possible combinations, as
shown in Figure 18.2.1.The numbering system selected for this
analysis ranges from T01 to T27 where T01 refers to the thermal
(non-Susitna)case,high load forecast,high alternative capital
18-24
)
j cost and high fuel cost escalation.At the lower end of the tree,
T27 refers to the thermal case,low load forecast,low alternative
capital cost and low fuel cost escalation scenario.
The Susitna probability tree (see Figure 18.2.2)could have a
maximum of 4 variables and 3 values for each,resulting in 3
4,or
81 branches.However,a review of the Susitna base plans developed
in the economic analysis showed that the medium plan calls for the
addition of only three 70 MW gas turbines in the last three years of
study. A check on the effect of varying the cost of these units
indicated an impact on long-term costs of less than 0.5 percent.
Thus,it was assumed that in the medium IIbranches ll there is no
vari abil ity in thermal al ternatives cost.
In the low forecast there is no need for thermal alternative
generation in the 1993-2010 period during which the II with ll Susitna
scenario is being considered.Accordingly, the alternative capital
cost variable is removed from that branch.As a result,both the
medium and low forecast portions of the probability tree are reduced
by a factor of 3.These adjustments reduce the number of ultimate
scenarios from 81 to 45 without affecting the accuracy of the
multivariate analysis.
A similar numbering system was adopted for the Susitna analysis
ranging from SOl to S45 where SOl to S27 refer to high load forecast
scenar-t os,S28 to S36 refer to medi um load forecast scenari os,and
S37 to S45 represent low load forecast scenarios.
(iii)Present Worth of Long-term Cost
and Net Benefit Approach
The OGP production cost model was used to determine the PW (in 1982
dollars)of production costs for each scenario,as described in
Section 18.1 (c).For each tree,the scenario costs were ranked
from lowest to highest and the probability associated with each
scenario was used to provide a plot of cumulative probability versus
PW cost.Additionally,the scenario costs were weighted with their
associated probabil ities to provide an expected value of the PW
cost.
A second method of cost comparison used in Section (d)below is by
comparing net benefits.The net benefit can be estimated by
comparing similar II with ll and II without ll Susitna scenarios,and by
examining the difference in PW long-term costs.For example,in a
"wi th"Susitna scenario with PW costs of $6 billion compared to a
similar non-Susitna scenario with $7 billion PW costs,the PW of the
production cost saving over the long-term would be $1 billion.This
difference is the net benefit and again, these net benefits were
ranked from low to high and a cumul ative probabil ity calculated from
the individual probabilities.An expected value of net benefits was
al so calcul ated.
Susitna
(c) Variables and Ranges
(i)Load Forecast
As a single variable,the variance of load forecast remains one of
the most important factors.The selection of type and timing of
alternative units is dependent on the selected forecast.
In terms of the multivariate sensitivity analysis,the load forecast
variation represents the first level of uncertainty in the
probability tree.The forecasts used were generated by the Battelle
Railbelt Alternative Study group in December 1981 with the use of
their Railbelt Electric Demand (RED)model,which relates economic
activity,energy prices,and government expenditures to energy
demand.The range of variability in the load forcastis presented
in Table 18.2.1.Note that these forecasts differ slightly from the
final forecasts produced in January 1982 by Battelle.
The probability of the low,medium or high forecast occurring was
estimated as a symmetrical pattern of .2,.6 and .2 respectively.
These estimates of probability were based upon the estimate by
Battelle that the probability of exceedance of their forecasts was
approximately 90 percent for the low forecast and 10 percent for the
hi gh forecast.
The plans used in the probabilistic analysis are identified as
follows:
Low Load Forecast:
Non-Susitna -first 200 MW of thermal capacity added in 1995
-Watana 600 MW in 1995
-Devil Canyon 600 MW in 2004
Medium Load Forecast:
Non-Susitna -first 200 MW of thermal capacity added in 1993
.Susitna
1982 -1992 period:(common to both cases)
200 MW of thermal combined cycle capacity added
in 1987
200 MW of thermal combined cycle capacity in
1990
70 MW of thermal gas turbine in 1992
, !
I
.~
I
.r
.1
J
'\
J
together with:
Non-Susitna first 200 MW of thermal capacity added in 1993
Susitna -Watana 680 MW in 1993
-Devil Canyon 600 MW in 1997
(ii)Alternative Capital Cost
Consistent with the univariate economic analysis,the base capital
cost estimate plus 20 percent was used as the high value and the
base capital cost estimate minus 10 percent was used as the low
value.These figures were selected based on a review of the
Railbelt Alternatives Study Coal Cost Estimate report prepared by
Ebasco for Battelle.The discussion contained in the report
indicated that there was a greater likelihood of cost increase than
decrease.
The base (medium),high and low capital costs for the coal,gas
turbine and gas-fired combined cycle plants are shown in Table
18.2.2.These capital costs include allowance for interest during
construction based on an S-shaped expenditure curve and the medium
economic parameters used throughout the study. In addition,the
first unit sited in the Beluga area and the single unit at Nenana
district carry the appropriate costs of transmission system
strengthening and interconnection.The probability of the
occurrence for the high,medium and low capital costs were estimated
as a .20, .60,and .20.
(iii)Fuel Cost and Escalation
Considerable effort has been concentrated on defining fuel prices
and escalation rates of the various fuels for alternative forms of
generation Railbelt,both by Acres and by Battelle for their
Railbelt Al ternative Study.
The low,medium and high cases are all linked to the forecast
escalation rate in the world market price for oil,as shown in
Section 18.1 (b).
-Coal
As outlined in Section 18.1 coal reserves available to the
Railbelt include coal mined at Healy and a potential coal supply
from the as yet undeveloped Beluga field.Furthermore,Healy coal
could be transported to Nenana for use as fuel in a potential 200
MW coal-fired plant located there due to air quality restrictions
at Healy.Three starting coal prices based on point of use were
developed for input into the multivariate sensitivity analysis.
For each of these starting coal prices,three escalation rate
scenarios were developed, a low, a medium or most likely case,and
18-27
a high case.Probabilities of occurrence of .25, .50 and .25
respectively were assigned to the three escalation rates.These
probabilities are discussed in detail in Section 18.1 (b).Table
18.2.3 summarizes these prices and escalation rates.
- Natural Gas
Cook Inlet natural gas is presently sold to Anchorage utilities at
existing contract rates.It is generally agreed that the price is
artificially low and will increase significantly as these
contracts are renegotiated.Thus,a world market opportunity
value was selected as the base starting price for modeling
purposes.Based on the Battelle medium price forecast,a 1982
opportunity value of $3/MMBtu was selected.This value when
coupled with Acres medium fuel escalation rates yields values
equal to Batte11e
1s assumptions during the 1993-2010 study period.
In the low case,prices were assumed constant at $3/MMBtu through-
out the study period.The medium case escalation rate was 2.4
percent (1982-2000)and 2 percent (2001-2010).The high case
escalation rate was set at 5 percent (1982-2000)and 2 percent
(2001-2010).Table 18.2.3 summarizes these forecasts of gas
prices.
Di still ate Oil
Table 18.2.3 summarizes the low,medium and high oil price
trends used in this analysis assuming a 1982 rate of $6.50/MMBtu,
based on Battelle estimates.
(iv)Susitna Capital Cost
The potential for variation in the Susitna Project capital cost has
been analyzed in the feasibility study. In general,the approach
has been to produce an estimated capital cost with a re1 ati vely hi gh
level of confidence that the ultimate project cost will be less than
the "upper limit"cost (in 1982 dollars).As shown in Section 18.2
(f)through (g),the risk analysis has indicated that the estimated
capital cost has a 17 percent chance of being equalled or exceeded
given the 1ow probability but high imp(fctr;-~Ks~wnicfccoUl doccUr
during construction (i.e.,major seismic event or flood).
During earlier sensitivity tests,capital costs were allowed to vary
from 83 percent of the project estimate to 117 percent.These
capital costs are presented in Table 18.2.4.
Assi gnment of probabil i ti es to the three 1evels of estimate was
based upon the feasibil ity study risk assessment.The approach to -f.•
the "upper 1imit"val ue for the Susitna capital cost was an attempt )
to bound the base estimate with a high level of confidence that the
18-28
overall project cost will be less than this estimate.Therefore,
the assignment of probabilities of occurrence are somewhat different
than for the non-Susitna alternatives.Based on the risk analysis,
a probability of .6 was assigned to the low case and values of .25
and .15 were assigned to the medium and high values.These values
reflect the expectation that ultimate costs of the project will be
less than the current estimate (in 1982 dollars).
(d)Resul ts
This section presents the results from the analysis of the two probability
trees and of the input data in accordance with the methodology described in
Secti on (b).
(i)Probability Tree: Non-Susitna
The parameters for the twenty-seven scenarios defined by the
probability tree in Figure 18.2.1 were entered into the simulation
model to determine the 1982 PW of system costs.These results are
presented in Table 18.2.5 and Figure 18.2.1.
The PW cost varied by nearly 350 percent from the lowest cost
scenario ($4.41 billion)to the highest cost scenario ($15 billion).
The low cost relates to the case of low load forecast,low capital
costs for thermal uni ts and zero real escal ati on in fuel costs.
Conversely, the high case includes the high forecast for each of
these variables.The large spread from low to high cost seems most
dependent on the fuel cost escalation rate used.The wide range in
fuel costs during the study period and the reliance on fossil fuels
in the non-Susitna cases led to the wide spread in PW costs.
Table 18.2.5 also shows the calculation of costs versus cumulative
probability.This plot is derived as the summation of the
probabil i sti c increments of costs for each scenari o,The increment
is the product of a scenario·s PW cost and its probability.For the
non-Susitna case,the expected value of PW costs is $8.48 billion.
Visual representation of the data from Table 18.2.5 is shown in
Figure 18.2.3.This graph is based on a histogram of PW cost versus
cumulative probability.
(ii)Probability Tree:Susitna
The 45 scenarios in the "with"Susitna case shown in Figure 18.2.2
were also run using the simulation model to obtain the system
production costs.The results are shown in Table 18.2.6.The
overall variability of PW costs in the Susitna case is much less
than the non-Susi tna case.The range from lowest to hi ghest is
$5.54 billion to $11.59 billion,a range of about 200 percent as
compared to 350 percent for the non-Susitna alternatives.The
expected val ue of PW costs ts $7.03 bill ion.
18-29
(iii)Comparison of Present Worth of Long-term Costs
Figure 18.2.3 presents the two histograms of long-term costs for the
II with ll and II without ll Susitna cases.From these it is seen that the
non-Susitna plan costs could be expected to be significantly less
than the Susitna plan costs about 6 percent of the time,approxi-
mately equal to the Susitna costs 16 percent of the time,and
significantly greater 78 percent of the time.
A compari son of the expected val ue of long-term costs for the II wi th"
and "wi thout" cases yields an expected value net benefit of $1.45
billion.This value represents the difference between the
non-Susitna PW cost of $8.48 billion and the Susitna PW cost of
$7.03 billion.
(iv)Net Benefits
A second method of exam,m ng the II wi th"and "wi thout" Susitna proba-
bility trees is to make a direct comparison of similar scenarios and
to calculate the net benefit of each comparison.This method is
discussed in more detail in section (b).Table 18.2.7 lists the 81
comparisons of similar scenarios between the 27 non-Susitna case and
45 Susitna case scenarios.As was done for the individual tree
cases,the net benefits were ranked from low to high and plotted
against cumulative probability,as shown in Figure 18.2.4.The net
benefits vary from minus $2.92 billion with an associated
probability of .0015 to a high of $4.80 billion with an associated
probability of .018.The single comparison with the highest proba-
bility of occurrence of .108 has a net benefit of $2.09 billion.
The plot of net benefits shows a IIbreakeven ll between the II with ll and
II without ll Susitna cases at about 23 percent,consistent with the
previous comparison,i.e.,positive net benefits will accrue from
the Susitna project with a probabil ity of 77 percent.
(e) Extensions to the Multivariate Analysis
Introduction
The initial probability analysis was carried out under the implicit
assumption that energy prices and load forecasts (energy demand)are not
correlated.The probabilities attached to high (H),medium (M)and low (L)
energy prices were therefore constant across the L,M,and Hload
forecasts.
Glven the importance of energy prices to the Al askan economy it may be
postulated however,that energy demand could be either positively or
negatively correlated with prices and that the probabilities of H,M,and L
demand should be conditional on the levels of energy prices.These
conditional probabilities would reflect the elasticity of demand with
respect to energy prices.Two cases were explored, corresponding to
positive and negative correlation and elasticity.
18-30
~
Ij
(i)Case 1 -Positive Price/Demand Correlation
This case depicts a scenario in which higher (lower) energy prices
provide an increase (decrease)in state revenues,incomes and
overall economic activity,leading to higher (lower)energy
consumption in general,and higher (lower)electricity demand in
particular.In essence,it is assumed that the income effect
outweighs the price effect stemming from higher or lower energy
prices.1 As shown in Table 18.2.8 the probability tree was
modified such that higher (lower)demand is more likely to be
associated with higher (lower) energy prices than with lower
(higher)prices.Note that the initial tree was altered only with
respect to the conditional probabilities of the load forecasts.It
is also noted that the revised probabili ti es correspond to an
elasticity of about +0.15 2.
Based on these probabilities,the cumulative probability
distributions of present valued costs were constructed for the
Susitna (S)and thermal (T)plans.These show that the chances of
an S plan being more costly than the T plan are 25 percent.The
costs of the Sand T plans are approximately equal with a
probability of 6 percent,and the S plan is distinctly less costly
with a probability of 69 percent.In comparison, the initial
probabil ity analysis indicated that the chances of more-costly,
equal-cost,and less-costly S plans were about 16 percent,6 percent
and 78 percent respectively.
(ii)Case 2 - Negative Price/Demand Correlation
In this scenario,it is hypothesized that higher (lower) energy
prices would on balance result in lower (higher)energy consumption
and electricity demand.In contrast to Case 1,Case 2 depicts a
1 There is a further possibility that larger state revenues from higher
energy prices would lead to substantial subsidies to the cost of electrical
energy to Alaskan consumers and hence further increase the positive
correlation between energy prices generally and demand.'Since such subsidies
are a political policy decision they cannot be forecast and are therefore not
taken into account. This factor could,however,only reinforce the
conclusions reached.
2 The el asti ci ty is defi ned as the percent change in the expected val ue of
demand divided by the percent change in real prices.For example,in 2010,
the expected values of the load forecast given Land Menergy prices are 7 263
GWh and 8 223 GWh respectively,a difference of 13 percent.The percent
difference between Land Menergy prices in 2010 is 99 percent.Thus the
elasticity is 13 percent (13/99) or .13.Similar elasticities were measured
for the L-H and M-H pairs of load forecasts and energy prices.
18-31
situation in which the price effect outweighs the income effect
resulting from a shift in energy prices and corresponding levels of
Alaskan economic activity.As shown in Table 18.2.9 the initial
probability tree was modified such that higher (lower) energy prices
are more (less)likely to lead to lower energy demand and load
forecasts.The revised conditional probabilities reflect an
elasticity of demand of about minus 13,calculated as in Case 1
above.Cumulative probability distributions of PW system costs were
developed for the Sand T plans.These indicated an even higher
lt keli hood for posi ti ve net benefi ts from the S pl an wi th a 91
percent chance that the S pl an woul d be the 1ess costly al ternative.
In this case there is no region of "ambiguity"with equal costs
attached to the Sand T plans;therefore,it is asserted that there
is only a 9 percent probability that the T plan would be
cost-competitive.Table 18.2.10 summarizes these results and
compares them with those obtained in the initial probability tree
analysis.
(f)Approach to Risk Analysis
As the preceding paragraphs demonstrate, the Susitna hydroelectric project
is viable in economic terms through a broad range of possible deviations
from expected values of key parameters.Even so, net project benefits are
sensitive to Susitna capital cost variations;and alternative financing
plans are predicated on the assumption that the proposed project schedule
will be met.Every reasonable effort was made to prepare conservative cost
estimates and to produce an achievable schedule. Yet,uncertainties are
i nvol ved and their potenti al importance demands that they be gi ven
appropriate consideration at various stages in project development.
rJ
A risk analysis was undertaken as the basis for determining the extent to ')
which perceived risks are likely to infiuence capital costs and schedule...
In addition,because a mature Susitna project would represent a major
portion of the total generation system, a further risk analysis was )
accomplished to assess the probability and consequences of a long-term )
outage of the proposed transmission system. This section summarizes the
risk analyses.A more detailed report is included in the project
documentation for Subtask 11.03,Risk Analysis.
Any major construction effort is inevitably exposed to a large number of '
risks.Floods may occur at crucial times. Accidents should not happen,I J
but they sometimes do. Sub-surface investigations,no matter how thorough,
do not al ways tell the whol e story about what will be found when major
excavation work goes on.The normal estimation process impl icitly accounts?
for a set of reasonably "normal"expectations as direct costs are )
developed, addi ng a conti ngency to the di rectl y-computed total on the
grounds that probl ems usually do occur even though their specific nature ,)
may not be accurately foreseen at the outset.,
)
}
The Susitna Risk Analysis took explicit account of 21 different risks,
applying them as appropriate to each major construction activity.The
effort involved combining reasonably precise data (e.g.,the probability
that a particular flood crest will occur in any given year can be
determined from analysis of hydrologic records) with numerous subjective
judgments (e.g.,until a particular flood crest does occur,we cannot know
with any degree of certainty what havoc it will wreak).The over-all
methodology is illustrated in Figure 18.2.5 and is briefly described
below:
(i)The base cost and schedule estimation effort was reviewed to
determine important underlying assumptions, areas of uncertainty,
proposed construction methods and sequence.
(ii)A risk list was developed, providing an initial statement of major
areas of uncertainty to be considered in the analysis.It was
important at this stage to begin to make initi al gross assessments
of how each risk might affect the project at various stages of
completion, as well as to estimate the extent to which dependency
existed between one risk and another.(In this regard,for example,
the risk of a major flood is independent of the risk that geologic
conditions will differ from those expected.On the other hand,it
can be reasonably asserted that the risk that any given contractor
will experience a construction accident is at least partially
dependent on the risk that the same contractor will have poor
construction quality control.)
(iii)Upon completion of the estimate review and concurrent with
development of an initial risk list,a review was made of
proprietary risk analysis software as the basis for specifying
particular modifications which would permit proper treatment of all
data el ements.
(iv)Adata collection effort was accomplished for each identified risk
and a determination was made of the probability that each of a
selected range of risk magnitudes would be realized in any given
year.Where data gaps existed,a decision analysis process was used
to produce required information.
(v) Transformation criteria were developed so that individual risk
analysts could more easily view the consequences of realizing any
single risk in terms of "natural"criteria.For example,it is
easier to think in terms of the volume of earth involved in a slope
failure than to think directly of its cost impact. Transformation
criteria can then be used to convert to cost and schedule
implications.
(vi)Software revisions were made in accordance with specifications noted
at sub-paragraph (iii)above concurrent with the analysis of risks.
18-33
(vii)For each major construction activity at each dam site,the
consequences of realizing each possible risk magnitude were assessed
and estimated.Responses (actions which will be taken if a
particular consequence is realized)were developed.
(viii)As the work proceeded,reviews and revisions were made to introduce
collective jUdgments from diverse disciplines into the process.
(ix)The initial data set was run and interpreted.Anomalies were
identified and risks emerging as most significant were further
reviewed to ensure that their consequences had been adequately
accounted for.
(x)Whereas the primary risk analysis effort focused upon the
construction phase, a separate analysis of the transmission system
was also made to assess the likelihood and the consequences of a
major transmission outage. A similar methodology was foll owed in
this sub-analysis.
(xi)All input data was updated based on the results of step (ix)above.
(xii)A final run was made to compute expected values of costs and
completion schedules as well as to create probability distributions
for these items. This final output provided the basis for
interpretation.
.,
I i
••J
J
(g)Elements of the Analysis
Figure 18.2.6 graphically depicts important.questions which were addressed
at the start and relates them to elements of the analysis.Each element is
further subdivided as follows:
(i)Configurations
Three primary configurations were considered:
- the Watana hydroelectric project (with transmission)
- the Devil Canyon hydroelectric project (with transmission)
the Susitna transmission systen-elcnev-
Separate risk studies of these configurations permitted the J
production of data which can be aggregated in various ways to
accommodate alternative "power-on-line" dates which differ according
to the various demand forecasts.}
(il)Configuration States
Two confi gurati on states were considered:)
-Construction Period -applicable to Watana and Devil Canyon;..)
- Operation Period -applied only to the transmission system
configuration.
..J
(iii)Risks
Twenty-one risks were identified for consideration in the analysis
and were grouped as follows:
- Natural Ri sks
• flood
·ice
•wind
• seismic
• permafrost deterioration
· geologic conditions
1ow streamflow.
-Design Controlled Risks
•seepage/piping erosion
·groundwater.
-Construction Risks
•equipment availability
·labor strikes/disputes
· material avail abil ity
·equipment breakdown
• material del iveries
• weather.
-Human Risks
•contractor capability
•construction quality control
•accidents
•sabotage/vandalism.
- Special Risks
• regulatory delay
·estimating variance.
(iv)Activities
For each configuration state involving construction,up to 22
activities were considered.For Watana,for example,these
included:
-main access
-site facilities
-diversion tunnels
18-35
- cofferdams
-main dam excavation
-main dam fill initial portion
-main dam fill final portion
-relict channel protection
- chute spillway
-emergency spillway
-service spillway tunnels
-intake
penstock
-powerhouse
-transformer gallery
-tailrace and surge chambers
-turbine-generators
-mechanical/electrical equipment
-swi tc hya rd
-transmission
-impoundment
-test and commission.
(v)Damage Scenarios
Up to ten different damage scenarios were associated with each
logical risk-activity combination.While these varied significantly
from one risk-activity combination to another,they generally
described a range of possibilities which accounted for discrete
increments ex tendi ng from "no damaqe"to "catas tropht closs II •
(vi)Cri teri a
The consequences of realizing particular risk magnitudes for each
activity were measured in terms of the following criteria:
-cost implications
- schedule implications
-manpower requirements.
(vii)Boundary Conditions
The following assumptions and limitations were established to permit
a reasonable and consistent analysis of the problem:
-All cost estimates were made in terms of January 1982 dollars.
Thus,results are presented in this report in terms only of real
potential cost variations,exclusive of inflation.
-The analysis was limited only to the construction periods for
Watana and Devil Canyon si nee the greatest potenti al cost and
schedule variance would be possible during these periods.The
risk analysis for the operating period was associated solely with
),
I
I
I,
\
( h)
the transmission system since that configuration represents the
most likely source of a major system outage during project
operation.
-The risk analysis was accomplished concurrently with finalization
of the total project cost estimate and was necessarily associated
with the feasibility level design.There is clearly some potential
for design change as the project proceeds and a future risk
analysis should be undertaken coincident with completion of final
detailed design and prior to commitment to major construction
activities.Even so, the "estimating variance"risk takes into
account the fact that some design changes are likely to appear as
detailed design effort proceeds.
- A great deal of subjective judgment was necessarily involved in
assessing certain probabilities and in predicting possible damage
scenarios.This effort was accomplished initially by individual
qualified professionals in the various disciplines and was
subjected to iterative group review and feedback efforts.To the
extent that individual hiases entered the analysi s,thei r effects
were probably mutually offsetting.Even so,sensitivity tests
were made for risks which were important contributors to the final
resul ts.
The risk list does not include the important possibility of
funding delays or of financing problems.These issues were dealt
with in a separate financial risk analysis as discussed in
paragraph 18.5 below.
Risk Assessments
For each of the risks identified in paragraph 18.2 (g)(iii)above,the
assessment commenced with detailed definition of credible events.Whereas
flood was identified as a risk,for example,a definition was sought of the
magnitudes of floods which could occur and, with each magnitude,the
probability that it would occur.Depending upon the particular risk under
consideration,data sources included reasonably accurate scientific data
(particularly applicable to the natural risk category),historical
experience on water resources projects,and,where data gaps existed,
subjective group judgments.
In each case,the effort was to identify some maximum credible event (what
is the most extreme event,albeit highly unlikely,that could occur?).
This cholce set an upper limit on a scale of possible events which always
began with a minimum magnitude corresponding to a "no damage"situation.
Continuing with flood as an example,the maximum credible event was
considered to be the probable maximum flood which had been computed in the
hydrologic studies (corresponding to a return period of more than 10,000
years and an annual probability of occurrence of less than .0001).The
minimum magnitude "no damage"event at the lower end of the scal e varied
18-37
from activity to activity.(In this regard for example,a cofferdam built
early in the construction period and designed to withstand a 50-year flood
event can be expected to suffer damage if a 100-year event actually occurs.
Late in the project a 100-year event would not only cause no damage to
structures in place,but also it might be regarded as fortuitous because it
could improve the reservoir impoundment schedule.)
Once risks were defined and logical risk-activity combinations were
rev'i ewed,a concept of the consequences of real izi ng each sel ected ri sk
magnitude was postulated (e.g.,if this risk magnitude is real tzed.,will a
partially completed structure be damaged?Will it fail?If it fails,is
some other work in progress di srupted?)•Cl early,it cannot be determi ned
with certainty what precise damage scenario should be associated with a
given risk magnitude for a particular activity.Thus,a range of damage
scenarios was defined and associated with each of them a probability of
occurring if a particular risk magnitude is realized.
Even if a particular risk level is realized and a particular damage
scenario is suffered,there is no certainty as-to the cost of restoring the
activity,nor can we be sure how long it will take to do so.Things do go
exceedingly well every once in a while. Occasionally they go very badly,
indeed.Each of the ri sk anal ysts was asked to provide three val ues for
each criterion:
- A minimum corresponding,for instance,to the one time in twenty that the
weather is particularly good,materials are readily available,no
accidents occur,and the like.
- A modal value associated with the most likely expectation of the
analyst.
A maximum value corresponding to the one time in twenty that everything
is more difficult than expected.
In the computerized calculation process,the three criterion values,
supplied by the risk analysts were fitted to a triangular distribution,
which approximated the Beta distribution illustrated at the bottomof
Figure 18.2.7.In effect,then,designation of the three conceptual
.c~i-tey:'..io n·-values-led·,to··gen eration"ofahistog ram'wi'th'reTativeTY'narrOw
intervals and a nearly-continuous range of possible values over a
relatively-wide spectrum.
Figure 18.2.7 illustrates the structural relationship for handling
risk-activity combinations,damage scenarios,and criterion values.
While the procedure described above is generally applicable,some
commentary on particular aspects of its application and on certain unique
risks is appropriate:
.I
J
1''''''
}
.'/,
)
(i)The terminology "damage scenario"has been used for convenience
since most identified risks will normally be thought of as reasons
that the cost will be higher than had been estimated or that the
schedule will be exceeded.In fact,however,the process does
permit consideration of what might be regarded as a "negative"
damage scenario.The geologic conditions risk is an excellent
example.The cost estimate was produced on the basis of estimates
of requirements for some concrete lining in the penstocks,extensive
grouting,a certain level of rock bolting,and the like.If
geologic conditions are found to be better than currently assumed,
the costs could be less and the schedule might be accelerated.
(ii)The estimating variance risk was treated in a special way because it
cannot easily be conceptualized in physical terms.It accounts for
inevitable differences which do occur between estimates and actual
bids,and between bids and actual activity costs -even in the
absence of any other identi fied ri sks,Its probabili ty of
occurrence and associated range (fractions or multiples of the basic
estimate)were determined from historical data on water resources
projects.It includes,but is not necessarily limited to,such
considerations as:
- the influence of competition and market pressures;
-estimating discrepancies or errors in unit quantities on the parts
of both owner's estimator and bidder;
-particular contract forms and the owner's acceptance/
non-acceptance of certain risks;
-labor market conditions and the nature of project labor
agreements;
-productivity and efficiency changes over time;
- the cost implications of variances between activity schedules and
actual activity durations;
- the potenti al for scope changes over time;
-extraordinary escalation of construction costs above the
underlying inflation rate.
(iii)In addition to estimating variance,a second special risk is
associated with regulatory matters.Various legislated controls
will most certainly be applied to the Susitna project and it is a
rel atively simple matter to compute the minimum time in which
regulatory requirements could be satisfied.It is a far more
difficult task indeed to estimate the precise nature and duration of
possibl e future regul atory delays.It woul d also cl early be
inappropriate to attempt to apply regulatory risks at the activity
1evel .
This risk was handled by developing a separate distribution for a
range of periods necessary for satisfaction of important licensing
and permitting requirements.
18-39
Data used in arrlvlng at a distribution was based on recent
experiences on other water resources projects,as well as on
discussions with staff members of the Federal Energy Regulatory
Commission.The effect of applying the regulatory risk is primarily
one of shifting the starting time for commencement of construction
activities,leading to corresponding change in the projected
completion time. A lesser effect of the regulatory risk was to
introduce delays during construction.
Regulatory requirements have been an important infiuence during the
past decade on major construction costs and schedules,though it is
difficult to isolate their effects.In order to separately consider
estimati ng vari ance ri sks and regulatory ri sks, "
e stimating
variance" probabil ity determination rel ied heavily upon water
resources construction data developed for projects essentially
completed prior to the passage of the National Environmental Policy
Act (NEPA).As noted above,regulatory risk probability
di stributi ons were derived from more recent projects.
(iv)Each of the various risk magnitude probabilities was originally
calculated as an annual value.On a risk-activity by risk-activity
basis,these annual values were then converted by standard
computational procedures to provide a probability of occurrence
during the duration of the activity.
(v)The concept of "response"is particularly important in the formal
risk analysis process.As the terminology suggests,a "response"
represents the action to be taken if a particular event occurs.
There are two ki nds of II response".The fi rst -and most often used
-is an expected reaction to the occurrence of a particular damage
level (i.e.,if this damage level is incurred,then what actions
must be taken~o restore the activity to its pre-damage status?And
what costs,schedule,and manpower implications (consequences)wiT!
result?).A second kind of response can also be considered and it
provides an important link between the design team and the risk
analysis team.This latter is the "preventive response" (i .e.,what
changes might reasonably be made in the design and/or construction
_~__procedures -which wo uld-permi-t -us -to -evotd-o r-reduceapar-ttcular
damage level?Is the cost and schedule change which might ensue
worthwhile when compared to the probability and magnitude of the
consequences which would otherwise be incurred?).A number of
preventive responses were identified by risk analysts during the
risk study and several of these were incorporated into the project
design and design criteria.There may be further opportunities for
preventive response. Since none would be chosen unless it offered a
net benefit to cost and/or schedule,it may reasonably be concluded
that as detailed design proceeds and as subsequent risk analysis
updates are accomplished, a gradual reduction in the spread of
possible values can be expected.
'j
j
,'1
Jj
1}'
")
J
J
(i)Interpretation of Results
(i)Presentation of Data
A variety of formats is available for presentation of risk analysis
results.Figure 18.2.8 illustrates three common methods.The
choice of a particular graphic display and of lIexpected value ll
calculations is explained as follows:
The density form ((2)on Figure 18.2.8)plots the probability that
a particular value will occur against its value. This kind of
distribution was used in the preparation of histograms for risks
and damage levels,as may be seen on Figure 18.2.7.Insofar as
presentation and interpretation of final outputs are concerned,
however,the density form is not as meaningful.The decision
makers tend to be more concerned about the confidence they can
have that a particular value will not be exceeded than that the
same value will actually be achieved. (In other words,it is more
meaningful to know that there is a 90 percent chance that a
certain cost will be $100 million or less than it is to know that
there is a 5 percent chance that the cost will be between $95
million and $100 million.)
-The reverse cumulative form ((3)on Figure 18.2.8)provides a
measure of the probabil ity that a parti cular cri teri on value will
be exceeded (e.g.,such a distribution might indicate that there
is a 10 percent chance that a particular activity will cost more
than $100 million).
-The cumulative form ((1)on Figure 18.2.8)provides a measure of
the probability that a particular value will not be exceeded.
This latter form was selected for presentation of results since it
relates directly to the decision maker1s need to know how
confident he can be that total costs will be within certain limits
and it also allows him to understand that further exposure may
exi st.
-The lIexpected value ll is the value which would appear on the
average if a large number of projects of this type were
constructed independently under the same conditions.
Minor variations in activity costs were generated by the estimating
team concurrent with development of the risk analysis.In addition,
account was taken of the expectation that construction costs will
escalate at a faster rate than normal inflation - both in the
economic analyses and the risk analyses.To avoid confusion
regarding absolute cost values,the results of the risk analysis are
presented in this section as percentages of the estimated project
cost or as ratios between actual costs and estimated costs.
18-41
(ii)Watana Cost-Probability Distribution
Figure 18.2.9 provides the cumulative distribution of total direct
costs and their related non-exceedance probabilities as determined
in the risk analysis.Certain important points noted on the figure
are interpreted as follows:
-The project cost estimate was presented in Chapter 16 of the
Feasibility Report.Point "A"on Figure 18.2.9 corresponds to
this project estimate.As may be read directly from the display,
the analysis suggests that the probability of completing Watana
for less than the project estimate is about 73 percent.Said
another way,the chance of underrun (in January 1982 dollars)is
73 percent.
-When the low cost estimate (as tested in the sensitivity analysis)
is considered,Point "S"results.The probability that Watana
will be completed for less than the low cost estimate is about 46
percent.
The fact that this probability is lower than that cited above is,
of course,to be expected.It will be noted that the percentage
value on the horizontal scale at Point "S"is 83 percent,arrived
at from the ratio between low cost estimate and project estimate.
- In spite of the relatively comfortable chance of underrun (or said
another way,the degree of confidence we may have in the project
cost estimate),it is nonetheless true that the project remains
exposed to some potential for costs well above the total estimated
costs.Point "C"on Figure 18.2.9 corresponds to the high cost
estimate.It will be recalled that a sensitivity analysis was
undertaken to determine the effect of such a cost on total project
economics.The risk analysis suggests that there is a 90 percent
probabil i ty that the hi gh cost estimate wi ll not be exceeded.
-As will be noted from Figure 18.2.9,there remains a small but
measurable possibility that the project costs will exceed even the
high value at Point "C".It can be argued that the degree of
conservatism which was used inthe~ai'faTysls~~na~s(fverslatea the·
possibility of extreme upper limits on total cost.The paragraph
on comparison with available data below addresses this
conservatism issue,comparing our results with historical data.
-The expected value of the actual cost is 90.25 percent of the
project estimate.
(iii)Devil Canyon -Probability Distributions
Figure 18.2.10 provides the cumulative probability distribution for
Devil Canyon costs.Points "A",liS II ,and "C"on the curve
correspond to those discussed above for Watana and are associated
18-42
if-··l..
"
'(,l'
.)
')
/J
}
with probabilities of 74 percent,47 percent,and 90 percent respec-
tively,for actual percentages of the project estimate being less
than indicated values.Once again, a not insignificant long "tail"
in the extreme upper right-hand portion of the distribution provides
a measure of the potential exposure to large overruns.The expected
value of the actual cost is 91.5 percent of the project estimate.
(iv)Total Project Distribution
Figure 18.2.11 combines the separate Watana and Devil Canyon
projects,providing a cumulative distribution for the Susitna hydro-
electric project as a whole.Points "A","S",and lieu now have
associated probabilities of non-exceedance of 73 percent,47
percent,and 90 percents,respectively.Taken as a whole,the
figure suggests a very broad range of total project cost ratios is
possible.Even between the 10 percent and 90 percent probability
interval,the cost range spans nearly $3 billion.If the project
follows historical patterns,it may be expected that this range will
narrow over time as detailed design and construction proceeds. A
word of caution is important enough to deserve repetition at this
point: the cost di stri buti ons are in every case based upon January
1982 doll arsand they do not account for the effects of infl ati on.
Nor do they include interest during construction or finance charges.
Only the potential for extraordinary construction cost escalation
(over and above inflation)has been taken into account.It follows
that if the project is completed in the next several decades, the
final "actual"cost will have to be adjusted to equivalent 1982
dollars if it is to be compared with risk analysis results as
presented herein.
(v)Comparison with Available Data
During the assessment of the important "estimating variance"risk
(see paragraph 18.2 (h)(ii)above),historical data for 48 federal
water resources proj~cts completed prior to passage of NEPA were
considered.While certain important limitations apply to the use of
this data,it is nonetheless worthwhile to compare it with our
Susitna Risk Analysis results.Recognizing that each of the histor-
ical projects differed from another in terms of cost,schedule,and
complexity,we have once again chosen to normalize the data by
displaying a cost ratio scale rather than an actual absolute cost
value.Figure 18.2.12 offers a cumulative probability histogram for
various cost ratios.In each case,the cost ratio reflects the
actual project cost (after adjustment for inflation)divided by the
"initial"estimated cost.As may be seen from the display,
relatively large overruns have occurred in the past and they were
almost inevitably the basis for widely publicized "finger pointing".
Less well known,but parti cul arly important,is the evi dence that a
substantial number of water resources projects have been
accomplished for less than the originally estimated costs.
18-43
In order to compare this information with the Susitna Risk Analysis
results,it is necessary to determine the meaning of "initial"
estimate in terms of the historical data.In each case,the
"initial"estimate is the estimate presented to the Congress at the
time a request was made for project authorization.Thus,it would
be inappropriate to regard the current Susitna estimate (as
discussed in Chapter 16) as an "initial"estimate in the federal
sense.Fortunately,however,the Susitna project does have a long
history of federal involvement. Indeed, the Corps of Engineers
provided a detailed "initial"estimate in 1975 as the basis for
seeking authorization for important design activities.This
lIinitial"estimate was further updated by a second "initial"
estimate in 1979 after some additional exploratory work and further
analysis were requested by the Office of Management and Budget.
Inclusive of contingencies and excluding lands,the direct cost
"initial"Corps of Engineers'estimate (from the 1979 report)in
January 1982 dollars for the Watana/Devil Canyon (thin arch dam)
project was used as the denominator for display of possible Susitna
cost ratios.
Figure 18.2.13 overlays the results of the Susitna Risk Analysis on
the historical data.Note that the cost ratios differ on this
display from those on Figure 18.2.11 because of the necessity to use
the "initial"estimate for comparison purposes.
As may be seen from Figure 18.2.13,the Susitna Risk Analysis
results reflect a more pessimistic expectation at low cost levels
than the historical data would appear to indicate is reasonable.
The degree of pessimism appears appropriate,however,for .the
following reasons:
-The pre-NEPA data base largely excludes cost implications of
regulatory requirements.Our own assessment indicates that
regulatory matters do impose some additional important cost
burdens on post-NEPA projects.These have largely been accounted
for in the project estimate,but some uncertainty must remain.
-The data base includes a variety of time intervals between the
.lIi-nitiap·-estimate and the-·-actual-re-al;zed-cost-:-BY--arsa~fgr-egat=
ing the data to include only those water resources projects
reflecting ten years or more between "initial"estimate and actual
costs,a new histogram can be generated as shown on Figure
18.2.14.The Susitna results continue to appear pessimistic at
the lower end in light of historical data,but the difference is
seen to have diminished on this display.Some optimism is
reflected for higher cost possibilities,but the Susitna estimate
is well above the mean of the values in the data set.The
distribution also reflects a longer tail at the extreme upper end
than the data set displays.
18;,;44
)
)
/)
j
I
I
(vi)
-The data base included water resources projects which are not
directly comparable to Susitna.Removing such projects as canals,
harbors,and locks permits generation of a third histogram for
dams and reservoirs as shown on Figure 18.2.15.As may be seen
from this display,the Susitna Risk Analysis appears to offer an
even more conservative expectation than the total data base had
refl ected •.
In short,it appears reasonable to assert that the results of the
risk analysis are consistent with historical data and,if any bias
is evident,it is on the side of conservatism.
Schedule Risks
At the same time that minimum,modal,and maximum cost values were
estimated for each damage scenario in each risk-activity set,
estimates were also made of similar values for potential schedule
changes.As a result,schedule probability distributions were
generated for each major activity.These individual distributions
could not be combined in the same way as was accomplished on the
cost side,however.Delays in certain activities can be tolerated
with no expectation of change in total project schedule.Delays in
other areas may bear a one-to-one relationship with total project
delay.
A critical path network was prepared for the entire set of
activities for each configuration.Individual probability
distributions for critical activities were then combined to yield a
distribution for the total project schedule.
Several critical paths were identified in the process since a long
delay on a non-critical activity can, of course,place that activity
on a new critical path.The raw schedule delay distribution was
then considered in·the context of a one-year sc~edule contingency
which had been built into the original estimate and in light of
regulatory delay risks.The resulting distributions are discussed
and interpreted as follows:
-Figure 18.2.16 provides a cumulative probability distribution for
months from the scheduled completion date for the Watana project.
It reflects all risk contributions except those posed by regula-
tory requirements.It is based upon a critical path through the
3 It is important to note that wi th the excepti on of the "requlatory"and
lI estimate variance ll risks,all criterion values were estimated as increments
or decrements to the direct cost or schedule estimate.The assertion by the
estimating team that a one-year contingency was included in the schedule
distribution was accounted for by shifting the raw probability distribution
one year to a new centerpoint.
18-45
main dam and it takes into account the one-year schedule contin-
gency.As may be read directly from the figure,the probability
of completing the project ahead of schedule or on time is about 65
percent.There is only a 17 percent chance of completing the
project a year early (i.e.,in 1992).
- Figure 18.2.17 provides a similar distribution after regulatory
risks are accounted for.Two components are included: (1)prior
to the start of construction a license must be issued by the
Federal Energy Regulatory Commission.There is a small chance (25
percent)that the license will be issued a year earlier than the
current 30-month licensing schedule anticipates.The probability
of meeting or bettering the 30-month estimate is about 72 percent
and there is a 90 percent probability that not more than 39 months
will be required;(2) during the construction period,regulatory
delays may be imposed as a result of various permitting require-
ments,injunctions,and the like.These delays yield only
increases in schedule and range from a 50 percent probability of
delays of a month or less to a 95 percent probability that
regulatory delays during construction will not exceed 12 months.
As may be seen from Figure 18.2.17,the net effect of the
regulatory risks is to broaden the range of possible values.At
the lower end of the distribution,it will be noted that the
chances of completing at least a year early have increased to
nearly 40 percent --primarily because of the chance of getting a
license early and therefore starting early.No significant change
appears for the probability of meeting or bettering the schedule.
A substantial effect is evident in the upper portion of the curve
where the chances of long regulatory delays have pushed out the 95
percent confidence level to an expectation of no more than three
years'delay --a significant change from the 12 to 13 months
attributable to risks other than regulatory,as may be seen on
Figure 18.2.16.
While similar distributions can be plotted for Devil Canyon,they
are less meaningful since there is flexibility associated with its
starting date.
('li tl Transmission-Li-ne-Risk-s----_··.
The separate risk analysis of the Susitna transmission system was
conducted to determine the probability of significant power supply
interruptions at the two major load centers in Anchorage and
Fairbanks.The methodology was generally similar to that described
in preceding paragraphs.Recognizing that the system is assumed to
be in an operating mode,those risks which had applied only for
construction in the preceding analysis (e.g.,contractor capability)
were eliminated from the risk list.Additions to the list were made
to account for the potential effects of lightning,aircraft
collisions,and anchor-dragging in Knik Arm (applicable to the
I
)
}
1
}
}
J
submarine cable segment).Account was taken of redundancies
designed into the system (e.g.,a loss of one line in the three-line
system extending south toward Anchorage can be tolerated with no
loss of energy delivery capability).
In addition,special ~ttention was given to dependencies (e.g.,an
earthquake which causes the loss of two lines will very likely knock
out the third.On the other hand,vandalism which causes an outage
on one line is only infrequently expected to extend to all lines).
Important assumptions included the availability of well-trained
repair crews and equipment,and a reasonable supply of spare
components.
The results of the analysis provide the cumulative probability of
not exceeding a given number of days of reduced energy delivery
capability.Figures 18.2.18 and 18.2.19 display this information
for Anchorage and Fairbanks,respectively.Interpretations are as
follows:
- In the particular case of Anchorage (Figure 18.2.18),it will
first be noted that the probability scale includes only the
extreme upper range of non-exceedance probabilities.The
intersection of the distribution curves on the probability axis
indicates that the probability of no lost energy delivery
capability in a given year is .958 and of not having 50 percent
reduction is .955.Beyond these points the curves rise sharply,
indicating that outages beyond 5 days are extremely unlikely.The
lJexpectedlJ annual value of .0696 days for a total delivery loss
may be compared with the 1J10s s of load probebt l f ty"of .1 (one day
in 10 years)which had been used in the generation planning
efforts in the economic studies.In short,the risk analysis
confirms that the reliability of the transmission system for
energy delivery to Anchorage is consistent with the requirements
of the overall Railbelt generati on system.The "expected"annual
value of .09171 days for a 50 percnet reduction in energy delivery
appears to be similarly acceptable when compared to assumed loss
of load probability.
-The cumulative probability distribution for Fairbanks (Figure
18.2.19)has a slightly different intercept on the probability
axis and its shape is also slightly different from those for
Anchorage.These differences stem from the fact that delivery to
Fairbanks requires no submerged crossing and certain other risks
(e.g.,flood,temperature extremes)would be expected to have
different probabilities for northern and southern segments of the
system. In spite of the absolute differences,it may be seen from
the display that the lJexpectedlJ annual value of .08116 does not
exceed the loss of load probabil ity cri teri on of .1 day per year.
No 50 percent loss for Fairbanks is shown since the loss of one of
two lines causes no reduction in delivery capability.Two lines
lost is,of course,a 100 percent loss.
18-47
(viii)Emergency Response
In spite of the apparent reliability of the transmission system,it
is nonetheless true that a small but finite chance of relatively
long-term outages does exist.It is also unfortunately true that
certain extreme risk magnitudes (e.g.,combination of extreme low
temperature,wind,and ice)which could lead to an outage also tend
to coincide with high demands by users on the generating system.
The "response" in this case is extremely important.The final
report for Subtask 11.03,Risk Analysis,provides such a response in
the form of a preliminary emergency plan which includes such
measures as shedding non-essential loads,putting reserve capacity
on line,and energy transfers from military generation systems.
Prior to the time that the Susitna hydroelectric project begins
operation,this plan should be updated and occasional tests should
be made of its practicality.
(j)Concl usions
.\
J
I..1
Based upon the risk analysis,it is concluded that:
-The probabilities that actual costs will not exceed values subjected to
sensitivity tests in the economic analysis are as follows:
_~__Exposu~eto-potenti-al-costs-above--theprojectestima t.e does exist cHid
there is about a 1 percent chance that an overrun of 40 percent or more
(in 1982 dollars)will occur.
Value
•Project estimate
.Low capital cost tested in
the economic analysis
High capital cost tested in
the economic analysis
Probabil ity that
value wi 11 not
be exceeded
73 percent
47 percent
90 percent
\
}
)
J
~,
The annual probability that no interruption in energy delivery to major
load centers will occur as a result of transmission line failures is in
excess of 95 percent.
Expected values of energy delivery interruptions are less than one day in
ten years and are consistent with loss of load probabilities assumed in
the generation planning efforts.
\
..J
I
1
- There is a 65 percent probability that the Watana project will be
completed prior to the scheduled time in 1993.Exposure to schedule
delays is heavily influenced by regulatory requirements and there is a 10
percent probability that the Watana project will not be completed until
1995 or later.
18-49
1 Battelle Pacific Northwest Laboratories,December 1981.
11
\ I
1~1
u
u
u
TABLE 18.2.2
PROBABILITY ASSESSMENT
ALTERNATIVES-CAPITAL COST ANALYSIS1
\1
11
II
TABLE 18.2.3
[1 PROBABILITY ASSESSMENT
[-1 FUEL COST AND ESCALATION1
I I
Probabi1ity of
['Occurrence 0.25 0.50 0.25
I I
Healy Coal @ Healy (cents/MMBtu)
[1 Year Low Medium ~it1990l.4b 179
(J 1995 146 204 275
2000 146 232 351
2005 146 246 391
2010 146 261 436
Healy Coal @ Nenana (cents/MMBtu)
!]
1990 175 210 249
1995 175 235 310
2000 175 264 387
[1
2005 175 279 425
2010 175 295 467
Bel uga Coal (cents/MMBtu)
lJ 1990 143 176 211
1995 143 200 269
2000 143 227 343
2005 143 241 382
2010 143 256 426
Natural Gas (cents/MMBtu)
1990 300 300 443
l_J
1995 300 327 565
2000 300 480 722
2005 300 530 797
IJ 2010 300 585 880
U Oi 1 (cents/MMBtu)
1990 650 762 890
1995 650 841 1083
2000 650 928 1317
2005 650 1025 1954
2010 650 1132 1605
1 Base prices and escalation patterns derived from Battelle
and Acres meetings and research
II
(1
IilJ
11
I 1lJ
IJ
U
lJ
TABLE 18.2.4
PROBABILITY ASSESSMENT
SUSITNA CAPITAL COST ANALYSIS1
January 1982$
Dam/Size Low Medium High
MW $/kW2 $/kW2 $/kW2
Watana
680 MW 5018/kW 6021/kW 7025/kW
Devil Canyon
600 MW 2265 2718 3171
Probabil ity
of Occurrence 0.60 0.25 0.15
1 Based on the 1280 MW Susitna Project estimate of $5,117 million
2 Includes AFDC and transmission line costs.
Note:Low capital cost is computed as medium divided by 1.20 and
is equal to a zero percent contingency.High capital cost
is computed as the low times 1.4 and represents a double
(40 percent)contingency.
I
1-\
I I
TABLE 18.2.5
I]
I )LONG-TERM COSTS AND PROBABILITY
NON-SUSITNA TREE
(1982 $)Cumula-
i ]Rank $x 106 tiveII(Low to Long-Term Proba-Proba-Expected
High)ro 1 Cost bi 1 ity bi 1 ity LTC2
Il 1 T27 4412 .01 .01
44.12
2 T24 4590 .03 .04 137.70
3 T21 4856 .01 .05 48.56
4 Tl8 5489 .03 .08
164.67
5 Tl5 5661 .09 .17
509.49
6 Tl2 5991 .03 .20 179.73
7 T26 6101 .02 .22
122.02
8 T23 6878 .06 .28 412.68
9 T09 7184 .01 .29 71.84
(\10 T06 7313 .03 .32 219.39
I I
11 T20 7460 .02 .34 149.20_J 12 T03 7624 .01 .35 76.24
II 13 Tl7 7915 .06 .41 474.90
14 Tl4 8238 .18 .59 1482.84
15 T25 8492 .01 .60 84.92
16 T22 8746 .03 .63
262.38
17 Tll 8858 .06 .69
531.48
18 Tl9 9253 .01 .70 92.53
19 Tl6 10321 .03 .73
309.63
20 T08 10503 .02 .75 210.06
21 T13 10637 .09 .84 957.33
22 T05 10859 .06 .90 651.54
23 T10 11272 .03 .93 338.16
24 T02 11569 .02 .95 231.38
25 T07 13742 .01 .96 137.42
26 T04 14194 .03 .99 425.82
II 27 T01 15058 .01 1.00 150.58
T:\J()
I j• I
\-
U 1 Relates to Figure 18.2.1
2 LTC -Long-term Costs.
TABLE 18.2.6
1--]LONG-TERM C05T5 AND PROBABILITY
I I
5U5ITNA TREE
(1982 $)Cumula-
Rank $x 10
6 tive
(Low to Long-Tenn Proba- Proba-Expected
High)ID1 Cost bil ity bi 1 ity LTC 2
1 545 5543 .03 .0300 166.29
2 542 5757 .06 .0900 345.42
3 536 5827 .09 .1800 524.43
4 539 6097 .03 .2100 182.91
5 533 6151 .18 .3900 1107.18
6 544 6437 .0125 .4025 80.46
7 530 6477 .09 .4925 582.93
8 541 6650 .025 .5175 166.25
9 535 6738 .0375 .5555 252.67
10 538 6991 .0125 .5675 87.38
11 532 7062 .075 .6425 529.65
12 527 7087 .006 .6485
42,.52
13 518 7108 .018 .6665 127.94
14 509 7151 .006 .6725 42.91
15 543 7331 .0075 .6800 54.98
16 529 7388 .0375 .7175 277 .05
17 540 7543 .015 .7325 113.15
18 534 7650 .0225 .7550 172.12
19 537 7884 .0075 .7625 59.13
20 531 7974 .045 .8075 358.83
21 526 7986 .0025 .8100 19.96
22 517 8008 .0075 .8175 60.06
23 508 8050 .0025 .8200 20.12
24 524 8326 .012 .8320 99.91
25 515 8347 .036 .8680 300.49
LJ 26 528 8371 .0225 .8905 188.35
27 506 8390 .012 .9025 100.68
28 525 8886 .0015 .9040 13.33
U 29 516 8908 .0045 .9085 40.09
30 507 8951 .0015 .9100 13.43
31 523 9225 .005 .9150 46.12
(J
32 514 9247 .015 .9300 138.70
33 505 9290 .005 .9350 46.45
34 521 9614 .006 .9410 57.68
35 512 9758 .018 .9590 175.64
36 503 9784 .006 .9650 58.70
37 522 10126 .003 .9680 30.38
38 513 10147 .009 .9770 91.32
39 504 10190 .003 .9800 30.57
40 520 10514 .0025 .9825 26.29
TABLE 18.2.6 (Continued)
[I
LONG-TERM COSTS AND PROBABILITY
SUSITNA TREE
(1982 $)CUffiula-
Rank $x 106 tive
(Low to Long-Term Proba- Proba-
Expected
High)10 1 Cost bil ity bil ity LTC 2
[I
( 1 41 Sl1 10658 .0075 .9900 79.94
42 S02 10683 .0025 .9925 26.70
43 S19 11414 .0015 .9940 17.12
44 S10 11558 .0045 .9985 52.01
45 SOl 11584 .0015 1.0000 17.38
1.000
1 Relates to Figure 18.2.2
2 Long-term Costs
!I
U
u
TABLE 18.2.7
NET BENEFIT -CALCULATED VALUE5
Net
Comparison T-ID 5-ID P T-LTC 5-LTC Benefit-
1 T01 501 .0015 15058 11584 3474
("\2 T01 502 .0025 15058 10683 4375Ii3T01503.006 15058 9784 5274
4 T02 504 .003 11569 10190 1379
5 T02 505 .005 11569 9290 2279
6 T02 506 .012 11569 8390 3179
7 T03 507 .0015 7624 8951 (1327)
8 T03 508 .0025 7624 8051 (427)
9 T03 509 .006 7624 7151 473
10 T04 510 .0045 14194 11558 2636
11 T04 511 .0075 14194 10658 3536
12 T04 512 .018 14194 9758 4436
13 T05 513 .009 10859 10147 712
14 T05 514 .015 10859 9247 1612
15 T05 515 .036 10859 8347 2512
16 T06 516 .0045 7313 8908 (1595)
17 T06 517 .0075 7313 8008 (695)
18 T06 518 .018 7313 7108 205
19 T07 519 .0015 13742 11414 2328
20 T07 520 .0025 13742 10514 3228
21 T07 521 .006 13742 9614 4128
22 T08 522 .003 10503 10126 377
23 T08 523 .005 10503 9225 1278
24 T08 524 .012 10503 8326 2177
25 T09 525 .0015 7184 8886 (1702 )
26 T09 526 .0025 7184 7986 (802)
27 T09 527 .006 7184 7087 97
28 T10 528 .0045 11272 8371 2901
29 Tl3 528 .0135 10637 8371 2266
30 T16 528 .0045 10321 8371 1950
31 TlO 529 .0075 11272 7388 3884
32 T13 529 .0225 10637 7388 3249
33 Tl6 529 .0075 10321 7388 2933
34 TlO 530 .018 11272 6477 4795
35 T13 530 .054 10637 6477 4160
36 T16 530 .018 10321 6477 3844
37 Tl1 531 .009 8858 7974 844
38 T14 531 .017 8238 7974 264
39 Tl7 531 .009 7915 7974 (59)
40 Tl1 532 .015 8858 7062 1796
41 Tl4 532 .045 8238 7062 1176
42 T17 532 .015 7915 7062
853
11
I )..I
TABLE 18.2.8
CASE 1 -POSITIVE CORRELATION BETWEEN
ENERGY DEMAND AND PRICES
Conditional Probabilities of Energy Demand
High Medium Low
Load Forecast Load Forecast Load Forecast
High Energy Prices 0.6 0.3 0.1
Medium Energy Prices 0.2 0.6 0.2
Low Energy Prices 0.1 0.3 0.6
TABLE 18.2.9
CASE 2 -NEGATIVE CORRELATION BETWEEN
ENERGY DEMAND AND PRICES
Conditional Probabilities of Energy Demand
TABLE 18.2.10
SUMMARY OF PROBABILITY ASSESSMENT
Case 1 Case 2 Initial Case
positive Negat1ve Zero
Correlation Correlation Correlation
Between Between Between
Energy Pri ces Energy Pri ces Energy Prices
)and Demand and Demand and Demand
I
\
)
Probabil ity that
(a)Thermal plan ;s
more costly than
the Susitna plan 69 percent 91 percent 78 percent
(b)Thermal plan ;s
less costly than
the Sus;tna plan 25 percent 9 percent 16 percent
(c)Thermal and
Sus t tna plans
are equal cost 6 percent o percent 6 percent
\\
LJ
(!
LJ
LOAD
FORECAST
ALTERNATIVE
CAPITAL COST
FUEL COST
ESCALATION
RESULT
10 PROBABILITY
LONG-TERM COST
PRESENT WORTH
.01 $15,058
.01 4,412
.01 7,624
.01 8,492
.01 9,253
.01 7,184
.01 4;856
.01 13,742
.02 11,569
.03 8,746
.18 8,238
.03 10,321
.09 5,661
.06 6,878
.09 10,637
.03 5,991
.06 8,858
.03 4,590
.06 10,859
.02 10,503
.03 1~194
.03 7,313
.02 ~1M
.0-2 -7~460
.03 11,272
2:=1.00
fir ----~...-:~r -~::~~
i,HIGH TOIHIGH .04 MEDIUM Tb2~LOW I03%T04HIGH.20 .60 MEDIUM .12 /
~-,IDS
lOG
I07LOW.04 /lOB-,I09
TlOct'HIGH .12 /-,III%112
11360MEDIUM.60 60 MEDIUM .36 /114-,~Tl5
EE='b LOW .12 /-,
HIGH .04 /Tl9120-,Ix T21
122LOW.20 .60 MEDIUM .12 /
"<.-,123
124
","HIGH T25LOW.04 AD MEDIUM T26"'~LOW T27
FIGuRE 18.2.1-PR08A81L1TY TREE - SYSTEM WITH ALTERNATIVES TO SUSITNA IA~~m I
FIGURE 18.2.2 -PROBABILITY TREE - SYSTEM WITH SUSITNA
RESULT
10
HI/;H -
HIGH 01 7.0 MEDIUM
"''0 LOW.~HIGH .04 .50 MEDIUM 02 /
~-,
LOW 01 /
-,
0 HIGH .03 /'If -,XHIGH20 60
MEDIUM 12 50 MEDIUM .06 /
~-,
'<g LOW .03 /
<,
HIGH .01 /
<,%LOW .04 50 MEDIUM 02 /
"<.-,
LOW 01 /-,
0
'If
HIGH 15 /-,~60 MEDIUM .60 1.0 MEDIUM .60 .50 MEDIUM .3C /
~-,
''b
LOW .15 /
<,
HIGH .O~/
<,%LOW 20 1.0 MEDIUM 20 .50 MEDIUM .10 /
I~-,
HIGH
LOW .05 '%5 MEDIUM
"fa LOW
___-=9,784
10,190
.--9,2~----
•
6,417
6.650
7,650
6.738
5,543
5,827
8.371
6,437
6,151
7.081
7.388
7,331
6.097
5.757
7,543
7.974
7.986
7.062
8.008
7,108
6.991
8,326
8.886
7.884
10,683
11,414
10,514
9,614
LONG-TERM COST
PRESENT WORTH
$11,584
.0060
.0120
,.&060
.0045
.0075
.0025
.0090
.0150
.0030
.0050
.0075
.0015
.0180
.1800
.0450
.0060
.0025
.0025
.0030
.0050
.0360
.0045
.0375
.0900
.0750
.0150
.0600
.0125
.0300
.0125
.0250
.0075
.0900
.0225
.0300
L =1.000
PROBABILITY
.0015
'"'I.Q
511
S03
S04
'"'~
523
S05
5"01)
SI2
S08
S02
SO?
SOl
'"'M
s3.5
S09
S44
Sl3.
SI4
S43
S33
S41
S37
S29
SI5
516
S40
S'36
S26
S31
542
539
532
'"'11
sl8
S19..
'"'W
s21
S38
'"'~
S25
528
S30
S45
527
SUSITNA
CAPITAL
COST
FUEL COST
ESCALATION
ALTERNAT IVE
CAPITAL
COST
LOAD
FORECAST
14
12
10
s:
C
0-
X
c
8c
C,
0-
f!!
.l!I...0o
E 6..
Q)
t-:"enc
oS
4
2
c--=:
r
.J
W-
I
~./
Non-Susitna Plan -~r V/1--1
r -.II
/rl'l.rf ...-.r-V
----rIr
..............
Susitna Plan J,,--,x·.·:-.·:·.·.·.·.·l~jjj~jjjjl~l~
e,
FIGURE 18.2.3 -SUSITNA MULTIVARIATE SENSITIVITY ANALYSIS - LONG-TERM COSTS VS CUMULATIVE PROBABILITY
o .1 .2 .3 .4 .5
Cumulative Probability
.6 .7 .8 .9 1.0
[Ii
1.0
.9
.8
.7
~
:Ei .6to.c'0..a.
Ql .5
.~
to
"S .4E
::Io
.3
.2
.1
'-'--
~-
/
V
/
V
/
.//
/V
/'"
..../V
(4500) (3500) (2500) (1500) (500) 0 500
Net Benefit - $ x 10
6 (1982 $)
1500 2500
3500 4500 5500
FIGURE 18.2.4 -SUSITNA MULTIVARIATE SENSITIVITY ANALYSIS -CUMULATIVE PROBABILITY VS NET BENEFITS •
~~
'-------."
--_.1--31
X.
TRANSMISSION
SYSTEM
AND
EMERGENCY
GENERATION
START
I
I
I
SUMMARY
NOTES
I
I
f
.)
\It
v.
TR ANSFORMATION
ASSESSMENTS
'"*IX.
INITIAL
COMPUTATION
AND
INTERPRETATION
'"
-31
XI.
UPDATE
AND
FEEDBACK
*
--.:JIll"
II.
RISK
LIST
DEVELOPMENT
I
I
I
RISK
LISTS
----'"
~
IV.
RISK
ASSESSMENTS
-,
I
I
ASSESSMENT
DOCUMENTS
,)
~
VII.
CONSEQUENCE
IRESPONSE
CRITERION
ASSESSMENTS,
I
I
DOCUMENTATION
~
~
VIII.
REVIEW
AND
REVISE
XII.
FINAL
COMPUTATION
AND
INTERPRETATION
w
RISK
ANALYSIS
REPORT
~
RISK ANALYSIS STUDY METHODOLOGY
FIGURE 18.25 11~IR I
I"\I
QUESTION:
WHAT MAJOR CONSTRUCTION
PROJECTS ARE INVOLVED '?
WHAT KIND OF WORK IS GOING ON
FOR A GIVEN CONFIGURATION?
WHAT ARE THE POSSIBLE INITIATING
MECHANISMS WHICH COULD INFLUENCE
ESTIMATED COSTS OR COMPLETION TIMES?
WHAT MAJOR PORTIONS OF ANY GIVEN
CONFIGURATION ARE SUBJECT TO
RISK REALIZATION '?
IF A PARTICULAR RISK MAGNITUDE IS
REALIZED,WHAT POSSIBLE
CONSEQUENCES CAN OCCUR?
HOW CAN THESE CONSEQUENCES
BE MEASURED?
WHAT IMPORTANT ASSUMPTIONS AND
LI MITATIONS MUST BE ESTABLISHED
TO PERMIT A REASONABLE ANALYSIS
AND TO DRAW IMPORTANT
CONCLUSIONS?
STUDY ELEMENT:
ELEMENTS OF THE RISK ANALYSIS
FIGURE 18.2.6 111m I
@FOR ANY GIVEN DAMAGE
LEVEL,THREE CRITERION
VALVES ARE ESTIMATED
AND FIT TO A MODIFI ED
BETA DISTRIBUTION.
®IF A RISK EVENT OCCURS,
IT CAN CAUSE A NUMBER
OF POSSIBLE DAMAGE
LEVELS,EACH WITH A
PARTICULAR PROBABI L1TY
OF OCCURENCE.IF
RISK MAGNITUDE ®
OCCURS, THE PROBABILITY
IT WILL CAUSE MODERATE
DAMAGE IS THE VALUE OF®ON THE 0 IAGRAM.
CD A SERIES OF DISCRETE
RISK PROBABILITY LEVELS
EXISTS FOR EACH RISK-
ACTIVITY COMBINATION.
THE ANNUAL PROBABILITY
OF EACH IS DETERMINED.
MODEMIN
INCREASING
OF RISK
PROBABILITY
OF A
PARTICULAR
RISK
MAGNITUDE
t ®
PROBABI L1TY
OF A
PARTICULAR
CRITERION
RISK
PROBABI L1TY
OF A
PARTICULAR
DAMAGE LEVEL
IF A PARTICULAR
RISK
MAGNITUDE
IS REALIZED
!)
I \
INCREASING CRITERION
VALVE
STRUCTURAL RELATIONSHIP FOR HANDLING
RISK ACTIVITY COMBINATIONS,DAMAGE SCENARIOS
AND CRITERION VALUES
FIGURE 18.2.7 [IIR I
.9
C
--
CRITERION VALUE
-
o ' ,
.4
.3
.2
P
.1
1.01
>-!::
....I
£0«
£0oa::a..
.5
P
---~
CRITERION VALUE
.4
o 'I
C
.3
>-I-
~.2
£0«
£0o .Ia::a..
-CRITERION VALUE
I
I
I
I
I
I
I
T IoC
.6
.7
.8
1.0
P I
>-I-
::J
iii«
£0oa::a..
CD CUMULATIVE DISTRIBUTION ®DENSITY FORM ®REVERSE CUMULATIVE
ANY POINT ON THE CURVE
INDICATES THE PROBABILITY
(p)THAT THE CRITERION
VALUE (C)WILL NOT BE
EXCEEDED.
ANY POINT ON THE
CURVE INDICATES THE
PROBABILITY (P)THAT
A PARTICULAR CRITERION
VALUE (C)WILL BE
INCURRED.
ANY POINT ON THE CURVE
INDICATES THE PROBABILITY
(P)THAT THE CRITERION
VALUE (C)WILL BE
EXCEEDED.
ALTERNATIVE FORMATS FOR
PRESENTING THE ANALYTICAL RESULTS
FIGURE 18.2.8 IA~lm I
1.0
0
W
IJ..W .9
OUX
WW .8
(!)t-~O .7
ZZ
W-,~-'.6
W-o..~
t-W .5
«I-W::r:«:::>t-~-'.4
>-t-~t-U>-'W o .3
-t-W
~~ti .2
CD""')U
00-0::0 .1
o..O::Z0..-
0
L__
I
I ~MATEEXPECTED VALUE
90.25%~I
~I
~i ~ROJECT ESTIMATE);/
-:~
I
~=..L<)~"ESTIMATE'
L I
I
I
V I
I
V I
I
I£I
I
70 80 90 100 110 120 130 140
PERCENTAGE OF FINAL DIRECT COST ESTIMATE WITH CONTINGENCIES
CUMULATIVE PROBABILITY DI,STRIBUTION
FOR WATANA PROJECT COST
FIGURE 18.2.9 iiJ
L-L_-c ---I ______I --~
---,_____--.J __--i
ATE
I I
--I
_1 ~JEXPECTED VALUE ~~C"HIGH ESTIM,91.5%~~
I ~PROJECT ESTIMATE)I
L-:I
I
lJ!lB ""tow"ESTIMATE
.L L
/I
I
V I
./I
L I
I
_H~V I
I
...J
...J 1.0
3=W .9I-(!)u>;:!
Oz .8
Uw
U
...Jo.:.7
<!w
:::>0-
I-.6
uO<!wI-.5l-<!<tU:::c:-
1-0 .4Z
>-0 .3I-W
...J W
mU'.2<!~m
01-.1
0.:0
O-Z
60 70 80 90 100 110 120 130
PERCENTAGE OF PROJECT ESTIMATE
CUMULATIVE DISTRIBUTION
OF DEVIL CANYON COSTS
FIGURE 18210 IHlml
j----r---
'---
1.0
.9
C!>
Z .8-0w
.7wo
X Ww::::>.6
I-..J
o ~.5Z
0
l.L WoI-~«>-U
I-0 .3
:i Z- -m .2«m
0 .10::
0..
0
I I ~STIM~TEEXPECTEDVALUE~.
9.06%~./
:1V
:./A =(PROJECT ESTIMATE)
/~
~=''LOW;''ESTI MATE
~
/'I
1
/V II
I
/'II
I
/'II
I
--"II
70 80 90 100 110 120 130 140
PERCENTAGE OF FINAL DIRECT COST ESTIMATE WITH CONTINGENCIES
CUMULATIVE PROBABILITY DISTRIBUTION
FOR SUSITNA HYDROELECTRIC PROJECT
FIGURE 18.2.11
[jj]
L-.-I iL---_~'_.----.J c.,~--~,------'
1.0
.90
1.1...80
0
>-o .70
Zw.::::>w
OU .60WZ
o:::W
1.1..0:0:
W:::::>.50
>8-0~AO
...J
::J
~
:::::>.30'
U
.20
.10
0.9 1.1 1.3 1.5 1.7 1.9 2.1 2.3
RATIO OF ACTUAL COST TO IINITIAL"ESTI MATE·
2.5 2.7 2.9 3.1
HISTORICAL WATER RESOURCES
PROJECT COST PERFORMANCE (48 PROJECTS)
FIGURE 18.ZIZIIRI
,---
1__-'---L.--_~--~'
1.0
.90
IJ...80
0
>-o .70zwwu
::>zOw .60Wo:::
0:::::>
IJ..U
U .50wo>
ti .40
-J::>
~.30::>
U
.20
.10
FIGURE 18.2J31'~IRI
0.9 1.1 1.3 1.5 1.7 1.9 2.1 2.3
RATIO OF ACTUAL COST TO IIINITIAL"ESTIMATE
COMPARISON OF SUSITNA RISK RESULTS WITH
HISTORICAL WATER RESOURCES PROJECT
COST PERFORMANCE (48 PROJECT)
2.5 2.7 2.9 3.1
L-_~~~L __
C)I .9Z
fil-I LL .81IJ(/)0~~I1IJ;:)~-.7
(/)\Z~I-1IJ 1IJ ~00::;:)0
Z 0-.6~11IJ1IJu,(/).0::U
00::\LL@ .5
>-«1IJ0::
f-Z\>0::::J f--;:)_-f-U£O(/)«U
~~\SO
0-~
0::I ;:)a-U
RATIO OF ACTUAL COST TO "INITIA~'ESTIMATE
COMPARISON OF SUSITNA RISK RESULTS WITH
HISTORICAL DATA FOR PROJECTS WITH 10 OR
MORE YEARS BETWEEN"INITIA~'ESTIMATE
AND COMPLETION
FIGURE 18.214 IRIR I
,.---
I
2.32.11.91.71.51.3
o_~~_
.8
.91 I I I I I I I I I I I..,....,..
u,o
>--7U«.
~~::>0 .6
0-
WW
ll:Uu..zW
wll:>ll:.4
-::>ti u
..JU::>0
:2::>
U
~I
~-,~~,x(/)w~«I-zf0«
z~
u...(/)IOll:
>-«I-zi:JI-m(/)
«::>1m(/)
0-
ll:a.I
RATIO OF ACTUAL COST TO IIINITIALII ESTIMATE
COMPARISON Of SUSITNA RISK ANALYSIS RESULTS
WITH HISTORICAL DATA FOR DAMS AND RESERVOIRS
FIGURE 18.2.15 I~~IR I
~~
-/->
----.._---:
)~=SCHEDULE ESTIMATE
/INCLUDING A ONE YEAR
CONTINGENCY
/V
-:
/
,/'
~B=SCHEDULE ESTIMATE
WITHOUT CONTINGENCY~.I
1.0
.9
(!)zz .8
W
W~.7
ww::::>s -I .6
Z~
LL.0 .5
Ow
~~.4_0
-1-_0
£D Z '2.«_.oJ
£Dog:.2
.1
o
,-'---
-15 -10 -5 o 5 10 15 20
MONTHS FROM SCHEDULED COMPLETION
WATANA SCHEDULE DISTRIBUTION
EXCLUSIVE OF REGULATORY RISKS
FIGURE 18.2.161111 I
.1
.6
.7
1.0
.9
.8
(!)z
owwox
Ww
t-3 .5
O~z:::>
LL 0 .4
Ow
>-~.3t-O:JC5
iii Z .2«-
00
~
Q.
o
~....-_.
-
~
.>,..,-
/'~
.J·~SCHEDULE ESTIMATE-:INCLUDING A ONE YEAR
CONTINGENCY
JV .
/B=SCHEDULE ESTIMATE
WITHOUT CONTINGENCY
/~
/
-"V
-30 -20 -10 o 10 20 30 40
MONTHS FROM SCHEDULED COMPLETION
WATANA SCHEDULE DISTRIBUTION
INCLUDING THE EFFECT OF REGULATORY RISKS
FIGURE 18.2J7II~lm I
1.0
C>
Z
.99-0
w~w«UwX>-w
.98~
I-W
OQ.z
lJ..cnO~.970>-1-0
...JW
m~.96«Um_
Oo
~z
Q.-
_.--------------"...--.....~1.--"'.....
c:>C:>'".............
yO"".~\oy~~v·r-<,.0 /'~EXPECTED VALUES:/0\0
/,,0 TOTAL LOSS 0.06961
I /50%REDUCTION 0.09171//
if IIANCHORAGE
V
f
o 2 3 4 5 6 7 8
DAYS PER YEAR OF REDUCED ENERGY DELIVERY
CUMULATIVE PROBABILITY
DISTRIBUTION FOR DAYS OF REDUCED
ENERGY DELIVERY TO ANCHORAGE
FIGURE 18.2.18 IMlml
1.0
C>
Z
0WWO::.99U<iXW
W>-
1-0::OWZo..98
lJ..cn
O~
>-0
1-0 .97
~W
ml-
<i<i
mU
0 0 .96O::z0._
/~
.:~
/EXPECTED VALUE:.08116
/I I
FAIRBANKS
I
f
o 2 3 4 5 6 7 8
DAYS PER YEAR WITH NO ENERGY DELIVERY
CUMULATIVE PROBABILITY DISTRIBUTION
FOR DAYS PER YEAR WITH NO SUSITNA
ENERGY DELIVERY TO FAIRBANKS
FIGURE 18.2J9IA~IR I
18.3 -Marketing
Introduction
This section presents an assessment of the market in the Railbelt region for the
energy and capacity of the Susitna hydroelectric development.Arange of rates
at which this could be priced in the year of first power and the price in
succeeding years is also considered as well as a basis for contracting for
supply of Susitna energy.
(a)The Railbelt Power System
It is necessary to consider first the basic characteristics of the Railbelt
region electric power demand and supply, load resource analysis for the
period during which Watana and Devil Canyon come into operation in 1993 and
2002 respectively.
The power system to which Susitna capacity and energy would be delivered is
defined as the Railbelt Region interconnected system which will result from
the linking of the Anchorage and Fairbanks systems through a transmission
intertie to be completed in the mid-1980s.
II
'i I
(...)
(i)Delineation of Region
The Railbelt Region covers the Anchorage-Cook Inlet area,the
Fairbanks-Tanana Valley area and the Glennallen-Valdez area as
shown in Figure 18.3.1.The utilities,military installations and
university for which electric generating facilities are included in
this report are listed in Table 18.3.1.The approximate location of
service areas of these utilities are shown in Figure 18.3.2 and the
generating plants servicing the region are listed in Table 18.3.3.
-Anchorage-Cook Inlet Area
There are five electric utility companies in the Anchorage-Cook
Inlet area.The two largest are Anchorage Municipal Light and
Power (AMLP)which serves the Anchorage municipal area and Chugach
Electric Association (CEA),serving the Anchorage suburban and
surrounding rural areas.Homer Electric Association (HEA)serves
the western portion of the Kenai Peninsula,including Seldovia,
across the bay from Homer.Matanuska Electric Association (MEA)
serves the town of Palmer and the surrounding rural area in the
Matanuska and Susitna Valleys.Seward Electric System (SES)
serves the city of Seward.Alaska Power Administration operates
the Eklutna hydroelectric plant and markets wholesale power to
CEA,AMLP and MEA.Chugach Electric Association also provides
power at wholesale rates to HEA,SES and MEA.
18-50
There are also two major national defense installations in the
Anchorage area:Elmendorf Air Force Base and Fort Richardson.
- Glenallen-Valdez Area
1 U.S.Department of the Army,Corps of Engineers, "South-Central Railbelt
Area, Alaska,Upper Susitna River Basin,Supplemental Feasibility Repor-t",
Appendix -Part II,Section G Marketability Analysis,February 1979.
-Fairbanks-Tanana Valley Area
There are two electric utility companies in the Fairbanks-Tanana
Valley area.Fairbanks Municipal Utilities System (FMUS)serves
the Fairbanks municipal area,and Golden Valley Electric
Association (GVEA)serves the rural areas.The University of
Alaska at Fairbanks owns and operates an electric generating plant
and its capacity is included in this report.The other generating
facilities in the area are those at three major national defense
installations:Eilson Air Force,Fort Greeley and Fort
Wainwright.Clear Air Force Base,which is not interconnected
with any local utf l-i ty ,is not included.
i}
There is only one e1ectri c uti 1 ity company in the Gl ena11 en-Val dez
area,the Copper Valley Electric Association (CVEA).
Ownership
The Railbelt Region is presently served by nine major utility
systems. Five are rural electric cooperatives,three are munici-
pally owned and operated,and one is a federal wholesaler.In 1980
the rural electric cooperatives supplied 70 percent of total net
energy generated by the Railbelt util i ti es,the muni cipal systems 23
perc:ent .a.11(LJh§!8l~~ka .Power8dmi nistra.:ttOJLL_p_el"centJsee Etgu~e~--
18:J.4a).Wholesale energy supply represented 28 percent of total
net generation.
(i 1)
The total nameplate generating capacity for each of the utilities,
military installations and the university in the Railbelt Region is
given in Table 18.3.1.The rural electric cooperatives own 58
percent of total generating capacity,the municipal systems 27
percent,national defense organizations 10 percent,the Alaska Power
···-------Admfni-stration-3--percent-an-d-th-e-Urri vers ftyof-Al a slfa atF a ir6an~2
----------pereent-(-see-F-i-gure--l-8.-3.4b-)~.~fhe-1980-net-energy-g~mE:r-atiOh-from -
each of the utilities is provided in Table 18.3.1.
Although national defense installations have represented a major
portion of the total installed capacity in the past,they now
constitute only 10 percent of the total in the Railbelt Region.It
is expected that the national defense install ati on will become a
less significant part of the total generating capacity,with the
projected stability of military sites and the relative growth of the
ut il i ties•1
IIII
J
There are three industrial plants in the Kenai Peninsula that
operate their own power plants:Union 76 Chemical Division Plant,
Kenai Liquified Natural Gas Plant and Tesoro Refinery Plant.These
plants are connected to the HEA system and are buying either energy
or standby capacity from HEA to supplement their own generation in
meeting their needs.There are other self-supplied industrial
generators including oil platform and pipeline terminal facilities
in the Cook Inlet area.
In general,industries own and operate generating facilities only
for their own use.They were not included in this analysis.
(iii)Types of Fuel
The net energy generated by the Railbelt utilities by types of fuel
is shown in Figure 18.3.4c.As shown in this figure,76 percent of
the total net energy generated in 1980 was based on natural gas,12
percent on coal,2 percent on oil and 10 percent from hydroelectric
plants.
The relative mix of the generating capacity of the Railbelt utili-
ties by type of generating capacity is shown in Figure 18.3.4d.
Most of the generating capacity (55 percent)is powered by simple
cycle gas or oil-fired combustion turbines.
(iv)Existing Power Sales
In the Anchorage-Cook Inlet area the two major wholesalers of
electricity are Alaska Power Administration,operating the Eklutna
hydroelectric project,and CEA.In 1980 the Alaska Power
Administration sold a total of 180,376 MWh made up of deliveries to
CEA,57,717 MWh;AMLP,90,854 MWh and MEA,31,805 MWh.CEA sold a
total of 550,548 MWh made up of deliveries to HEA,287,966 MWh;MEA,
236,209 MWh and SES,26,373 MWh,in 1980.In the same year AMLP
sold 10 MWh to Elmendorf Air Force Base.
The 1980 energy sales by each of the Railbelt utilities are stated
by category of customer (Table 18.3.1).The Anchorage-Cook Inlet
area had an 81 percent share of the total electricity sales in the
Railbelt Region,the Fairbanks-Tanana Valley area 17 percent and the
Glenallen-Valdez Valley area 2 percent.
(v)Transmission System
The existing transmission systems in the Railbelt Region are
indicated on Figure 18.3.2.In the Anchorage-Cook Inlet area the
utilities are at present loosely interconnected through facilities
of Alaska Power Administration and the CEA.CEA has intercon-
nections with MEA,HEA,SES and Eklutna.AMLP has an emergency 20
MW connection to Elmendorf Air Force Base.
18-52
In the Fairbanks-Tanana Valley area,CVEA has interconnections with
FMUS,Fort Wainwright,Eilson Air Force Base and the University of
Alaska.The CVEA serves both Glenallen and Valdez.
(vi)Power Exchanges and Interchange Contracts
The 1980 energy transfers between utilities in the Railbelt Region
are summarized in Table 18.3.3.As discussed earlier,the
main deliveries of electricity were made within the Anchorage-Cook
Inlet area.At present,the Anchorage-Cook Inlet and the Fairbanks-
Tanana Valley areas operate independently.The existing
transmi ssi on system between Anchorage and Will ow consi sts of a
network of 115 kV and 138 kV lines with interconnection at Palmer.
Fairbanks is primarily served by a 138 kV line from the 28 MW coal-
fired plant at Healy.Communities between Willow and Healy are
served by local distribution.
In 1980,28 percent of the total supply was purchased under
wholesale interutility arrangements. At present there are power
sales agreements between the following utilities:
(1)Alaska Power Administration and CEA,AMLP,MEA,and
(2)CEA and HEA,Matanuska Electric Association,and
(3)GVEA and the University of Alaska.
SES and HEA have long-term purchase contracts wi th CEA Lo_r _
---------n6n;,.emer-g-encjpower-supplles.The coordination of area power
exchange between systems is,at present,not formalized and takes
the form of 1mutual assistance and unstructured interchange
agreements.
The power sales contracts between the Alaska Power Administration
and the utilities are in pursuance of the Act of Congress approved
July 13,1950 (48.U.S.C.Section 312-312d)and all amendments and
(vii)Anchorage and Fairbanks Interconnection
It is considered likely that an electrical interconnection between
Anchorage and Fairbanks will be established before the Susitna
project comes into operation.The intertie has been found to be
1 The 1976 Alaska Power Survey,Volume I,FERC.
feasible 1 and its operation will result in significant economic
benefi ts to both areas.The recommended constructi on pl an will
involve the following steps:
(1 )
(2 )
(3)
(4)
(5)
Construct approximately 160 mile~of new transmission line
designed for future operation at 345 kV.
Add 138 kV circuit breakers at Healy,Willow and Teeland
sub-stations.
Add a new 138/24 kV transformer at Willow sub-station along
with a 138 kV connection.
Possibly add a 138 kV voltage regulating transformer at Point
Mackenzie sub-station if studies in preparation for design show
a need for it.
Install approximately 70 MVAR of switched capacitors to control
voltage across the interconnection.
-j
'I
(vii i)
The interconnection will allow a transfer of power between Anchorage
and Fairbanks in capacity up to approximately 70 MW in either
direction.It will provide opportunity for the economy interchange
of energy from Anchorage to the Fairbanks area.An average of
260,000 MWh per year from 1984 to 1993 can be exchanged.The
intertie will result in an estimated reserve sharing starting from
18 MW as early as 1985 to a maximum of 135 MW in 1994.
The proposed plan of interconnection includes provisions for a
future operating voltage of 345 kV that allows for integrating the
new line into the future transmission facilities for Susitna or
other regional generation source. Transmission facilities with
respect to Susitna project are discussed in further detail in
Chapter 12 of the Feasibility Report.
~mpacts of the Interconnection
In the feasibility study of the Anchorage-Fairbanks electrical
interconnection,it has been indicated that with the tie-line no
additional generating capacity will be required in the Fairbanks
area before 1993, but the Anchorage area may require approximately
120 MW of additional capacity by that time.The Anchorage and
Fairbanks systems however will require additional thermal generating
capacity,even with the tie-line in service,if Susitna is not
built.
It was also found in the interconnection study that,if the Susitna
project and its associated transmission facilities are placed in
service in 1994,the Susitna transmission will interconnect the
Anchorage and Fairbanks areas and greatly increase the transfer
capability between the areas.
1 Engineering Report R-2274,May 1981 Gilbert/Commonwealth
18-54
1
\
I
t
J
j
i
f
·-t
}
.t
....~
1
'r
(b)Regional Electric Power Demand and Supply
(i)Socioeconomic Conditions
The Railbelt Region,as shown in Figure 18.3.1,includes Anchorage,
Fairbanks, the Kenai Peninsula,and the Valdez-Glennallen area.The
1980 Railbelt population was 284,822 comprising 72 percent of the
state's population of 400,142 (U.S.Bureau of Census).Anchorage is
the Railbelt's major urban center with 61 percent of the total
regional population.Fairbanks,with 19 percent of the total,
represents the next major population center.Major industries in
the Railbelt include fisheries,petroleum, timber,agriculture,
construction,tourism,and transportation.Development of Alaska's
natural resources represents current and potential economic activity
(Alaska Department of Commerce and Economic Development,1978).The
Federal Government provides employment in both the military and
civilian sectors,although these sectors are presently declining.A
review of the socioeconomic scenarios upon which forecasts of
electric power demand were based is presented in Chapter 5 of the
Feasibility Report.
(ii )El ectri c.:Power Demand
Demand in terms of electric energy and peak load in the Railbelt
Region for the period 1980-2010 has been presented in detail in
Section 5 of the Feasibility Report.The forecasts adopted in this
report are the mid-range levels presented by Battelle Northwest in
December 1981.Subsequent forecasts which introduce price/demand
el asti ci ty consi derati oJls-.b_ay_e__not__b_e.eJL_US_ed_at_thts--s_tage .•....Ihe---~'-
----..-relatively wide range of demand scenarios associated with price-
dependent sales of electrical energy in the Railbelt deserve
particular consideration later.
The results of studies reported in Section 5 of the Feasibility
Report call for Watana to come into operation in 1993 and deliver a
full year's energy generation in 1994.Devil Canyon would come into
operation in 2002 and deliver a full year's energy in 2003.Figure
··-··----18.-3-;-4-shows--the-mi-d:;;ran-ge-r<H'e-casrof-energyaemana correspondfilg--··
---------te-medera-te-growth--and--the-en-ergy-outputs-p1-ann'ed-fr'om-the-Sa-s-i-tn-a-~'-'
hydroelectric development.
(c)Market and Price for Watana Output in 1994
In this assessment of the market for energy output from Susitna energy in[
.1994jtwilL be assumed initially that this energy will be supplied at a
single wholesale rate on a free market basis,that is QJLthe basis that no
utiLity hasaTlY obligation to purchase but will choose to do so on grounds
of the single wholesale price set for Susitna energy compared with other
alternatives.It should be noted that these marketing conditions,and in
particular the single wholesale rate,constitute a very exacting market,.!,
for they preclude the possibility of securing markets by discriminatory
pricing or of long-term contracts based on concessionary prices.In effect
.~
LJ
these marketing conditions require that all Susitna energy is based on a
wholesale price which is attractive even to the utility with the lowest
cost alternative source of energy.
(i)Organizational and Contractual
Preconditions for Susitna Energy Sales
Optimum economic operation of Watana and Devil Canyon hydroelectric
plants require that they are operated as close as possible to full
capacity.This is because of the inherent characteristics of hydro
power developments which resul t in effectively zero incremental cost
of additional energy when the facilities are operating at less than
full capacity.If it is determined,therefore,that Susitna is to
proceed it will be most important,in terms of obtaining the least-
cost energy system in the Railbelt,to plan for the introduction of
Watana as an operating plant in a systematic and orderly manner.
Specifically,the APA and the Railbelt utilities should consult on
any significant additions to the system capacity which the utilities
might consider in the years prior to Watana coming on-stream in 1993
and Devil Canyon in Z002 to avoid costly duplication of facilities
and consequent "over building"of capacity.
The APA should also commence power contract negotiations with the
four major electric utilities (CEA,AMPL,FMUS and GVEA)for the
output of Susitna as soon as any decision in principle is reached to
proceed with Susitna.Given that the utilities are wholly indepen-
dent,it must be expected that they will bargain for costs no higher
than the cost of energy from the best thermal option available to
them.It is on this assumption that the marketing plan given below
is developed.It is essential,however,that appropriate contracts
are established between the APA and the major utilities as a pre-
condition for the actual commencement of Susitna.The reasons for
thlS are firstly,that such contracts will be required (see Section
18.4) to support bond issues required to fund the construction of
the project and are,therefore,a precondition of Susitna financing.
Secondly such precontract would be necessary and desirable if
equitable terms were to be arrived at.If the contractual negotia-
tions were left until construction was substantially underway,the
contractual bargaining would be on a most unequal basis,given that
Susitna would then be virtually a "trapped"resource with no
alternative markets other than that provided by the Railbelt
utilities.
Subject to tax considerations noted in Section 18.4,power supply
contracts,entered into as a precondition of proceeding with
Susitna,should also be on the basis of utilities taking whole
blocks of energy long term at a price which is the lesser of either
the cost of energy from the best thermal option (as developed below)
or the APA wholesale rate,as laid down by Senate Bill 25.The
ceiling set by the best thermal option cost should also be consid-
ered over a period of years so that,for example,the maximum price
charged for Susitna energy over ten years might be the average price
18-56
The marketing position for Watana Stage I in 1994 is setout in
Figure 18.3.5.The basis of the figure is first the incremental
costs {i.e.,cost over and above those already incurred by way of
....____._.__.c aR italil]ve.s.tI!Leflt.OJL the_sy.stem_by_theeal".ly-19.80..'..s.)-thatwould
result if the best thermal option to Susitna were chosen.The major
incremental cost woul d ari se from the 400 MW Bel uga coal fi red
thermal power stati on produci ng 2554 GWh it11994.Si flee thi s waul d
be new capacity its whole cost (capital investment, fuel and O&M)
would be added to that for the overall system.The rest of the
generating plant required to meet the 1994 demand,primarily
combined cycle and gas turbines and all already installed,would
involve incremental costs equal only to fuel and O&M cost of this
Figure 18.3.5 shows,on the far right of the figure,the area in
which costs of the best thermal and the Susitna options are common
and ari se from pl ant required in both system confi gurati ons to
meet the full generating requirements of 1994.Watana,coming
on-stream at that time waul d effecti vely II avoid"all costs repre-
sented by the shaded area.These costsdi vided by the Watana output
of 3387 GWh gives a whol esal e energy rate of approximately 145
mills/kWh (in 1994 dollars)which is the maximum which could be
charged if'consumers were to be neither better nor worse off in 1994
by the decision to proceed with Susitna,rather than the best
thermal option.This confirms the estimate of 148 mills/kWh which
is produced by the more detailed OGP.5 analysis,the results of
which are given in Figure 18.3.6.
18-57
t
J
!
,!
r··
1
I
(iii)The Entry Price Problem
The entry price problem for Watana in 1993 (as for Devil Canyon
later)arises because its wholesale energy rate must be competitive
not only with the cost of the best thermal option (i.e.,the 145
mills/kWh above)but also with the avoided operating costs of all
supplied by existing equipment and this situation would continue
until such time as the equipment is retired and becomes due for
replacement or until the system needs additional capacity.
Unless appropriate measures are taken therefore,the entry price of
Watana might be constrained by the need to make it competitive with
the lowest significant block of avoided cost arising from existing
capacity.This could give rise to a situation in which the pricing
policy,which maximized revenue from Watana,was not to reduce its
wholesale price to a point at which all of its output was sold,but
maintain a higher price and "spi ll" the unsold energy.Such a
policy,while it might be effective in terms of increasing the
operating revenues of Watana,evidently would not be eff~cient for
the system as a whole.The system would incur operating costs of
around 70-80 mills/kWh for even the least-cost thermal energy while
Watana is "spt ll tnq''energy which would cost virtually nothing to
supply.It would therefore be far cheaper for the system to use the
Watana energy rather than operate any of the thermal sources still
avail ab1 e.
This entry price problem could be resolved in a number of ways to
achieve the lowest possible cost for the system as a whole.It
should in large measure be avoided by the pre-contract arrangements
described in (c)(i)above.Under such contracts the major
utilities would agree to take the Watana output in contracted-for
blocks of energy at an average price of 145 mills/kWh in 1994 rather
than to take whatever amount minimized their costs on a year-to-year
basis,regardless of the cost to the system as a whole.It would be
realistic for the major utilities to accept pre-contract arrange-
ments on this basis as the system will clearly require substantial
additions to generating capacity involving heavy investment in the
early nineties and this,as shown above, will bring the cost up to
145 mills/kWh.Under such block purchase pre-contract arrangements,
utilities would effectively be in a IItake-or-pay"position under
which it would be more economic for them to avoid using existing
capacity on an operating cost-only basis.
The second solution to the entry price problem,(which would be
supplementary to the block pre-contract arrangements and not a
substitute),would directly address the underlying cause of the
problem.This is that the single wholesale rate obliges the Susitna
output to be sold on the basis of an average price which takes no
recognition of the basic fact that,as long as there is any of the
hydroelectric capacity unused,its incremental cost is virtually
zero.This situation could be remedied by a two-part tariff system
18-58
After its initial entry into the market in 1994 the price and market for
the 3387 MWh of Watana output is consistently upheld over the years up to
2001 by the 20 percent increase in total demand over this period,and the
70 percent increase in cost savings which this output is providing compared
with the cost of the best thermal option.These savings per unit of output
are shown in Figure 18.3.6 and are,as noted above, derived from the OGP5
analysis.The very substantial increase in the costsav;ngs per unit of
Watana output_which occurs in the latter half of the 1990s reflects the
fact that,but for this hydroelectric plant,it would have been necessary
to bring on a further 200 MW coal station at Nenana in 1996.Another major
influence on the cost savings arising from Watana over this period is the
rapidly escalating cost of natural gas as existing contracts are renegoti-
ated.This rising curve of cost savings attributable to the Watana output
therefore again represents the maximum price at which the output cou]A~~~
-~-marketed-if-,-within~the co-nstr-crirft or-tl1esi ngl e wnol esare energy rate
system,it was possible for Watana to recapture the whole of the savings
which it confers on the system compared with the best thermal option.
Devil Canyon comes on-stream in the year 2002,but its first full year of
_________-nor-ma~-costl-ng-i·sZ003-and-i-t-~i-s-w-i·th-reference-to--thi-s-ye-ar~that~we--------
______=co~n=s i de.Lthe_p.r..ic.in-g_and_ma.r-ke.t-i-ng-pr-oblems-i-nvo-l-ved-i-A-se~~l~i-ng-the--
additional 2450 GWh made available and usable on the Railbelt system.
A diagramatic analysis of the total cost savings which the combined Watana
and Devil Canyon output will confer on the system in the year 2003 compared
with the best thermal option is shown in Figure 18.3.7.By this year,
un~er~~e ~h~rmalop~i()11,th~<:os1:s()f1:.hesys:t.em would have beendominated
by the three 200 MW coal plants completed in the years 1994 and 1996.The
c1iCigram shows the total_savings brought about by the usableoutputfroll1
Susitna in this year.Again,dividing these total savings by the energy
contributed by Susitna we arrive at the 250 mills/kWh price which
represents the maximum price which can be charged for Susitna output on a
basis that enabled the project to recapture the whole of the savings which
it confers on the system compared with the best thermal option.
(d)
(e)
with a demand charge and incrementally-priced energy supplied at
less than the operating cost of the existing equipment.This would
encourage utilities to absorb the maximum amount of the Watana
output,thus minimizing the cost to the system as a whole.
It is recognized that there may be grounds for opposing multi-part
tariff systems as possibly discriminating unfairly against parti-
cular categories of consumer.It should nevertheless be possible in
the context of the Railbelt system, as it will exist in 1994, to
devise a tariff which could be fairly and generally applied even if
only on an interim basis.
Market and Price for Watana
Output 1995 -2001
Market and Price for Watana and
Devil Canyon Output in 2003
t
)
..L··
j r,i
Again,the practical marketing problem which would need to be resolved in
the year 2003 is that of making the entry price of Susitna energy competi-
tive,not merely with the best thermal option,but also immediately
competitive with the actual combined cycle,gas turbines,plants,etc.,
which the additional output from Devil Canyon will displace.It is this
capacity (combined with the output of Watana and other hydroelectric
plants)that will have been supplying the whole Railbelt energy demand in
the years immediately preceding the start-up of Devil Canyon.It could
therefore still be available as an alternative power generating mode open
to the utilities wherever this is more economical than paying the single
wholesale rate charged for Susitna.
If the wholesale rate charged for Susitna would be at the 250 mills/kWh
1evel (designed to recapture wholly the savi ngs conferred by the project in
that year)it will be seen from Figure 18.3.7 that it would be more
economical for some utilities to keep in operation part of the combined
cycle and gas turbine generating capacity since their operating costs would
be considerably less than the 250 mills.This is expected however to be
only a relatively short term problem,one reason beirg that some of these
remaining facilities will be approaching retirement.At that time new
capital costs would need to be incurred for generation expansion and this
would clearly render much of this plant uneconomic given the option of a
supply from Susitna at a cost of 250 mills/kWh (in 2003).As in the case
of Watana in 1993-94 a block sale arrangement or a multi-part tariff might
be used as a temporary measure to guide the system to the least overall
cost generating plan.
It is also probable that by 2003 the Railbelt electrical supply system
(which will be about one-third larger than in 1994)will have developed an
appropri ate i nsti tuti onal structure to ensure that overall costs are
minimized.It might reasonably be assumed that rationalization of the
power supply function in the Railbelt area would lead to a demand for all
available and usable energy from Susitna since its incremental cost is
vi rtually zero.
Only about 90 percent of the total energy output of Susitna will be
absorbed by the system in 2002;the remaining output would be progressively
picked up over the following decade or so. This will provide increasing
total savings to the system from Susitna for no increase in operating costs
and thus progressively reduce the cost per unit of the Susitna output.
This,combined with the continuing escalation in the cost of thermal fuel,
will again progressively consolidate the market position of the project and
make Susitna the central element in the system.
1 It is also probable that,at this stage,some combined-cycle generating
capacity will be required for standby purposes given that hydroelectric plants
in these early years of the century,will account for almost all the system
needs.How such standby capacity is factored into the system will depend upon
the institutional arrangements at that time for the ownership of generating
capacity,and the distribution network.
18-60
(f)
(g)
Potential Impact of State Appropriations Reducing The
Cost of Susitna Energy Below The Best Thermal Option
In the preceding analysis we have identified the maximum prices at which
the Susitna energy could be sold.Whether or not the energy is sold at
these prices will depend upon the magnitude of any possible appropriation
designed to reduce the cost of Susitna energy in the earlier years when,
without such appropriations,it would be more expensive than energy from
the best thermal option.The demand forecasts used to analyze the market
for Susitna energy in the preceding sections have been based on the assump-
tion that the policy of "full cost"pricing obtains for electrical energy.
At significantly lower prices and on the basis of the unit elasticity of
demand estimated by Battelle,the total system demand could be substantial-
ly higher than assumed.It is nevertheless possible that the state
appropriation of funds for the project might be of a magnitude (see Section
18.4)that the Susitna energy would be supplied at a price materially below
that of the best thermal option.If this were the case then it would
evidently make it correspondingly easier to market the output from Watana
and Devil Canyon.As the preceding analysis shows,however,a viable and
strengthening market exists for the energy from these two facilities even
where they are priced up to the full cost that it would be possible to
charge for the best thermal option.
Conclusions
Based on the assessment of the market for power and energy output from the
Susitna hydroelectric project it has been concluded that,with the
appropriate level of state appropriation and with pricing as defined in
Senate Bill 25,an attractive basis exists,particularly in the long term,
~__foJ~_~the_Ra_Llbe]~t~uti-l i-tiesc~to-der-i-ve--benef+t-from--the-project;~~tt-shou-l-d~---
be recognized that contractual arrangements covering purchase of Susitna
ouput will be an essential pre-condition for the actual commencement of
pr-oj ettconstructi on.
)
J
,)
~
j
'r
-._-_/
Generating Purchases Utility Annual
Capacity 1981 Predominant Tax Status Wholesale Provides Energy Demand
MWat O°F Type of Re: IRS Electrical Wholesale 1980
UTILITY Rating Generation Section 103 Energy Supply GWh
IN ANCHORAGE-COOK INLET AREA
Anchorage Municipal Light and Power 221.6 SCCT Exempt *-585.8
Chugach Electric Association 395.1 SCCT Non-Exempt **941.3
Matanuska Electric Association 0.9 Diesel Non-Exempt *-268.0
Homer Electric Association 2.6 Diesel Non-Exempt *-284.8
Seward Electric System 5.5 Diesel Non-Exempt *-26.4
Alaska Power Administration 30.0 Hydro Non-Exempt -*-
National Defense 58.8 ST Non-Exempt ---
Industrial - Kenai 25.0 SCCT Non-Exempt ---
IN FAIRBANKS - TANANA VALLEY
Fairbanks Municipal Utility System 1 68.5 ST/Diesel Exempt --116.7
Golden Valley Electric Association 1 221.6 SCCTIDiesel Non-Exempt --316.7
University of Alaska 18.6 ST Non-Exempt ---
National Defense1 46.5 ST Non-Exempt ---
IN GLENALLEN/VALDEZ AREA
Copper Valley Electric Association 19.6 SCCT Non-Exempt --37.4
TOTAL 1114.3 2577.1
1Pooling Arrangements in Force
TABLE1B.3.1- RAILBELT UTIL1TIES PROVIDING MAR KET POTENTIA L IA~IR I
),...--.~--
NET GENERATION (1980 - MWh)
Rural Alaska Generation
Electric Municipal Power for
Cooperatives Systems Adm inistration Total Wholesale
ANCHORAGE-COOK INLET AREA
Alaska Power Administration 184,285 184,285 184,285
Anchorage Municipal Light &Power 493,531 493,531
Chugach Electric Association 1,444,104 1,444,104 550,548
Homer Electric Association
1)-
Matanuska Electric Association 2)-
Seward Electric System 3)-
FAIRBANKS-TANANA VALLEY AREA
Fairbanks Municipal Utilities System 116,685 116,685
Golden Valley Electric Association 316,705 316,705 2,453
GLENNALLEN-VALDEZ AREA
Copper Valley Electric Association 43,982
TOTAL
MWh 1,794,791 610,216 184,285 2,589,292 737,286
Percent 70 23 7 100 28
1) Homer Electric Association purchased its energy from Chugach Electric Association,284,810 MWh in 1980.
2) Matanuska Electric Association purchased its energy from Alaska Power Administration and Chugach Electric Association,31,805 MWh and
236,208.7 MWh respectively in 1980.
3) Seward Electric System received most of its energy from Chugach Electric Association 26,373.6 MWhin 1980.
Sources: Based on data from US Department of Energy, FPC Form No. 12,1980..
TABLE 18.3.2 -ENERGY SUPPLY FROM RAI LBELT UTI LOTIES 111m I
PLANT LIST
(,
I I
PLANT TYPE OF
No.NAMEOF PLANT UTILITY OWNERSHIP
2 Anchorage No. 1 Anchorage Municipal Light and Power Municipal
I ',3 Anchorage Anchorage Municipal Light and Power
Municipal
i I 6 Eklutna Alaska Power Administration Federal
7 Chena Fairbanks Municipal Utilities System Municipal
10 Knik Arm Chugach Electric Association, Inc.
Cooperative
22 Elmendorf-West United States Air Force
Federal
23 Fairbanks Golden Valley Electric Association, Inc.Cooperative
32 Cooper Lake Chugach Electric Association, Inc.Cooperative
34 Elmendorf-East United States Air Force Federal
35 Ft. Richardson United States Army Federal
36 Ft. Wainright United States Air Force Federal
37 Eilson United States Air Force Federal
38 Ft. Greeley United States Army Federal
47 Bernice Lake Chugach Electric Association,Inc.Cooperative
55 International Station Chugach Electric Association,Inc.Cooperative
58 Healy Golden Valley Electric Association, Inc.Cooperative
59 Beluga Chugach Electric Association,Inc.Cooperative
75 Clear AFB United States Air Force Federal
80 Collier-Kenai Collier-Kenai Municipal
81 Eyak Cordova Public Utilities Municipal
82 North Pole Golden Valley Electric Association, Inc.Cooperative
83 Valdez Golden Valley Electric Association, Inc.Cooperative
84 Glennallen Golden Valley Electric Association, Inc.Cooperative
TABLE 18.3.3 - LIST OF GENERATING PLANTS SUPPLYING RAILBELT REGION IA~lm I
)
I.:
II
65
65
\
\
\
Tanana
LOCATION MAP
LEGEND
\f PROPOSED
DAM SITES
----PROPOSED 138 KV UNe:
-EXISTING I.INES
F'GURE 18.3.2 -SERVICE AREAS OF RAILBELT UTILITIES IMIa I
u.s.Government
Alaska Power
Administration -Eklutna
1. Does Not Include Self Supplied Energy from
Military Installations and The University of
Alaska
A ENERGY SUPPLY
(Basedon Net Generation 1980)
Alaska Power
Administration -Eklutna
B GENERATING FACILITIES
(Based on Nameplate Generating Capacity 1980)
Oil
2"10
1. Does Not Include Generation by Military
Installations and The University of Alaska
Diesel
(60.6 MW - 6%)
Combined Cycle
Combustion Turbine
(139 MW -14%)
Regenerative
Cycle
Combustion
Turbine
(111 MW-
12%)
C NET GENERATION BY TYPES OF FUEL
(Based on Net Generation 1980)
o RELATIVE MIX OF ELECTRICAL GENERATING
TECHNOLOGY -RAILBELT UTILITIES -1980
FIGURE 18.3.3 [iii]
10,000
9,000
. 8,000
7,000
6,000
~
-;.5,000
i:'.,
c
W
Ir-----.a
I1l!!'I!!II'l!!!!I1..__1
Note: OGP-5ProgramIncreasesUsable
Output at Two YearIntervals
4,000
Energy Deliveries
FromSusitna->
3,000
2,000 .....1...1---------WatanaAlone--------+t_------WatanaAnd DevilCanyon ------.....
1,000
1992 1995 2000 2005 2010
Years
FlGURE ....-ENERGY DEMAND AND DELIVERIES FROM SUSTNA IAIIR I
f---.I
----"
I WATANAONLY IN
1994 1
LEGEND
Energy Cost of Best Thermal Option300
250
-•
Energy Cost of Susitna Option
Operating Costs of Thermal Plant in Use
in 1993 Extended to 1994
Shaded Area Represents Plant Operating
in 1992 Displaced by Watana
Area Under This Line isAnnual
, : Operating Cost of Existing Capacity 1993/4
(Avoided Costs of Fuel and O&MOnly)
Area Represents Annual Operating Costs
from Existing Generating Plant
- Common to Both Susitna and
,.';.:~.Thermal Options~:::::::::::::::::::::::::::::::/MMMt?i[i!;;;.•?.~.VM
Area Under This Line isAnnual Cost of BestThermal Option
_______________[_~:~~~~~::estmentCosts)
I
I
I
I
.......................................J....[..~~~~.under This Line isAnnual Cost of Susitna OptionI
200
.c
~-.
:!!ls
t!1500
(J
>-E'
CDcw
100
50
1,000 2,000 3,000
Medium Growth System Energy
Forecast for 1994;4,829 GWh
~'-~•I . I
Rev. 1
SYSTEM COSTS AVOIDED BY DEVELOPING SUSITNA
COMPARED WITH BEST THERMAL OPTION IN MILLS PER UNIT
OF SUSITNA OUTPUT IN CURRENT DOLLARS
•04 05 06 07 08 09 2010 11 12 13
FIGURE 18.3.6 - SYSTEM COSTS AVOIDED BY DEVELOPING SUSITNA
Devil Canyon on Stream in 2002
0120009876
/
/1
I I
.,COST SAVINGS FROM SUSITNA INCREASING
,OVER WHOLE LIFE OF PROJECT,
II..,.
Increasing Thermal Fuel ~~..
Co'"A,old'"~7
~_....._..........J
~/'#JVr•I
/.-Avoids Cost of a Further 200 MW Coal Fired Generating Unit
I•I
5
Watanaon Stream in 1993
~.Avoids Cost of 2 x 200 MW Coal Fired Generating Units
94
380
360
340
320
300
:c
~280-~
~260
en
Q)
U.;:
Q.240"Dc
III
:len 2200o
>-CD..
Q)200cw
180
1~0
140
120
100
400
r-I .'---L _'__I -'--]
IWATANA &DEVIL CANYON IN 20031
LEGEND..-.
••••••••
Energy Cost of Best Thermal Option
Energy Cost of Susitna Option
-Operating Costs of Thermal Plant in Use
in 1993 Extended to 1994
300
.c
i
~
t!200oo
~cw
100
•Shaded Portion Represents Plant Operating
in 2001 Displaced by Susitna
-L
3,000
~~~~j~j:~~j:~:j~~:~~jI~j~~~j~j:~~jI:j~~:jij··~!.!;l!:li:;·~~:·!~l~l;!!:.:!l!!!!!!·!;::![~:.~:!.::!!
1,000
.L
2,000
Energy Output Watana -----:
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
Annual Energy Output GWh
-L
4,000
FIGURE 18.3.7
I §«UVZK'ZZ"'Wa
5,000 6,000 ~
-ENERGY PRICING'COMPARISONS-2003 •
11 18 •.4 -Financial Evaluation
Introduction
\1
I J
11
U
I]
[1
l J
I I[J
\1
lJ
u
This section considers the basic financial characteristics of Susitna and a
range of financial plans under which the project might proceed.It also
considers the relationship between the economic and financing characteristics of
Susitna and the impact of inflation.This demonstrates the manner in which
inflation,without it changing the real economic worth of the project,creates
the major financing problem for the project if it is largely debt financed,in
the form of an "f nfl atf onary financing def tct t"in the early years.
The basic financing options which would effectively meet this inflationary
financing deficit while maintaining the Susitna output at a price competitive
with alternative energy options are then developed.The main issues involved in
these options are then considered in some detail with particular reference to
levels of possible state appropriation and securing tax-exempt bond financing.
The actual financial outcome for the project will depend not only on the real -
i.e.,constant dollar -characteristics of the project such as the constant
dollar capital cost but also on a range of financial characteristics including
the rate of inflation,the rate of interest at which debt financing is secured,
magnitudes of funding through possible State appropriation,etc.The actual
range of possible financial outcomes depends upon the interaction of this range
of real and financial factors.
In this section the analysis is confined to the financing outcomes for the
central forecasts of the real economic factors as developed in Section 18.1,and
the particular rate of interest and inflation given in the text.For
convenience of reference the real and financial estimates used are detailed in
Table 18.4.1.Forecasts of the main financial factors,i.e.,rates of interest
and inflation,are discussed in sub-section 18.4 (a)below.
The content of this section also concentrates on the problems of financial
planning as represented by the analyses of the basic financing options.The
problems of financial risk - ioeo, the problems arising from the range of
possible financial outcomes as both the real economic factors and the financial
factors are allowed to vary - are considered in the following Section 18.5.
(a)Forecast Financial Parameters
(i)Interest Rates on Possible Susitna
G.O.and Revenue Bond Financing
Unless Susitna is 100 percent state financed residual bond financing
will be required.A key factor here will be the level of interest
rates.Interest rates are determined by many complex political and
economic forces acting nationally and internationally.It is there-
fore evidently difficult to forecast with any degree of certainty
what the prevailing level of interest rates will be in the period
1985 to 2002 when the Susitna bond financing is likely to take
place.The authoritative Data Resources Incorporated long-term
projections are,however,given in the following Table 18.4.4.
18-62
The long-term rate of interest on high grade bonds over the period
from 1985 to the year 2000 is forecast to drop progressively from
10.7 percent through 9.8 to 8.8 percent as the rate of inflation
falls from 8.1 to 6.8 percent.
The tax-exempt bond rate implied by these figures will depend in
part upon the supply of these bonds relative to the markets which
have traditionally supported such issues.These have tended to be
high tax bracket investors,insurance companies and banks.The
reduction in U.S. tax rates and cyclical factors have reduced the
demand for tax-exempt bonds by insurance companies and banks.These
factors,as well as an increased supply of tax-exempt bonds, has
tended to push their yields closer into line with comparable non-
tax-exemp_t_b_o_nds-,r.educlng-the-i-r--Ja-vor-able~d.:j-f:fer-en-M-a-l-from~around~--"
25 to 35 percent of the comparable rate down to only 9 percent in
December 1981.~
TABLE 18.4.4
Annual Percentages Rates
Historical Forecast
1970 1975 1980 1985 1990 1995
to to to to to to
1975 1980 1985 1990 1995 2000
CPI 6.8 8.9 8.6 8.1 7.3 6.8
Interest Rate 8.0 9.4 11.3 10.7 9.8 8.8
for High Grade
Industrial Bonds
'l
1
1
j
l'
·1
I
-I
!
J
j
The differential which will apply in the future again cannot bel
estimated with any certai nty si nce it depends substanti ally on the
future pattern of Federal tax rates and supply of tax-exempt bonds.'
Subject to these qual ifications,it can be argued that the present ,,_'__'J
very low differential between tax~exemp-t and non-tax-e~_emp_t_b_o_n_ds_-_.,~
---------wfllwiaenagafrfTn--fhe-future.With tax-exempt bonds trading,--=-at~a:.-'.n,--_
---------i-nterest-ra-te-80-p-e-r1:1fn-t of-tYiatof~nign grade industrial s (with
which we might expect Susitna bonds to be comparable), the tax-1
exempt bond financing over the successive 5-year period from 1985 ,
might be of the order of 8.6,7.8 and 7 percent.
~Id:1~:~~~.~;a~~~~r~~~~~y~st~~~;~'t~~ta~:~~~a~~;~;~c~a~l~~e:very ]
level of tax-exempt bond interest rates (l3.3 percent in January
1982)the financing plan as developed above has been based on!
interest rates of 10 and 12 percent for Susitna financing in order J
to arrive at relatively conservative estimates of project financing
characteristics.Awider range of possible interest rates and rates 1
of inflation is developed in Section 18.5 dealing with the financing
risk.
!
(i ;)
.'~\~nf:'PY
Po C~(f~RESOURCES l..b utu'u'l.ALi-u a ..,.r..the IntedO ru.s.Depaxtmel1:c 01
Rates· of Inflation
The reference inflation index is taken as that of the Consumer Price
Index (CPI).The rate of inflation used in the projections given in
the preceding section was taken for simplicity at 7 percent through-
out the period 1982 to 2010.On the basis of the DRI estimates this
rate is approximately one percentage point too low for the 1985 to
1990 period although approximately correct for the following decade.
The impact of this on the basic financing analysis in terms of bond
financing requirements in 1982 dollars is,however,negligible.The
impact of a wide range of inflation and interest rates is considered
in the following Section 18.5.
Ii (b)The Infl ati onary Financi ng Deficit
Under inflationary conditions long life capital-intensive projects will
automatically tend to produce "tnfl at'ionary financing def'tc i ts"in their
early years of operation.Figure 18.4.1 demonstrates schematically the
relationship between this deficit and the long-term gain on a hypothetical
project which might well be a highly economic and attractive undertaking in
the long term.
The Susitna hydroelectric development with its long life and high capital
investment would,if financed in a conventional manner with debt funds,
have similar inflationary financing deficit of the actual magnitude
illustrated on Figure 18.4.2.This figure shows the energy cost to the
Railbelt system which would arise from supply from the next-best
(predominantly coal)thermal power generation plan (see Section 18.1).
Thi s energy woul d be expected to cost 148 mi 11 s/kWh in 1994 (the fi rst
normal year of operation of Watana,the first phase of the Susitna develop-
ment).With a general inflation rate of 7 percent and an approximate
additional inflation of 2 percent per annum in the price of coal,on which
the new thermal power generation would be based, the cost of electricity
generated by this means would increase from 148 mills/kWh to 287 mills/kWh
within a decade.
u
u
The economic justification for Susitna described in Section 18.1 is based
on the present worth of the total savings to the system with Susitna
compared with the thermal option and shows that,despite being more costly
in the early years,the net present worth of the savings over the life of
the project is $1,176 million in 1982 dollars.
If Susitna were 100 percent debt financed at a 10 percent rate of interest,
the price it would have to charge for its output is as shown by the higher
line in the Figure 18.4.2.Almost the whole of this cost would be made up
by interest and debt repayments since the operating costs of the hydro-
electric system would be only about 5 percent of the total cost in the year
1994.On this financing basis it would be some 14 years before the cost of
thermal-generated electricity overtakes that of the generation output from
Susitna.
Thereafter,however,there would be an ever-increasing,favorable gap
stretching out into the almost indefinite future,recognizing the very long
life of the hydroelectric generating facilities.
18-64
The effect on Susitna energy production costs would be even more marked.
This is because in a world of zero inflation,interest rates would no
longer be 10 percent but,on historical experience,would be about
3 percent.This means that the cost of electricity generated by Susitna
would very rapidly be lower than the cost of the best thermal option as
shown in Figure 18.4.2.It is in this sense that the inflationary
financing deficit can be viewed as a direct result of inflation.Without
inflation it would not exist.
In this inflationary world,therefore,the costs of supporting a major
hydroelectric development such as Susitna on a 100 percent debt-financed
basis are out of time phase with its benefits,giving rise to a deficit
(i.e.,a difference between cost and potential revenues).Being a direct
result of inflation this may appropriately be termed lithe inflationary
financing deficitll
•However,if inflation were to cease completely in the
year 1993 (i.e.,after the completion of the Watana segment of Susitna),
the cost of electricity developed by the best thermal option would no
longer grow at approximately 9 percent,but drop back to an annual rate of
around 2 percent,(i .e.,the rate by whi ch the rate of i nf1 ati on in thermal
energy costs is expected to exceed that of general inflation).
,OJ
Inflation,however,does not change the real economics of Susitna.In
terms of present worth and 1982 money the net benefits are exactly the same
as they would be in the absence of general inflation.This is principally JO
because inflation does not make debt financing more expensive over the
35-year term of the bond financing that is expected for Susitna.It merely
makes the bond financing more costly in the earlier years (in terms of 1982 oOj
money)and correspondingly less expensive in the later years.For example,
in terms of dollars of equal purchasing power,inflation at 7 percent wilL~o
-~~:~;Ylga;~~r;~e--~~~~e~e~~~-t~~~in-~i~~f~~gay~:~;~~p~~:e~;~j :~~~~~.~~~a into
0
1
operation,interest and debt repayment in terms of 1982 purchasing power
will be only 26 percent of the level existing in 1994.In contrast the
cost of electricity generated by the best thermal option is forecast to I
have increased by 24 percent in constant money terms over the 20 years from
1994.
___._In __summa~y_,__j_nfJ.at i-on,--wi-th out-neeess aY'-i-ly~ch ang-i-ng--th e-econontcsof-th e------
______praj ect,wi 11 auto1Datj_c_aJJy_c~ea-te-a-la~ge-i-n-f-la-t';-onar-y-f-i-nam:-i-ng-de-f-i-G-i-t --
for projects which are capital intensive and largely or wholly debt
financed.This inflationary financing deficit must be met either by
consumers or by the state if such projects are to be undertaken and their
substantial advantages in terms of economic benefit and long-term
stabilization of energy prices are to be realized.The following analysis
of thefinanci ng()pti0rlsava.i1 a~l ~f()rSlJsi tr1at:h~refQrecQnsjders the
varfous means by which the State of Alaska might meet Susitna's
inflationary financing deficit and ensure the ensuing benef.t ts;
As shown from the cost benefit analysis in 18.1 (c1 (ii),the project has a
rate of return of 11.4 percent,taking into account all the capital
invested.This shows that it would be possible,in the long term, for the
IJ
!
1
\
l
.l
T-
\I
lJ
lJ
IJ
state to recover the whole of its investment with this rate of return.
Since this is in excess of the forecast cost of capital at that time,state
appropriation of funds to meet Susitna1s inflationary financing deficit can
be justified on economic grounds.
(c) Basic Financing Options
A wide range of options exist for possible state participation in meeting
the inflationary financing deficit for Susitna.Three basic financing
options have been reviewed.To illustrate these,central estimates of
capital cost,thermal prices,etc.,are used throughout.As noted above
the inflation rate is assumed to be 7 percent and the interest rate
10 percent.Detailed printouts of the financial projections for the cases
considered are provided in Tables 18.4.5 to 18.4.8.The cases cover:
(i)100 Percent State Appropriation of Total
Capital Cost ($5.1 billion 1982 dollars)
Under this case 100 percent of Susitna capital cost is financed by
the state.This conforms with a possible out1ome of Senate Bill 25
and represents the simplest financing option.
The year-by-year appropriation required in then current dollars to
meet the $5.1 billion capital cost (in 1982 dollars)is given in
Table 18.4.5 (line 461).
The Alaska Power Authority,under the present wholesale energy
rate-setting requirements incorporated in Senate Bill 25,would not
be able to charge more for the output of Susitna than a wholesale
energy rate necessary to provide:
-operation,maintenance and equipment replacement costs
- debt service on bonds issued for the power project,if any,and
-safety inspections and investigations of the project by the
Authority.
These costs would enter into a wholesale rate which would be
determined by aggregating costs from all projects proyided for by
the Power Development Fund established in AS44-83-382 •
In this 100 percent state-financed case only the relatively small
year-to-year operating costs could therefore be charged as the cost
of output.For all practical purposes therefore,the energy
developed by Susitna would be supplied to the consuming utilities at
a price representing only a small fraction of the cost of power from
1 Reference:State of Alaska Senate Bill 25.nAn Act relating to energy
projects and programs of the Alaska Power Authority.1I
18-66
18-67
2 This conclusion would be modified if,as proposed by Senate Bill 646,the
APA is required to repay the state appropriation from the revenues generated
by the proj ect ,
It should also be noted that after the completion of Devil Canyon
the most meaningful basis of comparison is the Susitna cost
excluding excess debt service cover. This is because this excess
debt service charge is then available to finance other power
generation projects and could, under certain conditions,be
"refunded" to consumers (up until this date the excess charge is
used to help finance Devil Canyon).
')
alternative sources.2 Evidently,in this case there would be no I
financing or marketing problems.The major problem might well be
that of devising appropriate means of equitably sharing out this
major low cost energy supply between the different utilities takingl
the output since demand would exceed supply.'
(ii)$3 billion (1982 dollars)State Appropriation ',I
with Residual Bond Financing
The financing scenario which would arise if the state appropriated I
only $3 billion (in 1982 dollars)and the residual financing I
requirements were met by bond issues is summarized in Figure 18.4.6.
This again shows the cost of electricity on vertical axis over the
first years of operation of Susitna.The plot representing the 'j
"best thermal option"is again the central estimate of the year-to-
year costs of providing the same energy as Susitna by the least cost
thermal power generation system based on the costs as detailed in L,'1
Section 18.1 of,the report and assuming an interest rate of 10 ~
percent - the same rate assumed in determining the Susitna costs
applies to the cost of thermal units.1
As already noted, the wholesale price of the electricity supply from
Susitna (and other projects provi ded for from the Power Development "'1
Fund)would be limited to the actual costs incurred including the
cost of debt service.On the central estimates this would lead to
an almost constant wholesale price for Susitna's output over the
period up to the completion of Devil Canyon.This is because ',..j
virtually the whole of the costs would be accounted for by debt
s~r"tC:.f;wn ic:b\'!QY 1d~00 t change unUL~DeyjLG anyon .came..on-st ream •....
Interest incurred on the bonds issued to finance Devil Canyon would \
be capitalized and,therefore,have no effect upon price until Devil
Canyon was completed in the year 2002.At this time the cost of ',I
Susitna energy would increase as it became necessary for the project )
to recover the costs of Devil Canyon.This "step-up"results from
the fact that the $3 billion state appropriation would in effect
-~-'--'-~----~~-~~~~S~~~~d~~~-~-~~l~~~·~~~-~-~de~-~r~;-~-i~~~·'~~~a~:)-~t-~6e~~·~t~a~jo,~~t:~(il:he~--l
---------other-hand,wi-l-l-have-been-whu"l-ly-fi-n-a-m::-ea-oy irfterest-5ea ring50na-s---
so that its per-unit cost of energy output will be correspondingly 'I
higher than that from Watana.
l
j
(
1
r
II
ij'
I.
u
IIl-.J
(i t i )
However,after the step-up as Devil Canyon comes on-stream in 2002,
the future unit price of Susitna energy would be falling for some
years before becoming virtually constant,despite an assumed annual
rate of inflation of 7 percent and an additional escalation of about
2 percent in operating and maintenance costs.(This fall is due to
the effect of increased sales of Susitna energy after 2002.) In
terms of constant 1982 dollars,therefore,the cost of energy
supplied from Susitna will be falling markedly.
Under this scenario Susitna will again provide ever-increasing
savings to Alaskan consumers in terms of the difference between its
falling and then nearly-constant price energy and the ever-escalat-
ing cost of the thermal alternative as shown in Figure 18.4.3.
"Minimum"State Appropriation $2.3 billion (1982 dollars)
with Residual Bond Financing
The "minimum"state appropriation is taken as the minimum amount
required to meet debt service cover of 1.25 on the residual debt
financing by revenue bonds and to make Susitna's wholesale energy
price competitive with the best thermal option in its first normal
cost year of operation (i.e.,1994).The basic characteristics of
this scenario are shown in Figure 18.4.7.Again the results shown
are based upon central estimates for interest rates,inflation,
capital cost,etc.If these estimates were achieved, the $2.3
billion (1982 dollars)state appropriation would be just sufficient
to result in Susitna meeting its debt service cover and operating
costs in the first year.
As is seen from Figure 18.4.7,however,with an appropriation of
$2.3 billion (in 1982 dollars)Susitna will again,after the
completion of Devil Canyon,provide a falling and then virtually
stable cost of electricity indefinitely and ever-increasing cost
savings compared with the thermal option.
Slightly lower appropriations would still be consistent with
financial viability of the project based on the central estimates.
These would however result in Susitna being unable, in its first
normal year of operation (1994), to meet fully debt service cover,
i.e.,it would be unable to earn the 1.25 times debt service
requirement which must be expected as the minimum if the project
were residually financed by revenue bonds.Under such "l es s-than-
minimum"scenario,therefore,it must be assumed that this residual
bond financing in the earlier years is on the basis of a state
guarantee or general obligation (G.O.)bonds as detailed below.At
any substantially lower state appropriation than $2.3 billion (in
1982 dollars),Susitna would have a correspondingly large,early
year inflationary financing deficit unless it was possible to
wholesale its energy output at a higher price than that which would
apply under the best thermal option.If it was not possible to
secure such higher price contracts there might also be significant
financing difficulties as discussed in (d)(vi)below.
18-68
The conditions under which bonds will secure tax-exempt status are
covered in the Internal Revenue Code Section 103.These are
designed to prevent the benefits of tax-exempt bond financing
passing to non-exempt entities.The only significant tax-exempt
entities in the Rai1be1t area likely to purchase Susitna energy are
AMLP and FMUS.All other potential customers for Susitna energy
_-_-~_Cr.e prese nti.ng-approx-ima-tely--two-th-i-rds--of-th e-potenti-a-1-market-)~-are--~
__________Qrivat_e_u_:tiJj~tj_es_o_Lco~ops-whlch-ar:'.e-not-tax-",-exempt.--------
This issue has been considered in detail by the consultants and
reviewed by tax advisers.It has been concluded,that with an
appropriate degree of financial restructuring referred to above,
it will prove possible to meet the conditions.required for any bond
fi nanci for Su sitna obtai n 1:a)(_~)(~IT1Ptstatus.
(jji)Options for Resi dual Fi nancin~
Tables 18.4.2 and 18.4.3 set out the estimated requirements for bond
financing and state appropriations of $2.3 billion and $3 billion
respectively.
(d)Issues Arising From the
Base Financing Options
(i)Need for Financial Restructuring
If substantial revenue bond financing is to be secured for Susitna,
it will have to be based on firm power contracts from the major
Rai1be1t utilities.These contracts will,however,need to be
supported by adequate financial strength on the part of the utili-
ties themselves if they are to constitute acceptable security to
bondholders.Whether Susitna or any other alternative element of
generating capacity is chosen to meet the Rai1be1t energy require-
ments over the next decade, the same issue of the financial strength
of the Rai1be1t utilities will arise if revenue bond financing is to
be secured.On these grounds it is assumed that independently of
Susitna,financial restructuring will take place to ensure that all
the major Rai1be1t utilities will be able to offer adequate
financial security relative to their power contract commitments.
(ii)Tax-exempt Bond Financing
Tax exemption for its bond financing is important to the economics
ofSusitnainsofar as it is,iii substantial measure,to be financed
by G.O.or revenue bonds.Tax-exempt bonds have tended to trade at
interest rates some 25 to 30 percent less than the rate of interest
on comparable securities.Since interest charges account for some
90 percent of the total price for Susitna's output (in 1994 under
the $2.3 billion state appropriation scenario),loss of tax
exemption would have a serious adverse affect on the economics of
~...-~----theproject;
I
I
1
I
r
l
-I
I
I
l
I
I
}
l
l
\
(
l
1-
\1
I.j
(1
!j
\]
[\
\I(J
iJ
- Several options are available to meet these financing needs and
these are summarized below.
·Revenue Bonds with a Completion Guarantee
A completion guarantee must be assumed to be a precondition of
bond financing at the Watana stage (up to 1993). A State of
Alaska guarantee of project completion would probably enable all
residual financing to be met by revenue bonds.
· Guaranteed Revenue Bonds with
Post-completion Refinancing
If the revenue bonds were guaranteed by the State of Alaska,
this could be expected to limit the requirement for a completion
guarantee.
•G.O.Bonds with Post-completion Refinancing
G.O.bonds which have the "full faith and credit"of the State
of Alaska share a common security feature with guaranteed
revenue bonds and would limit the support required from a
completion guarantee.Furthermore,G.O.bond financing would
have a beneficial effect on energy pricing arising from reduced
debt service cover requirements.
In this case,as with that of guaranteed revenue bonds,the
burden on the credit of the state could be minimized by making
the bonds subject to "call"after a few years (when project
viability was established)and refinancing into non-guaranteed
revenue bonds.
-Revenue Bonds with Completion Guarantee
The first option is that of revenue bond financing for the whole
of the residual capital requirements.It is probable that such
financing will only be obtainable on the basis of bond holders
being protected from pre-completion risk including (a)the risk of
overruns and (b) the risk of actual non-completion.Neither the
Railbelt utilities nor the APA could provide a wholly satisfactory
guarantee covering both (a)and (b).The guarantee would have to
be provided by the State of Alaska.
The precise form of this completion guarantee cannot be determined
at this stage.It will depend on the extent to which the power
sales contracts accept any escalation in wholesale energy price
based on capital costs and on the magnitude of the state appropri-
ation since it is primarily these factors which will determine the
residual financing risk.With appropriate power contracts and a
sufficiently large state appropriation,the state completion
guarantee might be limited to guaranteeing bond holders against
18-70
non-completion due to natural hazards or national emergencies. In
other cases it might also be necessary to provide a contingent
authorization permitting a given maximum amount of subordinated
G.O.bonds to be issued to ensure completion.
-Guaranteed Revenue Bonds with Post-completion Refinancing
If revenue bonds were guaranteed by the State of Alaska they could
be issued without any requirement for a completion guarantee.
,This is because the strength of the state guarantee would make any
other security unnecessary.It is assumed,however,that in the
interest of avoiding unnecessary burdens on its 'credit',the
State of Alaska would wish to see the guarantee terminated at the
earliest possible date.This could be achieved by making the
bonds subject to "call"(repayment at the option of the issuer)15
years after issue in the case of bonds financing Watana and 10
years after issue of bonds to finance Devil Canyon.The state
guarantee would,of course,ensure repayment at the call dates.
Coverage level conditions at these call dates (2005 at the
earliest)are seen from Figures 18.4.3 and 18.4.4 to be such as to
offer adequate security without state guarantees and therefore,
subject to market conditions at the time, permit refinancing into
non-guaranteed revenue bonds.
-G.O.Bonds with Post-completion Refinancing
As an alternative to guaranteed revenue bonds,G.O.bonds on the
"full faith and credit"of the State of Alaska could be issued.
These .are _eff{;Lc_tLv_eJy_tdenticaLto-bonds--car-r-y-i-ng-acompa·r-able
state guarantee.Agai n they could be subject to "call"and as
such be converted to revenue bonds without state guarantee when
the project was fully established.
(iv)Borrowing Requirements for the Residual Financing Options
On the assumption that the residual source of finance for Watana is
revenue bonds,the estimate of year-by-year requi rements _._l!~the _,_
·----comp-leti-on-o-f-Watana are snown 'inTabler8--:-4--:-2-and 18.4.3 for the
----------,m;-n-imum-state-appropri-ati-on-of-$2-;3-oi'l-n on ana-tne $3-IJflTi"'70'C'C'n-----
scenarios respectively (1982 dollars).These again take the central
capital cost estimate as the starting point and estimate the bond
financing requirements year-by-year for a 7 percent rate of
inflation up to the date of completion of Watana.
Iherequi rementsaregiven,in the form of -then-actual money and in
terms .ofd~llars at 1982 purcha$ing power.It is the latter on
wl1ich the assessment should focus since,even with 7 percent
inflation,the value of the bonds issued for the completion of
Watana in 1993 will be worth only 48 cents of a dollar in 1982.It
is these "today's purchasing power dollars"which most accurately
reflect the financing burden of Susitna.Even in this,the
'/
I
I
I
I
I
\
I
I
I
I
\
}
j
I
..j
~
l
I
u
"minimum"$2.3 billion state appropriation scenario,the issuance of
$1.7 bi 11 ion of bonds (i n 1982 pu rchasi ng power)over the 4 years
from 1990 appears to be well within the financing capability of the
State of Alaska.The possible impact of such an issue on the credit
rating of the state is however considered below.
(v) Refinancing Watana and the
Financing of Devil Canyon
As already noted it is assumed that it would be the policy of the
State of Alaska to ensure that any guaranteed revenue bonds were
refinanced into non-guaranteed revenue bonds at as early a date as
possible.When this would in fact be possible would depend both on
the revenues actually obtainable from Susitna at the Watana stage of
development and on the conditions of the bond market at that time.
A dominant consideration,as regards the date at which refinancing
into non-guaranteed revenue bonds will be possible,will be the
magnitude of the initial state appropriation.In the $3 billion
(1982 dollars)scenario such refinancing should be possible for a
very wide range of outcomes.This is apparent in Figure 18.4.3
which shows that on the central estimates Susitna could be financed
with revenue bonds on a 1.25 cover basis and be charging a wholesale
energy price of approximately 236 mills/kWh (i.e.,20 mills/kWh less
than the cost of the best thermal option) in 2003.This price would
thereafter show rapid and ever-increasing divergence from the cost
of the best thermal option.In this case only a relatively extreme
combination of adverse eventualities in terms of interest rates,
capital cost overruns,etc.,could result in it not being possible
to undertake refinancing into non-guaranteed revenue bonds within a
few years of completion.
Capital expenditures for Devil Canyon for completion in the year
2002 will begin almost immediately after the completion of Watana.
On the basis of the central forecasts,the outcome,as depicted in
summary form in Figures 18.4.3 and 18.4.4,is that it would be
possible to finance this stage wholly by non-guaranteed revenue
bonds and without a completion guarantee where the initial state
appropriation is at the $2.3 billion or $3 billion level for the
total project (in 1982 dollars).
The grounds for this conclusion are that (a)Devil Canyon is a
considerably smaller capital project than Watana ($1.48 billion as
compared with $3.65 billion in 1982 dollars)and (b)the major
construction risks would have been fully explored during the 'Watana
stage.Also seen from Figures 18.4.3 and 18.4.4 on the central
forecast,the cost of energy from the best thermal option would be
23 percent or more costly than that from Susitna in 2005. This
comparative cheapness (and therefore the scope for substantially-
increased revenues if necessary)is the basic security which the
project would offer to bond holders.
18-72
18-73
The magnitude of the revenue bond financing required for the Devil
Canyon stage in the $2.3 billion state appropriation scenario is
shown in Table 18.4.2.The financing requirements are given for a
7 percent inflation rate and in then-actual money terms as well as
in the purchasing power of 1982 dollars.The amount of $2.1 billion
(in 1982 dollars)as a bond financing burden on the State of Alaska
does not appear excessively large.The financing requirements in
the $3 billion appropriation case are given in Table 18.4.3.
(vi)Importance of Adequate Appropriation
to Subsequent Financing
In the "minimum"scenario (i.e.,a state appropriation of $2.3
billion)refinancing into non-guaranteed revenue bonds would still
be possible on the central estimates with the completion of Watana
in 1993.On any less favorable outcome than that resulting from the
central estimates,however,G.O.bond refinancing could be delayed
until the ceiling on the Susitna energy price,set by the best
thermal option,was high enough for Susitna energy prices to be
increased to a level at which it could offer the 1.25 times debt ··l
service cover which would probably be required by revenue bond .
holders in the absence of guarantees.
This scenario is illustrated in Figure 18.4.8 for a state appropria-1
tion of only $1.8 billion.(See also Table 18.4.8.)In this case
it would be necessary to increase the price of Susitna's energy each
year (within the limit set by the cost of energy from the best )
thermal option)and use the additional revenue to refinance with \
________~non-.auarenteed..r-e-venue-bonds-.---I-n--th-i-s--seenari-ocomplete-refi-nancing-
into revenue bonds would not take place until 1995.J
Timely and adequate funding for Susitna is of great importance in
minimizing dependance on state guarantees.There is the likelihood 1
that inadequate initial funding would result in insufficient poten-I
tia1 earnings cover in the early years of Devil Canyon.This might
necessitate state guarantees for the financing of Devil Canyon as
well as_W~~~na_.InJ.~J~os!:;ibi1jty_is__als_o_iJJ_ustr.ated-i-n-F-i-gur-e-----I
f8--:-4--:-8-;-where the Susitna pri ce is forced to "track"the cost of the )
----------~e-st-tnermal~tion over the years 2002-2004.These considerations
point to the importance of adequate initial funding to the I
establishment of Susitna at the Watana stage as a project fully .1
capable of securing both tax-exempt low interest revenue bond
financing for the Devil Canyon stage and subsequent refinancing intoi
non-guaranteed bonds of the issues made to finance Watana.J
.~d:~~;~:ra~·~n~~~:~;tl~~tgfa~~~.~~A~.~~:;;.afri=~1.~i~~ii~~f~6~ii~u6ti en!
bid prices.It must be expected that any perceived inadequacy in
funding,creating possible delay in payment or uncertainties in the
construction schedule,would be fully reflected in the level of bid }
prices.I
l
_I -....--
(vtt)Impact on State Credit Rating
of Susitna G.O.Bond Financing
Where the financing plan actually undertaken is near the "minimum"
($2.3 billion)state appropriation,the guaranteed revenue bond or
G.O.bond financing at the Watana stage may be of a magnitude that
warrants consideration of its effect upon the overall credit rating
of the State of Alaska.
As at November 1981 the State of Alaska had approximately $681.7
million of G.O.bonds outstanding.In late 1981 these were rated
"AA"by Moody'sand "Aa-"by Standard &Poors,
)I
LJ
The impact on the state's credit rating of Susitna guaranteed or
G.O.bond financing of $1.7 billion (in 1982 dollars)for the $2.3
billion state appropriation case will depend upon a wide range of
factors.The most important will obviously be the strength of the
credit standing of the State of Alaska at that time, taking into
account the total amount of bonds which it has issued and outstand-
ing.The second factor will be the economic prospects for Susitna
itself -that is the extent to which it is perceived by the bond
market as likely to be able to meet the interest burden on the bonds
issued to finance its construction.The impact has been assessed by
the Alaskan Power Authority's investment banking and financial
advisers First Boston Corporation and First Southwest Company.They
have concurred in the following statement.
"We are only able to render a conditional estimate of the possible
impact on the credit of the State of Alaska as a result of the
contemplated general obligation bond financing of $1.7 billion for
the Watana stage of the Susitna Hydroelectric Project.Alaska's
presently-favorable ratings are greatly influenced by its low debt
to assessed value ratio which helps to overcome the unusually high
per capita debt statistics.Given the dramatic growth of assessed
valuation and in the fact that interest expense through start-up
of Watana is to be capitalized from bond proceeds the envisaged
financing should not significantly impair the credit of the state.
Even if the State of Alaska's general obligation bond rating were
reduced one full letter grade, the cost in terms o~interest rates
on future bond issues would likely be in the approximate range of
1/4 percent to 1/2 percent per annum."
(e) Financing Options Under Senate
Bill 646 and House Bill 655
Senate Bill 646 and House Bill 655 have been proposed and if enacted would
offer alternative financing options to those considered above.These
options are briefly reviewed in this sub-section.
In summary,Senate Bill 646 and House Bill 655 propose funding for approved
energy projects from the Power Development Fund on the basis of such
funding being recovered at a rate of 3 percent per annum together with an
18-74
uplift to reflect past inflation.The latter is determined at 10 yearly
intervals and increases the 3 percent recovery by the average rate of
inflation in the CPI over the preceding 33 years.
(i)100 Percent State Appropriation
First to be considered is the total appropriation required to
finance Susitna wholly under this proposed legislation.In terms of
total state appropriation this is the same as the outright
appropriation case considered in 18.4 (c)(i).As seen from Figure
18.4.6 and Table 18.4.9,however,the resulting cost of power is
very different.For the 'outright'appropriation case the cost of
power would be only 19 mills/kWh in 1994.For the Senate Bill 646
case it would be 81 mills/kWh.
(ii)"Minimum"State Appropriation of
$3 Billion (in 1982 dollars)
with Residual Bond Financing
To identify the impact of Senate Bill 646 and House Bill 655,where
residual bond financing is required,some details of the proposed
bills need to be clarified.Specifically:
•Whether the state recovery is subordinate to interest and debt
repayments on the revenue or G.O.bonds.
•Whether,in the event of any failure to meet the state recovery,
the APA would be deemed in default and the payment made be a debt
~~__~.~.~~toe APA and _att.r.a.c_t_tnte~es.t •.~~_~_~~~~_~.~__..._
l
J
Both questions are important to residual financing by revenue bonds.(
In the following analysis it is assumed that,to facilitate bond
financing,the state recovery will be wholly subordinate and failure I
to meet payment would not be deemed a default.This assumption has )
the important effect in terms of the pricing of Susitna energy that
the state recovery of funding could be largely made out of the .25
__,~~_~.~__~.~~e_x~c_e_ss~~__~_d_ebt servi ce cover and not need \
---------I-t-i-s-a-gai·n~a·s-sume·d-th-a·t~tne ceiTing price of-tile Susitna output i-s------
set by the cost of the best thermal option,and that 1.25 times ~,'j\,
cover would be required for the revenue bonds..
i~~~~:~~~i:~~:~~E~~~~~~1~~:~::~~;~!ii~~~:~1~:;~~~:di~~~~;i;~~~~d(~~1
1982 dollars)of bond financing required to complete Watana.In '!
1994 a further $2 •3 billion of revenue bonds would be requi red to
achieve the completion of Devil Canyon.
I
I
75l~~
i
'i 'j
I I
I, )
I')
I.)
jl
\]
The $3 billion appropriation would,however,be the "minimum"in the
sense that the Susitna output would need to be priced up to the full
cost of the best thermal option in the first year of operation of
Devil Canyon.As will be seen from Figure 18.4.7 this Senate Bill
646 scenario would result in a selling price for Susitna energy of
120 mills/kWh in 1994 compared with 80 mills/kWh in the $3 billion
outright appropriation case ((c)(ii)above}.This scenario would
nevertheless be effective in terms of the twin objectives of meeting
the inflationary financing deficit and reducing the cost of power to
Alaskan consumers and might be regarded as similar in these
characteristics and in state appropriation to the $3 billion
outright appropriation already noted.
Future Development and Resolution of Uncertainties
Prior to the decision to proceed with actual construction of Susitna,
several significant uncertainties affecting the project will have been
reduced.Demand forecasts will be more certain and the impact of the
electrical intertie between Anchorage and Fairbanks will be known.Fuel
cost trends and energy prices from alternative generation sources will be
more precisely known.More advanced engineering work and definition of the
basis for construction contracts will have firmed up requirements for
capital funds. In addition,the passage of time will have allowed better
definition of the level of state appropriation required and of the ability
of the state to provide the necessary financial support.
The development of the institutional structure of the Rai1belt utilities by
this date should also permit power contracts and legislative proposals to
be drawn up which would equitably share these then more clearly delineated
risks between the utilities,the APA and the State of Alaska.The key
requirements for state guarantees and financing could then be more
precisely defined in an appropriately limited form which would be
acceptable to the state and adequate for project financing.
(g) Conclusion
Early year inflationary financing deficits have been seen to be inevitable
in the case of capital-intensive debt-financed projects being built under
inflationary conditions.Such inflationary financing deficits have no
bearing on the economic Viability of the project but instead directly
result from inflation.As a highly capital-intensive,long-life project,
Susitnahas a substantial inflationary financing deficit despite its strong
economic viability.If the project is to go forward and its advantages in
terms of indirect economic benefit and stab1ization of Alaskan electrical
energy prices realized,major state appropriation of funds will be
required.
In terms of the magnitude of appropriation an amount of not less than $2.3
billion (in 1982 dollars)would represent an assured and effective means 6f
meeting the inflationary financing deficit.This would ensure that Susitna
energy could be made available in the first year of operation at a price
18-76
competitive with the cost from the appreciable increase in the Railbelt
system energy cost which would be otherwise occurring at that time as a
result of the rising cost of fuel and other factors.Substantially lesser
levels of appropriation might create appreciable difficulties or costs as
regards the residual debt financing.In particular such inadequacies might
create the need for a more prolonged period of guaranteed revenue bond or
G.O.bond financing,or involve higher electricity costs.
Finally,it is important to distinguish between appropriations to meet the
inflationary deficit and appropriations designed to reduce the cost of
electricity to Alaskan consumers.The economics of Susitna are such that
it could, long term, repay with an adequate rate of return,all of the
state appropriations used to finance Susitna's inflationary financing
deficit.State financing of the magnitude indicated is therefore
economically justifiable in terms of meeting the inflationary financing
deficit in an efficient and adequate manner to enable an economically
viable and important project to proceed.The decision to allow all or part
of this appropriation to be retained in the project,long term, or to
provide even larger appropriations to subsidize the cost of electrical
energy to Alaskan consumers,is a separate issue to be decided asa matter
of public policy and is beyond the terms of reference of this study.
~-,~,----
'I
I
i
or
(
t
J
l'
.J
J
I
\
J
------------------------------------'~-
J
,I
J
I
"j
i
TABLE 18.4.1:FORECAST FINANCIAL PARAMETERS
11
I \
Project Completion - Year
Energy Level -1993
- 2002
-2010
Watana
1993
Devil
Canyon
2002"
Total-
.3 387 GWh
0;223 II
6 6"16 II
"15 percent of Ope rat ing Costs
"10 percent of Revenue
100 percent of Operating Costs
100 percent of Provision for Capital
Renewals
Costs in January 1982 Dollars
Capital Costs
Operating Costs - per
annum
Provision for Capital
Renewals - per annum
(0.3 percent of Capital Costs)
Operating Working Capital
Reserve and Contingency Fund
$3.647 $"1.470
billion billion
$10.0 $5.42
million million
$10.94 $4.4"1
$ 5.117
billion
$15.42
million
$15.35
Interest Rate
Debt Repayment Period
Inflation Rate
Real Rate of Increase in Operating Costs
-"1982 to "1987
- 1988 on
Real Rate 0 f Increase in Capit al Costs
- 1982 to 1985
- 1986 to 1992
- 1993 on
10 percent per annum
35 years
7 percent per annum
1.7 percent per annum
2.0 percent per annum
1.1 percent per annum
1.0 percent per annum
2.0 percent per annum
(1, II!
TABLE 18.4.2 FINANCING REQUIREMENTS -$BILLION
For $2.3 billion State Appropriation Scenario
Interest Rate "10%
Inflation Rate 7%
1982
Actual Purchasing
Power
$billion
1985 State Appropriation 0.4 0.3
86 "
0.5 0.4
87 "0.5 0.3
88 "0.5 0.3
89 "0.9 0.6
90 "0.7 0.4
Total State Appropriation 3.5 2.3
1990 Guaranteed or G.O Bonds 0.8 0.5
1 ""1.3 0.7
2 ""0.9 0.4
3 ""0.3 0.1
Total Watana Bonds 3.3 "1.7
1994 Revenue Bonds 0.2 0.1
5 " "
0.3 0.1
6 ""0.4 0.2
7 ""0.3 0.1
8 ""1."1 0.4
9 ""1.4 0.4
2000 " "
1.5 0.4
1 " "
1.4 0.4
2 ""0.2
Total Devil Canyon Bonds 6.8 2.1
Total Susitna Bonds 10.1 3.8
TABLE 18.4.3:FINANCING REQUIREMENTS -$BILLION
For $3 billion State Appropriation Scenario
Interest Rate lOr.
Inflat ion Rate 7%
1982
Actual Purchasing
Power
$billion
1985 State Appropriation 0.4 0.3
86 II 0.5 0.4
87 II 0.5 0.3
88 II 0.5 0.3
89 II 0.9 0.6
90 II 1.5 0.9
91 II 0.5 0.2
Tot al St ate Appropr iat ion 4.8 3.0
1990 Guaranteed or G.O Bonds
1 II II 0.8 0.4
2 II "0.7 0.4
3 II II 0.3 0.1
T .al Watana Bonds 1.8 0.9
--------------------------------------------------------
1994 Revenue Bonds 0.2 0.1
5 II II 0.4 0.1
6 II II 0.4 0.2
7 II II 0.4 0.1
8 II II 1.2 0.4
9 II II 1.4 0.4
2000 II II 1.6 0.5
1 II II 1.5 0.4
2 II tI 0.1 0.1
Total Devil Canyon Bonds 7.2 2.3
Total Susitna Bonds 9.0 3.2
---'
*************************************~~~~~_•••~-~-~~~--~--~~-~~--~**************o********************o*************************DATAI0K WATANA-DC (ON LINE 199)-2002)·INFLATION 7%-INTEREST 10%-CAP COST 55.117 BN 23-FEB-82
*************************~:***********~~Y¥~~*~~~~~*~**************************************************************************~*
0.0 6.0 0.0
0.0 0.0 0.0
0.0 0.0 0.0
0.0 0.0 0.0
0.0 0.0 0.0
0.0 0.0 0.0
0.0 0.0 0.0
63.0
29.3
1994
33.6
5.6
9.8
0.0
216.9
2';9.2
17.10.0
33tH7.98
232.91
18.59
29.5
0.0
0.0
0.0
29.5
229.1
0.0
17.7
6975.8
61.6
54.1
0.0
6860.1========
33813.65
211.73
7.94
0.0
0.00.0
0.0
1993
26.9
26.9
431.1
333.1
98.0
0.0
0.0
333.1
0.098.0
0.00.0
0.0
0.0
56.5
41.5
0.0
6600.9
6698.9========
0.0676.4
0.0
0.0
0.0
0.0
O.C
0.0
616.4
676.4
0.00.0
0.0
0.0
0.0
0.0
0.0
0.0
1992
a0.00
203.48
0.00
0.0
0.0
0.0
6261.8
6267.8========
a0.00
190.17
0.00
0.0
J.O
0.0
0.0
1991
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.05591.4
5591.4
0.0
1241.1
0.0
0.0
124101
1241.1
0.0
0.0
====-====
1990
0.0
0.0
0.00.0
0.0
0.0
0.0
0.0
0.0
0.0
o0.00
171.13
0.00
0.0
1550.4
0.0
0.0
1550.4
1550.4
0.00.0
0.0
0.0
0.0
4344.3========4344.3
0.0
0.0
0.0
0.0
938.3
0.0
0.0
938.3
938.3
0.00.0
a0.00
166.10
0.00
2194.0
0.0
0.0
0.0
2794.0========
0.0
0.0
0.0
0.0
499.5
0.0
0.0
499.5
0.0
0.0
499.5
1355.6
0.00.0
0.01855.6========-
0.0
0.0
0.0
419.7
419.1
0.0
0.0
0.0419.1
0.0
0.0
1967 1983 1989
CASH FLOW SUMMARY
===($MlllIONt====o a0.00 ll.OO
14S.08 155.24
0.00 0.00
0.0
0.0
0.0
135 b.1
1356.1========
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1986
0.0
O~O
472.1
412.7
0.0
0.0
816.4
0.0
412.7
0.00.0
0.0
0.0
0.0
816.4
o0.00
135.59
0.00
========
0.0
0.0
0.0
0.0
0.00.0
0.0
1935
0.0
0.0
0.0
403.1
403.1
0.0
0.0
O.Q
403.7
0.0
0.0
0.0
0.0
0.0
403.1
403.1
o
0.00
126.12
0.00
======:-=
ENERGY GWHREALPRICE-MILLS
INFLATION INDEX
PRICE-MillS
-----INCaH~-----------------REVENUE
lESS OPERATING COSTS
OPERATING INCOME
AOD I~TEREST EARNEO 8N fUNDS
lESS INTeREST ON SHORT T=RH DEBT
LESS INTEREST ON LONG TERM DEBT
~ET EARNINGS fROM QPERS
-----CASH SOURCE AND US[----
CASH INCO~E FROM OP~RSSTATECONTRIBUTIQN
LONG TERM DEBT D~AWDOWNS
WORCAP DEBT DRAWDOWNS
TOTAL SOURCeS Of fUNDS
leSS CAPITAL EXPENDITURE
LESS waRCAP AND fUNDS
LESS DEBT REPAYHENTS
CASH SURPlUS(DEfICITI
SHORT TERM DEBT
CASH RECOVERED
-----BAlANCE SHEET----------
RESERVE AND CONT.FUND
OTHER WORKING CAPITAL
CASH SURPLUS RETAINEDCUH.CAPITAL EXPENDITURE
CAPITAL EMPLOYED
51!>
170
511
214
550
391
548
13521
466
520
-to:>
54i
44,~
14324a
549
320
44ii
260
14124')
444
22'i
311
45 ..
310
================================4bl STATE CONTRldUTIGN
462 ~ElAINED EARNING$
55;DEBT OUTSTANOING-SHORT TERM
554 DEBT OuTSTANDING-LONG TERM
54Z ANNUAL DEBT URAWWPOWN $19&2
543 CUM.DEBT DRAW~DOWN $1982
51~OEdT SERVICE COvER
========403.1
0.0
0.0
0.0
0.0
0.0
0.00
816.4
0.0
0.0
0.0
0.0
O.a
0.00
1356.1
0.0
0.0
0.0
0.0
0.0
(;.00
========1355.6
0.0
0.0
0.0
0.0
0.0
0.00
=::======2194.0
0.0
0.0
0.0
0.0
0.0
0.00
4344.3
0.0
0.0
0.0
0.0
0.0
0.00
5591.4
0.0
0.0
0.0
0.0
0.0
0.00
========6267.8
0.0
0.0
0.0
0.0
0.0
0.00
========6600.9
0.0
98.0
0.0
0.0
0.0
0.00
----------------6830.6
29.5
115.7
0.0
0.0
0.0
0.00
Sheet 1 of 3
100%STATE APPROPRIATION OF TOTAL CAPITAL COST ($5.1 BILLION IN 1982 DOLLARS)
TABLE 18.4.5 [Ii]
*************************************~_~__~~h_.__-_.~-------~*************O**************************O********************OATAI0K WATAhA-0C (ON LINE 1993-20021-·INFLATION 7%-INTEREST 10%-CAP COST $5.117 BN 23-FEB-62
**************************************~~~~~~~~~~~~~~**~*~*~*~**~*~***********************************************~*~***vv******
1991 1998 1999
CASH FLOw SUMMARY
===($HILLIONI====
3387 3387 3381
8.74 8.38 9.04
285.40 305.38 326.75
24.93 27.13 29.53
13 t:NERGY G..i1
521 REAL ~RICE-MILLS
466 INFLATION INDEX
'52;)PRICE-MILLS
-----INCOME-----------------sre R EVENU"
17d LESS OPERATING COSTS
511 JPERATING INCOME
21~'ADO INTEREST EARN~O ON FUNDS
550 LESS INTEREST ON SHORT TERM OEBT
391 L=SS INTEREST ON LONG TERM DEBT
~4~NET EARNINGS FROM OPcRS
-----CASH SOURCE AND USE----
54';C.ASH INCOME fROM OilERS
~4~STATE CONTRIBUTION
143 LONG TERM DEBT ORAWOOWNS
246 WORCAP OEaT ORAWOOwNS
54~TOTAL SOURCES OF FUNDS
320 tESS CAP ITAL EXPENOITURC
44B LeSS ~uRCAP AND FUNDS
?'bO LESS DEBT REPAYMENTS
1995
3367
8.24
l49.26
,!a.55
69.6
32.0
37.6
b.2
11.6
0.0
32.2
32.2
363.1
0.0
iI.l
403.4
395.3
8.1
0.0
1996
3387
B.38
266.73
22.36
75.7
35.0
40.8
6.7
12.4
0.0
35.1
35.1
Ja2.1
0.0
29.3
446.5
411.2
29.3
0.0
84.4
38.1
4b.3
7.3
15.3
0.0
33.3
3B.3
303.B
0.0
11.2
353.3
342.1
11.2
0.0
91.9
41.6
50.2a.o
16.4
O.G
41.8
41.8
102a.3
0.0
12.2
10112.4
1070.1
12.2
0.0
100.0
45.4
54.6
8.7
17.1
0.0
45.6
45.6
1171.5
0.0
10.6
1233.7
1223.2
10.60.0
2000
3387
9.17
349.62
32.06
108.6
49.6
59.0
9.5
18.7
0.0
49.8
49.8
1204.8
O.ll
10.1t
1265.1
1254.6
10.4
0.0
2001
3387
9.30
374.10
34.79
117.8
54.1
63.1
10.4
19.8
0.0
54.4
54.4
913.1
0.0
12.3
979.8
967.5
12.3
0.0
2002
52231.66
400.29
30.64
160.0
91.1
69.0
11.4
21.0
0.0
59.3
59.3
303.0
0.0
128.0
490.3
362.3
128.0
0.0
2003
5414
8.84
42t3.31
31.a6
204.'}
99.4
105.5
19.1
33.8
0.0
90.9
90.9
0.0
0.0
24.7
115.6
90.9
24.7
0.0
2004
5605
8.68
458.29
39.80
223.1
108.5--------114.6
20.9
3b.3
0.0
99.2
99.2
0.0
0.0
42.8
142.0
99.2
42.8
0.0
~42 ~NNUAL OEBT URAWWOOWN 519B2
543 CU~.DEBT ORAwWOOWN 51982
519 DEBT SERVICE COVER
141249
444
22':.
311
45 ..
370
ero5
461
462
555
554
CASH SURPLUS(OEFICIT.SHORT TERM DEBT
CASH RECOVERED
-----BALANCE SHEET----------
RESERVE AND CONT. fUND
OTHER WOaKING CAPITAL
CASH SuRPLUS RETAINEDCUM. CAPITAL EXPENDITURE
CAPITAL EMPLOYED
STATE CDNTRIBUTION
RETAINED EARNINGS
DEBT OUTSTANDING-SHORT TERM
nEBT OUTSTANDING-LONG TERM
0.0
0.0
0.0
67.2
56.6
0.0
7255.4
========
7379.2========7193.7
61.6
123.9
0.0
0.0
0.0
0.00
0.0
0.0
0.0
73.4
79.7
0.0
7672.6========1325.1=======:7575.8
96.8
153.1
0.0
0.0
0.0
0.00
0.0
0.0
0.0
80.1
84.2
0.0
6014.1========8179.0==:=====7879.6
135.1
Ib4.3
0.0
0.0
0.0
0.00
0.0
0.0
0.0
d7.4
a9.1
0.0
90B4.8========9261.4
=====::==
9901.'}
176.9
176 0 6
0.0
0.0
0.0
0.00
0.0
0.0
0.0
95.4
91.7
0.0
1030B.0========10495.1========10085.4
222.6
187.1
0.0
·0.0
0.0
0.00
0.0
0.0
0.0
104.1
93.4
0.0
11562.6========11760.2
========
11290.3
272.4
197.6
0.0
0.0
0.0
0.00
0.00.0
0.0
113.7
96.2
0.0
12530.1========12740.0========12203.4
326.7
209.9
0.0
0.0
0.0
0.00
0.0
0.0
0.0
191.3
146.6
0.0
12692.5========13230.3
=====::==
12506.1t
386.1
337.6
0.0
0.0
0.0
0.00
0.00.0
0.0
208.8
153.8
0.0
12983.3
========
13345.9
:::::==:::::
12506.4
477.0
362.6
0.0
0.0
0.0
0.00
0.0
0.0
0.0
221.8
177.6
0.0
13082.5========13'081.9
========
12506.4
516.1405.1t
0.0
0.0
0.0
0.00
Sheet 2 of 3
100%STATE APPROPRIATION OF TOTAL CAPITAL COST ($5.1 BILLION IN 1982 DOLLARS)
TABLE 18.4.5 [iii]
L_
*****~*~*=***************************~--~~~~••~~~-~--~-~~-~~-~---************~*************************************************OATAI0~WATANA-OC (ON LINE 1993-2002.-INfLATION 7t-INTEREST 10%-CAP COST $5.117 BN 23-FEB-B2
********************¢****************y~y~y~¥¥¥¥¥¥¥~~;~~~~**********************************************************************
320 LESS CAPITAL EXPENDITURE44dLESSWORCAPANDFUNDS
2bG LESS DEBT REPAYHENTS
141 CASH SURPLUSIDEFICITI
24~SHORT TERM DEBT
444 CASH RECOVERED
-----BALANCE SHcET----------225 RESERVE AND CONT.FUND
371 OTHER WOR~ING CAPITAL
454 CASH SURPLUS RETAINED370CUM.CAPITAL EXPENDITURE
40?CAPITAL EMPLOYED
461 STATE CONTRI3UTION462RETAINEDEARNINGS
55~OEBT OUTSTAN~ING-SHURT TERM
554 DEBT OUTSTANDING-LONG TERH
?42 ANNU~l DEBT 0RAftWGOWN $1982
543 CUM.DEBT DRAWWDOWN S1982
~1~UFBT SERVIC~COVER
2007 2008 2009
CASH FLOW SUMMARY
===($HILLION.====
6l?0 6472 65446.33 9.24 8.30
561.42 600.72 642.77
46.75 49.49 53.35
73
521
4b6
52'-1
51~
17a
517
214
55,)
391
!i4o
54;}
440
143
.24:1
549
::NERGY GWH
REAL PRICE-MillS
INflATION INDEX
PR ICE-MillS
-----INCOME-----------------REVENUE
LESS OPERATING CuSTS
OPERATING INCOME
ADO INTfREST EARNED ON FUNDS
LESS INTEREST ON SHORT TERM DE8TLESSINTERESTONLONGTERMDEBT
~ET EA~NiNGS FROM JPERS
-----CASH SOukCE AND USE----
CA5H INCOME FROM OPERSSTATE CONTRIBUTION
LONG TERM DEBT DRAWOOWNS
HORC4P DEBT DRAWDOWNS
TOTAL SOURCES OF FUNDS
2005
b092
8.18490.37
40.12
244.4
113.4
126.0
22.8
40.50.0
108.2
108.20.0
0003&.4
110407
108.2
3&.4000
0.0
0.0
0.0
248.7
193.2
.0.0131'l0.7====:::===
13032.6----------------1250&04
68404
441.B
000
00')
000
0.00
2006
6147
8.27
524.b9
43.39
266.7
129.2
137.4
24.9
44.2
0.0
118.1
1113 .10.0
0.0
51.3
169.4
113.151.30.0
0.0
0.00.0
271.4
221.7
0.01330B.9========13801.9========12506.4
802.5
4'H.1
0.0
0.0
0.0
0.00
2q l..1
14100
151.1
27.1
49030.0--------128.9
128.9
0.0
0.0
59.3
188.2
128.'159.30.0
0.00.0
0.0
2'10.2256.2
0.013437.8========13Q'l0.2========1250b.4
931.4
55~.4
0.0
0.00.0
0.00
320.3
153.9
166.3
29.6
55.20.0
140.7
140.7O.C
O.C
45.B
186.5
140.745.80.0
000
000000
323.3274.9
0.013578.5========14176.7========1250b.4
1072.1
Sn.2
0.0
0.0
0.0
0.00
349.1
16B.0
181.1
32.3
59.80.0
153.6
153.b
0.0
0.0
45.9
199.4
153.645.90.0
0.0
0.00.0
352.8
29102
0.013732.1==:=====1437601========12506.4
1225.7
b44.0
0.0
0.0
0.0
0.00
2010
6616
8.35
687.77
57.45
380.1
183.4--------196.7
35.3
64.40.0
167.6
167 06
0.0
0.0
52.0
219.6
167.6
52.00.0
0.00.0
0.0
3B5.1
310.9
0.013899.1========14595.7========12506.4
1393.3
696.0
0.0
0.0
0.0
0.00
2011
6638
8.48
735.91
62.39
414 01
200.1
214.0
33.5
b9.60.0
18Z.9
182.90.0
0.0
37.7
220.6
182.937.7
0.0
0.00.00.0
420.3
313.4
0.014082.6----------------14816.3========12506.4
1576.3
733.7
000
0.0
0.0
0.00
2012
6660
8.57
787.42
67.48
449.4
21B.4
231.0
42.0
73.40.0
199.7
199.7
0.0
0.0
41.2
240.8
199.7
41.20.0
0.0
0.0
0.0
458.7316.2
0.014282.3========15051.1=======::12506.4
1715.9
774.B
0.0
0.0
0.0
0.00
2013
66B2
B.67
842.54
73.02
4U7.9
238.4
249.5
45.9
77.50.0
217.9
217.9
0.0
0.0
lt4.'l
262.B
217.944.9
0.0
0.0
0.00.0
500.6319.2
0.014500.2::=====::=15319.9=======:12506.4
1993.8
819.7
0.0
0.0
0.0
0.00
TOTAL
1046260.00
0.00
0.00
4530.0
22 02.0--------2328.0
412.4
146.60.0
1993.8
1993.8
12506.4
0.0
819.7
15319.9
14500.2
819.70.0
0.00.0
0.0
500.6319.2
0.014500.2;=;::====
15319.9========12506.1t
1993.8
819.7
0.0
0.0
0.0
0.00
Sheet 3 of 3
TABLE18.4.5 [iii]
<---....__.e...-..__._.~'
*******************************************************************************************************************************DATAI0K WATANA-DC (ON LINE L993-20021-$3.0 BN($1982)STATE FUNDS-INFLATION 1~-INTEREST 10%-CAPCOST $5.117 BN 23-FEB-82
*******************************************************************************************************************************
:;t,.,}
465
548
440
143
24f:l
225111
454
310
3387
34.38232.91
80.06
0.0
0.00.0
199"
271.2
29.3
2"1.95.6
9.6
183."--------54.3
54.3
0.0
211.611.1--------283.1
259.211.7
6.8
219.3
26.9
38.5
0.0
294.698.0
1993
0.0
0.00.0
431.1
333.198.00.0
338129.74
217.13
6".16
192.40.0
0.0
154.0--------36.5
56.5 61.6
"1.5 5".10.0 0.06619.4 6938.6======:=::==~=:=6711.4.105".3
=~s===~=aaZB~=a=
4806.1 4006.1
38.5 92.8
98.0 U5.?
18 34.2 2039.a
135.3 90.8
918.9 1009.1
1.25 1.25
0.0
0.0
754.9
0.0
0.0
0.0
0.00.0
0.0
0.0
1992
o0.00203.48
0.00
154.9
154.90.00.0
0.00.0
0.0
0.0
0.00.0
0.0
6346.3========63"6.3::=======
4806.1
0.0
0.0
1539.5
311.0
783.6
0.00
1991
a0.00
190.11
0.00
0.0
0.00.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0462.4
184.70.0
1241.1
1241.10.00.0
"806.10.0
0.0
18".7
412.6
412.6
0.00
========
0.0
0.0
0.0
5591.4========5591.4
1990
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
a0.00
111.13
0.00
0.01550.4
0.0
0.0
1550.4
1550.4
0.0
0.0
43"".30.0
0.0
0.0
0.0
0.0
0.00
0.0
0.0
0.0
4344.3========4344.3========
0.0
0.00.0
0.0
938.3
0.00.0
0.0
0.0
938.3
938.30.00.0
0.0
0.0
0.0
0.0
0.0
o0.00
166.10
0.00
2794.00.0
0.0
0.0
0.0
0.0
0.00
2794.0
0.0
0.0
0.0
2794.0======:=
========
0.0
499.5
0.00.0
0.0
0.0
0.0
0.0
499.5
499.5
0.00.0
0.0
0.0
0.00.0
0.0
0.0
0.0
Q.O
0.0
1655.6
1655.6
0.0
0.0
0.0
0.0
0.0
0.00
1855.6========
========
479.70.00.0
0.0
0.0
0.0
1997 1966 1989
CASH FLOW SUMMARY
===I$MILLIONI====a 00.00 0.00
145.08 L55.24
0.00 0.00
0.0
0.0
0.0
0.0
0.0
479.1
0.00.0
0.0
0.0
419.1
0.0
1356.10.0
0.0
0.0
0.0
0.0
0.00
:======:
0.0
0.0
0.0
1356.1========L356.L
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1986
0.0
0.0
0.0
B76.4
0.0
0.0
0.0
0.0
0.0
0.00
0.0472.1
0.0
0.0
876.4
472.1
472.7
0.00.0
0.0
0.0
0.0
876.4
o0.00135.59
0.00
====::;:==
========
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.00.0
1985
403.1
0.0403.7
0.0
0.0
403.1
403.10.00.0
403.10.0
0.0
0.0
0.0
0.0
0.00
0.0
0.0
0.0
403.7
o0.00
126.720.00
==:=:;:===
.:=======
13 ENERGY GWH
521 REAL PRICE-MILLS
466 INFLATION INDEX
520 PRICE-MILLS
-----INCOME-----------------
REVEUUE
lESS OPERATING COSTS
OPERATING INCOMEADOINTERESTEARNED ON FUNDS
LESS INTEREST ON SHORT TERM DEST
LESS INTEREST ON LONG TERM DEBT
NET EARNINGS FROM OPERS
----~tASH SOURCE AND US[----
CASH INCOME FROM OPERS
STATE CONTRIBUTION
LONG TERM DEBT DRAWDOWNS
WORCAP DE8T DRAWDOWNS
TOTAL SOURCES OF FUNDS
LESS CAPITAL EXPENDITURELESSWORCAPANDFUNDSLESSDEBTREPAYHENTS
:ASH SURPLUSIDEFICITISHORTTERMDEBTCASHRECOVERED
-----BALANCE SHEET----------
~ESERVE AND CONT.FUND
aTHER WORKING CAPITAL
CASH-SURPLUS RETAINED
CUM.CAPITAL EXPENDITURE
CAPITAL EHPL3YED
STATE CONTRIBUTIONRETAINEDEARNINGS
DEBT OUTSTANDING-SHORT TERM
DEBT OUTSTANDING-LONG TERM
ANNUAL DEBT DRAWWDOWN 51982
CUM.DEBT DRAWWDOWN $198Z
DEBT SERVICE COVER
516
110
511
lh
55!)
391
548
320
448260
141249
444
461
462
555
554
542
543
519
$3 BILLION (1982 DOLLARS)STATE APPROPRIATION SCENARIO
7%INFLATION AND 10%INTEREST
Sheet 1 of 3
TABLE 18.4.6 Ii]
c..
.----,-_.-~~
*******************************************************************************************************************************DATAI0K WATANA-DC (ON LINE 1993-2002)-$3.0 g~I('1982)STATE FUNDS-INfLATION It-INTEREST 10%-CAPCOST 15.117 aN 23-FEB-82*******************************************************************************************************************************
1991 1998 1999
CASH FLOW SUMMARY
===(I~ILLION)====
3387 3387 3381
29.37 27.83 26.39
285.40 305.38 326.15
83.81 84.97 86.2~
73
521
466
:i20
516
170
517
2H
55?
391
548
543
446
143
243
549
320441)
261)
141
249
444
225
311
454
310
465
461
462
555
554
542
543
519
ENERGY GWH
REAL PRICE-HILLS
INFLATION INDEX
P~ICE-MILlS
-----INCOHE-----------------
KEVENUE
LESS OPERATING COSTS
OPERATING I~COME
ADO INTEREST EARNED ON FUNDS
LESS INTEREST ON SHORT TERM DEBT
lESS INTEREST ON LONG TERM DEBT
NET EARNINGS FROM OPERS
-----CASH SOURCE AND USE----
CASH INCOME FROM OPERS
STATE CONTRIBUTION
LONG TERM DEBT DRAWDOWNS
WORCAP DEBT DRAWDOWNS
TOTAL SOURCES OF FUNDS
lESS CAPITAL EXPENDITURE
LESS WORCAP AND FUNDS
lESS DEBT REPAYMENTS
CASH SURPlUS(DEFICIT)
SHORT TERM OEBT
CASH RECOVERED
-----BAlANCE SHEET----------
RESERVE ANO CONT.FUND
OTHER WORKING CAPITAL
CASH SUPPlUS RETAINED
CUM.CAPITAL EXPENDITURE
CAPITAL EMPL~YED
STATE CONTRIBUTION
RETAINED EARNINGS
JEST OUTSTANDING-SHORT TERM
DEBT OUTSTANDING-LONG TeRM
ANNUAL DEBT ORAWWDOWN $1982
CUM.DEBT DRAWWDOWN $1982
DEBT SlRVICE COVER
1995
3381
32.59
249.28
31.25
215.2
32.0
243.1
6.2
11.6
IB2.7
55.0
55.0
0.0
368.9
3.1
432.0
416.4
8.1
7.4
0.0
0.0
0.0
61.2
56.6
0.0
1355.0========1478.8========4806.1
147.8
123.9
2400.5
14S.0
1151.1
1.25
1996
3331
30.81
266.13
82.18
278.3
35.0
243.4
6.1
12.4
182.0
55.7
55.7
0.0
427.1
29.3
512.8
475.3
29.3
0.2
0.0
0.0
0.0
73.4
79.7
0.0
7B30.3========19B3.4========4806.7
203.5
153.1
2820.0
160.4
1318.0
1.25
2B3.8
38.1
245.1
7.3
15.3
181.2
56.6
56.6
0.0
395.4
11.2--------463.1
442.9
11.2
9.0
0.0
0.0
0.0
aO.l
B4.2
0.0
8273.2=::======8431.5======:=4806.1
260.1
Ib4.3
3206.4
138.5
1456.6
1.25
281.8
41.6
246.2
8.0
Ib.4
1'30.3--------51.5
51.5
0.0
1163.0
12.2--------1232.7
1210.5
12.2
9.9
0.0
0.0
0.0
al.4
89.1
0.0
9483.7========9660.3
========
4806.7
311.5
116.6
4359.4
380.8
1831.4
1.25
292.1
45.4
246.6
8.7
17.1
179.3
58.4
58.4
0.0
1432.3
10.6--------1501.3
1419.8
10.6
10.9
0.0
0.0
0.0
95.4
91.1
0.0
10963.5========11150.6========4806.7
376.0
187.1
51BO.8
438.3
2215.7
1.25
2000
3381
25.04
349.62
87.54
296.5
49.6
246.9
9.5
18.7
118.2
59.5
59.5
0.0
1604.7
10.4--------1674.1
1654.5
10.4
12.0
-2.3
2.3
0.0
104.1
93.4
0.0
12618.0==:====:
12815.6-========4806.7
435.5
199.8
1373.5
459.0
2734.7
1.25
2001
3387
23.79
374.10
89.00
301.4
54.1
241.3
10.4
20.0
117.0
60.1
60.1
0.0
1413.5
12.3--------1546.5
1527.9
12.3
13.2
-6.8
6.8
0.0
113.1
96.2
0.0
14145.9========14355.8
=======:
4806.7
496.2
21 ehO
8833.8
393.9
3128.6
1.25
2002
5223
58.55
400.29
2H.36
1224.0
91.1
1132.9
11.4
21.9
883.4--------239.0
239.0
0.0
137.8
128.0--------504.B
362.3
12B.0
14.5
0.0
0.0
0.0
19.1.3
146.6
0.0
14508.2
========lIt846.1
==ZI::8==
4806.7
735.2
346.9
8957.1
34.4
3163.0
1.25
2003
5H4
55.54
428.31
237.89
1287.8
99.4
1188.4
19.1
34.7
895.7
211.2
271.2
0.0
0.024.7--------301.9
90.9
24.7
42.6
143.7
-9.1
134.6
208.8
153.8
0.0
1"599.1
===:::z~=
H961.7
::1:======
"806.7
877.8
362.6
8914.6
0.0
3163.0
1.25
2004
5605
50.49
458.29
231 ..37
1296.7
108.5
1188.2
20.9
36.3
891.5--------2811.4
281.4
0.0
0.0
42.8--------324.3
99.2
42.8
46.8
135.4
0.0
135.4
227.8
177.6
0.0
14698.3=======2
15103.1
:z~z=====
4806.7
1023.8
405.4
8861.7
0.0
3163.0
1.25
$3 BILLION (1982 DOLLARS)STATE APPROPRIATION SCENARIO
7%INFLATION AND 10%INTEREST
Sheet 2 of 3
TABLE 18.4.6 [iii]
r-------~,c:~~.
**************************************************************************~**************~***~***********************v********~nATA10~WATANA-OC CON LINE 1993-Z002)-~3.0 3NCS1982)STATE FUNDS-INFLATION 7%-INTEREST 10%-CAPCOST $5.111 BN 23-FEB-82
**************************************************************************************~****************************************
2005 2006 2007 2008 2009 Z010 2011 2012 2013 TOTAL
CASH FLOW SUMMARY
===C$MILLION)====
73 ENERGY GWH 60n 6147 6250 6472 6544 6616 6638 6660 6682 10lt826
521 ~EAL PRICE-MILLS 43.82 40.97 38.08 34.79 32.53 30.45 28.74 27.13 25.63 0.00466INFLATIONINDEX4'l0.37 524.69 561.4Z 600.72 642.11 687.77 135.91 781.lt2 8ltZ.51t 0.00
520 PRICE-MillS 214.89 214.98 213.19 208.98 209.12 209.41 211.54 213.62 215.95 0.00
-----INCOME-----------------
516 ~EVENIJE 1309.0 1321.4 1336.1 1352.4 1368.4 1385.3 1404.1 1It22.6 1442.9 18656.4
110 LESS OPERATING COSTS 118.4 129.2 141.0 153.9 168.0 183.4 200.1 218.4 238.4 2Z02.0------------------------------------------------ ---------------- ----------------517 DPERATING INCOME 1190.6 1192.2 1195.0 1198.5 lZ00.4 1202.0 1204.0 1204.2 1204.5 16454.~
214 AD!>l"TEREST EAR~ED ON fUNDS 22.8 24.9 27.1 29.6 32.3 35.3 38.5 42.0 45.9 ~12.4
550 lESS INTEREST ON SHORT TERM DfBT 40.5 44.2 49.3 55.2 59.8 64.4 69.6 73.4 17.5 148.6
391 l~SS INTEREST ON LONG TERM DEBT 886.8 881.6 876.0 869.7 862.9 855.3 847.0 831.9 821.9 12013.6------------------------------------------------ ---------------- ----------------548 NET EARNINGS FROM OPERS 286.1 291.2 296.9 303.1 310.0 317.5 325.8 335.0 345.0 4104.6
-----C~SH SOURCE AND USE----
548 CASH INCOME FROM OPERS 286.1 291.2 296.9 303.1 310.0 311.5 325.8 335.0 345.0 Itl04.6
446 STATE CONTRIBUTION 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4806.1
143 LONG TERM DEBT DRAWDOWNS a.o 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9049.0
243 WORCAP DEBT DRAWDOWNS 36.4 51.3 59.3
.45.8 45.9 52.0 37.7 41.2 44.9 819.1------------------------ -------- ------------------------------------------------54.TOTAL SOURCES QF FUNDS 322.5 342.5 356.2 349.0 355.9 369.5 363.6 316.1 389.9 18180.1
3Z0 LESS CAPITAL EXPENDITURE 10B.2 118.1 12B.9 140.1 153.6 167.6 182.9 199.1 211.9 16115.9441LESSWORCAPANDFUNOS36.4 51.3 59.3 45.13 45.9 52.0 31.1 41.2 44.9 819.1
260 LESS DEBT REPAYMENTS 51.5 56.1 62.3 68.6 75.4 83.0 91.3 100.4 110.4 880.9--------------------------------------------------------------------------------141 CASH SURPLU$CDEFICITJ 12·!>.3 116.4 105.6 93.9 81.0 61.0 51.6 34.9 16.1 963.5249SHORTTERHD~8T 0.0 0.0 0.1)0.0 0.0 0.0 0.0 0.0 0.0 0.0
444 CASH RECOVERED 126.3 116.4 105.6 93.9 81.0 67.0 51.6 34.9 16.7 963.5
-----BALANCE SH£fT----------225 RESERVE ANO CONT.FUND 24'3.7 271.4 296.2 323.3 352.8 385.1 420.3 ~58.7 500.6 500.6
311 JTHER WORKING CAPITAL 193.2 221.1 256.2 214.9 291.2 310.9 313.4 316.2 319.2 319.2
454 CASH SURPLUS RETAINEO 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
370 CUM.CAPITAL EXPENDITURE 14306.5 14924.6 15053.6 15194.3 15347.9 15515.5 15698.4 15898.1 16116.0 16116.0========================:==================================================::=a:465 CAPITAL EHPLOYED 15248.3 15411.1 15605.9 15192.4 15991.9 16211.4 16'*32.1 16612.9 16935.1
16935.1=========:=======:======================================::=::::&=~~===z==:3S==S=461 STATE CONTRl~UTION 4806.1 4806.1 4806.7 4806.7 4806.7 4806.7 4806.1 4806.1 4806.1 4806.7
4~2 RETAINED EARNINGS 1183.5 1358.3 1549.6 1158.9 1981.9 2238.5 2512.7 2812.8 3141.1 3141.1
555 DEBT OUTSTANDING-SHORT TERM 441.3 493.1 552.4 598.2 644.0 696.0 133.1 114.8 819.1 819.1
554 DcBT OUTSTANOING-lIJNG TERM 8816.2 8759.5 8697.2 3628.6 8553.2 8410.2 8378.9 8218.6 8168.1 8168.1
542 ANNLAl DEBT ORAwWOOWN $1962 1).0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3163.0
'543 CUM.DE8T ORAWWDOWN $1982 3163.0 3163.0 3163.0 3163.0 3163.0 3163.0 3163.0 3163.0 3163.0 3163.0
519 DEBT SERVICE COVER 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 0.00
Sheet 3 of 3
$3 BILLION (1982 DOLLARS)STATE APPROPRIATION SCENARIO
7%INFLATION AND 10%INTEREST TABLE 18.4.6 •
!_--
r=:o-
!_--~.----l
*******************************************************************************************************************************DATA10K WATANA-OC (ON LINE 1993-2002t-$2.3 BN ($1982J STATE FUNDS-INFLATION 7~-INTEREST lOt-CAP COST S5.117 BN 23-FEB-82*******************************************************************************************************************************
1985 1966 1987 1966 1969 1990 1991 1992 1993 1990\
CASH FLOW SUMMARY
===(SMILLION)====73 ENERGY GI'lH 0 0 0 0 0 0 0 0 3387 3387521REALPRICE-HILLS 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 50.85 58.76466INFLATIONINDEX126.12 135.59 145.08 155".24 166.10 177.73 190.17 203.48 211.13 232.97
520 PRICE-HILLS 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 110.13 136.90
-----INCOHE-----------------516 REVENUE 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 375.0 463.6
110 LESS OPERATING C~STS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 26.9 29.3------------------------ --------------------------------------------------------511 OPERATING INCOME 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 348.1 431t.3214ADDINTERESTEA~NED ON FUNDS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 5.6
550 LESS INTEREST ON SHORT TERM DEBT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.8391LESS INTEREST ON LONG TERM OE6T 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 303.1 331.9--------------------------------------------------------------------------------548 ~ET EARNINGS FROM OPERS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1t5.0 98.3
-----CASH SOuRCE AND USE----548 CASH INCOME fROM OPERS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 45.0 98.3446STATECONTRIBUTION403.7 412.7 419.1 499.5 936.3 138.4 0.0 0.0 0.0 0.0143LONGTERHDEBTDRAWDOWNS0.0 0.0 0.0 0.0 0.0 812.0 1328.3 890.4 286.1 113.2248WORCAPDEBTDRAI'lDOWNS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 98.0 11.1------------------------ -------------------------------- -------- ----------------.549 TOTAL SOURCES Of fUNDS 403.1 472.1 419.7 499.5 938.3 1550.4 1328.3 890.4 431.1 289.2
320 LESS CAPITAL EXPENDITURE 403.1 412.1 479.1 499.5 938.3 1550.4 1328.3 890.4 333.1 259.2448LESSWORCAPANDfUNDS0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 98.0 11.7260LESSDEBTREPAYMENTS0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 12.2------------------------ ------------------------ --------------------------------141 CASH SURPLUS(DEfICITt 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0249SHORTTERMDE8T0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
444 CASH RECOVERED 0.0 0.0 0.0 0.0 0.0 0.0
0.0 0.0 0.0 0.0
-----8ALANCE SHEET----------225 RESERVE AND CONT. fUND 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 56.5 61.63711THERWORKINGCAPITAL0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 41.5 54.1
454 CASH SURPLUS RETAINED 0.0 0.0 0.0 0.0 (l.0 0.0 0.0 0.0 0.0 0.0370CUM.CAPITAL EXPENDITURE 403.1 816.4 1356.1 1855.6 2194.0 4344.3 5612.6 6563.0 6896.1 7155.3
465 CAPITAL EMPLOYED =================================================~=======:========z:========:===403.7 816.4 1356.1 1855.6 2794.0 4344.3 5612.6 6563.0 6994.1 1211.0=====:========================================================== ==========:=====461 STATE CONTRIBUTION 403.1 676.4 1356.1 1855.6 2194.0 3532.4 3532.4 3532.1t 3532.0\3532.1t
462 RETAINfD EARNINGS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
45.0 Ilt3.3
555 DEBT OUTSTANDING-SHORT TERM 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 98.0 115.1
554 DEBT OUTSTAN~ING-LONG TERM 0.0 0.0 0.0 0.0 0.0 812.0 2140.2 3030.1 3318.7 3lt19.6
542 A~NUAl DEBT DRAWWDOWN $1982 0.0 0.0 0.0 0.0 0.0 456.6 698.4 431.6 132.3 14.3
543 CUM.DEBT DRAWWDOWN $1982 0.0 0.0 0.0 0.0 0.0 456.8 1155.3 1592.9 1125.2 1799.5
519 DEBT SERVICE COVER 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.15 1.25
Sheet 1 of 3
$2.3 BILLION (1982 DOLLARS)MINIMUM STATE APPROPRIATION SCENARIO
7%INFLATION AND 10%INTEREST TABLE 18.4.7
[iJ
'--•.--___-,.---1
*****************************************************~****************************~**********************************~*********DATA13K wATANA-~C ION LINE 1993-2002)-£2.3 eN 1£1982)STATE FUNDS-INFLATION 1t-INTEREST 10%-CAP COST '5.111 BN 23-FEB-82*******************************************************************************************************************************
$2.3 BILLION (1982 DOLLARS)MINIMUM STATE APPROPRIATION SCENARIO
7%INFLATION AND 10%INTEREST
1991 1998 1999
CASH FLOW SUMMARY
===C.MlllluN)====
3387 3381 3381
49.21 46.43 43.18285.40 305.36 326.15
140.03 141.19 143.06
TABLE 18.4.7
13 ENERGY GWH521REALPRICE-MILLS466INFLATIONINDEX
520 PRICE-MILLS
-----INCOME-----------------
516 ~EVENUE
170 LESS OPERATING COSTS
511 JPERATING INCOME
214 ADO INTEREST EARhED ON FUNDS
550 LESS INTEREST ON SHORT TERM OE6T
391 LESS INTEREST ON LONG TERM DEBT
;4u NET EARNINGS FRQM OPERS
-----CASH SOURC~AND US[----~4a CASH INCOME FROM OPERS
446 STATE CONTRIBUTION
143 LONG TERM DEBT ~RAWDOWNS
243 WORCAP DEBT ORAWOOWNS·
549 TOTAL SOURCES OF FUNDS
320 LESS CAPITAL EXPENDITURE446lESSWORCAPANDFUNDS
260 lESS DEaT REPAYMENTS
141 CASH SURPlUSIDEFICITJ249SHORTTERMDEBT
444 CASH RECOVERED
-----BAlANCE SHEET----------225 RESERVE AND CONT.FUNO
311 JTHER WORKING CAPITAL
454 CASH SURPLUS RETAINED
310 CUM. CAPITAL EXPENDITURE
465 CAPITAL EMPLOYED
4bl STATE CONTRIBUTION
462 RETAINED EARNINGS
555 DEBT OUTSTANDING-SHORT TERM554DEBTOUTSTANDING-LONG TERM
542 ANNUAL DEBT DRAWWDOWN $1982
543 CUM.DEBT ORAWWDOWN 51982
51J DEBT SERVICE COVER
Sheet.2 of 3
1995
3387
55.36249.26
138.06
461.6
32.0--------435.6
6.2
11.6
330.6
99.5
99.5
0.0
326.5
8.1
434.2
412.6
6.1
13.5
0.00.0
0.0
67.2
5b.6
0.0
1561.9=:======1691.7========3532.4
242.8
123.93192.1
131.0
1930.5
1.25
1996
33tH
52.11266.13
139.00
410.8
35.0
435.8
6.1
12.4
329.3--------100.8
100.80.0
381.2
29.3
511.3
4b7.2
29.3
14.6
0.0
0.0
0.0
13.4
79.7
0.0
6035.1=::==:===
3168.2========3532.4
343.1
153.14159.0
1'.2.92013.4
1.25
41b.3
38.1--------438.1
1.3
15.3
321.8
102.3
102.30.0
344.2
11.2--------457.1
430.211.2
16.3
0.00.0
0.0
60.1
84.2
0.0
6465.3========8629.6========3532.4
446.0
164.3
4486.9
120.6
2194.0
1.25
480.2
41.6
438.6
8.0
16.4
326.2--------104.0
104.0
0.0
1106.b
12.2--------1222.6
1192.1
12.211.9
0.00.0
0.0
81.4
89.1
000
9651.9========9634.5========3532.4
550.0
116.6
5575.6
362.42556.3
1.25
484.5
45.4
439.1
8.1
17.1
324.4
105.8
105.60.0
1310.3
10.6
1486.6
1456.3
10.6
19.1
0.00.0
0.0
95.4
91.1
0.0
11114.2=======:11301.4========3532.4
655.1181.1
6926.2
419.42915.7
1.25
2000
3381
41.29349.62
144.36
488.9
49.6
439.3
9.5
18.1
322.4
101.7
101.1
0.0
1538.8
10.4
1651.0
1624.8
10.421.1
0.0
0.0
0.0
104.1
93.4
0.0
12139.1========12936.6========3532.4
763.4
197.6
6443.3
44.0.1
3415.8
1.25
2001
3381
38.96314.10
145.15
493.6
54.1--------439.5
10.4
19.8
320.3--------109.9
109.90.0
1405.6
12.3--------1527.8
1491.6
12.3
23.9
0.00.0
0.0
113.1
96.2
0.0
14230.7
========14440.5
========
3532.4
873.3
209.9
9825.0
315.1
3191.5
1.25
2002
5223
63.51400.29
254.41
1329.0
91.1
1231.9
11.4
21.0
982.5--------245.8
245.80.0
142.8
128.0--------516.5
362.3
128.0
26.2
0.0
0.0
0.0
191.3
146.6
0.0
14593.0========14930.B-=====:=3532.4
lU9.1
337.8
9941.5
35.13827.2
1.22
2003
541459.90
428.31
256.58
1389.0
99.4
12B9.6
19.1
33.8
9940.1--------280.8
280.80.0
0.0
24.1
305.5
90.9
24.7
53.9
136.0
0.0
136.0
206.8
153.B
0.0
14683.8========15046.4=:=:====
3532.4
1263.9
362.6
9887.6
0.0
3827.2
1.22
2004
5605
55.83
458.29
255.86
1434.0
108.5
1325.5
20.9
36.3
988.8--------321.3
321.3
0.0
0.0
42.8
364.2
99.2
42.8
59.3
162.80.0
162.8
221.8171.6
0.0
14183.0======-==15188.4
=~a=====
3532.4
1422.it405.4
9828.2
0.0
3827.2
1.25
•
L-,._-.-J __---i ~
********~*******************************************************************************~~**************~****************~***v*DATAI0K WATANA-DC (ON LINE 1993-2002)-$2.3 9N ($1982)STATE FUNDS-INFLATION 1%-INTEREST lot-CAP COST $5.111 BN 23-FEB-82*******************************************************************************************************************************
2005 2006 2001 2003 2009 2010 2011 2012 2013 TOTAL
CASH FLOW SUMMARY
===($MILLIONJ====
13 ENEIlGY GWH 6092 6141 6250 6412 6544 6616 6638 6660 6682 104826521REAL?RICE-MILLS 48.42 45.23 41.99 38.32 35.80 33.46 31.55 29.15 28.01 0.00466I~FLATION INDEX 490.31 524.69 561.42 600.72 642.11 681.77 135.91 187.42 842.54 0.00
520 PRICE-MILLS 237.42 237.31 235.75 230.18 230.09 230.15 232.21 234.23 236.49 0.00
-----INCOME-----------------
516 REVENUE 1446.3 1458.6 1413.3 1489.6 1505.6 1522.6 1541.3 1559.8 1580.1 21929.6
110 LESS OPERATING COSTS 118.4 129.2 141.0 1')3.9 168.0 183.4 200.1 218.4 238.4 2202.0-------------------------------- -------- ------------------------ ----------------511 OPERATING INCOME 1321.8 1329.4 1332.3 1335.1 1337.6 1339.2 1341.2 1341.4 1341.7 19727.62HADOINTfRESTEARNEDONFUNDS22.8 24.9 21.1 29.6 32.3 35.3 38.5
42.0_45.9 412.4
55D LESS INTEREST ON SHoaT TERM DEBT 40.5 44.2 49.3 55.2 59.8 64.4 69.6 13.4 71.5 146.6391LESS INTEREST ON LONG TERM DE8T 982.8 916.3 969.1 961.2 952.5 943.0 932.5 920.9 908.2 14428.0-------------------------------------------------------- ---------------~--------543 NeT EARNINGS fROM ~PERS 321.3 333.8 341.0 348.9 357.5 367.1 377.6 369.2 401.9 4965.4
-----CASH SOURCE AND USE----
54~CASH INCOME FROM OPERS 327.3 333.8 341.0 348.9 351.5 361.1 317.6 389.2 401.9 4965.4
446 STATE CONTRI3UTION 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3532.4
143 LuNG TERM DEST ORAWDOWNS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 10101.8
248 WORCAP DE8T ORAWDOWNS 36.4 51.3 59.3 45-.8 45.9 52.0 31.1 41.2 44.9 819.7------------------------------------------------------------------------ --------5H TOTAL SOURCES OF FUNDS 363.1 365.0 400.2 394.1 403.4 419.0 415.3 430.3 446.6 19425.3
320 LESS CAPITAL EXPENDITURE 108.2 118.1 128.9 140.1 153.6 167.6 182.9 199.7 211.9 16200.1
448 LESS WORCAP AND FUNDS 36.4 51.3 59.3 45.8 45.9 52.0 31.1 41.2 44.9 819.7
260 LESS DEBT REPAYMENTS 65.2 11.8 19.9 86.8 95.5 105.1 115.6 121.1 139.9 1165.5---------------- ---------------- ------------------------------------------------141 CASH SURPLUS(DEFICIT)153.8 143.9 133.1 121.3 108.4 94.4 79.1 62.4 44.1 1239.3
24~SHORT TERM DEBT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
444 CASH RECOVERED 153.8 143.9 133.1 121.3 108.4 910.4 19.1 62.4 44.1 1239.3
-----BALANCe SHEEl----------
225 RESERVE AND CONT.FUND 248.7 271.4 296.2 323.3 352.e 385.1 420.3 458.1 500.6 500.6
371 OTHER WORKING CAPITAL 193.2 221.1 256.2 274.9 291.2 310.9 313.4 316.2 319.2 319.2
454 CASH SURPLUS RETAINED 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
370 CUM.CAPITAL EXPENDITURE 14891.3 15009.4 15138.3 15279.0 15432.6 15600.2 15783.2 15982.8 16200.7 16200.7=============================================================================z==465 CAPITAL EMPLOYED 15333.1 15502.5 15690.7 15811.2 16076.6 16296.2 16516.8 16151.6 11020.5 17020.5================================================================================461 STATE CONTRIBUTION 3532.4 3532.4 3532.4 3532.4 3532.4 3532.4 3532.4 3532.4 3532.4 3532.4
462 ~ETAINED EARNINGS 1595.9 1185.8 1993.7 2221.2 2410.3 2143.0 3041.5 3368.3 3726.1 3726.1
555 aEBT OUTSTANDING-SHORT TERM 441.8 493.1 552.4 598.2 644.0 696.0 133.7 774.8 819.7 819.7
554 OEBT OUTSTANDING-LONG TERM 9163.0 9691.2 9612.3 9525.4 9429.9 9324.8 9209.2 9082.1 8942.2 8942.2
542 ANNUAL DEBT DRAwwOOWN $1982 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3821.2
543 CUM.DEBT DRAwWOOWN $1982 3821.2 3827.2 3827.2 3821.2 3821.2 3827.2 3821.2 3821.2 3827.2 3821.2
~lq DEBr SERVICE COVER 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 -1.25 0.00
Sheet 3 of 3
$2.3 BILLION (1982 DOLLARS)MINIMUM STATE APPROPRIATION SCENARIO
7%INFLATION AND 10%INTEREST TABLE 18.4.7 [i]
L-_'---'
$1.8 BILLION (1982 DOLLARS)STATE APPROPRIATION SCENARIO
7%INFLATION AND 10%INTEREST I ~
FINANCIAL ANALYSIS TABLE 18.4.8 •
I
******************~t********************************************~******~,********************************************************OATAI0K WATANA-DC (ON LINE 1993-20021-£1.3 &N (L19821 STATE FUNDS-INFLATION 7Z-INTEREST 10%-CAP COST L5.117 BN 23-FEB-82
****************************************~=**********************=~***************************************************¢*********~~
19B5 1986 1931 19B8 1989 1990 1991 1992 1993 1994
4'H.O
29.3
260.2
259.211.716.4
-33.1
33.1
0.0
467.1
5.6
16.1444.4
12.B
0.0
229.7
17.1
12.8
61.654.1
0.07356.9
2653.5
-50.2
211.8
4657.4
9B.62476.5
0.99
3387
62.99
232.91
146.75
7412.6========
=======:
431.1
333.198.0
0.0
-63.0
-63.0
0.0
396.1
98.0
0.0
0.0
0.0
348.1O.C
0.0
411.L
315.0
26.9
338750.B5
211.73
110.73
56.5
41.5
0.0
1091.1========1195.1=:======2653.5
-63.0
161.0
4444.1
181.92371.9
0.35
0.0
0.0
988.6
988.6
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
988.6
0.0
0.0
0.0
0.0
0.0
a
0.00
203.48
0.00
2653.5
0.0
0.0
4111.0
485.8
2196.0
0.00
6164.6
0.0
0.0
0.0
6764.6
========
========
a
0.00
190 .11
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
5715.9
0.0
0.0
0.0
5175.9
2653.5
0.0
0.0
3122.4
745.4
1110.1
0.00
0.0
0.0
1417.6
0.0
1411.6
1417.6
0.0
0.0
========
========
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
a
0.00
117.73
0.00
1564.4
1564.4
0.0
0.0
2653.5
0.0
0.0
1704.8
B80.2964.1
0.00
0.0
0.0
0.0
4358.4
0.0
0.0
1564.4
0.0
4358.4==:=====
========
84.5
84.5
0.00
0.0
0.0
0.0
938.3
938.3
0.0
0.0
0.0797.9
140.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2794.0
a
0.00
166.100.00
2653.5
0.0
0.0
140.4
2794.0========
========
0.0
0.0
499.5
499.5
0.00.0
0.0
0.00.0
0.0
0.0
499.~
0.0
0.0
0.0
0.0
0.0
0.0
1855.6
0.0
0.0
0.0
0.0
0.0
0.00
O.G
0.0
0.01855.6
1855.6
----------------
:=======
0.0419.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
479.7
419.1
0.0
0.0
0.0
CASH FLOW SUMMARY
===(5MILLIONI====()0
D.OO 0.00
145.08 155.24
0.00 0.00
0.0
0.0
0.0
0.0
1356.1
0.00.0
0.0
1356.1
1356.1
0.0
0.0
0.0
0.0
0.0
0.00
========
===::====
0.0
0.0
0.0
0.0
0.0
0.0
0.00
0.0
0.0
0.0
0.0
0.0
0.0
876.4
0.0
0.0
0.0
616.4
0.0
0.0
0.0816.4
0.0412.1
0.0
0.0
412.1
412.7
0.0
0.0
a0.00
135.59
0.00
========
========
0.0
0.0
0.0
0.0
0.0
0.3
0.0
0.0
0.0
0.0
403.1
0.0
0.0
0.0
0.0
0.0
0.00
0.0403.1
0.0
0.0
403.1
403.1
403.7
0.0
0.0
0.0
0.0
0.0
403.7
o
0.00
126.72
0.00
========
========
73 ENERGY GWH521REALPrtICE-MILLS
466 INFLATION INJEX
52~PRICE-MILLS
-----IN~OME-----------------
Sla REVENUE
171 LESS OPERATING COSTS
511 JPERATING INCOME
21~ADD INTEREST EARNED ON FUNDS
550 LESS INTEREST ON SHORT TERM DEBT
391 LESS INTEREST ON LONG T~RH DEBT
548 ~ET EARNINGS FROM OPERS
-----CASH SOURCE AND USE----
54~CASH INCOME FROM OPERS
44b ~TATE CONTRIBUTION
143 LONG TERM DEBT DRAWDOWNS
243 WORCAP DEBT DRAWDOWNS
549 TOTAL SOURCES OF FUNDS
320 lESS CAPITAL EXPENDITURE
448 LESS WURCAP AND FUNDS
260 LESS DEBT REPAYMENTS
141 CASH SURP(US(DEFICITI249SHORTTERMDEBT
444 CASH RECOVERED
-----BALANCE SHEET----------
225 RESERVE AND CONT.FUND
371 OTHER WORKING CAPITAL
454 CASH SURPLUS RETAINED
370 CUM.CAPITAL EXPENDITURE
465 CAPITAL EMPLOY~D
461 STATE CONTRIBUTION
462 RcTAIN~D EARNINGS
555 DEBT OUTSTANDING-SHORT TERM
~54 ~E8T OUTSTANDING-LONG TERM
542 ANNUAL DEST JRAWWDOWN $1962
543 CUH.DEBT DRAWWDOWN $1982
519 OEaT SeRVICE COVER
Sheet 1 of 3
$1.8 BILLION (1982 DOLLARS)STATE APPROPRIATION SCENARIO
7%INFLATION AND 10%INTEREST TABLE 18.4.8 [iii]
---'
****~****************************:)*********************************************************************************************DATAIGK WATAhA-DC ION ll~E 1993-2002)-.I.d BN 1~19S2)STATE FUNDS-INFlATICN 7~-INTEREST 10%-CAP CCST i5.117 BN 23-fEB-82
***********************************************************:~**************************************************************~****
320 LESS CAPITAL EXPENDITURE
443 lESS WJRCAP AND FUNDS
loG lESS DEBT REPAYMENTS
141 CASH SURPlUS'OEFICIT)
24q 5HORT TERM DEBT
444 CASH RECOVERED
-----BAlA~CE SHEET----------
22j ~ESE~VE AND CONT.FUND
311 OTHER WORKING CAPITAL
454 CASH SURPLUS RETAINED
310 CUM.CAPITAL EXPENDITURE
465 CAPITAL EMPLOYED
461 STATE CONTRIBUTION
402 RETAINFO EARNINGS
555 DEBT OUTSTANDING-SHORT TERM
554 DEBT OUTSTANDING-LONG TERM
~42 ~NNUAl ~EBT DRAWWDOWN i1982
543 CUH.DEBT )RAWWDOWN $1982
519 DEBT SERVICE COVER
========:==:============================ ========================:===============
1991 1998 1999
CASH FLOW SUMMARY
===(5HlllION)====
3381 3387 3387
65.59 61.68 58.03
285.40 305.38 326.15
187.18 188.34 1~9.61
13
521
460
520
51!>
11;)
517
214
550
391
549
54!!
440
143
248
54'}
ENE~GY GWIi
REAL PrtICE-MlllS
I NFLATION INDEX
PRICE-HIllS
-----INCOME-----------------
REVENUE
lESS OPERATING COSTS
nPfRATING INCOME
AnD INTEREST EARNED ON FUNDS
lESS INTEREST ON SHORT TERM DEBT
lESS INTERFST ON lONG TERM UfBT
NET EARNINGS FRuM OPERS
-----CASH SOuRCE AND USE----
CASH INCOME FROM OPERS
STATE COIlTRIBUTI,lr.
lONG TERM DEST DRAWDOWN$
wORCAP OEBT DRAWOOWNS
TOTAL SOURCES JF FUNDS
1995
3381
61.36
249.28
152.95
518.0
32.0
486.0
6.2
21.2
442.8
2a.2
28.2
0.0
386.1
8.1
422.4
418.2
8.1
18.0
-22.0
22.0
0.0
67.2
56.6
0.0
7715.1========7898.9
2653.5
-22.0
241.9
5025.5
154.9
2631.3
1.02
1996
Bil1
69.51
26:'.73
185.56
628.4
35.0
593.5
6.1
24.2
441.0
135.0
135.0
0.0
363.0
29.3
521.9
47il.8
29.3
19.8
0.0
0.0
0.0
73.4
19.1
0.0
8253.9========8407.0
2653.5
113.0
211.2
53&9.2
130.3
2767.1
1.25
633.9
38.1
5')5.8
7.3
21.1
43"1.0
137.0
137.C
'I.C
324.8
11.2
413.0
440.0
11.2
21.8
0.00.0'
0.0
aO.1
34.2
0.0
8693.9======-==8858.3
2653.5
25 0.1
232.4
5612.2
113.8
2881.5
1.25
631.9
41.1>
5C)6.2
8.0
28.2
436.8
139.2
13q.2
0.0
1085.4
12.2
1235.8
1200.6
12.2
24.0
0.0
0.0
0.0
Fl1.4
89.1
0.0
96C)4.5========10071.1
2653.5
389.3
294.1
6133.b
355.4
3236.9
1.25
642.2
45.4
596.1
8.7
29.5
434.4
141.13
141.6
0.0
1346.9
10.6
1499.1
1462.1
10.6
26.4
0.0
0.0
0.0
95.4
91.7
0.0
11356.6========11543.1
2653.'i
530.9
305.2
8054.1
412.2
3649.1
1.25
2000
3381
54.61
349.62
190.92
646.6
49.6
591.0
9.5
30.5
431.8
144.3
144.3
0.0
1513.1
10.4
1661.8
1628.3
10.4
29.0
0.0
0.0
0.0
104.1
93.4
0.0
12984.9========13182.5
2653.5
615.1
315.7
9538.1
432.8
4081.8
1.25
2001
3387
51.40
314.10
192.30
651.3
54.1
597.2
10.4
31.6
428.c)
141.2
147.2
0.0
1311.3
12.3
1536.1
1492.5
12.3
32.0
0.0
0.0
0.0
113.1
9b.2
0.0
14411.4========14681.2
2653.5
822.3
328.0
108S3.4
368.1
44150.0
1.25
2002
5223
63.51
400.29
254.41
1329.0
91.1
1237.9
11.4
32.8
10B8.3
128.1
128.1
0.0
269.3
128.0
525.4
362.3
128.0
35.1
0.0
0.0
0.0
191.3
146.6
0.0
14839.1========15111.5
2653.5
950.4
455.9
11111.6
b1.3
4511.3
1.08
2003
5414
59.90
428.3.1
256.58
1389.0
99.4
1289.6
19.1
45.6
1111.8
151.4
151.4
0.0
0.0
24.1
116.1
90.9
24.1
64.1
-3.6
3.6
0.0
208.8
153.8
0.0
14930.5========15293.1
2653.5
1101.8
484.3
11053.5
0.0
4511.3
1.01
2004
5605
62.52
458.29
286.53
1605.9
108.5
14c)1.4
20.9
48.4
1105.3
364.5
364.5
0.0
0.0
42.8
401.3
99.2
42.8
10.5
lC)4.8
-58.1
136.1
227.8
111.6
0.0
150.29.1========15435.1
2653.5
1330.2
468.4
10983.0
0.0
4511.3
1.25
Sheet 2 of 3
$1.8 BILLION (1982 DOLLARS)STATE APPROPRIATION SCENARIO
7%INFLATION AND 10%INTEREST
TABLE 18.4.8 •
i _'----'~'--~
*********~*************~t***********************************************~*******************************************************DATAI0K WATANA-OC (ON LINE 1993-2002)-$1.B BN ($1982)STATE FUNDS-INfLATION 7~-INTEREST 10%-CAP COST $5.117 BN 23-FEB-82
*************~:*****************~:*********************t,=*** ****************************************** ****************************
2007 2008 20C9
CASH fLOW SuMMARY
===t$Hllll~Nl====
6253 6472 654446.72 42.59 39.14
561.42 bOO.72 642.17
262.31 255.B4 255.46
t s
521
't6)
520
516
170
517
211,.
')50
391
543
::NERGY Gwl-'
~tAL P~lCE-MILlS
INFLATION INOEX
ilR I CE-.IolIlL S
-----INCOME-----------------
~i:VENUf
LESS OPfRATING COSTS
nPERATING INCOME
AOD INTEREST ~A~~ED ON fUNDS
lESS INTEREST ON SHORT TERM DEBT
LESS INTEREST ON LONG TERM DEBT
Ni:T EARNINGS fROM OPERS
2005
6092
53.9B
4QO.37
264.6ti
1012.3
118.4
1493.9
22.8
46.8
1099.3--------371.5
200b
6147
50.38
524.69
264.32
1624.7
129.2
1495.5
24.9
50.51090.5
379.3
163<1.3
141.0
1498.3
27.1
55.6
10B2.0
387.8
1655.7
153.9--------1501.8
29.6
61.5
1012.6
397.2
1671.6
168.0
1503.6
32.3
66.1
1062.3
407.5
2010
6616
37.11681.17
255.25
1688.6
183.4--------1505.3
35.3
70.71050.9
418.9
2011
6638
34.95
135.91
251.23
1707.3
200.1--------1507.2
38.5
75.91038.4
431.4
2012
6660
32.91
781.42
259.16
172509
218.4
1501.5
42.0
79.1
1024.7
445.1
2013
668231.02
842.54
261.34
1746 01
238.4
1501.8
45.9
83.81009.6
460.3
TOTAL
1048260.00
0.00
0.00
24625.~
2202.0
22423.B
412.4
925.8
16744.9
5165.4
-----CASH SOURCE AND USE----548 CASH INCOHE FRO~OPERS446STATEcnNTRlaUTIJN
143 LONG TERM DEaT DRAWDOWNS
248 WO~CAP OEBT DRAWDOWNS
54~TOTAL SOURCES Of fUNDS
32~LESS CAPITAL EXPENDITURE443lESSWGRCAPANDfUNDS
260 lESS DEBT REPAYMENTS
141 CASH SURPLUStDEFICITt
24q SHORT TERM DEBT
444 CASH RECOVERED
-----6AlANCE SHEET----------
225 RESERVE AND CONT.FUND
371 OTHER WORKING CAPITAL
454 CASU SURPLUS RETAI",EO370CUM.CAPITAL EXPENDITURE
405 CAPITAL EMPlOYEO
401 STATE CONTRIBUTIUN
462 ~ETAINED EARNINGS
5~~OEBT OUTSTANOING-SHORT TERM
554 DEBT OUTSTANDING-lONG TER~
~42 ANNUAL DEBT ORAWWOOW~i1982
~43 CU~.DEBT URAwWDOWN $1962
519 DEBT SERVICf COVFR
311.50.0
0.036.4
408.0
1013.236.4
77.6
185.70.0
la5.7
248.7
193.2
0.01513A.O========15579.8========2653.5
1516.0
504.8
10905.4
0.0
4517.3
1.25
379.30.0
0.051.3
430.5
118.1
51.385.3
175.B
0.0
175.8
211.4
221.7
1).0
15250.1=::=====15749.2========2653.5
1119.5
5%.1
10820.1
0.0
4517.3
1.25
337.80.0
0.0
5q.3
447.1
128.959.393.9
165.0
0.0
165.0
296.2256.2
0.0
1~3e5.0========15931.4========2653.5
1942.3
615.3
10726.2
0.0
4517.3
1.25
397.20.0
0.045.B
443.0
140.7
4508
10302
153.3
DoC
15303
323.3274.9
0.0
15525.7========16123.9========2653.5
21~6.3
661.1
10622.9
000
4517.3
1.25
401.50.0
0.045.9
453.4
153.6
45.9
113.6
140.4
0.0
140.4
352.8291.2
0.0
15619.3
==='=====
Ib323.3========2653.5
2453.4
707.0
10509.4
0.0
4511.3
1.25
418.90.0
0.0
52.0
410.8
167.6
52.0
124.9
126.4
0.0
126.4
3B5.1310.9
0.015B46.9========16542.9========2653.5
2745.9
759.0
103B4.4
0.0
4517.3
1.25
431.40.0
0.0
37.7
469.1
182.9
37.7
131.4--------111.00.0
111.0
420.3313.4
0.0
16029.9========16163.5========2653.5
3066.3
196.1
10247.0
0.0
4517.3
1.25
445.10.0
0.0
41.2
486.3
199.1
41.2
151.2
94.3
0.094.3
45B.7316.2
0.0
16229.5========17004.3========2653.5
3417.1
831.8
10095.8
0.0
4511.3
1.25
460.30.0
0.044.9
505.2
217.944.9
16b.3
76.10.0
76.1
500.6319.2
0.0
16447.4========11261.2=====:==2653.5
3801.3
882.7
9929.6
0.0
4517.3
1.25
5165.42653.5
11.403.2
819.7--------20041.9
16447.4
819.1
1410.1
1364.1
0.0
1364.1
500.6
319.2
0.016447.4=====:==17261.2========2653.5
3801.3
8B2.7
9929.6
4517 .3
4517 .3
0.00
$1.8 BILLION (1982 DOLLARS)STATE APPROPRIATION SCENARIO
7%INFLATION AND 10%INTEREST
Sheet 3 of 3 TABLE1a~8 ~
_!_~L~____.--.-1
...............................................................................................................................
DATA1oK2 WATANA-DC CON lINE 1993-2002)-JOOt BILl6~6 FUNDS-INFLATION It-INTEREST 10I-CAPCOiT '5.111 BN 2-MAR-82•••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••
1985 1986 1981 1988 1989 1990 1991 1992 1993 1994
CASH FLOW SUMMARY
a==r'MllLION)=·a.13 ENERGY GYH 0 a 0 0 0 0 0 0.08 aU 1 3387521REALPRICE-MILLS 0.00 0.00 0.00 0.00 0.00 0.00 0.00 3 .49 34.60~66 INFLATION INDEX 126.12 135.59 1~5.08 155.2~166.10 111.13 190.11 203.48 211.13 232.91520PRICE-MILLS 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 66.39 BO.61
-----INCOME-----------------'16 REVENUE 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 224.9 213.0110LESSOPERATINGCOSTS0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 26.9 29.3---------------- ------------------------------------------------ ----------------511 OPERATIN'INCOME 0.0 0.0 0.0 0.0 0.0 0.0 0.0·0.0 198.0 2U.7210\ADO INTEREST EARNED ON FUNDS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 5.6
550 LEII INlllEIT 8N SHORT TIRM DEBT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.8391LE N RE T NLONG TE M DEBT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0------------------------ --------------------------------------------------------'48 NET EARNINGS FROM O.ERS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 198.0 219.5
-----iA5H SOURCE AND USE----548 CASH NCOME FROM OPERS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 198.0 219.5~46 STATe CONTRIBUTION ~0301 ~12.1 419.1 ~99.5 938.3 1550.~12·\1.1 676.4 333.1 229.1143.LONG TERH DEBT DRAWDOWNS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0248WORCAPDEBTDRAWDOWNS0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 98.0 17.7-------------------------------- ------------------------------------------------549 TOTAL SOURCES OF FUNDS 403.7 412.7 ~79.1 499.5 938.3 1550.4 1241.1 616.~629.1 487.0
320 L~fl CAPlTAL EX"NDITURE 403.1 ~72.1 ~19.1 499.5 938.3 1550.4 1241.&676.4 3U:A 259.'448 L WOR AP AND UN OS 0.0 0.0 0.0 0.0 0.0 0.0 o.0.0 17.
260 ~~ll DEBT R'PAYM~NTl 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 g.o395PAYHENTOTAE0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 198.0 21 .0--------------------------------------------------------------------------------1~1 CASH SURPLUS.OEFICIT)000 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.02~9 SHORT TERM DEBT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0~4~CASH RECOVERED 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
-----8ALANCE SHEET~---------
2i5 R~SERVE AND CONT.FUND 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 56.5 61.6310HERWORKINGCAPITAL0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 41.5 5~.1454CASHSURPLUSRETAINED0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0310CUM.CAPITAL EXPENDITU~E ~03.1 876.4 1356.1 1855.6 219~.0 43~4.3 5591.4 6261.8 6600.9 6860.1
~2a~===a aaaaaXES =az~a:==:zaaza:z :zaza==:z~a.a.3.a ••••as ••••••••••••••••••0 ••••••
~65 CAPITAL EMPLOYED ~03.1 876.4 1356.1 1855.6 2194.0 ~344.3 5591.~6261.8 6698.9 6915.8
••=asss~azas.saa ax:a:z==s=zzz:z=a=ssazzz ~~=.Z.E.aaaaa.aa ••••••••••••••••••••••••
461 STATE CONTRIBUTION 403.1 816.~1356.1 1855.6 2194.0 43~4.3 5591.4 6261.8 6600.9 6830.6462RETAINEDEARNINGS0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 29.5
555 DEBT OUTSTANDING-SHORT TERM 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 98.0 115.7
554 DEBT OUTSTANDING-LONG TERM 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
542 ANNUAL DEBT DUWWDOWN $1982 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
543 CUM.DEBT DRAWWDOWN '1982 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
519 DEBT SERVICE COVER 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Sheet 1 of 3
SENATE BILL 646 1000k STATE WITH 7%INFLATION AND lOOk INTEREST
TABLE 18.4.9
[iii]
'---iL.--~_,--'-',-----.1 ...--_!
•••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••DATA10KZ WATA"A-DC 10"LINE 1993-20021-1001 81LL646 FUNDS-INFLATION 1~-INTEREST 10~-CAPCOST S5.117 8N 2-MAR-82•••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••
1995 1996 1991 1998 1999 ZOOO 2001 200Z Z003 Z004
CASH FLOW SUMMARY
·.·.S"llLION.··.·n·ENERGY GWH 3381 3381 3381 3387 3381 3387 3381 3~~n 3i~n 3t~~3521REALPRICE-MilLS 34.64 34.56 34.69 34.62 34.56 34.48 34.39
466 I"FLATION INDEX 249.Z8 266.73 285.40 305.38 326.15 349.62 374.10 400.Z9 428.31 458.29
520 PR ICE-MILLS 86.35 92.17 99.01 105.12 112.91 120.53 128.66 lZ9.17 140.11·146.19
-----INCOME-----------------516 REVENUE 292.5 312.2 335.3 358.1 382.4 408.l 435.8 614.6 7'1.8 119.3
170 LESS OPERATING COSTS 32.0 35.0 38.1 41.6 45.4 49.6 54.1 91.1 99.4 108.'
•--------------------------------------------------------------------------------517 OPERATING INCOME 260.4 211.2 297.2 316.4 337.0 358.6 381.6 583.5 6'9.4 110.8ZI4ADOINTERESTEARNEDONFU"DS 6.2 6.7 1.3 8.0 8.7 9.5 10.4 11.4 19.1 ZO.9550LESS INTEREST ON SHORT TERM DEBT 11.6 12.4 15.3 16.4 17.1 18.7 19.8 21.0 33.8 36.)
391 LESS INTEREST 0"LONG TERM DEBT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0----------.---------------------------------------------------------------------548 HET EARNINGS fROM OPERS 255.0 211.6 289.2 308.0 328.1 349.5 312.3 573.9 644.1 695.5
-----CASH SOURCE'A"D USE----548 CASH INCOME FRO,.OPERS 255.0 211.6 289.2 308.0 328.1 349.5 372.3 573.9 644.8 695.5
446 STATE CONTRIB¥TION
363.1 38Z.1 303.8 1028.3 1117.5 1204.8 913.1 303.0 0.0 0.0143LONGTERMD 8 DRAWDOWNS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
248 NORCAP DEBT DRAWDOWNS 8.1 29.3 11.2 12.2 10.6 10.4 12.3 U8.0 Z4.7 4Z.8------------------------ ----------------------------------~---------------------5~9 TOTAL SOURCES OF FUNDS 626.2 683.0 604.2 1348.6 1516.1 156~.1 1291.1 1004.8 669.5 738.3
3Z0 LESS CAPITAL EXPENDITURE 395.3 411.2 342.1 1070.1 1223.2 125,..6 967.5 362.3 90.9 99.Z
448 LESS WORCAP AND FUNDS 8.1 29.3 11.2 12.2 10.6 10.4 12.3 128.0 24.7 42.8
260 LESS DEBT REPAYMENTS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
395 LESS PAYMENT TO STATE 222.9 236.5
250.9 266.2 282.4 299.6 317.9 514.5 553.9 596.3------------------------ --------------------------------------------------------141 CASH SURPLUS«DEFICITt 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
249 lHORT T~RM DEBT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
441t ASH RE OVERED 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
-----BALANCE SHEET----------
~fS RfSERVE A"D CaNT,FU"D 61.2 73.4 80.1 81.4 95.4 104.1 113.1 191 •3 n8 •8 U7 •8
1 0 HER WORKING CA ITAL 56.6 79.7 84.2 89.1 91.7 93.4 96.2 46.6 3.8 1.6
454 CASH SURP\US RETAINED 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0:no CUM.CAPI AL EXPENDITURE 7255.4 1612.6 8014.1 9084.8 10308.0 11562.6 12530.1 lZ892.5 12983.3 13082.5
a&&2.:=&==a2~Z:.zaaaaa~.2azaazza a~.=.2aa ••••••••••••••••••••••••••••••••••••••••
465 CAPITAL EMPLOYED 1379.2 7825.7 8179.0 9261.4 10 ....95.1 11160.2 12140.0 13230.3 13345.9 13487.9
sa.=.~S2 =Zza:aS2 ~a ••2==~aaaaa.aa a===a.a.~•••a •••aasa ••••••a.aa ••••••••••••••••••
....61 STATE CONTRIBUTION 1193.1 1515.8 7819.6 8907.9 10085.4 11290.3 12203.4 12506.4
12506.4 12506.4
462 RETAI"ED EARNINGS 61.6 96.8 135.1 176.9 222.6 272 .....326.7 386.1 471.0 516.1
555 DEBT OUTSTANDING-SHORT TERM 123.9 153.1 161t.3 116.6 181.1 191.6 209.9 331.8 362.6 405.4
554 DEBT OUTSTANDING-LONG TERM 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
542 ANNUAL DEBT DRAWWDOWN S1982 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
543 CUH.DEBT DRAWWDOWN S1982 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
519 DEBT SERVICE COYER 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Sheet 2 of 3
SENATE BILL 646 100010 STATE WITH 1%INfLATION AND 10010 INTEREST TABLE 18.4.9
[iii]
I ..---'__J
~~~~••*~.*••o~••~o~~*~.~oo••*~.~.o••~*•••*•••*~••••~•••••••••*0 ••••••••••••••0••••••0.000 •••••••*.0.0 •••••••00 ••00 ••••0•••0••••
DATAIOK2 WATANA-DC ION LINE 1993-20011-100t BILL646 fUNDS-INfLATION 1t-INTEREST 10t-CAPCOST '5.111 BN 2-MAR-82••••••••••••••••••••••••••~~•••~••~••~.~••~••~••*.*••~.~.~.~~*~••~••••••••*~.~.~.~.~~~~•••*•••••~~••••••*.~•••••••~••••••••••••
2005 2006 2001 2008 2009 2010 2011 2012 2013 TOTAL
CASH FLOW SUMMARY
:::I'HILLIONlaaaa
n ENERGY GWH 609~6141 6250 6412 65"4 6646 a638 2'~8K 668 1 1°3~~8521REALPRICE-MILLS 29.6 29.10 29.53 28.84 28.19 28.5 2 .93 29.2"66 INFLATION INDEX 490.31 524.69 561.42 600.12 642.11 681.11 135.91 181.42 842.54 0.00520PRICE-MILLS 145.50 155.81 165.11 113.22 185.08 191.13 212.90 228.96 2"6.28 0.00
-----INCOME-----------------
5I6 REVENUE 886.3 951.7 1036.0 1121.0 1211.1 1308.1 I1tl3.1 1524.8 1645.5 16318.61 0 LESS OPERATING COSTS 118.4 129.2 141.0 153.9 168.0 183.4 200.1 218.4 238.4 2202.0-------------------------------------------------------------------~------------511 OPERATING INCOME 161.9 828.4 895.0 961.1 1043.1 1124.1 1213.0 1306.4 1401.2 14116.6214ADDINTERESTEARNEDONFUNDS22.8 24.9 21.1 29.6 32.3 35.3 38.5 42.0 45.9 4ll.4550LESS INTEREST ON SHORT TERM DEBT 40.5 4".2 "9.3 55.2 59.8 64.4 69.6 13."11.5 146.6391LESS INTEREST ON LONG TERM DEBT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0-------------------------------- ---------------------------------------- --------54B NET EARNINGS FROM OPERS 150.1 809.1 812.8 941.5 1015.6 1095.6 1181.9 1215.0 1315.5 13842.4
-----CASH SOURCE AND USE----
548 CASH INCOME FROM OPERS 150.1 809.1 811,.8 941.5 1015.6 1095.6 1181.9 lZ15.0 1315.5 13842.4446STATE CONTRI8UTION 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 12506.4143LONGTERMDEBTDRAWDOWNS0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0248WORCAPDEITDRAWDOWNS36.4 51.3 59.3 45.8 45.9 52.0 31.1 41.2 44.9 819.1---------------------------------------- ------------------------ ----------------549 TOTAL SOURCES Of FUNDS 186.5 860.4 932.1 981.3 1061.5 11"1.5 1219.6 1316,,2 1420.5 21168.5
320 LESS CAPITAL EXPENDITURE 108.2 118.1 128.9 140.1 153.6 161.6 182.9 199.7 211.9 14500.~448 LESS WORCAP AND FUNDS 36.4 51.3 5q.3 45.8 45.9 52.0 :n.1 41.2 44.9 119.
260 LESS DE8T R~PAYMENT'0.0 0.0 0.0 '0.0 0.0 0.0 0.0 0.0 0.0 0.0395lESSPAYMENTOSTAE641.9 691.0 143.9 800.8 862.0 928.0 999.0 1015.4 1151.6 11848.'------------------------ -------- ------------------------------------------------141 CASH SURPLUSIDEFICITI 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
249 lH~R'I~RM RIB T 0.0 0.0 0.0 0.0 0.0 0.0
8:8 0·8 8:8 8:8444AHROVE0.0 0.0 0.0 0.0 0.0 0.0 D..
-----IALANCE SHEET----------
ift ~i~~lvSot~¥N~O~IJI~~rD U':l Ul:~~96.~nl:~Ui:t iU:~4n·3 til:l lYQ:t IYS:t56.3 ."454 CASH SURPLUS RETAINED 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0310CUM.CAPITAL EXPENDITURE 13190.1 13308.9 13"31.8 13518.5 13132.1 13899.1 1"082.6 14282.3 14500.2 14500.2
.sa.a~&a as::••••a •••a:a.casaaa.s ••aaaa ••z ••••••••••••••••a ••••••••••••••m•••••••
"65 CAPITAL EMPLOYED 13632.6 13801.9 13990.2 lIt176.1 14316.1 14595.1 14816.3 15051.1 15119.9 15319.9
•••a •••••a~aaa•••••ass ••aaasa •••••3=••••••••a.aD ••••••••••••••••••••••••••••••••
461 STATE CONTRIBUTION 12506.4 12506.4 1250b.4 12506.4 12506.4 12506.4 12506.4 12506.4 12506.4 12506.4
462 RETAINED ElRNINGS 684.4 802.5 931.4 1072.1 1225.1 1393.3 1516.3 1115.9 1993.8 1993.B
555 DEBT OUTSTANDING-SHORT TERM 441.8 493.1 552.4 598.2 644.0 696.0 133.1 114.8 819.1 819.1
554 DEBT OUTSTANDING-LONG TERM 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
542 ANNUAL DEBT DRAWWDOWN 51982 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
543 CUM.DEBT DRAWWDOWN 11982 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
519 DEBT SERVICE COVER 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Sheet 30f 3
SENATE BILL 646 100010 STATE WITH 7%INFLATION AND 100/0 INTEREST
TABLE lB.4.9 •
I ..
--~'-'-~
••••••••••••••••••••••••••••••*••••••••••••••••**••••••••••••••••••*••*•••*•••*••••*••••••••••••••*••••••••••••••••••••••••••••
OATA10K2 WATANA-DC CON LINE 1993-20021-S3.0 BNCI19821 BILL646 FUNDS-INFLATION l~-INTEREST 101-CAPCOST 15.111 BN 2-MAR-82••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••*••••••••••••••••••••••••••••••••••••••••••••••••••
61.654.1
0.0
6938.6••••••••7054.3••••••••4806.1
36.4
115.1
2095.It
98.6
1035.1
1.94
1994
0.0
0.0
0.0
3381
51.98
232.91
121.10
410.1
29.3--------380.8
5.6
9.B
187.3--------
189.4
189.4
0.0
229.1
11.7--------436.8
259.2n.7
6.9
153.0
0.0
0.0
0.0
1993
325.0
26.9
298.2
0.0
0.0
154.0
144.2
333.1
98.0
0.0
144.2
3381
44.08
211.13
95.91
56.5
41.5
0.0
6619.4••••••••6711.4••••••••4806.1
0.0
98.0
1812.6
153.0
936.5
1.94
144.2
0.0
333.1
98.0--------515.3
0.0
0.0
154.9
0.0
1992
0.0
o
0.00
203.48
0.00
0.0
0.0--------0.0
0.0O.gO.
154.9
154.9
0.0
0.0
0.0----------------0.0
0.0
0.0 •
0.0
0.0
0.0
6346.3••••••••6346.3••••••••4806.7
0.0
0.0
1539.5
311.0
181.6
0.00
o
0.00
190.11
0.00
0.0
0.0
0.0
0.0
0.0
0.0
462.4
184.1
0.0
1241.1
1241.1
-0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1991
0.00.0
0.0
5591.4
a •••••a •
5591.4.a ••••••
..e06.7
0.0
0.0
184.1
412.6
412.6
0.00
1550.4
1550.1t
0.0
0.0
0.0
0.0
1550.4
0.0
0.0
o
0.00
171.13
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1990
0.0
0.0
0.0
0.00.0
0.0
4344.3
:a •••asa
4344.3
a:aaas.caa
4344.3
0.0
0.0
0.0
0.0
0.0
0.00
o
0.00
166.10
0.00
0.0
0.0
0.0
938.3
938.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
938.J
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.02794.0
5=:=8.8:
2194.0
asa.,aa:a:
2194.0
0.0
0.0
0.0
0.0
0.0
0.00
0.0
0.0
0.0
0.0
0.0
499.5
0.0
0.0
0.0
0.0
499.5
499.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1855.6
::z:oza:z ....
1855.6
azzaaazos:
1855.6
0.0
0.0
0.0
0.0
0.0
0.00
1981 1988 1989
CASH FLOW SUMMARY
~~~CSMILLIONI==~2o0
0.00 0.00
!lt5.08 155.24
0.00 0.00
0.0
0.0
419.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
419.1
419.7
0.0
0.0
0.0
0.00.0
0.0
1356.1
s.z-aa&a.
1356.1
•a'C ..~.a=
1356.1
0.0
0.0
0.0
0.0
0.0
0.00
412.1
412.1
0.0
0.0
0.0
1986
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
412.1
0.0
0.0
0.0
0.0
0.0
o
0.00
135.59
0.00
0.0
0.0
0.0
876.4
:~~a:K~.:&:
876.4
aa;;a:r.a ••
816.4
0.0
0.0
0.0
0.0
0.0
0.00
0.0
0.0
0.0
0.0
0.0
0.0
403.1
0.0
0.0
403.1
403.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
It03.1
0.0
0.0
0.0
403.1
1985
o
0.00
126.12
0.00
•••aa._a
403.1
0.00.0
0.0
0.0'0.0
0.00
••:5.&:a8
73 ENERGY GWH
521 REAL PRICE-MILLS
466 INFLATION INDEX
520 PRICE-MILLS
-----INCOME-----------------
516 REVENUE
110 LESS OPERATING COSTS
511 OPERATING INCOME
214 ADO INTEREST EARNED ON FUNDS
S50 LESS INIERESl ON SHORT TERM DE8T391LESS N ERES ON LONG TERM DEBT
5~8 NET EARNINGS FROM OPERS
-----CASH SOURCE AND USE----548 CASH INCOME FROM OPERS
~46 STATE CONTRIBUTION
1~3 LONG TERM DE8T DRAWDOWNS
2~8 WORCAP DEBT DRAWDOWNS
5~9 TOTAL SOURCES OF FUNDS
320 LESS CAPiTAL EXPENDITURE~48 LESS WOR AP AND fUNDS
260 LESS DEBT REPAYMENTS
395 LESS PAYMENT TO STATE
141 CASH SURPLUSCDEflCITI
249 SHORT TERM DEBT
444 CASH RECOVERED
-----8ALANCE SHEET----------
225 RESERVE AND CDNT.FUND
311 OTHER WORKING CAPITAL
~54 CASH SURPLUS RETAINED
310 CUM. CAPITAL EXPENDITURE
1t65 tAPITAL EMPLOYED
~61 STATE CONTRIBUTION
462 RETAINED EARNINGS
555 DE8T OUTSTANDING-SHORT TERM
554 DEBT OUTSTANDING-LONG TERM
542 ANNUAL DEBT ORAWWDOWN 119B2
543 CUM.DEBT DRAWWDOWN $1982
519 DEBT SERVICE COVER
Sheet 1 of 3
SENATE BILL 646 "MINIMUM"APPROPRIATION OF
$3.0 BILLION WITH 7%INFLATION AND 100~INTEREST
TABLE 18.4.10 •
r---
L.--L...-..
-~-----,__---J
*******************************************************************************************************************************DATA10KZ WATANA-OC CON LINE 1993-2002'-11.0 8NC'1982'81LLb46 FUNDS-INFLATION l~-INTEREST 10t-CAPCOST 55.111 8N 2-MAR-B2
*******************************************************************************************************************************
1995 199b 1991 1998 1999 2000 2001 2002 2003 2004
CASH FLOW SUMMARY
===C'HILlION'====13 ENERGV GWH H87 H81 3381 3387 3387 H81 3381 5223 541"1 5605521REALPRICE-HILLS 50.107 108.94 107.73 Iob.101 45.11 44.00 42.90 63.06 59.90 59.13466INFLATIONINDEX249.28 266.13 285.40 305.38 326.15 349.62 314.10 400.29 428.31 458.29
520 PRICE-MILLS 125.82 130.55 136.22 141.11 141.60 153.84 160.51 252.41 256.58 213.12
~----INCO"E-----------------516 REVENUE 42b.1 442.1 4bl.4 1079.9 499.9 521.0 543.6 1318.2 1389.0 1534.1
170 LESS OPERATING COSTS 32.0 35.0 18.1 41.6 45.4 49.6 54.1 91.1 99.4 108.5--------------------------------------------------------------------------------517 ~PERATING INCOME 394.1 401.2 423.2 438.3 454.5 411.4 489.5 1221.1 1289.6 1425.b
21~ADD INTEREST EARNED ON FUNDS 6.2 b.l 1.3 8.0 8.1 9.5 10.4 11.4 19.1 20.9550LESSINTERESTONSHORTTERMDE8T11.6 12.4 15.3 16.4 11.1 18.1 19.8 21.0 33.8 41.3391LESSINTERESTONLONGTERMDE8T186.b 185.8 185.0 184.1 183.0 181.9 180.1 891.1 926.5 922.1--------------------------------------------------------------------------------548 NET EARNINGS fROM OPERS 202.1 215.1 230.3 245.8 262.5 280.3 299.4 319.9 348.5 483.0
-----CASH SOURCE AND USE----548 CASH INCOME FROM OPERS 202.1 215.1 230.3 245.8 262.5 280.3 299.4 319.9 348.5 483.0
446 STATE CONTRI8UTION 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0143LONGTERMDEBTDRAWDOWNS386.1 443.1 409.1 1115.2 1442.0 1613.5 1483.1 303.0 0.0 0.0
248 WORCAP DE8T DRAWDOWNS 8.1 29.3 11.2 12.2 10.6 10.4 12.3 128.0 24.1 42.8---------------------------------------------------------------- ----------------
54q TOTAL SOURCES OF FUNDS 596.3 688.1 651.2 1433.3 1115.0 1904.2 1194.8 150.8 313.2 525.9
320 LESS CAPITAL EXPENDITURE 418.2 418.8 448.0 1211.1 1481.6 1663.3 1531.5 362.3 90.9 99.2448LESSWORCAPANDFUNDS8.1 29.3 11.2 12.2 10.6 10.4 12.3 128.0 24.1 42.8
260 LESS DEBT REPAYMENTS 1.6 8.4 9.2 10.1 11.1 12.2 13.5 14.8 43.9 48.3395LESSPAYMENTTOSTATe162.3 112.2 182.1 193.9 205.1 218.3 231.6 245.1 264.5 284.1-------- -----------------------~---------------------------------------- --------141 CASH SURPlUSIOEFICIT'0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0'-50.8 50.8
249 SHORT TERM DEeT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 50.8 -50.8
444 CASH RECOVERED 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
-----BAlANCE SHEET----------225 RESERVE AND CONT.FUND 61.2 13.4 80.1 81.4 95.4 104.1 113.1 191.]208.8 221.8311OTHERWORKINGCAPITAL56.6 79.1 84.2 89.1 91.7 93.4 96.2 146.6 153.8 111.6454CASHSURPLUSRETAINED0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
310 CUM.CAPITAL EXPENDITURE 1356.8 1835.6 8283.6 9500.1 10988.3 12651.6 14189.1 14551.4 14642.3 14141.4
z:aza::3 =:za~2za =~===z==z:z=:azz xaaazza==~sas••z a •••••••••••••••••••••••••••••••
465 CAPITAL EMPLOYED 14BO.l 1988.1 8448.0 9611.3 11115.4 12849.1 14398.9 14889.2 15004.8 15146.8
:aZ~=2aa aaaaazaz z~~a===a :z::as:a sazsassz a.zs:saa Es ••••a •••••••••••••••••••••••a.
1061 STATE CONTRIBUTION 4806.1 4806.1 4806.1 4806.1 4806.1 4806.1 4806.7 4806.7 4806.7 4806.1
462 RETAINED EARNINGS 16.2 119.6 161.1 219.1 215.9 331.9 405.8 479.9 563.9 162.2
555 DEBT OUTSTANDING-SHORT TERH 123.9 153.1 164.3 116.b 181.1 191.6 209.9 331.8 413.4 405.4
554 DE8T OUTSTANDING-LONG TERM 2413.9 2909.2 3309.1 4474.9 5905.1 1506.9 8916.6 9264.1 9220.8 9112.5
542 ANNUAL DEBT ORAWWOOWN 11982 154.9 Ibb.3 143.b 384.8 441.3 461.5 396.4 15.1 0.0 0.0
543 CUM.DEBT DRAWWDOWN 11982 1190.0 1356.4 1499.9 1884.8 2326.0 2181.5 3184.0 3259.6 3259.6 3259.6
519 DEBT SERVICE COVeR 2.00 2.01 2.14 2.21 2.29 2.38 2.41 1.33 1.31 1.45
Sheet 201 3
SENATE BILL 646 "MINIMUM"APPROPRIATION OF
$3.0 BILLION WITH 7%INFLATION AND 10010 INTEREST
TABLE 18.4.10 Iii
L.......-..;
1--
L---c:=L,__'--..--J
.*.**0 ••*000 ••••0•••••••0***•••••****.*••0***••*.00****.00*•••••*••***.**.******•••••••••••••••••**•••*••••••••••••••••••••••••DATA10K2 WATANA-DC (ON LINE 1993-2002)-'3.0 8NII19821 81LL6~6 FUNDS-INFLATION l~-INTEREST 10t-CAPCOST '5.111 8N Z-MAR-82•••••••••••••••••••••••••••••••••••••••••••*•••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••
2005 2006 2001 2008 2009 2010 2011 2012 2013 TOTAL
CASH FLOW SUMMARY:zal'MILLION)==a&13 ENERGY GWH 6092 6141 6250 6412 6544 6616 6638 6660 6682 104826521REALPAICE-MllLS 50.93 48.59 ~6.11 43.04 41.16 39.42 38.11 36.81 35.12 0.00
466 INFLATION INDEX 490.31 524.69 561.42 600.72 642.71 681.11 135.91 181.42 842.54 0.00
520 PRICE-MilLS 249.14 254.95 258.86 258.52 264.55 271.12 280.46 290.31 300.99 0.00
-----INCOME-----------------516 ~EVENUE 1521.3 1561.0 1611.1 1613.0 1131.1 1193.6 1861.6 1931.3 2011.1 24060.4
170 lESS OPERATING COSTS 118.4 129.2 141.0 153.9 168.0 183.4 200.1 218.4 238.4 ~202.0---------------------------------------- ----------------------------------------511 OPERATING INCOME 1402.9 1431.8 1416.1 1519.1 1563.1 1610.3 1661.4 1114.9 1112.1 21858.4
214 ADD INTEREST EARNED ON FUNDS 22.8 24.9 21.1 29.6 32.3 35.3 38.5 42.0 45.9 412.4550LESSNTERESTONSHORTTERMDEBT40.5 44.2 49.3 ~5.2 59.8 64.4 69.6 13.4 77.5 751.7
191 LESS INTEREST ON LONG TERM DEBT 911.3 911.9 906.1 899.1 892.6 884.8 816.3 866.8 856.5 12386.5------------------------ -------- -------- ----------------------------------------548 NET EARNINGS FROM OPERS 467.9 506.6 548.4 593.8 643.0 696.3 754.1 816.1 884.6 9132.6
-----CASH SOURCE AND USE----548 CASH INCOME FROM OPERS 467.9 506.6 5~8.4 593.8 643.0 696.3 754.1 816.7 884.6 9132.6
446 STATE CONTRIBUTION 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4806.1
143 LONG TERM DEBT DRAWDOWNS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9358.6248MORCAPDEBTDRAWDDWNS36.4 51.3 59.3 45.8 45.9 52.0 31.1 41.2 44.9 819.1--------------------------------------------------------------------------------549 TOTAL SOURCES OF FUNDS 504.3 551.8 601.1 639.6 688.9 748.3 191.8 .51.9 929.5 24111.6
320 LESS CAPITAL EXPENDITURE 108.2 118.1 128.9 140.1 153.6 161.6 182.9 199.1 217.9 16159.1448LESSMORCAPANDFUNDS36.4 51.3 59.3 45.8 45.9 52.0 31.7 41.2 44.9 819.7260lESSDEBTREPAYMENTS53.1 58.4 64.3 70.1 17.8 85.6 94.1 103.5 113.9 901.6
395 LESS PAVMENT TO STATE 306.5 330.0 355.2 382.4 411.6 443.1 471.0 513.~552.8 6231.2--------------------------------------------------------------------------------141 CASH SURPLUS&OEFICITl 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
249 SHORT TERM DEBT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0444CASHRECOVERED0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
-----8ALANCE SHEET----------225 RESERVE AND CONT.FUND 248.1 211.4 296.2 323.3 352.8 385.1 420.3 458.1 500.6 500.6
311 OTHER WORKING CAPITAL 193.2 221.1 256.2 214.9 291.2 310.9 313.4 316.2 319.2 319.2
454 CASH SURPLUS RETAINED 0.0 0.0 0.0 0.0 0.0 0.0.0.0 0.0 O.y 0.0310CUM.CAPITAL EXPENDITURE 14849.1 14967.8 15096.7 15231.4 15391.0 15558.6 15141.6 15941.2 16159.16159.1
.a~a.3.a aa:•••••aa.a.zaa •••a ••su aaaa ••••••••••••••••••••••••••••••••••••••••••••
465 CAPITAL EMPLOYED 15291.5 15460.9 15649.1 15815.6 16035.0 16254.6 16415.2 16116.0 16918.9 16978.9
•••~a •••••••38 •••••••••••••••••a a.a ••••a ••••••••••••••••••••••••••••••••••••••••
461 STATE CONTRIBUTION 4806.7 4806.1 4806.1 4806.7 4806.7 4806.1 4806.1 4806.1 4806.1 4806.7
462 RETAINED EARNINGS 923.5 1100.1 1293.4 1504.8 1736.2 1989.3 2266.4 2569.6 2901.4 2901.4
555 DEBT OUTSTANDING-SHORT TERM 441.8 493.1 552.4 598.2 644.0 696.0 133.7 714.8 819.1 819.1554DEBTOUTSTANDNG-lONG TERM 9119.4 9060.9 8996.6 8925.9 8848.1 8762.5 8668.4 856~.9 8451.0 8~51.0
542 ANNUAL DEBT DRAWWOOWN 11982 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3259.6
543 CUM f DEBT DRAWWOOWN 51982 3259.6 3259.6 3259.6 3259.6 3259.6 3259.6 3259.6 3259~6 3259~6 3259~60519DEBSERV~CE COVER 1.43 1.46 1.50 1.54 1.58 1.63 1.68 1.,3 1.,9 O.u
Sheet 30f 3
SENATE BILL 646 "MINIMUM"APPROPRIATION Of
$3.0 BILLION WITH 1%INfLATION AND 10%INTEREST TABLE18.4.10 [iii
(1
I I
(J
11
I I
Best Thermal Optlcn ~
7%Inflation,10%Interest ~~
~~~~~~~#~#~#~#~~~#,
~#Hydroelectric Energy Cost
....~##7%Inflation,10%Interest
.c
3:.:.:..
Cll
(J
Q,
{I)
en'Ii:
Q
(.)
>
[[en..
Cll
Cw
\j
~))II))~))))t)~)~{)~~))~)~~I))j)~{)~~~j~)~)~)~)))~)~)~)~)~~~)~~~)\~\~\~~)~)~)~)\~~~\)\)~?~j~~~.~
:::::Inflationary Financing Deficit :::::::::::::::::::~~
:::::With 7%Inflation,10%Interest :::::;:;:::::.,;,
::::::::~~..;:::1"..~..Zero Inflationary Deficit with Zero Inflation
Best Thermal Option
0%Inflation,3%Interest
Hydroelectric Energy Cost
0%Inflation,3%Interest
)I
\.....!
1994 2000
Years
2010
FIGURE ,....,-DIAGRAMATIC COMPARISON ENERGY COSTS - 0 AND 7%INFLATION 111m I
l~__,\_-'--,
--~'
FIGURE 18.4.2-ENERGY COST COMPARISON -100%DEBT FINANCING 0 AND 7%INFLATION iiJ131209 2010 1108
Mill Rate Cost
Best Thermal Option
0%Inflation,3%Interest
J
07
·#1;#
I•J COST SAVINGS GROWING OVERIW1HOLEOFSUSITNALIFE
I
0605
Mill Rate Cost
Best Thermal Option
7%Inflation,10%Interest
040302
COST SAVINGS
2000 0198
mcing Deficit with Zero Inflation
Years
Susitna Mill Rate Cost With
7%Inflation,10%Interest
"\
7
NO STATE APPROPRIATION SCENARIO
100%DEBT FINANCING
6 ...
J>----7 "
"
6594
140
160J!!!!~!~~!~!I?
380
360
340
320
300
~
~280-:!l
~260
'"II)u';:
Q.240"Cc
III
:l
'"2200o
>-2'
II)200cw
180
Rev. 1
c=
COST SAVINGS GROWINGOVER
WHOLE OF SUSITNA LIFE
Devil Canyon Completed with $7.2 billion ($2.3 bn 1982)of
Revenue Bonds 1994 -2002
STATE APPROPRIATION OF
$3.0 BILLION WITH 7%INFLATION AND 10%INTEREST
Watana Completed 1993 with $1.8 billion
($0.9 bn 1982)of Bonds 1991 -93;Cover of
1.25 at 80 Mills/kWh i"n 1994
IlIIlI
Mill Rate Cost "
Best Thermal Option I__f
-,-
#".,"
....................#............1 Susitna wholesale energy price falls as
.-..energy increases to 2009 and rises
;#.......slowly thereafterf#/;~ll~lllilil!!~::i::::,""""""",.".,"",.,,.,...-1••••-•••••-•••.•-:-:.-:.:.:-.::::-::::-:::::-::::-:::~-:::::-::::-:::;-----'
•,,~.:::Less Excess Debt Service Cover :::::::::::::::::::::::::::::~;;:;;::,:~..--~--I ....~<lJ~~:~:.:.·~;;.:;;:.:.·;;;,;:;;:;·;;;;::.:::,;.·:.:.·...~..:.·.:;;:.:.:~~:~~8;,;;;:,;~-
II•I--*~-
Rev. 1
360
340
320
300
280
:c
~260-~
~:;240
II)u.;:
a.
"tl 220cIII
'"-=8 200
>ell..
!180w
160
140
120
100
FIGURE 18.4.3 - ENERGY COST COMPARISONSTATE APPROPRIATION $3 BILLION (1982 $)
Years
94 5 6 7 8 9 2000 01 02 03 04 05 06 07 08 09 2010 11 12 13 •
r----~L __~
r---
L---...
Rev. 1
#/
II•./
IMill Rate Cost
Best Thermal Option
Susitna Pricing Restricted to.
Maximum of Best Thermal Cost
:iusitna Wholesale Energy Price
MINIMUM STATE APPROPRIATION OF
$2.3 BILLION WITH 7%INFLATION AND 10%INTEREST
380
360
340
300
320
200
180
it~I
~#COST SAVINGS GROWING OVER
;41 WHOLE OF SUSITNA LIFE
;#~*,
________~}"":~;:':~:::::,::~7~:~~:;:'"
./Ma;mr§;~~,"':""~'~"'N......•.U ...................)'i'
I•I•I
160 ~J .
,---140.
-.c:3:;
~1
280
a:
-:'260
II)u.;:
a.
-g 240
III
t!8 220
~
II)
an
120.Watana Completed 1993 with $3.3 billion
($1.7 bn 1982)of Bonds 1990 - 93;Cover of
1.25 at 137 Mills/kWh in 1994
Devil Canyon Completed with $6.8 billion ($2.1 bn 1982)of
Revenue Bonds 1994 - 2002
Years
FIGURE 18.4.4 -ENERGY COST COMPARISON $2.3 BILLION "MINIMUM"STATE APPROPRIATION
100 .
9!t 5 6 7 8 9 2000 01 02 03 04 05 06 07 08 09 2010 11 12 13 Wi
~.L-__
Rev.1
MillRate Cost
Best Thermal Option
STATE APPROPRIATION OF
$1.8 BILLION WITH 7%INFLATION AND 10%INTEREST
Susitna Price Tracks Cost of Best Thermal Option
Until 1.25 Debt Service Cover Established
DevilCanyon Completed with $6.9 billion ($2.1 bn in 1982)
Inadequate Cover Until 2004
#......
/1
III
,COSTSAVINGS GROWINGOVER
,WHOLEOF SUSITNA LIFE
~#
.,#
.~.~#
A#JIJ,,---------./-.
IIII•
Watana Completed with $4.4 billion ($2.4 bn 1982) of
Bonds 1989 - 93.Inadequate Cover Until 1996
380
360
340
320
300
J:
~280--:'f:
~260
Ul
CD
U.;:
a.240
'tlc
III
Uli 220
to)
>-l:ll..!200
w
180
160
140
120
...-/...--
__--I
SENATE BILL 646 PROPOSAL -100%STATE FINANCING
Susitna Wholesale
Energy Price
COST SAVINGS GROWING OVER
WHOLE OF SUSITNA LIFE
Devil Canyon Completed 2002
#Jt'
".'
""""4--'
##
--.#._.•..
Mill Rate Cost
BestThermal Option Price
96 97 98 99 2000 01 02 03 04 05 06 07 08 08 10 11 12 13 IAPD(P I
FIGURE 18.4.6 -ENERGY COST COMPARISON MEETING SENI:\TE BILL 646 REQUIREMENTS WITH 100 PERCENT FINANCING un d
WatanaCompleted 1993
,----,",.,'~.,
""I
I---
94 95
Years
140
100
120
380
360
340
320
i
I'
300 !i
:c 280 .~-~
~260
'"II)u.;:
240Q.
"'C
C
IV
'"220' .
1;;
0
(J
~..200 •
II)cw
180 I
160 .
=_L--
Operating Costs, Renewals and
Interest on Working Capital
DEBT SERVICE
Devil Canyon Completed with $7.5 billion
($2.3 bn in 1982)of Revenue Bonds 1994 -2002
'1lr,
I COST SAVINGS GROWING OVER_..J WHOLE OF SUSITNA LIFE
r 1#~'-.-rtfIIIIB----
~~~~~~~;~~m~~~~~~~~~~~~~~m§~::-,
Susitna Wholesale
Energy Price
Mill Rate Cost
Best Thermal Option
SENATE BILL 646 "MINIMUM"APPROPRIATION OF
$3.0 BILLION WITH 7%INFLATION AND lOOk INTEREST
....-_......-......_-~~-_...~#.-
~##,,#
I•I
I
I
I
I
......'"
140 Operating Costs, Renewals and
Interest on Working Capital-
:::::::::::::*:::!'~f,i~~~t~:~~:;~~~~!liliiililiililiilliil!li!
80 r::::}::::::::Watana Completed 1993 with $1.9 billion :::::;:::::;::
:::::::::::::::($0.9 bn in 1982)of Bonds 1991 -1993 ::::::::::::::
60 ,~~~~~~~~~~~~ji~?{?\::::???t~}}}}~~~?t?;~?t??~}}~tt~~~~I~~~~~~j~~
340
320
300
280
260
:c 240
3:.:.:-~
~220
'"III
Ud:200
-cc
ClI
'"180...'"0
(J
>~160
IIIc
W
FIGURE 18.4.7 - ENERGY COST COMPARISONMEETING SENATE BILL 646 REQUIREMENTS WITH $3 BILLION APPROPRIATION
94 95 96 97 98 99 2000 01 02
03 04 05
Years
06 07 08 09 10 11 12 13 iii]
I'iJ
U
U
18.5 -Financial Risk
This section of the report considers the financial risks ari'sing to the entities
potentially fi nanci ng Susi tna.These enti ties are the State of A1 aska,A1 askan
consumers and bond holders.Under the financing schemes described in Section
18.4,the only risks to bond holders would arise in the later stages of the .
project's life when either the G.O.bonds had been converted into revenue bonds
or the revenue bonds were no longer guaranteed.These financing plans would
therefore protect bond holders from all risks from Susitna until the project was
fully estab1i shed and fully met the normal standards of securi ty for bond
holders.It can be taken therefore that the proposed financing schemes would,
in effect,hold the bond holders free from all abnormal,risk.On these grounds
only, the risk arising to the State of Alaska and Alaskan consumers will be
considered.
The analysis is also confined to Watana completion and operation up to the year
2001.Thi s is fi rst1y because Watana accounts for more than two-thi rds of the
total capital cost of the Susitna Project.Secondly, as can be seen from Figure
18.4.3 to 18.4.5,the long-term viability of Susitna (i.e.,its costs compared
with the best thermal option)is such that,long term,there is very little risk
that the project would be unable to meet all flnanclng costs when charging a
price which is more favorable to consumers than the best thermal option.This
means that there is little likelihood of any additional burden falling on
A1 askan consumers (compared with that imposed by the best thermal option)after
Devil Canyon comes on-stream.Risk to the State of Alaska in terms of being
called upon to permit Devil Canyon to be financed by guaranteed revenue bonds or
G.O.Bonds is correspondingly small.These considerations,and the extreme
uncertainty attaching to any detailed financing scenarios some two decades
hence, support the approach followed here of concentrating on the risk at the
Watana stage of project development.
The analysis considers risk in terms of pre-completion and post-completion risk.
It concludes that there is very little pre-completion risk as measured by
likelihood of non-completion.The major specific risks at the pre-completion
phase (i.e.,risk of capital overruns,higher-than-forecast interest rates,
etc.)have their effect in the post-completion phase by giving rise to
additional financing requirements,inadequacy of debt service and delay in
conversion to non-guaranteed revenue bonds.Each of these specific risks is
considered and their probability of occurrence estimated.Also considered is
the critically important aggregative risk relating to project earnings expressed
in terms of the cumulative net operating deficit or surplus.
The general conclusion is that,in terms of failure to achieve estimated
forecasts in 1982 dollars,both specific and aggregative risks have well defined
probability limits which should be acceptable having regard to the long~term
net benefits and the energy price stabilization advantages of the project.
(a) Pre-completion Risk
The first major risk,considered in the pre-completion phase,is the risk
that the project will not be completed.The scenarios which might lead to
18-78
this conclusion are possibly that major and unforeseen natural hazards are
identified in the construction phase or alternatively that an actual
natural calamity prevents completion.The possibilities of seismic and
other natural hazards are dealt with in Sections 9 and 10 of the
Feasibility Report for the Susitna Hydroelectric Project.The analysis
given there supports the conclusion that the chance of unforeseen natural
hazards of a magnitude sufficient to prevent completion,occurring during
the construction phase,is negligible.The probability of construction
being permanently halted by occurrence of a major natural hazard is also
identified in that section and is assessed as very small.It may be
concluded therefore,that the risks arising from non-completion owing to
natural hazards are negligible.
In considering the risk of non-completion owing to capital overruns it is
necessary to differentiate between capital overruns which are the result
merely of general inflation and capital overruns which represent constant
(1982)dollar increases in the capital cost of the project should its costs
ri se faster than the general rate of i nf1 ati on.It was noted in the
Section 18.4 (c)which deals with the basic financing plan that the general
rate of inflation is inherently unpredictable in the long term,since it is
the result of complex worldwide political and economic forces which also
cannot be predicted.Providing,however,that suCh inf1 ation has a uniform
effect on prices and leaves the real rate of interest unchanged,it will
have zero impact on the net benefits of the project.The capital required
to complete the project will certainly increase in line with inflation but,
given that the net benefits are not adversely affected,this should not
lead to any significant risk that the project will not be completed.
Additional inf1 ation,far from chall enging the viabi1 ity of long term price
.stabi1 izi ng i nvestmentssuch as Susitna,shou1 d ge'!.E!ra11YI11~_k~Lthem m.o_re
desi-rableandurgent-fn-the-"prefere"nce-scafe-o-fthe majority of consumers.
In contrast to such i nf1 ati onary capital overruns whi ch shoul d not
adversely affect the economic viability of the project,capital overruns in
excess of inflation could,if sUfficiently large,result in the project
being abandoned.In this context,however,we must note that:
(i)The project involves only well established and proven technology and
hence is .not exposed to technological risk ;
Construction will be undertaken on a well-defined and carefully
surveyed site so that the project should be free from the extensive]
and unsurveyed terrain problems which led to environmental and .
geotechnical factors giving rise to major real capital overruns in -.J
the case of the A1eyska pipeline;and
(iii)The risk of any cons1:an1:(1,982)dollar overrun has been extensively
~~~m~~~~a~yp~~~:~i~~t~h~n~~~~~so:n~t:~~~~~t:~g~~e~~~~go~f~r~a~~e~ol
27 percent probability of occurrence.
I
-I
11
II
IIL_'
Taking these factors into account and considering the economic logic which
would require that already-incurred costs be disregarded in any completion
decision,it may be concluded that the risk of non-completion due to
captt~cost overruns is negligible.
(b) Post-completion Risks
(i)The Generation of Post-completion Risks
Any major project,dependent for its outcome on a range of different
factors,can be regarded as a risk-generating mechanism.The risks,
in terms of their actual outcome,can be either favorable or .
unfavorable.To make any general assessment of such risks,however,
the risk-generating mechanism in terms of its major variables must
be defined.These are summarized in Table 18.5.1 and define the
variables to which the project financial outcome is sensitive and
provide an estimate of the range of such variables together with
their corresponding probabilities.
Amajor variable in the risk-generating mechanism is the range of
capital costs in 1982 dollar terms.For purposes of this analysis
the probability distribution of the range of capital costs as given
in Section 18.2 has been reduced to the cumulative probability
distribution shown in Table 18.5.1.
Another variable to which the risk-generating mechanism is highly
sensitive is that of the rate of inflation and the related rate of
interest on the revenue'bonds and G.O.bonds fi nanci ng the i nvest-
mente Historically,inflation and interest rates have tended to be
closely,although not precisely,related,as can be determined from
Table 18.4.4.As was stressed in connection with that table,rates
of inflation and interest are subject to a wide range of uncertain-
ty.Furthermore,there exists no objective manner by which the
probabilities of different inflation and interest rates occurring
can be determined.As these are variables of fundamental importance
in the risk-generating mechanism,however,probabilities have been
estimated on a judgmental basis for a range of interest and
inflation rates.These center on the Data Resources Incorporated,
forecasts in Table 18.4.4 and result in the estimates given in Table
18.5.1.
The fourth variable to which the risk-generating mechanism is
sensitive is that of the rate of escalation of thermal fuels,
particularly coal.It is this which will primarily- determine the
cost savings Susitna energy will produce,and hence the wholesale
rate which Susitna may charge.This determines the revenue earned
by Susitna.The probabilities and range in this case are as given
in Section 18.1.
While other variables also have an impact on the risk generating
mechanism,it is the above four variables which are its primary
determinants.In the analysis each combination of these four
variables defines a particular financial outcome for the project.
18-80
lJ
U
IJ
-Specific Risk II:Inadequate Debt
Service Cover (Figure 18.5.2)
An adverse impact on the state credit rating-might occur if the
project failed to earn adequate debt service and cover,and
consequently,conversion into non-guaranteed revenue bonds was
delayed.The analysis showed that in the $2.3 billion state
appropriation case:
.The probability of forecast coverage being less than adequate
{i.e.,cover of less than 1.25}in 1994 (first normal year of
Watana)is .22.
The probability of a shortfall in coverage also diminishes with
time (due to increasing cost of alternative fuels).Reference to
the 1997 line in Figure 18.5.2 shows that the probability of
inadequate cover by that year is only .05.
-Specific Risk III:Early Year
Non-viability (Figure 18.5.3)
The third specific risk that may be considered to be of importance
is the risk that,although the project is fully completed and
operational,it is not completely financially viable in its early
years.A wide'range of the factors detailed in Table 18.5.1 could
lead to this result.For example,at the completion of Watana in
1993 the project might be unable to meet interest charges because
capital costs had been higher than expected (due, for instance,to
inflation or constant dollar overruns),or because interest rates
had been higher than expected, or revenues lower.
The probabilities of this occurring are analyzed in Figure 18.5.3.
This shows probability on the vertical axis,and on the
horizontal,the Watana costs in 1996 as a percentage of the cost
of the best thermal option.
Again, the reference financing scenario is that of the $2.3
billion state appropriation and the analysis is based on the
central estimates of capital cost,interest rates,revenues,etc.
This, as can be seen from Figure 18.4.4,should enable the Watana
output in 1996 to be produced at a cost (excluding excess debt
service cover)51 percent of the cost of the best thermal option
in that year.The 51 percent value is the reference point of the
results summarized in Figure 18.5.2.
The result which may be of particular concern relates to the.
probability of the Watana costs exceeding the costs of the best
thermal option so that the project either shows losses {i.e.,is
unable to meet its interest charges} or alternatively,insofar as
it is able,it is forced to charge a higher energy price than the
best thermal option.The probability of this occurrence is only
.05. There is also a .71 probability that Watana costs will be
less than the forecast level of 51 percent of the best thermal
option (see previous paragraph).
18-82
(iii)Aggregate Risk (Figure 18.5~4)
While specific risks of the type considered above are of importance
in eva1 uati ng particu1 ar aspects of the project,the basic concern
in the financial risk analysis must relate to aggregate risk.It is
inherent in the large number of independent varlables and the very
long time period involved in the Susitna project that,while many of
these factors at any given point of time will be deviating from
their forecast values,the deviations will,in total effect and over
time, tend to cancel out so that the aggregate outcome will be close
to forecast.There are,however,certain conditions under which
thi s II averagi ng out"wou1 d not occur.Thi sis where the outcome of
the project depends critically upon relatively few major factors
which are themselves very variable.
An essential purpose of the probability analysis is to evaluate this
variability in a systematic manner so that we can ascertain the
extent to which,long term, the averaging process will bring the
aggregate outcome for the project close to forecast despite the
inevitable variations from forecast of many of its component
forecasts.
A number of measurements can be made to test the aggregate outcome
for the project.The most obvious is that of the rate of return
which it earns.This was considered in some detail in Section 18.1.
The measure of aggregate outcome most appropriate for the financial
analysis in this case is probably the cumulative net operating
earnings at the end of the first nine years of operation of Watana
(i.e.,the year 2001,immediately before Devil Ganyonc()Jnes into
operation).These net operating earni ngs are after interest and
include accumulated interest on any deficits which may arise over
the period.
This statistic could not,however,reflect the impact of favorable
outcomes which reduced the cost of the Watana output below its
forecast level.This is because the requirements of Senate Bill
25 governing the wholesale electricity rate would oblige the APA to
r~<:lI,(c;e'thEtpriceofWatanaenergyin 1ine with the lower cost so
that no additi ona1~gai ns_.w.o~u]_d_show~~up-jn-the--net-ope)"a~t-ing-~~~..........-.~_~.._.~.__.-_._..-'--~-'----earni ng-5.In order to make the stati sti c refl ect the II upsi dell as
well as IIdownside ll possibilities,it has been reestimated for the
present analysis on the assumption that the APA would have the
freedom to set the wholesale price of the Watana energy at higher
levels up to the full cost of output from the best thermal option.
On thi s basis the resu1 ti ng net operati ng earni ngs at the year 2001
fully reflect all favorable as well as unfavorable possibilities,
picking up both the cost savings to consumers in the favorable
outcomes and the excess costs arising from the adverse ones.
The results of this analysis for the $2.3 billion state appropria-
tion scenario are shown in Figure 18.5.4.Again,probability is
shown on the vertical axis.On the horizontal axis is shown the
cumulative net operating deficit or surplus at the year 2001
18-83
I
1
I
,I
I
:1
I
I
I
I
I
)
,I
I
,.,
!
I
IJ
u
u
I 'lJ
(c)
(reexpressed in terms of 1982 dollars).The reference point of the
figure is the forecast of $0.8 billion net operating surplus which
would have occurred if the central estimates used in the financial
analysis were realized.The $0.8 billion kherefore represents the
"forecast"against which the other outcomes can be assessed.
On the basis of this analysis,the probability of the net operating
surplus being.less than the forecast level is only .27.The
probability of the surplus being less than $0.6 billion is only .2.
Moreover,counter-balancing these adverse possibilities are the
probabilities shown of very much larger surpluses arising.This
would lead to very much larger cost savings being conferred upon
Alaskan consumers than the forecast $0.8 billion.There is,for
example,a .35 probability of the surplus exceeding $1.4 billion.
Conclusions
The main conclusion of this analysis is that the project at the Watana
stage has onlyttntted exposure to adverse outcomes in terms of specifi c
risks,particularly those of financing overruns, delayed revenue bond
conversion or failure tg realize early year cost savings once it is in
operation.An importahtqua1ification attaching to the risk of financing
overruns is that a point of reference is the forecast capital requirements
in terms of 1982 dollars.It is inherent in the extreme unpredictability
of the rate of inflation over the long term that forecasts of financing
requirements in terms of then-current money (e.g.,money of the purchasing
power of the years 1985 to 1992 when the financing takes place)would prove
to be sUbstantially in error.It is,however,the risk of financial
overrun in terms of today's purchasing power which represents the only
meaningful assessment of this particular category of risk.
As regards the aggregate risk as measured by the net operating surplus or
deficit over the first nine years of Watana's life,there is only a
relatively low probability of this variable failing to achieve its forecast
1evel .Thi s 1owprobabi·1 ity a1 so extends to the chance that the project
would not realize cost savings as large or even larger than those forecast
in the central estimate.
The qualification attaching to all the foregoing analyses is that the
estimates and probabilities used are free from any systematic biases which
might render them unrealistically favorable.The approach to the study for
Susitna and the analysis of its alternatives has been specifically designed
to guard against this possibility.The Acres capital cost estimates have
been subjected to independent verification by EBASCO and the economic
estimates independently assessed by BATTELLE.Every practical precaution
has been taken to exclude the possibility of any such systmatic bias,and
to base the analysis on consistently objective estimation.
18-84
BASIC PARAMETERS OF RISK GENERATION MODEL
COAL PRICE ESCALATION (%REAL)
2.6 to 2000 5.0 to 2000 •
0
1.2thereafter 2.2 thereafter
PROBABI LITY .25 .50 .25
INTEREST RATES %
r,,
5-7 7-9 9-11 11-13
PROBABILITY .10 .32 .43 .15
INFLATION RATE
DIFFERENCE FROM INTEREST RATE
-2%-3%-4%
PROBABIL1TY .33 ..34 .33
CAPITAL COSTS (REAL 1982 $billion)
Below 3.1 Below 3.6 Below 4.3 Below 5.1
PROBABILITY .46 .73 .90 1.00
TABLE 18.5.1 •
Il
SPECIFIC RISK I: RISK OF BOND REQUIREMENT OVERRUN
Bond Requirements for Watanain $bn (1982)
FIGURE 18.5.1 - BOND FINANCING REQUIREMENTS
ForecastWatana Borrowing Requirement
/"in $2.3 bn Appropriation Case
4.03.01.7 2.01.0
-....
II
1.0
II 0.9
0.8
0.7
>0.6:=::s 0.5ra.Qe 0.4Q.
0.3
0.2
0.1
0.0
I ]Ii
IJ
SPECIFIC RISK II:IMPAIRMENT OF STATE CREDIT
Minimum Cover Requirement
.........fIIIIII'-..-1994
1.0
0.9
0.8
0.7
\J
>0.6:!::s 0.5ra
.Q
Q..0.4[]Q.
0.3
0.2
U 0.1
0.0
1.0 1.25 2.0 3.0
.-1997
4.0
Coverage on Bonds Issued for Watana
FIGURE 18.5.2 - DEBT SERVICE COVER
SPECIFIC FINANCING RISK III:EARLY YEAR NONVIABILITY
1.0
0.9
0.8
0.7
~0.6
:s 05oS.
~0.4
0.3
0.2
0.1
0.0
-20 -10 0
Forecast Watana Cost
as %BestThermal
/
10 20 30 40 50 60 70 80 90 100 110 120 130
Watana Unit Cost as %of Best Thermal
FIGURE 18.5.3 -WATANA UNIT COSTS AS PERCENT OF BEST THERMAL OPTION IN 1996
AGGREGATE RISK:POTENTIAL NET OPERATING EARNINGS
Forecastin $2.3 bn
State Appropriation Case-:0.0__
-0.6 -0.4 -0.2 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4
Cumulative Net Operating Earningsin $bn (1982)
1.0
0.9
0.8
0.7
~0.6
:soS 0.5
ECl.0.4
0.3
0.2
0.1
11L-1
I Iu
lJ
U
FIGURE 18.5.4 -CUMULATIVE NET OPERATING EARNINGS BY 2000
I
.!
l]
lJ
1
-.I
I
IJ
lJ
lJ
LIST OF REFERENCES
(1)U.S.Department of Labor,Monthly Labor Review,various issues.
(2) Alaska Department of Commerce and Economic Development,The Alaska
Economic Information and Reporting System,July 1980.
(3)Data Resources Inc.,U.S.Long-Term Review,Fall 1980,Lexington,
M.A.,1980.
(4)Wharton Econometric Forecasting Associates,Fall 1981,
Philadelphia,P.A.,(reported in Economic Council of Canada
CANDIDE Model 2-0 Run,dated December 18, 1981.)
(5)Baumol,W.J.,"On the Social Rate of Discount",American Economic
Review,Vol. 58,September 1968.
(6)Mishan,E.J.,Cost-Benefit Analysis,George Allen and Unwin,
London,1975.
(7)Prest,A.R.and R.Turvey,"Cost-Benefit Analysis: A Survey",
Economic Journal,Vol. 75,1965.
(8)U.S.Department of Commerce,Survey of Current Business,various
issues.
(9)Data Resources, Inc,, personal communication,November 1981.
(10)World Bank,personal communication,January 1981.
(11)U.S.Department of Energy,Energy Information Administration,
Annual Report to Congress,Washington,D.C., 1980.
(12) National Energy Board of Canada,Ottawa,Canada,personal
communication,October 1981.
(13)Noroil,"Natural Gas and International LNG Trade", Vol. 9, October
1981.
(14) Segal,J."Slower Growth for the 1980's",Petroleum Economist,
December 1980.
(15) Segal,J.and F. Niering, "Special Report on World Natural Gas
Pricing",Petroleum Economist,September 1980.
(16)SRI International,personal communication,October 1981.
(17)World Bank,Commodity Trade and Price Trends,Washington 1980.
(24 )
LIST OF REFERENCES (Continued)
(18)Battelle Pacific Northwest Laboratories,Beluga Coal Market Study,
Final Report, Richland,Washington,1980.
(19)B.C.Business,August 1981.
(20)Coal Week International,various issues.
(21) Japanese Ministry of International Trade and Industry,personal
communication,January 1982.
(22)Canadian Resourcecon Limited,Industrial Thermal Coal Use in
Canada,1980 to 2010,May 1980.
(23)Battelle Pacific Northwest Laboratories,Alaska Coal Future
Availability and Price Forecast,May 1981.
Roberts, J.O.et al,Treatment of Inflation in the Develo~ment of
Discount Rates and Levelized Costs in NEPA Analyses or the
Electric Utility Industry,U.S.Nucl ear Regul atory
Commission,Washington,D.C., January 1980.
(25)Acres American Incorpo~ated.Report on IIEconomic,Marketing and
Financial Evaluation ll for Susltna Hydroelectrlc ProJect.
I
I
j
j
j
I
j
I
I
I
j
·1
j
I
I
j
,I