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IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 21, NO. 4, NOVEMBER 2006
On the Quantification of the Network Capacity
Deferral Value of Distributed Generation
Hugo A. Gil, Member, IEEE, and Geza Joos, Fellow, IEEE
Abstract—This paper presents an approach to the quantification
of the distribution network capacity deferral value of distributed
generation (DG). Besides different technical benefits such as reliability and power quality improvement, there are a number of economic benefits related to DG, the most important of which being
the end-user electricity bill reduction capability. However, since the
onset of the implementation of these technologies, the potential of
DG to defer investments on distribution wires and transformers
was soon realized, to the point that “non-wire solutions” are now
considered as an alternative to network upgrades. In this work, a
first approximation to the capacity deferral benefits brought about
by DG is obtained. Such approach can be the starting point towards the development of a framework of credits to the owners of
DG that fully and fairly recognize the deferral benefits provided to
the utility. The financial performance of investments on these important technologies can be then improved, thus broadening DG
as a viable market alternative for customers and utilities.
Index Terms—Distributed generation, economic benefits, investment deferral.
nb
g
NOMENCLATURE
Number of buses in the network.
Index of group of feeders for upgrade.
Current in feeder (A).
Sensitivity of the current , in branch (or feeder)
by an increment (or reduction) of load (A/kW).
Active load at bus (kW).
Growth rate of load (kW/year).
Active power injection by a DG at bus .
Deferral time for feeder (years).
Deferral time for group of feeders (years).
Real interest rate (%/year).
Investment cost on group of feeders ($).
Benefit to utility by DG at bus i ($).
I. INTRODUCTION
URING the last decade, the deployment of distributed generation (DG) resources has been growing steadily. In this
process, the power distribution utilities have been one of the in-
D
Manuscript received July 12, 2005; revised June 1, 2006. This work was supported by the National Sciences and Engineering Research Council (NSERC),
Canada, by the Fonds nature et technologies; Province of Quebec, Canada and
by Natural Resources Canada through the Innovative Research Initiative and
the Technology and Innovation Program as part of the climate change plan for
Canada. Paper no. TPWRS-00428-2005.
The authors are with the Department of Electrical and Computer Engineering, McGill University, Montreal, QC H3A 2A7, Canada (e-mail: hugo.
[email protected]; [email protected]).
Digital Object Identifier 10.1109/TPWRS.2006.881158
dustry’s most concerned stakeholders. The main reason is that
DGs are connected primarily within their distribution networks,
which have been designed under the paradigm that consumer
loads are passive and the power flows only from the substations to the consumers and not in the opposite direction. For this
reason, many studies on the interconnection of DG with distribution networks have been carried out, ranging from control and
protection to voltage stability and power quality ([1], [2] among
many others). There have also been serious arguments about the
environmental impacts of the widespread use of DG, in terms of
pollutant emissions and noise [3].
Notwithstanding the disadvantages of DG, some important
benefits have also been acknowledged. These benefits are not
only technical, such as the improvement of end-user power
quality and reliability. In fact, there are a number of economic
benefits of DG, the most important of which being the end-user
electricity bill reduction, especially for gas-fired technologies
(peaking internal combustion engines or microturbines). This
is especially valid in those regions where the so-called “spark
spread”, that is, the difference between the local electricity rates
and the gas prices, is high.1 The quantification of this benefit
is relatively straightforward as the technology costs (upfront
investment, taxes, utility rates, and fuel) can be weighted against
annual expenditures in electricity purchases and financial returns
thereforecan be estimated without much effort by the end-user.
On the other hand, utilities have recognized the importance
of the utilization of DG solutions to defer the investment on
distribution wires and power transformers. In some cases, DG
has even been the only viable solution found to supply growing
demands on certain neighborhoods, due to NIMBY opposition
and aesthetical concerns [4].
The identification and quantification of the benefits of DG has
received a great deal of attention from regulators, system operators, public utilities, consumers and society in general. Governments are devoted to provide the owners of renewable DG
with credits of different sorts as a way of encouraging the installation of clean technologies. However, there has been some
criticism regarding the way these credits are defined. We argue
here that in an open market for DG deployment and incentives,
such credits should be based on the real benefits produced by the
particular DG solution and not in governmental policies in the
form of flat production credits or tax benefits. The DG industry
will only mature as a viable market alternative for consumers
and utilities when all the benefits produced by a particular DG
are accounted for and credited to its owners.
1The state of New York, in the United States, is an example of a region with
a relatively high “spark spread”. In regions like this, the use of microturbines to
produce electricity locally by the end-user is very attractive, especially for CHP
combined heat and power (CHP) applications.
0885-8950/$20.00 © 2006 IEEE
GIL AND JOOS: ON THE QUANTIFICATION OF THE NETWORK CAPACITY DEFERRAL VALUE OF DG
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This paper then targets the quantification of one of the most
important benefits of DG, which is the capability to defer
planned or required investments in wires and transformers by
the distribution utility.
If the capacity deferral benefit of DG can be quantified, utilities can find new opportunities to implement “nonwires” solutions to tackle necessary network upgrades and internalize all
benefits. Regulators have also more opportunities to better design credits for third-party owned DG investments that benefit
not only the owner itself but the local utility altogether.
II. THE VALUE OF INVESTMENT DEFERRAL
Distribution utilities have traditionally followed the load
growth within their concession areas through the investment on
new power transformers in heavy loaded substations or by the
upgrade or installation of new distribution feeders. However,
in many cases, the costs of upgrading the network by traditional procedures can reach extremely high costs, especially in
congested metropolitan areas. Therefore, by using DG technologies to supply locally the needs of the loads, the investment
on strategic expensive network upgrades can be deferred.
The value of the deferral of these investments depends on the
investment costs and the time by which these investments are
deferred. This deferral time depends, in turn, on the size of the
DG being installed and the rate at which the local load grows.
This topic is explored next.
A. Impact of DG on the Distribution Network Currents
When a new DG is installed to operate under a certain
equivalent capacity factor, the currents in some of the feeders
are reduced, according to the size of the DG and its location
throughout the network. Those DG located at the extremities
of the feeders will impact the whole network to a larger extent.
If the demand across the network continues to grow, certain
time will pass before the feeder currents reach the values found
before the DG started to operate. The benefit to the distribution
utility is immediate: it will take more time for the current on
those loaded transformers or feeders to reach the technical
limits at which new investments have to be put in place. The
benefit is even more evident when the current reduction defers or avoids already scheduled investments. Therefore, one
of the first steps towards the quantification of the benefit of
transformers or feeders investment deferral is to measure the
impact of the DG output on the currents across the distribution
network.
With this in mind, let
be the sensitivity of the current in
feeder , , by an increment of load , represented by
. So
is defined as
Fig. 1. Flowchart with the steps for the calculation of the factors in (1).
much does the calculated
change (this is better viewed by
plotting
versus
). Ideally, the
factors should remain
but due to the nonconstant for different small values of
linearity of the system, slight changes are observed.
It was perceived for the network under study that by varying
from 0.1% to 1% of the bus load, the
factors changed
by up to 0.1% of their total value, which was considered substan, considering
tially small. For instance,
equal to 0.1% of
, whereas
a
for a
equal to 1% of the corresponding load (a change in
equal to 0.3% of the load was
the factor of 0.89%). A
factors. Such value is rechosen for the calculation of the
lated to the integration step of (9), which was also considered
suitable (small enough) to carry out the numerical integration
without compromising its accuracy, as it will be described later.
The validation loop is done only once for the network under
study.
Continuing with the methodology, for every increase on network loads, there will be an increase in the different feeder currents, according to the location of the demand relative to that of
the feeder. The increase in current , by a load increment
is equal to
(2)
If the demand
is growing in time at a certain rate, , then
, is equal to
the incremental rise on a given demand,
(3)
(1)
Even though the calculation of these
is relatively complex
(obtained from the Jacobian of the distribution load-flow), they
can be computed numerically. Fig. 1 shows the basic flowchart
factors. The critwith the steps for the calculation of the
ical sequence is the validation loop, which consists on choosing
and determining by how
small but increasing values of
Therefore, the differential of the feeder current
spect to time is given by
with re-
(4)
However, according to the nonlinearities of the distribution
load flows,
depends on , that is, on the state of operation
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IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 21, NO. 4, NOVEMBER 2006
and may itself depend on the time, that is, there may be periods when the demand grows faster than in others. Therefore
(5)
Expression (5) characterizes the rate of growth of feeder currents with time.
is
Now, when a given DG with equivalent capacity
installed at bus , the feeder currents drop by a certain amount
given by
(6)
This expression involves another sensitivity factor,
,
which gives a measure of the change in the current in feeder
due to the injection of power,
, in kVA, by a DG located
at bus . Notice that these factors differ from the ones derived
in (1) as the effect of the power injection by a DG depends
on its operating power factor and so it cannot be treated as a
negative load. Expression (6) can however be calculated exactly
by running two load flows, one with the DG at bus and other
one without it. As the simulations below will show, the output
of the DGs at different power factors will be studied.
Therefore, we can now define the time , as the time that it
takes the current in feeder , , to reach the value it had before
the DG was installed, that is, the period during which the growth
of the feeder currents reach the total current drop caused by the
for
presence of the DG. Notice that there is a different time
is negative, that is, the ineach feeder. Also, in most cases,
stallation of a given DG will typically cause a reduction in feeder
currents. However, according to the size of the new DG, the current in immediate upstream feeders may reverse to a point that
such reversed current reaches the feeder’s limit. This situation
takes place when the DG power output equals the local bus load
plus the total feeder’s capacity. In this situation, the utility may
either: 1) invest on new network capacity to integrate the DG
output or 2) temporarily limit the DG output so as to keep current levels within accepted levels. As the loads continue to grow,
the reversed current is reduced and more and more DG output
can be integrated. If low load growths are expected, the utility
may definitely invest in new “wires” capacity. In this case, the
connection of the DG imposes a cost instead of representing a
benefit to the utility, although, according to the industry’s experience, this situation is the exception and not the rule.
Considering that the above mentioned situation does not take
place, can be calculated, according to (5), as the time at which
the following expression holds for those feeders whose current
drops due to the installation of the DG
(7)
is the current at the time right before the DG is
where
installed. Integrating the term on the right-hand side, and
according to (6)
(8)
Fig. 2. Deferral time by a drop in the feeder current.
Fig. 3. Deferral time when a DG increases the feeder current.
This expression could be easily calculated, were it not for the
and depend on the operation point and on time,
fact that
respectively. Therefore, this integral has to be solved numerically step by step, where at every time interval, new values of
and must be calculated.
The time can be interpreted as a capacity deferral time in
the sense that it will take more months or years for the current
in feeder or substation transformer to reach the technical limits
at which new investments are needed.
To better illustrate this concept, consider Fig. 2, where it is
shown how the current in feeder is growing in time, and then
at
, a DG with capacity
is installed at bus . The
current then drops by an amount given by (6) and, as the dewill pass before the curmands continue to grow, the time
achieves the level found previous to the installation of
rent
the DG.
Now, as it was stated earlier, suppose that the current in one or
some feeders is reversed by a DG, whose output is large enough
to increase the magnitude of the reversed currents as opposed to
decreasing it. As the loads continue to grow, the magnitude of
those reversed currents will decrease over time until the current
reaches the levels seen before the DG was installed. The deferral
time for those feeders can be calculated in a similar way as in
as positive.
(8), but taking the term on the right-hand side,
This situation is better explained in Fig. 3. In order to account
for both conditions, (8) should then be written as
(9)
GIL AND JOOS: ON THE QUANTIFICATION OF THE NETWORK CAPACITY DEFERRAL VALUE OF DG
However, in such particular cases, the calculated is not indicative of the time by which investments on the corresponding
should not be confeeders can be differed. These values of
sidered in further calculations to evaluate the capacity deferral
benefits. Some utilities attempt to avoid the situation of reversed
currents by limiting the maximum amount of DG capacity connected to their distribution networks (sometimes up to 10% of
the peak load).
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time minus the present value of the deferred investment. In other
words
(11)
The total benefit, , to the utility given by the DG located at
bus is the sum of all benefits obtained in all groups of feeders.
Therefore
B. Network Expansion Strategies
(12)
During the expansion planning process, the distribution utilities elaborate expenditure plans for wires and transformers that
are about to reach the admissible technical levels within the
planning horizon according to the expected demand growth.
More precisely, utilities have different strategies when dealing
with overloaded feeders. According to these expansion strategies, the economic and financial costs of the foreseen investments are then carefully calculated and the projected plan is then
passed on for budget approval. However, when a given feeder
reaches its maximum current capability, it might not make economic sense to just upgrade the corresponding feeder without
upgrading parts of the downstream network. In other words, if
a given feeder becomes overloaded, the utility would take the
opportunity to upgrade a larger part of the network with a new
conductor with larger current capability. In this way, utilities divide the network in different strategic groups of feeders. If one
particular feeder becomes overloaded, all the feeders belonging
to its group are also upgraded.
The methodology presented here was applied to the 34 bus
version of the test distribution system presented in [7]. Fig. 4
presents an outline of the network (not to scale) as presented
in the mentioned reference. To simplify the analysis and the
innumerous load flows run, the effect of the voltage regulators
was ignored.
C. Quantification of the Investment Deferral Benefit
A. Assumptions
As it was seen in Section II-A, the presence of DG postpones
the need for investment on certain portions of the network by a
time span given by . Therefore, the planned expenditures for
a particular feeder can be held up for months or years. As
a result, the economic benefits to the utility are immediate and
are related to the temporal value of money.
The time by which a given investment on a group of feeders is
delayed is given by the lowest deferral time of any of the feeders
belonging to that particular group. In other words, the presence
of a particular DG will cause a drop in all/some of the feeders’
currents in a particular group. The investment in upgrading the
whole group will take place at the first moment that any of the
group’s feeders becomes overloaded.
The benefit to the utility is related to the time value of money.
, of a deferred inIn mathematical form, the present value,
vestment in a particular group of feeders, depends on the total
investment cost of the group, , the group’s deferral time ,
and the real interest rate, . The exponential continuous approximation to the expression for the present value of money (consider for instance, [5]) is given by
In order to implement the described methodology and obtain
the desired meaningful generalized quantification, several assumptions had to be made, which are described next.
1) DG Capacity: The analysis of the deferral benefit was
calculated by installing a hypothetical DG at every bus of the
system (one bus at a time), with a capacity varying from 10 to
100 kVA.
2) Load Growth: The load growth rate was supposed to be
3% a year for all buses, although different rates can be supposed
for different buses. Lower growth rates yield larger benefits as
all investments can be deferred for longer periods.
3) Upgrade Strategies and Feeder Groups: The network was
divided into different groups of feeders,2 according to the network topology and the upgrading strategy followed by the utility
as described before. Fig. 5 presents the breakdown of the groups
into which the distribution network was divided.
This network separation was done as an attempt to represent
the common case of a distribution network comprised of a backbone group of feeders (Group 1 in the example) and lateral, secondary feeders attached to it.
According to one of the assumptions of the methodology, if
for instance, the current in feeder between buses 842 and 844
(Group 6) reaches the maximum permitted value, the utility
strategy is to upgrade all the feeders belonging to the corresponding group 6.
(10)
As a consequence, the net benefit to the utility,
, obtained
by postponing a planned investment in a particular group, , for
months or years due to the presence of a DG at bus is given
by the difference between the values of the investment at present
To calculate the deferral time for a group, , (in months or
years) due to the presence of a DG at bus , the deferral time is
first calculated for all feeders according to (8). The deferral time
for a particular group is then the minimum deferral time for all
feeders belonging to that group. In other words
(13)
III. ASSUMPTIONS, APPLICATION, AND RESULTS
2In this paper, a feeder represents any segment of the distribution network
between two loads (distribution transformers).
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IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 21, NO. 4, NOVEMBER 2006
Fig. 5. Test distribution network divided into feeder upgrade groups.
Fig. 4. 34-bus test distribution network.
Moreover, once a given group has been selected for upgrade,
it was assumed that the upgrading strategy is then followed by
the replacement of the feeders’ conductors by the next conductor in the list of AWG conductor classification. For instance,
it was assumed that if a feeder made with, say #2 AWG phase
conductors is to be upgraded, the utility will then install new 1/0
AWG conductors for the corresponding group. This practice obviously changes widely from utility to utility; however, such an
assumption makes possible the desired generalized quantification. More expensive upgrades will yield larger benefits.
As a result, there is an increment in the maximum power
that can be distributed along the corresponding feeder group.
For instance, the 1/0 AWG conductor has cross-sectional area
60% greater than that of the #2 AWG, therefore, it can carry
60% more current. Thus, the upgraded feeders can then transport 60% more power. This notion is very important for the calculation of upgrade costs as shown in the next section.
4) Upgrade Costs: The calculation of upgrade costs is one
of the most important steps towards the quantification of the deferral benefit of DG. It is evident that the total costs of a particular network upgrade depend on particular conditions such as
the duration of the work, the materials and number of crews involved, the type of feeder (overhead or underground), its length,
etc.
In order to obtain typical figures for distribution network upgrade costs, the results from the study [7] were used. In this
important work, typical distribution costs for 124 utilities (in
United States) were examined. Different attributes such as annual investments or maintenance costs are averaged out in terms
of peak power or number of costumers served. In particular, the
average marginal investments on feeders per growth in system
peak are calculated for the period 1995–1999 for all the utilities
under analysis. Those values were used as an approximation for
the cost per megawatt of new investments on feeders.
From the above mentioned study, it could be seen that typical
marginal costs are spread over a wide interval (from 100 000
to 2 million dollars per megawatt of system peak). However,
GIL AND JOOS: ON THE QUANTIFICATION OF THE NETWORK CAPACITY DEFERRAL VALUE OF DG
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TABLE I
GROUP CONDUCTORS, AMPACITY LEVELS AND UPGRADE COSTS
Fig. 6. Feeder groups upgrade cost function.
half of the 124 typical investment costs are clustered within the
200 000–500 000 $/MW range (200–500 $/kW). The reason for
this wide variability is that upgrade costs depend not only on
its own capacity but also on factors such as the length of the
feeder. For instance, an upgrade will be less expensive, per kilowatt, if the feeder in question is only several hundreds of meters
long compared with much longer feeders running across a whole
neighborhood, considering that the capacities of both upgrades
are the same.
With this in mind, we used a proportional upgrade cost function, by which the total cost of the upgrade (in $/kW) varies between the lower limit of 200 $/kW (for the shorter feeder groups)
to 500 $/kW (for the longer feeder groups). The costs for all
other upgrades fall between those two values according to the
length of the group. Fig. 6 clarifies this assumption.
In the case of our particular test system, the eighth group
is the shortest (152 m) so its upgrade cost is 200 $/kW, while
group number 1 is the longest (14.3 km) with an upgrade cost
of 500 $/kW. Table I presents the list of existing conductors,
the conductors used for upgrade together with the existing, upgraded feeder current capacity, and group’s length and upgrade
cost.
B. Simulation and Results
After considering all the hypotheses described above, a hypothetical DG with capacity ranging between 10 and 100 kVA was
placed at one bus at time for all the buses across the network.
The integral given by (9) was solved numerically step-by-step,
a process that required running hundreds of load flows, for each
DG capacity and location.
The total benefit in $/kW for each capacity level was calculated. It was seen that this unitary benefit in $/kW does not
change much with the capacity itself, so a bus average benefit
was calculated. Although this average benefit does not change
much with the capacity of the DG itself, it depends in large extent on its relative location within the system. The largest benefits are obtained when the DG is located downstream after the
end of one or several groups of feeders.
To better clarify this fact, consider the case of a 100 kVA DG
operating at unity power factor (100-kW output) located at bus
832. This bus is the second to last bus of group number 1. As
the current in the feeder 832-858 (the last feeder of the group)
has not been greatly reduced by the presence of this DG (just
0.82 A), the total deferral time for the whole feeder is small, no
matter if all other currents in this group dropped significantly.3
Therefore, the current in feeder 832-858 will soon reach the
level that existed before the DG was installed (simulations show
a time of 1 year, according to the load growth assumed, compared to a deferral time of 13.5 years found for an upstream
feeder such as the 854–852).
As it was stated before, the utility’s strategy is to upgrade the
network by groups of feeders; therefore, the upgrading time for
the group will be set by the time by which the current in any of
the feeders in that group first reaches the existing level with no
DG (in this case, 1 year found for feeder 832-858). Therefore,
when the DG is installed at bus 838, the upgrade for group 1
will be delayed for 1 year. The upgrade cost for this group is
given by the substitution of the existing #2 AWG conductors
by new 1/0 AWG conductors (Table I) at a cost that, according
to the length of the group (14.3 km) and the function given by
Fig. 6, is equal to $278 520. Therefore, the benefit of delaying
such an investment for 1 year is given by (11), which is $13 584
or 135.84 $/kVA.4 However, this is not the total benefit given by
this particular DG. The total load of group 6, which is located
downstream of bus 838, is relatively high (152 kVA). As a result,
any voltage improvement on bus 834 will represent some current
reductions along the feeders in group 6. In fact, a deferral time
of 0.42 years (5 months) was found for these feeders, with a
total benefit, that according to the length of the group and the
corresponding upgrade cost, reaches 32.74 $/kVA. Therefore,
the total benefit to the utility by a 100 kW DG installed at bus
.
832 is
Nonetheless, different DG technologies are likely to operate
at power factors different from unity, although utilities favor or
even require the operation of the DG at leading power factors
(are required to produce reactive power). The reason is that distribution network loads are mostly reactive and the consumption of reactive power by the DG degrades the network’s power
factor, with all the consequences that this implies.
The deferral benefit was calculated for all DG operating at
power factors within the range of 0.9 lagging and 0.9 leading, as
shown in Fig. 7, which illustrates the deferral benefits in $/kVA
3In fact, there is a “downstream effect” deferral by the DG. Currents in downstream feeders will slightly drop due to voltage improvement. This effect will
be discussed later.
4As it was mentioned before, deferral values in $/kVA were almost constant
for the different DG capacities tested at the same bus.
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Fig. 7. Capacity deferral benefit of DG in $/kVA for the test network.
calculated for all the buses across the network. Under the series
of assumptions considered, important benefits to the utility may
be realized for DG connected in their networks. Buses from 800
to 810 are not shown, as the benefits obtained for those locations
are negligible.
Fig. 7 confirms the fact that DG operating at lagging power
factors provides the utility with lower benefits than those operating at unity or leading power factors.
Continuing with the analysis of specific DG locations, consider now the case when the 100-kVA DG, operating at unity
power factor, is moved over to the end of, or downstream of
group 1 (for instance, to bus 858). In such case, all feeder
currents in that group will be significantly reduced (of course,
depending on the capacity of the DG), therefore the deferral
time for the group will increase markedly. The deferral benefit
jumps from the 168.57 $/kVA found before for bus 832, to
926.06 $/kVA for the new location (bus 858) (again, refer to
Fig. 7 for the values at unity power factor). Total deferral time
for feeder 832–858 changes abruptly from 1 year to 15.1 years,
therefore the new deferral time for group 1 (the minimum deferral time found for all feeders in that group) is now 7.67 years,
which corresponds to feeder 800–802. Again, considering the
upgrade cost for group 1 of $278 520, being delayed for 7.67
years, gives the utility a total benefit of 886.86 $/kVA. This,
plus 39.20 $/kVA of benefit from group 6, gives the utility the
total benefit of 929.06 $/kVA shown (again, for a DG installed
at bus 858).
From Fig. 7 it can also be seen that the largest benefit is obtained from a DG located at bus 848, which is not only the farthest bus of the system, but also one located in an area with
most of the load. This was the result expected because the farther the DG is installed with respect to the main distribution
substation, the wider the effects will be in terms of feeder currents reduction.
Notice that the selection of the different feeder groups plays
a key role in the final numerical values of deferral benefit. The
most important objective here is to estimate the extent of such
benefit. Once utilities realize the extent of the deferral benefit
through generalized methodologies like this, the numerical approach should be incorporated into the utility’s particular investment/planning process in order to estimate real benefits and
savings.
IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 21, NO. 4, NOVEMBER 2006
Fig. 8. Effect of equivalent load reduction and voltage improvement on feeder
currents.
C. Voltage Improvement Benefit
When a particular DG is installed in a distribution network,
the injection of active power helps to improve also the voltage
profile of the network. This is due to the fact that, in distribution
networks, the resistance of the wires is generally larger than
their reactance, so the flow of active power has a larger influence
on the voltage profile as opposed to high-voltage transmission
networks.
The electric benefits of DG studied so far, in terms of feeder
current reductions, are a combination of equivalent load reduction and voltage improvement for feeders upstream of the DG.
However, the improvement of the voltage at a particular bus
helps to also reduce currents in feeders downstream of the DG.
This effect can therefore be quantified by knowing the fact that
deferral times created by a particular DG in all downstream
feeders/groups are only due to voltage improvement.
As an example, the benefits obtained from a DG located along
group 1, from bus 802 through bus 832, are only due to voltage
improvement. Total deferral times for the whole group will be
defined by the minimum deferral time found for any feeder in
that group, which will certainly be any feeder downstream of the
DG all the way to the end of the group. Consider, for instance,
Fig. 8, where the hypothetical 100-kVA DG, producing at unity
p.f. is installed at bus 830 and the effect of both, the injected
power and the voltage improvement, on feeder currents in group
1 are shown.
From Fig. 8, it can be seen that currents on feeders upstream
of bus 830 are reduced significantly due to injection from the
DG. However, the small feeder current reduction downstream
of bus 830 is due to the improved voltage profile. These current
reductions, although small, set the deferral time for the whole
group 1 and can represent important benefits to the utility if
investment costs are high. In this particular case, there is a delay
of 0.75 years (nine months) for an investment of $278 524 with
a benefit of 102.51 $/kVA to the utility, according to the real
annual interest rate of 5% assumed.
This analysis help to better understand the benefits of voltage
improvement by DG. An important quantification of the voltage
improvement benefits by DG was made in [6], where the impacts on the life-time of a tap-changer transformer by a 500-kW
solar plant were quantified.
GIL AND JOOS: ON THE QUANTIFICATION OF THE NETWORK CAPACITY DEFERRAL VALUE OF DG
IV. CONCLUSIONS
This paper presented an approach for quantifying the deferral
benefits created by DG on planned or scheduled network upgrade investments.
Different DG solutions provide the owners with many wellknown benefits, the most important of which have to do with
electricity bill reduction. However, the presence of DG has been
recognized to provide utilities with an alternative to traditional
“wires” network upgrades. A given DG can postpone or even
eliminate the need for investments on feeders or transformers
(strategies better known as “nonwire solutions”). However, only
when all the economic benefits of DG are understood and quantified can all the advantages be exploited to their full extent.
Each DG application yields different benefits to the distribution utilities. Although a generalized quantification of the
deferral benefit is extremely complex, if not impossible, the
main contribution of this paper is the utilization of real typical
upgrade costs for utilities. After several necessary assumptions
were made, an idea of the magnitude of the benefits was
obtained.
It was found that the most important deferral benefits are obtained when DGs are installed at the end of long feeders and near
load pockets. This almost obvious result was not only confirmed
but also quantified. However, the benefit figures obtained in the
form of $/kVA depend largely on the actual upgrade strategies
followed by the utilities.
A quantification of the benefits brought about by the voltage
improvement effect of DG was also carried out. The improved
voltage at a given bus will cause a slight reduction on downstream currents. These reductions can play an important role
in the case of large upgrade investments, as was shown in the
results.
All the quantifications performed in this paper were based on
amounts related to the capacity of the DG, in $/kVA. The quantification of such benefits with respect to the energy output, that
is, in $/kWh, depends on the timing of the planned or scheduled upgrades. Such quantification is very important towards
the development of deferral credits to DG technologies, especially when they are owned by third parties and not by the utility,
which can internalize to itself all the benefits. Such quantification is motive of ongoing research.
An important issue brought up by the utilities is the concern
that the DG will not operate when needed, especially during
peak load periods. In addition, DG developers and utilities altogether state that the deferral benefits may be short-lived when
the planned wire upgrades have to be implemented later anyway.
These are important topics that have to be contemplated when
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considering utility or third-party owned DG as a network nonwires upgrade solution.
Finally, we argue that the DG industry will only mature as
a viable market alternative for consumers and utilities when all
the benefits produced by a particular DG are accounted for and
credited to its owners.
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Hugo A. Gil (S’00–M’06) received the Eng. degree from the Universidad Nacional de Colombia, Medellín, Colombia, in 1995 and the Dr. Eng. degree from
the Universidade Federal de Santa Catarina, Florianópolis, SC, Brazil in 2001,
both in electrical engineering.
He is currently a Postdoctoral Fellow at McGill University, Montreal, QC,
Canada. His research interests are the regulatory and economic issues of distributed generation, power systems expansion planning, transmission network
cost allocation, as well as optimization and microeconomics and their applications to power systems.
Geza Joos (M’82–SM’89–F’06) received the M.Eng. and Ph.D. degrees from
McGill University, Montreal, QC, Canada, in 1974 and 1987, respectively.
He was with ABB, the Ecole de Technologie Supérieure, and Concordia University, all in Montreal. Since 2001, he has been with McGill University, where
he is involved in fundamental and applied research related mostly to the application of high-power electronics to power conversion and power systems, an area
in which he has published extensively.
Dr. Joos was Vice Chair (2001–2003) of the Industrial Power Converter Committee of the IEEE Industry Applications Society (IAS) and is active in a number
of IEEE Power Engineering Society working groups, including the DC and
FACTS Subcommittee of the Transmission and Distribution Committee and
Chair (2003-present).