AN ABSTRACT OF THE THESIS OF
Mark Ross for the degree of
Agricultural
and
Master of Science
in
Resource Economics presented on May
25,
1984.
Title: Opportunity Costs: Irrigation vs. Hydropower
Abstract approved:
In
^- «' " 'Bruce'A'/ McttTrf
recent years we have seen increasing
the allocation of PNW water resources.
are
vs.
conflicts
debate
In particular there
over using the river system for
electricity
production.
Denying
over
the
irrigation
hydroelectric
system water implies higher costs to electricity
consumers
as producers substitute more expensive nonhydro resources.
This
on
research looked at the impact of new
PNW electricity consumers.
assumptions
pumping
take
This was done under varying
demand response
of irrigation water.
difference
to
of
irrigation
and farmer
payments
for
The study also examined
the
between the current policy of allowing
all the water they need,
and a policy
farmers
in
withdrawals are limited in periods of low streamflow.
which
Simulations
were
run
to
determine
the
amount
electricity production lost because of
withdrawals.
results
of
were
then
used
in a series
of
These
simulations
to
estimate the economic impacts under the various assumptions
and policies.
It
was
electricity
order
of
found
that
consumers.
$200/acre
significantly
irrigation
caused
losses
to
In some cases this loss was on the
of
irrigated
land.
The
mitigated
under the
interruptible
loss
was
policy.
Farmer payments for irrigation energy also reduced the loss
to consumers.
Opportunity Costs:
Irrigation vs. Hydropower
by
Mark Ross
A THESIS
submitted to
Oregon State University
in partial fulfillment of
the requirements for the
degree of
Master of Science
Completed May 25, 1984
Commencement June 19 85
APPROVED:
Pro€'essor of Agricultural & Resource ETconomics in charge of
Major
_=;—v>^-
ts 7
Head of Department of Agricultural & Resource Economics
Dean of Graduates Schoo
Date thesis .is presented
May 25, 1984
AKNOWLEDGEMENT
I
would
like to take this opportunity to
thank
the
many people who have helped me in my program.
My major professor,
in
Dr.
Bruce A. McCarl, was crucial
providing a funded project to enable me to complete
program.
His
my
insights and encouragement were very helpful
(if at times frustrating).
I
would
committee,
Dr.
like
to
A.
thank
the
other
members
of
my
Gene Nelson, and Dr. Stanley F. Miller
for their patience and understanding as the project dragged
on through its many changes.
A special thanks to the following people at the BPA:
John Wilkins
John Dillard
Art Evans
Pam Marshall
Without
their
help,
the
project
would
not
have
been
completed.
To all of my fellow students and friends,
thanks and warm feelings.
Especially to Ann
a heartfelt
Wilson,
Andy
Gatti, and Kasi Beal who helped me through my operation and
the ensuing depression.
Most of all: thanks to my parents who always told me I
could accomplish whatever I set out to do. You were right.
TABLE OF CONTENTS
Page
I.
INTRODUCTION
II.
BACKGROUND AND THEORY
Physical Relationships
Economic Relationships
Interruptible Water Policy
III.. METHODOLOGY
Electricity Loss
Economic Analysis: Inelastic Demand
Noninterruptible Model
Interruptible Model
Economic Analysis: Elastic Demand
Supply Conditions
Demand Conditions
Market Equilibrium
Change in Consumers' Surplus
IV.
RESULTS AND CONCLUSIONS
Energy Losses
Economic Results
General Results
Noninterruptible Policy
Interruptible Policy
Comparison of Policies
Conclusions and Implications
1
10
10
12
21
23
23
29
30
31
33
33
34
36
37
40
40
43
43
44
52
61
62
BIBLIOGRAPHY
74
APPENDIX
76
LIST OF FIGURES
Figure
Page
1-1
Annual Streamflov/ - Bonneville
Dam
4
1-2
Hydro System Generation
5
II-l
Demand Models
14
II-2
Average Price
18
III-l
Map of Development Areas
25
LIST OF TABLES
Table
Page
1-1
Streamflow Probabilities
7
III-l
Characteristics of Development
Areas
24
IV-1
Generating Loss
41
IV-2
Noninterruptible Policy
East High
47
IV-3
Noninterruptible Policy
Umatilla II
48
IV-4
Noninterruptible Policy
Horse Haven Hills I
49
IV-5
Noninterruptible Policy
Grande Ronde
50
IV-6
Noninterruptible Policy
Combined Areas
51
IV-7
Interruptible Policy
East High
55
IV-8
Interruptible Policy
Umatilla II
56
IV-9
Interruptible Policy
Horse Haven Hills I
57
IV-10
Interruptible Policy
Grande Ronde
58
IV-11
Interruptible Policy
Combined Areas
59
IV-12
Comparison of Policies
East High
66
IV-13
Comparison of Policies
Umatilla II
67
IV-14
Comparison of Policies
Horse Haven Hills I
68
Page
IV-15
Comparison of Policies
Grande Ronde
69
IV-16
Comparison of Policies
Combined Areas
7
0
OPPORTUNITY COSTS: IRRIGATION VS. HYDROPOWER
I. INTRODUCTION
The
valuable
Columbia
River
resources
in
Northwest.
however,
the
As
major
used
increases
development
and economic
uses of
generation,
fisheries support,
is
in
tributaries
the
the
growth
and recreation.
to
one
river
irrigation,
control
continue,
system
are
the dam
In
the
future,
use may well diminish the
use
of
amount of hydroelectric
the
For example, increasing
reduces
the
power that can be generated.
recent years we have seen public concern regarding
allocation
of
river
waters in the
region.
The
current
debate over irrigation development in the East High
of
At
transportation,
levels for the needs of migratory fish
In
been
Pacific
Additionally,
flooding.
rivers for one or more other uses.
water
of
have
to these resources are being reached.
time
hydroelectric
system
the
population
limits
present
and its
Washington
Another
is
for irrigated agriculture is
the
continuing problem of
one
meeting
region
example.
projected
increases in electricity demand. Since much of the region's
electricity
is
river,
removal
areas)
will
therefore
sources.
an
produced at hydroelectric dams
along
of
(or
result
water to develop East High
in a
increase
loss
of
hydroelectricity
in the need for power
(Whittlesey et'al,
from
the
other
and
other
1981). The Oregon legislature
has
recognized
writing,
that
such conflicts
exist.
As
of
there is an effort underway to establish
this
minimum
streamflows subject to competing uses as mandated by Senate
Bill
SB-225.
establishes
There
is also a recently enacted bill
a multiagency water planning group that
among
other things,
water
management plans,
will,
create basin and possible state
including processes to
that
wide
identify
present and emerging water use conflicts (SB-523).
Clearly, there are social tradeoffs between irrigation
and hydroelectric generation. Water used in irrigation will
usually
result
in
hydroelectricity
portion
reduced
will
hydroelectricity.
lead to higher prices,
Lost
since
of the lost power will be replaced by more
some
costly
thermal generating sources (Whittlesey and Gibbs, 1977).
The question is then:
"How is the welfare of
society
best served?" To answer that it is necessary to compare the
costs
and
benefits
irrigation.
investment
1979).
costs
would
society
come
from
from
due
to
Benefits
The
first
the change
would
in
increased
the
and from the higher prices paid by
consumers
methods.
The
accruing to
irrigation
electricity
electricity
come from two
sources
would be the increased supply
production
(Martin,
of
food
grown on the now irrigated acreage. The second would be the
change
arise
in
to
income from the land.
those whose incomes are
Costs and benefits
affected
by
also
increased
irrigated production.
This
study will focus on the the cost in terms of the
electricity
consumers.
Whittlesey
and
Whittlesey
et
Gibbs
al
(1977) ,
(1981),
conditions
of
electricity
prices.
will
This
has
been
done
Obermiller
inelastic
That is,
assume
of
its price.
electricity
and
problem
demand
under
response
they assume that
continue to purchase the same amount
regardless
(1980) ,
all look at the
perfectly
before.
of
It would be more
to
consumers
electricity
realistic
consumers would respond to
to
increasing
prices by purchasing less electricity.
Virtually
additional
Critical
system
all
water withdrawals are at critical flow
flow levels are those water levels in
that
are equivalent
February 1932,
above
the
river
to the period August 1928
to
the lowest flows on record. However, levels
in the future.
range
of
levels.
critical flow are the norm and are to be most
expected
full
studies which evaluate any effects
This study will
often
incorporate
of observed flows to better gauge
the
the
actual
be
quite
Over the thirty year
period
results of a given change.
Streamflow
variation
across
substantial (see Figure 1-1).
from
1929 to 1958,
averaged
177,421
time
can
the yearly discharge at Bonneville Dam
cubic
foot
seconds.
However,
the
distribution was fairly wide - the coefficient of variation
was
19% (PNRBC,
consumers,
1970) .
The implications for
and therefore society's welfare,
electricity
can be
quite
significant. Figure 1-2 shows the fluctuation in hydropower
resulting from the BPA simulation model used as a source of
ANNUAL STREAMFLOW - BONNE VILLE DAM
(1000 CFS)
280
230
180-
130-
Y.EAR
FIGURE I-l. Annual streamflow — Bonneville Dam.
HYDRO SYSTEM GENERATION
(1000 ave. MW/year)
01
o
^t
a>
o
in
O)
YEAR
FIGURE 1-2.
Hydro system generation,
o
ID
o»
00
<D
<n
data within this study.
The variation in streamflow (i.e. - amount of water in
the
river
welfare.
system)
This
electricity
run
the
is
is important
in
estimating
because the average cost
of
varies with the amount of water
hydroelectric turbines.
increases,
electricity
expensive
thermal
hydroelectric generation,
producing
available
As the amount
producers
generation
societal
can
to
switch
the
of
lowering consumer
water
from
less
to
more
expensive
prices.
Thus
the variation in water flows will be incorporated into this
research.
The
generation
levels
computed
probabilities
due
to
of
selected
underlying
hydropower
streamflows
were
using BPA simulation data to gain a sense of
the
likelihood of seeing given streamflows (see Table 1-1).
If
the water levels drop low enough,
the demand
for
electricity might exceed the available generating capacity.
New
thermal
constructed,
generating
pushing
plants
would
then
need
up the price of electricity
to
in
be
all
years as the construction is amortized. The current cost of
producing
hydroelectricity is about one tenth of the
cost
of producing it with new thermal plants (NPPC, 1983).
Under current law (BPA, 1980), consumptive uses of the
river
system,
such
as
irrigation,
have
instream uses such as electricity generation.
that
of
in periods of low streamflow,
priority
over
This implies
when the imputed value
the water is higher to electricity
consumers,
farmers
TABLE 1-1:
STREAMFLOW PROBABILITIES
Hydro Level(ave. MW)
Probability (%)
11960
12960
13960
14960
15960
16960
17960
18960
5
14
29
50
70
85
94
98
(1)
(2)
(1) These are the annual hydropower generation of the
present system for particular underlying streamflows.
(Without withdrawals.)
(2)
These are the computed probability of seeing an underlying
streamflow that is less than or sufficient to produce the
indicated level of hydropower.
8
are
implicitly being subsidized by electricity
Therefore
of
consumers.
consumers should be willing to pay some
that
subsidy
available
to farmers in order to
for electricity production,
eliminated
the
need
have
portion
the
water
particularly if
for construction of
new
it
generating
plants. Farmers, of course, would want that compensation to
at
least
equal
the
benefits
they
would
expect
from
irrigation. Such a payment would meet the criterion for the
Kaldor - Hicks compensation test,
policy
which states: "...that a
should be accepted if those who gain by the
could
policy
fully compensate for the welfare losses of those who
lose by the policy"
The
purpose
(Freeman, 1979 p55).
of
this
research is
to
gain
greater
insight into selected tradeoffs involved in allocating
river water to competing uses.
between
Specifically, the tradeoffs
hydroelectric generation and increased
development
will
be
PNW
examined in terms of
irrigation
the
costs
to
cost
to
electricity consumers.
This
will
be done by estimating the social
electricity
consumers of new irrigation under
streamflows
and demand conditions.
will
also be examined.
alternative
Interruptible policies
The social cost under the
current
noninterruptible policy will be compared to the social cost
under an interruptible policy where limitations are
placed
on how much water farmers can take under low streamflows.
The procedures to be used in meeting the objectives of
this research are:
1. To construct an estimate of the loss of
hydroelectricity associated with various
proposed irrigation developments.
2. To construct an estimate of the new average
price of electricity facing consumers,
given the new irrigation development. This
would be under both the current
noninterruptible policy, as well as a
potential interruptible policy and varying
farm payments for pumping energy.
3. To construct an estimate of the new market
clearing quantity of electricity in the
region, given the irrigation development
(under both policies and varying farm payments
for pumping energy).
4. Estimate (2) and (3) under varying demand
conditions.
5. Estimate (1) through (4) under varying
streamflows.
6. Estimate the expected value of the change
in consumers' surplus under the two policies.
7. Compare the change in consumers' surplus
estimated in (6).
10
II. BACKGROUND AND THEORY
Physical Relationships
Underlying
physical
any
economic
relationship is
relationships.
In
a
the
set
of
case
of
irrigation/hydropower tradeoffs, the physical relationships
involve
the amount of water diverted from instream use
electricity
generation,
to
use in
developing
in
irrigated
acreage.
There
are
irrigation
these
a
number of factors
encouraging
development in the Pacific
further
Northwest.
One
of
is the Congressional mandate specifying "...that
in
those areas lying ... west of the 98th meridian,
[instream]
uses must not conflict with any beneficial consumptive use,
present
or
future.
consumptive
uses
irrigation."
(BPA,
Certainly
from
the
one
of
Columbia
the
most
River
common
System
is
1980 p. 1-13) Such a regulation reduces
the risk of those who wish to develop irrigated cropland.
Economic
well.
The
farmers'
be
costs.
to develop irrigation include
costs,
pumping
energy
only
as
the
costs,
and
The water itself is not paid for (King
1978). This means that any welfare loss incurred by
electricity
not
costs
capital
application
et al,
incentives exist for farmers to irrigate
consumers as a result of the diversions
fully
irrigating.
reflected in the
Certainly,
costs
farmers
would
incur
in
the strongest incentive to farmers
11
is the expected increase in profits that they would receive
from
irrigated over dryland farming (Whittlesey and Gibbs,
1977;
Obermiller 1978,1980;
Whittlesey 1981) .
Although a
farmer may or may not be aware of the other considerations,
he must surely be aware of the results of his decisions
on
his profits.
The
magnitude of new development is potentially quite
sizable.
Over 2.2 million acres of current dryland in
Pacific
Northwest
have
irrigation (King et al,
estimated
that
approximately
been identified as
1978).
5.3
million
suitable
If fully developed,
this would result in a
acre-feet
net
of
the
for
it is
depletion
water
of
annually
(Whittlesey et al, 1981).
The
physical sequence of interactions resulting
increased
withdrawals
straightforward.
of
the
irrigation
return
flow,
volume
of
is
As withdrawals increase,
(level of water in the river),
of
water
most
from
conceptually
the
streamflow
is decreased. Although some
water comes back into
of it is does not.
water available for other
the
This
uses.
rivers
reduces
time
since there are storage pools
with most of the dams along the rivers.
act
as storehouses of potential
cannot be stored directly,
the
Hydroelectric
generation is not dependent upon natural streamflow at
particular
as
any
associated
These pools partly
electricity.
but having the pools
Electricity
available
allows electricity generation to coincide with demand. Lost
water
means
that the turbine blades can be turned
for
a
12
shorter time, or in some cases, not at all. This of course,
means
a reduction in the total amount of electricity
that
can be generated.
If
for
there were a substantial number of sites available
construction of additional large
projected
such
generate
more electricity.
is
dams
and reusing the
The
available
water
This was done for many
no longer possible due to the
sites.
dams,
shortfalls in electricity supply could be met by
building
but
hydroelectric
lack
of
to
years,
available
shortfall must then be met by other sources of
electricity generation. In practice this means some kind of
thermal
electricity
generation.
The
range
of
choices
includes: oil fired steam or turbine, coal fired steam, gas
fired
turbine,
and
nuclear
fired
steam.
Engineering
considerations would cause some combination of these
kinds
of plants to be chosen.
Economic Relationships
The factors influencing the demand for electricity
the
region are well identified,
in
although estimating their
aggregate be difficult. As a consequence, previous analysts
(Whittlesey
and
Whittlesey,
1981)
electricity lost,
Gibbs,
have
1977;
Obermiller,
1978,
looked only at the value
that is,
1980;
of
the
at the opportunity cost of the
withdrawn water. Opportunity cost is defined here to be the
cost
of
producing
substituting
electricity
the
next
for the
lowest
foregone
cost
method
of
hydroelectricity
13
generation.
This
is equivalent to looking at a
perfectly-
inelastic demand function.
A price inelastic demand function is defined to be one
for which the change in quantity demanded is less than
one
percent for each one percent change in the good's price. In
the case of perfect inelasticity, the change in quantity is
zero, regardless of the magnitude of the price change. This
says that the amount of the good demanded is independent of
its price.
In
contrast,
inelastic
a demand function that is not perfectly
is one for which there is a change
demanded
with a change in the good's price.
in
quantity
A graph of
a
demand function that is not perfectly inelastic will show a
negative
slope,
while
a graph of a
perfectly
inelastic
demand function will show a vertical line (see Fig.
Thus,
show
a
a
good
that is not perfectly price inelastic
decrease
increases.
II-l).
in the quantity demanded
as
its
will
price
This is what we observe with most market goods,
including electricity.
Given that lost hydroelectricity generation
will,
to
some extent, be replaced by thermal generation, it is clear
that overall costs of electricity generation will increase.
This
is
because
generating
an
new thermal generation costs
more
equivalent amount of electricity
than
with
the
between
the
current hydroelectric system.
To
price
properly
estimate the
relationship
of electricity and the amount utilities will supply.
14
PRICI
DEMAND
fl
CHANCE IN
CONUMERS' SURPLUS
«2
QUAKIITil
PRICI
DEMAND
#1
#2
\
V
CHANGE INJ
CONUMERS SURPLUS
QUANTITV
FIGURE II-l.
Use changes in consumers' surplus.
15
we must specify an average cost function.
free
Most goods in
a
market economy can be modelled with a supply function
derived
from
a marginal cost
function.
market is highly regulated however.
The
electricity
The regulations
allow
to meet their costs without gaining any "excess1
utilities
profits (i.e.
- rents).
The investor owned utilities
allowed
to add a modest profit to their costs
1979).
Rates
are
then
set
at
the
(Mansfield,
average
cost
production,
including
this
uses an average cost function in lieu
study
the allowed 'profits.
are
of
Consequently
of
the
supply function usually used in comparative statics.
Because
of the large number of electricity
producing
facilities
and the complex interutility sales
that
occur,
is
the
it
extremely
difficult to relate
production process to the final sale.
are
In
often
actual
addition,
there
highly complex technological relationships that
often
change.
In
order to do the analysis it is therefore necessary
to make some simplifying assumptions. The first is that all
hydroelectric
demand
resources will be used to
satisfy
consumer
before more expensive thermal and import resources.
Although
it
is
not
to
be
strictly
true,
it
reasonably
assumed that decision makers will use
relatively
low
cost hydropower in their power
can
as
be
much
generating
mix as possible (BPA, 1983a) .
The second assumption relates to the cost factors used
in
the
economic
analysis.
Due
to
the
difficulty
in
16
obtaining
plants
detailed
in
the
cost data on all
region,
it
relevant
is not
possible
reasonably
accurate estimate of the unit and
associated
with
plant.
each plant,
Therefore,
estimate
(NPPC,
for
the
generating
to
fixed
nor even with each
Northwest
make
the cost of producing
costs
type
Power Planning
hydropower
a
of
Council
was
used
1983), and aggregate BPA data were used to estimate
the cost of providing electricity from nonhydro sources and
for estimating system fixed costs.
(For details on sources
and
derivation of all input data for the economic analysis
see
the
Appendix.)
production,
except
administrative
The
result
for
is
ancillary
expenses
that
all
fixed
costs
and
transmission
not
likely
costs
of
such
as
costs,
are
introduce
much
considered variable.
This
assumption
distortion
'close'
into
to
introduce
the
bias
is
the results
when
initial starting
into
to
estimating
conditions
conditions,
those analyses
that
but
look
extreme conditions of water level and diversions.
be
seen
by
function
cost
looking
in the electricity market.
components
numerator.
Three.)
(The
Any
generating
increase
costs
at the nature
as
model
increase
sources
the
multiplicative
an
in
the
associated
more
This can
average
arguments
relative
with
at
cost
It has the individual
is presented formally
overall average price.
are overstated,
of
could
in
in
Chapter
amounts
these
the
of
costs
the
will
Since the
variable
the greater the change in
resource
17
mix
due
to
estimated
more
extreme
changes
in
conditions,
the
price and quantity
greater
than
the
would
be
addressing
is
expected with 'real' resource costs.
One
of
whether
the
there
generating
questions this study
will
capacity
withdrawals.
This
generating
be
a
need
for
as a result of
implies
capacity
will
is
a long
more
electricity
increased
run
require
irrigation
context,
that
as
new
new
thermal
generating plants be constructed.
To
under
determine
conditions
recognize
the
the equilibrium prices
of
varying demand it
and
is
quantities
necessary
that the amount of electricity purchased
to
equals
amount of electricity sold and that the price paid
by
consumers is the price received by utilities.
As
water
production
withdrawals
from
nonhydropower,
cause a shift
lower cost hydropower to
as
electricity
more
expensive
the average cost will be greater to produce
a given amount of electricity (see Fig.
cost
in
II-2). The average
will be affected by natural variations in
well as by any water withdrawals.
streamflow
Figure I1-2 is drawn
assuming a given streamflow in order to isolate the
effect
of withdrawals.
Given
that both the demand and average cost functions
have two variables for which values need to be
price
and
unknowns
quantity,
can
determined,
the system of two equations
be solved simultaneously.
This is
in
two
done
by
first solving the two functions separately for price.
This
18
e.
Nith MithdPAyah
\
Without ^C^V
Uithdrawals ""-\:
\
Quantity
AVERAGE PRICE
FIGURE II-2.
Price change due to withdrawals,
19
results
in:
supply price,
demand price,
P
= f[quantity supplied]
P, = f[quantity demanded].
and
Since the supply
price equals the demand price in equilibrium: P
= P-,. This
then
f[quantity
implies
that
f[quantity
supplied]
=
demanded]. Further details and derivations will be found in
Chapter Three.
One
measure
consumers
will
of how much the welfare
change
under
of
increased
electricity
irrigation
provided by the change in consumers' surplus.
a direct measure of the change in utility,
measured
in any case,
Although not
which cannot be
the change in consumers' surplus is
nonetheless
a widely accepted measure associated with
change
utility
in
experience
is
that
electricity
with increased irrigation
the
consumers
would
withdrawals.
(Just,
Hueth, and Schmitz, 1982).
Consumer's
between
what
the
is defined to be
the
area
difference
what
is
In a geometric analysis this is represented
area above the price line and to the left
demand function (see Fig.
areas
the
the consumer is willing to pay and
actually paid.
by
surplus
II-l).
of
In the aggregate,
the
these
for individuals are summed. Therefore, in looking at
market demand function,
above
function.
the same measure
the price line and to the left of
It
should
be
noted
that
this
holds:
the
the
demand
assumes
that
individual consumers are not associated with specific units
of the good purchased.
then
the
The change in consumers' surplus is
difference between the area measured before
the
20
price change and the area after.
When
looking at the change in consumers'
electricity consumers,
surplus
to
it is important that new irrigators
not be included in with them. To do so would understate the
change in the electricity market.
However, the electricity
that farmers pay for should be included when estimating the
new
average
price
if
farmers
are
charged
the
market
clearing price along with other consumers.
Farmers
pumping
upon
In
may in fact pay for differing amounts of
energy
used.
How much they pay for would
depend
the particular arrangements in the development
some
cases,
they
would pay for all
of
the
area.
pumping
energy.
In others,
others,
they might only pay for the energy required to get
the
water
This
is
they might not pay for any.
the
from the 'farm gate' to the
common
crops
In
still
themselves.
in land developed with support
from
the
Bureau of Land Management.
Once
is made,
an estimate of the change in consumers'
surplus
it would then be necessary to compare the loss to
consumers
with
irrigation
the gain to irrigators to see if
withdrawals
are
beneficial to
the
society
new
as
a
whole.
The
this.
Kaldor/Hicks
Simply
put,
compensation test can be
this
test asks if
the
irrigation are able to compensate the losers,
electricity
compensation,
consumers.
It
does
only the potential for
not
used
gainers
for
from
in this case
require
compensation.
actual
Thus,
21
the
gainers
must get more from irrigation than those
lose because of the irrigation.
If this were not the case,
there would be a net loss to society as a whole.
be
noted
that'
the Kaldor/Hicks test and
the
consumers'
surplus can only measure pecuniary
society's
welfare.
Kaldor/Hicks
This
who
paper
does
not
It should
change
in
changes
in
make
the
test since the agricultural benefits are
estimated.
(Readers
interested
in
the
background
of the Kaldor/Hicks test are referred to
not
assumptions
and
Just,
Hueth, and Schmitz, 1982, or Freeman, 1979.)
Ihterruptible Water Policy
If excess electrical generating capacity does not
exist,
the
increases
in irrigation withdrawals might
construction of new generating facilities.
This would
happen
when water flows were sufficiently low for
enough
period
that hydroelectric and
thermal
require
a
long
generating
capacity would not be enough to meet projected demand. This
involves
the
concept of critical flows mentioned
in
the
previous chapter.
Thus
as electricity demand and irrigation withdrawals
increase,
the limits of electrical generating capacity may
be reached.
As withdrawals lower the effective streamflow,
critical flow levels may be approached. If in fact they are
reached,
new
thermal plants will be needed to supply
the
projected shortfall.
If,
however,
the
shortfall could be
eliminated
or
22
reduced by denying irrigation withdrawals, the new capacity
would not be necessary.
electricity
market.
arrangements
with
Such a precedent exists in the PNW
Some
utilities
certain
have
customers
contractual
that
allow
the
utilities to reduce the amount of electricity sold to those
customers when possible shortfalls exist.
contracting
In
return,
the
customers are charged less for that portion of
their power they purchase as "interruptible."
This
suggests
an analogy to
the peak
load
pricing
model in the electricity market where "...peak users should
pay
marginal operating costs plus marginal capacity
and
off-peak
users
should pay
only
marginal
costs
operating
costs." (Joskow, 1976 p. 198)
This leads to the second policy to be
examined.
This
is an interruptible policy where irrigation withdrawals are
limited
to
electricity.
levels
In
hydroelectricity
that
this
will
model,
not
cause
power
used
shortfalls
for
of
replacing
lost due to irrigation is not charged
at
the average cost, but at the marginal operating costs of an
average
PNW
coal
plant.
This will have
the
reducing the losses to electricity consumers.
effect
of
23
III. METHODOLOGY
Electricity Loss
There
are
development
in
his
research.
Umatilla
II,
III-l).
possible
in the PNW.
independently:
would
many
sites
for
Whittlesey identified
High,
Horse
Haven
were
chosen on the basis of
from the mouth of the river,
(TDH).
the
possible
Hills
of
those
I
(HHH),
and Grande Ronde (see Table III-l and Figure
impact hydroelectric generation:
head
forty-four
This study will look at four
East
These
distance
irrigation
factors
size of the
and
total
The larger the development area,
acreage
to
be
put
under
that
area,
dynamic
the greater
irrigation
and
therefore the greater amount of water required. The further
upstream
the withdrawals occur,
flows through,
the fewer dams the
resulting in a greater loss of
water
electricity
generation. TDH is the total pump lift required to take the
water
from
height
the river to the cropland.
It depends on
and distance the water is pumped,
operating
as well
pressure of the irrigation system.
The
the
as
the
greater
the TDH, .the greater the loss of generated electricity used
in pumping.
The
volume
of
constant over time.
control
short
primarily
This
flow
water
flowing in the
river
not
Although storage pools can be used
run fluctuations,
the
yearly
has
an
impact
on
the
to
streamflows
depend upon the precipitation during that
variation
is
year.
amount
of
TABLE III-l:
firea
State(s)
CHARACTERISTICS OF DEVELOPMENT AREAS
Acres
Pump
Lift (ft)
Diversions
(1)
Return
Flowsd)
794,392
31,817
196,350
John Day,
McNary
John day
25.8
109,300
10,933
98,367
John day
John Day
13.5
74,068
7,410
66,658
Lower
Granite
Lower
Granite
13.
1,643,602
487,335
1,156,267
310,000
690
1,242,067
447,175
norse
Haven
Hills
Washington
70,000
865
218,167
Uniatiila II
Oregon
40,000
900
Grande
fonde
Oregon
38,000
380
458,000
1. Acre - feet oer year
2. Average oegawatts per year. This figure is the amount of electricity
reouired to PUED the indicated diversion.
SOURCE: Mhittlesey et al., 1981
Pumping
loss(d)
HcNary<50<)
Priest
RaDids(50X)
Washington
Washington,
Oregon
Point of
Return
Grand
Coulee
East
High
Combined
Areas
Net
Point of
Depletiond) Diversion
143.0
25
LEGEND:
1
2
3
4
-
EAST HIGH
HORSE HAVEN HILLS
UMATILLA
GRANDE RONDE
FIGURE III-l : DEVELOPMENT AREAS
(After Whittlesey et al, 1981)
26
electricity
generated
at
the
dams.
streamflow,
the
This
study
will use the yearly flows,
uses,
over
the
The
less electricity that can
period 1929-1968 for
lower
be
the
generated.
adjusted for
sample
data
1983
(BPA,
1983c) .
To determine the loss for each of the study areas,
is
necessary to identify those dams that would
reduced
the
of
1981) .
A
portion
percolates
area.
The
water withdrawn for irrigation is not equal
amount lost for hydroelectric generation
into
experience
water because of withdrawals from that
amount
of
the
water
applied
it
to
(Whittlesey,
to
the
crops
into the water table and ultimately comes
the river system as return flows (Table
back
III-l).
The
return flow may or may not enter the river at the pool from
which
the
it was drawn.
area
subtract
dams
in
This will depend upon the geology
which it is
applied.
is
necessary
the return flows coming in above the
from the withdrawal figures.
depletion
It
affecting
the
of
to
appropriate
This will yield the net
appropriate
dams
(Whittlesey,
1981) .
Withdrawals
nor
even
require
are not made evenly throughout the
throughout the growing season.
varying
amounts of water at different
their life cycle (Soil Cons.
total
Ser.,
crops
points
water on a monthly basis gives the
a given month.
in
1970). Multiplying the
net depletion for a given year by the proportion
applied
for
Different
year,
net
of
depletion
Since the water year is divided
into
27
fourteen months (there are two April and two August periods
of fifteen days each),
application
the SCS data for monthly irrigation
percentages
were modified.
For those
months
that are divided, the percentages were also divided.
Having
determined
the
net depletions
associated with the given area,
at
each
dam
the generation loss can be
computed. Each dam is operated according to a 'rule curve1.
This rule curve is designed to operate both the dam and the
river
system
account
which
as efficiently as possible.
It
takes
both the available water and the various
it
will
be put.
This study will
not
into
uses
to
attempt
to
investigate changes in rule curves, but only the changes in
electricity
generation associated with incremental changes
in water availability caused by irrigation.
Thus, the rule
curve is assumed to be given and constant. This will result
in
each dam in the simulations being operated in the
same
way regardless of the amount irrigation withdrawals.
The generating loss is computed by multiplying the net
depletion at a dam by its
is
a
figure
generation
water
gained
and
the
yields
over K' factor (H/K).
the
or lost for an
availability.
month,
from
that
'H
amount
Columbia Rivers.
electricity
incremental
change
Each H/K is specific to a given
streamflow in the study.
BPA
of
The H/K
H/K's were
for nineteen major dams on
the
in
dam,
obtained
Snake
and
There are 560 H/K's for each dam, ordered
by month (14) and year (40).
The
data for withdrawals and return flows were
taken
28
from
Whittlesey
et al (1981).
They were
converted
from
acre-feet to cubic foot-seconds in order to give the proper
units when used in the model.
To determine the total generating loss associated with
a given development area and a given yearly streamflow, the
losses
from
those
dams
streamflow are summed.
loss
is
associated with
that
area
The expected size of the generating
useful in estimating the pecuniary value
diverted water.
and
of
the
It is defined to be the average generating
loss taken over the forty year study period.
The generating loss model for a given area is:
a) GENLOS
y
= IT. [ (HK
) • (MOPROP )•[ (D )■ (DIVER )]
md
myd
m
Id
d
.-[ (D ) • (RETURN ) ] ]
2d
d
where:
GENLOS
= generating loss at the streamflow
y
associated with water year y [ave.
MW/year]
HK
(y = 1929...1968)
= H/K for dam d and streamflow y in
myd
month m [KW/cubic foot-second]
(d = 1. . .19, y = 1929...1968,
m = 1...14)
MOPROP
= the proportion of the yearly withdrawal
m
in month m (m = 1...14)
DIVER
= amount of withdrawal from dam d
d
(d = 1. . .19)
RETURN
[cfs]
= return flow through dam d (d = 1...19)
d
[cfs]
29
D-]^ = 1 if dam d is downstream from point of
withdrawal, 0 otherwise
09^
= 1 if dam d is downstream from
point
of
return, 0 otherwise
b)
AVLOS = (1/40)•(
GENLOSy)
where:
AVLOS = average generating loss for the
given area over the 40 year study
period
GENLOSy = as defined above
Economic Analysis: Inelastic Demand
In
order
to estimate the societal cost of
the
lost
hydropower, it is necessary to compute the change in price.
An average pricing scheme was used for reasons explained in
the
previous chapter.
In the case of completely inelastic
demand it is not necessary to compute a new quantity, since
under
the assumption of inelasticity,
the
will be demanded regardless of its price.
lost
gas
same
quantity
In the PNW,
hydropower will be replaced with some combination
or
oil fired turbine,
coal fired steam,
or
the
of
nuclear
powered steam. The levelized cost of this new generation is
estimated
to
(NPPC, 1983) .
be approximately 40
mills/KwH,
on
average
30
Noninterruptible Model
The
average
pricing model for
the
noninterruptible
policy is:
PI = (FC + CH-(H - AVLOS)
+ CN-(NI + AVLOS))/(QF + d-PUMP)
where:
PI = new average price of electricity [mills/Kwh]
FC = system fixed costs
CH = average levelized cost of hydropower
[mills/Kwh]
H = net amount of hydropower given
streamflow without withdrawals [Kwhs]
AVLOS
=
average generating loss over the
study period [Kwhs]
40
year
(see Generating Loss,
above)
CN = average
levelized cost of nonhydro
resources [mills/Kwh]
NI = net amount of nonhydropower
(= QF + PUMP - H)
[Kwh]
QF = forecast electricity demand [Kwh]
d = the proportion of pumping energy paid for
by farmers
PUMP = the pumping energy used by farmers in
getting water from the river to the
cropland
[Kwh]
(Whittlesey
et
al,
1981)
(For derivaion and sources of input data, see the
Appendix.)
31
This formula is a weighted average of the fixed costs,
the
value
of
nonhydropower
practice,
some
also
used
to
there
This
meet
the
and
the
value
region's
of
the
needs.
(In
is sufficient hydropower
holds
to
meet
all
for the remaining models as well.)
takes into account the amount of pumping energy
farmers
model
at
hydropower,
the model is slightly more complicated, since in
cases
needs.
the
actually
pay for.
It should be noted
the
market clearing price is included in
that
that
assumes that pumping energy not paid for by
It
this
farmers
the
average
price paid by all consumers, including farmers.
Interruptible Model
The
interruptible
different approach,
average
of
simulation
requires
a
somewhat
although the model is still a weighted
different costs.
In this model,
the
maximum
amount of generation is fixed at the total
hydrogeneration
available
the
nonhydro
at
the
given
streamflow plus
amount
power necessary to meet the region's needs
of
under
critical conditions.
First, the simulation tests to determine if the farmers
can take any withdrawals.
forecast
that
demand
would
This is done by subtracting
for electricity plus the generating
arise from withdrawals from the
generation at the given streamflow.
total
the
loss
system
If the system can meet
all needs for power and irrigation, the farmers are allowed
to take the water. The amount that they are allowed depends
32
upon the capacity of the system at the given streamflow.
The
simulation
then
computes
the
amount
of
nonhydropower resources that will be required. This is done
by subtracting the amount of hydropower plus the generating
loss from the forecast electricity demand.
The interruptible model has an additional category
power.
This
power.
It
is
is
what will be referred to
the
power that the
as
of
replacement
electrical
generating
system must produce in order to replace the hydropower lost
to irrigation.
take
water
streamflow
In those years that farmers are allowed
it is equal to the generating
situations
needs from hydropower.
it
loss.
may be possible to
If this is the case,
In
supply
high
all
there will be
no need for either replacement power or nonhydropower.
The average price is then found by:
PI = (FC + CH-(H - AVLOS) + CN-NI
+ CR-R)/(QF + d-PUMP)
where:
CR = cost of replacement power [mills/Kwh]
(see Appendix)
R = QF + PUMP - (H -AVLOS) - NI
= the amount of replacement power [Kwh]
All other variables are as defined in the
previous model.
to
33
Economic Analysis: Elastic Demand
It
the
would be more realistic if the simulation
quantity
average
of electricity demanded to decrease
price increases.
as
the
This is what we would expect
happen in the electricity market itself.
necessary
allowed
to
To do this, it is
to examine the relationship between
the
supply
and demand sides of the market under assumptions of elastic
demand.
Supply Conditions
The
electricity
currently sold in the
region
comes
from several sources: publicly owned hydropower and thermal
plants, privately owned hydropower and thermal plants, with
minor
supplies
from long term import contracts
and
wind
generated power.
As in the previous analyses, a weighted average of the
different
is
costs incurred in generating the region's
used to estimate the new supply price for
power
electricity.
Under the elastic assumption the quantity to be supplied is
no
longer fixed,
term
to
simulate
so the model must incorporate a variable
the consumers'
accomodation
to
price
changes. The model is:
PE = (FC + CH-(H - AVLOS)
+ CN- (QF - H - AVLOS) ) / (QE - ((1 - dpPUMP)))
where:
34
PE = average cost with given streamflow
and withdrawal [mills/Kwh]
FC = fixed system costs
CH = average cost of hydropower [mills/Kwh]
H = net available hydropower given
streamflow, without withdrawals [Kwh]
AVLOS = average generating loss due to withdrawals
[Kwh]
(see Generating Loss)
CN = average cost of nonhydro resources
[mills/Kwh]
QE = market clearing quantity of electricity
[Kwh]
QF = QE + PUMP [Kwh]
d = proportion of pumping energy farmers pay
for
PUMP = amount of pumping energy farmers use in
getting irrigation water to the cropland
[Kwh]
Demand Conditions
Although
for
there is no widely accepted demand
electricity
in the PNW,
a number
of
function
estimates
are
available.
Given
the wide range of range of functional forms for
electricity demand in the literature (EPRI,
equally
wide
elasticity,
variation
it
was
in
decided
estimates
to
use
1982), and the
of
three
own
levels
price
of
35
elasticity in the study:
Elasticity
Reference(s)
-0.1
Charles River Assoc.
-0'. 54
Dept. of Energy
-1.0
Elec. Power Res.
Inst.,
Bonneville Power Adm.
An
unknown
simple
linear
demand function can be approximated by
demand
function of the form Q =
a
- b
a
P
(where Q = quantity demanded, P = price of electricity, and
a,b
are
constants).
regardless
general,
short
This is a
reasonable
approximation
of the form of the "true1 demand
any
function.
functional form can be approximated
range by a linear function.
over
In
a
It should be noted that
the elasticity of a linear demand function does not
remain
constant throughout its range.
The
was
slope
found
by
of the demand function in each
rearranging
the
formula
for
simulation
own
price
elasticity and solving for the slope value:
E = -(dQ/dP)•(P/Q)
= b-(P/Q)
=>
b =
(E-Q)/P
where:
E = own price elasticity of demand
dQ = change in quantity demanded from Q
dP = change in unit price from P
P = original unit price at average streamflow,
before withdrawals
Q = original quantity demanded at average
streamflow, before withdrawals
36
b = slope of the demand function
The
demand
function can be rearranged to
function.
obtain
This inverse function
is
an
inverse
demand
then
equated
to the average price function to solve for the new
market equilibrium.
The inverse demand function is:
P = (Q - a)/(-b) = [(H + NE) - a]/(-b)
= [a - (H + NE)]/b
Market Equilibrium
The
inverse
equals
average
demand
the
identically
equation
price
function can be
function since
price
consumers
supply
pay and
equated
price
the
equals the quantity purchased.
then has only one unknown
to
identically
quantity
The
variable,
the
sold
resulting
the
market
clearing quantity of electricity.
P
= P
supply
demand
rearranging this equation yields:
QE2 + QE-[b-CN - a - PUMP - (1 - d)-PUMP]
+ [b-FC + b-CH- (H - AVLOS) - b-CN- (H AVLOS) + a-PUMP - d-a-PUMP
+ (1 - d)-PUMP2] = 0
where:
QE = market clearing quantity of electricity
[Kwh]
H = quantity of available hydropower given
streamflow, without withdrawals [Kwh]
37
a = intercept term of the demand function
PUMP = amount of pumping energy used by farmers in
getting irrigation withdrawals to the cropland [Kwh]
(Whittlesey et al, 1981)
d = proportion of pumping energy paid for by
farmers
b = slope of the demand function
CH = average cost of hydro resources [mills/Kwh]
AVLOS = average generating loss [Kwh]
(see Generat-
ing Loss)
CN = average cost of nonhydropower [mills/Kwh]
FC = system fixed costs
The
simulation
then
finds
the
solution
to
this
equation by applying the quadratic formula:
QE =
[-NB +
(NB2 - 4-NC)1//2]/2
where:
QE = market clearing quantity of electricity
[Kwh]
NB = b-CN - a - PUMP - (1 - d)-PUMP
NC = b-FC + b-CH- (H - AVLOS) - b-CN- (H - AVLOS)
+ a-PUMP - d-a-PUMP + (1 - d)-PUMP2
It then remains to compute the new equilibrium
This
price.
is done by using the average price function for which
all values are now known.
Change in Consumers' Surplus
The
change in consumers' surplus is
estimated
using
38
the Hicks procedure (Brokken et al,
computing
the
1981). This is done by
the area bounded by the old average price
new average price line,
the ordinate,
line,
and the demand
curve.
In the case of a completely inelastic demand
the
function
change in consumers' surplus would be represented by a
rectangle. Mathematically:
CS = dP-QO = (PO - Pnew>-Q0
where:
CS = change in consumers' surplus
Pnew = new average price given streamflow
withdrawals
PO = old average price without withdrawals
QO = amount of electricity marketed
Under the assumption of less than perfectly
demand,
the
perfectly
boundaries
estimation
is
inelastic case.
as
before,
but
similar
to
that
inelastic
under
The area computed has the
the demand curve
now
negative slope. The formula is:
CS = dP •[(QO + QE)/2]
where:
CS = change in consumers' surplus
dP = change in average price (= PO - PE)
QO = original guantity of electricity
marketed, without withdrawals
QE = quantity marketed at new equilibrium
PO = average price without withdrawals
the
same
has
a
39
PE = average price given withdrawals
40
IV. RESULTS AND CONCLUSIONS
Energy Losses
It
should
be noted that the distribution
of
energy
losses show a very narrow dispersion (Table IV-1).
not
surprising
dam
system - flood control,
needs.
This
This is
in light of the major purposes behind
will
and water storage
for
the
later
tend to smooth out the distribution
of
water through time, even over a period of years. This would
result
i.e.
in a lessened effect from a change in
- an
irrigation
storage
facilities.
'years'
in
withdrawal,
It
water
flow,
than if there were
should be kept in mind
this study are water years and
no
that
the
therefore
run
from October to September.
The
area with the greatest loss,
was East High at 114.4 ave.
expected
on a yearly
MW/year.
basis,
This is as would
be
since East High is the largest area in the study,
with the largest withdrawals,
and is the farthest upriver.
This
total
is
about
consumption
of
.6%
of
the
the region.
forecast
The area
with
yearly loss was Umatilla II at 2.1 ave.
not
with
the
smallest
MW/year.
Although
the area with the smallest withdrawals,
the second smallest withdrawals.
electricity
it is the one
Grande Ronde has
a
net depletion approximately 68% of that in Umatilla, but is
further
upstream
Because
it
is
and shows a loss of
further
upstream,
4.3
the
ave.
water
MW/year.
lost
to
>
I
MMMMHJMMHJhJMMMhJMh^MMMHJhJMHJMMMH'Mt-'l-'l--'l--'H'l--'l--'l--'l--'H,|--'l--'l--'
I
I
I
I
I
|
1
1
1
i
1
^«
UIOJ
CO •
^JH'
O •
LTlCTi
h-1
vo ro
ai ai
M •
tri
I
I
*^
O •
4^^(^03U^^^UJUJOLnu^M^a^u>^4^u^^£>ooo^v£lvDC^lV04iCX)cr^wco^M^M^a^^^a^U)
MI-'h-'h-'l-'l-'h-'i-'H'h-'l-'l-'
l-» I-1 M (-' I-" K-* M
l-'l-'l-'l-'l-'l-'l-'l-'l-'K'l-'l-'l-'l-'t-'l-'l-'l-'l-'
UJO(^MMU>tOMMrOMM^H'MMMOK'NJCONJMUJUJMWl^U>CaNJOJMU>M[SJU)*.^=-UJ
U)^OTMU5^UlLO^^U)hJl^aiU1Cr\<»COMOCQOVD^^^^^(X>a\^MDVr)Ln^MOOOOO
VDU3O^OOOUl^C^(^hJC^CriCnM00V0^0JUJr0OOLnO|--'Ot--'00l--'C0O0,l0Ja3l--'l--'O
(^0:U>H'C0C^L0MMMOUD4iMMM^^00OU1OOU)U)MUJ4^W0JNJ4^U)U)NJOM4^*-U)
UlCT\C0^C^U1LnM^MOC00JUlMOC»00^MMU)Ji.LnOO0000--J~JNJ004^VDCriO-~J00~0O
^4^Mcr^M<DCi^u^oo^J^l^^U)c^lL^^XlVDvoL^lOOOU)MUJ^J^^u^a^Mcrl^o^L^o^^-'U^o^.o
l-'l-'ll-'l-'l-'l-'l-'H'l-'MI-'l-'t-'l-'
I-4 (-* h-* (-'
h-'l-'
H'l-'l-'l-'MI-'l-'h-'l-'l-'t-'l-'l-'l-'h-'l-'l-'t-'l-'
MH' t hJOr0MMNJMOhJMhJOCX3OOMOVDOM00MONJMI--'MrvJNJK)l--'ro(-'NJI--'l--'l-'tOMNJ
Cri4^ I MOU>MOU1U)^C^LOU)NJUn^^aiC»OOMOOOU3^ljn^U1^a^^C»-~J--JUJMNJOOCDOOcri
I
n
1
1
i
i
I
1
>
H
C5
t-a
>
tr1
l-H
>
t"1
M
M H
t-H M
1 s
1 s
1 E
1
1
1
1
1
1
1
c
s
» 50
C) >
25 2
O a
w w
1
1
1
1
1
1
1
1
1
K M
M >
O en
K t-3
1
1
1
1
I K
I w
i >
I Jd
(D
0)
\
a
S
ro
<
(u
^—^
o
m
en
tr1
a
o
H
5H3
W
W
••
1
h-'
<
H
w
bs
^
>
^.
I--1
42
irrigation
causes
Horse
is
denied to more dams along the
a greater loss of electricity generation in
Haven Hills I
of Grande Ronde',
has
river.
a
This
total.
(HHH) shows a loss very close to
at 4.6 ave.
that
MW/year. This is because HHH
net depletion much larger than either
Umatilla
Grande Ronde but is about the same distance from the
or
mouth
of the river as Umatilla.
On a per acre-foot basis, the losses show an identical
pattern.
East
High has a loss of about 1261 KwH per acre-
foot,
while Umatilla has a loss of about 187 KwH per acre-
foot.
HHH and Grande Ronde have losses of 205 and 565
KwH
per acre-foot respectively.
These
height
results
above
Grand
1167 feet.
be compared to
sea level of each of the
water is taken.
behind
could
would
Obviously,
pools
cumulative
from
which
East High uses water from the highest pool
Coulee Dam which has a cumulative height
of
Grande Ronde would take its water from the pool
behind Lower Granite Dam at 710 feet.
both
the
take
the
Umatilla II and
water from John Day pool
greater
at
242
the cumulative height of the
from which the water is taken,
the greater the
HHH
feet.
dam
generating
loss.
In addition to the loss of potential hydropower due to
withdrawals,
from
the
region also loses generated
electricity
the pumping required to move the water from the river
to the cropland (see Table III-l). In the case of East High
this is 98.8 ave. MW/year., about 1/2 of one percent of the
43
forecast demand of 18672 ave.
MW/year for the region as
a
whole.
Economic Results
General Results
The
results
consistent
of
the
economic
with economic theory.
simulations
were
This was assured by
the
nature of the models. As the amount of available nydropower
diminished
and
was
nonhydropower,
quantity
the
wholly
or
partially
replaced
with
equilibrium price increased while
decreased
(except
for
the
inelastic
the
demand
scenarios).
Changes
in
consumers'
surplus showed
the
expected
decrease with streamflows below the average streamflow, and
the
expected increase with streamflows above the
average.
This is due to the resource mix shifting from nydropower to
nonhydropower
reduced.
as
This
reduction,
the
amount of water
in
the
either
irrigation
withdrawals
expected value of changes in consumers'
less
than
is
will happen regardless of the source of the
or
streamflow variation caused by precipitation.
the
river
the
change
in
consumers'
natural
In addition,
surplus
surplus
at
were
low
streanflows.
At
all
streamflows,
the effects due
to
irrigation
withdrawals were dwarfed by those due to natural changes in
44
streamflows.
However,
irrigation
caused
a
loss
to
strong
in
This
is
electricity consumers in all situations.
Changes
response
to
in
consumers' surplus were quite
farmer payments for pumping energy.
true for all elasticities and for both policies. The change
in consumers' surplus dropped quickly as payments increased
from none to 100%.
Since East High, as the largest area, has the greatest
generating
loss among the areas in the study,
used to illustrate the magnitude of effects as
it will
be
withdrawals
are varied. The patterns exhibited in East High are similar
to
those
in other areas.
For details on other areas
the
reader is referred to the tables below.
Noninterruptible Policy
The
in
all
results from these simulations will be
terms of the weighted average (expected
streamflows.
The
elasticity assumptions:
elasticities
simulations
were
discussed
value)
run
under
four
completely inelastic and the three
mentioned previously (-0.1,-0.54,-1.0).
of these was also run under three assumed levels of
payments for pumping energy:
pay
across
Each
farmer
none, all, and one where they
only for the energy required to apply the water to the
crops (assumed to be equal to 100ft.
of the total
dynamic
head). In this last case, the energy used to get water from
the river to the farm gate is implicitly assumed to be paid
for by all electricity consumers.
45
Relative
changes
in
the
quantity
of
electricity
marketed due to withdrawals were not extreme.
The greatest
effect was observed in the simulations at an elasticity
of
one.
The quantity fell to slightly over 17000 ave. MW/year
from
the
base
decrease
case of 17411
ave.
of about 2.5 percent.
MW/year.
in
the
level
is
a
The remaining elasticities
showed less of an effect (see Tables IV - 2
Changes
This
of
hydropower
constant across all elasticity levels.
to IV - 6).
produced
This is the
are
result
that would be expected, since the amount of hydropower is a
function
only
exception
of streamflow and
is
streamflow.
the
Here
meet demand,
case
of
withdrawal
inelastic
level.
demand
and
there is more than enough hydropower
so demand is the limiting factor rather
The
high
to
than
water availability.
The greatest change in price due to withdrawals occurs
under similar conditions: an elasticity of one when farmers
don't
pay
for any pumping energy.
The expected value
price increases from 31.864 mills/Kwh to 32.232
This
of
mills/Kwh.
a relative change of about 1.4 percent.
(see Tables
IV - 2 to IV - 6).
Changes
pattern,
elastic
in
consumers'
that is,
the
Four
measures of
a
different
the
change
were
total change to consumers due to effects of
natural streamflow variation only,
irrigation
showed
the greatest changes occur in the least
simulations.
computed:
surplus
only,
the total change due to
the change per acre of farmland
due
to
READING TABLES IV-2 TO IV-6
NOTE: all entries are expected values
PROPORTION - the proportion of pumping energy paid for
by farmers
PRICE - market clearing price of electricity, given
withdrawals [rnills/Kwh]
DEMAND QUANTITY - market clearing quantity of electricity,
given withdrawals [ave. MW/year]
HYDRO QUANTITY - amount of hydropower produced
[ave. MW/year]
NON HYDRO - amount of nonhydropower produced
[ave. MW/year]
CHANGE IN CONSUMERS' SURPLUS
DUE TO STREAMFLOW - the change in consumers' surplus caused by natural streamflow variation only [$1000's]
DUE TO IRRIGATION - the change in consumers' surplus caused by irrigation withdrawals only [$1000,s]
PER ACRE - the change in consumers' surplus caused by irrigation on a per acre basis [$'5]
PER ACRE-FT - the change in consumers' surplus caused by
irrigation on a per acre-foot basis (i.e.-per acre-ft
of net depletion) [$'s]
**
TABLE IV-2:
NONINTERRUPTIBLE POLICY
EAST HIGH
DEKftND
HYDRO
PRICE QUflNTITY QUflNTITY
CHAN6E IN CONSUOS' SURPLUS:
DUE TO DUE TO
PER
PER
STRMFL. IRRIG.
ACRE
flCRE-FT
NON
HYDRO
Proportion: 0
INELASTIC
ELASTICITY: -0.1
ELASTICITY: -0.54
ELASTICITY: -1.0
32.241
32.240
32.245
32.232
18672
18020
17612
17193
14757
14760
14760
14760
3450
3355
2947
2529
-191464
-186519
-178376
-167902
-64441
-65802
-60863
-56475
-207.87
-212.26
-196.33
-182.18
-78.46
-82.78
-76.57
-71.05
32.216
32.215
32.221
32.209
18672
18021
17619
17207
14757
14760
14760
14760
3450
3357
2955
2542
-191464
-186519
-178376
-167902
-60398
-61826
-57166
-53031
-194.83
-199.44
-184.41
-171.07
-73.51
-77.78
-71.92
-66.71
32.071
32.072
32.084
32.076
18672
18029
17663
17286
14757
14760
14760
14760
3450
3365
2399
2621
-191464
-186519
-178376
-167902
-36684
-38523
-35508
-32868
-118.34
-124.29
-114.54
-106.03
-44.4E
-48.47
-44.67
-41.35
Proportion: .145
INELASTIC
ELASTICITY: -0.1
ELASTICITY: -0.54
ELASTICITY: -1.0
Proportion: 1
INELASTIC
aASTICITY: -0.1
ELASTICITY: -0.54
ELASTICITY: -1.0
!
i
!
!
TABLE IV-3:
NONINTERRUPTIBLE POLICY
UMATILLA II
DEMAND
HYDRO
PRICE QUANTITY QUANTITY
NQN
HYDRO
DUE TO
STRMFL.
DUE TO
IRRI6.
PER
PER
ACRE
ACRE-FT
-191464
-186519
-178376
-167902
-4937
-5027
-4642
-4300
-123.42
-125.67
-116.05
-107.50
-48.57
-51.10
-47.13
-43.72
Proportion: 0
INELASTIC
ELASTICITY: -0.1
ELASTICITY: -0.54
ELASTICITY: -1.0
i
!
i
!
i
!
!
!
31.877
31.867
31.890
31.891
18672
18042
17725
17394
14858
14869
14869
14869
3267
3186
2869
2538
31.874
31.864
31.888
31.889
18672
18042
17726
17396
14858
14869
14869
14869
3267
3186
2870
2540
-191464
-166519
-178376
-167902
-4518
-4617
-4261
-3947
-112.%
-115.42
-106.53
-98.67
-44.43 i
-46.93 i
-43.32 i
-40.12 i
31.854
31.844
31.869
31.871
18672
18043
17732
17407
14858
14869
14869
14869
3267
3187
2876
2551
-191464
-186519
-176376
-167902
-1170
-1334
-1216
-119
-29.24
-33.35
-30.40
-27.99
-11.23
-13.56
-12.36
-11.38
Proportion: .111
INELASTIC
ELASTICITY: -0.1
ELASTICITY: -0.54
ELASTICITY: -1.0
Proportion: 1
INELASTIC
ELASTICITY: -0.1
ELASTICITY: -0.54
ELASTICITY: -1.0
!
i
;
!
00
TABLE IV-4:
NONINTERRUPTIBLE POLICY
HHH I
DEMAND
HYDRO
PRICE QUflNTITY QUflNTITY
NDN
HYDRO
CHANGE IN CONSUICRS' SURPLUS:
DUE TO DUE TO
PER
PER
STRMFL. IRRIG.
ACRE
flCRE-FT
Proportion: 0
INELASTIC
ELASTICITY: -0.1
ELASTICITY: -0.54
ELASTICITY: -1.0
31.905
31.8%
31.918
31.918
18672
18040
17716
17379
14856
14867
14867
14867
3290
3198
2827
2537
-191464
-186519
-178376
-167901
-9576
-9756
-9006
-8344
-136.80
-139.37
-128.65
-119.20
-47.20
-49.69
-45.87
-4249.00
31.900
31.981
31.913
31.913
18672
18040
17718
17382
14856
14857
14867
14867
3280
3198
2876
2540
-191464
-185519
-178376
-167901
-8739
-8935
-8245
-7637
-124.85
-127.65
-117.78
-109.10
-43.05
-45.51
-41.99
-36.90
31.861
31.852
31.876
31.878
18672
18042
17729
17402
14356
14367
14867
14867
3280
3201
2887
2561
-191464
-185519
-178376
-167901
-2375
-2692
-2455
-2260
-33.92
-38.46
-35.08
-32.29
-11.49
-13.71
-12.51
-11.51
Proportion: .116
INELASTIC
ELASTICITY: -0.1
ELASTICITY: -0.54
ELASTICITY: -1.0
Proportion: 1
INELASTIC
ELASTICITY -0.1
ELASTICITY -0.54
ELASTICITY -1.0
!
!
;
!
>H
u
J
H
PQ
^
o
a<
w
H
EH
CU
D
«
«
H
EH
w
Q
2
O
(X
w
Q
2
Z
H
O
$
S
2
O
ID
I
>
H
W
En
<
crt
oe
Ui
a.
a: or
ra ui
en a.
XXL
in
Z UJ
a1-
ii
IJ-
^
Sj
UJ
XXL
CJ
CX
.
CD
a
-J
(X.
en rp ac
o a »—*
z
►—•
CE:
fe
S '"
3:
C3 C>
z >•
>3:
o
CM
l£)
in IT> ren in uo
cu
<<-I T
^
O
R S s?«
•
oi <)•
IS ¥
I
¥1
i^j
i~i
OJ
1
I
I
i
I
I
I
UD
I
UD
I
r- oj
-3- OJ O UO
m r~- n- o
....
eo co UT ro
ro ro ro ro
I
I
I
I
U3
WD
I
—< O
CO CO
ro
CU
UT
OJ
n
OJ
1
cu n en -^
i
er> u3
t— <y
in
in U3 *-•
II
II
1^ir> co r~- co
—•'-•—•—•
U3
CO
CO
r- "da
OJ
i
g £
OJ
-<iU3
•<r
s?
rCO
CO
OJ
o
co
—•
ro
o t—
M S
ro oj
« S3
o
i
en
—«
\n
co
co
r-
50
en
i
<j•*r
in
O.I
i
'.-"J
CT>
Ml
rxi
co *->
r- o
ro en
CO i—
r~- vo
m o in <-o
ro oj 6^ en
-a- in ro oj
—•—..-•-■•
i
-aco
-a^-<
m
i-O
^-^
,-« m
t.O
OJ
II
n
n
II
II
1
1
1
n
ro
r^- r- r-Ul tn t-O
»T3 oa Ul
-;r <r -sr -sr
I--J
utt in -.o I'U
in -«r- r- r*•^1 1:0 co ca
Li)
U-]
oj
<-j
-•
tj3
•.xi
ro
ti
II
II
II
n
n
ro r-i r-i
I
1
cr
1—
I.J liJ II
n
u3 o- i~- -*•
r^-
L)
1- -
II
i-3
o
i
r.j
f- r^ rCO d) CO
co a5 an
-T r- -3—.*-.—.
f^
CO
'fz
vo r— r-- t—
in ua ifl eo
en co co ao
xr ■*• -a- -a-
OJ en •*-.
-a- oj o
co r- i~-
I-J
o r~- ■•»■
IO
kXI
•J3
CO CO
cu
rin
co
ro
1 J
^ 4
1
ce
..j
UJ
to
LJ
I.J
II
n
I.J
tj
tj
>•>->-
sr ro co en
ud ui r- r^
co co ta co
tn
ex:
i
UJ
>■-
»". J
ro ro ro e-i
•-• in o
o o -5
i—
t—
u
IJJ
o
•—•
i—
en
i—
I— CJ til
en i-t >-«
er h— i—
_j en en
bW CU
5 LU
3 "i
•-^
TABLE IV-6;
NONINTERRUPTIBLE POLICY
COMBINED AREAS
DEMAND
HYDRO
PRICE QUANTITY GUMITY
NGN
DUE TO
3TRMFL.
DUE TO
IRRIG.
PER
PER
HYDRO
ACRE
ACRE-FT
Proportion: 0
INELASTIC
ELASTICITY: -0.1
ELASTICITY: -0.54
ELASTICITY: -1.0
;
!
i
!
32.347
32.348
32.348
32.332
18672
18013
17579
17134
14749
14750
14750
14750
3502
3402
2968
2523
-191464
-186519
-178376
-167901
-81756
-83467
-77254
-71724
-178.51
-182.24
-168.68
-156.60
-68.43
-72.19
-66.81
-62.03
!
:
!
!
!
i
i
1
32.312
32.314
32.316
32.300
18672
18015
17589
17153
14749
14750
14750
14750
3502
3404
2978
2542
-191464
-186519
-178376
-167501
-76130
-77938
-72102
-65919
-166.22
-170.17
-157.43
-146.11
-63.69
-67.40
-62.36
-57.87
!
!
!
i
, 101
18672
18027
17653
14749
14750
14750
3502
3417
3042
-191464 -41544
-186519 -43951
-176376 -40483
-90.71
-95.96
-68.39
-34.57
-38.01
-35.01
Prcaortion: .133
INELASTIC
ELASTICITY: -0.1
ELASTICITY: -0.54
ELASTICITY: -1.0
i-rooortic-rii :
INELASTIC
ELASTICITY: -0.1
ELASTICITY -0.54
rjlSTICITY -1.0
52
withdrawals,
and
the
withdrawals.
The
last
total
the
change per
acre-foot
two are computed by
due
dividing
to
the
change due to withdrawals by the number of acres and
the net depletion in the study area respectively.
The
expected
value of the losses due
varied considerably.
million
about
to
irrigation
They ranged from a high of about
$66
when farmers pay for no pumping energy to a low of
$33 million when they paid for all of their
energy.
pumping
This translates into a difference of about $42 per
acre-foot (see Tables IV - 2 to IV - 6).
Interruptible Policy
As expected,
amount
of
the interruptible simulation limited the
withdrawals
farmers
could
make
under
low
streamflow conditions. Since the probability of seeing such
a
low streamflow is only about 5 percent,
we
would
expect to see denials in five years out of 100.
at
which
some
quantity
of
in
market)
the
interruption will occur
is
the
electricity demanded (without new
minus
the
available
The
only
level
forecast
irrigators
nonhydro
system
generation (assumed fixed under this policy). This is 18672
MW - 6341 MW = 12331 ave. MW/year. This is within about two
percent
under
of
published figures for average
critical
flows
(PNUCC,
1983a).
hydrogeneration
As
mentioned
53
previously,
the
model
assumes
available water and demand.
be
implemented
perfect
Clearly,
forecasting
of
the policy could not
in exactly the same manner
as
the
model
suggests.
Because
of
the simplicity of the model,
it was
not
possible to run the simulations for elastic conditions. The
nature
of
the
replacement
Therefore,
examined
model
is
such
that
it
supplies
power before it uses expensive
only
the
completely
nonhydropower.
inelastic
scenario
and the total quantity demanded remains
at the forecast quantity of 18672 ave.
cheap
was
constant
MW (see Tables IV -
7 to IV - 11).
Hydrogeneration
equal
the
follows the expected pattern.
It
to the amount of power that would be generated
natural streamflow minus the withdrawals.
streamflow
there are no withdrawals,
is
from
At the
so these two
low
values
are equal. At high streamflows, where there is enough water
to supply all needs from hydropower,
there
including irrigation,
is more hydropower than is needed.
(Note:
data
on
individual streamflows are not presented in the tables.)
Nonhydro
generation
follows
a
regular
pattern
as
streamflow is varied. For each 1000 ave. MW that streamflow
is increased, the amount of nonhydropower decreases by 1000
ave.
MW. The exception is at the high streamflow, where no
nonhydropower is produced at all.
The replacement power, that is, the power used in this
simulation
to
replace
the
generating
loss
due
to
54
READING TABLES IV-7 TO IV-11
NOTE: all entries are expected values
ALLOWED DIVERSION - the percentage of irrigation withdrawal allowed under the new policy
DIVERSION - the generating loss associated with the
allowed diversion [ave. MW/year]
PUMP LOSS - the pumping energy associated with the
allowed diversion [ave. MW/year]
NEW PRICE - see Tables IV-2 to IV-6
NON-HYDRO -
"
REPLACED - the amount of electricity needed to replace
that lost to irrigation withdrawals and pumping energy
[ave. MW/year]
HYDRO GENERATION - see Tables IV-2 to IV-6
TOTAL QUANTITY - same as demand quntity in Tables IV-2
to IV-6
CHANGE IN CONSUMERS' SURPLUS
TOTAL - change caused by natural streamflows only
[$1000,s]
IRRIGATION
- change caused by irrigation withdrawals
[$1000,s]
PER ACRE - see Tables IV-2 to IV-6
PER ACRE-FT - "
55
TABLE IV-7 : INTERRUPTIBLE POLICY
EAST HIGH
Proportion Paid by Farmers:
NONE
.145
ALL
91
91
91
Diversion
104.1
104.1
104.1
Pump loss
89.9
89.9
89.9
New price
31.947
31.924
31.791
Non-hydro
3252
3252
3252
194
194
194
Hydro gen.
14764
14764
14764
Total quant.
18672
18672
18672
-191464
■191464
■191464
Irrigation
916361
-12649
9121
Per acre
-52.78
-40.80
29.42
Per acre-ft
-19.88
-15.34
11.27
Allowed div.
Replaced
Change in consumers' surplus:
Total
56
TABLE IV-8 : INTERRUPTIBLE POLICY
UMATILLA II
Proportion Paid by Farmers:
NONE
.111
ALL
91
91
91
Diversion
1.8
1.8
1.8
Pump loss
12.3
12.3
12.3
New price
31.855
31.853
31.834
Non-hydro
3252
3252
3252
14
14
14
Hydro gen.
14858
14858
14858
Total quant.
18672
18672
18672
-191464
•191464
■191464
-1399
-1012
2088
Per acre
-34.97
-25.29
52.20
Per acre-ft
-13.74
-9.91
20.71
Allowed div.
Replaced
Change in consumers' surplus:
Total
Irrigation
57
TABLE IV-9 : INTERRUPTIBLE POLICY
HHH I
Proportion Paid by Farmers
NONE
.116
ALL
91
91
91
Diversion
4.2
4.2
4.2
Pump loss
23.5
23.5
23.5
New price
31.863
31.859
31.823
Non-hydro
3252
3252
3252
28
28
28
Hydro gen.
14857
14857
14857
Total quant.
18672
18672
18672
-191464
•191464
•191464
-2704
-1930
3958
Per acre
-38.63
-27.57
56.54
Per acre-ft
-13.30
-9.47
19.66
Allowed div.
Replaced
Change in consumers' surplus:
Total
Irrigation
58
TABLE IV-10: INTERRUPTIBLE POLICY
GRANDE RONDE
Proportion Paid by Farmers:
NONE
.208
ALL
91
91
91
Diversion
3.9
3.9
3.9
Pump loss
4.5
4.5
4.5
New price
31.851
31.850
31.844
Non-hydro
3252
3252
3252
8
8
8
Hydro gen.
14856
14856
14856
Total quant.
18672
13672
18672
-191464
-191464
-191464
-726
-463
540
Per acre
-19.11
-12.19
14.20
Per acre-ft
-10.52
-6.69
7.93
Allowed div.
Replaced
Change in consumers' surplus:
Total
Irrigation
59
TABLE IV-11: INTERRUPTIBLE POLICY
COMBINED AREAS
Proportion Paid by Farmers
NONE
.139
ALL
91
91
91
Diversion
114.1
114.1
114.1
Pump loss
130.1
130.1
130.1
New price
31.976
31.945
31.751
Non-hydro
3252
3252
3252
244
244
244
Hydro gen.
14756
14756
14756
Total quant.
18672
18672
18672
-191464
■191464
•191464
Irrigation
-21189
-16036
15642
Per acre
-46.26
-35.01
3 4.15
Per acre-ft
-17.70
-13.37
13.25
Allowed div.
Replaced
Change in consumers' surplus:
Total
60
withdrawals,
ave.
MW.
farmers
is
The
constant across most streamflows
at
exceptions are at the low streamflow
are denied any water,
where none is needed.
and at the high
114
where
streamflow
In both of these cases the amount of
replacement power is zero.
Price
amount
changes
of hydropower increased,
decreased.
This
farmer payments.
when
showed the expected
farmers
mills/Kwh.
was
the price of
As
the
electricity
true under all three assumptions
The greatest expected value of price
paid
The
pattern.
for no
lowest
pumping
energy,
of
was
about
31.95
all
their
was when they paid for
pumping energy, about 31.791 mills/Kwh.
Changes
in
consumers'
surplus
witdrawals showed a wide variation.
due
to
irrigation
At the low streamflows
there was no loss or gain to consumers, that is, the change
was
zero.
This is because the farmers in
the
simulation
were not allowed any withdrawals.
There
was
proportion
a
strong
response
to
the
change
in
of pumping energy paid for by the farmers.
The
greatest expected value of loss was in the case where
did not pay,
pay
for
all
electricity
farmers
about $16.4 million.
that
they
use,
In contrast,
there is
consumers of about $9 million.
a
they
when they
net
gain
In this
to
case,
are paying more for the electricity they use
than
the loss from irrigation withdrawals.
The
acre
change
in consumers' surplus computed on
a
and per acre-foot basis followed similar patterns
per
as
61
those
for total change due to withdrawals.
change
varied
The
per
acre
from a loss of about $53/acre to a gain
about $29/acre.
The per acre-foot change went from a
of
loss
of about $20/ac're-foot to a gain of about $ll/acre-f oot.
Comparison of Policies
Since
under
the
interruptible
policy was
simulated
the assumption of completely inelastic
only
demand,
the
only possible comparison is at this elasticity.
The
total
simulations
was
consistent
with
demand.
quantity of electricity marketed
constant
the
at
18672
assumption of
ave
MW.
by
both
This
completely
is
inelastic
(See Tables IV - 12 to IV - 16.)
The
differed
amount of hydropower produced in the
simulations
by about 114 MW at the low streamflows.
This
is
the amount of the generating loss at East High. This is due
to the different assumptions underlying the two models.
the
noninterruptible model the irrigation withdrawals
assumed to be taken under all streamflow conditions,
In
are
while
in the interruptible model withdrawals do not take place at
low
streamflows.
At all other streamflows the
amount
of
hydropower was identical in both models.
It is not possible to make a direct comparison between
the
two
policies
nonhydropower.
class
The
in
terms
of
noninterruptible
the
production
model has
of nonhydropower while the interruptible
of
only
one
model
has
two: nonhydro power and replacement power. However it would
62
be
instructive
to
noninterruptible
nonhydropower
compare
the
nonhydropower
model with the combined
in
the
interruptible
streamflows there was no difference.
in
the
replacement
model.
and
At
most
The exception was
at
the low streamflow. Here the difference was 213 MW, the sum
of
for
the generating loss and pumping energy.
This
accounts
the differences of about 200 MW in the expected values
of the amount of nonhydropower in the two models.
Prices
were generally higher in the
than in the interruptible simulations.
at
the
(under
high
all
streamflow scenario where
farm
payment assumptions.)
noninterruptible
The exceptions were
they
were
equal
This
pattern
of
higher price is followed by the expected values as well.
Differences
relatively
in the change in consumers' surplus
sizable.
When farmers do not pay
for
were
pumping
energy, the loss to consumers is about four times higher in
the noninterruptible model than in the interruptible model.
At
the
other extreme,
pumping
energy,
consumers
when farmers pay for all of
there is a loss' of about $33
their
million
to
under the noninterruptible policy compared to
a
gain of about $9 million under the interruptible policy.
Conclusions and Implications
Before
study,
it
drawing
is
any particular conclusions from
necessary to caution the
reader
that
this
any
63
economic
analysis
approximation
of
can,
at
simulations is no exception.
able
to
available
to
only
be
to the situation being modeled.
were made about' the data used.
be
best,
Some
the
gross
This series
strong
assumptions
These were made in order to
obtain some estimates,
do
a
research.
given
the
resources
Additionally,
a
highly
aggregated series of models was used.
Nonetheless,
although
doubt.
the
Thus,
some
exact
the
clear conclusions can
be
stated,
magnitudes of the effects may
reader
is advised to
use
be
in
caution
in
evaluating and using these results.
Examination
assumptions
are
of
the results suggest
not
as
strong
an
that
elasticity
influence
as
those
involving farmer payments. Although the losses to consumers
are
generally less under the more elastic assumptions
(in
the noninterruptible scenarios) vis-a-vis the less elastic,
the
amount of change is considerably less than that due to
farmer payments. For example, in East High, when farmers do
not
pay for any pumping energy the greatest change
elasticities is about $26/acre,
across
or about 10%. In contrast,
the change from no farmer payments to full farmer
payments
is on the order of $80/acre, or about 60%.
The
results
of
these
simulations
suggest
that
electricity consumers in the Pacific Northwest would,
an extended period,
limit
seen
over
be better off with a policy that would
consumptive uses of the river system.
This
can
be
by the comparison of the change in consumers' surplus
64
due to irrigation withdrawals between the two policies.
Farmers
policy
would
obviously prefer to have
the
maintained.
This is a case where the
Kaldor-Hicks
compensation
consumers,
test
as
policy,
could
farmers.
The
debate,
might
gainers
applied.
under the
compensate
amount
but
be
of
The
proposed
the losers,
current
electricity
interruptible
in this
case
the
compensation would be
open
for
amount
of
economic theory suggests that the
compensation would not exceed the gain from the new policy.
That
would
be
the
consumers' surplus.
not
be
expected
Clearly,
of
the
change
electricity consumers
expected to pay farmers more than they
from the new policy.
at
value
in
would
would
get
On the other hand, farmers would want
least as much as they would be giving up under the
new
policy.
As an example, the difference between the two policies
studied
$48.1
had an expected value of between $45.8 million and
million
inelastic
East
demand.
electricity
amount
in
to
This
consumers
limit
High
under
suggests,
the
that
assumption
on
average,
would be willing to pay up to
farmers' withdrawals
in
years
of
of
this
low
streamflow (see Tables IV - 12 to IV - 16).
The
question
arises as to how this payment might
be
made. Given that it would not be possible to make long term
forecasts of streamflow further ahead than a few months
at
best, it would be extremely difficult to time payments. One
possibility
would
be an insurance program.
The
electric
READING TABLES IV-12 TO IV-16
NOTE: all entries are expected values
PROPORTION - the proportion of pumping energy paid
for by farmers
DIFFERENCE - the change in consumers' surplus under the
interruptible policy minus the change under the noninterruptible policy
TOTAL - the change in consumers' surplus due to irrigation [$1000ls]
PER ACRE - the change in consumers' surplus due to irrigation on a per acre basis [$'s]
PER ACRE-FT - the change in consumers' surplus due to irrigation on a per acre-foot basis (i.e.-per acre-ft of
net depletion) [$'s]
en
en
TABLE IV-12: COMPARISON OF POLICIES
EAST HIGH
CHANGE IN CONSUMERS' SURPLUS
Noninterruptible
Policy
Interruptible
Policy
Difference
total
per acre
acre-ft
-64441
-207.87
-78.87
-16361
-52.78
-19.88
-48080
-155.09
-58.99
total
per acre
acre-ft
-60398
-194.83
-73.51
-12649
-40.80
-15.34
-47749
-154.03
-58.17
total
per acre
acre-ft
-36684
-118.34
-44.46
9121
29.42
11.27
-45805
-147.76
-55.73
Proportion
145
0"\
TABLE IV-13: COMPARISON OF POLICIES
UMATILLA II
CHANGE IN CONSUMERS' SURPLUS
Proportion
Noninterruptible
Policy
Interruptible
Policy
Difference
0
: total
: per acre
: acre-ft
-4937
-123.42
-48.57
-1399
-34.97
-13.74
-3538 1
-88.45
-34.83
.111
: total
: per acre
: acre-ft
-4518
-112.96
-44.43
-1012
-25.29
-9.91
-3506
-87.67
-34.52
1
: total
: per acre
: acre-ft
-1170
-29.24
-11.28
2088
52.20
20.71
-3258
-81.44
-31.99 1
TABLE IV-14: COMPARISON OF POLICIES
HHH I
CHANGE IN CONSUMERS' SURPLUS
Noninterruptible
Policy
Interruptible
Policy
total
per acre
acre-ft
' -9576
-136.80
-47.20
-2704
-38.63
-13.30
-6872
-98.17
-33.90
total
per acre
acre-ft
-8739
-124.85
-43.05
-1930
-27.57
-9.47
-6809
-97.28
-33.58
total
per acre
acre-ft
-2375
-33.92
-11.49
3958
56.54
19.66
-6333
-33.92
-11.49
Proportion
116
Difference
TABLE IV-15: COMPARISON OF POLICIES
GRANDE RONDE
CHANGE IN CONSUMERS' SURPLUS
Noninterruptible
Policy
Inte'rruptible
Policy
total
per acre
acre-ft
-2802
-73.75
-40.69
-726
-19.11
-10.52
-2076
-54.64
-30.17
total
per acre
acre-ft
-2518
-66.27
-36.54
-463
-12.19
-6.69
-2055
-54.08
-29.85
total
per acre
acre-ft
-1435
-37.77
-20.72
540
14.20
7.93
-1975
-51.97
-28.65
Proportion
208
Difference
TABLE IV-16: COMPARISON OF POLICIES
COMBINED AREAS
CHANGE IN CONSUMERS' SURPLUS
Noninterruptible
Policy
Proportion
.139
Interruptible
Policy
Difference
total
per acre
acre-ft
-81756
-178.51
-68.43
-21189
-46.26
-17.70
-60567
-132.25
-50.73
total
per acre
acre-ft
-76130
-166.22
-63.69
-16036
-35.01
-13.37
-60094
-131.21
-50.32
total
per acre
acre-ft
-41544
-90.71
-34.71
15642
34.15
13.25
-57186
-124.86
-47.96
o
71
utilities would pay a fixed amount,
i.e.
the insurance fund on a regular basis.
be
- a premium,
This premium
incorporated into the rates consumers pay.
low
streamflow',
the
to
would
In years of
fund would pay farmers not
to
take
water.
This explicitly recognizes the risk in setting
for
the use of the river system.
policy
To a significant extent,
much of the risk faced by electricity consumers is
taken
into
account.
This can be seen in
the
relatively
stable prices that have been charged in the past.
there
have been numerous price increases,
already
Although
there have
not
been fluctuations in response to changing river conditions.
This
is
policy
not to suggest that introducing an
would
not
make
the
rate
interruptible
setting
process
more
complicated. Quite obviously, it would.
An interruptible policy would serve to shift risk from
electricity consumers to farmers. However, farmers could in
turn
those
shift
risk to there customers.
To the
customers lie outside the region,
those
customers
lie
within
the
that
the risk will
transferred away from the Pacific Northwest.
that
extent
be
To the extent
region,
and
are
electricity consumers, the risk will be transferred back to
electricity consumers.
Society
may
wish
to limit the
development could take place.
locations
in
which
It is clear that the further
upstream
withdrawals take place,
society.
The
the greater the cost
loss to consumers under the
to
noninterruptibe
72
policy
for
and inelastic demand is about seven
East High than Umatilla II,
This
times
greater
on a per acre-foot basis.
suggests that areas downstream be developed prior
to
those upstream.'
Although
much
water
focused
the law now states that farmers can take
as they need,
attention
possible
on
the recent
the
public
increasing
users of the river system.
debate
competition
as
has
among
It would however,
be
more complicated to institute an interruptible water policy
than might first seem to be the case.
Water law has a long
and sometimes colorful history of confrontation.
be
It
would
likely that proposal of an interruptible policy in
the
region would contribute to these ongoing confrontations.
Under current practice new users of surface water must
apply for permits to make withdrawals. There may be denials
of
requests,
for many reasons.
Those who receive permits
later than others are known as 'junior' users. Senior users
have priority when there are low streamflows. This would be
consistent with an interruptible water policy.
implement
an
interruptible
policy
would
One way
be
to
to
grant
hydroelectric producers permits that would be senior to new
irrigation development areas.
could
be
granted
Additionally,
in such a way as
to
these
limit
rights
irrigation
withdrawals only under noncritical conditions.
The
situation.
permit
In
system does not fully describe the
addition
there
are
many
legal
jurisdictional
questions that arise. An area might fall under the aegis of
73
a
local
irrigation
government,
these.
district,
federal
government,
county
government,
or some
state
combination
of
The objectives of each level of government, and its
constituency,
might
well differ in any given area
(NADP,
1979) .
It
is
remaining
water
quite
clear
that there
are
many
questions
to be answered before any substantial change
policy
implemented.
such
that
studied
here
of them are economic in
could
be
nature.
Those
mentioned in regard to the models used here could be
dealt
with
Some
as
in
by building more comprehensive models or running some
of the existing simulations available in the region with an
eye to testing proposed policies.
This
study has only considered the question
of
what
happens to electricity consumers under the proposed policy.
The agricultural side of the issue has not been dealt with.
There
to
are social benefits to be had from allowing
irrigate additional acreage in the region
farmers
(Obermiller,
1980,1981).
Some
the
further insights might be gained from
agricultural
benefits
from
issues,
with an eye to
irrigation
development.
examining
estimating
A
the
cost/benefit
comparison could then be made. It might also prove valuable
to incorporate these analyses into a larger framework, that
is, examine other river uses simultaneously.
74
BIBLIOGRAPHY
Bonneville Power Administration. "Role of the Bonneville
Power Administration in the PNW Power Supply System",
Final Environmental Impact Statement (DOE/EIS-0066),
Washington, 1980.
"Supply Pricing Model Documentation for the ShortTerm Nongenerating Public Utility Load Forecast
and the 1983 Wholesale Rate Environmental Impact
Study." Portland, 1983a.
"Wholesale Power Rate Design Study: 1983 Initial Rate
Proposal." Portland, 1983b.
Brokken, Ray F., D. Cory, R. Gum, and Wm. E. Martin.
"Simplified Measurement of Consumers Welfare Change."
Am. Journal of Agricultural Economics, 63(pg. 715717) , 1981
Electric Power Research Institute. "Price Elasticites of
Demand for Energy - Evaluating the Estimates." Palo
Alto, 1982.
Freeman, A. M. The Benefits of Environmental Improvement:
Theory and Practice. Johns.Hopkins University Press;
Baltimore, 1979.
Garfield, P. J. and W. F. Lovejoy. Public Utility Economics
Prentice- Hall; Englewood Cliffs, 1964.
Joskow, P. L. "Contributions to the Theory of Marginal Cost
Pricing." The Bell Journal of Economics, 7(pg. 197206) , 1976
Just, Richard E., D. L. Hueth, and A. Schmitz. Applied
Welfare Economics and Public Policy. Prentice Hall;
Englewood Cliffs, 1982.
King, Larry D., M. L. Hellicksen, W. E. Schmisseur, and M.
N. Shearer. "Projected Energy and Water Consumption
of Pacific Northwest Irrigation Systems." Dept. of
Energy (PNL-RAP-3 3); Oct. 1978.
Mansfield,Edwin. Microeconomics: Theory and Applications.
W. W. Norton; New York, 19 79
Martin, Wm. "Returns to Public Irrigation Development and
the Concomitant Costs of Commodity Programs" American
Journal of Agricultural Economics,61 (pg. 1107-1114),
1979
75
Northwest Agricultural Development Project. "An Analysis
of Agricultural Potential in the Pacific Northwest
with Respect to Water and Energy" (Working Paper III)
Vancouver, 1979.
Northwest Power Planning Council. "Northwest Conservation
and Electric Power Plan." Portland, 1983.
Obermiller, Frederick W. "Agriculture and Ilydropower:
Costs, Benefits, and Tradeoffs" from a seminar:
Conflicts Over the Columbia River, conducted by the
Water Resources Research Institute, Oregon State
University, 1930.
"Evaluating the Social Benefits and Social Costs of
Irrigation Development" Paper presented to the Water
Policy Advisory Committee, State of Oregon Legislative Committee on Trade and Econoraic Development, 1973
Pacific Northwest River Basins Commission. "Comprehensive
Framework Study" Portland, 1970.
Pacific Northwest Utilities Conference Commitee. "Northwest
Regional Forecast of Power Loads and Resources" Portland, 1983a.
"Projection of Utlity Power Loads and Resources" Portland, 1983b.
"Thermal Resources Database" Portland, 1982.
Soil Conservation Service. "Irrigation Water Requirements."
Technical Release No. 21. Washington, 1970.
Whittlesey, Norman K., J. R. Buteau, W. R. Butcher, and
D. Walker. "Energy Tradeoffs and Economic Feasibility
of Irrigation Development in the Pacific Northwest"
College of Agriculture Research Center, Washington
State University Bulletin 0896; Pullman, 1981.
Whittlesey, Norman K. and K. C. Gibbs. "Energy and Irrigation in Washington." Western Journal of Agricultural Economics, 3(pg. 1-9), 1973
APPENDIX
76
DERIVATION OF INPUT VALUES
The
test
models in the analyses are run using 1985 as
year.
quantities
That is,
of
the
the current forecasts of prices
electricity
for 1985 are used
as
a
and
base
against which changes due to new irrigation withdrawals and
differing precipitation levels are made. It should be noted
that all prices are inflated or deflated to 1983 dollars as
necessary.
Some
readily
of
the
values used as
model
parameters
were
available in published reports of regional utility
agencies or industry groups. They were:
PO: forecast price of electricity, 31.625
mills/Kwh (NPPC, 1983)
QO: forecast quantity of electricity, 18672 ave.
MW (PNUCC, 19 8 2a)
CH: unit levelized cost-of producing hydropower
4 mills/KwH (NPPC, 1983)
Average hydropower production
159 6 0 ave MW
(PNUCC, 1983b)
Note: this is not a model parameter, but is one
of several levels of hydropower capability
examined in the analyses. It is useful as a
'best guess1 for predicting hydro generation and
also as a benchmark against which to compare
other levels of capacity. The minimum and
maximum levels of capacity are 119 6 0 ave. MW
77
and 18960 ave. MW. These correspond closely
to values obtained from the BPA. It is also
used to derive the cost of nonhydro resources.
Some
of
the
identifiable
generating
not
have
jointly
values.
inputs
utilities in the PNW,
owned
by
do
the
have
easily
In addition,
several utilities.
same type may
of
and that many of them do
to allocate the costs among
of
not
This is due to the large number
available data.
possible
plants
other
have
many
It
plants
is
not
owners.
very
are
always
Also,
even
different
cost
structures depending upon age and other factors.
Since
the
representative
BPA
of
uses
all
several
ages
and
types
price
of
resources
structures,
and
supplies a large proportion of the region's electricity, it
was
decided
to use BPA costs as the basis
of
allocating
costs for the region. Specifically, BPA costs broke down as
follows (BPA, 1983w):
Resource
Hydropower generation
Cost
%
263,494,492
9.5
533,413,602
19.3
1,972,631,398
71.2
2,769,539,492
100.0
Nonhydro generation +
purchased power
Nongenerating costs
Total
Regional costs/revenues are found as follows:
Total Revenue:
78
(18672 MW)
(8.76) = 163566.72 gigawatt hours
(163556.72 GwH)
($31625/GwH) = $5172797520
Fixed Costs:
($5172797520)
(.712) = $3683031834
Hydrogenerating Costs:
(15960 MW)
(8.76) = 139809.6 GwH
(139809.6 GwH)
($4000/GwH) = $559238400
Nonhydro Costs:
Total costs - Fixed cost -Hydrogenerating costs
= Total nonhydro cost
$5172797520 - $3683031834 - $559238400 = $930527286
Per Unit Nonhydro Costs:
Quantity of nonhydro resources:
Total quantity - Hydro capability = (18672 MW) (15960 MW) = 23757.12 GwH
Unit cost:
($930527286)7(23757.12 GwH) = $39168/GwH
[or 39.168 mills/KwH]
The
mills/KwH
percent
mills/KwH
cost
of
(NPPC,
greater
for
resources is estimated
1983).
than
the
However,
derived
as
to
this is
estimate
be
only
of
40
two
39.168
of nonhydro resources projected to be on line in
the test year,
rate
new
it was decided to use the nonhydro resource
both.
The projected capacity
of
the
nonhydro
resources is 6341 ave. MW (PNUCC, 1983b).
The
as
the
variable costs of operating a PNW coal plant used
cost
of replacement power
in
the
interruptible
79
simulation
were
estimated
from average
figures
current plants in the region (PNUCC, 1982) :
Fuel cost;
Operating _& maintenance
Total
10.60 mills/KwH
1.53 mills/KwH
12.13 mills/KwH
of
all