HomeMy WebLinkAboutHouse Bill 9 Power Rate Structure Analysis 1983HOUSE BILL 9
POWER RATE STRUCTURE ANALYSIS
By
STATE OF ALASKA
DEPARTMENT OF COMMERCE &·ECONOMIC DEVELOPMENT
ALASKA POWER AUTHORITY
334 West Fifth Avenue
Anchorage, Alaska 99501
March 1983
HOUSE BILL 9
POWER RATE STRUCTURE ANALYSIS
By
STATE OF ALASKA
DEPARTMENT OF COMMERCE & ECONOMIC DEVELOPMENT
ALASKA POWER AUTHORITY
334 West Fifth Avenue
Anchorage, Alaska 99501
March 1983
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MEMORANDUM
To. Eric P. Youlrl
Executive Oirpc+nr
FROM: ~1ylPs C. Yerkes
Director of Sv5tems &
Planning Operations
StaLe of Alaska
DATE:
FILE NO:
TELEPHONE NO:
SUBJECT: Marketino of Proiect " .... Power Under the EnProv
Program for Alaska. -
In discussino revisions to Power Sales Agreements required by ~ouse
Pill #9 w'ith concerned utilities, ma.ior problems \'lith the Energy Progral'fl
for Alaska surfaced. The Al a.ska Power Authority must consider modifica-
tions to this program or othP.r actions necessary to secure power sales
agreements with related utilities. Problems primarily relate to the
inability of the current proqram to establish a reasonable and
predictable ener~y rate for power customers under the program.
Utilities voiced concern with current-program language which allows the
debt service for a particular project t~ be increased bv thP Leoislature
or the Power Authority without control by the utility. ·Utilities are
understandably resistive to signing such ltTake or Pay 11 agreements since
the ecor.omic impact to rel~ted communities could be devastating.
The first major concern is the estimated initial cost of project
power. Projected wholesale power rates by the financial group indicate
Tyee at 18rt per kilowatt hour in the initial years of operation with a
very slow tapering foll~winq that period. Since existinq utilities in
the area (Wrang~11 and Petersburg) are currently generating power from
diesel plants at a cost of approximately 10~ per kilowatt hour, it is
difficult, if not impossibl~, to market the project energy at this rate.
This problem is not exclusive to the Tyee project, but will in all
probability arise for most projects in the program. Program debt
service must bP. reduced to in turn reduce the initial wholesale power
rate. Since the Power Authority has no means to generate such revenue,
it appears that our only option is to request the State of Alaska to
appropriate additional funds to pro(]re~.m construction to reduce future
debt sP.rvice. Unless debt servicP. is reduced to allow marketing of
project power at or slightly above the present cost of utility diesel
gen~ration, I sincerely doubt utilities will complete or abide by the
terms o~ existing or proposed power ~ales agreements.
The second major concern is the inabi1itv of utilities to nredict
future wholesale power rates due try cur·rent program language which
allows debt service to be increased bv the Legislature through approval
of additional projects tc the program or implementati~n of the "Susitna
Rlackmai1 Clausen. "Take or pav 11 wholesale power agreement<.; with
utilities are required to secure revenue bond financing o~ project costs
above that appropriated by the State. For utilities to assume such a
f'inancial responsibility, they must see a oredicable and reasonable
wholesale power rate throughout the life of the contract.
rurr~nt l~ois~atinn ~""~ nnt mP~ thi~ critnri~ ~inc~ costs r~n b~
un11at~rallv i!'lCrP:;c;Pd t0 th.::o ut Htirc-, hy th(l P'11riP.r 1\ut.hnritv fl0;:~rri 'lr
the L~qisl~tur~ without concid~r~tin~ o' al'~rn~tivp~ to th~ utflitv.
Tr'l t;.!lmr-lcH·•;, F \.If-' ,-,r•• +;, hP ::ut:r;:c::d'ul in f"''trh•tin"l Pr'!\ot~r ;,;:1e<: ·
P.crr:~mertts rNHJ i r~d fnr proj;:-ct r~V~"'"'UP. hondi no. r-urrr:r.t r>ro~r~m
1~qisl.Hion t1Uc::" b'? anenrlec tr-· rpstrict the St~te fror. unr!"~Sonablv
incr~?~ino rle~t SPrvic~ to ~ pr~iect cr cau~ino rnt~~ to rfs~ ~hnv~
r~a~onable a1tern~tivPs.
ThF! third cnncerr is the abiHtv of the PowPr Authoritv tn pr~vid~
stable wholesale r0wer ratP5 to the pur~;,asing consuffll:lr. Thic: nr0bl!\M
?.rises primarily fro!'!! two t~reas. Fir~t is the ability of the
leq1 s 1 .11turP or thf" Pow~r Authority Rtio rd to ?.11 ow rew nrc.iects urder thP.
proqr~m and ~sses~ increas~d debt service ~o eristing utiliti~s withnu~
spe~i#ic rpg~rrl ~" prir~ ~tab11izet1n~ to the ult1m~te ~o~sumino oublic.
Second is program languaoe which impl icc; t:hat wl'!oll"~.:lle power r~t~s nuo;t
be based uocn estimated OfH?r(ltir.n i!nrl m.?lintPnill'lCf! e:vpen!:~ for th-:
upc!'mi'lg ye~r. If we· are to provide r~~sonably stable who1~~a1e power
rates a~d pr~pPr pric~ signaling to th~ gpneral public, th~n currPnt
progral'!" l~(]islation mus.t he mcc1i~ipd or intP.rprf:"ted to allow the Power
~uthoritv to ammortize ~nnual oneration ~nd ~aintPn~n~e co~t over a
reasonable per1f"rl. to t.t11ow f'or reasonah1e price ad.iustP~ent on a ve3r hv
_v~~r b~sis .lin<:' avcid the ~ppe~r::~n~~ af hud9t?t or fi~cal
irrpspon~ihility. Such a nol1cv would acc:onnodate proaram l~nquaaP.
reauiring purchas,~rs pay the ongoina cost of pro5ect ooeratfons,
~eintenance, anrl debt service but would ellow the Power Authority to
ammortize operntion a"d Maintera"ce cost over a perio~ of several years
if reouired to provide reasf'lnable ~nd uniform who1P.sa1e power ratPs.
The f1na! probleM is the ability of Utilities to 5P.t powar r'ltPc;
for dif~erent c1a~ses of custoners ir: accordanc~ with ~ost 0f service
principlll!ls ~enerallv recn~nized hv the ~tate and Fed~ral Re~ulatorv
Commissions. Gu rrP.n t program 1 a nguage requ i res that a purcha sesr of
project enP.r~y maintain oower rat~s for industrial class customers equal
tn or above that provided to a residential class customer. Utilities
have indicated concern th~t this ~v restrict their ability to market
pnwer on a rt~asonable cost hasis to industrial customers and would
hinder economic growth and ~~panded utilization of the hydroelectric
pro.jects. t1ti11t1es have suq~ested that current r1rooram 1 anguage be
chanqed to dP.l~te this requiN~~nt and ;11law a utility to SPt r?.t.es for
all ~l~s~e~ of custoMers in eccordao~~ wi~h r.ost of SPrvice princip?ls
aPn~ral1y accP.ptable or nporoved hy the FERC ~nd the ~1aska Puhlic
11!i1 Hies Comission.
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Th ... ~r~JklF:n ~t·=~;~.-: ~ic;ruc::t:~rl muc;t hr:: dr,:.lt ~,o.,ith rfurin9 this
'trf'iS1ative p~·riorl i~ Wf' .lrF ~Q c::urCf'St:zullv Mil!"'~(>t' ~J,,:-. n~u~r f"rom
nr\liects un~Pr t:hf' ~nr.:~r11v Pr0cr,..,~ J:nr ,lll11c:k?. :"'~C ~·~rfur::"' ... h" f,,,-:<-"htivP
f"f)r. l! uti 1 f tv t.0 r!pf·~u't t 0!"1 ,1~ e•x; s ~ i 110 .:~q~·a<=>,.,.::r.t. Yrur co:ur.nl"rt i 1 f'ld
participation will bP critic~l.
~~v 1 P. s C • Y e rk c s
O~rrctrr of Systems
Planning & 0~er~ti"ns
cc: Paymond \1. ~enish, A.flf., flnchoragf'
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HB 9 POWER COST STUDY
1. INTRODUCTION
2. DESCRIPTION OF HB 9
2.1 History
2.2 Wholesale Power Rates Under HB 9
3. WHOLESALE POWER RATE FORECASTS UNDER HB 9
3.1 Forecast Assumptions
3.2 Power Rate Forecasts
3.3 Retail Power Rates Under the Power Assistance Program
4. EARLY YEAR POWER COST, SYSTH1 INCREMENT AND UNTFORM RATE PROBLEMS
UNDER HB 9
4.1 Problems
4.2 Solutions to the System Increment Problem
4.2.1 Stand Alone Legislation
4.2.2 Higher State Equity Contributions
4.2.3 Low Interest Rate Loans
4.2.4 Eaualization Grants as an HB 9 Over-ride
4.2.5 Equalization Loans
4.2.6 Standardize State Financing Until System ~aturity
5. MARKETING AND DEVELOPMENT
6. SUMMARY AND CONCLUSIONS
Appendix A Project Descriptions
Appendix B Assumptions Used For HR 9 Forecasts
Appendix C Description of Financial Model and Power Rate Calculation
~1ethodo 1 ogy
Appendix 0 Eval~ation of Blackmail Clause
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1 -INTRODUCTION
At its inception in 1979/80 Alaska's hydroelectric program was provi-
sionally based on the estimates that hydro units would come on at a
period when thermal energy costs had continued to rise and the units
w~uld be substantially financed by the State of Alaska. This program,
l1ke many other energy programs elsewhere, now needs to be reviewed in
the light of the currently prevailing circumstances under which some of
the projects are expected to be· substantially debt financed and may come
on stream at a period when there has been a significant weakening in
thermal energy prices.
This poses a number o-f problems which need to be addressed in the
context of the HB 9 legislation which effectively interlocks the power
rates of a 11 projects in the system. The paper first describes the
essentials of the HB 9 legislation and then considers the present status
of the first four authorized projects (Swan Lake, Tyee Lake, Solomon
Gulch and Terror Lake) in the light of this legislation. lt then outs
forward a number of possible solutions to the problems posed by this
legislation for consideration by the Board before further development
proposals are presented to the legislature.
This presentation focuses on the rate setting formula and presents four
alternatives to attain a wholesale power rate comparable to the
projected thermal rates. This approach may inadvertantly create the
impression that HB 9 is itself a problem. However, the Power Authority
does not in any way take issue with the legislation and believes that
HB 9 is an equitable and workable rate setting mechanism.
2 -DESCRIPTION OF HOUSE BILL 9
2.1 -Historv
During the last session of the Legislature, HB 9 (subsequently enacted
as Chapter 233, SLA 1982) was adopted to amend the Energy Program for
Alaska.
The major and most detailed change introduced by HB 9 was to establish a
system related but project-specific wholesale power rate rather than a
single system-wide wholesale power rate. Under the previous legisla-
tion, the single wholesale power rate was calculated by totaling the
opera.tion and maintenance costs, inspection fees, and debt service .costs
for all projects in the system, then dividing by total sales to arrive
at a cents-per-kilowatt hour rate, which would be applied to all project
sa 1 es. The new and somewhat comp 1 ex power rate system is outlined
below.
2.2 -Wholesale Power Rates Under HB 9
Under the new HB 9 legislation a project's power rate vlill be based on
the followina three components: (1) it's own operation and maintenance
costs, (2) ft•s own inspection fees, and (3) a portion of the total
system debt service.
2
The 0/M and inspection fee portion of the power rate is simply the
actually incurred costs divided by project sales.
The debt service portion of any individual project's power rate is the
most significant aspect of the legislation and is most easily described
by the following formula. The debt service component is
where
~)
( X -y ) Z
( y - p )
x = the state's total investment in the particular project
y = the state's total investment in all projects within the energy
program for,Alaska
z = total debt service including coverage for all projects for the
year in question
p = the amount of principal repaid as at the date of the calculation
This formula, however for our present purposes, simplifies to:
X t' Y 1mes z
Thus total system debt service z is allocated to individual projects on
the basis of the project's share (x/y) in the total investment by the
state. This formula holds, regardless of whether a project itself has
incurred any debt service.
In essence, this formula therefore allocates debt service so that each
project pays the same amount of debt service relative to project cost as
all other projects. Thus the benefits of state grants, directed towards
specific projects, will be shared by all.
This methodology is complicated by subsection {c) (h) of the legislation
which places a "cap" on the level to which the debt service component of
the wholesale rate can increase in any one year. The 11 Cap 11 rate each
year is eoual to the average system debt service rate (total system debt
service divided by total sales) times a factor which increases by four
percent per annum from one in 1983. If any projects have the debt
service portion of their rates capped then the other projects, whose
rates are still less than the cap rate, will have their rates adjusted
upwards {to a maximum of the cap rate) so that sufficient revenues are
collected to meet debt service obligations of the entire system. This
allocation of the remaining debt service is again based on project cost.
This "cap 11 provision applies only to Swan, Tyee, Terror and Solomon
Gulch. In consequence, any new projects will have to carry a corre-
spondingly higher burden of debt service.
The final wholesale power rate then is the sum of the operating cost
rate and the debt service rate. Further details of the methodology for
power rate calculations is contained in Appendix C.
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3 -WHOLESALE ·POWER RATE FORECASTS FOR; SWAN LAKE, TYEE LAKE, SOLOMON
GULCH AND TERROR LAKE
In this section the effect of the HB 9 legislation on wholesale power
rates for the Swan Lake, Tyee Lake, Sol oman Gulch, and Terror Lake
projects are examined to the year 2001. Power rate calculations und!r
HB 9 depend not only on the usual parameters such as project cost ,
sales and financing, and economic variables such as inflation and
interest rates, but also on which pro.iects are included in the calcu-
lations. For example, Solomon Gulch, with a current wholesale rate of
3~/kwh, would see its rate increase substantially when the Swan Lake and
Tyee Lake projects are brought on-line and into the calculations in
FY 1985.
3.1 -Forecast Assumptions
The forecasts presented are based on the assumptions detailed in Appen-
dix B. A detailed description of the forecast methodoloqy and model are
provided in Appendix C.
3.2 -Wholesale Power Rates
Table 1 gives the wholesale power rates for each of the four authorized
projects under the existing HB 9 legislation. The table is essentially
for record and does not compare the results with the cost of therma 1
power. This is considered in the fuller context of the analysis of
Section 4.
TABLE 1
WHOLESALE POWER RATES UNDER HB 9 {¢/kwh) IN THEN CURRENT DOLLARS
Swan Tvee Solomon Terror
% Debt/% Equity 26/74 367"t4 0/lOO 58!42
1985 11.4. 12.1 9.7 N/A
1986 15.0 15.8 10.1 12.3
1987 15.1 16.1 10.1 11.7
1988 15.2 16.3 10.2 11.1
1989 15.2 16.6 10.4 10.6
1990 14.7 16.9 10.7 10.2
1991 14.3 17.4 11.0 10.1
Project Summarl *
Total Project
Cost Insta 11 ed On-line Utilities
Project ($millions) Caoacit;t Date FY Served
Swan Lake 93.50 22.5 MW 1985 Ketchikan
Tyee Lake 124.60 20 MW 1985 Petersburg/
vJrange 11
Solomon Gulch 53.00 12 MW 1983 Copper Va 11 ey
Terror Lake 189.40 20 MW 1986 Kodiak
Total 460.50
* See Appendixes A and B for further details
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3.3 -Retail Power Rates Under the Power Assistance Program
The impact of the hydro projects on retail rates for the regions served
are materially reduced at the retail level by the Power Cost Assistance
Program. This in outline provides (with some limitations} for 95·
percent of the cost of power in excess of 15 cents per kwh in 1985 to be
covered by State grants to the utility. T~is reference level of 15
cents in 1985, however, increases by one (1) cent each year. The effect
of this in mitigating the early year cost of the hydro projects is shown
in Table 2 in the context of the retail power rates to which the Power
Cost Assistance Program provisions apply.
It is seen from this that after the power assistance grants, the average
net retail cost (after the Power Cost Assistance is applied) of the
hydro power to consumers is competitive with that of thermal for all
projects in 1985.
The effect of Terror Lake coming on in 1986 is to introduce a jump in
the cost of power for the whole system. This occurs as a result of the
debt/eouity ratio for Terror Lake which is substantially below the
system average. This, as also shown in Table 2, results in Tyee Lake
having a cost of power nine percent higher than thermal.
TABLE 2
AVERAGE NET RETAIL POWER RATE
UNDER POWER ASSISTANCE PROGRAM
Power Swan Tyee Solomon Terror
Assistance Gt/KWH C/KWH rt/KWH tt/KWH
Level Hydro Thermal Hydro Thermal Hydro Therma 1 Hydro Thermal
1985 15.0 14.4 16.1 16.1 16.4 14.3 20.2 N/A N/A
1986 16.0 17.1 17.2 19.1 17.5 15.1 21.6 17.8 18.3
1987 17.0 17.8 18.4 19.8 18.8 15.5 23.2 17.9 19.6
1988 18.0 18.5 19.6 20.6 20.0 16.0 24.7 18.1 20.9
1989 19.0 19.1 20.8 21.4 21.3 16.6 26.3 18.1 22.3
1990 20.0 19.0 22.1 22.2 22.7 17.3 28.1 18.3 23.8
1991 21.0 18.8 23.5 23.1 24.1 18.1 30.0 18.7 25.4
1. See Appendix A for project descriptions
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It is possible that these temporary differentials, in net cost, will be
lower and that they will be acceptable to the local utilities as a small
price for the major long term benefits conferred by having large re-
sources of low cost hydro power indefinitely. The .Power Authority
planning must, however, prepare for the contingency that this is not the
case since, short term, it depends both on the unpredictable short term
cost of fue 1 oi 1 and on the continuance of the Power Cost Assistance
Program. It is also possible that the utilities will wish to negotiate
the power rate, while ignoring the Power Cost Assistance Program.
The following section, therefore, reviews the HB 9 legislation and the
competitive position of the hydro development at the wholesale power
rate level excluding the mitigation effect of the Assistance Program.
4-THE EARLY YEAR POWER COST, SYSTEM INCREMENT
AND UNIFORM RATE PROBLEMS UNDER HB 9
4.1 -The Problems
The wholesale power rates as they stem from existing legislation (and as
shown in Table 1) need to be considered in the context of the estimated
cost of thermal power generation from existing capacity in the areas
served. Here the economics of the Swan, Tyee and Terror Lake projects
are each seen to be materially affected by three interrelated problems
arising from their basic economics and the impact of the HB 9 legis-
lation. The problems are:
The Early Year Power Cost Problem
This is the problem of .the recent weakening of oil prices which may
result in making the early year cost of power from the hydro projects
being higher than the early year cost of the diesel operation which they
displace.
The Svstem Increment Problem
This is the problem of all power rates on the system being increased
through the HB 9 mechanism when a new project is introduced to the
system and the project has a higher proportion of debt finance than the
average of the existing system as a whole. The Terror Lake project is
more heavily debt financed than the existing projects (5R percent
compared with 26 percent). When this project comes on stream in FY 1986
the effect of HB 9 is to share this increased cost of debt service among
all four projects and so further increase the cost of power for Swan
Lake, Tyee Lake and Solomon Gulch .
The Uniform Rate Problem
The HB 9 legislation requires that a single-power rate be established
for each project. As noted in Section 5, this creates underutilization
and consequently higher unit costs by precluding the Power Authority
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f:"'>
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The effect of the early year power cost problem alone is shown in
Table 3 on the assumption that diesel oil costs increase by only the rate of
inflation between the end of 1983 and the first year of service (FY 1985). On
this assumption, in 1985 all projects show power rates less than local thermal
generation cost. ·
However, a problem occurs when Terror Lake is brought into the calculations in
1986. This is the System Increment problem -the effect of HB 9 when a higher
r;:._ than system average debt financed project is added to the system. When this
occurs it is seen from Table 3 to have the effect of:
(i) increasing the cost of power of Swan and Tyee over their 1985
level by 32 percent and 31 percent, respectively (even with the 11 Cap 11
in place);
(ii) making the cost of power of Tyee Lake 15.8 ¢/kwh compared with
13.4 ~/kwh for diesel generation.
Terror Lake itself, with its higher debt service, would come in at approximately
the same cost as thermal. On the inflationary assump.tions given, it would take
four years to close the net cost gap between thermal and hydro for Tyee Lake.
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,..,, .... ,, ·-"~ r·..,.. ; ~ ..... . ... . .. "• ""' ,j ' ·' & ' ' '
TABLE 3 ---
EARLY YEAR COST OF POWER & SYSTEM INCREMENT PROBLEM
WHOLESALE RATE {¢/kwh}
Swan Tyee Solomon
% Debt/Equity 26/74 36/64 0/100
Hydro Hydro Hydro Hydro Hydro Hydro
Without With
Therma1 1 Terror Terror Thermal 1 Without ~Jith
Therma1 1 Without With
Terror Terror Terror Terror
1985 14.1 11.4 11.4 12.5 12.1 12.1 18.1 9.7 9.7
1986 15.2 11.8 15.0 13.4 12.7 15.8 19.5 9.3 10.1
1987 16.3 12.0 15.1 14.4 13.0 16.1 ?0..9 8.9 10.1
1988 17.4 12.2 15.2 15.4 13.4 16.3 ?.2.4 8.5 10.2
1989 18.6 11.9 15.2 16.5 13.8 16.fi 24.0 8.6 10.4
1990 20.0 11.5 14.7 17.6 14.1 16.9 25.6 8.8 10.7
1991 21.4 11. 1 14.3 18.9 14.5 17.4 27.5 9. 1 11.0
1 Source: Based on 1981/1982 utility accounts for; Ketchikan, Wranqell, Petersburg,
Copper Valley and Kodiak.
Diesel oil price assume constant until 1984 and increasing
thereafter in line with inflation (as given in Appendix R).
Units o/a costs assumed to increase with inflation from 1981.
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Terror
SA/42
Therma1 1 Hydro
N/A N/A
13.0 12.3
14.0 11.7
15.0 11.1
16.0 10.6
17.1 10.2
1A.4 10.1
4.2 -Solution to the Early Year Power Cost
and System Increment Problem
Possible Solutions
It is seen from the preceding analysis that the Early Year Power Cost
problem alone is not unduly severe. The System Increment problem,
however, is of considerably great seriousness first, because it com-
pounds the Early Year Power Cost problem by increasing the cost of power
whenever heavily-debt financed projects are added to the system.
Second, and of more importance, it places the utilities in a position of
appreciable uncertainty as to the future burden of power costs which
·they might be obliged to assume through the HB 9 mechanism.
It is true that the HB 9 mechanism does provide a "cap" for the existing
four projects on the rate of increase of individual project power rates
resulting from new increments to the system. But this does .not rectify
the basic fact that over the long term, utilities coming into the system
are exposed to what might appear an open-ended liability to meet their
share of whatever the debt service cost is of additional increments to
the system. This was not a material issue while expectations were that
the hydro power, even in the early years, would be less expensive than
the highly escalating cost of the thermal option and there was the
general expectation that the hydro additions would, in very large
measure, be financed by equity contributions from the State~ With the
weakening of both these expectations, a concern on the part of utilities
joining the system as to the extent of escalation in future hydro power
costs is understandable. It is also possible that this combined with
the Early Year Cost of Power problem {which it exacerbates) will result
in.difficulties in negotiating contracts with the local utilities.
This problem has no easy solution. A range of possible solutions have
been considered and are as outlined below.
4.2.1 -Stand Alone Leg~slation
The first option to be considered is that of amending HB 9 such that
future projects had a calculated cost of power which was on a stand-
alone basis, that is, the "new 11 projects were exempt from the HB 9 debt
service sharing provision. This would indeed shelter the existing
projects from any high debt service component of new projects, but would
have the obvious serious disadvantage of 1 eaving these new projects
disadvantaged relative to the projects which preceded them under the
HB 9 legislation.
At a practical level it would also appear to be unacceptable since, for
example, in the case of Terror Lake it would imply a wholesale cost of
power in the first year {1986) of 15.4 cents and 25 percent higher than
under HB 9. Rather than meet this cost of power. {estimated to be some
25 percent higher than that of the thermal option) the local utilities
might feel obliged to forego the very substantial long-term advantage
which would be conferred by the fact that the cost of the hydro power
would be virtually fixed in money terms.
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In summary, the 11 Stand-alone 11 solution would involve the probability of
foreQoing the long-term falling real cost of power which the present
hydroelectric program is designed to achieve.
4.2.2 -Higher State Equity Contributions
Higher State Equity Contributions than those which form the basis of the
forecast power rate of Table 1 would have the overall effect of reducing
power rates and so helping to resolve the Early Power Cost and System
Increment problems. The major difficulty with this solution, however,
is that the HB 9 legislation effectively shares the benefits of any
larger state equity in any particular project between all the projects
in the system thus reducing all power rates. In consequence, higher
State Equity contributions to reduce the cost of power, in the case of
Lake Tyee for example, would have the ·effect of reducing not only the
Lake Tyee power rate, but a 1 so the power rates of Swan Lake, Terror
Lake, and Solomon Gulch, although the last would already have a power
rate 50 percent less than the cost of thermal under the existing
proposed financing. Moreover, this sharing of the benefits of greater
state equity of necessity, means that much larger state equity is
required to reduce the power rate of any given project. The numerical
effect of this is shown in Tab1e 4.
TABLE 4
WHOLESALE POWER RATES RESULTING FROM ADDITIONAL
STATE EQUITY CONTRIBUTIONS
Swan Solomon Gulch
Thermal Rate
1985
1986
1987
HB 9 Rate Under Base
Financing Assumption 1
1985
1986
1987
HB 9 Rate After
Additional State
Grants of $40 million
1985
1986
1987
14.1
15.2
16.3
11.4
15.0
15.1
11.4
12.5
12.7
12.5
13.4
14.4
12.1
15.8
16.1
12.1
13.4
13.7
18.1
19.5
20.9
9.7
10.1
10.1
9.7
8.6
8.8
Terror
N/A
13.0
14.0
N/A
12.3
11.7
N/A
9.9
9.6
1 See Appendix B Tota 1 state contributions assumed to be
$281 million (approximately 60% of total financing)
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This estimates the total additional equity contribution which will be
required to ensure that all the power rates from the authorized projects
are below the cost of thebest thermal option. As seen from Table 4,
Lake Tyee presents the most serious problem with a cost of power
2.4 cents higher than the thermal cost in 1986. Consequently, the
equity contribution would be determined by whatever was required to
achieve this objective. It would, however, require $40 million of
equity. As can be seen from the table, this makes Lake Tyee equal in
power rate to the cost of therma 1 by reducing the cost by 2. 4 cents.
But it a 1 so reduces the cost of power for Swan, So 1 oman Gulch, and
Terror Lak~ by 2.5, 1.5, and 2.4 cents . respectively in 1986, thus
bringing their cost well below the cost of thermal power in their areas.
This is again beca~se the high equity contribution to Lake Tyee has the
effect, through the operation of HB 9, of reducing all other power
rates. It is because HB 9, effectively makes it necessary to reduce all
power rates in order to reduce any one of them by greater equity! that
the magnitude of the equity contribution at $40 million is so large.
4.2.3 -Low Interest Rate Loans
The Early Year Power Cost and System Increment problems could also be
reduced by the state providing financing in the form of low interest
rate 1 oans. The 1 arger the amount of such 1 oans and the 1 ower the
interest rate, the lower the burden of debt service which HB 9 would
require to be shared among all the projects on the system.
This solution, however, has much the same disadvantages as the higher
state equity proposal considered above. Again the whole of the benefit
of this low cost form of financing would be shared among all projects on
the system irrespective of their power. rate so that the problem of
sharing applies here as in the equity financing case.
Moreover, in terms of the total level of appropriations required, this
proposal would require very much higher appropriations than in the
greater state equity case. This is because it would require
$2.4 million of (say) five percent interest rate money to reduce power
cost by as much as Sl million of state equity since the latter involves
no burden of interest or repayment. Hence the low interest loans will
have all the adverse affects of greater state equity and the addition
\vould require appropriations 140 percent higher to achieve the same
impact on the power rates.
4.2.4-Equalization Grants as an HB 9 Over-ride
It is clear from the options considered above that any state assistance
in meeting the Early Power Cost and System Increment problems through
state fi nanci no assistance is made very costly by the effect of HB 9
sharing the benefits among all the projects on the syst.em, irrespect~ve
of their existing power rates. Economical and effect1Ve state ass1s-
tance therefore, needs to be in a form which was not treated in this
way by the HB 9 division and so could be directed at the particular
projects which have the Early Year Cost of Power and System Increment
prob 1 ems.
11
This could be achieved by a system of annual "Equalization Grants 11
directed towards making the cost of power from the hydro station equa 1
to that of thermal alternative, until such time as the increase in fuel
costs on the thermal alternative brought its costs up to that of hydro
and thus made further Equalization Grants unnecessary. To ensure that
such grants were not swept up by the HB 9 legislation and the benefits
shared among all projects irrespective of need, it will be necessary to
legislate that the Equalization Grants were not to be taken into account
in the application of HB 9.
Specifically, the legislation might take the following form. It would
apply to areas where the cost of power from the hydro source was higher
than the existing thermal power option. The program would then under-
take for, say, a five to six year period, a special "Equalization
Grant". This grant would meet the whole of the estimated· difference
between the cost of the hydro power and the cost of the thermal power as
estimated each year based upon the price of diesel oil.
In the case of Tyee Lake, where the early year cost problem has been
seen to be most material under HB 9, the cost of this (on the assumption
of diesel oil prices increasing at the rate of inflation from 1984)
would be approximately $1.8 million in then current dollars (approxi-
mately $1.4 million in 1983 dollars). The year-by-year costs of the
Equalization Grant are shown in Table 5 in then current dollars. On the
inflation assumptions assumed, the Tyee Lake power rate would be
competitive with that of thermal at the end of four years so that the
Equalization Grant could be terminated. Thereafter, as already noted,
the cost of the hydro power would be falling progressively in terms of
constant dollars as inflation progresses.
TABLE 5
COST OF EQUALIZATION GRANTS ($ millions)
Swan Tyee Solomon Terror Total
1985 0 0 0 N/A 0
1986 0 0.8 0 0 0.8
1987 0 0.6 0 0 0.6
1988 0 0.3 0 0 0.3
1989 0 0.1 0 0 0.1
1990 0 0 0 0 0
1991 0 0 0 0 0
TOTAL 0.0 1.8 0 0 1.8
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Similar Equalization Grants might need to be extended to other projects.
The total cost in the latter case, however, is likely to be relatively
small given that with this solution to the systerrt increment cost pro-
blem, their cost of power would become competitive with thermal within a
very ·short period.
The Equalization Grant provisions could be written into the power
contracts of the utilities with the Power Authority, thus giving the
assurance of their continuation over the appropriate period.
4.2.5-Equalization Loans
An alternative to the Equalization Grants would be Equalization Loans.
These would be simply the grants made repayable at a date when the hydro
power was competitive with the thermal alternative. Under this proposal
the grants would be carried .as an unsecured loan for a given period -
for example, eight years from the commencement of the grant. By this
date, the hydro power should be strongly competitive with the therma 1
option. In consequence, by this time it should be possible for the
utility to accept an increase in the power rate, which would be suffi-
cient to support long-term commercial borrowing with the proceeds of the
borrowing going to repay the outstanding 1 oan accounted for by the
Equalization Grant.
This proposal would involve some technical problems in the debt fi-
nancing. It would, for example, be necessary to secure the prior
consent of the existing bond holders for this additional subsequent
borrowing, and the terms on which the borrowing would take place would
need to be precisely and legally specified if the existing bond holder
interests were to be protected. These problems, however, would have to
be overcome without undue difficulty if this particular proposal won the
consent and cooperation of the utilities concerned.
There might remain the problem for the uti 1 ities that they would be
subject to uncertainty as to whether or not the Equalization Grant would
apply to later increments to the system or whether, after their own
Equalization Grants had run out, they were to be subject to the effect
of the System Increment problem as other projects with relatively high
debt service were added to the system and were not in receipt of
Equalization Grants. This potential exposure, however, might be
acceptable to the utilities given they had the shelter provided by the
Equalization Grants over the first five years and the then highly
competitive economics of their own sources of hydro.
Turning to the economics of the Equalization Grant system from the stand
point of the State of Alaska, it is seen from Table 5 to involve only
$1.8 million in total ($1.4 million in 1983 dollars). Against this must
be set the major long term economic advantages of reduced future costs
from the hydro program.
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4.2.6 -Standardized State Financing Until System Maturity
It has been seen that the System Increment addition problem essentially
arises where the increment to the system has higher debt service costs
than the then existing units in the system. This particularly arises
with Terror Lake where it is 58 percent financed by debt compared with
26 percent for the system as a whole. A means of substantially
eliminating the System Increment problem would therefore be to ensure
that for an interim period at least {for, say seven years) additions to
the system were financed with the same proportion of debt as the
existing system -that is only 26 percent with the balance being funded
from state equity.
This would be needed for only an interim period until the system was
established and like other "mature" power systems, begin to reap the
benefits of decreasing cost of power in constant dollars from the
substantial amount of capacity acquired in the past. This measure would
realistically address the fundamental problem which all newly estab-
1 i shed power systems pose, namely that they have no backlog of cheap
capacity acquired at the lower prices prevailing in earlier years. In
consequence they have an inherent problem introducing into the system
new units of capacity, the current costs which, in an inflationary
world, inevitably involve higher costs than units purchased at the
substantially lower prices prevailing in earlier years. If this problem
is not addressed and resolved it would result in the system being
permanently locked into whatever types of capacity have the lowest early
year costs irrespective of the long term economics.
The Standardized Financing Option would be a solution which, within
existing legislation, would create a "mature" system such that the power
rates resulting from this option would all rapidly become competitive
with the existing thermal option so that within a few years other units
could be introduced into the system without causing excessively large
increases in power rates.
The evident major problem with this option is that it would involve
additional equity of approximately $60 million to be appropriated in FY
1984 and 1985 and as such may be deemed unacceptable.
5 -MARKETING AND DEVELOPMENT SOLUTIONS
The preceding sections have addressed the immediate problems in a
legislative context since these need detailed and lengthy consideration
prior to legislation. The Power Authority is, however, actively pur-
suing the marketing and development activities which will help improve
the economic comoetitiveness of the projects under construction or
authorization. This includes:
(1) Transmission interconnections to serve adjacent communities or
interties;
(2) Securing home heating markets and
(3) New industrial and commercial loads.
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Very substantial potential increases in sales of power (and consequent
reduction in unit costs) are possible given that the three projects have
substantial underutilized in the early years and, in the case of Swan
Lake, only about 40 percent.
The uniform rate imposed by HB 9 for all power from a given project is a
serious obstacle to the greater utilization of capacity by securing home
heating and industrial and commercial loads. These loads can only be
secured on the basis of a price of power·significantly lower than the·
single wholesale rates of Table 1.
On these grounds, it is recommended that HB 9 be modified to permit
multiple tariffs whenever this is shown as likely to improve utilization
and reduce unit costs overall.
6 -SUMMARY AND CONCLUSIONS
1. The report reviews the key elements in the Power Authority's
hydroelectric program in the light of the issues posed by the
recent weakening of alternative energy prices, the present stage of
development of the projects, and the impact of the HB 9
legislation.
2. The HB 9 legislation is designed to share the debt service cost of
all projects on the system between all projects, irrespective of
the actual level of debt service which they have incurred indi-
vidually. The allocation of the system debt service between
individual projects is in proportion to the percentage which the
state investment for each project represent of the tota 1 state
investment for all projects. If, for example, the inve~tment in a
particular project represented 20 percent of all such investment it
would have to carry 20 percent of all the debt service on the
system. This means that the power rates of individual projects are
not fixed but wi 11 increase if new projects with heavy debt fi-
nancing are added to the system. This is referred to below as the
System Increment problem.
3. This legislation and the weakening in diesel oil prices has created.
three separate but inter-related problems. These are:
The Eqrly Year Power Cost Problem -the problem that a weak-
ening in the cost of diesel oil can make a new and substan-
tially· debt financed hydro project uncompetitive with the
thermal alternative it displaces in the early years.
The Sfstem Increment Problem-the phenomenon of additional,
large y debt financed project increasing the power rates on
all the existing projects.
The Uniform Rate Problem -the problem that HB 9 calls for
each project to have single uniform wholesale power rate.
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4. These three problems represent significant difficulties in the
marketing of hydro-electric power and the realization of the long
term economic benefits of this renewable power source. Utilities
may be reluctant to take the hydro-electric power where it involves
higher early year power costs and may also be reluctant to enter
into long term contracts given that the System Increment problem
presents them with an indeterminate future cost of power. The
Uniform Rate problem also makes it difficult to resolve the prob-
lems by securing greater sale since it precludes offering lower
tariffs to secure "low cost 11 loads such as those offered by indus-
trial demand and the home heating market.
5. These problems are illustrated by an analysis of the Terror Lake,
Swan Lake, Tyee Lake and Solomon Gulch project.
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Prior to the tntroduction into the system of Terror Lake,
Swan Lake, Tyee Lake, and Solomon Gulch are all com-
petitive with the cost of the thermal power which they
displaced.
Adding Terror Lake (with its 58 percent debt financing)
to the system in 1985 highlights the increments to system
problem. Through the HB 9 mechanism this increment to a
system has the effect of increasing the power rates of
all the projects on the system and in particular making
Tyee Lake 2.4 cents more costly than the cost of thermal
power.
6. While these problems· are inherent in the HB 9 legislation their
numerical magnitude results from the small size and recent estab-
1 i shment of the system. This means that any new project can be
relatively large compared with the rest of the system, and because
the system is relatively new it does not have a large base of old
assets acquired at the much ·lower prices obtained years earlier
into which to easily assimilate any new high cost source of power.
7. A wide range of possible solutions to these problems were con-
sidered in Section 4 including greater state equity contributions,
lower interest rate loans, etc. The problem, however, is to find a
solution to these problems that is economical in terms of the
magnitude of the state contribution required. ThP HB 9 legislation
makes the additional state equity solution very costly since this
leaislation would share the benefits of such contributions between
ali projects in the system thus reducing all power rates irrespec-
tive of the extent of which they were already competitive with
therma 1.
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8. In the light of this· analysis it is concluded that the most econom-
ical and effective means of resolving the problems indicated in
paragraph 4.2.4 would be that of "Equalization Grants 11 • These
would be special state grants designed to reduce the cost of the
hydro power in the early years into equality with the cost of the
thermal power which it displaces. On present forecasts, grants
would only be required for Tyee Lake for a period of four years.
The total cost (in 1983 dollars) would be $1.4 million compared
with approximately $37 million· in the case of the additional state
equity.
9. It is expected that the Equalization Grants might be necessary for
a number of projects unti 1 the system achieves the 11 maturi ty 11 and
competitiveness inherent in the 1 ow esc a 1 at ion rate of hydro and
thus becomes able to absorb new high cost additions to the system
without unacceptably high increases in power rates.
10. Turning to the Uniform Rate problem, it is concluded that this is a
material obstacle to greater utilization of the hydro projects and
prevents the system obtaining lower unit costs by supplying the
industrial and heating markets. It is recommended, therefore, that
consideration be given to changing the legislation to permit the
Power Authority to establish multi-rate tariffs wherever this
appears likely to secure larger markets and hence lower unit costs.
Given such legislation the Power Authority would expect to be able
to significantly improve the competitiveness of the hydro power
projects.
11. In summary, the HB 9 legislation as it now stands poses significant
problems for the hydro-.e l ectri c deve 1 opment program at its current
relatively immature stage of development and in the context of the
weakening in thermal fuel prices. Legislation along the lines
indicated in paragraph eight and paragraph ten of this section
wou 1 d, however, reso 1 ve these prob 1 ems and enab 1 e the program to
realize its ultimate objective of long term low cost power for most
Alaskans .
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APPENDIX A
A.1 I. SWAN LAKE HYDROELECTRIC PROJECT HISTORY AND DESCRIPTION
The City of Ketchikan, having made the decision to discontinue its
reliance on the use of diesel electric generation to meet rising energy
demands, authorized the engineering firm of R. W. Beck in September of 1977
to investigate the feasibility of developing, as a major hydroelectric
generating resource, the Swan Lake Project which is located approximately 22
miles northeast of Ketchikan near the northern end of Carroll Inlet in the
central portion of Revillagigedo Island.
In June of 1978, R. W. Beck issued a feasibility report indicating that
a hydroelectric project which would demonstrate a benefit/cost ratio of 1.25
could be conitructed at Swan Lake at a total investment cost of $80,924,000.
Subsequently, the City of Ketchikan, Ketchikan Public Utilities {KPU) au-·
thorized R. W. Beck to proceed with preparation of final design of the
project.
The 1980 Legislature through joint resolution authorized the Alaska
Power Authority to issue bonds up to the maximum amount of $120,000,000 for
financing the construction of the Swan Lake Project.
Construction was initiated by KPU in November of 1980. Funding for
project design and initial construction was secured primarily through the
proceeds of loans from the Power Authority's Power Project Revolving Loan
Fund. ·
On May 28, 1981, the Power Authority 1 oaned KPU $35 ,000,000 for con-
struction from funds which had been raised through the sale of General
Obligation Bonds.
On May 21, 1982, the Power Authority and KPU executed an acquisition
agreement under which, in return for providing funds to complete project
construction, the Power Authority will receive title to the project and as
operation of the project will provide sufficient power for the City of
Ketchikan•s needs via a Power Sales Agreement.
The Swan Lake Project consists of a dam, a power tunnel and a powerhouse
situated at tidewater on Carroll Inlet, plus approximately 30 miles of
transmission line from the site to Ketchikan.
The dam, which is essentially completed, is a double curvature concrete
arch structure 1 ocated about 0. 75 mi 1 e downstream from the outlet of the
existing Swan Lake. The dam has a maximum height of 174 feet above the base
of the foundation excavation. The dam crest of e 1 evati on 344 above mean
lower law water (MLLW) is 428.5 feet long. The dam has a crest thickness of
6 feet and has a base thickness of 16.5 feet.
A 100-foot wide ungated agee service spillway section with the crest at
elevation 330 is located in the central portion of the dam. Spillway
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discharges will be flipped downstream from the toe of the dam to a plunge
pool excavated in rock in the existing stream channel. The spillway is
designed to pass a Probable Maximum Flood which is.estimated to have a peak
inflow of 37,150 cfs and a volume of 38,700 acre-feet.
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A.2 I. TYEE LAKE HYDROELECTRIC PROJECT HISTORY AND DESCRIPTION
On December 19, 1979, the Alaska Power Authority submitted an
application to the Federal Energy REgulatory Commission (FERC) for the
construction of the Tyee Hydroelectric Project in the vicinity of Wrangell
and Petersburg, Alaska. Our engineers, R. W. Retherford Associ-
ates/International Engineering Company (IECO), estimated the cost of the
project at that time at $53,333,000.00, including an allowance for inflation
at the rate of seven percent per year during the construction period.
Procurement of long-lead-time turbines began in July 1981, in anticipa-
tion of a FERC license. FERC issued a license August 5, 1981, and the award
of severa 1 addi ti ana 1 procurement and one construction contract fa 11 owed
almost immediately thereafter.
The power-on-1 i ne date is schedu 1 ed for January 1984. The current
estimate of the total project cost is $124,000,000.00. Available funds
include $82,000,000.00 in State grants and $50,000,000.00 in interim financ-
ing.
The powerhouse is located in the Tongass National Forest, approximately
40 miles eastsoutheast of Wrangell, Alaska. The project is designed to
develop the energy potential of Tyee Lake--a natural lake at Elevat"ion
1396---convert it to electricity, and transmit the energy to the communities
of Wrangell and Petersburg for distribution. The project includes the
following principal features:
1. A tunnel system between Tyee Lake and a powerhouse, which is
located at sea level on the south side of the Bradfield River
valley. The tunnels consist of approximately 4,770 feet of
10-foot diameter tunnel, 1,880 feet of 13-foot diameter
tunnel, and 1,380 feet of 10-foot diameter vertical shaft, all
nominally unlined. The tunnel will contain a rock-trap,
tunnel plug, access gate, steel penstock, and manifold. The
tunnels wi 11 be connected to Tyee Lake by the 11 Lake-Tap 11
method at a water depth of approximately 140 feet. A dam is
not required.
2. A gate-shaft near the upstream end of the tunnel, consisting
of approximately 420 feet of vertical, 12-foot diameter shaft,
containing an intake gate, stoplog, and fine trashrack .
3. A powerhouse containing two, 10-MW hydro-generating units with
provision for a future third unit. There will be an adjacent
outdoor switchyard.
4.
5.
A 1200-foot lana tailrace for discharging water from the
powerhouse to an existing slough.
A 138-kv transmission system, 81-miles long. Approximately 60
miles will be overhead line and 12 miles will be underwater in
four separate crossing.
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A.3 I. SOLOMON GULCH HYDROELECTRIC PROJECT HISTORY AND DESCRIPTION
The Solomon Gulch Project, located outside of Valdez, is a 12 MW hydro-
electric project owned by the State of Alaska. Associated with the Project
and also owned by the State are approximately 100 miles of 138 KV trans-
mission line connecting the Project with Valdez and Glennallen, and three
substations. The Project has been operation a 1 for a year and during that
time has been operated for the State by the Copper Va 11 ey Electric Associ-
ation (CVEA}. Under agreements between the Authority and CVEA, it is
expected that CVEA will continue to operate the Project for the State and, as
has been the case for the past year, CVEA will continue to be the sole
purchaser of the output of the Project. The average annua 1 generation from
the Project is expected to be 55,000 MWH, although at the present time, CVEA
can use only approximately 40,000 MWH per year. CVEA is presently paying
three cents per KWH for the project output.
On June 21, 1978, the Federal Energy Regulatory Commission (FERC}
granted CVEA a license to construct, own, and operate the Solomon Gulch
Hydroe-lectric Project. The project· site faces the City of Valdez from the
opposite shore of Port Valdez and is located approximately 3 miles east of
the Trans-Alaska Pipeline Terminal.
The site was originally licensed in 1932 for a 480 HP project construc-
tion in 1907. This project was operational until 1945 when the license was
surrendered to the Federal Power Commission (FPC}, forerunner to the FERC}.
In 1952, the FPC issued a 1 i cense for a 225 HP project which was to be a
partial restoration of the original project. This project was never con-
structed, and at the time of the application in 1975 by CVEA for a license to
construct the project as it presently exists, all that remained of the
original project was the 100-surface-acre reservoir (Solomon Lake}, scattered
remnants of the penstock and powerhouse machinery, and a deteriorating
operator 1 s cabin.
CVEA proposed to replace the existing dam at Solomon Lake, raising the
normal elevation of the lake from 610 feet to 685 feet. Surface area of the
reservoir waul d be increased from 100 to 660 acres, and storage capacity
would be increased from 1,700 acre-feet to 31,500 acre-feet. The power plant
was proposed to produce 12,000 kilowatts of capacity with an annual average
energy output of approximately 55,596,000 kilowatthours.
CVEA, an REA borrower serving Glennallen, Valdez, and an irregularly
shaped service area in between the communities, has realized substantial
growth in recent years, mostly due to the increased population and industria1
activity generated by construction of the pipeline. The Solomon Gulch
Project was determined to be the most economical means of supplying the
additional generating capacity needed by CVEA and of providing an intercon-
nection between the Glennallen and Valdez distribution systems. Using REA
and CFC loans for funding, CVEA began construction of the project.
In 1981, prior to completion of the project the State of Alaska,
directed the Alaska Power Authority, to approach CVEA about the idea of
purchase of the project from CVEA. It. was felt that by us~ng funds
appropriated by the State for the cap1tal costs of the proJect, the
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costs of the utility, and hence its customers, would ·be less. The State and
CVEA signed an Acquisition Agreement in 1981 whereby the State assumed the
project and all costs and debt associated with the project. Agreements were
also signed specifying the conditions under which the project would be
operated by CVEA for the State and under which the entire output of the
project would be sold to CVEA.
Construction of the project and the transmission line was completed in
January, 1982, and commercial operation of the project began on March 31,
1982. The FERC license for the project was transferred to the Power
Authority on May 28, 1982, and the Power Authority assumed full ownership of
the project in July, 1982. Since that time, the project has been operated by
CVEA for the Power Authority with sa 1 e being made to CVEA of the usab 1 e
output of the project.
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A.4 I. TERROR LAKE HYDROELECTRIC PROJECT HISTORY AND DESCRIPTION
The Terror Lake Hydroelectric Project was initiated by the Kodiak Elec-
tric Association (KEA) in the mid-1960's to provide lower cost electrical
power to its customers. Tippetts, Abbett, McCarthy and Stratton and
Robert W. Retherford and Associates were retained to prepare a feasibility
study which indicated the the project was not economically feasible at that
time. The rapid rise in the cost of diesel fuel in the mid-seventies
~resulted in KEA retaining Robert W. Retherford and Associates and Inter-
national Engineering Company to upgrade the previous feasibility study, apply
for a Federal Energy Regulatory License and to accomplish the project design.
The application for a license was submitted to the Federal Energy Regulatory
Commission (FERC) in December 1978, and their initial review indicated that
more environmental data was required. The additional data was acquired
during 1979 and was submitted to FERC in February, 1980. The Department of
the Interior, the Alaska Department of Fish and Game, the Legal Defense Fund
of the Sierra Club, the Audubon Society and the Northwest Wildlife Federation
were granted interventions by FERC. By letter of July 28, 1981, KEA trans-
mitted an Agreement between KEA and the interveners in which the interveners
agreed to withdraw their objections in return for certain additional stipu-
lations. The FERC License was issued to KEA on October 5, 1981, and
transferred to the Alaska Power Authority on May 12, 1982.
The Terror Lake Hydroelectric Project is located on Kodiak Island as
shown in and is about twenty-five miles southwest of the City of Kodiak.
The principal components of the project consist of the following:
The natura 1 storage of Terror Lake wi 11 be increased by 108,000
acre-feet by building a dam across the lake's natural outlet. This
dam will raise the water surface level from the present elevation
of 1,250 feet to a maximum elevation of 1,420 feet.
The dam wi 11 be a compacted rockfi 11 structure with an upstream
concrete face. It wi 11 have a maximum structura 1 height of 193
feet and an effective crest elevation of 1,420 feet. A sidechannel
spillway will be excavated in the rock of the right abutment. It
will be ungated and unlined, and it will have an inlet crest 625
feet long. A reinforced-concrete outlet conduit will pass through
the base of the dam, and will be used to make controlled releases
down the Terror River for maintenance of the fish spawning beds.
A power tunnel will leave Terror Lake from an intake structure on
the eastern shore and head northeast for 26,300 feet to an outlet
portal on the slopes of the Kizhuyak Valley. It will have an
11-foot-diameter section, and will be unlined, with only nominal
lengths of concrete lining and other supports as required.
Runoff from the 15.1 square miles of the natural catchment area of
Terror Lake will be supplemented by diversion from 8.6 square
miles of adjacent catchment areas. These areas are Shotgun Creek,
Falls Creek, Rolling Rock Creek, and Mount Glotoff Glacier. The
diversions will be accomplished by small diversion dams, open
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channe.ls, and intake tunnels and shafts connecting into the main
power tunne 1 • One of these shafts (of Ro 11 i ng Rock Creek) wi 11
also function as a surge shaft. Provisions have been made in the
design for the future diverston of the runoff-from 4.0 square miles
of the Upper Hidden Basin Creek catchment area and the 5.1 square
miles of the Upper Uganik catchment area.
A single, inclined, steel, penstock, 3,100 feet long, will extend
from the tunnel outlet portal, down the side of the Kizhuyak
Valley, to an above ground powerhouse located on the
valley floor. The powerhouse will contain two vertical-axis,
18,336hp Pelton-type, 6 nozzle impulse turbines, each
connected to a 10-MW electrical generator. Thus, the total
initial installed capacity will be 20 MW. The turbines, which
will be set at Elevation 103.5, will operate at an average net
head of 1,207 feet. Provisions will be made for a future
third generating unit in the powerhouse, and the power tunnel
and penstock have been designed to accommodate the additional
flow, without modification.
Transmission of the electric power to Kodiak will be via a
single circuit, 138-KV, 19 mile long transmission line, using
a combination of steel and wooden pole structures and AACSR
conductor .
J: APPENDIX 11 811
ASSUMPTIONS FOR FINANCIAL FORECASTS
0 Project Costs and Financing
State
Total Cost Appropriations Debt Financed On-Line
Projects Included (Millions$) (Millions $) (Millions $) Date FY
Swan Lake 93.50 69.09 24.41 1985
Tyee Lake 124.60 79.48 45.12 1985
Solomon Gulch 53.00 53.00 0.00 1983
Terror Lake 189.40 79.26 110.14 1986
410.50 280.83 179.67
Notes
1. Costs are the total projected costs including escalations.
2. Debt is assumed to be 35-year bonds with a 10 percent interest rate.
3. Bond coverage was assumed to be 1.10 (i.e. 10 percent in excess of
debt service costs).
4. Debt amounts exclude any Reserve Funds.
,.,.
8-1 INFLATION AND INTEREST RATES
Ca1ender Genera1 Inflation Interest Rate for Bonds
Year ~Percent) 1. (Percent
1983 6.8 10.0
1984 6.5 10.0
I"
1985 7.4 10.0
I 0'~~ 1986 7.4 10.0
1987 6.9 10.0
1988 7.0 10.0
1989 7:1 10.0
1990 7.1 10.0
t _, .. _ 1991 6.8 10.0
1992 6.6 10.0
1993 6.5 10.0
1994 6.4 10.0
1995 6.4 10.0
1996 6.4 10.0
1997 6.4 10.0
1998 6.4 10.0
1999 6.4 10.0
2000 6.4 10.0
2001 6.4 10.0
NOTES
1. Source: Data Resources Incorporated, Ju1y 1982.
2. All costs shown in forecasts represent a January 1 or mid-fisca1 year basE
..
;·.":
' .
B-2 °0PERATION AND MAINTENANCE COSTS
Annual
0/~1 Costs
Project (Millions $) Year
Swan Lake 1.028 1985
Lake Tyee 1.32 1985
Solomon Gulch 1.27 1985
Terror Lake 1.08 1986
NOTES
1. Source: Alaska Power Authority
2. No real escalation in 0/M costs was assumed, inflationary increases only
DRI Indices.
B-3 °AGGREGATE PROJECT FIRM SALES:
FISCAL (KWH in thousands)
YEAR SWAN LAKE TYEE LAKE SOLOMON GULCH TERROR LAKE
f ~.-~'--~
1985 32,000 33,620 41,000 -0-
1986 33,600 34,460 41.,000 88,200
1987 35,280 35,320 41,000 91,954
1988 37 ,044 36,210 41,000 95,867
1989 38,896 37,110 41,000 99,947
1990 40,841 38,040 41,000 104,200
1991 42,883 38,990 41,000 106,294
1992 45,027 39,960 41,000 108,430
1993 47,279 40,960 41,000 110,609
1994 49,643 41,990 41,000 112,832
1995 52,125 43,040 41,000 115 '100
2000 66,526 48,690 41,000 125,800
l' ,,, 2001 69,850 49,910 41,000 128,060
Source: Alaska Power Authority
. -
APPENDIX 11 C11
C.1 DESCRIPTION OF FINANCIAL MODEL
(refer to Table C.1)
L Year:
2. Energy GWH:
Fiscal years ending June 30.
Total firm sales for all projects included in
forecast.
3. Real Price &/KWH: Price ¢/KWH : inflation index.
4. Inflation Index: Mid-year FY 1983 (January 1, 1983) = 100.
5. Price ¢/KWH: Wholesale Power Rate calculated under HB9.
When more than one project is included in the
forecast the rate shown is the average cost
of power (Revenue~ Energy) for all projects.
6. Revenue: Sum of the revenues for all projects included
in the forecast. Revenues are based on
project sales and the power rate calculated
under HB 9 Legislation.
7. Less Oper. Costs: Sum of operating costs for all projects
included. The calculation for each project
is:
8.
9.
10.
11.
12.
Operating Income:
Add Interest Earned
an Funds:
Less Interest an
Long-Term Debt:
Less Interest an
Lang-Term Debt:
Net Earnings from
Operations:
Operating Costs = (Generation KWH) X variable
0/M costs ($/KWH)).
p 1 us (fixed O/t4 costs ( $/ K~J) X KW) .
plus administration costs.
plus insurance casts.
6 -7
Interest Rate X Reserve and Contingency Fund
(previous year balanc~) (see 25 below)
Interest Rate X Outstanding Short-Term Debt
(previous year balance) (see 16 below)
Annual interest casts for long-term debt (bands
and state loans)
(8 + 9) -(10 + 11)
.. . ~·
13. Cash Income from
Operations: 12
14. State Grants:
15. Long-Term Debt
Drawdowns:
16. Workcap Debt
Drawdowns:
17. Total Sources of
Fund:
18. Less Capital
Expenditures:
19. Less Workcap and
Funds:
20. Less Debt
Repayment:
21. Less Payment to
State:
22. Cash Surplus
(Deficit):
23. Recovery from
HB9:
24. Cash Recovered:
Annual state grants
Long-term debt drawn (including state loans and
capitalized interest)
Short-term debt drawn for working capital (see
25 and 26 below)
13 + 14 + 15 + 16
Annual capital €xpenditures, including
capitalization interest and annual provision
for renewals and replacements (0.3 percent of
project construction cost per annum, no real
escalation)
Increase in, working capital and reserve and
contingency fund (See 25 and 26 below)
Allowance for special payments to the state
(not currently used)
Allowance for special payments to the state
(not c~rrently used)
Surplus or shortfall of funds. For projects
which receive more revenue under HB9 than is
required to meet obligations (including debt
service) the surplus is paid to the general
state fund. For projects which do not receive
sufficient revenues under HB9 to meet obliga-
tions, the deficit is met by a transfer from
the general fund. This deficit will only occur
for single projects. On a combined basis, a
deficit can never occur under HB9 Legislation.
Transfer of funds under HB9 to projects which
show a deficit (see 22)
Cash retained by the project. This will always
be zero as all excess funds are sent to the
general state fund •
25. Reserve and
Contingency Fund:
26. Other Working
Capita 1 :
27. Cumulative Capital
Reserve fund is equal each year to 100 percent
of provisions for renewals and replacements
plus 100 percent of operating costs.
Annual working capital is equal each year to
15 percent of operating costs plus 10 percent
of revenues.
Expenditure: Cumulative 18.
28. Capital Employed: 25 + 26 + 27.
29. State Contribution: Cumulative 14.
30. Recovery from HB9: ·Cumulative 23.
31. Retained Earnings
from Operations:
32. Debt Outstanding
Short-term:
33. Debt Outstanding
Long-term:
34. Debt Service
Cover:
35. Annual Borrowing
Cumulative (net earnings from operations -cash
surplus paid our).
Cumulative 16.
Outstanding long-term debt (bonds and State
loans) after principal repayments.
(12 + 11) . (11 + 20).
$ 1983: 15 . 4.
36. Cumulative Borrow-
ing $ 1983: Cumu1ative 35.
37. Annual State
Grants $ 1983:
38. Cumulative State
14 : 4
Grants $ 1983: Cumulative 37.
39. Total Annual
Financing $1983: 35 + 37.
40. Total Cumu1ative
Financing $ 1983: Cumulative 39.
Table C.1
Alaska Power Authority Financial Forecast for Fiscal Years ending June 30.
( $ MILLIONS)
1. YEAR 1982 1983 1984 1985 1986
2. ENERGY GWH
3. REAL PRICE
' 4. INFLATION INDEX
5. PRICE -¢/KWH
-----------------------------INCOME-------------------------------
6. REVENUE
7. LESS OPERATING COSTS
8. OPERATING INCOME
9. ADD INTEREST EARNED ON FUNDS
10. LESS INT. ON SHORT-TERM DEBT
11. LESS INT. ON LONG-TERM DEBT
12. NET EARNINGS FROM OPERATIONS
------------------------CASH SOURCE AND USE-----------------------
13. CASH INCOME FROM OPERATIONS
14. STATE GRANTS
15. LONG-TERM DEBT DRAWDOWNS
16. WORKCAP DEBT DRAWDOWNS
17. TOTAL SOURCES OF FUNDS
18. LESS CAPITAL EXPENDITURES
19. LESS WORKCAP AND FUND
20. LESS DEBT REPAYMENTS
21. LESS PAYMENT TO STATE
22. CASH SURPLUS (DEFICIT)
23. RECOVERY FROM HB 9
'. 24. CASH RECOVERED
----------------------------BALANCE SHEET--------------------------
25. RESERVE AND CONT. FUND
26. OTHER WORKING CAPITAL
27. CUM. CAPITAL EXPENDITURE
28. CAPITAL Ef~PLOY ED
29. STATE CONTRIBUTION
30. RECOVERY FROM HB 9
31. RETAINED EARNINGS FROM OPS. --
32. DEBT OUTSTANDING SHORT-TERM
33. DEBT OUTSTANDING LONG-TEru1
34. DEBT SERVICE COVERAGE
35. ANNUAL BORROWING $ 1983 --
36. CUM. BORROWING $ 1983
37. ANNUAL STATE GRANTS$ 1983
38. CUM. STATE GRANTS $ 1983
39. TOTAL ANNUAL FINANCING S 1983
40. TOTAL CUM. FINANCING $ 1983
;-
C.2 METHODOLOGY USED FOR CALCULATION OF
POWER RATES IN FINANCIAL MODEL
I. Operation and Maintenance Portion of Power Rates
"'-::~~ This rate is calculated independent of other projects.
)
t
Components of Rate
A. Operation and Maintenance Costs. (see C.1 -7).
B. Net short-term interest costs (interest on short-term debt -
interest earned on reserve funds). (See C.1 -9 and 10).
C. Annual provision for renewals and replacements. 2 {see C.1 -
18).
0/M portion 6f the Power Rate = (A + B + CY/Project Sales.
II. Debt Service Portion of Power Rate
Components Used in Rate Calculation
A. Total System Debt Service (see C.l -11 and 20).
B. Bond Coverage (ten percent).
C. Period (year-1983).
D. State 1 S Investment in each Project (equal to project cost for
this analysis).
E. Project Sales (see C.1 -2).
NOTES
1. A provision for working capital has been included in this
analysis as well as a general reserve and contingency fund.
Working capital is assumed to be met by short-term debt, with
an annual interest rate of ten percent. The reserve and con-
tingency fund earns interest at ten percent per annum, (on the
previous year's ending balance}.
2. The annual provision for renewals and replacements (0.3
percent of project construction costs (excluding IDC) per
annum} is assumed to be funded with bond coverage where
possible. If this coverage proves to be insufficient, then
revenues (and rates} are increased so that this shortfall is
just met.
' .
Methodology Used to Calculate Debt Service Portion of
Wholesale Power Rates
1. Calculate Average System Debt Service Rate (R1)
R1 = (Total System Debt Service + Coverage)/Total Sales for all
Projects.
Rl = (A+ B)/SUM(E).
2. Determine System Cap Rate (R2) {see Subsection 44.83.398(2)(h)).
R2 = System Debt Service Average x (1 + .04 (year-1983)).
R2 = Rl X (1 + .04 x C).
3. Calculate each project's·initial, proportionate share of total
debt services and Without Cap Rate (R3).
R3 = (Total System Debt System Service+ Coverage x (State's
Investment in the Project/State's Investment in all Power
Projects))/Project Sales.
R3 = ((A+ B) X (D/SUM(D))/E
4. Determine whether the Without Cap Rate for each Project exceeds
the Slstem Cap Rate and if it does, set that Project's Debt Service
Rate R4) equal to the System Cap Rate. .
1 If R3 greater than.R2 then R4 = R2
5. If any projects are capped then using these rates would result in
a shortfall of funds to meet debt service obligation. In order
to correct this, the debt service share (and thus power rates)
for projects whose debt service rates are still below the cap
rate, are adjusted upwards (to a maximum of the System Cap Rate).
This adjustment (RS) is again based on the State's Investment in
the project.
RS = (State's Investment in the Project/Total State Investment in
all projects whose rates are less than the System Cap Rate)
x Shortfall.
If a project's rate should exceed the System Cap Rate under this
reallocation of the shortfall, its rate is also capped and the
above procedure is repeated for the remaining projects whose
rates are still less than the System Cap Rate.
6. The final debt service portion of the power rate for each project .
is equal to Project's share of Total System Debt Service Costs
after application of limits/Project Sales.
R4 = (R2 or (R3 x RS))/E
' .
APPENDIX 11 011
EFFECT OF "BLACKMAIL" CLAUSE ON POWER RATES
Section 44.83 383 {b) {2) states that if the general state fund does not
stand at $5 billion by July 1, 1986, the power rate for each project wi11 be
set at the greater of
(a) the standard HB9 rate,
(b) a rate which will return 10 percent annually on the
amount invested in the project, including loans and
grants made by the state.
A comparison of power rates under standard HB9 calculations and those
under the "Blackmai1 11 clause starting in FY 1987 is presented in
Table F.1. These results are also summarized for 1987 and 1991 in
Table F.2. These calculations assume bond coverage of 1.10.
Results
The 11 8lackmail" clause, if invoked in 1987, would result in power rates
increasing by more than 75 percent for Swan Lake, Tyee Lake, and Terror.
Lake. The rate for Solomon Gulch would increase by approximately 30
percent. ~hese levels of rate increases would generate additional re-
venues in 1987 ranging from $1.2 million for Solomon Gulch to $9.0 million
for Terror Lake. Total additional revenues for 1987 would be
$21.2 million. These results are itemized in Table F2.
The difference between the standard HB9 rate and the "Blackmai1 11 clause
rate is seen to decline over time. Since the revenue generated under
the 11 8lackmail 11 clause is fixed (at 10 percent of project cost) the
11 8lackmail" clause rates will decline as sales continue to increase.
For the standard HB9 rates there is a decline in rates over time for
most projects but this is much less since operating costs are increasing
with inflation.
Table F .2 ·.
C,": SUMt1ARY COMPARISON OF STANDARD HB9 AND "BLACKMAIL 11 CLAUSE RATES
r·:_ Additional
Revenues
Standard "Blackmail" Clause Percent Generated
HB9 Rate Rate Difference ( $Mi 11 ions l
( ¢/ KvJH) (¢/KWH)
Swan Lake
; :.-. 1987 15.5 27.8 79 4.4
1991 14.1 22.9 62 3.8
Tyee Lake
1987 16.4 34.8 112 6.6
1991 15.8 25.6 62 4.8
Solomon Gulch
1987 10.0 12.9 29 1.2
1991 10.6 12.9 22 1.0
Terror Lake
1987 12.2 22.0 80 9.0
1991 10.1 19.1 89 9.5
table r.t
COST OF· F'llWER SUHHARY FOR AUTHORJ!:EI.l f·ROJECTS liSJNI.l SJANMIW Hflq eftS IS (UCLUI•IOO lilACI\HAll rt AU~E It
YEAR
\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\PROJECTS\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\
SWAN lAIIE lAkE TYEE SOlPHIJII GIIU:H I l Pf::!l~ lAt.£
cosJ c.o.tt c.o.r cosJ · c.o.t c.o.r ro!IJ t:.(l,f· c.o.r cus1 c,p.r c.o.r
lCl HI!:: C:I\I.F.'i CI'IPPF;D U/~ CAt tr.L If!£ SAI['J CAF't£.0 U/0 r.nf· ttl. JllC !II\I.F.!I CtoHP• WID f.Af· Cl IJIC C::'ll.f.'1 Cf,ffF'.ll 11!0 r,u·
fi'IILl tltiH f/1\UH /~IIH ttl Ill OIIH C/KIIH C/1\1111 ttl ll Ulltt f lt.\111 f /tiiH fltlll UWH C/1\WH f/HIII
\\\\\\\ \\\\\\\ \\\\\\\ \\\\\\ \\\\\\ \\\\\\~ \\\\\\~ \\\\\\ .\\\\\\ ,,,,,,, \\\\\\\ \\\\\\ ,,,,,,, \\\\\\\ ,,,,,,, \\\\\\
19113 83.0 o.o o.o o.o 87.9 o.o o.o o.o s:~.o •• ,(I J,!) 3 .{) IIJfl, I l' ,IJ Q,O o.o
U84 91!.2 o.o o.o o.o 125.3 o.o '1.0 1),1) 51·11 41.0 j,] J,] t9l.4 o.o o.o l),ll
198, 911.2 32·0 u.A 12·1 125.3 30.4 12·8 16.3 5J•O a•·o ?.q 6·9 20.:!.5 o.o o.o Q,Q
. 1986 91!.::? 33.6 15. 16.3 n~. J :n.t ,~."j ;'t.l :; .o t•O 1().0 9.1 202.!5 IJ!J,2 u.o II·~
1987 YB.2 35.3 15·5 15.8 125.] 36.0 16.4 19.7 53·0 41.0 1o.o ,,] 29:'.5 72.0 12·2 11·1 rea V9.2 17.0 l5o!S 15·1 Fs.:t ]9,;! u.z fllo4 n:o 41.0 IQ,(l '·~ 102.s t5.S' 11·4 11).7
9(19 ~·9.2 ]8.9 n:i U:l 2~·~ U:& It: A U:~ .. 8 11:8 10 .I '1.9 202.:5 ??.9 10.7 10.4
99(1 91'!.2 10.8 n. 11).1 10.2 202·S 104.2 10·2 10.2
1991 13.:> 42.9 14·1 14.1 125.3 48.9 15.9 15.(1 53.0 41.(1 IIJ.~ !!).~ 202.~ 106.3 10.1 11J .I
$ COSt 11r flliiER CAlCIA .. ATtiJH PASt::IJ ON TIIF. IKCI .. Il'iiON llF TH~ Fllli.OIIH!Il f·Rn Jt;r.T!JI
SIIAH lA~.E lAiiE TYEE SOLUtiON t::UlCH JFRF:nR I Af.f
CIJ"'T or F'fJWH; IHClUli[S 0/ft f'ORTION
COST OF F·DWE~: SUtltiAr:Y FOR AUJHORISEll F·P.(l.ICCJS Utll•Efi PlAf.kHAll ClAtt!'IU
'\ \\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\ \FI"O IF.CPl\ \\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\
YEAR !:WAH LAP.£ lAkE TYFF SOlOtlllll ctlt r:H IH:F·nF: I AH:
CflSI r;,o,r AIJll ftf;:IJ r.ost r.,Q,F' A[tt• P.F.V COSt r..ll.f· Al•l• ~I'.:V f.OSJ r.o.f· AN• 1\f\1
ttl lf•C SALES OEtt ICl l[lf SAl £S G£tl Cl U•C !lf:lE~ t:ftl I l:l II•C S•llE!I t:rtl
ttl ILl I'IIH [/1(1111 ttllll ttllll GIIH C/UIH ttllll ttllll OliN Ut.\11-1 fiHI.l ft!llL I:Uif C/t IIH fltlll
\\\\\\\ \\\\\\\ \\\\\\\ \\\\\\ \\\\\\\ \\\\\\\ \\\\\\\ \\\\\\ \\\\\\ \\\\\\\ ,, '""· \\\\\\ \\\\" \\\\\\\ \\\\\\\ \\\\\\
!\).0 IJ,o
sJ.o o.o
;i].Q 1),()
~.o
t co-::r flf F'OIIIC!"\ r.AI.CIJI.ATIIJH 'ASJ:O Ott THt: tNCI.U!HilH IJF TUE FlliJ.OIIltiiJ f·~n IF.f.T!=I
SIIAII lAIIE lAKE TYFF SIJLOHON GUlCH TERF:flf:: lAtE
CO'il nJ: f·•lll[fi r.AtCUtATF.D IJ!'JUIO lllACIIHIIR ttn•J";[ (,F.. THE r.F:F:I\IFJl Ofl
JHE SIANl•likl• l'NCAFUit Hll9 P.A1E OR 10 .. /A Of THE AllfH{IP.IH~ IHIJFSJtiFHT JH FACH f·Rfl!Erl
' ..
' '
'f..,~-
,. '-""·
.
(
•
1983 3 16
If) IOC,D/S=t.lO,t«l RfAI. OUt fmt., SWM : $95.~ Int .• P/C,8ft.O ~ ~iS (~'-?OOJJ, CM C05TS= $.30 11IL. H98S lnl.ARS) TVFF S'lt.F
S= FFB 83' AlUM'S.
SlJitARY IF SYS1f.lt llf.BT SERVICE RATF. Cttru..ATJ(N;
\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\
PRru CSTS IF.BT SYSTEJt SYSTEM
lf«l. JOC SERYI(E StL.fS MRATf rAPRATE
'tBIR SttiLLI«<6 SHILLI«<6 (V4 C/KIIt Cll<llf
\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\
1982 78.1·9 0.00 0.00 0.00 o.oo
1983 :r..r~.. 77 o.oo ~1.00 o.oo 0.00
1984 ~~.91 o.oo ~l.OO o.oo• 0.00
1985 462.~ 7.99 162.67. ~.91 ,.31
1986 462.50 20.~ 251.66 9.J7 9.15
1987 %2.~ 20.~ ~.2ft 8.0?. 9.30
1CJ88 ~.50 20.55 261.07 7.PJ 9.45
1989 462.~ 20.~ 2(16.06 1.n 9.58
J990 462.50 20.55 171.2~ 7.5ft 9.70
1991 462.50 20.~ 274.28 7.~9 9.99
.1992 462.50 20.s.-i m.39 7.~1 10.00
·tm· 462.50 20.s.-i 2a'.57 7.'¥1 IO.Zi
~~-· 462.50 20.~ 283.8'1. 7.24 10.~3.
.tm 462.~ 20.~ 287.14 7.16 10.59
·.1996 .... 462.:;(l .. 20.55 .290.28 7.08 J0.76 -•m· ... ~.,o·, 20.~ m.~ 7.00 10.92
1998 '-~.50 20.~ 296.~ 6.93 u.oa
·1999 ;,<; '462.:;cl 20.55 .300.09 6.~ 11.23
2000 462.50 20.~ 303.~ 6.77 11.38
2001 462.50 20.55 306.97 6.70 u#~
I.AKF TYff.
I •
1983 3· 16
Nl IOC,D/S=t.JO,tll REAl. ordt ESfJII., SWAN : w.i.5 "Il. P/C,98.0 taft SAI.FS (a5'-2001), OM COSTS= S.30 "IL. (1985 M.lARS) TYF'F SAI..F.
~ FEB 83' AtOINTS.
r .. ~ MF.R RATF BASF.D !If Tt£ lfl'tl.ISICW (F: SWAN LJ«E I. AICF TVF.F.
.i
~·.
r"~ PRO.ECT Poe RATE stJttARV FfR-: SWAN lAKE
L \\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\
I
l PRru COST PR0J W/0 CliP WITH Cf::f> 01" TOTAL
.-t ...
It«::. JOC lfJJT IRAW SAlES DIS RATE DIS RATE RATF RATE
~ .. IUJl*S ~IU.JCWS GYt CIK1fl C/KIIf C/taff C/taff
\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\
i. 1982 0.00 o.oo 0.00 0.00 o.oo 0.00 o.oo
tm . Et4.29 t3.n o.oo o.oo o.oo o.oo o.oo 1* ~~ ~n ~oo ~oo ~oo ~oo ~oo
19fe ~.!'-4 24.93 88.00 3.J7 4.58 0.41 4.99
1986 95.!10 24.93 ft8.00 4.~ 6.~ 0.42 7.24
~~ ~~ ~93 ~00 ~~ L~ ~~ L~
198ft ~.50 24.93 88.00 4.82 5. 90 0.«1 6.38
1989 ~-~ -24.93 88.00 4.8'1 ~.46 0.52-·-~-98
/t990 ~-~ 24.n 88.00 4.82 5.4? o.~ 6.00
1991 95.50 24.93 89.00 4.82 5.36 0.65 6.01
1m 95.~ 24.93 88.00 4.82 ~.3J o.n 6.03
1993 95~!10 24.93 -.oo 4.82 5.25 o.79 6.04
1994 ~-~ 24.n aEI.OO 4.~ 5.19 O.l17w 6.06
1995 ~.50 24.93 89.00 4.82 5.14 0~95 6.09
1996 95.!'-4 24.93 88.00 4.82 ~.08 1.04 6.11
1997 95.!'-4 24.93 aa.oo: 4.92 s.ot 1.13 6.t4
199a ~.50 24.93 88.00 4.82 4.~ 1.23 6.18
1999 95.!10 24.93 aa.oo 4.82 4.89 J .33 6."0
2000 95.50 24.93 sa.oo 4.82 4.92 t.44 6.XT •
2001 95.!10 24.93 fB.OO 4.82 4.81. 1.~ 6.39
..
.. ·
I·'
s
. 1983 3. 16
'"·-til IDC,DIS=I.tO,fll RF.Af. OU. ESr/t., ~: m.~ "IL. PIC.88.0 K1lf SAf..ft; (85'-?.00U, t:M COEn'9: f.30 "IL. U965 ll" •. I.AR$» TYF.E SAlF
S= FeB 83' NICNI"S.
f ,__ PRO.F.CT fl(v.R RATF St..WW RR : LAI<E ME
j \\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\
PM.I COST PfiU · ' W/0 f.AP WITH r./IP OJ" TOT((
trn. IDC !DT tNif . SMn DIS RAlF. PIS RAlF. RAlF RATE
't'£M ti1Il.l.I(IIS tffiU.IdeS tuf CIIQif r.m~t CIIGH CJK114
\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\
1982 25.19 o.oo 0.00 o.oo 0.00 o.oo 0.00
1983 . . f17.74 8.26 o.oo o.oo o.oo o.oo o.oo
t984 124.60 45.12 o.oo o.oo 0.00 o.oo o.oo .
1965 124.#.0 45.12 33.62 10.84 5.31 .3.9~ 9.ZI
t986 224.60 45.12 34.46 16.07 9.1~ 3.99 13.!3
1987 114.60 45.12 35.32 15.68 9,30 4.1~ 13.46
19tl8 . 124.60 45.12 36.21 15.29 9.45 . 4.31 13.1!1i
. 1989 124.60 45.1?. 37.11 14.91 . 9.,.. -4~53 !4.11
1990 114.60 45.12 '-"'38.04 ,.i 14.56·-e 9.70 4.80 14.50
1991 124.60 4~.12 :19.99 '.J !4.20 9.89 ~.10 14.99
1992 1?.4.60 45.12 341.96 13.85-. JO.OEt ~.40 1~48
1993 124.60 45.12-40.9~ 13.52 10.25 5.70 15.96
1994 114.60 45.12 41.99 -·13.19 10.4.1 ~.01 16.;43
1m 114.60 45.12. 43.04 · t2.f17 10,, 6.32 1o.n
1996 114.60 · 45.12 ·44.U 17,55 10.76 6.64 17.-40
,...,.
, ;;:-;£ •c-
1997 124.6o 4~12 4~.22 J2.25 ---10.9'l. . 6.97 17.90
'tm 124.60 45.12 ~.~ -u~" u.os . 7.31 28.341
.1m t24.60 45.!?. 47.50 11.66 u.23 1.u. 28.90
2000 114.60 45.12 48.69 · 11.37 H .37 8.03 19.-40
2001 124.60 45.12 49.91 11.09 U.09 ~.41 19.50
t"':
il.
1983 3 16
Nl IJC.D/Srrl.tO,r«) Rf.Al "'"EStf.l, SWAN: t95.!i "It.. P/C,a8.0 IGif SI!IES Ca5'-200th (Wdt COSTS= f.~ "ll. U9EI5 MJ.ARS) TYEE SAI.E
!P FEB '13' AtOMS.
PfnET POSt. RAlE SlfttARY Flit : SCI.CQ tUOf
\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\
PfW COST PR6J W/0 rJP WilH aP 01" TMM.
Jtlt. IOC JFBT IMI Sll.ES DIS RAlE DIS RATE RATF. RATf:
~ tltiU.ItiiS ttllllltt4S (VI C/1Qif C/tslf C/mf Cl~
\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\
. 1982 53.00 o.oo o.oo o.oo 0.00 o.oo 0.00
. '1983 53.00 0.00 41.00 o.oo o.oo 3.02 3.02
·.· -1984 53.00 o.oo 41.00 0.00 o.oo 3.25 3.Z'I
1~ 53.00 o.oo 41.00 3.78 S.:31 3.ot 8.40
1986 53.00 o.oo 4t.oo 5.74 a.J2 3.23 u.~
1987 53.00 o.oo 41.00 5. 74 7.~ 3.4S 11.04
Jm 53.oo o.oo 41.00 :5.74 7.tt& 3.66 1o.6'
1989 53.00 0.00 4J.OO 5.74 6.50 3.91 10.41
1990 53.00 0.00 41.00 5.74 . ~6.4.1\ 4.19 10.64
1991 53.00 0.00 41.00 ~.74 6.39 4.51 J0.90
1m 53.00 o.oo 41.00 . s.74 6.3.1 4.86 u.1s
1993 53.00 .· 0.00. 41.00 5.74 6.26 5.21 U.46
1994 53.00 o.oo 41.00 5.74 . 6.t9 5.58 . 11.77
1995 53.00 · 0.00 41.00 5.74 6.t1 5.99 J?.JO
1996 53.00 o.oo • 41.00 5. 74 6.05 . 6.40 ... 12.44
1997 53.00 0.00 41.00 5.74 5.97 6.84 11.8J
1998 53.00 0.00 41.00 5. 74 5. 90 7.32 13.21
1999 53.00 o.oo 41.00 5.74 5.82 7.82 13.64
2000 . 53.00 0.00 41.00 5.74 5.74 8.36 14.10
2001 53.00 o.oo 4t.oo 5. 74 s. 74 e: n 14.68
•
., . ;'
~~ 3 16
NO IOC,D/S=1.JO,t«l RF.AI. OM E'5r.AI .• SWAN: S9S.!i I'IJL P/r.,sa.o Kill AAI.F~ U~S' .. :'.OOJ), 001 COSlS= S.~ "Il. (1985JXltM!:U TYF.f. SAtE
*'1~·-S= FF.B 83' AflltcTS.
PflFR RATF BASfD IJf Tl£ Jtll.USliJf IF: SWAN lAKE
M.l:CT PfVR RATF. ~II'IARY F~ : TFRRffi lAKE
\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\
PROJ COST PftOJ 11/0 rw WITH C* 01" TOTA..
Iw:t. IOC IF.RT MAW f4.ES DIS RATE DIS RATF. RATf: RATE
YEAR tMJtLJ~ tttJI.Uat\ (VI r.IIGM C/kWH ClkWH C/Kifl
\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\
1982 o.oo 0.00 0.00 o.oo 0,00 0.00 0.00
J9ft3 107. 7~ 28.47 o.oo o.oo 0.00 o.oo o.oo
1984 1~.81 105.~ 0.00 0.00 0.00 o.oo 0.00
1~ 1~~ ~~~ ~00 LOO ~00 LOO LOO
J9& 1~.40 110.14 88.20 9.54 9.15 I.J1 J0.27
J9a7 1~.40 U0.14 91.95 9.15 9.30 1.16 10.56
19a8 1~.40 110.14 95.87 9.78 9.4~ !.78 10.73 I
1989 189.40 110.14 99.95 tt.42 9.53 1.35 10.88
1990 189.40 110.14 104.20 8.~ 9.07 1.4.1 10.50
1991 t89.40 uo.t4 101>.29 1.n ~.ao t.54 10.34
1992 1~.40 JtO.J4 108.43 7.76 8.54 !.65 10.20
1993 189.40 110.14 110.61 7.61 ~.29 1.77 10.~
1994 1~.40 110.14 112.83 7.46 a.~ J.~ 9.92
1995 1~.40 110.14 115.10 7.31 7.79 2.01 9.90
199b 189.40 110.14 117.16 7.18 7.56 2.14 9.70
t997 1~.40 IJ0.14 1J9.27 7.06 7.34 2.29 9.61
1998 189.40 110.14 121.40 6.~ 7.12 2.42 9.53
1m t~40 t~M tn~ ~m L~ ~~ ~%
2000 tlf9.40 110.14 125.80 6.69 6.69 2. 72 9.41
2001 J~.40 UO.J4 t?S.otf 6SI bST 2.00 9.45
Stlt1110N GtlCH Tf:RRfiR t Akf