HomeMy WebLinkAboutAPA1618t1.8.
INTRODUCTION TO ELECTRIC POWER SUPPLY PLANNING
WITH SPECIAL ATTENTION TO ALASKA1S RAILBEhT REGION
AND THE PROPOSED SUSITNA RIVER HYDROELECTRIC PROJECT
Prepared for the Alaska State Legislature
May 9,1980
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1425
.88
A23
no.1618
ARLON R.TUSSING AND ASSOCIATES,INC.
Anchorage,Juneau,and Seattle
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OF INTERIOR
JUl :1 B !!mlii
This report was prepared under contracts between the
Power Alternatives Study Committee of the Alaska House of
Representatives and ArIon R.Tussing and Associates,Inc.
It combines summary papers on three issue areas the commit-
tee asked the consultants to address:
1.The history of the Susitna hydroelectric
proposal:a description of the existing electric
utilities in Alaska l s Railbelt:and an explanation of
how the Susitna project would fit into the existing
system:
2.The major issues of electric power supply
planning,with a special emphas is on the issues the
legislature should examine if it is asked to authorize
and fund the Susitna project:and
3.A review of Acres American,Inc.I s plan for
its $30 million feasiblit·y study of the Susitna pro-
ject,and recommendations (if any)for improving the
stUdy plan.
Chapter 1,"Overview of the Electric Power Industry,"
\vas written by ArIon R.Tussing (Anchorage and Seattle).
Barbara F.Morse (Seattle)researched and wrote the appendi-
ces to chapter 1,"Existing Railbelt Utilities"and "Federal
and State Agencies Having Jurisdiction over New Electrical
Generating and Transmission Facilities in Alaska."Tussing
and Lois S.Kramer (Juneau)wrote Chapter 2,"Planning for
New Generating Capacity.II
Chapter 3,"History of the Susitna Hydroelectric
Project,"was written by Morse,and Chapter 4,reviewing
"The Acres Plan of StUdy"was written by Tussing and Kramer.
Comments on the review draft of this report,by Eric P.
Yould,executive director of the Alaska Power Authority,are
appended to Chapter 4.
Connie C.Barlow (Juneau and Santa Fe)reviewed the
enti re report and made many substant i ve and ed i tor ial
improvements:final editing was by Tussing,who accepts full
responsibility for any errors or omissions •
PREFACE
..
ARLIS
Alaska Resources
Library &Information Services
~chorage,AJaska
-"-_._,..._.._--_.-~-....~--_.._-~-~-_.
CONTENTS
ICHAPTER I:OVERVIEW OF THE ELECl'RIC PCMER INDUSTRY ••••••••••••••••••••••••
Electric utilities ••••••••••••••••••••••••••••••••••••••••••~•••••••••••
Generation,transmission,distribution •••••••••••••••••••••••••••••••
Railbelt utilities .••••••••••.••••.•••.•••••••••.•.••.•••.•••••••••••
Non-utility generation~cogeneration ••••••••••••••••••••••••••••••••••••
Interconnection and power pools ........•••..••..••••..••..••...•..••••..
Utility customers:residential,commercial and industrial ••••••••••••••
Methods of organizing and financing electric power supply •••••••••••••••
Pr'ivate utilities _..'.
ee:x:.J?erat i ves •••••••••••••••••••••••••••••••••••••••••••••••••••••••••
Municipal utilities .••...•...••..••••.••••.••....•••..••..•.•.•..•.••
Federal I;XJw~r••••••••••••••••••••••••••••••••••-e •••••••••••••••••••••
Regulation of the electric power industry •••••••••••••••••••••••••••••••
Ra.te regulation .....e-••••••••••••••••••••••••••••••••••••••••••••••••
Ra.te structures ..-,..
p!:"oIt'K)tional rates ••••••••••••-••••••••••••••••'.
Inverted rate structures -.
Regulatory au'thorities .
The Alaska Public Utilities Commission •••••••••••••••••••••••••••••••
The Federal Energy Regulatory Commission •••••••••••••••••••••••••••••
The Economic Regulatory Administration •••••••••••••••••••••••••••••••
Other licensing,permitting,and regulatory agencies •••••••••••••••••
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lWPENDIX A:EXISTJliJG RAILBELT UTILITIES •••••••••••••••••••••••••••••••••••18
lWPENOIX B:FEDERAL AGENCIES HAVING JURISDICI'ION
OVER NEW ELECl'RICAL GENERATING AND TRANSMISSION
FA.CILITIES IN AIASKA....................................................25
CHAPTER II:PLANNING FOR NEW GENERATJliJG CAPACITY..........................28
Prornc:>tion vs.oonservation 28
DeInand forecasting......................................................29
l?c>IJlll ation arld real lnoo.me •••••••••••••••••••••••••••••••••••••••••••
E-COllO-mic 1:x:x:>m in the 1980·s •.••••••••.••••.••.••.••••..•••••••.•••
Decline in the 1990's ••.••••.••••••••••••••.•••••••••.••••.•••••••
Electricity consumption per capita •••••••••••••••••••••••••••••••••••
Per capita in-come •••••••••••••••••••••••••••.••••.•••..•••.•••.•••
Electricity prices ••••.•••••.•••••••••••••..•••.••••••••••••••..••
Fuel substitution •••••••••••••••••••••.••••••••••••••.••••••••••••
Electricity consumption by new energy-intensive industry •••••••••••••
IX>es cheap PJWer attract industry •••••••••••••••••••••••••••••'••••
Interruptible sales contracts •••••••••••••••••••••••••••••••••••••
!.Dad characteristics •••••••••••••••••••••••••••••••••••••••••••••••••'•••
'Ba.se loads ••••••••••••••••••••••••••••••••••••••••••••••_•••••••••••••
Peak loads •••••••••••••••••••••••••••••••••••••••••••••••••••••••••••
Inte-rm.eCiiate loads •••••••••••••••••.••••.••••.••••••••••••••••••.••••
:Sy'"stem load factors ••••••••••••-•••-•••••••••••••••••••••••••••••••••••
.Alternatives to peakin.g -pJ'Wer ••••••••••••••••••••••••••••••••••••••••
Facilities planning •.••••••••.•••••••••••••••••••••••••••••••••••••..•.•
COst ooncepts ••••••••••••••••••••••••••••••••••••••••••••••••••••••••
Fixoo -costs •••••••••••••••••••••••••••••••••••••••••••••••••••••••
OJ?e'rating oo.sts •••••••••••••••••••••••••••••••••••••••••••••••••••
Heat rate •••••••••••••••••••~••••••••••••••••••••••••••••••••••••••••
Electrical generating technologies ••••••••••••••••••••••••••••••••••••••
Diesel Electric generating units •••••••••••••••••••••••••••••••••••••
Combustion (or gas)turbine generating units •••••••••••••••••••••••••
Federal restrictions on use of natural gas ••••••••••••••••••••••••
Natural gas liquids as turbine fuel?
Methanol as turbine fuel?
Steam turbine generating units •••.••••.••••••••••••••••••••••••••••••
Hydroelectric generating units •••••••••••••••••••••••••••••••••••••••
Cost hierarchy for electrical generation ••••••••••••••••••••••••••••••••
PlaIlt mix •••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••
Use of existing equipment ..••••.••••••.••••••••••••••••••.••.•••••••••••
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CONTENTS
Reserve generating capacity••••••••••_••••••••••.••••••••••••••••••••••••
I.oad m.anag ernen t...•. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .'.. . . . . . . . .
Construction financing •••••••••••••••••••••••••••••••••••••••••••••••
Conventional balance-sheet financing •••••••••••••••••••••••••••••••••
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Project financing •••••••••••••••••Alternative financing strategies:
Reserve requirements and load management ••••••••••••••••••••••••••••••••
Organization and financing ••••••••••••••••'••••••••••••••••••••••••••••••
Principles of finance ••••••••••••••••••••••••••••••••••••••••••••••••
Dealing with uncertainty••••••••••••••••••••••••••••••••••••••••••••••••
System reliability ••••••••••••••••••••••••••••••••••••••••••••••••••••••
Origins of the Susitna project•••••••••••••••••••••••••••••••••••~••••••
Creation of the Alaska Power Administration•••••••••••••••••••••••••••••
The Arrn¥Engineers'Rampart proposal ••••••••••••••••••••••••••••••••••••
The Acres stud.y •••••••••••••••••••••••••••••••••••••••••••••••••••••••••
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HISTORY OF THE SUSITNA PROPOSAL ••••••••••••••••••••••••••••••
Senator Gravel's funding ~posal•••••••••••••••••••••••••••••••••••••••
Current investigations ••••••••••••••••••••••••••••••••••••••••••••••••••
New federal interest in Susitna •••••••••••••••••••••••••••••••••••••••••
State initiatives:The Kaiser proposal and establishment
of the Alaska Power Authority •••••••••••••••••••••••••••••••••••
CHAPTER I II :
The legislature's study of alternatives to Susitna,
aIld this report •••••••••••••••••••••••••••••••••••••••••••••••••,•••••83
DeInand studies •••-•••••••••••••••••••••••••••••••••••••••••••••••••••••••
IntrOO.uction ••••••••••••••••••••••••••••••••••••••••••••••••'••••••••••••
ISER's dem.and see-narios •••••••••••••••••••••••••••••••••••••••••••••••••
Information for decision-making •••••••••••••••••••••••••••••••••••••••••
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'rfiE ACRES PI.AN'OF SnJDY •••••••••••••••••••••••••••••••••••••••
Forecasts of peak loads and load duration curves ••••••••••••••••••••••••
Peak-responsibility pricing and load management •••••••••••••••••••••••••
(£neral description •••••••••••••••••••••••••••••••••••••••••••••••••••••
CHAPTER IV:
iii.
CONI'ENTS
Selection of new generating facilities ....•................•••..•...••..
Financial feasibility •.•.•..•••...••.•••..•.....•.......•..........•...•
Marketabil ity ,~.
Study findings,incentives,and credibility.•..•......•••.••••.•••.....•
Rerornrnendations •••••••••••••••••••••••••••••••••••••••••••••••••••••••••
I::::k::cision date ••••••••••••••••••••••••••••••••••••••••••••••••••••••••
Divorcement of forecasting and analysis from
ronstruction design and manageInent •••••••••••••••••.•••••••••.••••••.
Soope an.d funding of l=JOW'er studies ••-•••••••••••••••••••••••••••••,_•••
Fallba-ck.strategy •••••••••••••••••••••••••••••••••.••••••••••••••••••
LErrER OF ~,AI.ASKA.~AIJ'lliORITY'••••••••••••••••••'••••••••••••••••
iv.
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CHAPTER I:OVERVIEW OF THE ELECTRIC POWER INDUSTRY
Electric utilities.
Generation,transmission,distribution.The electric
power bus iness has three main branches:generation,trans-
mission,and distribution.I1Electric utilities l1 are first
of all retail power distributors;as such they invariably
own and operate local low-voltage lines,transformers,and
switching facilities that deliver electricity to retail
customers in their respective service areas.
Most utilites also own generating plants (fossil-fuel,
hydro,nuclear,etc.),alone or jointly with other'uti li-
ties,but some purchase their power at wholesale from
other utilities,federal power projects,or other entities.
Some utilities are wholly self-sufficient,but most of them
buy some of the power they distribute,and/or sell some of
the power they generate to other utilities.
Utilities may own the high-vo~tage transmission
lines connecting the generating plants with their distri-
bution systems,or they may depend on other utilities or
governmental entities to I1 wheel l1 power for them.
Railbelt utilities.There are six electric utilities
and one federal power project in Alaska's Railbelt.Ancho-
rage-based Chugach Electric Association (CEA),the area's
largest,is a net seller of power at wholesale.Fairbanks-
centered Golden Valley Electric Association (GVEA),Ancho-
rage Municipal Light and Power (AML&P),and the Fairbanks
Municipal Utility System (FMUS)are nearly self-sufficient,
while Matanuska Electric Association (MEA),the Seward
Electric System (SES),and Homer Electric Association (HEA)
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are net buyers,mainly from CEA.The federal Alaska Power
Administration operates the Eklutna hydroelectric project,
and sells power to AML&P and MEA.[See the appendix to this
chapter,"Existing Railbelt Utilities.]
Non-utility generation;cogeneration.
Institutions an6 industrial plants often produce their
own electricity because they can generate it more cheaply
than they could buy-it from a utility,or because they need
to supplement or backstop utility-supplied power.In some
instances,utilities buy or exchange surplus electricity
generated by non-utility power producers.In Alask!3.'s
Railbelt,the chief non-utility power producers are military
installations,the Uni versi ty of Alaska at Fairbanks,and
petroleum-related installations in Cook Inlet or on the
Kenai peninsula.
Power generation that is incidental to,or a co-product
of,other.activities such as raising stearn for space heating
or industrial processes is called "cogeneration."
Interconnection and power pools.
Transmission lines owned by electric utilities and
other entities are typically interconnected into regional
power pools or grids that allow the utilities and non-
utility power producers to lend,exchange,or sell power to
one another.Interconnection helps ---
(1)to minimize joint costs,by allowing one utility to
shut down a high-cost generating unit when another
utility has surplus power available at lower cost;
(2)to level daily and seasonal load peaks:Where the
loads of different utilities peak at different times
times of the day or the year,interconnection can
reduce their overall requirements for high-cost peak
generation capacity;and
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(3)to meet emergencies:
utility's individual
capacity}.
Interconnection reduces each
need for reserve generating
In the Anchorage area,the generating capacity of CEA
and AML&P are interconnected at the Eklutna substation,but
these two utilities have yet not found it necessary or
practical to manage their facilities jointly in order to
minimize generating costs or to reduce the need for capacity.
In the Fairbanks area,however,the intertie composed of
GVEA,FMUS,the University of Alaska,and the two military
bases,does actually function as a local power pool.
Utility customers:residential,commercial,and industrial.
For ratemaking and statistical purposes,electricity
consumers are usually classified into at least three groups:
residential,commercial,and industrial.Electric consump-
tion by institutions and government is usually treated as
part of the commercial sector,but is sometimes counted
separately.
Residential consumers are individual households,
including those apartment dwellers who are individually
metered by the utility.
Commercial consumers include stores,office buildings,
hotels,service establishments,and (usually)schools,
hospitals,and other institutions,government buildings and
street lights,and centrally-metered apartment houses.
Industrial consumers include manufacturing plants,
resource extraction and processing <facilities,and the
like.Electric service to the industrial sector is either
"firm"or "interruptible.If
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The utility is obliged to
provide service to its firm industrial customers to the
limi t of its capacity at all times,but in times of peak
demand or equipment failure,it may shut off its interrupt-
ible customers,who pay lower rates,in order to assure
reI iable service to its residential,commerc ial and firm
industrial customers.
Methods of organizing and financing electric power supply.
The chief forms of business organization in the
electric power industry are private utilities,cooperatives,
municipal utilities,and federal agencies.
Private utilities.Private or "investor-owned ll elec-
tric utilities account for about three-fourths of the
electricity sold in the United States,but their role is
insignificant in Alaska and none currently exists in the
Railbelt area.
A private utility is an ordinary business corporation
governed by a board of directors responsible to its share-
holders,who are typically ind i viduals,other businesses,
and financial institutions (insurance companies,pension
funds,etc.).Its earnings are taxable,and it has no power
to issue tax-exempt bonds.
Most private utilities do business only in a single
state and have local operational management,but many
are controlled by multi-state utility holding companies that
make major construction and financing decisions.State
public utility commissions or public service commissions
like the Alaska Public Utilities Commission (APUC)typically
regulate retail rates and terms of service for private
utili ties,while in most cases {but not in Alaska,where
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there are no interstate connections),the Federal Energy
Regulatory Commission (FERC)regulates their wholesale rates
and service.
Cooperatives.Rural electrification (REA)cooperatives
(or co-ops)are subscriber-owned utilities,governed by a
board of directors elected by its ratepayer-members.Most
co-ops outside of Alaska are distribution utilities for
small towns and rural areas,and buy their power from
private utilities or federal projects.Co-ops,however,
currently generate more than half of the electricity sold in
Alaska IS Railbel t.Anchorage-based Chugach Electric Asso-
ciation (CEA),with about 75,000 subscribers,is the largest
electric utility in Alaska.
CEA sells electricity to two other co-ops,Matanuska
Electric Association (MEA)and Homer Electric Association
(HEA).Golden Valley Electric Association (GVEA),the
state's second largest utility,serves the Fairbanks area,
the upper Tanana valley,and the Nenana-Healy-McKinley Park
area.
The retail business of electric co-ops,like that of
the investor-owned utilities,is regulated by state utility
commissions,including APUC,and their interstate wholesale
business is regulated by FERC.As private enterprises,
electric cooperatives do not have the power to issue tax-
exempt securities,but they can borrow at 2 or 5 percent
from the Rural Electrification Administration (REA),a
federal government entity.REA will also guarantee the
bonds of electric cooperatives,most of which are sold to
the Federal Financing Bank at rates one to two percentage
points below market rates for private utility bonds.
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Cooperatives can borrow from the National
Cooperative Financing Corporation at rates
those of the private market.
Rural Utility
sl ightly below
Municipal utilities.The term municipal utility refers
to any utility operated by a subdivision or agency of a
state or province.In North America,most municipal utili-
ties distribute power in a single community,and most of
them are relatively small.The municipals do,however,
include some large-city systems with substantial generating
capacity,such as the Los Angeles and Seattle utilities.In
Alaska's Railbelt,municipal utilities serve Fairbanks,
Seward,and part of Anchorage.
The municipals include a variety of government-owned
enti ties.In add i tion to city systems,the term is used
to cover state-and county-chartered public utility dis-
tricts,and state and provincial power or hydro authorities,
including the Alaska Power Authority.
The management and accounts of some municipal utilities
are merged with those of their parent city,county,or state
government,as in the case of the Anchorage and Fairbanks
municipal utili ties.Al ternati vely,the util i ty may be an
autonomous government-owned corporation with an independent
board of directors and a wholly separate budget,and with
the power to make its own construction and borrowing deci-
sions (like the British Columbia Hydro Authority),or
something in-between (like the Alaska Power Authority).
The retail business of municipal utilities is regulated
by the state uti I i ty commiss ion in some states,whi Ie
in others it is left unregulated,on the ground that local
elections give the consumers a better remedy for unsatis-
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factory servic~or excessive rates.~n Alaska,the public
utilities commission regulates municipal utility rates and
terms of service only (1)outside the limits of the munici-
pality (where the direct political remedy is absent),(2)
where the utility competes with another utility in the same
service area (e.g.,CEA and AML&P),or (3)where the munici-
pal utility wholesales power to a utility that is subject to
APUC jurisdiction.
The Alaska Power Authority is exempt from APUC regu-
lation,but the APUC may regulate the purchase and resale of
Authority-generated electricity by the utilities that are
under its jurisdiction.
As agencies of government,municipal utilities are
generally exempt from federal,state,and local taxes.The
state legislation establishing the Alaska Power Authority,
however,explicitly allows it to make payments in lieu of
local property taxes,but the law is not clear whether the
local government or the Authority is to decide whether or
not such payments will actually be made.
The Internal Revenue Code allows municipal utilities
that engage in the retail distribution of electricity to
issue tax-exempt securities,but it is not clear whether
tax-exempt bonding would be available for a wholesale power
project like the proposed Susitna facility.Tax-exempt
revenue bonds are the most common source of funds for
municipal power projects.Unlike general obligation bonds,
for which the "full faith and credit"of the municpality
or state is committed to servicing the debt,revenue bonds
are a form of "non-recourse"debt,in which the lenders can
call only on the revenues of the project itself,and not on
the revenues or assets of the parent government.
-7-
Federal power.Outside of the Tennessee Valley Autho-
rity (TVA),federal power in the United States is generated
in hydroelectric projects built by the Army Corps of Engi-
neers or the Interior Department 1 s Bureau of Reclamation.
The Bureau of Reclamation or a regional subdivision of the
Department of Energy (like the Bonneville Power Administra-
tion in the Pacific Northwest or the Alaska Power Adminis-
tration)operates the facilities and markets the power.The
Alaska Power Administration currently operates two projects
---Snettisham near Juneau and Eklutna near Anchorage.
Each federal power project must be acted upon several
times by Congress during its planning,design,and construc-
tion.Congress first authorizes funds for planning and then
---in a separate action ---appropriates them.After that,
Congress mayor may not authorize construction and appro-
priate the funds called for in the initial construction
budget.Project designs are often modified,and cost
overruns are almost inevitable,creating a need for further
rounds of Congressional deliberation.As a result,decades
may pass between a project's initial conception and its
operational start-up.
Federal law requires PERC to review rates charged by
federal power projects,in order to ascertain that those
rates correspond to the project's operating costs,including
an allowance for depreciation and payment of interest to the
U.S.Treasury on the federal funds invested in the project.
Congress typically stipulates the interest rate for
each project in the specific legislation authorizing its
construction.In most cases,interest rates on federal
power projects ---and thus the rates for power they gen-
erate ---have embod ied a federal subsidy.The interest
-8-
rates,in other words,have tended to be substantially less
than the current yields on U.S.Treasury bonds at the time
they were authorized;more importantly in the view of most
economis~s,the rates have been far less than the rates
private investors would have had to pay for capital under
otherwise similar terms.
Regulation of the electric power industry.
The distribution of electricity is often characterized
as a "natural monopoly;"that is,an industry,in which the
economic cost of service (sometimes called "resource cost"
the value of labor,materials,and capital that go into
the service)tends to be lowest when only one firm serves
each market area.For an industry with this characteristic,
competition would promote unnecessary duplication of facili-
ties and consequently higher consumer costs.Wi thout
competition,however,there is little to spur a profit-
seeking firm to pass the technical benefits of natural
monopoly through to its consumers;economic theory and
historical experience both suggest that unregulated private
monopolies tend to charge excessive prices,and to deliver
inadequate service.
There are two general ways of dealing with this
dilemma:public utility regulation and government enter-
prise.In either case,public authorities face three broad
types of decisions:
***
***
franchising (sometimes called "certification"or
"licensing")---authorizing a particular entity
to operate in a giv€n service area;
certification of new facilities (sometimes called
"licensing"or "permitting");and
-9-
***ratemaking
customers.
setting or approving charges to
Regardless of the type of utility involved,construc-
tion of new facilities typically requires approval from
several federal,state,and local agencies with respect to
safety,environmental and other concerns.For utilities,
however,the term "regulation"is often reserved for deci-
sions regarding the three economic issues just listed.
For municipal utilities and other government enterpri-
ses,the franchising decision is made when the city council,
state legislature,or Congress authorizes the utility.or
agency's establ ishment or expansion,whi Ie the budget
approval process serves the function of certifying new
projects.Some government-owned utilities have complete
discretion over the rates they charge consumers (perhaps
within some statutory guideline);the rates of others are
set or reviewed by the general political authorities (e.g.,
the city council)or regulated by a state public utility
commission or FERC.
Rate regulation.The several forms of utility organi-
zation use significantly different accounting concepts;
likewise the ways in which government regulators define and
measure the elements of utility cost vary from state to
state and between levels of government.Nevertheless,the
basic principles of utility ratemaking are essentially the
same for regulated private utilities and government enter-
prises.Rates are generally designed to produce just enough
revenue to cover the utility's "cost of service",which is
composed of ---
***
***
operating costs,such as the costs of fuel,labor,
materials,and purchased services;
interest on debt;
-10-
***
***
***
***
amortization (repayment)of debt;
depreciation (to the extent not covered by amorti-
zation of debt);
taxes (if any);and
a fair and reasonable return (or a competitive
return)to the owners'equity inveatment.
Rate structures.
The principle that a utility's revenues should be just
sufficient to cover its total costs (including a "fair and
reasonable"return to investment in the case of a private
firm)does not necessarily dictate the utility's "rate
structure"the allocation of those costs among its
customers and types of service.A utility's rate schedule
or "tariff"normally provides different rates for different
classes of service and,within each class,according to the
amount of electricity the customer consumes.
Promotional rates.utilities and regulatory bodies in
North America have tended to favor "declining-block"or
promotional rate structures,in which
1.Those customers whose electricity demand is
least sensitive to prices,like households and small
businesses,pay the highest rates,and those whose
demand is more sensi ti ve,heavy industry for example,
pay lower rates;
2.Consumers within any service class who consume
more electricity pay lower prices,as under "all-
electric"residential rates,for example;and
3.Each class of consumers pays the same price for
expensive peak-period power as for cheaper off-peak
service.
-11-
---------_."._..,---_.,----------
One intended effect of such rate structures is to
encourage the growth of power demand.They thereby accomo-
date the desire of utility managements to expand their
organizations and,until the 1970's at least,this rate
design strategy was supported by a widespread bel ief that
electrical generation was a "decl ining-cost"industry in
which load growth could result in lower rates for all
classes of consumers.
The decl ining-cost rationale for promotional rate
design includes the following elements:
Economies of scale in generation.Larger thermal
(fossil and nuclear)generating plants cost less per kilo-
watt of capacity,and are more fuel-efficient.Thus,the
larger a utility's total demand the greater the opportunity
it has to use the largest,most economical plants.
Technical advance.Newer plants cost less per
kilowatt of capacity,and are more fuel-efficient,so that
the more rapidly a utility's demand grows,the newer its
plant is on the average,and the lower its average cost of
generation.
Economies of scale in distribution,administra-
tion,and billing.The more electricity each customer
demands,the lower will be the unit cost (the cost per
kilowatt-hour)of distribution,administration,and billing.
Load factors.Industrial demand for electricity
fluctuates less over the the course of the year than resi-
den tial or commerc ial demand,and the res iden tial and
commercial use of electricity for space-heating,water-
heating and air-conditioning fluctuates less over the
course of the day than do the residential and commercial
uses (cooking,lighting,appliances,etc.)Lower rates for
-12-
industrial consumers and for all-electric residential and
commercial service,therefore,result in higher system load
factors,and result in lower costs of service for everybody.
Value of service.Rates need to be lower for
large industrial and commercial customers than for house-
holds and small businesses,because the former might find it
profitable to generate their own power or switch from-
electricity to other forms of energy.
Some of these arguments are more valid than others;
some of them are valid for some utility systems and not for
others;and some of them have become distinctly unfashion-
able in recent years.Today most systems seem to face
increasing,not decreasing,long-run generating costs.It
is not clear that effective economies of scale exist for
thermal plants beyond a capacity of about 500 megawatts,and
the fact that a large plant can generate electricity more
cheaply than a small one does not necessarily mean that
greater system demand means lower costs,if it requires
building of a greater number of plants.Moreover,while the
energy efficiency of new generating plants improved con-
stantly until the late 1960 IS,technical advance on this
front now seems to have halted.
Most importantly,however,increased siting and con-
struction costs,additional outlays for safety and environ-
mental protection,higher interest rates,and licensing
delays have made capital costs for new generating plants of
all kinds ---and thus the cost of electricity from them ---
far higher than at existing plants.
Increasing demand for
higher rates in most parts
rapid increases in demand
electricity now clearly means
of the United States,and more
mean even higher rates.The
-13-
difference between the cost of power from existing plants
and new ones is most acute in regions like the Pacific
Northwest that have been blessed with low-cost hydroelectric
energy,but where incremental demand must be served by
expensive nuclear or coal-fired steam plants.
Inverted rate structures.The phenomenon of long-run
rising costs for electric power,coupled with greater public
concern over adverse env ironmental,heal th,and safety
impacts of all types of power plants,and the high price of
fossil fuels,has created a national interest in designing
utility rate structures that encourage conservation and
restrain the growth of demand.This approach,in contrast
to the customary promotional rate design,includes some or
all of the following features:
1.The most price-sensitive customers pay rates that
are at least as high (if not higher than)other custo-
mers,in order to encourage those who have the greatest
ability to conserve power to do so.
2.Each class of customers faces an inv~rted or
"as Cend ing-block"rate structure,under whi ch all
customers share some of the low-cost power from old
fac il i ties,but in which increases in consumpt ion
are billed on the basis of "long-run marginal cost"(or
"incremental cost fl
)---the full cost of power from the
utility's most expensive source.
3.Rates differ according to the season or the time
of day,in order to encourage consumers to shift their
power demand away from peak periods;such "peak-
responsibility"pricing both reduces the current demand
for expensive peaking power,and reduces the need for,
new generating capacity to serve peak period loads.
-14-
Regulatory authorities.
The Alaska Public utilities Commission.The Alaska
Public Utilities Commission (APUC)has jurisdiction over
service areas,licensing of new facilities,and both retail
and wholesale rates and terms of service for all Alaska
private utilities,including cooperatives.
As we stated previously,the APUC also has authority to
regulate municipal utilities ---
***where they compete with another utility in the same
service area;(Chugach Electric Association
and the Anchorage Municipal Utility,for example,
have overlapping service areas.)
***where they operate outside municipal limits;and
***in their wholesale electricity sales to regulated
(Le.,non-municipal)utilities.(This authority
has apparently never been exercised.)
The APUC has no direct jurisdiction over the Alaska
Power Authority (state)or the Alaska Power Administration
(federal),but it may approve or disapprove electricity
purchase contracts that Alaska regulated utilities propose
to sign with either agency.
The Federal Energy Regulatory Commission.The Federal
Energy Regulatory Commission (FERC),formerly the Federal
Power Commission (FPC),is an independent agency housed in
the u.s.Department of Energy.FERC jurisdiction includes:
Licensing of all power facilities (1)on navigable
rivers,and (2)on federal lands.Any Susitna power
proj ect will therefore need a license from FERC,
because the upper Susitna is a navigable river for
purposes of the Federal Power Act.The damsi tes and
-15-
their surroundings are now on federal lands,but by the
time any license could be granted,they will have been
conveyed to the Cook Inlet regional corporation under
the Alaska Native Claims Settlement Act.
Review of rates and terms of service on wholesale
electricity transactions in interstate commerce.The
federal courts have repeatedly upheld FPC claims of
jurisdiction over wholesale electricity sales in the
Lower 48,even wi thin a single state,on the theory
that almost all commerce is at least indirectly inter-
state commerce.Alaska I s geographical isolation and
the absence of electrical interties with other states
mayor may not make a differenceJ but thus far,FPC and
FERC have not tried to assert jurisdiction over whole-
sale electricity transactions among Alaska utilities.
Review of rates and terms of service for electric-
ity sold by federal power projects including the
Alaska Power Administration 's Snettisham and Eklutna
hydroelectric projects.
TransE2£tation of natura~a~_for_E~~~le_ln
inter-state commerce.FERC might conceivably use its
authority over interstate gas transportation to re-
strict shipment of Prudhoe Bay natural gas through the
Alaska Highway gas pipeline for electric utilities in
Alaska.The federal courts have upheld FPC prohibi-
tions of shipment of gas on an interstate pipeline even
wi thin a single state and even for direct sale (that
is,not a sale for resale),for an "inferior"purpose
electric utility boiler fuel.
The Economic Regulatory Administration.The Economic
Regulatory Commission (ERA)of the U.S.Department of Energy
-16-
administers the Powerplant and Industrial Fuels Act of 1978
(PIFUA),which generally prohibits use of oil or natural gas
as fuel for new electrical generating plants,and discou-
rages its use in existing plants.The Act provides several
grounds on which ERA may waive the prohibition.
Other licensing,permitting,and regulatory agencies.
An appendix to this chapter lists other state and federal
agencies with licensing,permitting,or other regulatory or
supervisory authority over new electrical generating plants
and associated transmission lines.This list is not com-
plete,however,either with respect to the agencies in-
volved or to their responsibilities.
-17-
APPENDIX A:EXISTING RAILBELT UTILITIES
Excluding the military bases,the University of Alaska and the
private industrial installations on the Kenai Peninsula,the majority of
Alaskans receive their electric };X)W€r from eight major utility systems
located thrOl.ghout the Railbelt region.Of the utilities,three are
municipally owned and operated,one is a federal power project,and four
are rural electric cooperatives:
Cooperatives:
CEA .
GilFA
MEA
HEA
Municipals:
AML&P
FMUS
SES
Federal project:
APA-E
Chugach Electric Association,Inc.
Golden Valley Electric Association,Inc.
Matanuska Electric Association,Inc.
Homer Electric Association,Inc.
Anchorage Municipal Light and Power
Fairbanks Municipal Utility System
Seward Electric System
Alaska Power Adrninistration-Eklutna
I
'I
The Copper Valley Electric Association,Inc.(CVFA),and the region
from Valdez to Glenallen served by this utility are not eXFected to
berome part of an interconnected Railbelt unless and until the Susitna
Dam beromes a reality.We have,therefore,excluded it from this
review.
As of December 1979,CEA estimated the nurnl:er of its customers at
50,000 retail and 24,000 wholesale acrounts making it the largest
utility in the state.Peak demand reached 31 0 ~in 1979,with a recent
annual growth rate of aOOut 12 percent.The retail service area of CEA
encompasses the Greater Anchorage Municipality,the City of Whittier and
the Eastern Kenai Peninsula,while the utility supplies wholesale power
to the City of Seward,the Horner Electric Association service area,and
the Matanuska Valley.
Aside from being the largest electric utility in Alaska,Chugach
Electric currently supplies its customers with the some of the least
expensive fX)W€r in the country.Natural gas prices in Anchorage are
less than those in other states:hence,wholesale generation rosts of
operating natural gas turbines are now at a minimum and are being passed
along to customers of the cooperative.
How much for how long?It is roth an enviable and difficult
position in which CEA now finds itself.The National Energy Act of 1978
technically prohibits the use of natural gas in future powerplant
facilities and encourages utilities to convert to coal-fired generation.
At the same time,exemptions can be granted under special conditions.
It is logical for Chugach to seek these exemptions,either temporarily
or permanently,in the hope of retaining the low-priced natural gas
generation for as long as possible.What is difficult for roth the
utility and others to determine is exactly how long a time that will
be.
-18-
Lobbying and legal efforts may be used to retain access to the gas
at least for the short term.What is not clear is whether conversions
to coal,small"hydro,or other alternative technologies could be made
later in a relatively short period of time to serve the mid-term growth
needs of CEA's service area,if prohibitions on use of natural gas are
enforced.
Let us asstmle,however,that the short-term needs are satisfied by
natural gas and that CEA attempts to meet its mid-term needs by coal or
arother alternative,the question remains as to the amount of power
needed for the long-term.Should Chugach enter into a take-or-pay
contract that guarantee the utility's willingness to rely on Susitna-
generated power in the next decade?Will the growth of demand make
Susitna an economic power source for the Railbelt,or might a series of
smaller generation projects fulfill the area's power needs at the same
or even lower cost?It is the examination of questions such as these on
which CEA must base its future actions;and one must keep in mind that
Chugach is probably the key to a yes or no determination on Susitna's
financial feasibility,and therefore,to the ultimate fate of"the
project itself.
On the Kenai Peninsula,power outages are frequent in severe
winters,but they usually stem from transmission and distribution
failure rather than inadequate generating capacity.While aburrlant power
from a major hydroelectric project v,uuld seem to be a general !:xxm,the
cost of tapping into that power v,uuld still have to be rorne by the
customers of the smaller cooperatives,thus making individual billings
higher during the time those tie-in services are being amortized.This,
combined with the arrKJrtization of the capital costs of the Susitna Dam
itself,might make any of several energy alternatives more attractive to
Kenai residents.A smaller hydro project such as the one being consider-
ed at Bradley Lake may be more in scale with the size and demands of
this area of the Railbelt.
Currently,only the Seward Electric System is engaging in new
construction,the majority of which is aimed at upgrading transmission
and tie-in facilities for wholesale power purchased from CEA Both SES
and REA (Homer)purchase the bulk of their present generation from CEA.
During winter outages,each utility relies on minimal back-up systems.
REA has generators on lease from Golden Valley Electric Association in
Fairbanks;these leases expire in the near future.
For non-emergency power supplies,SES and REA remain under long-
term purchase contracts with Chugach until the turn of the century -
effectively locking them into costs and budgets tied to the decisions
Chugach makes as to its own future course.If Chugach decides not to
participate in a take-or-pay contract for Susitna,these smaller coop-
eratives may be hard-pressed to keep up with generation needs of their
customers given a developnent spurt in the Anchorage area.On the other
hand,if Chugach does guarantee their purchase of Susitna-generated
power,initial expenses will be passed to wholesale and retail customers
alike.For the Kenai Peninsula,electricity is likely to become more
expensive whatever the source.
-19-
The service area of Matanuska Valley Electric Association,Inc.
(MEA)is immediately adjacent to the pIDp::>sed Susitna dams.Proximity
to the source might make Susitna power here somewhat less expensi ve
than in the outlying regions of the Railbelt.Anticipation of new
industry,new oonstruction jobs,and general Susitna-related growth
make the project very appealing to many residents of this region.In
light of a current eoonomic slump in the Valley,a large project is more
attractive to local business and p::>litical leaders than the suggested
alternative of several scattered hydroelectric or thermal projects,as
the developnental benefits of the former would be more ooncentrated in
the Mat-Su area.
The Northern Railbelt is ~erved by the Golden Valley Electric
(GVEA)Association,Inc.,and the Fairbanks Municipal Utility System
(FMUS)•GVEA operates in part of the city of Fairbanks,the Upper
Tanana valley,and the Nenana valley as far south as the McKinley
Park resort,and the FMUS is oonfined to the Fairbanks urban oore.
GVEA,like MEA,is also suffering a post-pipeline depresssion.Antici-
pation of gas pipel ine oonstruction has been keeping some investors
interested in the area,but according to one utility executive,there
were "some 1300 to 1400 idle services [inactive hookups]in Fairbanks lf
in December 1979.Something is desperately needed to revitalize
business,and some (but mt all)local leaders see the possibility that
higher electric bills would be necessary to finance new generating
plants as insignificant when weighed beside the positive impact new
contstruction activity ~uld have on the ecx:>noIT¥of the area.
GVEA I s short and mid-term expansion plans include tapping of waste
heat from Alyeska pump stations and extension of transmission lines
further South along to Surmnit the Alaska Railroad and Parks Highway,and
some new tie-ins expected mrth of Fairbanks.While m new generating
plants are currently being considered planned,and plans to use coal
from Healy were cancelled due to the oost of oornpliance with Environmen-
tal Protection Administration (EPA)clean air standards,more effective
utililization of waste heat and effective conservation efforts are
anticipated and are being encouraged in order to meet the imnediate
and near-future demand.Establishment of an intertie with the rest of
the Railbelt,which is now under active consideration,might make GVEA
more favorable to the Susitna hydroelectric proposal.
FMUS,serving the Fairbanks city core as an arm of the municipal
government,is perhaps the most vulnerable to the boom/bust cycle of all
Railbelt utilitieS.Rapid growth,as during TAPS construction,causes
overuse of electricity as construction workers and others crooo the
town.Yet long-range or even mid-to short-range generation plans can-
not be made on the basis of these relatively short bursts of activity.
Money for new and expensive facilities must oome from the local tax
base,whether it be sales,or residential and industrial property.
These tax sources are constantly fluctuating,making planning all the
more corrplicated.For mw,m new money is going into utility expan-
sion;and as is the case with GVEA,oonservation and more efficient use
of existing facilities are ex}?eCted to suffice for the foreseeable
future.
-20-
The Alaska Power Administration-Eklutna,and its principal custo-
mer,Anchorage Municipal Light and Power,would be less affected by
construction of a Susitna Dam than the other utilities mentioned here.
No expansion is now planned for Eklutna,and APA-E could deliver unused
power to the military installations in the area if Susitna power dis-
placed it from its present utility markets.
AML&P operates in a limited service area (partially overlapping
that of CEA)within the Anchorage municipality;this area is already
fully urbanized,so that its electricity demand may be relatively
insensitive to further growth in the region as a whole.As in the case
of FMUS in the north,AML&P plans its expansion budget around the
service area's tax base,which is currently in a perioo of slow growth.
Past projections of demand have been scaled down from a high growth rate
in the mid-teens to a current 12 percent figure.Installation of tltiQ
gas turbines in the early 1980's,as currently planned,should keep this
utility well on track for meeting its 1989 capacity goal of 225 row.As
in the case of CEA,the effect of federal legislation on future natural
gas supplies to~&P remains to be seen.
-21-
EXISTING lJrILITY PLAN!'AND ORGANIZATION:ANCOORAGE --COOK INLET
UTILITY SERVICE AREA OJSIQMERS TYPE OF PRESENr AND PLANNED PFAK WAD DEW\ND
lJrILITY GENERATING EQUIPMENT FORECASTS
CHUGACH ELECTRIC Greater Anch-50 ,000 retail,REA coop Five generation plants,310 MW peak 1985:856 MW
ASSOCIATION,INC.orage,Eastern 24,000 whole-since 1948 13 gas turbines,2 hydro (Dec 1979)(1976 study)
(CEA)Kenai Peninsu-sale (via MFA,turbines (Cooper Lake).
la,Whittier REA)(1979)Present base capacity tiew study in
(including 9.0 MW purchase 1980 will
from Eklutna)403 MW.probably
lower
New gas turbine will add forecast
60 MW in 1980 ; 5 gas
turbines to be retired
in 1985.
Interconnections:MFA,HEA,
SES,Eklutna
ANCHORAGE MUNI-Anchorage muni-16,378 retail Municipal Six gas turbines,5 sim-107 MW peak 1989:225 MW
CIPAL LIGHT &cipality within 4,756 street utility pIe;one waste heat.One (Sep 1979)
PCMER (AML&P)and specific lights owned by gas turbine scheduled
locations out-Merrill Field Muncipal-for installation 1980,109 MW peak
side old city (1979 )ity of one more in 1982-83.(1978 )
limits Anchorage
Interconnectionm:Emer-
gency 20 MW oonnectiom
to Elmendorf
MATANUSKA Matanuska-13 ,000 retail REA coop 93 percent of rower pur-63 MW peak 1989:225 MW
ELECTRIC ASSQ-Susitna Borotgh (1979 )since 1941 chased from CEA;7 per-(Feb 1979)(does not
CIATION,INC.including o:mt from Eklutna.include new
(MFA)Palmer,Eagle 13 MW 1970 capital)
River,600 KW standby diesel 11 MW 1969
Talkeetna generator at Talkeetna.
Interconnection:CEA
-22-
"
EXISTING UTILITY PLAN!'AND ORGANIZATION:ANCOORAGE --COOK INLEl'(CCNl'INUED)
UTILITY
HOMER ELECTRIC
ASSOCIATION
(HEA)
SEWARD ELECTRIC
SYSTEM (SES)
SERVICE AREA
Western Kenai Pen-
insula,Port Gra-
ham,Seldovia,
Homer,Soldotna
City of Seward to
mile 24,Seward
Highway
CUSTOMERS
10,422 retail
(1979 )
1,319 retail
(1979 )
TYPE OF
UTILITY
REA coop
Municipal
utility
owned by
city of
seward
PRESENr AND PLANNED
GENERATING EQUIPMENT
Four diesel and two sim-
ple gas turbines,9.3 MW.
Balance purchased from
CPA.
Interconnection:CEA
All power purchased from
CEA.
Interconnection:CEA
PEAK LOAD
55 MW peak
Dec 1979
184 million
KWH (1977)
5 MW average
daily peak
(1979 )
DEMAND
FORECASTS
1989:100 MW
1982:502 mil
KWH ('annual)
1989:967 mil
KWH (annual)
ALASKA PCMER
ADMINISTRATION-
EKLUTNA
rot applicable CEA,MEA Federal
hydropower
project
-23-
2 hydro turbines,30 MW not available not applicable
EXISTING IJI'ILITY PLAm'AND ORGANI 7,ATION:FAIRBANKS --TANANA VAU..EY
UTILITY SERVICE AREA CUSIOMERS TYPE OF PRESENr AND PLANNED PFAK LOAD DEMMU
IJI'ILITY GENERATING EQUIPMENT FORECASTS
GOLDEN VALLEY Fairbanks 15,000 retail REA coop Goal-fired steam turbine 850 KHW/mol 1983:900
ELECl'RIC NJrth Star (Healy)25 MW~Six oil-customer KWH/mol
ASSOCIATION Borough,in-fired gas turbines 179 (1979 )customer
INC (GVEA)eluding part MW;10 diesel 22 MW ---
of Fairbanks 'Ibtal 226 MW 1988:1000/
city;North kwh/mol
Pole,Ester,Interconnections:mus,cLEtomer
Delta Junction,Fort Wainwright"Eilson
Healy,Clear,AFB,U.of A.
Anderson,
Cantwell,Rex,
McKinley Park,
Ft.wainwright,
Eilson AFB.
Will extend
to Summit
FAIRBANKS Fairbanks 5,615 retail Municipal Four stearn turbines 8 MW 28.7 MW n.a.
MUNICIPAL city limits (1979 )utility TWo oil-fired gas tur-(1979 )
IJI'ILITY CMl1edby bines 32 MW;three
SYSTEM city of diesel 8 MW ---
(FMUS)Fairbanks 'Ibtal 68 MW
Interties:GVFA,U of A
-24-
APPENDIX B:FEDERAL AGENCIES HAVING JURISDICTION OVER NEW
ELECTRICAL GENERATING AND TRANSMISSION FACILITIES IN ALASKA
AGENCY
DEPARTMENT OF ENERGY (DOE)
Federal Energy Regu-
latory Commission (FERC)
Economic Regulatory
Administration (ERA)
'Alaska Power Adminis-
tration (APA)
DEPARTMENT OF THE INTERIOR (DOl)
Office of the Secretary
Geological Survey (USGS)
Fish &Wildlife Service
(FWS)
-25-
PERMIT OR JURISDICTION
Licenses power facilities on
navigable waters and on
federal lands.
Regulates wholesale elec-
tric rates and service in
interstate commerce
Reviews electric rates on
federal power projects.
Regulates natural gas sales
and transmission in inter-
state commerce.
Administers PIFUA,grants
exceptions allowing new gene-
ating facilities to burn oil
or gas.
Establishes and administers
price ceilings,entitlements
treatment,and allocation of
petroleum,including electric
utility fuel.This author-
ity reverts to standby emer-
gency power only on October 1,
1981.
Constructs and operates fede-
ral power projects in Alaska,.
as authorized by Congress.
Administers overall policy.
Advises on geological,
seismic,geotechnic,and
hydrological criteria and
design.
Protection of fish,wild-
life,and migratory birds:
anadromous/fish:endangered
species.
FEDERAL AGENCIES HAVING JURISDICTION OVER NEW ELECTRICAL
GENERATING AND TRANSMISSION FACILITIES IN ALASKA (CONTINUED)
AGENCY PERMIT OR JURISDICTION
DEPARTMENT OF THE INTERIOR (DOl)(CONTINUED)
Bureau of Land Management
(BLM)
National Park Service (NPS)
Bureau of Indian Affairs
Mining and Safety Enforce-
ment Administration (MESA)
DEPARTMENT OF AGRICULTURE
Forest Service (USFS)
DEPARTMENT OF THE ARMY
Corps of Engineers (COE)
DEPARTMENT OF LABOR
Occupational Safety and
Health Administration
(OHSA)
DEPARTMENT OF TRANSPORTATION
Federal Aviation Ad-
ministration (FAA)
DEPARTMENT OF THE TREASURY
Bureau of Alcohol,
Tobacco &Firearms
-26-
Grants rights-of way for
electrical transmission
lines across public lands.
Supports BLM and USFS in
protecting archeological and
palentological remains under
Antiquities Act.
Advises Alaska Native orga-
nizations on lands,employ-
mwent,etc.
Approves gravel removal
from federal lands.
Grants rights-of-way,per-
mits for use and occupancy
in national forests.
Issues permits for construc-
tion in and affecting navig-
able waters as designated by
COE;floodplains management.
Builds hydroelectric and
other river basin develop-
ments as authorized by
Congress.
Establishes and enforces
safety and health stan-
dards for workers.
Reviews construction af-
fecting airspace use,con-
trol and safety.
Issues permits for use and
storage of explosives (if
not overseen by OSHA or
Alaska Department of Labor)
FEDERAL AGENCIES HAVING JURISDICTION OVER NEW ELECTRICAL
GENERATING AND TRANSMISSION FACILITIES IN ALASKA (CONTINUED)
AGENCY
DEPARTMENT OF COMMERCE
National Oceanic and
Atmospheric Adminis-
tration
ENVIRONMENTAL PROTECTION
ADMINISTRATION (EPA)
COUNCIL ON ENVIRONMENTAL
QUALITY (CEQ)
PERMIT OR JURISDICTION
Coordinates and/or advises
on administration of
Coastal Zone Management
Act (CZM),particularly
with reference to protec-
tion of anadromous fish.
Administers air and water
quality standards.Grants
permits for discharge into
navigable waters.Grants
exemption from noise con-
trol standards.
Advises DOl,DOE,COE,EPA,
et aI,and the President on
environmental issues.
ALASKA STATE AGENCIES HAVING JURISDICTION OVER
NEW ELECTRICAL GENERATING AND TRANSMISSION FACILITIES
DEPARTMENT OF COMMERCE &
ECONOMIC DEVELOPMENT
Division of Energy &
Power Development
Alaska Power Authority
(APA)
Alaska Public Utilities
Commission (APUC)
-27-
Forecasts electricity de-
mand~plans facilities.
Review and approve construc-
tion plans~oversee design,
construction,acquisition,
financing,and operation of
hydroelectric and other
power generation projects;
lend money to utilities.
Grants and amends authority
to operate generation and
transmission facilities.
Oversees rates,classifica-
tions,practices,services,
and facilities of utility
companies.
-------"._--------
CHAPTER II:PLANNING FOR NEW GENERATING CAPACITY
This chapter considers the decision to install new
electrical generating capacity from the four most important
vantage points:
1.Demand forecasting.How much new central-station
electrical generating capacity will the Railbelt
require over the next ten to twenty years?
2.Facilities planning.What combination of generat-
ing and transmission facilities will provide this
capacity at lowest cost?
3.Organization and financing.
and financial arrangements
capacity most efficiently?
What organizational
will provide this
4.Marketing.How should the fixed and operating
costs of the new and old facilities be allocated
among different user groups?
Promotion vs.conservation.Despi te the seemingly
distinct headings,these four issues cannot be completely
isolated from one another.For example,utilities and
government power agencies determine their need to install
new generating capacity on the basis of expected future
electrical demand.But these same entities have a powerful
influence on future demand,because their own decisions on
whether and what kind of new generating capacity to install
and how to allocate costs among different categories of
consumers and uses,directly affect future electricity
prices.Prices are,in turn,one of the most important
influences on the amount of electricity each category of
consumer uses.
utilities and government agencies,therefore,cannot
avoid molding the future,at least in part.They can,in
fact,use their power over demand forecasting,facilities
-28-
..
planning,organization and financing,and marketing in a
manner to accomplish chosen goals,for example promoting
greater electricity demand and thereby maximizing the need
for new capacity,or fostering electricity conservation and
thus minimizing the need for new capacity •
Electric utilities,both private and public,under-
standably tend to favor the first strategy,which was almost
unchallenged in the United States until the 1970's.In the
Lower 48,the promotional approach to electric power plan-
ning has recently lost much of its support outside the
utility industry itself,but it still has many enthusiastic
backers in Alaska.
Demand forecasting.
The amount of new electrical generating capacity needed
in the Railbelt depends,of course,on the increase in total
demand for electricity,which reflects the area's population
growth,its per-capita demand for electricity in residen-
tial,commercial,and small industrial uses,and the elect-
rical requirements of new energy-intensive basic industries.
The kind of generating equipment that will meet this
demand growth most efficiently will depend upon the load
characteristics of demand ---its daily and seasonal varia-
tions ---as well as on the technical characteristics of the
various kinds of generating equipment,the kind and capacity
of existing facilities,and on the rate of demand growth.
Finally,because large-scale power projects take many
years to plan,design,build,and put into reI iable full-
capacity operation,their justification typically depends
-29-
upon forecasts of demand ten or twenty years or even further
into the future.Projections of electricity consumption
are notoriously inaccurate,no matter how sophisticated
their methodology,even for much shorter periods.Power
facility planners must therefore take into account a large
degree of uncertainty,and compare the consequences of
underbuilding with those of overbuilding.
Even without big surprises,20 year forecasts are
bound to be speculative.Figure 1 compares the forecasts of
authori tati ve government and industry groups,made between
1960 and 1970 regarding u.s.electric energy requirements in
1980,and the forecasts made between 1970 and 1980 for the
year 2000.Power system planners must anticipate require-
ments at least that far in advance,but the range of their
judgments has been astonishingly wide.
Most government and industry forecasters in the 1960's
and early 1970's essentially extrapolated the high rates of
electrical load growth that had prevailed since World War
II.Until very recently they took very little account of
the "price-elasticity of demand for"electricity ---that
is,the responsiveness of power loads to higher electric
rates.As a result,most regional and national forecasts in
the Lower 48 greatly overestimated the growth of demand,and
many large utilities have now voluntarily postponed or
curtailed the building programs that they had predicated on
these forecasts.
During the 1960's,forecasters in Alaska,on the other
hand,consistently underestimated the demand growth that
would occur in the Railbelt during the 1970 1 s,because they
had no way of anticipating the economic stimulus of TAPS
construction and Prudhoe Bay oil revenues.It appears,
-30-
..
, I
Figure 1"
Long'Range Forecasts of U.s.Electric Energy Requirements
FORECASTS OF
U.S.ELECTRIC ,,:;ERGY REQUIREMENTS
iN THE YEA.'l 1980
""I
"00 1
JL-----.-l---~---'---~_.J......-'--J!
F·:R::C.l.STS OF
L:.S.'::LEC7,,:C E.'IE;:(GY R:::aUIREM€NTS
:N ,ri£YEAR 2000
l04CCO r-----.,....-------------,
--31:-
however,that 1980 power demand will turn out to be consid-·
erably lower than the lowest forecasts for that year in
either the Alaska Power Administration's 1974 study or
ISER's 1976 report.As we indicate elsewhere in this paper,
current forecasts of Rai lbel t demand in 1990 and 2000 are
also more likely to be too high than too low.
Population and real income.The most powerful influ-
ences on electricity demand are population and per-capita
real income.Projections of rapid demand growth for the
Railbelt rest mainly upon the assumption that its population
and economy will continue to boom at annual rates like those
of the 1970's.
Economic boom in the 1980's.The most likely
prospect is indeed that rapid economic growth will resume in
1980 or 1981,fueled by the spending of Prudhoe Bay (and
perhaps other)oil and g as revenues.Major construction
projects,including the Alaska Highway gas pipeline and
possibly the Alpetco refinery,one or more petrochemical
plants,or the Susitna hydroelectric project,are likely to
give the boom added force during the mid-1980's.
The Railbelt's long-term economic outlook,however,is
dominated by the manner and rate at which the state govern-
ment spends its oil and gas income.Over the ten-to-twenty
year span that is relevant for planning new electrical
generating facilities,nothing else is nearly as important.
Wi thout extremely large new petroleum discoveries on state
lands,the coming boom will have run its course by the late
1980's or early 1990's at the latest.
-32-
Decline in the 1990's?No other basic industry or
combination of industries is now in sight to replace the
state's Prudhoe Bay petroleum revenues or otherwise to
support even Alaska's 1979 levels of population,employment,
and per-capita income,much less the levels that will be
reached by the mid-1980's.As a result,Alaska's population,
and thus the residential and commercial demand for electri-
city,will probably peak and then begin a long-term decline
some time before the end of the 20th Century.
The authors have presented the grounds for this assess-
ment in considerable detail elsewhere.In this report,
however,what matters most is not whether the "boomers"·or
"doomers"will ul timately be vind icated,but the need for
power planners to consider more than one development sce-
nario and the costs and risks their chosen strategy will
impose in the event that actual electricity demand turns out
to be much less,or much more,than their projections.
Electrici ty consumption per capi ta.Per capita elec-
tr ici ty consumption tends to increase if per capi ta real
incomes or the relative prices of competing fuels go up;and
it tends to fall if the real (constant-dollar)price of
electricity rises.
Together with population,therefore,per-capita real
income,electricity prices,and the prices and availability
of alternative fuels will be the chief influences on the
res iden ti aI,commerc ial ,and inst i tu t ional demand for
electricity in the Railbelt.The effect various deliberate
conservation measures would have on electricty demand also
must be taken into account.
Per capita income.In the past,higher level s of
real family income have consistently resulted in greater
-33-
residential and commercial use of electricity,as people
moved into larger houses,used more lights and electrical
appliances,and demanded more and better commercial and
public services that use electricity ---generously lit and
outfitted stores,offices,schools,and the like.
Since World War II,however,the most income-sensitive
part of electricity demand nationally has been air-cond i-
tioning ---an application of little relevance in Alaska.
Except for air-conditioning,most households in the Railbelt
now have most of the heavy energy-using appliances that
characterize the American lifestyle,so that income-driven
increases in per-capita electricity demand may have about
run their course ---at least in the residential and commer-
cial sectors.
Electricity prices.Higher electricity prices
discourage elecricity consumption generally;they also make
voluntary conservation measures more attractive economical-
ly,and mandatory conservation measures more acceptable.
They also encourage owners and builders of homes and commer-
cial buildings to install sol ar heating and cool ing equip-
ment,and industry to rely more on co-generation.
Higher electricity prices outside of Alaska will likely
restrain the future growth of per-capita electricity con-
sumption in the Railbelt,even if real costs for power there
do not increase at all,as Alaskans adopt the more energy-
efficient appliances and construction techniques developed
in response to Lower 48 conditions,or mandated nationwide
by federal regulations.
Fuel substitution.During the 1980 IS,energy
conservation will almost certainly more than offset any
tendency of higher personal incomes to increase electricity
-34-
..
consumption.Thus,per-capita demand in the Railbel t is
likely to grow only to the extent that higher prices or
unavailability of heating oil and natural gas may induce
households,businesses,and public institutions to use more
electricity for space heating,water heating,cooking,and
the like •
Competition between electricity and fossil fuels for
the home and commercial space-heating market has its great-
est impact at the time owners or developers choose the
equipment to go into new buildings.Conversion of existing
structures takes place only where very substantial differ-
ences exist in the price or supply reliability of alterna-
tive fuels;even in these cases,conversion tends to be
gradual and incomplete.
For this reason,the timing of new power projects may
be crucial.If Susitna power could be made available in the
early 1980's,for example,and if it were significantly
cheaper than natural gas as a fuel for space-heating,most
of the structures built in the Railbelt during the next
decade would be electrically-heated.
No power is likely to come on line from any new low-
cost source,however,until the end of the 'eighties at the
earliest,when the economic expansion and construction boom
driven by development of Prudhoe Bay oil and gas will have
played themselves out.By then,anew power source may face
a large existing stock of residential and commercial struc-
tures already committed to oil or gas,and little or no
opportuni ty to provide heating for newly-built structures.
In any event,a realistic forecast of residential and
commercial demand for electricity in the Railbelt must
-35-
carefully consider the area's natural gas price and supply
outlook,including the question whether gas distribution
systems are likely to be established in the Matanuska-
Susitna and Fairbanks areas.
Electricity consumption by new energy-intensive indus-
~.Forecasting the growth of large-scale industrial
demand for electricity is particularly tricky in a relative-
ly small market like the Alaska Railbel t,where one plant
could account for a very large fraction of total electricity
consumption.While projections of residential,commercial,
and small industrial use of electricity can normally rely on
forecasts of broad economic indicators like population,
employment,or personal income,a realistic estimate of the
demand for electricity by large energy-intensive firms has
to be approached on a plant-by-plant basis.
The demand for electricity by large-scale energy-inten-
sive industrial plants is even more sensitive to power costs
and to the relative prices of different energy sources than
are residential,commercial,and small industrial demand.
Heavy industry's choice among sources of energy is also more
affected by government regulation,which currently tries to
discourage industry from using oil and gas,even where they
are plentiful.
Unfortunately,the plants whose potential electrical
requirements need to be analyzed do not yet exist,and in
most cases are purely speculative.Forecasters of electric
power demand thu~have to make assumptions about the eco-
nomic prospects of various industries in Alaska ---about
the likelihood,timing,and location of actual investments
---as well as about the technical characteristics of each
kind of facility and about prices and the other factors that
will influence their choice of energy inputs.
-36-
Does cheap power attract industry?Forecasts of
large-scale industrial demand for electricity in Alaska are
therefore not just highly speculative,but are bound to be
controversial.Some of the push to build large electrical
generating facilities comes from Alaskans who hope and
assume ---almost as a matter of faith ---that abundant or
cheap electrical power will attract energy-intensive indus-
tries like aluminum or other primary metals refining.
Ironically,some of the opposition to the same projects
comes from people who fear heavy industrialization,but
share the boomers 'faith,for example,that construction
of the Susitna dams will guarantee establishment of an
aluminum refining industry in Alaska.
The cost of electric power,like the cost of any input
to production,will surely have some effect on Alaska's
attractiveness as a location for heavy industrial invest-
ments,but there will be few instances in which it will be
decisive.One illustration should put the issue into
perspective:Suppose that a given plant costs 1.6 times as
much to build in Alaska as in the Lower 48,Europe,or East
Asia ---a not unrealistic figure.Energy costs faced by
such a plant outside of Alaska would therefore have to equal
at least 60 percent of its fixed capital costs (depreciation,
interest,and required return on equity)before even free
energy in Alaska would offset the plant's construction cost
handicap.
In almost every case,however,energy-intensive indus-
tries are also capital-intensive industries.We know of
only two (uranium enrichment and basic aluminum)for which
energy costs in the form of electricity normally exceed even
10 percent of total costs,or 20 percent of fixed costs.
-37-
It is worth noting that a uranium enrichment plant
accounted for more than half of the Railbel t's industrial
power consumption in the Alaska Power Administration's 1974
forecasts for 1990 and 2000.Since then,the u.S.market
for new light-water reactors has virtually disappeared ---a
trend that was apparent even before the Three Mile Island
incident ---and the prospect that an enrichment facility
would be installed in Alaska in this Century is therefore
almos,t nil.It is probably safe,therefore,to regard
basic aluminum as the only energy-intensive industry that
might ever plausibly be attracted to Alaska by the prospect
of abundant or relatively cheap power as such.
The potential for attracting aluminum refiners to
Alaska is a legitimate consideration in estimating the
probable benefits (and costs)of a project like the Susitna
dams.But many factors beside the availability and cost of
electricity influence an aluminum producer's decision
whether,where,and when to build a new plant,including the
world supply-and-demand outlook for aluminum and for
other primary metals,the particular company's existing
capacity and market position,the type and source of ore
available and the cost of shipping it to the proposed
location,and local construction and labor costs.
It is therefore prudent for power supply planners
to include new energy-intensive industries in forecasts
used to ascertain the Susi tna project's feasibil ty if and
only if the new industrial facility is made an integral part
of the development plan by means of a minimum-bill "take-or-
pay"contract between the industrial firm and the Power
Authority for a definite part of the plant's generating
capacity.
Interruptible sales contracts.The desire to attract
energy-intensive industry may not be a realistic basis for
-38-
..
building new large-scale generating plants in the Railbelt,
but the prospect of marketing off-peak or surplus power to
industries already located or planning to locate in the area
is an important consideration in determining the feasibility
of a large power project like Susitna.
One possible example is the sale of interruptible power
for pump-or compressor-stations on TAPS or the Alaska
Highway gas pipeline (ANGTS).Petroleum refineries and
petrochemical plants may offer another market for interrupt-
ible power,as a substitute for the oil,natural gas,
liquefied petroleum gases (LPG's)that the plants would
otherwise use as bo iler and process fuel,or to gener;3.te
hydrogen.
It is not likely that electricity from Susitna or any
new generating facility would be competitive with oil or gas
as pump-station or refinery fuel,if these industries had to
pay the same price per kilowatt-hour as other electricity
consumers ---a price designed to cover each kilowatt-hour's
proportional share of the project's fixed capital costs,as
well as its operating or "variable"costs.
Once a generating plant's capital costs have already
been sunk,however,the added variable cost incurred in
generating and selling more hydropower is virtually nil,up
to the plant's full year-round capacity.Likewise,the
added variable cost incurred in generating more power at
(say)a coal-fired steam plant is little more than the cost
of the additional fuel it consumes,up to the point at
which the plant is running at full capacity all the time.
In such an instance,the variable cost of the addition-
al power used by pipelines or refineries might well be less
than the value of the oil or gas it would displace.If so,
the Alaska Power Authority might be able to set a price for
-39-
interruptible off-peak or surplus power that allowed the
pipeline companies or refineries to reduce the cost of
energy needed to run their facilities and which,at the same
time,contributed something toward the generating plant's
fixed costs and thereby permitted all consumers to receive
lower rates than they would in the absence of the inter-
ruptible contracts.[In technical terms,the required price
is one greater than short-term marginal costs and less than
long-term average costs.}
Load characteristics.
The generating capacity of a power supply system must
be able to del i ver both (1)the highest peak load and (2)
the total amount of electrical energy demanded during the
year (wi th an adequate reserve to cope wi th equipment
fai lures or unexpectedly high demand).For this reason,
load forecasts are generally stated in terms of two dimen-
sions of demand:
***
***
peak loads,which are measured in
kilowatts ···(KW =10 3 watts),
megawats ···(MW =10 6 watts),or
gigawatts · · ·
(GW =10 9 watts);and'
total annual consumption,which is measured in
kilowatt-hours (KWH =10 3 watt-hours),
megawatt-hours (MWH =10 6 watt-hours),or
gigawatt-hours (GWH =10 9 watt-hours).
Electricity consumption in a given service area will
have large daily,weekly,and seasonal fluctuations.The
daily peak is typically in the late afternoon or early
evening;loads tend to be greater on weekdays than on
Saturdays,and lightest on Sundays and hoI idays.In warm
climates the annual peak is usually in the summer when air
conditioners are operating;in cold climates,including
Alaska's,demand usually peaks in the winter.
-40-
The load characteristics of a given system can be
described by means of an "annual load duration curve,"which
represents the number of hours in each year that consumers
demand a given amount of electricity.Figure 2 shows such a
curve for a hypothetical power supply system with a peak
demand of 250 MW,and total annual consumption of 1,000 GWH.
Base loads.The horizontal axis of Figure 2 measures
the number of hours in the year's total of 8760 hours [365
days X 24 hours].The vertical axis measures electrical
consumption in MW.Point c shows that in this case,the
load never falls below 75 MW;this level of consumption is
called the "base load,"and the annual base load consumption
is therefore 660 GWH [8760 hours X 75 MW]•
Peak loads.For a small part of the year consumption
greatly exceeds the base load.A load exceeding some
specified level is called a "peak load."In Figure 2,
levels of consumption more than 150 MW twice the base
load ---are regarded as peak loads.Point a shows the
annual peak ---the highest level of consumption encountered
during the entire year ---as 250 MW,and point b shows that
consumption is 150 MW or more for 1000 hours during the year.
The total peak load consumption over the year is 40 GWH.
Intermediate loads.Consumption that exceeds the base
load [75 MW]but is less than the lower boundary of the peak
load [150 MW]is referred to as an "intermediate load."In
Figure 2 the total annual intermediate load consumption
during the year is 360 GWH.
System load factors.The peak load and the total
annual load can be combined into a single measure that
indicates the greatest efficiency with which a power supply
-41-
FIGURE 2
HYParHETlCAL LOAD DUPATION CURVE
(A)
250 liP.~------------------......;-
Peak lDad (40 avE)
150-~
Cl..:r:
0
H
~75~(C)E-t
UJ
>l
UJ
HOURS PER YEAR
-4:2-
system could use its generating capacity.The system's load
factor is its average consumption,expressed as a percentage
of peak consumption.In the hypothetical power supply
system of Figure 1,the average annual load is 114 MW [1,000
GWH ~8760 hours],and peak consumption is 250 MW.Thus its
load factor is 46 percent.The average load factor for the
utilities of Alaska's Railbelt is currently around 50
percent.
Low load factors are exceedingly costly in terms of the
fixed capital that must be invested in generating capacity.
In figure 2,the peak load accounts for only 4 percent of
total annual consumption [40 out of 1000 GWH]but requires
40 percent of the system's capacity [75 out of 250 MW].
The intermediate load accounts for 36 percent of total
annual consumption [360 GWH]and 30 percent of capacity [75
MW],while the base load accounts for 60 percent of total
consumption [600 GWH]and only 30 percent of capacity [75
MW].Thus,each KWH of peak load power delivered requires
the utility to have 20 times as much fixed capital as a KWH
of base load power.
The preceding figures exaggerate the disparity between
peak load and average generating costs per KWH,because the
kind of generating equipment that can produce the lowest-
cost power when it operates every hour of every day is
likely to be different from the equipment that produces the
lowest-cost peaking power.Knowledge of a system's expec-
ted load characteristics is therefore necessary for deciding
what combination of generating facilities will be most
economical for meet ing future electr ici ty demand.We
explore this issue later in the present chapter.
Alternatives to peaking power.Even if a utility
installs the ideal combination of generating equipment for
-43-
serving its individual combination of peak-,intermediate-,
and base-load consumption,peak-load power is still exceed-
ingly expensive in terms of capacity.Unless something
causes a system's load factor to improve as its loads
expand,the need to serve peak loads will account for a very
large part of its investment in new generating capacity.
Thus,strategies capable of increasing system load factors
might significantly reduce both the average cost of elec-
tricity to the utility's customers and the need to build new
generating plants.
In the United States,however,forecasts of electricity
demand have traditionally accepted a system's load duration
curve as given,and the normal incl ination of util i ty and
power agency planners is to design and build new facilities
to serve the projected peaks.[The current feasibility
study for the Susitna project,by Acres American,Inc.under
contract to the Alaska Power Authority,does plan to fore-
cast both total consumption and load duration curves for the
Railbelt.Chapter IV of this report,however,points out
some serious shortcomings in this aspect of the study plan.}
Measures do exist for significantly increasing load
factors,thereby improving the efficiency with which instal-
led generating capacity is operated,and (assuming that
total annual consumption remains unchanged)economizing on
the need for pew capacity.These effects,in turn,can be
expected to reduce average costs per KWH.Such measures
incl ude (1)interconnection,(2)interruptible electricity
sales,(3)central-station load management,and (3)peak
responsibility pricing,which are described later in this
chapter.
-44-
Facilities Planning.
Even given some idea of the amount of electricity
needed and the load characteristics of that demand,we are
still faced with the problem of choosing a combination of
generating and transmission facilities that will provide
electricity at lowest cost.Facilities planners have
traditionally used forecasts of demand and load as the major
determinents 0 f requ ired plant si ze.However,there
are a number of other issues that are important in thinking
about how to expand an electrical supply system.Capital
and fuel costs for new power facilities are obviously
important factors as are system requirements for reli-
ability.Another important consideration that has so far
received inadequate attention in the public discussion of
Railbelt supply is the impact of uncertainty about future
demand,construction costs,fuel prices,and the like,and a
system's need for flexibility to cope with the unexpected.
Facilities planning involves looking at the entire
supply system ---including its present and anticipated load
factors,use of existing equipment and management of
reserve capacity ---and for that reason,each utility and
each region faces its own unique set of facility planning
problems.One factor that complicates any evaluation of the
Susitna project is the fact that the existing generating
plants and distribution system for the area Susi tna would
serve are owned and operated by several different utilities.
Determining where and to what extent Susi tna would ii t in
requires some assumptions about how the rest of the power
supply system will function ---an issue that is clouded by
the separation of jurisdiction among several utilities.
Planning for power development in the Railbel t as a
whole must take into account the potential uses of existing
-45-
facilities owned by the utilities as well as any new facil-
ities that may be owned and operated by the Alaska Power
Authority.The legislation that established the Authority
placed this responsibility in the Department of Commerce and
Economic Development,but thus far [early 1980]the depart-
ment does not even have the funding or the staff to begin
work on a credible power development plan.
Cost concepts.
describing the costs
system supply plan
Several concepts frequently used in
of a particular generation facility or
are worth mentioning at the outset.
Fixed Costs.Fixed costs are costs incurred by a
facility regardless of whether or not it is actually oper-
ating.They include the initial outlays for purchase and
development of a site,equipment and its assembly,mater-
ials,engineering,overhead and contingencies,and interest.
Fixed costs are generally spread over the entire operating
life of a facility~if they are very large,they will
significantly affect the cost of electricity.A working
index of how important fixed costs are to the cost of
electricity generated by a particular facility is the ratio
of fixed cost in dollars to its installed capacity in
kilowatts,or "installed cost."Table I compares (1976)
installed costs for a variety of generating equipment.
Table I tells us that for each kind of generating
facility (with the possible exception of hydroelectric,
where fixed costs per unit of capacity vary enormously from
one site to another),the larger the generating unit,the
smaller the installed cost per unit of capacity.Table 1
also suggests that initial capital costs per kilowatt for
diesel generators tend to be considerably less than for
steam turbines or hydroelectric plants.
-46-
Table 1
Installed Cost Estimates for Typical Generating Units*
Unit
Diesel Generator
Gas Turbine (Simple)
Steam Turbine (Coal Fired)
steam Turbine (Gas Fired)
Hydroelectric
Nuclear
Size (MW)$/KW Installed
0.1 680
3.0 412
.8 526
10.0 322
50.0 210
.3 1346
10.0 ,891
200.0 494
.3 1130
10.0 749
200.0 415
5.0 1557
30.0 1032
125.0 1748
1000.0 1000+
*The installed costs are taken from estimates for Alaska,
made by the Institute of Social and Economic Research in
1976 and should be considered only as examples.
-47-
Operating costs.Operating costs,or "variable costs"
as they are sometimes called,refer to expenses incurred to
operate,maintain and insure a particular facility once it
is built.with the exception of nuclear and hydroelectric
plants where fuel is relatively cheap,fuel is the.number
one operating cost if a plant is operating near full capa-
ci ty.For example,in 1978,Anchorage Municipal Light and
Power spent 85 per cent of its operation and maintenance
budget on fuel.If fuel comprises a large portion of total
costs (fixed and operating),the cost of electricity from
that particular facility will,of course,be very sensitive
to the price of fuel.
Heat rate.Heat rate is a measure of the energy-effi-
ciency of a given generating facility,stated as the amount.
of heat energy in BTU that a specific fuel must provide in
order to produce one KWH of electrical energy.(Thus,the
more energy-efficient the facility,the lower is its heat
rate.)The heat rate for a given generating plant depends
not only the type of fuel,but also on the type of generat-
ing unit,the characteristics of the particular plant,and
its operating schedule.Together with the price~of indivi-
dual fuels,therefore,heat rates determine the relative
fuel costs for a unit of electricity.
Table 2 illustrates heat rates for different kinds of
generating units.One plant's greater energy-efficiency in
converting fossil fuel to electricity may be balanced
against a higher price for the fuel it requires.Combustion
turbines,for example,convert natural gas energy into
electricity less efficiently than diesel generators convert
distillate fuel oil.In Alaska,however,the greater
efficiency of the diesel engine is more than offset by the
higher price of distillate fuel oil.
-48-
Table 2
Heat Rates and Relative Fuel Costs for Electrical Generation
Heat Rate Fuel Price Fuel Cost
Plant (MBTU/KWH)(¢/MMBTU)(Mills/KWH )
steam turbine coal fired 10 90 9.0
Combustion turbine,open cycle -gas fired 16 60 9.6
Combustion turbine,regenerative cycle --gas fired 14 60 8.4
Combustion turbine distillate o~l fired 17 221 37.6
Combustion turbine residual oil fired 18 180 32.6
Diesel --distillate oil fired 11 221 24.3
Source:Estimates for Alaska made by ISER in 1976.
Electrical generating technologies.
In practical terms,it makes sense to talk about four
basic types of generating technologies that could be
used to augment generating capacity in the Railbelt.
Di~sel Electric Generating Units.Diesel generating
units are diesel-type internal combustion engines directly
connected to an alternating generator.The units are built
as a complete assembly and marketed by major manufacturers
as an "on -the-shelf"item.If properly installed and
maintained,they are fairly reliable both for base loads and
for emergency on-line systems.Larger units (500 KW or
greater)can approach fuel efficiencies of 13 kwh/gallon or
a heat rate of 10,800 btu/kwh,which is competitive with the
larger steam plants.However,smaller units (75 to 250 KW
diesels)may have efficiencies as low as 7 kwh/gallon or
20,000 btu/kwh.
-49-
Diesel generators have low fixed costs relative to
other fossil-fuel-fired generating units,but they need
a high-priced fuel.As a result,the price of distillate
fuel oil is the single most important factor determining the
cost of electricity generated by diesel plants.
Combustion (or gas)turbine generating units.Gas
turbines are installations in which either gas or oil is
fired in a turbine that drives a generator.There are a
variety of turbine types,each designed for different
capacities and fuel efficiencies.Like diesel units,small
simple-cycle turbines can be purchased ready-made from the
manufacturer;larger regenerative or combined-cycle units
may take two years to build on-site and another year to
bring on line.
Heat rates for simple-cycle gas turbines range from
12,000 to 16,000 btu/kwh,depending on their size.Regener-
ative-cycle gas turbines are more costly but more fuel-
efficient,with heat rates between 9,500 and 13,500 btu/kwh.
In the Railbelt,gas-fired turbines are the predominant
type of electrical generating unit,carrying about 70 per
cent of the total load in 1977.(See Table 3.)The popu-
larity of gas turbines in Alaska reflects their ease of
installation and consequent ability to respond quickly to
rapid (and uneven)demand growth,as well as the exception-
ally low price of natural gas in the Anchorage area (where
it constitutes the cheapest utility fuel in the United
States)•
Because of rising gas prices,gas turbines may prove
too expensive in the future for base-load power generation.
For a limited number of hours,the cost per kilowatt hour
-50-
Table 3
Railbelt Electrical Generating Capacity ---1977
Installed Capacity ---Megawatts
Gas Steam
Hydro Diesel Turbine Turbine TOTAL
Anchorage-Cook Inlet
Utilities 45.0
Military
Industrial
Subtotal 45.0
Fairbanks-Tanana Valley
Utilities
Military
Subtotal
TOTAL
9.8
9.2
10.2
29.3
32.1
14.0
46.1
75.4
435.1
14.8
449.9
203.1
203.1
653.0
14.5
40.5
55.0
53.5
63.0
116.5
161 .5
504.5
49.7
25.0
579.2
288.8
77.0
365.8
945.0
for electricity produced by gas turbines is,and probably
will remain,inexpensive relative to other types of gener-
ation.But,as the load factor increases,unit costs do not
fall rapidly,as they do for coal-fired,nuclear,or hydro-
electric plants.For this reason the greatest appeal of gas
turbines is for use in limited peak load situations.
Nevertheless,the low capital costs of gas-fired power
are an especially welcome feature in a period of double-
digit interest rates and disorganized bond markets,and
gas-based generating strategies are by far the most flexible
in the face of uncertain future demand growth.For these
reasons,the installation of new gas turbines is one
of the most attractive options for Alaska utilities,even
for base-load generation.This is likely to remain the case
despite the prospect that prices for new gas supplies
(whether from Cook Inlet or the North Slope)will be about
ten times as costly as the utilities'current supplies.
-51-
Federal restrictions on use of natural gas.For
almost a decade,FPC (FERC)and most state utility commis-
sions have discouraged the use of natural gas as electric
utility fuel.More importantly,the Power Plant and Indus-
trial Fuels Use Act (PIFUA)prohibits the use of gas in new
generating facilities,with certain exceptions.The Econo-
mic Regulatory Administration of the Department of Energy
(ERA),which administers PIFUA,has thus far tended to
interpret the Act strictly.
Since the law was enacted in 1978,however,the
national outlook for natural gas supply has improved radi-
cally,and unless ERA interprets PIFUA liberally,Congress
wi 11 almost certainly amend or repeal it.If Rai lbel t
utilities conclude that gas turbines remain the least-cost
or most prudent source of additional power,we do not
believe that federal regulators will prevent them from
obtaining as much gas as they need for new facilities,
as well as for their existing plants.
Federal policies,however,coupled with uncertainty
about future gas prices,do contribute significant risks to
any natural-gas-based generation strategy.It is not clear,
however,whether these risks are greater than the engineer-
ing,cost,schedul ing,marketing,and regulatory risks of
strategies that depend upon Susitna hydropower or steam
generating plants fired by Beluga coal.
Natural gas liquids as turbine fuel?Another
possible fuel for combustion turbines in Alaska is natural
gas liquids (NGL's)ethane,propane,butane,and pen-
tanes-plus ---that will be separated from the crude oil and
natural gas streams at Prudhoe Bay.State agencies and
chemical producers are now looking at the possibility of
shipping these liquids by means of a third pipeline (in
-52-
addition to TAPS and ANGTS)from the North Slope to the
Fairbanks or Cook Inlet areas,where they would be used as
feedstocks for chemical manufacturing.
No reliable estimates yet exist on the cost of such a
gas liquids pipeline or the delivered price of NGL's in
the Railbelt area,but prices that are low enough to assure
the feasibility of petrochemicals manufacturing may also be
low enough to make NGL's competitive as a turbine fuel for
electric util i ties.Prudhoe Bay NGL's would constitute a
reliable 20-to 25-year supply,with two conspicuous advan-
tages over oil or gas as turbine fuel:(1)their prices
could be fixed in advance for the life of the field,on the
basis of the maximum price they would be allowed to receive
under federal law as part of the natural gas stream in
ANGTS,and (2)the largest component of the gas liquids
(ethane)seems to be exempt from federal end-use controls on
both oil and gas.Thus,NGL's are at least worthy of
consideration for use as electric utility fuel.
Methanol as turbine fuel?Another potential
source of energy for combustion turbines in the Railbelt is
methanol.Several firms are now investigating the feasibil-
i ty of producing fuel-grade methanol from Prudhoe Bay
natural gas,from Beluga coal,or both.Credible cost
estimates are not currently available but methanol,like
NGL's,may conceivably turn out to be a clean utility fuel
that is cheaper than oil and exempt from some of the regu-
latory risks of natural gas.
Steam turbine generating units.Conventional steam
plants consist of a fuel-fired boiler for raising steam,
which then drives a turbo-generator.Steam turbine genera-
tors,especially units built to handle large base loads (100
-53-
to 1000 MW),are considered the most reliable and fuel-
efficient thermal generating equipment.Steam can of course
be raised by oil,gas,natural gas liquids,coal or nuclear
fuel.Except for the smallest units,the systems are always
custom-designed,requiring long lead times for environmental
assessment,fabr ication and del i very of major equipment.
As with gas turbines and diesel generators,the economics of
steam plants are very sensitive to the price of fuel.
The 1976 ISER study found that uranium and coal would
be the least expensive fuels for steam generation in Alaska
in the long run.While nuclear power may be viable techni-
cally,the Alaska Power Administration and most of the
utilities in the region have ruled it out because of its
high initial fixed cost,siting problems,and probable
public opposition.
Coal-fired plants remain a serious alternative as a
source of additional power for the Railbelt,because of the
nearby Beluga coal reserves.Although fuel costs would
probably be low compared with those of oil or gas,initial
cost for an enclosed plant with scrubbers would be extremely
high:the Power Administration has estimated them at $372
mill ion (1978 dollars)for a 200 MW plant ($1,860 per
kilowatt installed),and $810 mill ion for a 500 MW plant
($1,620 per kilowatt installed).
Hydroelectric generating units.Hydroelectric facil-
ities create electricity from falling water and are con-
sidered among the most reliable types of generating equip-
ment.Minimum maintenance requirements and the virtual
absence of fuel costs make these facilities very cheap to
operate.Initial capital costs are usually very high,
however,with investment per KW of total capacity greater
-54 ...
than fossil fuel-fired installations.Because the best
hydro sites are usually at some distance from the load
centers,transmission facilities are often a large portion
of the initial cost.In Table 4 the 1978 cost estimates
suggest that hydroelectric plants would be more expensive to
build but cheaper to run than coal-fired steam turbine
plants.
Table 4
Estimated Costs for Coal-Fired
Steam Plants and the Susitna Project
Installed Cost OM&R Cost
(mil.S/(S/KW/
(mil.S)(S/KW)year)year)
100 MW coal steam turbine 245.4 2,454 3.76 37.6
200 MW coal steam turbine 372.0 1,860 5.70 28.5
400 MW coal steam turbine 646.8 1 ,617 9.80 24.5
Watana dam (795 MW)2,020.7 2,554 0.74 0.94
Transmission line 470.5 2.01
Devil Canyon dam (778 MW)834.0 1,072 0.73 0.94
Total Susitna project 3,335.2 2,120 1.47 3.89
Source:Alaska Power Administration,October 1978
The efficiency of hydroelectric energy conversion is
expressed as the ratio between electric energy delivered out
of the plant and the maximum theoretical energy of the
available volume of fall ing water.This ratio can reach
about 90 per cent,compared to a maximum conversion effici-
ency of about 38 per cent in the best fossil-fueled plants.
Each hydroelectric site and each facility is unique,
and thus the economics of hydroelectric plants are very
sensitive to local conditions (e.g.,topographic and hydro-
graphic conditions,distance to load centers,etc.).
Typically,hydroelectric facilities require long lead times
for design and installation.
-55-
Cost hierarchy for electrical generation.As the
previous discussion shows,the composition of generating
costs depends upon the type of plant.When initial fixed
costs are high,as in the case of steam and hydroelectric
plants,operating costs playa relatively small role in the
unit cost of electricity.At the other end of the hierarchy
gas turbine and diesel plants have relatively low initial
costs but high operating costs for fuel and maintenance.
This cost hierarchy is the main consideration in power
supply and management strategies.For a hydro project where
fixed costs are large and must be recovered whether electri-
city is generated or not,it is extremely important for
demand to justify operating the plant as many hours as pos-
sible.A utility that relies on diesel or gas turbine
generation,on the other hand,will not suffer disaster if
some of its plants are forced to stand idle.This is the
reason demand forecasts are so crucial in ~ssessing the
viability of the Susitna project.
Plant mix.The cost hierarchy among generating tech-
nologies,plus the load duration curve,determine what mix
of facilities would provide the lowest cost electricity for
base,intermediate,and peak load situations,and thus,for
the entire system.
In figure 3,the top graph is a load duration curve
similar to that of figure 2,depicting the number of hours
in a year that hypothetical utility faces a given level of
demand,from the peak load (L 4 )down to the lowest load of
the year.In the bottom graph the four curves each depict
the annual costs (in dollars per kilowatt of capacity)for
four types of generating technology.The point where each
line originates on the vertical axis shows the fixed capital
-56-
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-57-
cost of a given type of technology,while the slope reflects
hourly operating costs ---principally fuel.
As we have seen in earlier examples,initial fixed
costs cost per kilowatt of capacity are lowest for gas
turbines (FC,),followed by the coal-fired steam turbine
(FC 2 ),nuclear (FC 3 ),and hydro (FC 4 ).The hierarchy
of fuel and other operating costs is just the opposite,
however:the figure shows that gas turbine generating costs
increase the most steeply,and hydropower costs the least,
as the number of hours of operation increases.
In this example,the four cost curves indicate that
gas turbine generation is the least-cost way to satisfy
any load that will persist for no more than T l hours.For
any load whose annual duration is more than T l and less
thanT 2 hours,a coal-fired steam plant would have the
lowest unit cost.In a similar manner,the figure identi-
fies those portions of demand for which nuclear and hydro
would be the cheapest alternatives.
Returning to the upper graph,we can infer the least-
cost mix of generating plant for the entire system:
Hydro capacity should be L,MW,and should be operated
continuously.Nuclear capacity should be L 2 -L,MW (pro-
vided,of course,that this is a feasible scale for a
nuclear plant)and should be operated T3 hours per year.
Coal-fired Plants should have a capacity of L 3 -L 2 MW,
and should be operated T 2 hours per year,while gas-turbine
capacity should be L 4 -L 3 MW,and operated only T,hours
per year.
Use of existing equipment.When facilities planners
choose a mix of technologies,they must match the system's
-58-
load characteristics to both existing and proposed equipment
in order to determine what kind of supply system will best
serve base,intermediate,and peak loads,while providing
sufficient reserve capacity to meet unantic ipated demand,
and scheduled and unscheduled equipment outages.Each
utility or region has a unique cost hierarchy,and the cost
of available generation technologies are not always ranked
on the load duration curve in the same order as they appear
in figure 3.Some hydroelectric projects,for example,are
best sui ted for use as base-load supply,and others make
more sense for meeting peak load requirements.The distinc-
tion depends on each facility's unique combination of annual
stream flow,reservoir storage capacity,and installed
generating capacity.
The most cost-effective role for an existing plant may
also change through time.An older fossil-fired plant may
be shifted from base-load to peaking service,and ultimately
retained only as reserve capacity,if operating costs are
lower on newer parts of the system.Changes in the relative
costs for different generating technologies may likewise
make it worthwhile to install additional generators at an
existing hydro-electric project whose initial construction
had to be justified by its low cost for base-load supply,in
order to use its limited water supply to generate peak-load
power.
Dealing with Uncertainty.With perfect foresight,it
would be possible to choose the lowest-cost combination of
plants for a given system with confidence,but the real
world is full of surprises.We noted earl ier that demand
forecasts are notoriously inaccurate,especially in Alaska
where major development projects continue to have an uneven
and often unanticipated effect on demand.
-59-
There are other uncertainties as well.Large projects
are more prone to cost overruns and delays in completion and
operation than small,quickly constructed plants.Large ($1
billion and up)custom-engineered construction ventures in
North America begun in the 1970 I s typically took three to
fi ve years longer to complete than orig inally planned,and
cost overruns of 100 to 500 percent were not unusual.
The bigger the unit of construction,the more unique
the design,the more novel the technology or environment,
and the larger the number of governmental entities and
permits and licenses involved,the greater the overruns and
the longer the delays tend to be.A project that seems
feasible on the basis of its original engineering cost
estimate and planned completion date may easily turn out to
be uneconomic on the basis of a more realistic schedule and
cost estimate.
Choosing to build a series of small generation plants,
say gas turbines,avoids most of the uncertainty about
construction cost overruns and scheduling delays,but it
invokes another unknown:the rate of fuel cost escalation.
The latter was certainly one of the great surprises of the
last decade.
In providing for an uncertain future,therefore,
utility planners must be aware of the consequences of both
overbuilding and underbuilding.The costs of excess capaci-
ty will consist largely of fixed charges on investment,
resulting in higher unit costs of electricity and higher
costs to consumers.Proponents of maximizing capacity tend
to argue that the new capacity,with its greater thermal
efficiency,can be expected to save on fuel costs.But a
new fuel-efficient facility can be justified as a replace-
ment for,or duplication of,an existing facility if and
-60-
only if the old intallation's operating costs alone exceed
the new plant's total costs per unit of electricity ---that
is,its fixed and operating costs combined.
If capacity turns out to be inadequate,a power system
usually has considerable latitude for using its existing
generating capacity more intensively.Doing so is likely
to require more high-priced fuel,however,and some reduc-
tion in system reliability.Utilities can also bring on
line additional capacity in smaller if less efficient
---units as they are needed,and not run the risk of
investing large amounts of capital for a demand that may not
materialize.
Reserve requirements and load management.
The investment strategy of most electric utilities in
the United States has historically been a passive response
to growing demand.Each utility tried to construc~,in
advance of need,sufficient generating capacity to meet
its forecasted total and peak load demands,plus an adequate
reserve to cover unexpected peak loads and scheduled or
unscheduled equipment outages.To the extent that rate
design or marketing strategies were deliberately used to
influence demand,they tended to be promotional ---aimed at
stimulating demand and thus justifying new construction.
In Europe and Asia,however,where both capital and
operating costs have been considerably higher than in the
United States,planners and utility managers have given much
more attention to conservation ---both of dollars invested
and of fuel consumed.As a result,system load factors in
some countries are as high as 65 to 75 percent,in contrast
to a range of 45 to 60 percent in the united States.Also,
-61-
reserve margins above forecasted peak loads have been
reduced below 10 percent in some countries,while utilities
in the United States tend to carry reserves of 20 to 30
percent.
The promotional policies of North American utility
systems generally had the support of state and federal
regulators and of the public at large,so long as utility
fuel remained cheap,blueprints for massive new projects
seemed to offer major economies of scale,and the techno-
logies of newer plants surpassed the older ones in effici-
ency and operating costs.
Recently,however,the growing difficulty of siting and
licensing new plants,higher construction costs and interest
rates,and above all higher fuel costs,have finally created
an interest among utility planners and regulators in promot-
ing the more intensive use of existing generating capacity
and reducing the need for new facilities,by means of (1)
peak-responsibility pricing,(2)"load manangement"tech-
niques,and (3)reduction of planned reserve ratios.
These initiatives were boosted in 1978 by Congressional
passage of the Public Utility Regulatory Policies Act
(PURPA),which is intended to encourage:
***conservation of energy supplied by electric
utilities;
***efficient use of existing generation facilities
and resources;and
***equitable rates to electric consumers.
Among other things,PURPA requires FERC and the state
utility commissions to consider peak-responsibility pricing
and other rate-design measures intended to foster efficiency
and energy conservation.
-62-
Reserve generating capacity.Electric power systems
always carry some reserve capacity in excess of their
forecasted peak demand.The excess capaci ty provides
insurance against system failure,and is also available to
meet unanticipated peak loads or future increases in base
load demand.
Reserve capacity is usually measured in terms of a
"reserve margin,"which is the percentage of total capacity
that is in excess of the anticipated annual peak load.In
the two Railbelt load centers,1977 reserve margins were as
follows:
(1)(2 )(3 )(4 )
(2)-(1)(3)/(2)
Generating Reserve Reserve
Peak Load Capacity Capacity Margin
Place (MW)(MW)(MW)( %)
Anchorage-
Cook Inlet 464.4 691.1 226.7 32.8
Fairbanks-
Tanana Valley 159.9 364.9 220.5 56.2
TOTAL 623.3 1,056.0 447.2 42.3
Source:Alaska Power Administration.
The reserve margins that Railbel t utilities carried,
even at the peak of the TAPS construction boom,were thus
considerably higher than the 20 to 25 percent sought by most
Lower 48 utilities.This comparison does not necessarily
mean that the Alaska margins were excessive,because they
reflect in part the relatively small size of these systems,
in which the shutdown of a single unit would make a very
significant dent in total generating capacity.They do,
however suggest that measures that reducing the required
reserve margins could serve as a substitute for a large
volume of new plant construction.
-63-
Suppose,for example,that the two load centers were
interconnected into a single power pool,and that this
pool ing,plus load management and selective load-shedding
strategies,permitted reserve margins to fall as low as 15
percent and yet preserved acceptable levels of reliability:
The 1056 MW of area-wide generating capacity that existed in
1977 would then be able to serve a peak load of 898 MW [85
percent of 1056],an increase of 44 percent over the actual
1977 peak demand.The additional useful capacity that
might thus be made available from the Railbel tis existing
equipment would be equal to more than one-third of the
projected capacity of the Susitna project's Watana dam.
System reliability is the extent to which power can be
provided to customers without interruption and at an accept-
able voltage and frequency.System planners have developed
a number of statistical measures of reliability,which serve
as the i r targets in determining each system's opt imum
reserve margin,taking into account uncertainty of load
forecasts,size of generating units relative to total system
size,need for preventive maintenance,and the reliability of
individual units.
A growing number of analysts believe that the prevail-
ing reliability standards are unnecessarily strict,and
require wasteful excess capacity.One reason for this new
skepticism about traditional reliability standards is of
course the soaring cost of new plants,and the difficulties
of obtaining site approval and licenses.But it also stems
from a growing recognition that the great majority of power
interruptions that electric customers actually experience
result from distribution system failures,rather than
generating plant outages.It makes little sense to provide
a generation "loss of load probabl i ty"(LOLP)of one inc i-
dent in ten years while the utilities offer (and regulatory
-64-
---------------------~--~-----_....
authorities and consumers are willing to put up with),say,
an average of one outage per year arising from a failure of
transmission lines,substations,or distribution lines.
Load Management.Utilities in the United States are
belatedly finding it attractive to reduce reliability target
levels and devise peak-responsibility pricing or load
management schemes.Load management permits a utility to
make more intensive use of its low-cost base-load generating
capacity;to economize on the higher operating costs of
existing intermediate and peak capacity;and to reduce the
amount of new construction required to serve intermediate
and peak loads and to maintain reserve margins.
Load management techniques include:
1 .~s tabl ishmen t 0 f power pool s or in tert Les with
other utilities,in order to take advantage of peaks
occuring at different hours or times of th~year and to
share reserve generating capacity.
2.Installation of time switches to shut off less
essential heavy-load appliances and industrial equipment
during peak demand hours.
3.Install ation 0 f remote-control switches that
permit the utili~y to shut off less essential loads during
peak demand hours or system emergencies,by means of a
signal sent by radio,telephone,or through the power line.
4.Design of peak-responsibility rate structures,
under which consumers are billed for peak period power at
its relatively high cost to the system and for off-peak
power at the much lower cost of base-load generation,
creating an incentive for consumers themselves to reduce
peak-hour demand.
-65-
5.Sale of off-peak or surplus power to industry at
low interruptible rates.
Only pool ing (=If 1)and in terruptible sales (=If 5)are
commonplace in the United States today,and the latter is
actually a device for increasing off-peak loads rather than
for reducing peak demand.In the past,the cost of instal-
ling time-switches,remote control load-shedding equipment,
and time-of-day metering was a major obstacle to implement-
ation of load management strategies in the United States
or so the utilities argued.The appearance of the $10
microprocessor (the chip at the heart of pocket calculators
and mini-computers)has now swept away any substance this
objection may have had in the past.
In the future,environmental and consumer spokesmen at
licensing and rate hear ings;federal and state regulators,
and the utilities r bankers and investors will all demand
that utility planners fully exlore the potential of using
rate design and load-management strategies to reduce capital
and operating costs,before they raise rates or build
expensive new plants.Thus far,the question is practically
unheard-of in Alaska,but we are confident that ---sooner
or later ---it will be a prominent issue in debate over the
Susitna project,and rightly so.
Organization and financing.
Principles of finance.When utilities must replace
equipment or build new capacity,they are concerned,from a
financial standpoint,with two questions:how to raise the
necessary capital and who will assume the risk.These
questions are major ones,for advances in technology,
stricter environmental and safety standards,inflation,and
the cost of capita!have all conspired to drive up the
original cost of electrical generating plants.
-66-
While large projects offer certain benefits with
respect to economies of scale,their sheer si ze also in-
creases the investment risk.In recent years,other eco-
nomic circumstances,such as an unanticipated fall-off in
demand growth,rapidly and unpredictably rising fuel prices,
changes in laws and regulations,equipment and technology
failures,cost overruns,and delays in plant construction,
have also aggravated the uncertainty of actual completion
and final costs for large projects.
To avoid or minimize these risks,lenders invariably
require one,and usually both,of the following assurances:
(1)The project's anticipated cash flow from
operations must be sufficient to make all scheduled
payments of principal and interest on time,and with a
~substantial margin ("coverage")to spare~and
(2)The borrower or a creditworthy third party
must pledge sufficient collateral or unrelated income
to pay of the entire loan plus accumulated interest,
even if the particular project should fail altogether.
The first requirement is normally met by the borrower's
equity in the venture.The more equity there is in the
project's "capital structure,"the less likely it is that
revenues will fail to cover operating expenses and debt
service.Conversely,the more leveraged a firm's capital
structure ---that is,the higher the percentage of debt ---
the greater the danger that,for some reason,revenues will
not be adequate.
The second assurance is usually carried on the strength
of the borrower's total assets and the soundness of its
-67-
overall capital structure.Most firms maintain a capital
structure about evenly divided between equity and debt.The
1978 debt of the top 50 manufacturing companies in the
Fortune 500,for example,was 51 percent of their total
assets.utilities can safely carry higher debt ratios than
unregulated industries because,while regulation does limit
profit rates,a utility's monopoly status gives lenders
confidence that it will be able to cover its costs,inclu-
ding debt service charges,under almost any circumstance.
Even for Fortune's top 50 utility companies,however,debt
"was only 62 percent of total assets,and among the utili-
ties,there were just two that had "debt ratios"exceeding
75 percent.
conventional balance-sheet financing.Traditionally,
private and municipal utilities alike have raised capital
and assumed the risk of build ing and operating new gene-
rating facilities through "balance-sheet financing".That
is,all debt capital contributed to the project is secured
not only by the assets of and the cash flow from that
project,but by the entire income and assets of the spon-
soring company or government agency.
Capital for conventional balance-sheet financing is
usually raised by selling securities (stocks and bonds)to
the public individuals,banks,mutual funds,pension
funds,and insurance companies.Municipal utilities usually
sell tax-exempt bonds,thus obtaining a lower interest rate
than conventional bonds,and cooperatives are able to borrow
from the Rural Electrification Administration (REA).
The surplus earnings that a utility retains from its
operations,and depreciation allowances on existing facili-
ties,are also sources of capi tal.Generally,pri vate
-68-
utilities do not payout all their net earnings in dividends
to shareholders,but rather retain a portion for reinvest-
ment or as a reserve to cover their debt service (principal
and interest payments)obligations,should future cash flow
fall short of expectations.(Municipal utilities and
governmental power authorities generally do not calculate a
"profit"entry in their books,or pay dividends to their
governmental owners at all.They may nevertheless accumu-
late surplus cash from earnings and depreciation allowances
for reinvestment or debt service coverage.)
Most utility expansions,including all projects we are
aware of in Alaska (other than federal power projects)have
been financed conventionally on the utility's balance-sheet.
Several factors,however,are undermining the abil i ty of
individual utilities to finance large projects conventional-
ly,particularly in Alaska:
1•Proj ects are getting bigger.In most places,new
base-load generating facilities are designed to carry
greater loads and thereby take advantage of economies of
scale.However,with the attendant high initial fixed
costs,compounded by long construct ion and shake-down
schedules,the assets and markets of a single utility may
not be able to cover construction and operating costs,or
bear the risks of cost-overruns,delays,and non-completion.
2.Traditional sources of direct and third-party
guaranteed loans to Alaska utilities are drying up.Most
cooperatives in Alaska have financed their expansion hereto-
fore wi th two-and five-percent REA revol v ing loans.
Payments of principal and interest on earlier REA loans are
the chief source of new loan money.Because the demand for
these loans is increasing,while the original appropriation
-69-
into the revolving fund is limited,this source of capital
will be depleted within the next five-to ten-year period
unless Congress injects additional money.
3.Rapid facilities expansion in the 1970's aggravated
the already high debt ratios of REA cooperatives in the
Railbelt.Despite their exceptionally low interest rates,
the utilities appear to be facing increasing difficulty in
servicing their existing long-term debt.
As a general rule REA expects its borrowers to have an
"interest coverage ratio"---the ratio between revenues
less operating expenses and interest payment obligations ---
of at least 1.5.Table 5 shows that the utilities'debt
ratios have tended to increase,with a corresponding drop in
interest coverage down to levels that may preclude large
debt issues in the future,at least without very dramati c
and unpopular rate increases.
Table 5
Debt and Interest Coverage Ratios for Railbelt REA Cooperatives
Utility
Matanuska Electric Association
Homer Electric Association
Golden Valley Electric Association
Chugach Electric Association
Debt
Ratio
1973 1977
87.0 93.7
88.5 87.7
92.1 95.9
90.9 94.7
Interest
Coverage
1973 1977----
2.76 1.03
2.07 1.51
2.07 1.61
1.52 .93
Thus far,"the Alaska regional office of REA has managed
successfully to meet the utilities'demand for low interest
capital.But if the cooperatives must turn to other sources,
-70-
r n
such as the Federal Financing Bank or the National Rural
Electrical Cooperative Financing Corporation,they will face
not only higher interest rates,but the need to reduce their
debt ratios and increase their interest coverage.
4.The cost of money is increasing.with soaring
interest rates,utilities that need to raise capital will
have to pay dearly for that money ---if,indeed they can
obtain it at all in a disorganized bond market.Recent
rates in municipal bond sales have been at 8 to 9 percent or
higher,and higher interest rates may require more than
proportional increases in electricity prices,because of the
need for higher absol ute levels of interest coverage --_.in
addition to the rate increases dictated by higher fuel and
construction costs.
Alternative financing strategies:Project financing.
The circumstances we have described probably make conven-
tional balance-sheet financing of a project as large as
Susitna infeasible for any existing Alaska utility or even
any combination of existing utilities.Instead,the Alaska
Power Authority is considering an alternative method:
"project financing."
The essence of project financing is creation of a new
business entity in charge of the project for which the
sponsoring companies or government bears no liability.The
new entry has virtually no assets outside of the proj ect
itself;hence prospective lenders must be assured that some
other creditworthy party will meet the tab for principal and
interest payments in the event that the project does not
generate sufficient revenues.
-71-
Project financing if attainable carries two
advantages for sponsoring utilities:(1)the debt ratio can
be comparatively high (70 to 100 percent),and (2)the debt
is secured by means other than placing the assets of the
parent companies (or the full fai th 'and cred it of the
governmental sponsor)on the line.It virtually absolves
the sponsoring companies from carrying any business risks
beyond contributed equity capital,if any.Moreover,
because the debt does not appear on the sponsors I balance
sheet,they can use project financing to sidestep provisions
in their existing debt obligations that would otherwise
limit their ability to incur further debt.
Project financing is not,however,a means of shifting
construction,operating,or marketing risks to the lenders.
All such risks must be assumed by some other party or
parties at least as firmly as the sponsors would have
assumed them in a conventional financing.There are essen-
tially two methods of securing debt without recourse against
the sponsors ---guarantees from consumers,and guarantees
from governments or other third parties.
The first approach relies on revenues from project
customers,secured by II all-events II,II minimum-bill ll
,IItake-
or-pay"contracts,whereby the wholesale customers (Alaska
utilities)bind themselves to pay the costs of operation and
maintenance,interest and the scheduled repayment of princi-
pal ---however high those charges may be,and whether or
not the service or product is actually delivered.There are
three preconditions for this kind of project financing:
1.Distribution utilities must be willing to sign
all-events,minimum-bill,take-or-pay contracts,in advance
of construction,obI igating themselves to pay all of the
project I s debt service and operating costs,however high
those costs might be.
-72-
2.The Alaska Public Utilities Commission (APUC)must
have the legal authority,and use that authority,to assure
in advance that those contract obligations will be "per fect-
ly tracked"into the bills of the final electricity consum-
ers,no matter how great the charges may be.
3.Lenders must be confident,despite these contrac-
tual and legal assurances,that an adequate market exists
for the power,and that the bills paid by final consumers
will in fact be enough to meet the utilities'contractual
obligations to the project entity (along with their other
obligations).
These conditions are not implausible,but they are
exceedingly demanding.If they can not be met,a non-re-
course (revenue bond)project financing will be impossible,
and capital can be raised for plant construction only by
means of general obligation bonds or some other form of
state loan guarantee,Or by direct governmental financing.
Construction financing.Take-or-pay contracts do not
normally take effect until projects are complete and oper-
ating.There is little chance that private lenders will
agree to assume the risk that a major Alaska power project
will not be completed,will be completed only after an
extended delay or,if completed,will not work properly.
Thus,while the three assurances described above might
attract financing of post-construction long-term debt,it
will be far more difficult to find lenders who are willing
to carry the project over its construction period.
There are only two parties capable of securing the
construction debt of a large project-financed generating
-73-
plant in Alaska:final consumers and the state government.
The preconditions for consumer guarantees of construction
debt are even more demanding,and considerably less probable
of achievement,than those for securing long-term debt by
means of take-or-pay contracts:
1.The utilities that contract to buy power from the
project entity must agree to pay interest and to begin
repaying the principal on all funds used for "construction
"-
work in progress"(CWIP)during the entire construction
period.This arrangement is in contrast to the more conven-
tional one in which all pre-operational costs,incuding
interest on construction debt (the "allowance for funds used
during construc.tion"[AFUDC])are "capitalized,"with all
charges to cus,tomers postponed until the facility begins
operating.
2.The APUC must have the authority,and must use that
authority,to assure that these pre-operational charges are
perfectly tracked into final consumer bills,despite the
fact that consumers might not receive any electricity from
the project for ten or more years (if ever).
3.Lenders must be confident,despite these contrac-
tual and legal assurances,that the existing market for
electricity in the Railbelt can bear the additional charges,
and that the bills paid by final consumers will in fact be
enough to meet the utilities'contractual obligations to the
project entity in addition to their other obligations.
We have not rigorously calculated the expected impact
of this method of financing on consumer electric bills,but
in the case of the Susitna project it would likely double or
triple the average cost of electricity to Chugach Electric
-74-
Association customers over the entire period of ten years or
more before they even began to receive Susitna power.
Consumer bills after the facility went on line would be
correspondingly lower because much of the project's capital
cost would already have been paid.This attraction,how-
ever,probably would not be sufficient to override the
consumer outcry against taking on huge price increases
now.
The implication of the foregoing is that construction
of the Susitna project,or any generating facility of
comparable size in Alaska,is unlikely to be financed
wi thout some kind of government loan guarantee or direct
government investment.
-75-
CHAPTER III:HISTORY OF THE SUSITNA PROPOSAL
During the first half of the Twentieth Century,hydro-
electric generation (with its high reliability and its
freedom from recurring fuel costs)was the preferred source
of electricity wherever suitable damsites existed.One of
the chief missions of the Interior Department's Bureau of
Reclamation was to identify potential hydropower sites,
particularly on the Western federal lands.
Origins of the Susitna project.
Alaska's rivers were included in the federal site
identification program,but they were too remote from the
continent's population centers to draw much attention during
the federal dam-building programs of the 1930's.Major
developments,instead,centered on the Tennessee,Columbia,
Colorado and other Lower 48 river systems.Federal interest
in Alaska's hydropower potential was almost nonexistent
until the late 1940's.
[In 1950,]the Department of the Interior provided
$150,000 to be used by the Bureau of Reclamation to update
its Alaskan investigations of 1948.The results of these
studies were to be used as a basis for legislation authori-
zing the developnent of the territory's water resources.
In its final report,published in 1952,the Bureau of
Reclamation identified a large number of possible hydro-
electric power sites throughout Alaska.The Bureau pointed
out that,among all the potential rivers,the Susitna River
was the JOOst strategically located of all Alaska streams
because of its proximity to Anchorage and Fairbanks and the
connecting railbelt.[Naske &Hunt,1978]
The Bureau of Reclamation report identified three
Susitna River damsites as having special potential ---Vee,
17 miles below the mouth of the tributary Tyone River;
Watana,36 miles downstream;and Devil Canyon,28 miles
-76-
further downstream.In view of the still-limited demand for
electricity in the region,however,Congress only authorized
construction of a smaller dam closer to the Anchorage load
center:the Eklutna project,which was completed in 1955.
Bureau of Reclamation interest in the Susitna con-
tinued nevertheless,with release of a feasibility study in
1960 that favored a two-dam project at Devil Canyon and
Denali a site between Vee and Watana,about 10 miles below
the Susitna River Bridge on the Denali Highway.In 1961,
the Interior Department recommended Congressional author-
ization of this project with transmission lines to move
Susitna power to both Fairbanks and Anchorage.
The Army Engineers'Rampart proposal.
About the same time,however,a rival project promoted
by the Army Corps of Engineers and the Alaska Congressional
delegation began to draw off much of the pol i tical support
for Susitna development both within Alaska and in Congress.
Advocates of the gigantic Rampart Dam on the Yukon River
successfully persuaded Congress to defer action on the
Susitna concept until studies of Rampart were completed.
Although Governor Egan,two major Railbelt utilities,
the Anchorage Daily News and the Fairbanks News-Miner,the
Alaska Chapter of the National Electric Contractors Associ-
ation,and the Alaska Conservation Society all preferred the
Susitna development,the Corps of Engineers and Senator
Ernest Gruening captured the public's interest for the much
more dramatic Rampart project throughout the mid-sixties.A
recent review of Rampart's political history by Klaus Naske
and Will iam Hunt [1978]concl uded that obsession with the
grandiose and unrealistic Rampart scheme delayed serious
consideration of the Susitna by more than a decade.
-77-
._-_._--------------~-------------------------
A 1967 report by the Interior Department effectively
eliminated Rampart as a contender,finding that the project
was neither economically nor environmentally sound.In-
stead,Interior recommended creation of a power pool that
would interconnect the Cook Inlet and Interior Alaska load
centers,and construction of new gas-fired plants in the
Cook Inlet area and a mine-mouth coal-fired plant at Healy.
For the longer-term it recommended further consideration of
hydroelectric projects on the Susitna River and at Bradley
Lake near the head of Kachemak Bay.
By the time that Interior issued its report,two
organizational changes had occurred that affected the
outlook for the Susitna project.First,the Army and
Interior Departments,responding to Congressional annoyance
about their competitive posture on river-development schemes,
agreed to end their rivalry.The lead in hydropower policy
and research was to be located in the Bureau of Reclamation
(Interior),while design and construction responsibilities
went to the Corps of Engineers (Army).
Creation of the Alaska Power Administration.
Subsequently,in 1967,the Interior Department withdrew
the Bureau of Reclamation from Alaska entirely,and trans-
ferred its duties to the Alaska Power Administration (now
part of the Department of Energy,and not to be confused
with the state's Alaska Power Authority).The new agency is
charged with forecasting electricity demand,and planning
water resource development and electrical transmission
facilities.The Administration also operates and markets
\
power from the existing Eklutna hydroelectric installation
near Anchorage and the Snettisham project near Juneau.
-78-
New federal interest in Susitna.
In 1972,the u.s.Senate Public Works Committee,of
which Alaska's Mike Gravel was a member,passed a resolution
requesting the appropriate federal agencies to assess the
electricity needs of Alaska's railbelt area,and to take a
fresh look at development of the Upper Susftna.In 1974,
the Alaska Power Administration responded with an update of
the Bureau of Reclamation's 1961 report and again recom-
mended construction of a two-dam system,using the Denali
and Devil Canyon sites.
In 1976 the Corps proposed to proceed with Phase I
of the project's engineering and design on the basis of the
1974 studies.That year,Congress authorized $25 mill ion
for the Phase I effort,conditional upon "notification to
Congress of the approval of the Chief of Engineers.II All
the required procedures for this approval had been completed
by May 1977,when the office of Budget and Management (OMB)
blocked the expenditure,insisting instead on supplementary
geological,engineering,and economic studies.The Corps
issued its supplemental report in February 1979;OMB ap-
proved it,and in the summer of 1979 the Corps forwarded it
to Congress,where it is still under consideration.
State initiatives:The Kaiser proposal and establishment of
the Alaska Power Authority.
Meanwhile,the State of Alaska had begun to consider
independent initiatives to advance Susitna hydropower
development.The state contracted for an economic and
engineering feasibility study with the Henry J.Kaiser
Company,which was considering Alaska locations for a major
aluminum refining plant.Kaiser's 1974 report proposed a
wholly different construction strategy,composed of a higher
-79-
darn (Susitna I)about five miles upstream from the Devil
Canyon site recommended by the Bureau of Reclamation and the
Corps of Engineers,with smaller dams downstream (Olson)and
upstream (Vee and Denali),to be built later.This concept
appears to have no active support today.
The 1976 session of the Alaska Legislature created the
Alaska Power Authority (to be distinguished from the federal
Alaska Power Administration)as a vehicle for direct state
in i t i a t i ve sin the des i gn ,fin a nc in g,con s t r uc t ion and
operation of a Susitna hydroelectric project or other
electrical generating and transmission facil i ties in the
state.
The Authority was empowered to conduct engineering,
economic,and financial feasibility studies;finance power
projects directly through issuance of revenue bonds;lend to
existing utilities or regional power authorities through a
power project revolving loan fund;and contract with pro-
ducers for the purchase of electricity.While legislation
creating the Authority was enacted in 1976,it did not get
any staff or funding until 1978.
Senator Gravel's funding proposal.
In 1976,the Susitna development was not moving very
rapidly on the federal level.Moreover,Alaska's Senator
Mike Gravel was concerned that Congressional attitudes
toward federal power were changing and that the time
was quickly running out on the practice of appropriating
vast amounts of money for ri ver-development projects
whose benefits were wholly local.The Susitna proposal was
clearly in this category:It would require a large portion
-80-
of total federal outlays for power development to an oil-
rich state,for the benefit of as little as one-tenth of one
percent of the nation's population
state in the nation,to boot.
and in the richest
Senator Gravel argued the urgent need for a break with
tradition.Alaska must rely u~another means of financing
hydroelectric projects.The senator profX)sed that Congress
appropriate monies to a revolving fund equal to the phase
one or the advanced engineering and design portion of any
one Project.The sponsoring state agency,in this case the
Alaska Power Authority,soon to be created by the state
legislature,would issue bonds based on the profX)sed.Project
to pay the Corps for the phase-one ~rk.
In the event that the proposed development was not
feasible,the federal revolving fund monies ~uld be used to
payoff the state t:onds.If,however,the profX)sed project
proved to be feasible,the Alaska Power Authority would
issue revenue t:onds and contract for the work.Under the
Gravel plan,the federal revolving fund.~uld act solely
as a guarantee for the phase-one costs incurred by the state
sponsor.[Naske and Hunt,1978]
Current investigations.
The Gravel proposal as such was not adopted by Con-
gress,but Phase I work for Susitna was conditionally
authorized in the Water Resources Development Act of 1976.
The Act did incorporate Gravel's concept of a coopera-
ti ve federal-state effort in detailed feasibil i ty stud ies,
and required the state to reimburse the federal outlay for
Phase Iif the project proved feasible.
As an alternative to executing a cooperative agreement
with the Corps of Engineers,the state had the option of
arranging for and financing its own studies.The creation
of the Alaska Power Authority in 1976,combined with suspi-
cions in Alaska that the federal government was both out of
sympathy with Alaskan goals and unable to move with dispatch
or competence,led the state legislature to appropriate
-81-
$8.17 million to the Authority in 1979 for a series of
feasibility analyses and design studies that may ultimately
cost more than $50 million.
The Acres study.
The Alaska Power Authority treated the Corps equally
with three private consulting firms as competitors for the
Phase I effort.In November 1979,nevertheless,the Power
Authority contracted for the studies with a private group
led by Acres American,Inc.of Buffalo,N.Y.and Columbia,
Maryland.Acres'subcontractors include
***R &M Consultants of Anchorage (geotechnical field
studies);
***Frank Moolin &Associates of Anchorage (construc-
tion management):
***Terrestrial Environmental Specialists,Inc.,of
Phoenix &New York (environmental assessment);
San&Woodward-Clyde Consultants of Anchorage
Francisco (seismic studies);
Salomon Brothers of New York (financial advisors);
and
***
***
***Cook Inlet Region,Inc.,and Holmes and Narver,of
Anchorage (logistical support).
Work began in January,1980,and will continue for
about 30 months.There is no guarantee that the engineer-
ing,environmental,and economic findings will be favorable.
Further,even with the most positive study conclusions,the
state and federal permitting process would take another
three to five years before construction could begin.
Chapter IV of this report summarizes Acres t February
1980 Plan of Study,identifies some weaknesses in the Plan,
and proposes some modifications to it.
-82-
The legislature's study of alternatives to Susitna,and this
report.
In 1979,the Alaska legislature,fearing the attention
and funding devoted to the Susitna project would obscure
potential alternatives,which might be more economical
or less environmentally disruptive,appropriated $200 ,000
to the Division of Legislative Research to "(1)analyze
existing assumptions and findings concerning power needs and
population growth proj ections of the Railbel t •[and]
(2)analyze energy supply alternatives,including
Susi tna • •.I'
When the research division was disbanded in the Summer
of 1979,the House of Representatives establ ished a Power
Alternatives Study Committee,composed of Representatives
Brian Rogers and Hugh Malone,to oversee this appropriation.
[The Committee funded the present report out of the $200,000
with a $25,000 contract to ArIon R.Tussing and Associates,
Inc.]
The Alaska Power Authority subsequently augmented the
legislative appropriation with $30,000 to increase the scope
of a power market demand study for Acres by the Institute of
Social and Economic Research,so that ISER might consider
end uses of energy in Alaska.
-83-
CHAPTER IV:THE ACRES PLAN OF STUDY
Introduction
In February 1980,Acres American,Inc.,published its
Susitna Hydroelectric Project Plan of Study.This document
is the refinement of a preliminary plan that Acres submitted
to the Alaska Power Authority in September 1979,in the
firm's original study proposal.Eric P.Yould,executive
director of the Power Authority,introduced the Study Plan
"to the public at large and all interested agencies and
organizations,"stating:
1.The fact that a feasibility study is to be under-.
taken does not necessarily mean that a hydroelectric project
of any kind will ever be oonstructed on the Susitna River.
It will provide the basis,however,upon which an informed
decision can be made as to whether the State oould or should
proceed in the matter.
2.The publ ication of this plan does not permanently
fix the manner in which the prop::>sed v.ork is to be accomp-
lished.On the contrary,I regard it as a dynamic document
which will,I hope,~steadily improved with your assist-
ance.It has already undergone an important metamoq.hosis
as a result of testimony and correspondence received during
the past four rronths,and I have no doubt that further ed i-
tions will be responsive to your suggestions and oomnents.
In line with the Power Authority's request,the Alaska
House of Representatives'Power Alternatives Study Committee
contracted with ArIon R.Tussing &Associates to review the
Acres Study Plan,in order to propose further improvements.
After examining the February 1980 document,the reviewers
concluded that the plan needs serious changes in its empha-
sis and in the scheduling of its study tasks if it is to
serve as the basis for informed decisions by the state.
This chapter briefly summarizes the Study Plan,identifies
those shortcomings in subject areas that we are competent to
address,and proposes a number of amendments in the sub-
stance,funding level,and sequence of study tasks.
-84-
..
General description.
The $30 million Acres American,Inc.,study plan is
intended to establish the technical,economic and financial
feasibility of the proposed Susitna hydroelectric project
for meeting the future power needs of the Railbel t region,
and to evaluate its environmental consequences.If the
Alaska Power Authority determines that the venture is
feasible,Acres and its subcontractors would prepare a
license application for submission to the Federal Energy
Regulatory Commission.
The
involves
***
***
***
***
***
***
study itself is scheduled to take 30 months and
a multidisciplinary team of consulting firms:
Woodward-Clyde Consultants power studies and
seismic analysis;
Salomon Brothers ---financing plan;
R &M Consultants hydrologic investigations;
Frank Moolin&Associates ---project and construc-
tion management;
Terrestrial Environmental Specialists environ-
mental assessement;and
Cook Inlet Region,Inc.,and Holmes and Narver ---
logistical support.
The project team will ,undertake essentially thirteen
tasks as follows,at a total cost of $29,604,249:
1.Power studies ---demand forecasts,generation al-
ternati ves,expansion sequence and plant mix,and
impact assessment.($359,200)
2.Survey and site facilities ---land tenure and j u-
risdictional analysis,field studies and surveys,
aer ial photography and mapping,and access road s.
($7,858,600)
-85-
3.Water resource studies development of stream
flow data;reservoir operation;gl acial movement,
flooding,ice,sedimentation,etc.($1,826,000)
4.Seismic studies seismic risk analysis,and
development of seismic design criteria for dams,
transmission 1 ines and access roads.($1,139,000)
5.Geotechnical exploration data collection and
analysis for surface and subsurface geology and geo-
technical conditions.($3,620,500).
6.Design development development of preliminary
engineering design and cost information for Watana
and Devil Canyon damsites.($1,769,000).
7 Environmental studies assessment of alterna-
tives for power generation,access road and site
facility locations and power transmission corridors;
preparation of PERC license application exhibit.
($6,570,300)
8.Transmission selection of transmission route,
preliminary engineering designs,and cost esti-
mates.($729,300)
9.Construction cost estimates and schedules cost
estimate summaries and construction schedules
suitable for the application to PERC;analysis of
possible delays,changes and their effects on
costs and schedules.($185,000)
10.Licensing preparation and assembly of all
necessary documentation for the application to PERC.
($293,500)
11.Marketing and financing examination of finan-
cial feasibility and development of a financing
plan.($383,100)
12.Public participation establishment of a public
information office;conduct of public workshops and
meetings;and preparation of information,materials,
and action lists.($383,000)
•
13.Administration project management.($467,700)
-86-
Information for decision-making.
The Study Plan assumes that the Power Authority will
base a choice between the Susi tna project and one or more
al ternatives on the findings of a Power Al ternati ves Study
Report to be completed 11 months into the overall study,
containing
"load forecasting for the Railbelt region:
"selection of alternative energy and/or
'power generation scenarios:
"evaluation of viable expansion sequence
scenarios:and the
"recommended expansion sequence."
This first phase of the study is thus its most vital
element from the standpoint of deciding whether or not the
state should concentrate its efforts on developing the
hydropower potential of the Susi tna River or pursue other
alternatives in earnest.Unfortunately,this phase seems to
be both the most superficially considered part of the Acres
plan,and the least adequately funded,accounting for only
1.2 percent of the total study budget ($359,200).
The gravest defect in the current plan of study is the
fact that neither Acres'findings nor the Power Authority's
decision regarding Susitna I s viability would be based on
its economic or financial feasibility.This is not a fault
that Acres or the Authority can remedy simply by providing
more funds or a more sophisticated work plan for some of the
study subtasks but is,rather,one that demands an overhaul
of the organization and scheduling of the study as a whole.
As it now stands,the Acres plan proposes to choose
among alternative generation strategies before making any
cost,schedul ing,or contingency analyses of the Susi tna
project itself.The contractors would not begin making
even preliminary cost and scheduling estimates for the
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project until the 73rd week ---five weeks after all other
alternatives have been rejected ---nor does it begin to
consider "potential contingencies/risks and to evaluate
their effects upon cost estimates and schedules"until the
115th week.The study plan,moreover,would begin consider-
ing the marketability of Susitna power and the project's
financibility only after the Power Authority had made a
decision to proceed.
The contractors would look at cost and risk comparisons
for alternative methods of electric generation (to Susitna)
in the power al ternati ves study prior to the go/no-go
decision,but according to the plan information on even the
al ternatives would be "developed for each technology
(cost/unit energy)based on existing studies."[em-
phasis added]The sources that the plan explicitly refer-
ences are 1976 documents,while the whole work tasks of
analyz ing al terna t i ve power generat ion strateg ies and
determining the optimal plant mix account for only 4/1000 of
the total project budget ($126,000).Even if this infor-
mation on al ternati ves were adequate for making a choice
among them,it is hard to see wha t us e it would be in the
absence of cost,scheduling,and risk estimates for the
Susitna project itself.
Demand studies.
The "need"for Susitna power,its marketability,its
cost to consumers,and the project's financibility all
depend upon the total amount of electricity demanded by
residential,commer ical and institutional,and industrial
consumers in the Railbelt.In order to choose the best
combination (or indeed,even a workable combination)of
generating facilities,power system planners need to know
two dimensions of future demand:(1)the total demand for
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electrical energy,which is usually measured in megawatt-
hours over the course of a year,and (2)the peak load,
which is the highest number of megawatts demanded at any
time ,during the year.
In the Acres plan,the Institute of Social and Economic
Research of the University of Alaska (ISER)will prepare
forecasts of total demand,while Woodward-Clyde-Consultants
are to produce peak power demands and load duration curves
"in a manner which is consistent with the economic,social,
political,and technical assumptions made by the ISER when
developing their energy consumption forecasts."
ISER I S demand scenarios.This report does not review
or criticize the scope or methodology of the ISER study.
It is important,however,to recognize one crucial limit-
ation of the "scenario"approach to demand projection used
by ISER and most other forecasters.The scenario method
uses an economic model to produce results that are consis-
tent with some set of assumptions about (say)future oil
discoveries or petrochemical development in Alaska,world
energy prices,federal regulations regarding the end-uses
and pricing of natural gas,and the like.But the scenarios
themselves will say nothing about the truth or even the
likelihood of such assumptions,and most forecasting tech-
nicians hesitate to express strong opinions on their
truth or likelihood.
Using the scenario method,therefore,ISER will surely
present several forecasts of future electricity demand,some
of which will seem to argue in favor of,and others against
building the Susitna project,but Acres and the Power
Authority will have to decide which,if any,of these fore-
casts they should take seriously in planning new electrical
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generating facilities for the Railbelt.If a rational
decision is ever to be made,in other words,somebody
ultimately must (1)make an implicit or explicit judgment
which scenario describes Alaska's future most plausibly,and
(2)be prepared for that judgment to turn out quite wrong.
In our judgment the most likely scenarios for the
state's future are ones that no recent power demand forecast
(including ISER's 1976 study)has even mentioned,let alone
formally considered:scenarios in which no combination of
existing and new basic industries can equal or replace
government revenues from Prudhoe Bay oil and gas as a source
of Alaska income and employment.In these scenarios,the
inevitable decline in Prudhoe Bay production will mean that
the Railbelt's business activity,employment,population ---
and electricity demand ---will peak in the late 1980's or
early 1990's,and fall sharply for at least several years.
We do not expect the Alaska Power Authority to agree
with our judgment that this is the most probable course for
Railbelt electricity demand,but it is vital for power
planners in Alaska to recognize that it is a wholly plausi-
ble course,and to consider the implications for the State
of a decision to build Susitna if power demand did actually
begin to decline at just about the time the project was
completed.
It would be a relatively simple matter for ISER to add
one or more boom-and-bust scenarios to the demand forecasts
if such scenarios are not already part of ISER I S program.
Our more serious concern is that the Study Plan does not
seem to deal systematically with any kind of uncertainty or
risk (demand forecasting errors,delay or non-completion
risks,construction cost overruns,uncertainties regard ing
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the availability of alternative fuels,or interest rates and
other financial risks)in choosing among different strate-
gies for providing electricity to the Railbelt.
For~~~~t~~-Eeak loads and load duration curves.
The amount of generating capacity a region requires in a
given year stems directly from (1)the need to meet the
highest anticipated peak load for the year,and (2)the need
for sufficient reserve capacity to serve unanticipated
peaks,while allowing for scheduled and unscheduled equip-
ment outages.Estimates of total annual requirements for
electrical energy by themselves reveal very little about
the need for peaking and reserve generating capaci ty.
A utility's total energy demand and its peak demand are
both functions of population,per capita income,cl imate,
the regional industrial mix,and the like.Its load factor
the ratio between the average annual demand for electri-
cal energy and the annual peak load ---also depends on all
of these variables,and moreover,can be powerfully influ-
enced by the utility's rate structure,and by various "load
management"measures.While the Study Plan discusses a
number of arcane theoretical issues in the forecasting of
load duration curves,the meager funding for this subtask
impl ies that Woodward-Clyde must der ive its peak load
forecasts and load duration curves from ISER's projections
of annual demand for electrical energy,on the apparent (and
unwarranted)assumption that peak loads and load patterns
are are a reI ati vely simple function of total demand.
The total annual dema~d for electrical energy can
always be derived from a load duration curve,but Woodward-
Clyde will not be able to make forecasts of future load
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duration curves or peak loads consistent with ISER's assump-
tions without working from the original data and methodology
for each of ISER's scenarios ---in other words,without
repeating ISER's work and adding new analyses to it.But
the Acres study plan provides only $43,700 for this effort.
No credible forecast can be produced for this sum,and we do
not believe that any credible firm would offer to produce
one for this amount.
Peak-resE2n~ibilitY-Eri£in~andload 'management.
Peak-responsibility pricing and other techniques of load
management can reduce costly peak loads,enhance the opera-
t ing eff i c iency of base-load generating capac i ty,and
provide a partial substitute for reserve generating capa-
city.While these measures are relatively novel in the
Uni ted States,European experience suggests that they can
reduce the need for total generating capacity by 20 to 30
percent,and thereby postpone the need for new investment
for several years.
Concei vably,peak-responsibil i ty pricing and load
management might eliminate any need in the forseeable future
for new large-scale generating facilities to serve the
Railbel t,and at the same time spare consumers large rate
increases necessary to help finance new construction.
Federal law now requires utilities and the federal and state
agencies that regulate them to consider such measures,and
the failure of the Susitna planning process to give them
sufficient attention could,at the very least,jeopardize or
delay the project's ultimate approval.The Acres plan does
consider rate design and load management,under the heading
of "non-hydro al ternati ves,"but as with peak-load fore-
casting,their placement and funding level suggest that they
are being treated only as an afterthought or parenthesis,
rather than as central issues in assessing the need for new
generating capacity.
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..
Selection of new generating facilities.
Acres plans to combine the ISER and Woodward-Clyde
demand forecasts with exist ing capital and operating cost
estimates for various power alternatives (but not,apparent-
ly,for Susitna itself),by means of a mathematical model
that will "determine the total system costs of
selected future Railbelt expansion sequences,both with and
without incorporation of the Susitna Hydroelectric Project,
and rank the preferred generation expansion scenarios •••n
according to the cost of electricity.
The program Acres has selected for choosing among the
various generation strategies would combine ..•system
reliability evaluation,operations cost estimation,and
investment cost estimation."Even the most sophisticated,
state-of-the art planning model of this type would be
wasted,however,on the incomplete or questionaable infor-
mation inputs Acres intends to process.In the context of
the current study plan,therefore,the model's output will
be of little use to the state in making an informed decision
on Sus i tna.The fact that Acres plans to spend only one-
tenth of one percent of the project budget ($30,000)for the
systemat ic compar ison of generation al ternati ves is a
dramatic signal of the contractor's lack of regard for the
entire power alternatives study task.
Financial Feasibility.
As we pointed out earlier,the current Acres plan would
begin to consider the marketability of Sustina power and
the project's financial feasibility only after the Power
Authority had made its decision whether or not to proceed.
Even so,the plan's approach to financing is based upon two
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assumptions that are doubtful at best and which,in any
case,warrant a close and early examination.The first is
that the Susitna project can be financed by revenue bonds
(preferably tax-exempt),and the second is that the electric
utilities of the Railbelt will voluntarily enter into
full-cost-of-service take-or-pay contracts for Susitna power
with the Alaska Power Authority.
In recent years,a substantial number of electrical
generation projects (fossil-fueled and hydro,as well as
nuclear)have foundered in mid-construction because of
design faults,poor management,revised demand forecasts,or
legal and regulatory hurdles.It is not surprising,there-
fore,that financial institutions are reluctant to buy bonds
whose only security is project revenue.There has never
actually been any utility venture as large as the-Susitna
project whose construction has been project-financed entire-
ly,or even as much as 75 percent,with non-recourse debt
(that is,with revenue bonds).While there have been many
attempts at such financings,sponsors in each case have had
to choose between pledg ing their "full faith and cred it II
(that is,by selling general obligation bonds),finding
third-party guarantors,or abandoning the project.This has
been the case even for projects of proved design in familiar
environments,facing guaranteed markets.
Rightly or wrongly,lenders are bound to perceive the
Susitna project as bearing even greater risks of non-comple-
tion,extended delays,cost overruns,or market deficiencies
than the Lower-48 projects they have already decl ined to
finance on a non-recourse basis.Moreover,since Salomon
Brothers first reported to the state on possible methods of
project financing·for the susitna proposal,inflation has
severely damaged the bond markets~and unless economic
-94-
91
conditions improve radically between now and the time a
Susitna financial plan is completed,debt in the quantities
it requires may be unavailable at any price,on any terms.
Thus,it is very I ikely that the state will be faced
with the choice between financing Susitna with a direct
appropriation,guaranteeing the project's bonds,or compel-
ling Railbelt power consumers to begin paying for Susitna's
enormous capital costs in their electric bills many years
before they receive any power from the project.It is
probably imprudent to count on selling revenue bonds as the
principal means of financing Susitna and even more imprudent
to assume that the costs or availability of financing will
not influence the project's viability or merits.Although
we are considering a facility project whose completion is at
least ten years away,the feasibility of project financing
may indeed be an important consideration in choosing a
power supply strategy for the Railbelt.
Marketability.
The second assumption,concerning the utilities'will-
ingness to enter into take-or-pay contracts,should not be
taken as given.Railbelt utilities are not a single
entity,and unless the legislature is willing to impose
Susi tna power on reluctant utilities and their customers,
the Alaska Power Authority will have to negotiate individual
contracts with each utility.Non-recourse financing,
moreover,would require all-events contracts (compelling
consumers to pay for Susi tna whether or not they ever got
Susitna power,and no matter how much it turned out to cost)
prior to construction.Since Susitna power is likely to be
more expensive than conventional Railbelt power generation,
at least at the outset,the Power Authority could face a
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buyer's market,especially if gas prices remain relatively
low or if Beluga coal development proves economically
feasible.
Chugach Electric Association is by far the biggest
electric utility in the Railbelt,and its service area
together with the service areas of its wholesale customers
encompasses the region in which most of the future growth of
population and power demand in Alaska is likely to occur.
Susitna power mayor may not be the lowest-cost alternative
for Chugach customers,but it is very likely that,absent
Chugach and its customers,Susitna power will not be market-
able or financ ially feasi ble and that,as a result of ·the
project's underutilization,it would not be the lowest-cost
alternative for anybody.
Chugach Electric Association has not thus far been an
enthusiastic backer of the Susitna project,and its manage-
ment is not now convinced that Susitna power is the lowest-
cost or most practical way of serving its customers ---who
are the owners of the utility and elect its management.
Curiously,these realities have not yet been mentioned in
any of the public literature on the feasibility of Susitna,
and it is not alluded to even indirectly in the Acres plan
of study.
Study findings,incentives,and credibility.
The Plan of Study does not explicitly presume that the
Susitna project is feasible,and its introduction explicitly
rejects any such presumption.The substance and sequence of
work tasks,however,strongly imply that Acres and possibly
the Power Authority have already decided that Susitna
is in fact the best generation alternative for the Railbelt,
and that the project should go ahead.
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Clearly,the $13.5 million already spent on the study
at the time the power al ternati ves report is issued will
create substantial momentum for the contractor and sub-
contractors to complete their work in progress.Even more
importantly,the $16.1 million remaining to be spent if and
only if the initial go/no-go decision is affirmative cannot
help but be a powerful incentive for the study team to
arrive at a favorable conclusion.
The current study plan1s treatment of economic,finan-
cial,and inst i tutional issues is consistently inadequate,
and it does not provide the funding necessary for timely
and professionally competent demand forecasts,cost and risk
analyses,or studies of marketing and rate design,reI i-
ability and load management,or financial feasibility.
The Acres plan apparently does not even intend that its
cost,risk,and scheduling analyses,or its study of market-
ing and financing,be used for decision-making in Alaska.
The place of these studies in the project schedule,and the
language of the Plan itself,state implicitly and explicitly
that the main or only reason for including the studies is
the fact that FERC requires them as part of a power facility
license application.
This strategy,if endorsed by the Power Authority,the
governor,and the legislature,means that Alaska is wifling
to postpone any realistic and credible analysis of Susit-
na I s feasibility to the FERC licensing proceeding,and to
delegate the real go/no-go decision on Susitna to FERC and
other federal agencies.
As it approaches construction,the Susitna project will
become more rather than less controversial.It will arouse
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controversy within the state's utility industry,in the
legislature,and among the publ ic at large;before FERC,
EPA,and other federal agencies involved in the licensing
process,and possibly in the Congress;and it will be
controversial at best in the financial community.If the
project is indeed the best alternative for the Railbelt,
an ,inadequate information-base or patently biased decision-
making process at the state level will hinder rather than
speed the federal review process,and it will not make
ultimate approval any more likely.On the other hand,if
the project is unsound,Alaskans ought to find out earlier
rather than later,and in a study process that they control,
rather than in adversary proceedings before federal regula-
tory bodies.
The established philosophy of Alaska's capital budget-
ing procedures is that planning,and particularly the
projection of capital needs,can be objective and rational
only if they are independent of the parties that have a
material interest in construction.The legislation that
established the Alaska Power Authority explicitly set out
such a procedure,placing the responsibility for power
facil i ties planning in the Department of Commerce and
Economic Development,and requiring a thorough executive-
branch review of any major power project the Power Authority
proposes for legislative approval.
The current study plan and decision-making schedule for
the Susitna project are quite inconsistent with this philo-
sophy •.The Division of Energy and Power Development in the
Department of Commerce and Economic Development has appar-
ently not yet attempted to assert the role the legislature
contemplated for it,and the division's staff and funding
-98-
'.
have in any case been inadequate for that role.As a
result,forecasting and planning responsibilities have
fallen by default to the one party the legislature intended
should not bear them ---the Power Authority.And the Power
Authority has,through the Acres contract,delegated these
responsibilities to a consultant group that has a compel-
ling material interest in approval of the Susitna project.
Under the present plan,the Governor is scheduled to
make his recommendation to the legislature in late 1980
whether to concentrate the state's effort on Susitna or on
some other alternative.There is now a serious danger that
the information available at that time will not be (or
appear to be)objective,credible,or even wholly relevant
to informed decision-making on this issue.
Recommendations.
We therefore recommend four major changes in the Study
Plan and decision schedule:
A.Decision date.The initial go/no-go decision
should be delayed until about the end of 1981.There is
virtually no possibility that sufficient information will be
available for an informed decision before that time.This
recommendation does not mean that study tasks currently
scheduled by Acres for 1981 should be postponed until the
later decision date,but only that neither Susi tna nor any
of its plausible alternatives should be rejected before that
date.
B.Divorcement of forec~~tin~_a~an~lysis-irom
construction design and management.The combination of
demand forecasts and analyses of power alternatives into a
facilities investment strategy should be directed by,and
responsible to,someone other than Acres or the Power
Authority.
-99-
The location and administration of these studies for
bookkeeping purposes is not at issue,nor is the need for
the contractors to coordinate their assumptions and method-
ology with Acres and its subcontractors.In the absence of
an establ ished power planning capabil i ty anywhere else in
state government,timely attention to the issues identified
in this report proqably demands a continuity of effort that
can be achieved only within the framework of the existing
Acres contract,but the Plan should be restructured so that
the analysis of generation alternatives,and the input to
that analysis,is more independent of the Power Authority
and Acres,both in fact and in appearance.
One way of achieving this independence might be for the
Power Authority to contract (or Acres to subcontract)
management of an expanded "power studies"phase to a consul-
tant firm that has no other role in the study,and for that
firm to be responsible for its assumptions,methodology,and
results to an interdepartmental task force in the executive
branch or to a joint executive-legislative task force,
rather than to Acres or the Power Authority.
c.Scope and funding of power studies.The "power
studies"phase of the Susitna feasiblity study needs to be
expanded in scope and fund ing,at the same time as it is
extended and made more independent of entities that have a
material stake in the st udy outcome.The following recom-
mendations for additional time and funding are little more
than preliminary,intuitive estimates,but we offer them in
order to ind icate the shift in emphas is we bel ieve is
necessary to an adequate,objective study plan:
1.Total and peak loads,and load duration curves,
must be derived in a single coordinated effort,and
-100-
$
must explicitly take into account the potential
impact of peak-responsibility pricing and load
management on the need for peak and reserve gene-
rating capacity.A credible effort would require
at least $250,000 and one year.
2.Preliminary cost,risk,and scheduling analyses for
alternative Susitna scenarios should be available
as inputs to the decision on generating strategy.
These preliminary analyses would cost at least
$300,000,and require one year.
3.Cost,risk,and schedul ing analyses for the most
promising alternatives to Susitna identified at.in
the initial study phase should be "as thorough and
reliable as those for Susitna itself.At least
$150,000 and six months would be necessary.
I
4.The potential of natural gas liquids and fuel-grade
methanol as turbine or boiler fuel should be added
to the list of generation alternatives to be
studied.Initial consideration of these al terna-
tives (at least sufficient to determine whether or
not to reject them summarily)would cost about
$30,000.
5.Prel iminary marketing and financial analyses are
necessary as inputs to the demand,cost,risk,and,
scheduling studies,and to any practical decision
regarding Susitna.The cost of these studies would
probably be about $75,000 over six months.
6.A multidisciplinary panel of contractor,subcon-
tractor,agency and outside experts should examine
and reexamine the major assumptions used in the
demand,cost,risk,scheduling,marketing,and
f inanc ing st ud ie s •The views 0 f the se experts
should be translated into probability distributions
and systematically incorporated into the assump-
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tions by means of "Delphi"or comparable methods.
This process would cost on the order of $75,000,
and run concurrently with the other studies men-
tioned here.
7.The program used to rank expansion strateg ies for
Railbelt electrical generating capacity should take
account of all of the information generated in the
power studies,and should be operable within a
"Monte Carlo"framework so that its results can be
expressed in terms of probabilities.Operating a
state-of-the-art power planning model with the
information described here would cost at least
$100,000.
8.The results of the decision model should be "run
backward"through the process that led to those
results.That is,those strategies that the model
identifies as having the greatest expected net
benefit,or having the greatest benefit in the most
likely scenario,should be analyzed under other
plausible assumptions in order to compare (say)the
consequences of not build ing Susi tna if it turned
out to be "needed",with the consequence s 0 f
building the facility if its power turned out to be
unmarketable.The costs of this process are
incorporated in the previous figures,which total
(at minimum)$980,000.
9.Because circumstances and knowledge about the
Susitna project and its alternatives will change
substantially during the overall study period,all
of the assumptions,methods,and results of the
preliminary study phase should be reevaluated and
updated before any construction actually takes
place.This process is likely to cost about
one-fourth the original studies,or $250,000.
-102-
D.Fallback strategy.It is likely that the Alaska
Power Authority,the governor,and the legislature will
choose Susitna hydropower over other Railbel t generating
al ternatives at each decision point in the present study
schedule.The proj ect may nevertheless fail to obtain a
federal license,sales contracts with Railbelt utilities,or
financing on terms that are acceptable to Railbelt con-
sumers or Alaska voters.Even wi th a license,sales
contracts,and financing commitments,actual construction or
operation may be delayed indefinitely by regulatory inde-
cision or litigation.For this reason,the state and the
utilities of the Railbelt should always keep alive one or
more fallback strategies that involve smaller fixed invest-
ments and shorter lead-times.The study of alternatives,in
other words,should never be totally given up.
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ALASKA POWER AUTHORITY
333 WEST 4th AVENUE·SUITE 31 -ANCHORAGE,ALASKA 99501
May 2,1980
Phone:(907)277-7641
(907)276-2715
Mr.Arlon R.Tussing
Arlon R.Tussing &Associates,Inc.
2720 Rainier Bank Tower
Seattle,Washington 98101
Dear Mr.Tussing:
We have had the opportunity to examine your review draft entitled
"S us itna Hydropower:A Review of the Issues ll and appreciate the opportunity
to offer our comments before your preparation of the final version.In this
response we initially summarize the purpose of the Susitna Plan of Study
CPOS}and discuss its intended philosophy.This is followed by a discussion
of some speciftc issues raised in your Report.
The Susitna Plan of Study is a dynamic document which has been and will
continue to be modified and expanded as the concerns and needs of various
a·gencies and the general public become known.There are obviously a number
of courses of action which the Power Authority and the utilities might take
over the next decade to meet the future electric power needs of the Railbelt
Region.As presently conceived,the Susitna POS embodies but one of these
courses of action.The scope of work will:
-establish the criteria by wbich the technical,economic,financial and
environmental feasibility of the Susitna Project should be measured;
-assess whether Sus1tna or some other alternative future Railbelt generati.on
expansion plan satisfies such e-riteria;and finally,
-if such criteria are satisfied,pursue the FERC licensing of the Project.
In.other wo.rds,the st~dy will establ ish whether theSusitna development
is appropriate and if so,how best to proceed with that development.
The POS has since its inception undergone a continuing process of
evolution in ·satisfying the overall objectives.At the same time,provision
has been made for ta pping the input of those concerned through revi ews ,
publ ic meetings and the action list.As a result,the scope and direction of
the Susitnastudy may be changed at any time or the study even terminated,
should the evidence indicate that some other course of action snould be
pursued instead.
Your Report constitutes probably the mos·t detailed assessment yet made
of the POSt and is welcomed as a positive contribution to the development of
an acceptable course of action.By and large,it is well prepared,thought-
ful,and well written,but a significant flaw is its p.reoccapation with
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Mr.Arlon R.Tussing
Page Two
May 2,1980
making explicit judgements about the Project before all the evidence is in.
Many of the comments may prove to be valid,but until studied,cannot be
verified.More specific comments follow.
1.The Report seems to be based on a misunderstanding of the Go/No Go
decision points.In the POS there are essentially three such decision
points.During the proposed 30-month study period,each of these
decision points relate to "continue-to-study"or "not-continue",rather
than "build the project".We wholeheartedly agree with you that a
project as large as Susitna requires extensive study and cost expendi-
tures to fully determine whether it is the appropriate course of action.
In our judgement and that of Acres,a 30-month period and at least a $30
million expenditure is necessary for a license application decision to
be made which adequately considers all issues involved.Nevertheless,
it would clearly not be cost effective to defer an obvious No-Go decision
until the end of the 3D-month period.The Power Authority has not only
fiscal responsibility,but also cannot delay its power generation expansion
planning activities for that long.The first Go/No Go decision in early
1981 will consequently be made on the basis of an initial comparison of
alternathes essentially based on available information and considerable
well-informed judgement.
There is no question that,with the constraints imposed on data collection,
load forecasting,alternative energy studies,etc.,it will be difficult
enough to make the decision whether or not to proceed with the study
within one year;it would be entirely impractical and imprudent to make
the much more profound decision regarding whether or not to build at
that time,unless some overWhelming factor(s)intervene (either for or
.gainst}.
Nowhere does the pas propose that IIWoodward-Clyde will derive •••load
duration curves from ISER's projections".The first paragraph of Page
5-11 of the POS states that vari ous recogni zed methodo 1o'gi es and thei r
applicability will be studied for the problem at hand.
Contrary to the assertion that peak load pricing is not mentioned in thepas,Subtask 1:03 has load management activities as an integral part.
In response to your concern regarding the lack of some sort of probability
assessment for ISER's scenar1'os,it should be noted that the ISER contract
calls for an evaluation of n •••the probability of each of the pro-
jections generated •.•11.
5.Your Report presents a useful overview of the planned Susitna hydro-
electric project in relation to likely future developments and economic
trends in Alaska's Railbelt Region.In this regard,however,the Report
seems biased towards a general scenario whtchsees preferential pricing'
of natural gas continuing into the next century and a resource-depletion-
led slow-down in the mid 1990's.This bias strongly influences the
arguments presented in relation to the marketability of Susitna power
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Mr.Arlon R.Tussing
Page Three
May 2,1980
and energy.Further,the Report seems to view Susitna hydroelectric
development as a single project coming into operation all at once.In
fact,the present proposal is for a two stage development phased to meet
market area requirements,and we are pursuing studies to assess the
possibility of more numerous smaller stages.While there is some support
for the cautionary attitude regarding competitiveness of Beluga coal and
'other alternatives,the situation regarding these must certainly be
taken at the time as "not proven"..The l~vel of relative competitiveness
with Susitna hydroelectric power production will be only partially
established one year from now when the decision is taken whether or not
to proceed with the study (let alone the project).
The lack of support for Susitna development from the management of
Chugach Electric is readily acknowledged,but Chugach can hardly be
expected to commit itself to the Project in advance of completed feasi-
bility studies.At the same time,it would be foolish to drop further
consideration of Susitna because Chugach has not committed itself;to do
so would be to accept a Catch-22 situation.Also overlooked in your
assessment of marketability is the opportunity to provide power to
industries which now produce their own power.Certain marketing arrange-
ments are conceivable that would induce the purchase of Susitna power to
the benefit of all Susitna power customers.
6:The content of Task 11 as proposed in the POS does not appear to be
properly understood.You state with emphasis that "Susitna I s viabil ity
will not be based on either its economic or financial feasibility".
This is incorrect.Task 11 requires incisive studies and reports on:
-M Possible Economic Limits to Project"
-1I0verrun Possibilities"
-"Security of Project Capital and Structure"
-"Evaluation of Alternative Markets of Susitna Output"
-Evaluation of Alternative Options for Meeting Railbelt Power Needs"
All of these are to be completed before the third Go/No Go decision
point and before a decision is made on SUbmitting the license application.
7.It is fully realized that one of the problems to be faced with a capital
intensive development such as a hydropower plant is that the cost of
service with the project in the system is likely to exceed the cost of
service ~out the project in the system for the first several years
(probably 8-10).Particular attention will be necessary to find ways
and means of alleviating the burden on Alaskan consumers in this century
of costs of service which will benefit the next generation.This is a
very major issue which will require review of a number of options and it
should not be readily assumed that past practices will prevail.
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•
•
In two places in your report t the burden imposed on consumers by the
Construction Financing burden (AFUDC)is referred to.It is suggested
that the consumers will pay in advance for electricity they may not
receive for 10 years art in your words t "if ever".Capitalization of
AFUDC is yet another issue that will be exhaustively studied and treated
in the marketing and financing tasks.It is quite improper to assert at
this stage that IInon-recourse financing would require all-events contracts
com en in consumers to pay for Susitna whether or not they ever got
Sus tna Power and no matter how much it turned out to cost)prior to
construction".The statement is correct if the words in parenthesis are
omitted;but the inference with the words left in iS t to say the least t
provocative and misleading.You may claim that under Alaska PUC rules
this has occurred in the past on other arrangements between wholesaler
and utility delivering to consumers,but it is a gross assumption that
it is necessarily to be the approach for Susitna.
In closing,I want to reiterate my sincere appreciation for your helpful
review of our Susitna Plan of Study.While I believe there were a number of
inaccuracies or misunderstandings in the review draft,there were also a
number of very worthwhile suggestions.A revised plan of study has already
been prepared and presented to the Legislature and to the Administration for
their consideration.If approved and funded,I think it will be extremely
responsive to your recommendations.
Sincerely,
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Eric P.'-Youl d
Executive Director
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