HomeMy WebLinkAboutBay of Fundy Reassessment 1977I ,.
.
REASSESSMENT
of
FUNDY TIDAL
POWER
BAY OF FUNDY TIDAL POWER REVIEW BOARD
NOVEMBER, 1977
The Honourable Alastair Gillespie,
Minister of Energy, Mines and Resources
The Honourable Gerald A. Regan,
Premier of Nova Scotia
The Honourable Richard B. Hatfield,
Premier of New Brunswick
Gentlemen:
December 2, 1977
We are pleased to advise that the investigations authorized
under the terms of your agreement dated December 3, 1975, have now
been completed. Our report, describing the principal aspects of
these investigations, together with our conclusions and recommendations,
is attached.
The report of the Management Committee, providing a fully
detailed technical description of the work undertaken and the results
thereof, is now in the printing stage. It has been reviewed and
accepted by the Board and will be forwarded when printed.
All phases of our work have been marked by excellent co-
operation between the agencies of the three governments, consultants,
other organizations and individuals who have been involved in the
investigations. Our ability to provide a firm assessment of the
viability of exploiting the energy of the Fundy tides owes much
to their interest and cooperation.
Respectfully submitted,
For Canada For Nova Scotia For New Brunswick
f~or:r~~~
E.W. Humphrys L.F. Kirkpatrick
/~~/'~~~
A. E. Collin R.B. Cameron Thompson
REASSESSMENT
of
FUNDY TIDAL
POWER
BAY OF FUNDY TIDAL POWER REVIEW BOARD
NOVEMBER, 1977
Contents
INTRODUCTION ........... ..
SUMMARY AND CONCLUSIONS
RECOMMENDATIONS ....
APPROACH TO THE STUDY ..
THE TIDAL PLANT ............. .
1
5
11
. ................. 13
. .................... 14
UTILITY SYSTEMS ABSORPTION OF TIDAL ENERGY ... . ....... 24
ECONOMIC FEASIBILITY
SENSITIVITY ANALYSIS ..
FINANCIAL ANALYSIS ....
SOCIO-ECONOMIC AND ENVIRONMENTAL
CONSIDERATIONS ..................... .
ANNEX A: TERMS OF REFERENCE .
ANNEX B: PHASE II, PRE-INVESTMENT DESIGN
PROGRAM ......................................................... .
32
37
41
······ 46
. ............ 49
··················· 56
THE ENERGY SITUATION
1
Introduction
Since the onset of the Industrial Revolution, civilization has
gradually grown remarkably dependent upon geologically-stored
sources of energy; not only for its pleasures and comforts, but
even for survival at present population levels. This period has
brought about an exponentially-increasing use, enc ouraged by
stable or gradually declining real prices, and supported by an
increasing availability of energy resources. An expandi ng tech-
nology has provided both the incentive and the means for exp-loit-
ing stored energy reserves. Cost and convenience dictated the
transfer of predominant use, first from wood to coal and, in this
century, from coal to oil and natural gas. Adequate supplies of
cheap energy came to be more or less taken for granted.
However, events of the present decade have led to a vastly
altered perception of the energy future. Concerns about atmos-
pheric pollution temporarily , at least, inhibited the use of some
fuels and caused greater consumption of petroleum products.
Other concerns delayed the development of nuclear resources.
Price stability vanished. It is now considered that recoverable
reserves of oil and gas could become insufficient to meet demand
in a few years or a few decades.* Security of energy supply and
the stabilization of costs have become urgent concerns. Renewable
resources have assumed added importance; not only because of
present economic pressures, but also because of a growing aware-
ness of the consequences to future generations of a policy of
continuing massive withdrawals from the dwindling patrimony
of traditional non-renewable energy resources.
Such concerns are perhaps more keenly felt in the Maritime
provinces , because of their relative scarc~ty of indigenous energy
resources, than elsewhere in Canada. Primary energy demand for
all purposes in the Atlantic Provinces exceeds 6.3 x 1014 British
* The meeting of the Governing Board of the International Energy Agency
in October 1977 chaired by the Honourable Alastair Gillespie, Minister of
Energy, Mines and Resources, concluded that ·~ .. unless present energy poli-
cies are strengthened there is a serious risk that as early as the 1980 's, the
world will not have sufficient oil and other forms of energy available and
that such a situation would have severe economic, social and political
consequences throughout the world." In addition, the Ministers " ... noted
that the current surplus of oil in the world market is a temporary condition
and could lead to ill-founded complacency ... " and expressed the d e ter-
mination" ... to reduce this risk by a strong concerted and sustained policy
response designed to make more effective use of energy resources ... and
to put more emphasis on development and use of less depletable energy
sources."
2
TERMS OF REFERENCE
thermal units (Btu) per year, (or 180 billion kilowatt hours (kWh)
per year) of which only about 10% derives from renewable hydro
resources, while the balance is made up from coal (6%) and im-
ported oil (84%). Excluding Newfoundland and Labrador, there
is relatively small potential for the development of indigenous
energy sources to reduce oil dependency. Nova Scotia's coal
output, recently averaging 1.6 million tons per year, (equivalent
to 0.41 x 1014 Btu), may be capable of significant expansion. New
Brunswick currently mines about 0.5 million tons per year
(equivalent to 0.13 x 1014 Btu) and it is not likely that output will
be expanded much beyond one million tons. About 1,500,000,000
kWh per year of additional hydroelectric energy potential has
been defined in New Brunswick. Offshore oil and gas exploration
has, as yet, met with only minor success.
Inputs to electric utility systems in the Maritimes total
14.2 x 109 kWh (equivalent to 1.4 x 1014 Btu). Of this total, oil sup-
plies 48%, coal 12% and hydro 40%. These figures include hydro
energy imported to New Brunswick from Quebec but exclude
thermal inputs related to exports from New Brunswick to New
England. Nova Scotia's electrical utility production depends on
oil to an even greater extent than the Maritimes as a whole, ie.
62% in contrast with 48%.
The Fundy tides represent an unharnessed potential of
hundreds of billions of kilowatt hours per year-a continuously
renewable supply of energy. The large tidal ranges to be found
in the upper reaches of the Bay of Fundy with its unique physio-
graphic characteristics offer optimistic possibilities for harnessing
at least a portion of this energy. If it can be demonstrated that
a tidal power development is both economically feasible and
financially viable then the Maritime provinces could have a pollu-
tion-free and a relatively inflation-free contribution to their grow-
ing energy needs.
The tidal power resource of the Bay of Fundy has been the
subject of sporadic interest for over half a century and the object
of a number of investigations of successively greater scope and
intensity, culminating in the work of the Atlantic Tidal Power
Programming Board.* However, although its deve lopment has, in
general, been held technically feasible, economic justification
* "Feasibility of Tidal Power Development in the Bay of Fundy," Atlantic
Tidal Power Programming Board, October, 1969.
3
could not be established. Nevertheless, under the revolutionary
changes in energy economics brought about by the events of this
decade, implicit faith could no longer be placed in previous con-
clusions. Renewed interest in the possibility of developing energy
from the Fundy tides was both natural and appropriate.
Despite the fact that the period of energy stability had not come
to an end when the Atlantic Tidal Power Programming Board
(ATPPB) report was written in 1969, the authors envisaged, with
some prescience, that changes might occur. They recommended
additional studies in the event of significant changes in interest
rate, construction costs, conventional energy prices, or threatened
exhaustion of conventional supplies.
Significant changes did occur in both energy prices and supply
position within three years. Accordingly, the Bay of Fundy Tidal
Power Review Board, hereinafter referred to as the Board, was
created on February 29, 1972 by agreement among the Govern-
ments of Canada, Nova Scotia and New Brunswick. The Board
was directed inter alia to identify areas significant to the conclu-
sions of the 1969 report of the ATPPB which should be re-
examined in the light of current and projected conditions, and
to undertake or recommend procedures for re-examination.
After reviewing and updating ATPPB estimates of the cost
of tidal power development, examining certain marketing possi-
bilities and comparing the market value of tidal power with the
value of energy from fossil fuels, the Board concluded that the
relative economic merits had converged sufficiently to warrant
the undertaking of more comprehensive studies on a phased basis.
In this way, the investigation could be terminated if the results
of any phase indicated that tidal power could not become
competitive with alternate energy sources.
Subsequently, on December 3, 1975, the three governments
entered into an agreement directing the Board to carry out further
studies with the object of " ... providing a firm estimate of the
cost of tidal energy in relation to its alternatives, on which to
base a decision to proceed further with detailed investigations
and engineering design", and to report within two years.*
The agreement established a Management Committee, herein-
after referred to as the Committee, to carry out the studies under
the general direction of the Board. The agreement also authorized
* The full text of the Federal-Provincial Agreement, with its Amendment,
is presented in Annex A.
4
ACKNOWLEDGEMENTS
expenditure of up to $3,000,000 for the purposes of the
investigation. This amount was increased, through an amendment
dated June 24, 1977, to a total of $3,652,000 in order to provide
for additional investigations needed to enhance the reliability of
the estimates.
The Committee's studies, taking fully into account the new
energy perceptions and state-of-the-art technology, were com-
pleted within the time and cost agreements as revised. Its
technical report has been accepted by the Board.
Due to the various complicating factors which can impact on
energy economics of tidal power, including the large initial in-
vestment, the cyclical nature of energy production, and the lengthy
breakeven period, the Board was faced with a difficult, if not
unique, task in evaluating the economic and financial feasibility
of tidal power. The Board believes, however, that the sensitivity
analysis used in the study has provided a reasonable basis for
its conclusions and recommendations which are based on the
Committee's findings. The Board's report also highlights the
salient features of the Committee's report.
The Board acknowledges the outstanding service rendered by
the Management Committee and its Subcommittees and the Study
Co-ordinator. The assistance of the consultants, the participating
agencies and other organizations and individuals who contributed
to the knowledge and understanding of the problems associated
with Bay of Fundy tidal power development is also gratefully
acknow !edged.
ESTIMATE OF PROJECT
COSTS
ECONOMIC FEASIBILITY
5
Summary and Conclusions
Of the tidal power sites which would be capable of producing
significant amounts of energy, those at the mouths of Cumberland
Basin (Site A8), Cobequid Bay (Site B9) and Shepody Bay (Site
A6) wou ld provide the best prospects for development. The con-
struction of a tidal power plant at any of these sites would be
technically feasible. The use of "floated-in" caisson modules for
the powerhouse and sluiceway sections, for which foundation
conditions at these sites have been found to be suitable, would
lead to lower capital costs than conventional in situ construction
behind temporary cofferdams.
In common with hydroelectric plants, a tidal power develop-
ment would have a useful project life of about 75 years, and be
relatively free from inflationary cost increases over this period.
Firm estimates of the cost of tidal power developments in June
1976 dollars, as well as projected total in-service costs as of 1990,
for the most favourable sites to provide minimum "at-site " cost
of energy are:
Net Average Costs in $Million Projected
Site Plant Annual {June 1976 dollars) in-service
Capacity Output Tidal Transmiss ion Total costt
MW GWh Plant Link (1990)
Cobequid Bay (B9) 3800 12,653 3637 351 3988 9290
Shepody Bay (A6) 1550 4,533 2160 37 2197 -
Cumberland Basin
(A8) 1085 3,423 1197 37 1234 3120
t Projected total in-service costs assume, for the purposes of the study,
commissioning by 1990 and include escalation and interest during constr u c-
tion; development of Site A8 would require about seven years to complete
and that of Site B9 , about 11 years; in-service cost of A6 was not computed
since a development at this site is not economic.
Sites with potentials smaller than that for AB were found to
be uneconomic on the basis of preliminary comparisons. More-
over, sites having capacities significantly less than 1000 MW
would be of limited interest to the Maritime utilities within the
time frame considered.
Under the economic conditions expected to prevail up to and
beyond the end of this century, and based upon the likely expan-
sion programs of the power utilities of the Maritime provinces,
single basin schemes operated for maximum energy output would
6
offer the lowest unit costs of energy. The primary role for tidal
power is displacement of energy generated by thermal plants,
both fossil-fired and nuclear-fuelled. It would not decrease the
role of nuclear generation in meeting base load, but it would result
in a net elimination in the Maritime Integrated System* of oil-fired
thermal of some 350 MW for a project at Site B9.
Conclusion No.1: Tidal power, in its most economic role, would
displace fossil-fuelled energy production. Although a tidal plant
would eliminate some fossil-fuelled generation from the Maritime
utilities expansion programs, it would neither eliminate nor
reduce the need for nuclear generation.
As of 1990, fuel consumption by the Maritime utilities is es-
timated to be 8.3 million barrels of fuel oil and 3.8 million tons
of coal, annually. Since most of the energy displaced by tidal
for both Sites A6 and A8 would occur in the MIS, the tidal energy
from these sites could displace about one-half of the estimated
1990 oil consumption for thermal generation. The estimated fuel
savings from Site B9 are combined savings to the Maritime and
New England systems; the fuel savings to the Maritimes would
be proportionally greater than from Sites A6 or A8.
The annual fossil fuel consumptions displaced by tidal power
plants at Sites A6, A8 and B9 are estimated to be:
Sites
Fuel
A6 AB B9
Oil (millions of barrels) 4 3 12
Coal (millions of tons) 0.45 0.38 1.3
The Maritime Integrated System is inherently capable of
absorbing virtually all of the energy from sites with potentials
of from 1000 to 1500 MW. However, the energy output of sites
with larger potentials would necessarily depend to a greater extent
on export markets or require extensive retiming. Sites with po-
tentials larger than B9 could cause changes in tidal amplitudes on
the coast of the Gulf of Maine, of a magnitude that might be
* The Maritime Integrated System (MIS) has been defined as the combined
New Brunswick, Nova Scotia and Prince Edward Island power utilities for
the purpose of generation planning in this study.
FINANCIAL VIABILITY
7
significant in the design and operation of the plant. Such larger
sites are not considered by the Board to be attractive for develop-
ment in the period 1990 to 2010.
From a purely economic assessment of the conditions most
likely to prevail during the planning period, up to 2010, viz. an
intense * nuclear scenario, two per cent escalation of fuel prices
after 1990, a real interest rate of 4.75 per cent, a load growth
of slightly less than 7.2 per cent and export proceeds of 50 per
cent of the value of the power that is exported, the probable
benefit to cost ratios and associated breakeven periods for each
of the preferred sites are as follows:
Site B IC Breakeve n Bo t h S ites B9 and A8 are
Period economic but Site A6 is
B9 1.2 30-35 years uneconomic.
A8 1.2 30-35 years
A6 0 .9 non e
Conclusion No. 2: The reassessment has conclusively demon-
strated the fundamental economic feasibility of tidal power and
the technical and economic feasibility of its integration into the
projected generation supply systems of the Maritime Provinces.
Annual revenues required to support the actual year-to-year
development costs would make it very difficult, if not impossible,
for a utility or a group of utilities in the Maritime provinces to
justify a commitment to a tidal power development. The Maritime
provinces would also find it impossible to raise the capital re-
quired for an MIS expansion program with either tidal sites A8
or B9 and still maintain an "A " credit rating. Even though either
project is economic in the long term compared to alternatives,
each has a very high initial investment requiring a 30-to 35-year
period for the early year disadvantages to be completely compen-
sated by financial advantages. For example, a development at
Site A8 could raise consumer prices of electricity in the Maritime
provinces by about 15 per cent for the first few years of operation
but lower them for the remainder of the plant life; a development
at Site B9 could raise consumer prices of electricity to an even
* This scenario assumes the maximum economic uses of nuclear generation
within acceptable technical criteria and would lead to the lowest cost of
service in the MIS.
8
greater extent. A cost of service equivalent to that resulting
through optimal generation expansion without tidal power could
only be maintained by means of extra-provincial financial partici-
pation equivalent to one-third of the total capital investment for
the development of Site AB or three-quarters of the capital invest-
ment for Site B9.
Conclusion No. 3: Because the minimum investment would be
about $3 billion and because this would result in an inordinate
financial burden being placed upon utility customers in the early
years, financial feasibility of a tidal power plant would be condi-
tional upon substantial direct participation by governments which
would enable raising of the necessary capital and maintaining
the cost of service to utility customers at annual levels not
exceeding those which would be incurred by an optimal genera-
tion expansion program without tidal power.
MERITS OF TIDAL POWER In summary, the exploitation of tidal energy is attractive for
the following reasons:
(i) it would provide for exploitation of an indigenous resource
of renewable energy and through reduction of demand for
dwindling fossil fuel supplies conserve foreign exchange;
(ii) the characteristics of hydroelectric plants, viz. long plant
life and annual costs which are almost completely dependent
upon the magnitude of investment cost, apply also to tidal
power;
(iii) the costs of tidal energy can be expected to remain relatively
stable throughout plant life, whereas costs of thermal energy
can be expected to increase with the passage of time;
(iv) it would lead to a reduction of system generation costs in
the Maritimes over the project life compared to those which
would be incurred without tidal power;
(v) it would provide some measure of security against unfore-
seen escalation of generation costs;
(vi) it would lead to lower environmental pollution loading com-
pared to generation expansion programs without tidal
power;
(vii) it would place Canada in the forefront of a technology of
worldwide interest and offer an opportunity to develop
industrial capacity and technology applicable not only to
tidal power, but also to low-head hydroelectric develop-
SITE SELECTED
9
ments, which are of increasing interest and importance.
Based upon a preliminary review of such information as exists
and advice from federal and provincial environmental authorities
as well as a broad spectrum of other scientific sources it appears
there would not be any major environmental or social problems
which would prohibit development at any of the sites.
The Cumberland Basin Site (AB) would be the preferred can-
didate project for initial development for the following reasons:
(i) it is a joint site and affords an opportunity to equalize
benefits between New Brunswick and Nova Scotia;
(ii) an initial ranking of sites in order of merit from socio-
economic considerations would indicate a preference for
development of the Cumberland Basin site;
(iii) the project is the smallest of the three projects considered
potentially viable and would thus tend to minimize any
technical problems of introducing a new generation source
into the Maritime region electric supply;
(iv) it is the largest and most economical site for which system
benefits are at least 90 per cent derived from within the
Maritime Integrated System; moreover, adjustments, such
as retiming devices, within MIS can be foreseen which would
eliminate dependence on an export market for surplus
energy;
(v) the changes indicated from the tidal regime studies do not
suggest any measurable effects would be imposed beyond
the limits of Canadian jurisdiction;
(vi) the regime effects of development are considered to be less
likely to give rise to significant environmental impacts than
those imputed to developments at the other two sites;
(vii) the capital investment requirements for Site AB would
impose the least strain upon the borrowing capacities of
the Maritime utilities (while undoubtedly any tidal power
development may be perceived by North American financial
sources as involving the introduction of a new technology,
the smaller project would invoke the least risk);
(viii) the project is large enough to provide a substantial contribu-
tion to the energy requirements of the Maritime region as
soon as its development could be completed and, if in service
by 1990, would demonstrate the practicability of further
exploitation of tidal power at a time when it is contemplated
10
the rapidly increasing depletion of sources of oil may provide
additional incentives to development of indigenous renew-
able resources.
Pre-investment investigations and designs for Site A8 and
an assessment of the practicality of the sequential development
of further developments are likely to cost about $33 million, with
allowance for inflation. Such definitive designs will require a
minimum of three years to complete. A preliminary budget cover-
ing pre-investment design activities, assuming authorization to
proceed by mid-1978 and completion by mid-1981, is presented
in Annex B.
Conclusion No. 4: The results of the studies warrant proceeding
with detailed engineering, socio-economic and environmental
investigations and the financial planning expressed by Conclusion
No. 3 for the development of a tidal power project at the mouth
of Cumberland Basin.
11
Recommendations
1. It is recommended that funding be provided in 1978 to complete
detailed investigations and definitive designs, including de-
tailed specifications, for a single basin tidal power development
at Site A8 in Cumberland Basin.
These pre-investment design activities should be undertaken
in accordance with a schedule which would be consistent with
the earliest practicable in-service date subject to periodic
evaluations of results. Such activities should also include
appropriate ancillary studies to permit an assessment of the
feasibility of subsequent future developments at one or both
of Sites B9 and A6.
2. It is recommended that institutional arrangements be estab-
lished for execution of the detailed investigations and definitive
designs and which could also provide the appropriate basis
for the development phase.
3. It is recommended that immediate consideration be given to
the resolution of the financial constraints to developing tidal
power.
The solution, identifying government participation, should
facilitate the raising of the necessary capital and also provide
for maintaining the cost of services to utility customers in the
Maritime region at levels which would not exceed, on an annual
basis, the cost of service which would arise through an optimal
expansion of generation facilities without tidal power.
Approach to the Study
The Terms of Reference for the study set three
explicit requirements: a firm estimate of the cost of
tidal energy; an estimate of the cost of energy from
alternate sources; and a comparison between the two.
It is an implicit requirement that the costs to be com-
pared should be the lowest likely to be achievable in
a practical sense.
The cost-effective design of a tidal power plant is
a complex undertaking involving the selection of an
advantageous site; the selection of the appropriate
development concept; the determination of the opti-
mum sluice and turbine capacities; and the selection
of an appropriate operating strategy. The results must
be translated into sound civil. mechanical and electrical
designs. with construction methods capable of achiev-
ing closure of the barrage against exceptionally strong
tidal currents. Moreover, since the market value of the
output is influenced by the amount of energy produced,
the whole design must be responsive to system require-
ments in the region where the energy output is to be
marketed.
The nature of the demands imposed upon utility
systems, together with the economic characteristics and
technical limitations inherent in each type of genera-
tion, usually require the integration of more than one
type, particularly in the case of the Maritime provinces.
For this reason, it is unrealistic to make one-to-one
comparisons between tidal power and each single
alternative. Rather, the Committee has considered that
the alternatives are utility systems containing near-op-
timal mixes of generating sources from which tidal
power has been arbitrarily excluded and then arbi-
trarily included.
Recognizing the complexity of the problem set by
the Terms of Reference, the Committee brought to bear
upon it the skills of many disciplines. In addition to
the obvious scientific and engineering aspects of the
approach an adequately broad interpretation of costs
and benefits brought into question many economic,
social and biological aspects. Socio-economic and
environmental considerations have been reviewed in
a mainly qualitative sense, since their full quantifica-
tion goes beyond the present authority.
This assessment is described in two parts to ease
the understanding of these complex issues. The first
part deals with the selection of the better tidal plant
sites and the establishment of firm estimates of their
cost. The second part describes the systems analysis
13
to determine the viability of tidal developments as
renewable generation sources to serve the electric
needs of power utilities.
Comparisons of alternative systems have been
made both on an economic and on a financial basis.
The economic comparison measures relative long-term
costs and benefits from the point of view of the public
interest, while the financial comparison reveals the
funding requirements from the utility standpoint. In
other words, the economic comparison shows the rela-
tive costs as measured over the entire period of study
but does not include the actual comparison, on a year-
to-year basis, of the real annual costs that would apply
to energy production from the projects.
14
The Tidal Plant
Thr~ major elements of a tidal povver devdopment
include the tidal hanier, the tidal basin and a transmis-
sion link to the system grid. The barrier itself consists
of a powerhouse. a sluiceway and dyke connections
to the abutments of a natural embayment which, thus
separated from thr~ sea. forms a controlled tidal basin.
DEVELOPMENT SCHEMES
The absolute predictability of the tides. and hence
the head and flow available for use. is a significant
advantage in estimating long-term availability.
However, the lack of concurrence between thr) luna~
dominated tidal rhythm (which has a period of 24 hours
and 50 minutes) and the solar-dominated life stvle of
mankind, poses problems unique to large "scale
exploitation and the use of tidal energy. Literally
hundreds of ideas, some of them ingenious. have br~r~n
put forward from time to time for the capture of tidal
energy and its conversion into mer.hanical or electrical
form. These may he classified as schemes for utilizing
tidal currents. or for impounding water and utilizing
the head subsequently provided by the changing level
of the sea.
The economic drawbacks which have precluded
the use of tidal power throughout most of the modern
era stem essentially from the lmv concentrations of
energy available. Since the concentration is much lower
for typical currents than for typical heads, current
generators are at a hopeless disadvantage. Previous
evaluations of the more complex schemes have never
proven them to be economically attractive. The present
studies have confirmed that under economic conditions
expected to prevail up to and beyond the end of this
century, and the likely expansion programs of the
power systems of the Maritime provinces only single
basin schemes would attain feasibility. The present
investigation, therefore. concentrated on schemes with
a single tidal basin utilizing the tidal heads so created
and the conversion of the energy by means of modern
low-head hydraulic turbines. The basic operating
strategy of the studies has been to maximize energy
production for any given level of installation.
A single basin scheme consists of a headpond,
formed by a barrage or dam together with sluices for
filling or emptying the basin, turbines and generators.
Single-effect operation would entail filling the basin
SINGLE BASIN
Single-effect on Emptying
(b)
SiNGLE BASIN
Double Effect
Fig. 1. Single Basin Tidal Power Development, Single and
Double Effect Operation.
at high tide, holding the water until the falling sea level
creates a hr~ad, then passing \Vater through thr~ turbines
to generate electricity until the rising tide eliminates
the head. Usually the generation is from the basin to
the sea (on the ebb tide) to take advantage of the greater
volumes and higher heads in the upper level of the
basin. Double-effect operation vvould entail substan-
tially the same operating sequence. except that on the
Hood-tide. generation would also take place by filling
thr~ basin through the turbines. as opposed to the exclu-
sive use of sluices for this purpose, providing a second
period of generation on each tide. In both modes of
operation. the turbines could also be designed to oper-
ate as pumps to "over-fill" or "under-empty" the basin,
. .
Dd • 0
~ ; ~ i ~ c:
12 ..
T!IJ'\1 ( Mrl-)
s,nQhl eHecl Operohon en Emotyu;o
D ...
~ j;
e
' ' " ..
Totnl ( Htt)
Ooublt-effect Operot:on
-!ltcl•~•l
i
! .I .. " ..
• 0
fl ~~
:~
' I J ' .. " ..
--&Qt•fl '·~·· i••'" Pvtnp·'IQ)
Fig. 2. Single and Double Effect Operation Sequences.
...
...
thereby increasing the gcn(1rating head and extending
the period of generation. Sketches of singlr basin
schemes for both single-and double-effect operations
are shown in Fig. 1. The effects of such operations on
the water levels in the controlled basin and the periods
during which energy would he generated are illustrated
in Fig. 2.
In general. it has been found that single-basin
devdopments. installed and operat£:d for singlc-eff£1CI
ebb-11ow gcn£)ration. offer the greatest net system
savings. Although marginally less attractive.
single-basin developments installed for double-effect
operation could offer a greater capacity support to the
system and. more importantly. inherently offer th£:
flexibility to vary output to meet variations in prevail-
tEGEND
TIDAL POWER SITES-
INVESTIGATED
TIDAL POWER SITES
-SELECTED
0
15
ing cost differentials or other system conditions.
As modern electrical systems have expanded and
individual systems have become integralt~d and inter-
connected to adjacent systems. the inherent 11£:xibility
necessary to meet internal system dr~mands. as well
as providing support for external demands. provides
a basis for absorption of energy from an intermittent
generating source. particularly when the output is en-
tirely predictable in magnitude and time, such as from
a sing]() basin tidal power plant.
This understanding of system characteristics re-
moved the preoccupation of previous studir:s with at-
tempts to create an equivalence between a tidal power
plant and conventional sources of generation. Conse-
quently, the current studir:s were focussed on the
10 0 10 20 30 40 ... --SCALE IN KILOMETRES
Fig. 3. Bay of Fundy.
16
system aspr~cts of intr~grating the output of a tidal
generation plant into total system requirr~nwnts. and
have established the inherr~nt capability of tlw MIS to
absorb virtually all of the energy from a sitr~ with a
potential of the order of 1000 MW. The primar~· role
of tidal energy in the Maritimes would be in
displacement of energy from thermal plants. fired
either by coal or oil. and to a limited extent from
nuclear thermal plants.
SITE SELECTION
Initially, consideration was given to every site of
significant potential in the Canadian section of the
Fundy system. In total, 30 sites, some with alternate
alignments and construction approaches, were evalu-
ated in terms of approximate development cost and
output. Successive screenings, based upon progres-
sively more detailed evaluations, showed that sites
with potentials smaller than that for A8 would not be
economic. It was recognized also that tidal power
plants with installed capacities less than 1000 MW
would be of limited interest to the Maritime utilities
towards the end of the century. As a result of the
screening process, three sites were selected for further
study. These coincide with the selections made by
the ATPPB. This review of site selection was under-
taken in the event that differential changes in costs
during the intervening years might have altered the
relative attractiveness of various sites. The fact that
no changes were indicated infers that the superiority
of the selected sites is inherent and due to physio-
graphical factors. The sites, as shown on Fig. 3, arc:
Site A6-Shepody Bay, St. Mary's Point to Cape
Maringouin;
Site AS-Cumberland Basin, Pecks Point to Boss
Point;
Site B9-Minas Basin, Economy Point to Cape
Tenny.
These sites were subjected to more intensive study for
the development of firm cost estimates and as a basis
for the power systems analyses and the economic and
financial analyses.
TIDAL REGIME
The tides of the oceans are produced primarily by
variations in the gravitational attraction of the moon
and the sun. These forces are directed outward from
the centre of the earth and attain a maximum at the
time of both upper and lower transit of the moon. The
net tide-producing force is thus dependent upon the
relative positions of these bodies and the distance of
each from the earth. The tides themselves are responses
to the generating force and vary not only in conformity
with the intensity of the force from time to time, but
also from place to place. due to physiographic con-
ditions. Thus, the range of the tides in the headwaters
of the Bay of Fundy would be affected both by the
alteration of its physiography, implied by the construc-
tion of a barrage, and by the extraction of energy from
the tidal waters. Obviously. a firm estimate of the cost
of tidal power must be based upon the best possible
understanding of the tidal ranges likely to be available
after the construction and coincident with the opera-
tion of a tidal power plant.
The tides in the Bay of Fundy-Gulf of Maine system
are driven by the ocean tides impinging upon the
Continental Shelf at the entrance to the Gulf of Maine,
and not to any appreciable extent by direct action of
the tidal forces upon the waters of that system. No
measurements of the tides in the offshore areas of the
Gulf of Maine had ever been made, and previous pre-
dictive efforts were hampered by this lack of data.
Because of the importance of reliable tidal predic-
tions, the Committee instituted a program of data
collection both from the edge of the Continental Shelf
and at selected points within the Bay-Gulf system.
These data were used to calibrate and verify a hydro-
dynamic mathematical model embracing the whole of
the system. Its predictions of regime changes resulting
from the construction and operation of a tidal power
plant have been taken into account in assessing the
appropriate installation and operation of each site for
both single-effect and double-effect modes of opera-
tion.
Verification procedures have indicated that con-
fidence can be placed in the model results to within a
few centimetres of tidal range and a few minutes of
phase difference. In general, the model predicts a
minor reduction of tidal range due to the construction
of a barrage at economically favourable sites. Some
further reduction may accompany an increase in the
energy extracted. However, in areas of the Bay remote
from tidal plants and in the Gulf of Maine, an increase
of tidal range is predicted. Such changes are illustrated
for Site A8 in Fig. 4. Table 1 presents the computed
effects of the operation of tidal power developments at
..
..
17
TABLE 1
Computed Effects of Operation of Tidal Power Developments
on Tidal Ranges at Selected Locations (Ranges given in metres)
Natural Tide
Location Site
MT LT MT
A6 Site 10.1 13.1 9.6
AS Site 10.5 13.5 9.9
89 Site 12.4 15.S 12.3
St.John 6.7 s.s 6.7
Yarmouth 3.1 4.1 3.1
Boston 3.1 4.1 3.1
Notes: MT -mean tide L T -large tide
Sites A6, A8 and B9 on tidal ranges at selected locations
in the Bay of Fundy-Gulf of Maine system. These values
are considered to be accurate to ± 0.1 metre.
These effects u pan the tides tend to increase for
larger tidal developments and may impose a practical
economic limit on the amount of energy eventually
extractable from the headwaters of the Bay.
CONSTRUCTION METHODS
Recent advances in construction technology asso-
ciated with marine structures, including those success-
fully applied in the Netherlands Delta Plan and in
·>O ·20 ·•O 0 •o 20 ~ ., ·•o ., 0 ' •o "t.
l'fiOYIO[MCE PII()YIO[MC(
_N,S. SIDE _ N S SIDE ~
BOSTON _NBSIDE "'""" -• B SIDE
,......,., LIJIIE-.tRG
"""""" <f YARIIOUTH
s.AIIIITJ~ IMUt'f JOMN
) CAP£ o'OR CAP£ o'OR
! GIIINOSTOME GRIIIIDSTOME
SUMtCOAT ~AO BURIICOAT HIAD
SITE A8 -AMPLITUDE CHANGE (em) SITE A8 -AMPLITUDE CHANGE (%)
Fig. 4. Regimen Effects for Development at Site AS.
A6
Tidal Developments at
I Site AS I Site 89
LT MT LT MT LT
12.5 9.S 12.7 10.6 13.7
12.9 9.S 12.S 10.9 14.1
15.7 12.3 15.S ll.S 15.2
s.s 6.7 6.S 7.1 9.2
4.2 3.1 4.1 3.2 4.3
4.2 3.1 4.1 3.3 4.4
development of offshore oil installations in the North
Sea, have indicated the practicability of constructing
the powerhouse and sluiceway elements of a tidal
power plant as floated-in caissons. This concept is
estimated to be less costly than construction in situ
behind cofferdams*, as well as affording an oppor-
tunity for a wider distribution of construction bene-
fits and a reduction of adverse local social impacts.
The method envisaged would involve installation
of sluice machinery and turbines in the caissons dur-
ing offsite construction, towage to the site, sinking
and ballasting the caissons in place on a prepared bed
of selected fill. Feasibility of the method hinges upon
load-bearing competency of the underlying strata. This
competency was confirmed by subsequent geophysical
exploration at Sites A8 and B9. A detailed drilling
program would, however, be required as a basis for
definitive design .
Practicality of the design concept has been con-
firmed to the extent possible by calculation, exper-
ience and limited modelling. However, extensive
physical modelling would be required, in the event of
a decision to proceed with definitive designs, to pro-
vide detailed solutions to construction scheduling and
strategy, as well as to resolve closure, scour, and em-
placement problems. Subject to these reservations, the
Board concurs that the proposed construction methods
are feasible and provide a reasonable basis for cost
estimates.
Typical powerhouse and sluice caissons are illus-
trated in Figs. 5 and 6, respectively.
* Cofferdams are temporary works erected to exclude water from
a construction site.
18
HALF PLAN AT HHWLT LEVEL
NOTES-
ALL ELEVATIONS ARE IN I\IETERS
AND ARE REFERRED TO 0 AT
ro AIO CLOSUit(
GEODETIC SURVEY OF CANAOA OATUM ( G SC 0)
HHWLT-HIGHER HIGH WATER, LARGE TIDES
LLWLT-LOWER LOW WATER, LARGE TIDES
BASIN
y aA$1111 L(V(L. -
~·ooo
OPJIIIGS TO J(T S.&JIO riLL
CJtAii( lUI!.
CAST lti !'lAC£ CLOt;.Mtl
tlAI SOO-THtCJt
CREST ELEV.:__I_Il~
OCEAN
------------------------------~H~H~W~L~T ELEV. 1.50
G.S.C.O. ELEV, 0.0
LlWLT ELEV. 6.93
PROTECTION
SIMILAR TO
OPPOSITE END
Fig. S. Powerhouse, Floated-In Caissons, Site A8-Single Effect.
..
HALF PLAN AT APPROX i OPENING
HALF PLAN AT HHWL T
MOTU-
lhiWLT • ~lt"U Hit" WATE~, LA~IE
TIOU
LLWLT-l.OWE~ LOW lMTIII, LA-TIDES
tit£ S T ( l IS 10
..__ UIS Si..A.I ll
I At ~000 • 40000 ~300
OSUR£ SLAt;$ 600 \T YP) AF'T[ff CLOSuRE SLABS ARE IN PLACE
P L A N
2~000 ,,.oo 10000
BASIN
:u!IOO
50500
liiO!Iiil!'!liJ'5il"!iiSi-..... -~~~~!io~~iiiiiiiiiiiit~O ..... -......... .....;'o ME T£1U
... GRAPH.C SCALf:
Fig. 6. Floated-In Sluiceway Caissons, Site AS -Single Effect.
PJtES!IJJt£ SYST£11
OCEAN
C 0 CISCO
tt..OW -
19
20
S ELEC TION OF E Q UIPMENT
Of the various types of low-head turbogenerators,
Kaplan or vertical shaft units were rejected on the
basis of higher total civil and mechanical costs. The
rim or flow-through type turbogenerator of innova-
tive design was not adopted because it is still under
development and because adequate cost and perform-
ance data were not available. As a result, bulb turbines
of the type used extensively in low-head hydro-
electric developments, and as installed in the La Rance
tidal generating station in France, were selected for
design purposes.
The turbine performance characteristics assumed
were derived from a survey of all existing and com-
mitted installations, while unit diameter, rated head
and number of units were determined by the optimiza-
tion methods described below.
OPTIMIZATION OF DE SIG N
The lowest unit cost of output was selected by the
Committee as the criterion for optimization. This
optimum occurs at some level of installed sluice and
25
22PH
~~v···~ 24
20 ,
.J: 24 ~
~ .....
IJ)
...J
...J
~ ........... 27 PH
I 23 )'..... .. 211 SL
turbine capacities between high and low levels for
the recovery of the energy in the tides. It is eco-
nomically practical to recover only a small part of the
natural energy available in the tides . Full recovery
would entail the installation of infinite capacity at
infinite cost. If, on the other hand, the installed capa-
city is too low, then the overhead costs represented by
the barrage lead to unacceptably high unit costs. The
outcome is also influenced by the turbine character-
istics.
The optimum installation for each selected site
was determined with the aid of mathematical models.
The method involved a large number of trials, for each
of which one parameter was systematically varied. For
each trial the model was also required to determine
and employ the operating procedure yielding highest
output. The output was then compared with the cost
of the facilities postulated in that particular trial to
determine the cost per unit output. Finally, synthesis
of the results indicated the required optimum com-
bination of turbine characteristics, sluice and turbine
capacity for each site. Figs. 7, 8 and 9 illustrate the
43 PH
~ I""' , .. /
·~ / _L ............ ,. ~~ ~IISl .. "
>-1.:>
0: w z w
Lo.
0
.....
Ill
0 u
w
~
Ill ..:.
ct
2 2
21
20
2000
0. 5 MILLS/o<Wt.
SANO
2500
PH -POWERHOUSE UN IT
SL -SLUICE UNIT
~.~r -........ ~
24
~ APPROXI MATE UPPER LIMIT
OF INSTALLATION TO MEET
ACCE PTA BL E CLOSURE CRITERIA
I
3000 3SOO
ANNUAL ENERGY GENERATED GW ...
Fig. 7 . Site AS -Optimization Curve, Single Effect Installation.
4000 4500
..
•
33 32 PH
40SL
~ .... ", ', 74 PH
..c
3= 32 -" ......
(/)
...1
...1
:i
r--...
....... , 64 PH
43PH :~ ' :/SA. 53 PH --__.___
-~ ;!5 ~ " -~~ -.> ~--~~----30 ........... __ ~
30" ---
-L0.5 MILLS/KWh
.,...
• 31 )-
(!) a: w :z w
.....
0 30
~
(/)
0
(.)
w BAND
!:::
(/) 29
t!-
<(
28
3000 3500 4000 4500 5000 5500
L
3:
.1€.
' V>
..J
..J
~
I
(';
a: w z ...,
Lo.
0
1-
V>
0 u
w
1-
V>
t!-
<[
PH -POWERHOUSE UNIT
SL -SLUICE UNIT
20
19 86 PH
....±...•o ?O ~ -
18
Lo.5 MILLS/KWh
BAND
17
16
ANNUAL ENERGY GENERATED GWh
Fig. 8. Site A6 -·Optimization Curve, Single Effect Installation.
96PH 106 PH 117 PH 128 PH
SL .
40
r--~54, _:;_ w •o 7051.. !10 10 TO 11051.. 50 60 70 ~SL ..... ----.I y APPROXIMATE U~PER LIMIT
OF INSTALLATION TO MEET
ACCEPTABLE CLOSURE CRITERIA~
40SL
10,000 11,000 12,000 13,000 14,000 15,000
PH-POWERHOUSE UNIT
SL -SLUICE UNIT
ANNUAL ENERGY GENERATED GWh
Fig. 9. Site 89 -Optimi~ation Curve, Single Effect Installation.
21
22
OREOG1NG DiSPOSAL
AREA \
PECKS POPiT
+20
+10
0
···ACCESS OIKE 1
~
ACC£$$
Ott<E CREST •
EL+l763M
CLA'r'H SILT AM)
SILTY CLAY TO
BE RE...OY£0
SilTY SANO WITH
sc.JlE GRAVEL AND ~
;~At~~~~5CLAYEY :
HORIZCJilTAL '?
0
VERTICAL
CUMBERLAND BASIN
CHIGNECTO BAY
P l A N
SKALE
SAHOOTONE
CLAY Stt.ALE
SLTSTONE
PROFILE
GRAPHIC ScAtES
I
SLUtCE*Y
I
I
I
i
I
I
I
\._SHALE
/
I I j
I I
I
/? I I
/ \ :>
' / BOSS POINT
I NOVA SCOTIA I I .\ TA.j 8
~ l87,190E ~ \ 5,~j430H .; ~-\, ..
"'
~ 8H-C8 If' 80REH0LE LOCATION
30 48 TOPOGRAPHIC CONTOuRS ,N METERS
~·25M--"' 8ATH'!'\4ETRIC CONTOl..IRS lN METERS
" SURVEY CONTR-OL ~T
9055 POINT
NOTES
l (LEVATIONS AREREFERREOTO GEODETIC SURVEY Of
CANADA OAru..-
2 SOUNDINGS ARE GIVEN IH METERS Afrf0 ARE R£LATtVE
fOG SCD
3 HWL REFERS TO HIGH HIGH W'ATER LARGE TIDE PLi...iS I 22M
L WL REFERS TO LOW LOW WATER LARGE TIDE MINUS 16M
COOiil'ruHATES ARE RELATE"O TO THE TEN Tt-OJSANO METER
UNIVERSAL TRANSV£RSE MERC)TQR GRID REF AMHERST 21 H
6 SEA-BEO CONTOORS HAVE BEEN INTERPOLAl£0 FROW
GEOPHYSICAL SURVEY t 1977)
1 POWERHOUSE ·· Wt0TH Of UNIT AS SHOWN
SLUICEWAY
TUR61NE 0lAMET£R 7 5 M
WIOT H Of SlUiC£ AS SHOWN
SLUICEWAY GAT£ 122M 11IZ 2M
80TH POWERHOUSES ANO SLUICEWAYS SHALL BE
COfCSTRUCT£0 IN a.IOOULES OF TWO UNITS, ONE SERVICE
a.A'f SHAll Bf PROYIOEO FO~ EVER¥ 16 POWERHOUSE UNIT$
9 ,JNSTALI...EO CAP!IlCITY 1$ NUMBER OF UNJTS TIMES 31 MW
9 THE SERVICE BAY IS hCORPORAT£0 WITH TWO GENERATING
UNITS IN A POWERHOUSE MODULE
10 THE LENGTH OF 01Jt[ REQUIRED FOR THE DRY OOCJC
{ACCESS DiKE) SHALL BE BUILT BY END DUMPING
THE BALANCE Of' THE Oil<[ SECT()N(CLOSURE Oft(£)
SHALL BE CONSTRUCTED IN HORIZONTAL LIFT FROtrll THE
SEA~S£0 USING h!IARINE TECHNIQUES
!I All n£ FOONOATION INFORMATION ON SlTf AS IS BAS£0
ON THE RESULT OF INVESTIGATIONS CAARI£.0 c.JT c.JRING
PHASE! SuPPLEMENTAL STUOY
12 SURfiCIAL DEPOSITS INCUOt.lG CLAYEY SILT ANC SUY CLAY,
00 NOT PRQvl()£ AOEQUAT£ FOUNDATION ~ htUST
BE R!~D
Fig. 10. Plan and Profile of Proposed Development for Cumberland Basin (Site A8).
TABLE 2
Summary of Characteristics and At-Site Costs
of Single-Effect Tidal Power Schemes
Item Units Site 89 Site AG Site AS
Total number of
generating units 101) 53 37
Total number of
sluices 60 30 24
Number of spare
generating units 6 3 2
Turbine diameter m 7.5 7.5 7.5
Generator rated
capacity MW. 38.0 31.0 31.0
Turbine rated bead m 7.5 6.5 6.5
Total installed
capacity MW. 4028. 1643. 1147.
Annual output kWhx108 12,653 4,533 3,423
Civil Works $X 10° 1,010 682 381
Mechanical and
Electrical SX108 1,010 514 337
Total direct costs SX108 2,020 1,196 718
Indirect and
contingency SX10" 964 479 _ ...... -.. _~
Total Capital cost $X 10 8 3,637 2,160 1,197
Annual cost
(5'h% int.) sx 10 8 227 135 75
At-site cost of energy mills/kWh 17.9 29.7 21.8
Note: All costs are in terms of June 1976 dollars.
final stages of the optimization procedure. and the
optimum at-site solutions for Sites A6, A8 and 89. The
optimization curves arc quite flat so that the installation
can vary significantly without changing the at-sit!~ unit
cost by more than 0.5 mills/kWh from the minimum.
Using the same models, with optimum levels of
installation and with due regard to the predicted tidal
ranges, a series of hourly outputs for the 705 tides of
a typical year was computed for each site and this in-
formation was used in subsequent systems absorption
and marketing studies.
The general arrangement of a tidal power develop-
ment is illustrated by Fig. 10 which presents the plan
and cross-sect ion at Site AB.
CAPITAL AND ANNUAL COSTS
The optimum installation was also used, in con-
junction with construction and unit equipment costs,
23
to estimate the capital cost associated with each de-
velopment. Allowances were added as follows:
Item
Indirect construction items:
Project management:
Owners expense:
Interest during construction:
Contingency allmvance:
10% of total direct cost.
lO'X, of total direct cost.
3% of total direct cost.
accumulated at real
interest rate according
to disbursement
schedules.
12.5'/(, of total direct
and indirect r:ost.
For the purpose of economic analysis, annual costs
were computed as amortization plus 0.621 p(~r cent for
operation and interim replacement. insurancE~ and
overhead. resulting in a value of 6.2:n per cent per
annum. Amortization was based on a 75 year life.
The base case was considered at a reo]* interest
rate of 5Vz'Yo, with parallel calculations at rates of 4%
and 7% to assess sensitivity to rate changes.
The optimum installation levels, costs and other
data relating to each selected site, derived from the
procedures described above, are presented in Table 2
for minimum at-site cost of energy.
* In the estimation of future costs and lwndits. thp conncpt of
reul interest was usr;d fur the economic portion of thPse in-
vestigations. Reo/ inten;st is defined. to a close approximation.
as the difference lwtwer;n the actual interest rate (taking into
account the borrower's credit rating. the risk involved, and other
related factors in the venture) and the mflation rate.
24
Utility Systems Absorption of Tidal Energy
The principal function of a power utility is to en-
sure that electric power is available to meet the load
demands of the system, that is, the energy require-
ments of its customers. The objective of the utility is
to carry out this function at minimum cost which re-
quires sound engineering planning.
Generating facilities required to meet the growing
load demands of major power utilities require large
capital expenditures, with decisions and approvals
to build such facilities made a decade or more in ad-
vance of the facility becoming available to the system.
The generating facilities must be optimum for the
system from the points of view of economy and flexi-
bility, at the time they contribute to system loads. In
addition, to ensure that the system loads are supplied
with adequate reliability and security, the system must
always carry reserve capacity for possible equipment
breakdown and scheduled maintenance.
Power utilities involve their entire systems in their
assessments of the economic, financial and technical
feasibility of incorporating additional generating
facilities. Accordingly, the Bay of Fundy tidal power
reassessment studies were pursued within this frame-
work. The methodology was developed with the full
cooperation of the pertinent utilities and is, therefore,
fully consistent with the accepted system planning
practices of the major eastern Canadian and north-
eastern United States power utilities.
There are four areas basic to a utility's planning
process: load forecasts: generation expansion plans;
economic evaluations of alternatives; and financial
evaluations of alternatives.
LOAD FORECASTS
Since, as stated previously, an electric utility ex-
ists to supply the power needs of its customers, it is
necessary that the probable future needs should form
the foundation for system planning. The priority
markets to be served by a tidal power development
would be those served by the Maritime Integrated
System (MIS) comprising the electrical utilities of New
Brunswick, Nova Scotia and Prince Edward Island.
Surplus tidal energy that may exist in the short and
intermediate term could be transmitted to contiguous
systems of Quebec and the northeastern United States.
The relationship of the potential markets to the se-
lected tidal power sites is illustrated by Fig. 11.
Fig. 11. Relationship of the Selected Tidal Power Projects
to Contiguous Market Areas.
, ... " .. " "'"" 2010 , ....
Fig. 12. Peak Demand (MW) in the Market Areas.
..
The load forecasts used for both the primary and
secondary markets for tidal energy were based on 1976
load forecast information and are displayed in Figs.
12 and 13. Fig. 12 shows the annual maximum firm
power demands, while Fig. 13 shows the corresponding
annual firm energy requirements.
The MIS system is expected to grow from 3200
MW and 18,000 GWh in 1980 to almost 23,000 MW
and 125,000 GWh by the year 2010. This corresponds
to an average rate of growth of the order of seven
per cent. although it is recognized that the ne\v energy
perceptions may lead to somewhat lower rates of
growth. The effect of the latter has been taken into
account in the analysis.
The expected growth rates for the Hydro-Quebec
system and the markets represented by the New Eng-
land Power Pool (NEPOOL) are 7.7% and 5.6% per
year, respectively. These two contiguous markets are
5 to 6 times larger than the MIS market and would
~ 70'1---------·········----+--~--+-----c;"'·-1--~---1----1
! eol--~-~~----~~~~~~~~-~~----~--~
10 .,L,"" __ _L,.~.,--_.1,.-..,---'-,,.-, __ .L2ooo---':.::::oo--:-, -.......J2o1o
YEAR
Fig. 13. Annual Energy Requirements in The Market
Areas.
25
offer the opportunity for energy sales surplus to the
latter. However, Fig. 12 suggests that the total load
growth of the MIS is expected to increase seven-fold
over the 30-year review period which is indicative of
the growth in potential capability of the MIS to ab-
sorb tidal energy.
SYSTEM EXPANSION PROGRAMS WITH AND
WITHOUT TIDAL POWER
As in the case of more conventional generating
sources, the determination of tidal development fea-
sibility required studies of the alternative generation
expansion programs. However, the intermittent output
from a tidal plant requires special attention in power
production scheduling. The output, although entirely
predictable many years in advance, follm-vs the lunar
cycle and hence can occur at predictable, but differ-
ent. times during successive nights and days. The
amount of tidal energy that can be utilized by any
system is thus related to that system's inherent retiming
capabilities. Moreover, the amount that can be ab-
sorbed is a function of the system size and load charac-
teristics, the rate at which the output from other gen-
erating units can be reduced or backed-off and dis-
placed by tidal generation as well as the rate at which
these units can be brought on line again when genera-
tion from the tidal plant has terminated. To evaluate
these aspects, computer models were developed with
the capability to simulate on an hour-by-hour economic
dispatch basis the operation of both conventional and
tidal generation.
These models were used firstly to determine
alternative plans for the expansion period 1986 to 2010,
which provided realistic mixtures of the types and sizes
of generation facilities, as well as associated capital
and energy production costs, needed to meet the fore-
cast load requirements without consideration of tidal
power. Generation programs were developed for the
provinces of New Brunswick, Nova Scotia and Prince
Edward Island based on the coordinated planning of
the MIS and for New England based on NEPOOL. The
probable future generation expansion programs for
Quebec were obtained from Hydro-Quebec and used
directly in the systems analysis.
Subsequently, representative small, medium and
large tidal plants were fed into the system modelling
process to determine when and how the output could
26
best be utilized in the MIS ;md export market systems.
and the resulting modifications of the generation
programs. Tidal energy absorbed \vithin the intercon-
nected svstems has the ctlect of displacing or reducing
a like an.wunt of conventional thermal energy produc-
tion within the svstems. A significant portion of the
value of tidal cnt:rgy can thus bt: m!~asured in tt:rms
of the amount of thermal energy displaced and its type
of fuel.
For tlw purposes of the analysis the expansion
period was assumed to start in 1986, when all com-
mittr~d gem:ration would be in seryice. and continue
to 2010. Studies relat!:d to the scheduling of construc-
tion indicatr:d that a tidal power plant at any one of
the selected sites could be brought into operation by
about 1990. This year was assumed in all cast:s for
cotW!:niencl:. !\simulation period of 25 yr;ars was thus
used in the comparison of tlw altcrnatin:s. t\ furthr;r
35-vear Pvaluation period {2011-2045). during\\ hich the
alt!.:rnativc programs W!:n: assumed to £'('!11ain fixed.
was us!:d to r:stimatr; the long-lt:rm r:flccts of all the
alternat ivcs.
nu
Fig. 14. Expansion Plan of Maritime Integrated System
Without Tidal Development.
Without Tidal Power
The expansion plans lor th(: MIS. illustrated by
Fig. l4. wert: assumed to include the dl:vdopment of thu
remaining hydroelectric resources of the area, up to an
ultimate installed capacity of 1200 MW. Additional
fossil-fired generation of 475 M\V unit sizes would be
utilized to supply the inlermediotc load generation
requirements while additional base load capacity
would be supplied by nuclear generation in unit sizes
of 750 MW and 1250 MVV. Finally. gas turbines and
enPrgy storage syst<:ms would be used for peaking
and required generation reserve purposes.
The projected mix of generation to meet the de-
mands of th(; markets forming NEPOOL is similar to
that of MIS (Fig. 14). However. because of constraints
on availabilitv and usP of oil as a boiler fuel. no addi-
tional uil-firr;d generation is anticipated within this
region. N(:\'Prthclcss. recognition must be given to thn
continued need for oil in existing steam turbine gener-
YEAR
Fig. lS. Expansion Plan of Hydro-Quebec System Without
Tidal Development_
ation. for peaking combustion turhirws and ancillary
purposes.
In the e<Jse of Hydro-Quebec. its expansion pro-
gram until 2010, illustrated on Fig. 15, will be larg!:ly
based on the development of its immense hydroelec-
tric potential. supplemented by nuclear generation to
supply base load. Analysis sho\\'cd that. in view of this
large hydroelectric compom~nt. absorption of tidal
energy by Hydro-Quebec would not be economic be-
cause then~ would be so little high-cost lht~rmal gener-
ation that might be r!!placed and becaust! of tlw high
cost of transmission required. As a result. the Hydro-
Quebec system must. for th!~ time being at least. be
set aside as a market for tidal energy.
With Tidal Power
For the generation expansion plans, the output of a
tidal plant is imposed on tht~ MIS in 1990. If the tidal
plant capacity is large enough. it forces the n~st of
the generation program for MIS as well as the con-
nected markets, to so that a near. least-cost plan
is obtained. This was undertakt!n for several
possible single-basin, tidal developments. under \·ar-
ious planning and operating strategies, including the
double-effect mode of generation. Some of the strate-
gies considered were as follows:-
(a) Raw Absorption: Power available from tidal was
utilized directly by the systems. \Jo energy storage
devices associated with a particular tidal plant for
retiming tidal e1wrgy were permitted. However. energy
storage facilities which were in the expansion plans
without tidal. wr~re utilized to retimc tidal energy.
(b) Retiming in MIS: Specific capacities of additional
storage devices vvere installed in MIS for retiming the
tidal generation which was not directly absorbable in
the raw absorption scenario.
TIDAL SITE-139 (:)800 MW)
The studies have shown that for the us!;able capa-
city of :3800 M\V. the best scr:nario for integrating tidal
energy would be that of raw absorption, with 1'\EPOUL
as the secondary market, rather than any form of IT-
timing in MIS or by Hydro-Quebec.
For the raw absorption scenario the optimum
transmission capacity between MIS and NEPOOL
would be 2500 MW while the gr~neration mix in MIS
\•,:ould be affected in the following manner: (i) th;;
nuclear installation schedule would remain unchanged:
(ii) by the year 2010, two 475 MVV oil-fired units could
27
IH• t:lirninatr:d and tiOO M\\' of <HiditilJil<d gas turbines
\\ ould he installt:d. n~sulting in a net tTducl ion of :150
M\Y of generating capacity. or about !()",of tlw uscablt:
cdpacity of l3~. In :\EPOOL. some IPmpurar~· ddnr·
nwnts of gas turbines would occur in lhP ~·ears
of tlw life of the tidal plant: hut. by 2010. therP \\ould
ht~ no capacil~' reduct1on lwcausc h~' tlwn the :VIIS
would lw r:xpl:ctt:d to ha\P incn·ast'd significant!~· in
size so thatthr: amount of surplus tidal t!IWrgy a\'ailalllc
to NEPCJOL \\ould be rclati\'t:ly small. Tlw impact of
singh: dluct tidal pLmts on tlw l:xp;1nsio11 program thus
!;
"" ...
Ill _,
;!!
;:
!
"" 0
1!1
;:! 110 Ill ... ... ... ...
30
20
10
1990 1995
01 RECT A8SORPTIOM IK Ml
2000
YEAR
2005
NOTES I) RAW ABSORPTION IN MIS AND NEPOOL
2) 2500 MW MIS-NEPOOL TIE
3) GENERAL PURPOSE RETIMING FACILITIES ARE NOT
INTRODUCED WITH THE RETIMING OF TIDAL POWER
AS THEIR PRIME PURPOSE.
200
Fig. 16. Utilization of Tidal Energy from Site 89 (3800
MW).
28
100
90
-e eo
~ i 7 0
;! 6
;:: 0
~ 5()
0
0
1990
I
i
I
~
1995
••
'\___ UNUTILIZEO ENERGY
!
I
OIL I
I
I I --_____.J---
COAL ~
NUCLEAR
2000
YEAR
NOTES-I) RAW ABSORPTION IN Ml S AND NEPOOL
2) 2500 MW MIS-NEPOOL TIE
---
I I
2010
Fig. 17. Energy Saving by Energy Sources, with Site B9
(3800 MW).
appears to be quite modest. However, the amount of
thermal energy displaced by tidal output is significant.
Fig. 16 shows the proportion of tidal energy output
absorbed within MIS and NEPOOL. It is evident from
the figure that because of the limited absorption capa-
bility of the MIS in 1990. a significant portion of tidal
energy. immediately following the commissioning of
a development at B9, would have to be transmitted
to NEPOOL for utilization in that system. Thereafter,
the energy absorption in MIS would increase.
Fig. 17 shows, as a percentage of the annual tidal
output for B9, the value of tidal energy measured in
terms of the amounts and types of thermal energy dis-
placed in the interconnected systems. A significant
quantity of the energy displaced by tidal output is
oil-fired generation. However, by the year 2010 be-
cause of the large number of nuclear generation addi-
tions to the expansion program the nuclear energy
displaced by tidal power reaches about 35% of the
tidal output.
TIDAL SITE -A6 {1550 MW)
Studies have shown that for the useable capacity
of 1550 MW, the best scenario for tidal energy utiliza-
tion would involve retiming by a 500 MW storage
device added to MIS in 1995 with NEPOOL as the
secondary market. The optimal transmission capacity
between MIS and NEPOOL would be 500 MW.
For this scenario the generation mix in MIS would
be affected in the following way: (i) the nuclear in-
stallation schedule would remain unchanged; (ii) by
the year 2010, two oil-fired units with a total capacity
of 950 MW would be cancelled while 300 MW of
additional gas turbines would be installed together
with 500 MW of storage for retiming. This would result
in a net reduction of 150 MW to the MIS expansion
program. As in the case with Site B9, only some tem-
porary deferment of gas turbine capacity for NEPOOL
100
90
eo
J;:" ~ L
~ ~ -~ t-f-VRETINED IN MIS N.___
\L UICUT ILl ZED
-
TIDAL EIIERGY
70
~ ... ... m ao _.
i! ;:::
; ... 50
0 ...
"' ;:!
........ ~ 01 RECT ABSORP.TION 141 S
m
~ ., ... ..
3D
31
10
11190 1895 3100 21105 3110
NOTES -I) RETIMED IN MIS BY 500 MW STORAGE FACILITY
AFTER 1995
2) 500 MW MIS-NEPOOL TIE
Fig. 18. Utilization of Tidal Energy from Site A6 (1550
MW).
100
90
a 6
;::
0
0
'
,___
.I ,r-10
0
1!190
I
[
i
I
I
I
7!
1995
UNUTILIZ~D
OIL
roAL
NUCLEAR
2000
YEAR
ENERGY-'"
i
I
i
I
I =---------'
I
+-------
i
2005 2010
NOTES-I) RAW ABSORPTION IN MIS AND NEPOOL
2) 1000 MW MIS-NEPOOL TIE
Fig. 19. Energy Saving by Energy Sources, with Site A6
(1550 MW).
would occur in the early years of the life of the tidal
plant. Similarly, the capacity credit associated with
the plant would also be equivalent to about 10% of the
useable capacity.
Fig. 18 shows the proportion of tidal energy output
absorbed within MIS and NEPOOL. It indicates that
the MIS alone would be capable of utilizing most of
the tidal energy output.
Fig. 19 shows the value of tidal energy measured
in terms of the amount and type of thermal energy
displaced in the interconnected systems. A major
portion of the energy displaced by tidal power would
come from oil-fired generation. Therefore, the value of
tidal energy is significantly influenced by the price
of oil.
TIDAL SITE-AB (1085 MW)
The best scenario found for Site A8 would involve
retiming tidal energy by means of a 250 MW storage
device added to the MIS in 1995 and with NEPOOL as
the secondary market. The optimum transmission
capacity between MIS and NEPOOL would be 500
MW.
The generation mix in MIS with a useable capacity
of 1085 MW at Site A8 would be affected in the follow-
ing way: (i) the nuclear installation schedule would
remain unchanged; (ii) by the year 2010, the net reduc-
29
lion of generation capacity vvould be 100 MW, which
would result from the cancellation of two 475 MW
oil-fired units, the addition of 600 MW of gas turbines
and 250 MW of additional storage.
The generation plan for NEPOOL would be un-
affected since the surplus tidal output available for
NEPOOL would be very small compared to its system
size.
Fig. 20 shows the proportion of tidal energy output
absorbed within MIS and NEPOOL, while Fig. 21
shows the value of tidal energy expressed in terms
of the amount and type of thermal energy displaced in
the interconnected systems. The results are very simi-
100 ~ v ""'"'"' "'""/
90 _~.=~
~~ Jt::_" "'
..,
\;NUTILIZED ENERGY .,
""
50
VDIRECT ABSORPTION I~ NIS
"'
20
10
1990 I!JII5 2000 2005 3110
YEAR
NOTES -I) RETIMED IN MIS BY 250 MW STORAGE FACILITY
AFTER 1995
2) 500 MW MIS-NEPOOL TIE
Fig. 20. Utilization of Tidal Energy from Site AS (1085
MW).
30
100
I
9()
~ UNUTIUZED ENE~GY
--
Oil I ro ' I 10
!
!()
1 ·--··
~ i ~ --30:
i 1--
! COAl ---i
20,
~ --IOV
MUClUR I : 0
1990 1!195 21!00
YUR
lll05 2010
NOTES I) ~AW A8SOI1PT!ON 1"'1 MIS AND NEPOOL
2) 500 MW MIS~ NEPOOL TIE
Fig. 21. Energy Saving by Energy Sources, with Site A8
(1085 MW).
Jar to those indicated for Site A6, namely that the MIS
would be large enough to absorb most of the tidal
output and that a significant portion of the energy
displaced would be oil-fired generation.
Fuels Displaced by Tidal Power Developments: The
amounts of fuels displaced by tidal developments at
each of the three sites are displayed in Table 3.
TABLE 3
Estimated Annual Amounts of Fuels Displaced
in MIS and NEPOOL Systems
by Selected Tidal Developments
Fuel Oil Coal
Item millions
of bbls.
-·-·
Site 89 (3800 MW)
Quantity displaced/yr 0.12
Site A6 (1550 MW)
Quantity displaced/yr 0.4
Site A8 (1085 MW)
Quantity displaced/yr 3 0.02
As of 1990. fuel consumption by the Maritime utili-
ties is estimated to IH~ tl.3 million barrels of fuel oiL
:l.B million tons of coal and 1.0 million pounds of
uranium, annually. Since most of the energy displaced
by tidal for both Sites A6 and AB occurs in the MIS,
the tidal energy from these sites could displace about
one-half the estimated annual oil consumption in 1990
for thermal generation. The estimated fuel sa\'ings from
Site 89 are combined savings to the Maritime and New
England systems: the fuel savings to the Maritimes
would be proportionally greater than from Sites A6
or AB.
Double Effect Operation: Studies for Sites 89 and A8
operated in the double-effect mode with pumping were
also undertaken to evaluate the benefits from incrcaSl!d
operational flexibility which permitted the plant to
calur to capacity shortage situations.
The analysis indicated that a 4019 MvV double-
effect installation at Site 89 with a useable capacity of
about 3782 MW would result in a net reduction of
generation in the MIS of 1350 MW by the year 2010
by the elimination of two 475 oil-fired units and four
100 MW gas turbines from the MIS expansion program.
The corresponding capacity reduction in the MIS as-
sociated with a double-effect development at Site AB
with a usable capacity of 1292 MW was calculated to
be 675 MW as a consequence of the elimination of
one 475 MvV oil-fired unit and tv,;o 100 MW gas tur-
bines.
Tidal plants operal!~d in the double-effect mode
could thus have a capacity contribution or "capacity
credit" to the power syst!!m equivalent to about 35'X,
of the plant's output. However, studies indicated that
these additional benefits were slightly more than offset
by the higher capital cost of the double-effect over the
single-effect plant. Although there appears to be no
economic improvement in benefits from double effect
develop men Is, the increased operating llexi bility they
afford may dictate their selection over single-effect
plants.
TRANSMISSION
Transmission planning for large power systems
concerns the incorporation of generation additions so
that the power produced from the total system genera-
tion is delivered to the interconnected loads in an
economical, flexible and reliable manner. For the
incorporation of conventional genPration, a preliminary
analysis was made of the internal transmission differ-
ence between the altern at iv1:s "with" and "without"
tidal power. The differenc1! was minimized by project-
ing tW\V plant additions in the same general geographic
area. However. the incorporation of tidal power plants
into the power systems required an analysis of the
transmission to link the output to both local and remote
markets. Since tidal output from a single-basin
development would occur in the form of isolated blocks
of energy, the transmission facilities should be capable
of transmitting the total power and energy output to
the markets. In addition. these facilities should be able
to receive energy from the system to operate the tidal
power plant in the pumping mode, if the plant were
designed for double-effect operation.
Site
89
AB
A6
TABLE4.
Costs of Transmission Links to System Grid
(all values in June 1976 dollars)
MIS Internal
Transmission MIS-NEPOOL Tie
Costs
Type Size Costs
$42.8 million 765 kV AC 2 500 MW $308 million
7.8 mill ion 345 kV AC 500MW 29 million
7.8 million 345 kV AC 500MW 29 million
------------
Only the transmission necessary to incorporate the
various tidal plants into the MIS system and the as-
sociated tics between the MIS and secondary markets
were considered in this evaluation. For study purposes,
no free utilization of the existing 500 MW transmission
tie between MIS and 1'\EPOOL or the 320 MW high
voltage, direct current (HVDC) transmission link
between MIS and Hydro-Quebec was assumed. Table
4 shows, for the base scenarios associated with each
tidal development. the transmission capacity and
corresponding costs required to incorporate the plant
into both the local and export markets. These costs
form an integral part of the overall cost of tidal projects.
31
32
Economic Feasibility
The determination of the economic feasibility of
tidal power or. in other words. its competitiveness over
the long term with conventional sources of energy used
by utility systems, involves the interaction of many
factors under future conditions which cannot be pre-
dicted with certainty.
The primary objective of an economic analysis is
to identify the generation programs which will provide
a required service at the least cost. The series of with
and without case comparisons carried out provides a
measure of benefits attributable to tidal power in terms
of present worth value of the differences in system
costs between these two cases. These values when
related to the cost of the particular tidal power
development will provide the net benefits to the MIS
and establish the relative economic feasibility among
the three selected schemes.
ASSUMPTIONS
To avoid misinterpretations of the study results.
it should be emphasized that the economic parameters
used and assumptions made were for the purpose of
the economic analysis. While appropriate for that pur-
pose, it should be realized that the results differ materi-
ally from actual costs that would be incurred in
developing a project. Realistic comparisons were made
for various changes in these parameters to which tidal
power would be particularly sensitive, such as the cost
of capital, cost of fuels, and the level of nuclear pene-
tration in the generation expansion programs. The
values of the parameters used and the assumptions
made for the base or standard case are:
a) The approach taken in these evaluations is con-
sistent with the engineering economics used by the
Maritime utilities. In other words, the value of tidal
energy for the utilities is the tangible cost which
they would avoid if a tidal power plant were built.
As indicated by the differences between the "with"
and ''without" tidal alternatives these have been
found to arise from the displacement of thermal
energy by tidal output and the elimination of some
generation installations from the expansion
programs.
b) For some tidal plants a secondary market could
be required to utilize tidal energy output surplus
to the MIS. Under these circumstances, it was as-
sumed that the value of the savings achieved
through absorption of tidal energy in the secondary
market would be credited to the tidal plant project.
c) All costs used were in terms of June 1976 dollars
and thus do not include future inflationary effects.
Where costs and revenues concern NEPOOL,
United States and Canadian dollars were assumed
to be at par.
d) In the estimation of future costs and benefits, the
concept of real interest was used for the economic
portion of these investigations. Heed interest is de-
fined, to a close approximation, as the difference
between the actual interest rate (taking into account
the borrower's credit rating, the risk involved and
other related factors in the venture) and the inf1a-
tion rate, and was assumed to be 5.5"/,,,
c) The general inflation effects on fossil fuel prices
were also excluded in this economic analysis.
However, differential changes between the esti-
mated fuel prices and general inflation were es-
timated and applied in the analysis. All fuels were
referenced to the June 1976 world fuel prices.
f) The economic costs associated with each of the
"with" and "without" tidal expansion programs
were derived by the summation of the annual fixed
charges plus operation and maintenance charges
associated with the capital additions and the total
annual energy production costs over the period
under review. In addition calculations of the
present worth (PW) of the costs of the alternatives
enabled equitable comparisons to be made of the
economic differences between the "with" and
"without'' tidal power alternatives. All PW costs
have been referenced to the bench mark year 1985
which is the starting year for all the expansion
programs.
g) In order to compare on a single-valued basis the
economic differences between the "with'' and
"without" tidal plant alternatives over the terms
of the expansion programs, it was useful to use
the concept of the levelized value of benefits from
tidal versus the corresponding levelized cost. These
two quantities are expressed in mills/kWh and are
obtained by dividing separately the total PW cost
and benefits as determined in (f) by the present
worth of the energy production of the tidal plant
cumulated over the study period.
It must be emphasized that comparisons of the PW
dollar value of the benefits and costs, or the equivalent
levelized mills/kWh amounts, with the current cost of
alternative generation are not valid. The primary ob-
jective of the economic analysis was to identify the
generation program which would provide a required
service at least cost over the total study period.
Although the PW values arc primarily indicative of
the relative magnitude of benefits and costs associated
with each tidal development, the ratio of these quanti-
ties is also an important indicator of economic viability.
A tidal development is considered to be economic
if the levelized benefit to levelized cost ratio is
greater than 1, regardless of the capital intensive differ-
ences between the "with" and "without" tidal
programs. The latter is a financial consideration which
is discussed in the next section. Another important
33
consideration in an economic evaluation is the "break-
even" point, that is, the time when the total present
worth of tidal benefits and costs would be equal. This
permits an assessment of the period of time required
for the benefits derived from tidal power to recover
all the associated costs of the development.
COMPARATIVE GENERATION COSTS
The capital costs and associated annual charges for
generating equipment used in the expansion programs
are shown in Table 5.
The projected average fuel costs for 1985 and 1990
are shown in Table 6. All costs are expressed in 1976
dollars and include only the real escalations that are
estimated to occur within the planning period i.e.
1886-2010.
TABLE 5
Capital and Annual Costs of Generating Equipment
Capital Costs'" Annual Fixed Charges"'
Description of Unit Size Per cent of Capital
Facility MW $/kW $million Cost $million
Gas Turbines 100 167 16.7 9.45 1.6
-"--
Oil fired thermal 475 311 147.7 8.90 13.1
(1st unit)
·------
CANDU Nuclear units 635 844 535.9 8.97 4B.1
(1st unit) 750 793 594.8 8.88 52.3
1250 665 831.3 8.63 71.7
--· ------------
NEPOOLLWR 1150 710 816.5 99.9
Nuclear units 1500 650 975.0 12.24'" 119.3
(1st unit) 1750 630 1102.5 134.9
--·--"---------r-------·--------------------------
Pumped Storage 200 305 61.0 6.231 3.8
-----------------------
Site B9 3800 MW"' 3637 227
SiteA6 1550 MW"' 2160 6.231 135
SiteA8 1085 MW'" 1197 75
----· ------------------------------· -
(1) Values in June 1976-dollars: includes interest during construction but excludes escalation.
(2) Based on a real interest rate of 5 .5%, including amonization, interim replacement, insurance and other fixed costs of opera-
tion and maintenance.
(3) Fixed charges associated with both MIS and Hydro-Quebec do not include taxes as they are provincial utilities: NEPOOL
is a private utility power pool and taxes are included in the annual fixed charge costs.
(4) Useable plant capacity.
34
TABLE 6
Projected Fuel Costs
(June 1976 Dollars)
Fuel
MARITIMES:
Residual Oil (0.3% Sulphur)
$/Million Btu
$/Bbl.
Distillate Oil
$/Million Btu
$/Bbl.
Alberta Coal
$/Million Btu
$/short ton
Uranium (U,O,)
$/Million Btu
$/lb.
NEW ENGLAND:
Residual Oil (0.3'Yo Sulphur)
$/Million Btu
$/Bbl.
Distillate Oil
$/Million Btu
$/Bbl.
W. Virginia Coal
$/Million Btu
$/short ton
Uranium (U,O,)*
$/Million Btu
$/lb.
* Includes processing cost of $0.20/million Btu
RESULTS OF ECONOMIC EVALUATION
The gross br~ndits dur~ to a tidal powr~r plant arc
the differencr~s lwtwt~en the total prr~sent worth costs
of thr~ "'with'' and "without" tidal plant expansion
programs. Both the cost of retiming facilitir~s and thr~
transmission required for incorporation of the tidal
plant to both local and external markets arr~ then de-
ducted to determine the net benefit. These lwndits
were compared subsequently to the cost of the tidal
plant to de!f~rminr~ its economic viability. 1\ summary
of the bcndits and costs arc provided in Table 7 for
thr~ three sitPs with single-effect installations. A discus-
1985 1990 1991-2010
2.49 2.50 1% annual escalation
15.55 15.60 1'Y., annual escalation
2.85 2.86 1 'Y., annual escalation
16.65 16.75 1% annual escalation
1.81 1.83 1% annual escalation
28.95 29.30 1 Of<, annual escalation
0.21 0.21 0.21
45.00 45.00 45.00
2.53 2.54 1% annual escalation
15.00 15.85 1% annual escalation
2.89 2.90 1% annual escalation
17.00 17.10 1% annual escalation
1.55 1.64 1% annual escalation
36.40 38.55 1% annual escalation
0.41 0.41 0.41
45.00 45.00 45.00
-----------------------
sion of tlw evaluation is sr~t out in the following para-
graphs.
Tidal Site -89 (3800 MW)
Fig. 22 shows the cumulative present worth of the
gross benefits (unadjusted) from Site B9 in terms of
both fuel costs and fixed cost components in the MIS
and NEPOOL systems over the planning period. By the
year 2045 the present value of the gross benefits are
calculated to be $3,638 million. A significant portion
of these benefits (i.e. 36'Yo) would be derived from the
secondary NEPOOL market on the assumption that
100'/'o of the cost of energy displaced would be credited
to the tidal power project. The competitiveness of Site
89 is therefore dependent on the sales contract with
NEPOOL. Also shown are the total PW costs for 89
and associated transmission calculated to be $3,428
millions.
Fig. 22 also shows that the cumulative present
worth benefits surpass the corresponding cost of 89
in the year 2032. Based on an in-service date of 1990
and the base case scenario, the indicated breakeven
35
period is about 40 years for a tidal plant at this site
with an assumed useful life of 75 years. A development
at Site 89 is. therefore, economic over the long term.
Tidal Site -A6 (1550 MW)
Fig. 23 shows the cumulative present worth of the
gross benefits (unadjusted) and corresponding costs for
Site A6 calculated at $1,:~02 million and $1,866 million
respectively by the year 2045. There is no breakeven
TABLE 7
Economic Evaluation Summary of Benefits and Costs
Site 89 Site i\6 Site AH
Item Raw absorption Retimed Storage 500 MW* Retimed Storage 250 MW**
MIS-NEPOOL TIE 2500 MW MIS-NEPOOL TIE 500 MW MIS-NEPOOL TIE 500 MW
MIS gross value from tidal 2:~:~2.3 1242.3 950.7
NEPOOL gross value from tidal B06.0 59.7 48.6
Total gross value from tidal 36:~8.3 1302.0 999.8
MIS internal transmission cost 32.7 6.0 6.0
MIS-NEPOOL transmission cost 235.7 22.2 22.0
Total transmission cost 268.4 28.2 28.2
Net benefits from tidal (unadjusted) 3369.9 127:t8 971.1
Present worth of Energy, GWh 176,439 63.210 47,732
Lcvelized value of Energy. mills/kWh 19.1 20.2 20.3
Total capital cost of tidal plant 3637 2160 1197
Annual charge (fv 6.231% 227 135 75
Present worth in 1985 of annual charges
(unadjusted) over the period 1990-2045 3160 1877 1040
At site cost of Energy, mills/kWh 17.9 29.7 21.8
Benefit/Cost ratio 3370/3160 = 1.07 1274/1877 = 0.68 971/1040 = 0.93
NOTES: 1. All present worth values and costs are in $million (June 1976 dollars); values are present worthed to mid-1985
at 5.5% discount rate over the review period (1986-2045).
2. Based on Intense Nuclear Scenario for the MIS.
*Cost of 500 MW storage installed in 1995 has been subtracted to give MIS gross value from tidal.
**Cost of 250 MW storage installed in 1995 has been subtracted to give MIS gross value from tidal.
36
point as the costs exccr~d the benefits. The development
of Site AG \\'ould therefore be uneconomic.
Tidal Site-AS (1085 MW)
Fig. 24 shows the cumulative present worth of the
gross lwncfits (unadjusll:d) and corresponding costs for
Site i\8. These an~ indicated to he $1,000 million and
$1.0GB million respectively by the year 2045. In this
case 95'Xl of the calculated benefits are derived from
the MIS alone. Such a size of clcvclopmcnt therefore
can be integrated into the MIS without reliance on the
secondary market. As the present worth benefits and
costs arc about equal at the end of the review period
it can be concluded that the hreakeven period is about
60 years.
4000 ~--.---.---,---,---,---.---,---,----r---r---,
i
1
! I I
3600 f---+-' -----+-J -t +-~ t---t--+----t-~
I l, •• ., ' I ---~ ! TOTAL SITE A .. D TRA~SSIO CO~ OF_ Ef-_ 4~ __ _ ~--~-r "-j-, -_p:--,-
3200 1---+---+-------+---~-l----fo--Y'-+---+---t----1
I : i ;:;
i I f"' I ' I '~--: tA/1_, 1"1 "'"I~-2800
!::!: 2400 ~. l-1/V t I L--+-' --+--+-----:.i
NEP10L FUt-VALUf I ~ ---
~ ,_ I -----
u: 2000 1/_..----~~, ----+~(----~~ ;_---t-I ~
,_
z I I / ..... \_-MIS !''XED ~ALUE
---r-· ./ -r
/ !
/; 1 /v /
1
!
~ 1600
1200 e-----+~-11 l /_L_ -----j ~--i
BOO If \~v 1 ~ MIS FUEL
1
vALuE I
400 -,1/ ---+----+----1 ---+-----t--i
v-_ ~02.!_ ~T~ SM~"!--1--____ _ ---
1990 9!5 2000 C6 10 20 2!5 30 40 4!5
YEAR
NOTES-l)RAW ABSORPTION IN MIS
AND NEPOOL
2) 2500 MW MIS-NEPOOL TIE
Fig. 22. Site 89 (3800 MW), Cumulative Present Worth
Value.
2000
1860
1600
1400
~ 1200
~ i 1000
600
400
1990 95
YEAR
NOTES-l)RETIMING IN MIS AND NEPOOL
2)500 MW MIS-NEPOOL TIE
Fig. 23. Site A6 (1550 MW), Cumulative Present Worth
Value.
1400
!2 1200
X :;: 1000
0
~
~ BOO
~
~ 600
400
200
~I I
I I I
..;._ l ' I
' I . I I
T¢1TAL S I ----~ ~N~ ~~M.:::'~ ...:04 ~-_ -r-----
TOTAL i hilS e NEPO L BE FITS~ l _: j-.: -i :::1:: =
I 0(;---~l
y ['---TO AL MIS BENEFITS
L
~_i__rl~o:_ TR ~SMISSI~ J --+------
1990 95 2000 05 10 20
YEAR
NOTES-I)RETIMING IN MIS AND NEPOOL
2)500 MW MIS-NEPOOL TIE
I
I
I
'
i
I
!
I i
__ J __ --
"' 30
~--
I
-
40 ••
Fig. 24. Site A8 (1085 MW), Cumulative Present Worth
Value.
Sensitivity Analysis
The Committee developed scenarios, that is, the
delineation of hypothetical but feasible futures, to
assess the economic feasibility of developments using
the established site-optimum installations and firm cost
estimates. Because of the unpredictability of the precise
future values of parameters involved in a scenario, a
range of values for each parameter was included in
the analysis so that the effect of an individual param-
eter on the economic feasibility could be assessed. In
other words, a sensitivity analysis was carried out to
provide as complete a picture as possible of the future
consequences of including or of not including tidal
prnver in the generation expansion programs of MIS.
Because Site A6 was shown to be uneconomic, a
sensitivity analysis to determine the effects of changes
in assumptions on the study findings has been detailed
only for tidal developments at Site B9 and A8. Analyses
showed that the significant parameters that could
inf1uence the benefit and cost determinations were as
follows:
1. Extent of nuclear development (penetration) in
the MIS expansion program
2. Loacl forecast changes
3. Marketing strategies for tidal energy in the
secondary market
4. Fuel costs
5. Interest rates.
The effects of these parameters are discussed
hereunder and summarized in Table 8. The effect of
appropriate adjustments to the unadjusted bene-
fit-to-cost ratios in Table 7 are presented in Table 9.
NUCLEAR PENETRATION
Since the greater portion of the value of tidal bene-
fits would be derived from the displacement of thermal
energy, it is evident that the higher the nuclear penetra-
tion in the expansion program, the greater the propor-
tion of nuclear energy that would be displaced and
consequently the lower the resultant tidal benefit.
With regard to the extent of nuclear penetration,
it should be emphasized that the base case MIS expan-
sion program shown in Fig. 14 results in an increase
in nuclear penetration, as a percentage of MIS peak
load, of from 50°/r, to 73% from 1990 to 2010, respectively.
This program is an intensive nuclear scenario with the
extent of nuclear generation limited only by technical
constraints of nuclear cycling. For this program, incre-
mental nuclear generation additions would be required
37
to operate at about 65'X, capacity factor. This was
considered to be the minimum technically feasible
capacity factor for this type of generation. For the
purpose of the sensitivity analysis. however. an all-
nuclear generation scenario for MIS vvas developed
which resulted in a range of 50% to 79% nuclear pene-
tration as a percentage of MIS peak load from 1990
to the year 2010. However, this scenario would violate
the nuclear cycling technical constraints since some
units would be required to operate at 35% capacity
factor. This scenario, therefore, is very unlikely to be
developed. In addition a low nuclear scenario. with
nuclear penetration limited to about 50% of the peak
load was also examined. Such a hypothetical future
might be seen as a possible result of resistance to
continued development of nuclear plants. However, in
this case, the objective function of the least-cost
generation program would be violated.
The Board concurs with the Committee that the
most likely magnitude of the benefits from Sites A8
and B9 would be those calculated as the base case
program of intense nuclear penetration followed by
the low and all nuclear scenarios in order of likelihood.
The benefit/cost (B/C) ratio could vary by + :30 '!;, to
-20% depending on the scenario chosen.
LOAD FORECAST CHANGES
The sensitivity to variations in projected load
growth was tested only for Site B9 by making alterna-
tive assumptions regarding future demand in the Mari-
time market.
The base case load forecast assumed an average
rate of growth of the MIS peak load of 7.2% per annum
after 1985. For the sensitivity evaluation of alternative
load growths, rates of 4% and 8.5% were used. The
minimum rate was assumed to result from both a strong
conservation program accompanied by a general slow
clown in the economic growth, while the high rate
reflected an increase in the market share of electricity
clue to substitutions from fossil fuel to electric power
use as well as a sustained high economic growth rate.
The effect of the alternative assumptions regarding load
growth is modest. The base case provided the lowest
B!C ratio. This was due principally to the fact that
the near-optimum generation expansion programs
developed to meet the three load growth cases resulted
in different mixes of generation. The Board considers
that the assumed base case load growth rate may be
slightly high.
38
MARKETING STRATEGIES
The base cas(~ program assumed that the full value
of tidal energy to the secondary markets was credited
towards the tidal powm· proj(~Ct. In reality. hovvever.
th(~ revenues gr~nerated by surplus tidal energy in the
secondary market would, in all probability. he l!~ss than
its full value and would depend on the sales contract
agreement between MIS and the external market.
For the purpose of this analysis various markding
strategies for sales to the secondary market were
dev(~loped. It was assumed that tidal energy sales to
NEPOOL would he based on an economy energy con-
tract. with a price for energy equal to 50% and 80'7(,
of the cost of the energy displaced.
R<~-cxamination of Table 7 shows that the contribu-
tion made to the total benefits by the NEPOOL
secondary market is very significant (i.e. 36%) with
respect to the large tidal development at Site B9, but
is insignificant with respect to tidal Site A8 since the
MIS system alone is large enough to absorb virtually
all of the tidal output.
For tidal Site B9. it should be noted the optimum
scenario chosen was that of raw tidal absorption into
the systems. It is evident that as the contribution of
benefits by the secondary market decreases. retiming
facilities tu enable more of the tidal enr~rgy to be ab-
sorbed within MIS,rcsulting in less surplus energy for
NEPOOL. would become mon; attractive. For example,
a 500 MW storage facility would reduce the net con-
tribution by NEPOOL from 30'Y., to 15%.
Based on the optimum scenario for each marketing
strategy. i.e. full credit. the B/C ratio for Site B9 would
he reduced by about 8'X, under the 80% value assump-
tion and by about 12% if the 50% value assumption
were used, On the other hand, the B/C ratio \\'ould
only be reduced by 1% for Site A8 under the 50'Yu value
assumption case.
For the purposes of the feasibility reassessment,
the Board considers that a value of 50'X, of the cost
of energy displaced would be the most likely condition.
FUEL COSTS
The value of tidal power is also very sensitive to
fuel costs since a significant portion of the benefits
would be derived from the displacement of fossil-
fuelled thermal energy.
With regard to fuel costs. the base case scenario
assumed that the price of fuel for oil and coal would
rise at the same rate as the general inflation to the
year 1990 and then would increase by one per cent
annually over inflation thereafter.
Projections of future long term oil prices were
subsequently re-examined to take into account the most
recent studies by Canadian and United States authori-
ties. the Organization for Economic Cooperation and
Development (OECD) and several specialized consul-
tants. The results of this reappraisal indicate that the
high fuel-price scenario of 2% real escalation over
general inflation after 1990 is nmv considered a more
realistic view of the future cost of oils.
However, it should be emphasized that the short-
term relative changes in the price of fuel with respect
to general inflation may also have an effect on the
relative long-term economics of tidal power. The likely
price of fuel in the period under review is speculative
but any increase over the rate of rise in fuel costs
assumed for the base case will enhance the economic
feasibility of a tidal povver development. The bene-
fit/cost ratios can vary by about + 10% for the range
of fuel prices assumed.
The Board considers that, based on recent studies
including that of the OECD, a two per cent inflation
rate in fuel price after 1990 is a realistic view.
INTEREST RATES
The interest rate assumption exerts great influence
on the benefit-cost ratio of a tidal power development
because the cost of output consists almost completely
of the annual capital cost, \'\'hile the benefits, largely
derived from displacement of thermal energy. are unaf-
fected by the interest rate.
In the financial analysis, a direct approach was
used. An estimated actual interest rate was applied and
revenues computed in current dollars, taking into
account an appropriate rate of inflation. A different
approach was used in the economic analysis. Inflation
was removed from both costs and revenues through
the use of a real interest rate and constant dollars. The
real interest rate was derived by eliminating from the
actual rate of interest that part which is considered
to represent the effect of general inflation.
Real rates of interest on Government of Canada
borrowings over the last quarter-century have ranged
between 5 per cent and -1.5 per cent, with an average
of just over 2 per cent. Risk factors result in higher
real interest rates for borrowers of lower financial
stability. The spread between Federal and Maritime
provinces' borrowings over the last quarter-century has
been about one per cent.
From the point of view of the opportunity cost of
capital. somewhat higher interest rates than those in-
dicated above might be appropriate for an economic
analysis. A rate of seven per cent or more would hf~
appropriate for work undertaken in a period when
national productive capacity was almost fully utilized.
However, this view of the cost of capital relatr~s more
directly to the timing of a commitment decision than
to the underlying economics of tidal pO\ver.
39
The Committee assumed 5.5 per cent inten:st for
th(: base case and pr:rformed s(;nsitivity analyses for
four per cent and seven per cent. finding that the bene-
fit-cost ratios for tidal developnwnts would vary by
:+ 20 per cent for each one per cent change in interest
rates.
A real interest rate was adopted in the f:conornic
analysis solely for the purpose of reducing the two
parameters of ar.tual or current interest rates and inf1a-
lion to one parameter. In view of this. together with
the fact that finanr:ial feasibility will depend upon some
TABLE 8
Summary of Sensitivity Analyses
Probability (1) Percentage Change to the Unadjusted
Parameter and
Ranking 8/C Ratios (Table 7)
Sensitivity Range of Parameter
Site 89 Site AB
1\!uclear Penetration
Lovv Nuclear Scenario II 24 36
Base Case Nuclear Scenario I 0 0
All Nuclear Scenario III -8 -22
Load Growth I
4.0'l'o II 3
7.2'~{) I 0
8.srv,) III 7
Marketing Strategy
Surplus Secondary Energy Valued at
100(;{) III 0 0
80'}·() II -8 -1
50% I -12 -1
Fuel Cost
Oil/Coal 2'X, Esc ala lion 1990/2010 I 12 10
1%, Escalation 1990/2010 II 0 0
O'X, Escalation 1990/2010 III -12 -11
Real Interest Rate
4.0(}~. II 36 33
5.5% I 0 0
7.0';.{) III -23 -22
(1) I Probable !!-Less Probable III-Least Probable
40
measure of federal participation, the Board considers
that a real interest rate of 4.75 per cent is sufficiently
conservative for the purpose of making a firm estimate
of benefits and costs.
ADJUSTMENTS
Based on an overview of the sensitivity analysis
the results of which are summarized in Table S, the
Board concludes that the benefit/cost ratios using the
base case program appear to be understated rather than
overstated.
Using values of the parameters which the Board
considers most likely to prevail over the next three
decades, that is, an intense nuclear scenario, two per
cent escalation of fuel prices after 1990, a real interest
rate of 4.75 per cent, a load growth of slightly less than
7.2 per cent and export proceeds of 50 per cent of the
value of the power that is exported, and the results
of the sensitivity analysis, an overall improvement in
the economic feasibility of about 10 per cent for Site
B9 and 25 per cent for Site AS would be more repre-
sentative of probable future conditions. The different
adjustments used for Sites B9 and AS arc due prin-
cipally to the different impacts in the results from
changes in the marketing strategy (refer Table S). On
this basis a final B/C ratio for Site B9 of about 1.2,
and for Site AS of about 1.2 would, in the Board's
judgement, be realistic.
TABLE9
Final Benefit/Cost Ratios for Selected Sites
Site
B9
AB
A6
B!C
1.2
1.2
0.9
Breakeven Period
30/35 years
30/35 years
none
Comparing the B/C ratios of Table 9 with those
of Table 7, the economic feasibility of Site B9 is im-
proved and Site AS becomes economic to the same
extent as Site B9. The long-term economic benefits
exceed the costs of a tidal development integrated with
the MIS by a margin of 20 per cent for both Sites.
Site A6, however, would remain uneconomic.
Financial Analysis
It is important to distinguish between an economic
analysis and an analysis of the financial implications
of alternative generation programs, particularly with
respect to a utility's financing capability.
A project, such as tidal power, which may be viable
over its lifetime on the basis of an economic analysis,
may require such initial heavy borrowing that it puts
a severe strain on a utility's financing capability and so
results in large rate increases to the consumers. The
financial analysis can thus be thought of as identifying
the impact of a new project on the cash requirements
and on the annual costs which must be covered by
revenues from the utility's customers.
A financial analysis was undertaken for Sites 89
and AS only, as Site A6 was uneconomic. The objective
of the financial analysis was:
(i) to assess the impacts of tidal power plants on the
cost of service in the Maritimes in terms of the
electricity rates to customers as compared to
alternatives considered;
(ii) to examine the effects of the capital requirements
of tidal power relative to other generation alter-
natives; and
(iii) to evaluate the impact of tidal developments on
the provincial credit ratings in the Maritimes.
ASSUMPTIONS
Two methods of financing were assumed: in one
case the Maritime Integrated System would own and
operate the tidal plant while, in the other, ownership
and operation would be through a stand -alone company.
However, only the MIS case has been detailed
hereunder.
Key financial parameters used to calculate the cost
of service of tidal power are summarized as follows:
Rate of interest on bonds 10'%
General rate of inflation as
measured by the Consumer
Price Index
7'Yo before 19SO and
6'Yt, thereafter
The financial analyses were based upon conven-
tional criteria as currently adopted for publicly-owned
utility financing in North America. The financial
performance of the utilities was based upon the main-
tenance of a debt to equity ratio of 90 to 10 or less.
In addition, the interest coverage which, by definition
is the ratio of net revenue to interest paid, was main-
tained at 1.25. Based on these two constraints the total
cost of capital at 90% debt was calculated at 11.25%
while the rate of return on the 10% of equity was
41
estimated at 22.5%.
In the economic analysis, the full vaiLw of tidal to
the secondary markets was credited towards the tidal
power projects for the base case. However, in the finan-
cial analysis various marketing strategies for sales to
the secondary market were developed to quantify the
impact on the cost of power arising from revenues
generated by such sales.
For the marketing strategies for sales to NEPOOL,
it was assumed that sales would be made on the basis
of either economy energy interchange or by a fixed
contract. The pricing assumptions for economy sales
ranged from NEPOOL paying as low as 30% to a high
of SO% of the cost of the energy displaced with a prob-
able value of 50%. In the fixed contract alternative, it
was assumed that NEPOOL would purchase 25% of the
output of the tidal plant on a take-or-pay basis at SO%
to 120% of the cost of the energy displaced with a mid-
point value of 100% plus any additional economy energy
available on the 50/50 basis outlined above.
All monetary values used in the financial analysis
are based on current dollars escalated over the period
19SO to 2010. This period covers a construction schedule
for the plant of about 10 years together with the first 20
years of operation, which is considered to be the long-
est bond issue period likely to be acceptable to financial
institutions. Since all dollars are escalated over the
review period, comparisons with those obtained from
the economic evaluations are meaningless. In addition,
comparisons between these results and the present cost
of service in the Maritimes have no validity, since the
current analysis relates to the cost of service for a
tidal plant coming on line in 1990.
The cost of service, revenue requirements and
impact on provincial credit ratings are highlighted in
detail for Sites 89 and AS with single-effect develop-
ment schemes.
COST OF SERVICE
This is the cost which the customer must pay in
order that the utility can meet its financial obligations.
The effects of the cost of service to the customers of
the MIS with a tidal development are discussed
hereunder.
Tidal Site B9
The total MIS annual cost of services in escalated
dollars for the "with" and "without" tidal plant at Site
89 expansion programs is presented graphically in Fig.
25 based on the indicated marketing strategies.
42
20.0
IUS WITH TIDAL .I.MD
ECOJIICMY IIITERCHANGE
TO M[POOL (50/50) MIS WITH TIDAL AJID
25% FliED COIHRACT
AT t~ AND ECOIICMY
IIIITERCHM'GE (50/!:10)
o.o+-~~-~--+--·1 ~5 ·-1111-00~' :_l~----~-1
1900 1990 2000 2010
"-''
Fig. 25. MIS Cost of Service With and Without 89.
Fig. 25 shows that during the period 1980 to 1989
before the in-service date of the tidal plant the cost of
service for both programs would be very comparable,
rising from about $500 millions in 1980 to about $1.5
billions by 1989. However, interest paid on the outstand-
ing debt associated with the tidal plant as well as main-
tenance of the required interest coverage would result
in a high level of financial charges immediately follow-
ing completion of the project. These charges would
gradually decline over the project life. As can be seen
from Fig. 25, the 1990 cost of service for the case with
Site B9 would be about $2.5 billions while the compar-
able figure for the case without tidal would be about
$1.7 billions resulting in a $800 million dollar difference
between the two programs.
Between the years 1997 and 1999 or after about
7 to 9 years of tidal plant operation the cost of service
for both programs would become equivalent between
$4.0 and $5.0 billions. By the year 2010 the cost of service
for the "with" tidal plant scenario would be about
$16.5 billions while the "without" case is estimated at
120 .------~--------· ·------n
90f------
~ 80f-----
tollS WITH TIDAL AND
MIS WITHOUT TIOAL
20!)-~ --L---==
1980 1990 2010
YEAR
Fig. 26. MIS Cost of Service With and Without 89.
$18 billions. During the period ending in 2010, the MIS
utilities would have accumulated an additional $3.4
billions of equity in fixed assets in excess of the equity
without tidal. This is an inevitable part of the cost of
service. Another cost of service comparison, but ex-
pressed on a mills/kWh basis, is often a very useful
indicator of the differences in the level of electricity
rate increases between alternative programs. This
information for the "with" and "without" Site B9 tidal
plant program is displayed in Fig. 26.
Fig. 26 indicates that the 1990 cost of service for the
case "with" tidal power could range from about 66 to
69 mills/kWh while the comparable value for the
"without" tidal alternative is estimated at 48 mills I kWh.
This is equivalent to about a 41% differential increase
in the level of electricity rates for that year for the plan
with tidal power.
The electricity rates for the "with" tidal alterna-
tive would approach those of the "without" tidal scena-
rio during the next 7 to 9 years of tidal plant operation,
the rates for two scenarios becoming about equal at
20.0.-----------.------.-----
i
3
;;
~
~ 10.0
i:j
:;
§
IUS WITH TIDAL AIID
'·'+-------
MIS WITH T TIDAL
1000 1990 2000 2010
,...
Fig. 27. MIS Cost of Service With and Without AS.
the 69 mills/ kWh level by 1999. By the year 2010 the
cost of service in mills/kWh is estimated at about 110
mills/kWh for the "with" tidal power plant and 122
mills/kWh for the "without" tidal scenario. This is
equivalent to about a 9'/'o differential decrease in the
level of electricity rates for the plan with tidal power.
It is evident that the impact of Site B9 on the total cost
of service for MIS, particularly during the period 1990
to about 1998, would be very significant. However,
beyond 1998, a development at Site B9 offers an im-
provement in the cost of service over the expansion
program without tidal.
Tidal Site A8
The costs of service for the MIS on a dollar and
mills/kWh basis '\vith" and "\vithout" Site A8 arc pre-
sented graphically in Figs. 27 and 28. As both graphs
show, the construction of the tidal plant would increase
the cost of service to the MIS especially from 1990, and
for the first 8 years of tidal plant operation.
Fig. 28 indicates that the 1990 cost of service for
43
120 1 !
II 0
!
-j:
I
0--
II
)I
0 VI
J,
0 ~ 1415 \liiTH TIDAL A.MD
ECOM()(Y IIHERCHAMGE T
0 MEPOOL (50/50) -[1~ _ ----~~ -~----
~ I I
100
/ 1415 WITHOOT TIDAL
7
,
--
-------~-30
20
1980 1990 2000 2010
YE.U
Fig. 28. MIS Cost of Service With and Without AS.
the case "with" tidal power is estimated at 55 mills I kWh
as against 48 mills I kWh for the case ''without'' tidal
power. This is equivalent tu a 14%, differential increase
in the level of electricity rates for the "with" tidal plant
alternative program. By the year 2010, however, the
cost of service is estimated for the "with" and "without"
tidal plant alternatives to be 120 and 122 mills/ kWh
respectively. This is equivalent to about a 2% differential
decrease in the level of electricity rates for the genera-
tion expansion plan with tidal power.
Since Site A8 would be considerably less costly
than B9, the impact on the total cost of service would
be correspondingly reduced. Nevertheless, even for this
1085 MW tidal development, a 14% differential increase
in the level of electricity rates could be expected in
1990 if the plant were commissioned in that year.
CAPITAL REQUIREMENTS FOR SITES A8 AND B9
Fig. 29 presents both the projected capital require-
ment of the MIS "without" tidal power and "with" A8
and B9 as well as these requirements as a percentage
44
197S 1980 1985 1990 1995 200)
YEAR
Fig. 29. Projected Capital Requirements for Generation
Facilities.
of MIS's fixed assets. The total projected costs of A8
and I39. including escalation and interest during con-
struction. would be $3.12 billion and $9.29 billion
respectively. assuming commissioning in 1990.
The capital costs as a percentage of fixed assets
shm.vn in Fig. 29 relate these expenditures to the size of
the MIS. Even without the construction of a tidal power
plant, the ratio of expenditure to fixed assets during
the period 1980 to 1990 averages 30'Yo which is above
the long-term trend of about 20%. A8 increases the
average to about 40% while I39 increases it to approxi-
mately flO'Yr, with a peak at 110°1<,.
EFFECT ON PROVINCES' CREDIT RATINGS
To determine the feasibility of financing tidal
power, one of the most important aspects is the effect
the schemes would have on the total indebtedness of
the provinces. Table 10 shovvs the projected debt for
the generation facilities in the Maritimes "vvith" and
"without" a tidal development. The 197() figure of $612
per capita represents about one-fifth of the provinces'
total direct and guaranteed debt.
As the table shovvs. even without a tidal plant the
per capita debt for generation facilities in constant
197() dollars is projected to increase from $612 per
capita in 1976 to $2,080 per capita by 1990. With A8 the
1990 amount is increased about 30':1., to $2710 per capita,
and with 89 it is approximately doubled to $:1950
per capita.
An analysis was undertaken of the potential effects
of lhcs(' increases on the Maritime provinces· credit
ratings based on the following constraints:
1. that the present direct and guaranteed debt per
capita in the Maritime provinces should not exceed
$4000 in order to maintain an "A" bond rating:
2. that the ratio of the per capita direct and guaranteed
debt to the per capita personal income \vould not
exceed 0.70:
3. that the provinces per capita debt for purposes other
that generating facilities would remain constant at
present levels.
The results of the analysis indicated that:
(i) The Maritime provinces should be able to raise
the debt required for an MIS expansion without a
tidal facility while maintaining an "A" bond rating.
Hm.vever. in so doing they would be using up most
of their available debt capacity.
(ii) The Maritime provinces would find it impossible
to incur the debt required for an MIS expansion
program with either tidal site l\8 or 89 and still
maintain an "A" credit rating.
(iii) It is evident some form of participation from the
governments will be required if a tidal develop-
ment is to be undertaken. Under these conditions,
Nova Scotia and New Brunswick should be able to
raise the debt required for an MIS expansion with
a tidal power development at Site A8 with support
from the Federal Government such as a loan ·with
repayment deferred for about 10 to 12 years from
project commissioning, limited to about 33% of the
tidal power facility. In this case the debt capacity
of the provinces for other purposes would be
limited if they are to maintain an "A" credit rating.
45
TABLE 10
Projected Debt for Generation Facilities
in the Maritime Provinces
1976 1980 1985 1990
Escalated Dollars (millions)
Without Tidal Pow~r 968.4 1,650.5 4.476.3 9,165.0
With A8 968.4 1,650.5 5,159.6 11,946.6
With 89 968.4 1,696.6 8,163.9 17,393.8
Consumer Price Index 1.035 1.36 1.82 2.43
Constant Dollars (millions)
Without Tidal Pow~r 935.7 1,213.6 2,459.5 3,771.6
With All 935.7 1,213.6 2,834.9 4,916.3
WithB9 935.7 1,247.5 4,485.7 7.158.0
Population (millions) 1.530 1.591 1.699 1.814
Per Capita D~bt in Mid-1976 Dollars (SiCapita)
Without Tidal Power 611.6 762.8 1.447.6 2,079.1
With All 611.6 762.8 1,668.6 2,710.2
With 89 611.6 784.1 2,640.2 3.946.0
Note:
Per capita debt levels "with" tidal plants include only extra transmission requirements. General transmission and distribution for
the MIS would increase capital requirements "with" and "without" tidal by 40% to 50%.
(iv) With Federal Government participation, such as
that suggested in (iii) limited to 75% for power Site
89, the provinces should be able to raise their
portion of the debt while maintaining an "A" credit
rating but they would almost exhaust their debt
capacity for other purposes.
Based on this financial review, the inclusion of
either the A8 or B9 tidal development into the MIS
generation program would create very high capital
expenditure requirements during the period of construc-
tion from 1980 to 1990. This would result in very signi-
ficant increases in the cost of service and the
corresponding electricity rates in the period starting
from the commission of the tidal plant in 1990 through-
out the first seven to nine years of plant operation.
It is evident that these large costs incurred during
the period of construction of a tidal development, or
"front-end" costs as they are often referred to, would
place a very severe strain on the utilities' financing
capability, and would make a tidal project unsuitable
as an undertaking solely as a utility-developed energy
resource. There would have to be an effective involve-
ment of governments, along with the utilities, possibly
through a "regional power supply agency" in develop-
ing the potential of the renewable tidal resource. The
Board suggests that consideration must also be given
to arrangements that will shift part of the financial
burden from the years of construction and initial
operation to a later period when benefits will become
greater by virtue of increasing utilization and escalation
of fossil fuels. Thus, direct government participation,
estimated at 33% of the capital cost of the proposed
Cumberland Basin development (Site AB), and 75% of
the Minas Basin Scheme (Site B9), will be required if
Bay of Fundy tidal power is to be developed.
46
Socio-Economic and Environmental
Considerations
SOCIO-ECONOMIC
The socio-economic considl:rations associated with
tidal developments huve rccr:ived prcliminar:;' wview.
Sonw of the significant effr;c!s are discussed herein.
Construction Labour Requirements
Fig. :m gives an indication of the peak annual man-
powr;r r!:quiremcnts dming tlw 19/J(J's for the MIS
gunnation cxp<Insion plan without tidal as well as for
those with I39 and ,c\IJ. 1\lthough this is an approxima-
tion of labour n:quircmcnts. it nonetheless serves to
illustrate the t:mploymcnt potential which could exist.
particularly in skilled tradf?S. if either Site B9 or Site AS
wr:rc to be undr:rtakcn. Until a more accur<Jte forecast
of manpower availability by skill-type is developed,
it is not possiblt: to predict the likelihood of bottlenecks
in the labour supply. The potential impact of a Fundy
tidal dcvdopment on employment during construction
should not be viewed as a decisive reason for proceed-
ing with the project.
In <Jddition the vast scale of 89. including its man-
power implications. suggests that from the vantage
point of the Maritime provinces it would be far less
"digestible" than Site A8.
Manufacturing Potential Arising
from Tidal Power Developments
As shown in Table 11, the creation or maintenance
of between 775 and 1500 jobs per year related to manu-
TABLE 11
Estimate of Employment Impact
by Type of Product I Activity
Locational Prospects
Employment
Rang<~ * * Other
:'>J.B. N.S. On!. Que. Canada
A. Product I Acti\·ity
Turbine-Ccncratm Manufdclun• 2b0-5·W X X XX XX *
SF6 Switchgear 15-30 X X XX XX *
SFf> Bus Duct 15<JO X X XX XX *
Total Electrical 29()-600
Rebar Manufacture 50-100 XX XX " X *
Rebar Fabrication 25-l10 XX XX X
Structural and Mechanical Sled 175-250 XX XX X X *
Total Steel Fabrication 250-410
B. Building Products
Cement Delivery 7-24 XX XX
Concrete Mfg I Delivery 8-11 XX XX
T imbcr Mfg i Delivery 50-60 XX XX
Total Building Products 65-95
C. Raw Construction Materials
Sand and Gravel
Production and Delivery 70-85 XX XX
Rock Quarrying and Deli\'l:ry 100-300 XX XX
Total Construction Materials 170-385
TOTAL JOBS 775-1.490
Legend:
X possible; XX probable;* possible but less likely;** range of employment estimates smallest to largest of selected
development.
Foreign
X
X
X
X
*
7 a oo
6000
SITl i\.8
---WITHQUl TICAL
50 00
I
2000
occ
19?9 !963
I''
i "·,
i \
/ \
I
198:,
I
I
\
1987
o'
I
1999
Fig. 30. Construction Labour Requirements for Sites B9 &
AS.
facturing could probably be directly related to a tidal
project. Of at least 400 to 500 would be created
in the Maritimes. To the extent that electrical and
mechanical equipment could be manufactured for the
projects in the Maritimes, thc~ employmenl impact r:ould
be The remaining jobs could acr:ruc mainly to
Ontario and Quebec.
Table 11 indicates that electrical and mechanical
equipment would most probably be manufactured in
Quebec and Ontario whilr: steel fabrication, building
products and rmv construction materials would prob-
ably come from the Maritime provinces. There also
appears to be existing capacity in Canada capable of
supplying the electrical and mechanical equipment,
fabricated steel and other materials and equipment
needed for tidal plant construction. To a large extent a
tidal development would tend to support exist cap-
acities rather than require new facilities.
Off-site Manufacture of Powerhouse
and Sluiceway Caissons
Off-site rather than on-site manufacturing strategy
of powerhouses anu sluiceway caissons might offer
some social and economic advantages.
47
Whih· tlw existing shipyards could not handle
construction of these units and might he nductant to
tak£~ on such a program that could b{' detrimental to
th(•ir ship n:pair business. it vvould app{~ar that setting
up ad jacunt. bu I separate, facil it ics may offer i rn mud iah~
advantages to th{~ tidal project and long-term advantages
to the adjoining shipyard. lnvPsligation indicatt:s that
Saint John ofl'!:rs the best possibility for this typ(: of
construction strategy because of potentially a\ailablc
space.
Off-site manufacturing would also cas(: what could
potentially be major social dislocations if on-site manu-
facturing were considered. It would also provide a
facility which could present long-h:rm employment
possibilities in a nwtropolitan area after the initial
tidal power program \vas completml.
Balance of Payments
Table 12 gives some indication of th!~ relative signi-
ficance of the savings on imported oil due to tidal
power in ndation to the balance of payments for 1970.
Sit{~
89
AB
TABLE 12
Credit on Current Account from Displaced Oil
as a Percentage of Total Current Payments
(All values in millions of June 1976 dollars)
Credit on Current Total Current P!:rcentagc Account Payments (1975)
258 51 ,O!l1 0.5 1 ~l
54 51.061 0.1(;{)
It is evident from the table that the impact of tidal
power on the balance of payments is modest. This
impact thercfon: is not large enough to affect the basis
upon which the decision to build tidal plants vvould be
made.
Based on this review it has been concluded that no
critical socio-economic issues have emerged to indicate
that Fundy tidal projects should not be regarded as
a potentially desirable source of energy for the Mari-
time region.
ENVIRONMENTAL ASPECTS
Engineering \\·orks of the type and magnitude of
tht~ proposed tidal po\\'er plants would rwcessarily givt:
rise to environmental impacts. Tht~se could be expected
48
to produce social costs und benefits requiring consid-
eration in any compn~hensivc uppraisal of tidal power.
Preliminar.y consideration was given to environ-
mental matters to ensure that then~ were no drawbacks
of such magnitude as to preclude the possibility of a
tidal development at any of the sdected sit1;s and to
obtain a relative rating of the environmental impacts
among the sites. To develop this background and to
prepare~ for the possible continuation of the design
process. the Committee undertook preliminary environ-
mental investigations intended to (1) identify the
impacts likely to result from construction and operation
of a tidal plant, (2) provide a rough ranking of their
probable importance. and (3) obtain a preliminary
outline of the requirements for a full environmental
assessment.
In an overall assessment of social costs and bene-
fits, it Vl.'ould clearly b(~ necessary to consider environ-
mental effects on a broader plane. The pertinent
question would be whether the production of a given
block of energy from the tide ·would have an impact
greater or less than that involved in generating the same
energy by other means. This question cannot be
resolved without a detailed assessment.
In pursuing the objectives defined above, the Com-
mittee received generous support and assistance from
federal and provincial government agencies. univer-
sities and the scientific community in general. Many
opinions were received from informed sources relating
to environmental effects. their possible magnitude,
their possible importance, and possible approaches
to definitive resolution of the issues.
Based on the information received, the Board con-
cludes that construction and operation of a tidal povver
plant would be unlikely to produce deleterious effects
of prohibitive magnitude. Preliminary indications
suggest that Site AB may have fewer and more moder-
ate impacts than Site B9.
It further appears that environmental impact assess-
ment will be hampered by a relative lack of detailed
knowledge concerning the Bay of Fundy-Gulf of
Maine ecosystem. At the request of the Board, the
parties to the Agreement have initiated the Environ-
mental Assessment and Review Process and have
formally established a joint Environmental Assessment
Panel. The Panel is currently in the process of finaliz-
ing assessment guidelines. It seems possible, and
perhaps necessary in a practical sense, that assessment
by a tidal power proponent would be based primarily
on a full compendium of existing data and un present
knowledge of the ecosystems involved. The desirability
of a long-term program of basic scientific research has
been represented, but the Board does not regard itself
as a suitable agency for such an undertaking.
49
ANNEXA
Terms of Reference
AGREEMENT BETWEEN
CANADA, NEW BRUNSWICK
AND NOVA SCOTIA
THIS AGREEMENT MADE THIS TJIIJ{D DAY OF DECEMBEK Hl75
BETWEEN THE GOVERNMENT OF C:\NADA.
hcrc;inaft!;r called "Canada",
OF Tl !E FI!\ST PART.
TilE GOVERNMENT OF THE PROVINCE OF
NEW BRUNSWICK.Iwreinafter
called "New Brunswick",
OF THE SECOND PART
and THE GOVERNMENT OF THE PROVINCE
OF NOVA SCOTIA, h1;reinafter
called "Nova Scotiu".
OF THE THIRD PART.
WHEREAS the Governments of Can<Jda. Ne\v Brunswick and Nova Scotia
Pstablish!od jointly the Bay of Fundy Tidal Pow1;r Review Board in Fdmwry,
1972:
WHEREAS the Bay of Fundy Tidal Power Review Board has r;xamined
tlw conclusions of the Octolwr 19b9 report of the federal-provincial Atlantic
Tidal Power Programming Board, in light of current and projected conditions;
WHEREAS in its report to Covernmc;nts of September 1974, entitltod,
"Preliminary Reassessrm:nt of Feasibility of Tidal Power Development in the
Bay of Fundy". the Ray of Fundy Tidal Povver R(:view Board concluded that
the economic position of Bay of Fundy tidal power has improved significantly
since 1969:
WHEREAS the: Bay of Fundy Tidal Power Review Board has recommended
that further study will be required to dctermim; whethc:r or not the Pconomic
viability gap between tidal energy and fossil-fuel based energy has or is likely
to be overcome:
WHEREAS the parties agree that further investigation is dc:sirable and
in the public interest in view of the distinct possibility that tidal energy can
be shown to be an economical contribution to energy n:sources in th1: Atlantic
region:
NOvV THEREFORE in consideration of the premises, covenants and agree-
ments herein contained. the parties covenant and agree vvith each other as
follows:
1. The objective of the studies authorized under this Agreement is to
provide a firm estimate of the cost of tidal energy in relation to its altc:rna-
tives on which to base a d(;cision to proceed furthPr with detailed
investigations and engineering design.
2. The studies to be carried out shall be gnncrally in accordance with
the investigational program. schedule ;md terms of reference outlined by
50
the Bay of Fundy Tidal Power Revie\\. Board in its report. "Preliminary
Reassessment of Fl~asibility of Tidal Power Development in the Bay of
Fundy", elated September 1974.
3. The Bay of Fundy Tidal Power Review Board. established by the parties
hereto on February 29. 1972, and hereinafter referred to as "the Board",
shall oversee the conduct of the studies.
4. (a) The Board, for the purpose of this Agreement shall consist of six
members, two from each of the parties hereto. The members of the Board
arc:
For Canada: E. W. Humphrys, Senior Adviser
Electrical Energy, Department
of Energy, Mines and Resources:
Dr. A. E. Collin, Assistant Deputy
Minister, Fisheries and Marine
Service, Department of the Environment.
For New Brunsvvick: A. J. O'Connor, General Manager,
New Brunsvvick Electric Povver
Co mm iss ion:
For Nova Scotia:
Eldon Thompson, President,
Trans-Canada Telephone System.
L. F. Kirkpatrick, President,
Nova Scotia Power Corporation:
Dr. R. B. Cameron, President,
Nova Scotia Tidal Power Corporation.
(b) Chairmanship of the Board shall rotate from meeting to meeting
vvith the follovving order of rotation: a member for Canada: a member
for Nova Scotia, a member for Nevv Brunswick. This order shall be repeated
for the duration of the study.
(c) The term of a Chairman shall date from the termination of the
preceding meeting to the end of the meeting which he is to chair. The
Chairman for the first term following the date of this Agreement shall
be Mr. Humphrys.
(d) Meetings of the Board shall be held at least once every six months
from the date of this Agreement unless the members unanimously agree
to defer a meeting. The current Chairman shall, on the request of any
two members of the Board, convene a meeting vvithin two \veeks following
such a request.
51
(e) The members of the Board may name alternates to represent them
at meetings vvhen they arc unable to attend.
5. The Board will determine, as results of the studies become available,
whether or not it is justified to continue the studies to completion or
to terminate them at an earlier stage. In any event, all reports on the
studies authorized by this Agreement shall be submitted no later than
two years following the date of this Agreement.
6. (a) The cost of the studies shall be borne as follows: Fifty (50) per cent
by Canada, twenty five (25) per cent by Nova Scotia, and twenty five
(25) per cent by New Brunsvvick, and such costs shall include, but shall
not be limited to, administration, the cost of collection and analysis of
data, field surveys and the cost of consultants engaged as part of the
program. Salaries and related costs of federal and provincial civil servants
engaged in the program shall not be paid from funds approved under
this Agreement excepting staff specifically assigned to, or engaged in,
studies under this Agreement.
(b) Subject to the terms and conditions of this Agreement and subject
to funds being voted by Parliament, the aggregate sum to which Canada
shall be liable in respect of this Agreement shall not exceed $1,500,000.
(c) Subject to the terms and conditions of this Agreement and subject
to funds being voted by each of the Legislative Assemblies of New Bruns-
wick and Nova Scotia, the aggregate sum to which Nevv Brunswick and
Nova Scotia each shall be liable in respect of this Agreement shall not
exceed $75'0,000.
(d) This Agreement shall become binding on the date executed but costs
incurred subsequent to June 1, 1975, shall be eligible for sharing under
this Agreement,
(c) Each party shall keep complete records of all expenditures made
severally pursuant to this Agreement and shall support such expenditures
with proper documentation. The parties agree to make these records and
documents available to auditors appointed by each other.
(f) Canada shall assume responsibility for the funding of this Agreement;
the financial arrangements shall be established by the Committee.
(g) New Brunswick and Nova Scotia undertake to pay promptly,
accounts submitted for their share of the study costs.
7. To carry out the study programme under the general direction of the
Board, there is hereby established a Management Committee, hereinafter
called the Committee, composed of seven members, as follows:
52
For Canada: R H. Clark, Senior Engineering Adviser
Inland Waters Directorate,
Department of the Environment:
*C. K. Hurst, Chid Engineer.
Department of Public Works:
A. N. Karas, Assistant Director. (Planning)
National Energy Board.
For New Bruns·wick: Frank MacLoon, Manager, Power System
Development and Operation Division,
For Nova Scotia:
New Brunswick Electric Power Commission;
D. G. Hayward. Senior Hydraulic Development
Engineer. New Brunswick Electric Power
Commission.
**G. D. Mader. Vice President (Engineering},
Nova Scotia Power Corporation:
G. C. Baker, Director, Nova Scotia Tidal
Power Corporation.
The Chairman of the Committee shall be R. H. Clark. In the event that
Mr. Clark must relinquish the responsibilities of Chairman. the Board shall
appoint his successor. The members of the Committee may name alternates
to represent them at meetings when they are unable to attend.
8. Any of the parties may at any time, by written notice to the other parties,
substitute a member in place of one of its members under Article 3 or 7.
9. In conducting its investigation and performing its duties in accordance
\\'ith the Agreement, the Committee, subject to the concurrence of the
Board by way of budget or explicitly.
(a) may employ a Study Coordinator and such specialists, consultants
or other personnel as it may deem necessary:
(b) may incur such other expenses as may be required; and
(c) may pay for such services, employment and expenses out of funds
appropriated therefore.
*Mr. K. A. Rowsell. Program Manager, Marine, Department of Pohlic Works, replaced Mr. C. K.
Hurst, January 1976
**Mr. R P. DeLory. Manager, Project Diviston. Nova Scotia Power Corporation. replaced Mr.
G. D. Mader, with effect from December 10. 1975.
53
10. The Committee may utilize the services of employees of the departments
and agencies of the parties hereto. including engirwers, scientists and other
specialists, wherever in the opinion of the party concerned the services
of such employees are available.
11. The Board shall submit specific reports or recommendations with docu-
mentation to the parties hereto at any time as the progress of the studies
reveals information that may substantiate or negate the prospect of tidal
energy becoming a viable competitor vvith alternative energy sources.
12. The Board may recommend to the three parties, joint participation in
expanded studies, to include hydraulic model studies and engineering
design for construction should the results of the authorized studies con-
tinue to show tidal energy in a potentially competitive position taking
into account economic costs and environmental effects.
13. (a) Canada, New Brunswick and Nova Scotia shall exchange copies of
all reports and related available informstion from prior and current studies
for usc in the programme.
(b) This Agreement may from time to time be reviewed by the parties
hereto and may be revised as the parties hereto may unanimously agree.
(c) r\o member of the Parliament of Canada or the Legislativr: Assemblies
of New Brunswick and Nova Scotia shall hold. enjoy or be admitted to
any share or part of any contract, agreement. commission or benefit arising
out of this Agreement.
IN WITr\ESS WHEREOF, the Honourable Alastair Gillespie, Minister
of Energy, Mines and Resources has hereunto set his hand on behalf of
Canada, the Honourable Richard B. Hatfield, Premier of New Brunsv11ick,
has set his hand on behalf of New Brunswick and the Honourable Gerald
A. Regan, Q.C., Premier of Nova Scotia, has set his hand on behalf of
Nova Scotia.
Signed on behalf of Canada Alastair Gillespie
Minister of Energy, Mines and Resources
Signed on behalf of New Bruns\vick
Richord B. Hatfield
Premier of New Brunswick
Signed on behalf of Nova Scotia
Gerald A. Regnn
Premier of Nova Scotia
Date DECEMBEF 3, 1975
54
AMENDING AGREEMENT This Amending Agrcerrwnt made as of 24th June, 1977,
BETWEEN
Her Majesty the Queen in the Right of
Canada, hert!in acting through and
represented by the Minister of
Energy, Mines and Resources,
hereinafter called Canada,
OF THE FIRST PART
ller Majesty the Queen in Right of
Ne'.>v Brunswick, hereinafter called
New Brunswick.
OF THE SECOND PART
Her Majesty the Queen in Right of
Nova Scotia. hereinafter called
Nova Scotia.
OF THE THIRD PART
WHEREAS Canada. New Brunswick and Nova Scotia jointly established
the Bay of Fundy Tidal Powf'r Review Board in February, 1972;
WHEREAS the Bay of Fundy Tidal Povver Review Board examined the
conclusions of the October 1969 report of the federal-provincial Atlantic Tidal
Power Programming Board, in light of the then current and projected condi-
tions:
WHEREAS in its report to Governments in September 1975, entitled,
"Preliminary Reassessment of Feasibility of Tidal Power Development in the
Bay of Fundy." the Bay of Fundy Tidal Power Review Board concluded that
the economic position of Bay of Fundy tidal power had improved significantly
since 1969;
WHEREAS the Bay of Fundy Tidal Power Review Board recommended
that further study was required to determine whether or not the economic
viability gap bet1.veen tidal energy and fossil-fuel based energy had been or
\vas likely to be overcome;
WHEREAS Canada, as authorized by Order in Council P.C. 1975-3/2823
of December 2. 1975, entered into an Agreement dated December 3, 1975
(hereinafter called the "Study Agreement"), with New Brunswick and Nova
Scotia, providing for further study of the cost of tidal energy in relation to
the cost of alternative energy sources;
55
WHEREAS Canada, New Brunswick and \.!ova Scotia wish to expand
th!~ said study:
AND vVHEREAS Canada has been authorized by Order in Council P.C
1977-1511 of June 2, 1977. to enter into an Agreement vvith New Brunswick
and Nova Scotia amending the Study Agreement:
NOW THEREFORE the pHrties hereto covenant and agree with each other
as follows:
1. Article 6 of the Study Agreement is hereby amended by deleting paragraph
(h) thereof. and by substituting the following therefor:
"(b) Subject to the terms and conditions of this Agreement, and to the
provisions of section 33 of the Finonciul Administrution Act RSC 1970
c.F-10, the aggregate sum for which Canada is liable in respect of
its duties and obligations under this Agreement shall not exceed one
million eight hundred and twenty-six thousand dollars ($1,826,000)."
2. Article 6 of the Study Agreement is hereby amended by deleting paragraph
(c) thereof, and by substituting the following therefor:
"(c) Subject to the terms and conditions of this Agreement. and subject
to funds being voted by the Legislative Assembly of Nevv Brunswick
and by the Legislative Assembly of Nova Scotia, the aggregate sums
for which New Brunswick and Nova Scotia are liable in respect of
their duties or obligations under this Agreement shall not exceed, in
the case of Nevv Brunswick, nine hundred and thirteen thousand dollars
($913,000), and, in the case of Nova Scotia, nine hundred and thirteen
thousand dollars ($913,000)."
3. The Study Agreement as amended by this Agreement is hereby confirmed.
This Agreement shall be read with and be deemed to be part of the Study
Agreement.
56
ANNEXB
Phase II: Pre-Investment Design Program
The current studies have been carried out over the
past two years under the direction of the Management
Committee, whose report to the Board discusses in
detail all aspects of the investigations and analyses
leading to the foregoing conclusions and recom-
mendations. The Board recognizes that in carrying out
its responsibility to develop a firm estimate. of the cost
of tidal power and to assess the implications of
development of the last large remaining source of
renewable energy supply in the Maritime region it has
been necessary to forego pursuing in detail many
aspects of concern to society as a whole as well as
the detailed assessment of engineering aspects neces-
sary to specify completely a development. To a consid-
erable extent such omissions of detail have been delib-
erate inasmuch as the time and funds required for
successive refinements have been authorized only as
reasonable justification to proceed with each stage was
established.
Thus the Management Committee in pursuing the
studies to date have been conscious of the necessity
to justify each progressive stage of refinement, and
during the phase now completed have provided the
Board with progressive interpretations and oppor-
tunities to review the prospects for a favourable finding
at each stage of expenditure.
The first phase of investigations is now concluded
-defined as the Phase I program by the Committee
-and was carried out in three stages at a cost of about
$3.4 million.
The further investigations proposed properly iden-
tify several areas which are germane to the current
assessment of tidal power, but which embrace broad
issues beyond the usual scope of project evaluations.
Thus the projected role of tidal power within the future
energy systems of the Maritime provinces requires
confirmation of the assumed growth and mix of
generation supplies, particularly in the light of changing
perceptions regarding future energy availability and
use and in the light of constraint which may be im-
posed by economic conditions limiting investments in
the utility sector. This aspect is of particular concern
to utilities as preliminary studies suggest the system
investment demands would require such large borrow-
ings as to impinge upon the limits of debt servicing
likely to be available to the provinces.
The inclusion of these aspects in the scope of future
studies is done on the basis that unless they are under-
taken separately but concurrently they must be
considered in order to place a tidal power development
in proper perspective. That these questions should be
addressed is evident and there is an opportunity to
do so meaningfully from the specific base which has
been established from the current studies and the
studies carried out independently during the past year
to assess the advantages of the proposed Maritime
Energy Corporation.
The results of further analysis in these areas may
provide a model of use to other utility systems in
Canada.
The final design of a tidal power development at
Site A8 in the Cumberland Basin could be influenced
by consideration of the implications of future develop-
ments of other tidal power sites. Such considerations
could enter into determination of the choice of operat-
ing requirements and hence the type of installation
selected, transmission routes as well as consideration
of many aspects of construction facilities such as the
location and capacity of drydocks for caisson fabrica-
tion, turbine assembly facilities, borrow and quarry
sites and other specialized construction requirements.
Since all such facilities have been independently in-
Pre-Investment Design Program*
Cost Estimate -Thousands of Dollars
1. Data Base
11. Regime Modelling
111. Engineering Design
iv. System Design
v. Socio-Economic & Environmental
Studies
vi. Supplemental Studies of Sequential
Development at other Sites
Contingency 20%
Project Management 20'Yo
Allowance for inflation @ 7%
per annum
$2,675
3,980
8,250
1,600
1,500
1,000
$19,005
3,800
$22,805
4,560
$27,365
5,400
$32,765
*Costs estimated in mid-1977 for program covering the period
mid-1978 to mid-1981 with allowance for inflation.
eluded in each project estimate at this time some econ-
omies may be anticipated from multiple use and thus
some further study in parallel with thlo detailr~d
investigation and design of Site AS should be pursued
to assess the feasibility of sequential development of
Sites A6 and B9. Such assessments could be made
primarily through the application of the refined design
results for AS as these become available. However,
supplemental additions to the data base to prrn·ide
comparable information at each site may prove desir-
able and \Vorthwhile where it vvould prove cost dfcc-
tive to include such in the data base programs for AB.
To undertake the detailed studies and design of a
tidal power development a new hydraulic modelling
facility is required. Although other uses for such facili-
ties have not yet been identified, the lack of a suitable
facility in Canada, or elsewhere, suggests the facility
be located in the Maritime region. Before proceeding
with design and construction, the Board feels the
opportunity should be taken to evaluate the needs and
potential use of such a facility serving as a major
marine-oriented research institute. Siting such a facility
in the Maritimes would facilitate immediate testing and
evaluation of construction techniques as construction
progresses, should a decision to proceed with tidal
power development ensue.
57