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Introduction to Transmission Planning
Assignment:
Read Chapters 7 and 8 of text.
Read these notes and also the appendix.
See HW10 on the website.
1.0 Overview of bulk electric power planning
Construction of new electric generation and transmission is a
capital-intensive activity. In addition, it is generally not possible to
quickly build generation or transmission. A full time-table for
design and construction of such facilities usually requires at least
2-3 years and more frequently 3-5 years or more. Therefore, any
organization that intends to invest in new generation or
transmission must have the ability to access large quantities of
money with significantly delayed payback revenue stream.
There are planning needs at the distribution level but those needs
focus mainly on the distribution wires or cables and often make
use of the available roadside utility right-of-way.
We will focus on the bulk electric power system planning needs.
These are more complicated for two reasons.
1. Bulk electric power system planning involves both generation
(or resource planning), as well as transmission planning, and
there usually exist complex interdependencies between the two.
Efforts at planning one of them without consideration of the
plans for the other will typically result in less desirable plans in
terms of reliability or in terms of economics, or in terms of both.
2. Bulk electric power system planning often involves acquisition
of new land, either for power plants of for transmission right-of-
way. This in itself is a socially complex issue that involves
many constituencies, most of whom have at best a layman’s
understanding of electric power engineering and economics.
Such people must be contacted, educated about the needs, and
given time to respond with concerns. The acronym “NIMBY,”
which means “Not In My Back Yard” was coined to reflect a
common position taken by many people and communities when
confronted with the possibility of a new power plant or
transmission line located nearby their living or working
location. There are many reasons for this position, but possibly
the most common are aesthetic, environmental, and health.
Planning involves simultaneous economic and reliability
evaluation of alternatives. Either one may motivate interest in or
the need for new investment.
2.1 Economic issues:
Two economic issues that have always been important in making
planning decisions are
1. What is the investment cost of each alternative?
2. How is the yearly operational cost impacted by each alternative?
Since the creation of electricity markets, it is also important to
understand the impact of each alternative on the operation of the
market. An alternative might be selected in order to maximize
profits in the electricity markets.
2.2 Reliability issues:
It is inevitable, if the usage of the transmission system is growing
or changing through load growth or load shifting or through
generation growth or generation shifting, that existing generation
and transmission will at some point become insufficient, leading to
an unreliable system. To better frame this notion, the industry has
established two different categories of reliability. They are:
- Adequacy: The ability of the power system to supply the
aggregate electrical demand and energy requirements of the
customers at all times, taking into account scheduled and
reasonably expected unscheduled outages of system elements.
- Security: The ability of the power system to withstand sudden
disturbances such as electric short circuits or unanticipated loss
of system elements.
2.0 Some basic tools
There are some very basic tools that are required in almost any
bulk electric power system planning endeavor.
Load forecasting program: Forecasting is a systematic method
of quantitatively identifying future loads.
o There are short-term, mid-term, and long-term load
forecasting methods.
o One may forecast actual load for a particular time (or times),
or one may forecast peak load for a particular time interval.
o Steps that are common to most load forecasting procedures:
Data preprocessing:
classification of loads: residential, commercial,
industrial, other
by geographical area
reduction of highly correlated inputs
outlier detection
General model identification:
Trend-line extrapolation, regression, time series,
neural network, expert system
Specific model form:
e.g., what kind of regression model, time series
model, or nn structure to use?
Model estimation:
tune various parameters of the specific model
Diagnostic checking:
check to determine whether model is correct
For example, in regression, the general approach is:
Let y(t-k) represent the historical loads.
Let x represent the time variables (season, week,
time-of-day) and the weather variables (current
temperature or maximum temperature for today,
forecasted temperature for tomorrow, past average
temperatures, or difference between average and
forecasted temperature).
Then we have that
y(t)=f(x,y,t)
y(t) is the load at time t.
f is a function chosen from one of the following:
linear function: y(t)=a+bt
modified exponential model: y(t)=a+bct
Gompertz model: y(t)=e(a+bct)
Logistic model: y(t)=1/(a+bct)
Model estimation done by least squares or maximum
likelihood
Load duration curve: A critical issue for planning is to identify
the total load level for which to plan. One extremely useful tool
for doing this is the so-called load duration curve, which is
formed as follows. Consider that we have obtained, either
through historical data or through forecasting, a plot of the load
vs. time for a period T, as shown in Fig. 1 below.
Load (MW)
Time T
Fig. 1: Load curve (load vs. time)
Of course, the data characterizing Fig. 1 will be discrete, as
illustrated in Fig. 2.
Load (MW) Time T
Fig. 2: Discretized Load Curve
We now divide the load range into intervals, as shown in Fig. 3.
10
Load (MW)
9
8
7
6
5
4
3
2
1
0
Time T
Fig. 3: Load range divided into intervals
This provides the ability to form a histogram by counting the
number of time intervals contained in each load range. In this
example, we assume that loads in Fig. 3 at the lower end of the
range are “in” the range. The histogram for Fig. 3 is shown in
Fig. 4.
9
8
7
6
Count
5
4
3
2
1
0
0 1 2 3 4 5 6 7 8 9 10 11
Load (MW)
Fig. 4: Histogram
Figure 4 may be converted to a probability mass function, pmf,
(which is the discrete version of the probability density
function, pdf) by dividing each count by the total number of
time intervals, which is 23. The resulting plot is shown in Fig. 5.
0.391
0.348
Probability
0.304
0.261
0.217
0.174
0.130
0.087
0.043
0
0 1 2 3 4 5 6 7 8 9 10 11
Load (MW)
Fig. 5: Probability mass function
Like any pmf, the summation of all probability values should be
1, which we see by the following sum:
0.087+0.217+0.217+0.174+0.261+0.043=0.999 (it is not exactly
1.0 because there is some rounding error). The probability mass
function provides us with the ability to compute the probability
of the load being within a range according to:
Pr(Load within Range) Pr(Load L)
L in Range
We may use the probability mass function to obtain the
cumulative distribution function (CDF) according to:
Pr(Load Value) Pr(Load L)
L Value
From Fig. 5, we obtain:
Pr(Load 1) Pr(Load L) 1.0
L1
Pr(Load 2) Pr(Load L) 1.0
L2
Pr(Load 3) Pr(Load L) 1.0
L3
Pr(Load 4) Pr(Load L) 1.0
L2
Pr(Load 5) Pr(Load L)
L5
0.217 0.217 0.174 0.261 0.043 0.912
Pr(Load 6) Pr(Load L)
L6
0.217 0.174 0.261 0.043 0.695
Pr(Load 7) Pr(Load L) 0.174 0.261 0.043 0.478
L6
Pr(Load 8) Pr(Load L) 0.261 0.043 0.304
L8
Pr(Load 9) Pr(Load L) 0.043
L9
Pr(Load 10) Pr(Load L) 0
L 10
Plotting these values vs. the load results in the CDF of Fig. 6.
1
0.95
0.90
0.85
0.80
0.75
0.70
Probability(Load > L)
0.65
0.60
0.55
0.50
0.45
0.40
0.35
0.30
0.25
0.20
0.15
0.10
0.05
0
0 1 2 3 4 5 6 7 8 9 10 11
L (MW)
Fig. 6: Cumulative distribution function
The plot of Fig. 6 is often shown with the load on the vertical
axis, as given in Fig. 7.
11
10
9
8
L (MW)
7
6
5
4
3
2
1
0
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
Probability(Load > L)
Fig. 7: CDF with axes switched
If the horizontal axis of Fig. 7 is scaled by the time duration of
the interval over which the original load data was taken, T, we
obtain the load duration curve. This curve provides the number
of time intervals that the load equals, or exceeds, a given load
level. For example, if the original load data had been taken over
a year, then the load duration curve would show the number of
hours out of that year for which the load could be expected to
equal or exceed a given load level, as shown in Fig. 8.
11
10
9
8
L (MW)
7
6
5
4
3
2
1
0
876 1752 2628 3504 4380 5256 6132 7008 7884 8760
Number of hours that Load > L
Fig. 8: Load duration curve
Load duration curves are useful in a number of ways.
• They provide guidance for judging different alternative plans.
One plan may be satisfactory for loading levels of 90% of
peak and less. One sees from Fig. 8 that such a plan would be
unsatisfactory for 438 hours per year (or 5% of the time).
• They identify the base load. This is the value that the load
always exceeds. In Fig. 8, this value is 5 MW.
• They provide convenient calculation of energy, since energy
is just the area under the load duration curve. For example,
Fig. 9 shows the area corresponding to the base load energy
consumption, which is 5MWx8760hr=43800 MW-hrs.
11
10
9
8
L (MW)
7
6
5
4
3
2
1
0
876 1752 2628 3504 4380 5256 6132 7008 7884 8760
Number of hours that Load > L
Fig. 9: Area corresponding to base load energy consumption
• They allow illustration of generation commitment policies
and corresponding yearly unit energy production, as shown in
Fig 10, where we see that the nuclear plant and fossil plant #1
are base loaded plants, supplying 26280 MWhrs and 17520
MWhrs, respectively. Fossil plant #2 and gas plant #1 are the
mid-range plants, and gas plant #2 is a peaker.
Gas plant #2
Gas plant #1
11
10
9
8
L (MW)
7
6 Fossil plant #2
5
4 Fossil plant #1
3
2 Nuclear plant
1
0
876 1752 2628 3504 4380 5256 6132 7008 7884 8760
Number of hours that Load > L
Fig. 10: Illustration of Unit commitment policy
Load duration curves are also used in reliability and production
costing programs in computing different reliability indices.
Power flow program: This well known tool is perhaps the
“bread and butter” of the planner since it enables the study of
steady-state network performance for various planning
alternatives, under different possible conditions expected in the
future, for normal states and for contingency states.
Voltage instability program: This is usually a variation of the
power flow program that enables the development of so-called
P-V or Q-V curves, often referred to as “nose curves.” In its
most evolved form, the program is called a continuation power
flow program.
Transient instability program: Dynamic security assessment
involves detection of transient instability, transient voltage dips,
and oscillatory instability, within the first 20 seconds or so
following a faulted condition. This tool is often referred to as a
time domain simulator.
Reliability criteria: Bulk electric system reliability begins with
planning. The North American Electric Reliability Council
(NERC), maintains an extensive set of standards that address
system adequacy and security, system modeling data
requirements, system protection and control, and system
restoration. These standards are located at
www.nerc.com/~filez/pss-psg.html. In addition to planning
standards, individual regional councils may develop their own
regional planning criteria. These are evaluated to ensure that the
regional criteria are consistent with NERC's planning standards.
A fundamental part of these standards is the disturbance-
performance table contained in the part on adequacy and
security. This table is based on the planning philosophy that a
higher level of performance (or lower level of severity) is
required for disturbances generally having a higher frequency
(or higher probability) of occurrence. This table is given below.
The criteria given in it must never be violated when planning
the system.
Some other tools that, although not always used, are generally
useful in the planning process, are described in what follows:
Reliability index evaluation program: A reliability index
evaluation program provides probabilistic indices to
characterize the reliability level of the power system.
o Common indices include Loss of Load Probability (LOLP),
Loss of Load Expectation (LOLE), Expected Energy Not
Served (EENS), Frequency of Load Interruption, and
Expected Duration of Load Interruption.
o The simplest of such programs model only generation, but
most also model transmission.
o The indices may be given at the system level, the regional
level, or the bus level.
o These programs provide a good quantitative evaluation of
reliability which can be utilized together with economic
criteria to select alternatives.
o These programs operate using either contingency
enumeration or Monte Carlo simulation. In these programs,
load is shed (after generation has been redispatched) in order
to avoid exceeding constraints.
o No commercial grade reliability evaluation program models
dynamic security constraints, and I am not aware of any that
model voltage instability constraints (although there may be
one of the latter). Therefore, the only constraints modeled in
these programs are ones due to overload and low voltage.
Production costing program: This program calculates a
generation systems’ production costs (costs of generating
power) together with generation reliability indices for long-
range generation planning decisions. Such programs incorporate
fuel costs and heat rates together with probabilistic models of
the load and each generator’s availability. Such programs were
developed before deregulation and typically were designed to
handle large number of generation units operating under a
centralized economic dispatch. Because of the computational
requirements of methods required to handle the probabilistic
nature of the models (convolution), such programs usually do
not represent the network. A modern day version of the
production costing program is the time domain market
simulator. This program provides assessment of each alternative
in terms of its effect on operating costs, or equivalently, in terms
of its effect on market efficiency. Such a tool needs to
chronologically calculate hour-by-hour production costs while
recognizing the constraints on the dispatch of generation
imposed by the transmission system. One such tool developed
by GE (MAPS) uses a detailed electrical model of the entire
transmission network, along with generation shift factors
determined from a solved AC load flow, to calculate real power
flows. This tool captures the economic penalties of re-
dispatching generation to satisfy transmission line flow limits
and security constraints.
3.0 Comments on resource planning
The pre-deregulation resource (generation) planning problem
differed from that of today. In the “old days,”
The amount of new resources required was almost entirely
dictated by forecasted load growth.
Generation decisions were made based on the criterion of long-
term minimum cost, where the principal decision variables
were:
o Usage (peaker or base load)
o Size
o Fuel type (coal, gas, nuclear)
o Site availability and related transmission availability
The actual decision would be made based on an economic
analysis of the alternatives using data characterizing each
alternative’s decision variables, including:
o Investment cost, expected plant life, and salvage value
o Plant heat rate (efficiency) and expected fuel cost
Production costing programs would usually be used in this
decision process.
The transmission planning process, although lagging behind the
resource planning process, was usually an integral part of it.
For example, it could occur that a long-term power purchase
agreement with another utility could replace or supplement
construction of new resources.
The “integrated resource planning” approach consisted largely
of the above together with consideration of demand-side
alternatives and/or renewable resources.
A key feature to the above is that the entire process was done
under the one “roof” of the vertically integrated utility company. In
contrast, the totality of resource planning today is done by many
different entities.
The main criterion used by many of these entities is that the long-
term payback must be profitable to the facility owner. Another
significant difference between the “old” resource planning process
and the “new” is the amount of uncertainty in expected revenues.
The revenues of the “old” utility came as a result of the prices the
regulators allowed the utility to charge their customers. Although
they did have some uncertainty about this (the regulators could
change their mind), that uncertainty was minimal compare to what
generation owners must handle today. The revenues of today’s
generation owner are dictated by the market, and as seen in
California during 2001, the market can fluctuate significantly.
One last anecdotal comment: I recently heard a generation owner
describe the generation process in the following way.
“Our generation planning process is like this.
1. We take maps of the natural gas pipelines and the rail
lines used by the coal companies and superimpose them
on a map of the high voltage transmission system.
2. We identify every intersection of natural gas pipelines
and the transmission system, and every intersection of
the railway lines and the transmission system. This
process identifies the locations where the investment
costs may be attractive.
3. Using a power flow model, we insert a generator bus at
every transmission system located identified in (2)
above, with Pgen=0, and Pmax=1000 MW.
4. For each new generation bus, and for each major load
center in the network, we identify the maximum
injection that can be consumed at that load center from
that new generation bus without a network violation.
5. Locations having the largest injections for the most load
centers are ones having minimal transmission
reinforcement needs and are attractive potential for
market flexibility.
6. Final decisions are made after performing detailed cost
analysis of constructing plants at the various sites and
detailed transmission analysis of operational costs and
potential revenues.”
Final comment on capacity markets: To be completed.
We will spend no more time on resource planning, simply
recognizing that it has been largely relegated to the “invisible
hand” of the market, and the market seems to have responded.
4.0 Transmission ownership and control
There are a number of terms that are used in reference to
transmission ownership and control. Some of these are defined
below [1]:
Independent system operator (ISO): A organization that
operates a transmission system but is not an affiliate of an
entity that owns or operates generation, transmission, or
distribution assets and has no interests in trading that is carried
out in wholesale or retail electricity markets.
Transco: An independent organization that owns and operates a
transmission system. A Transco differs from an ISO in that an
ISO does not own the transmission resources. A Transco
combines the functions of system operations and transmission
ownership, asset management, and maintenance.
Independent transmission company (ITC): A for-profit
company that owns but does not operate transmission assets
and is not affiliated with or in common ownership with
generation, distribution, or retail businesses or facilities.
Regional transmission organization (RTO): An entity
responsible for certain system operations, market
administration, and transmission functions, and meeting
specified criteria in accordance with FERC orders. Specifically,
FERC requires that RTO be responsible for (a) congestion
management, (b) ancillary services, (c) administration of a
balancing market, (d) OASIS administration including total
transmission capacity (TTC) and available transmission
capacity (ATC) calculations, (e) security coordination, (f)
market monitoring, and (g) regional transmission facility
planning, and (g) tariff administration and design.
Some clarifications about the relation between these terms:
An RTO may be either an ISO or a Transco.
An ISO is not an RTO unless it has all of the responsibilities of
an RTO, especially the planning function.
The relation between an ITC and other companies within its
service area is illustrated in Fig. 11.
Fig. 11: Cost distribution between utilities when an ITC is present
In the US, the FERC has consistently discouraged the existence of
Transcos, insisting that the system operator needs to be
independent of any interest in profiting from generation,
transmission, or generation. Nonetheless, there are some
organizations within the US that seem to fit the definition of a
Transco at this point in time. Internationally, the National Grid
Company (NGC) in the U.K., and Stattnet in Norway are clearly
Transcos, and it appears that Italy is also in the process of forming
a Transco.
An important benefit to the Transco model is that that there is
closer coordination between operation and management and
planning of the facilities. It is unclear whether this benefit
outweighs the potential of such organizations to make decisions in
operating the system that are inappropriately biased by their
interest in maintaining and planning the facilities.
Figure 12 illustrates the independent transmission companies in the
US as of May 2004. Figure 13 illustrates the ISOs and those
organizations that have been approved by FERC to be RTOs in the
US, as of May 2004 (circled).
3
Fig. 12: ITCs in the US [2]
2
Fig. 13: ISOs and RTOs, (circled ones are approved RTOs) [2]
5.0 Recovery of transmission costs
When transmission pricing was first implemented, there were 2
parts. A fixed part was based on the cost of the investments and a
variable part based on usage. For example, some transmission
service companies based the usage part on the MW-mile scheme,
where the charge was proportional to the product of MW flowing
on each line and the length of each line on which it flowed.
Today, transmission pricing is more typically broken into 3 parts:
Congestion charge
Base charge
Interconnection charge
5.1 Congestion charge
In studying the real-time electricity market and the locational
marginal pricing (LMPs) system on which it is based, we saw that
network constraints cause LMPs to increase. The additional
revenues paid by market participants as a result of these LMPs are
clearly related to the influence of the transmission system.
But in what way? If we return to the notes on the linear
programming optimal power flow, at the end, it is recalled that we
studied the below example, where line 3 was constrained to 0.3 pu,
and we increased the bus 3 load by 0.01 pu (1 MW).
Pg2=1.1803pu
Pg1=0.5pu
1 2
PB2=0.1197
PB3 =0.3
PB1 =
-0.0393 PB5=0.4197 Pd2=1pu
PB4 =
4 0.4590 3
Pg4=0.4984pu Pd3=1.1787pu
Fig. 11: System before bus 3 load increase of 1 MW
Pg2=1.1778pu
Pg1=0.5pu
1 2
PB2=0.1222
PB3 =0.3
PB1 =
-0.0443 PB5=0.4222 Pd2=1pu
PB4 =
4 0.4665 3
Pg4=0.5109pu Pd3=1.1887pu
Fig. 12: System after bus 3 load increase of 1 MW
We observed that, in regards to the locational marginal prices,
“Without transmission constraints, these prices were all the
same, at 12.11 $/MW-hr, a price set entirely by the generator
at bus 2 since it was the bus 2 generator that responded to any
load change. But now they are all different, with only bus 2
price at 12.11 $/MW-hr. This difference reflects that, because
of the transmission constraint, a load increase at one bus will
incur a different cost than a load increase at another bus.”
The nodal prices at the various buses were
Bus 1: 12.432
Bus 2: 12.11
Bus 3: 12.647
Bus 4: 12.540
In investigating differences among the nodal prices, we stated
further that:
“The comparison shows that in order to supply an additional
MW at bus 3, the generation levels of 2 different units had to
be modified. Specifically, Unit 2 was decreased from 1.1803
to 1.1778, a decrease of 0.0025 per unit (0.25 MW) and Unit
4 was increased from 0.4984 per unit to 0.5109 per unit, an
increase of 0.0125 (1.25 MW). Thus, Unit 4 was increased
enough to supply the increased load at bus 3 and the
decreased generation at bus 2. In fact, it is not possible to
supply additional load at bus 3 with only a single unit
increase. We will always have to compensate for the load
AND redispatch to compensate for the additional flow on the
branch 3. As a result, the nodal price at bus 3 is a function
of the generation costs at those buses that are used in the
particular redispatch that achieves the minimum cost.”
It should be clear that, although the nodal prices change as a
function of transmission constraints, the new nodal prices are still
entirely a function of system generator production costs. That is,
they are NOT a function of the investment, operation, or
maintenance costs related to the transmission equipment. We
will, in the remainder of these notes, refer to these three costs as
“transmission costs.” We will refer to the additional costs
associated with the increased nodal prices as “congestion costs.”
Although the congestion costs do not reflect actual transmission
costs, they do represent additional revenues brought in by the
market operator. For example, consider the situation of Fig. 12,
and compute the total payments made to the generation owners and
the total revenues from the loads. Table 1 below summarizes:
Table 1: Summary of payment/revenue stream from Fig. 12
nodal price, Generators Loads
$/MWhr MW Payment,$ MW Revenues,$
Bus 1 12.432 50.00 621.60 0 0
Bus 2 12.110 117.78 1426.32 100.00 1211.00
Bus 3 12.647 0 0 118.87 1503.35
Bus 4 12.540 51.99 640.67 0 0
Total 2688.59 2714.35
The additional revenues collected for this one hour, $2714.35-
$2688.59=$25.76, is the settlement surplus collected by the market
operator. This amount may not seem like much money, but it can
be significantly larger for larger systems; in addition, of course, it
is just 1 hour and taken over an extended period of operation, can
represent a large financial resource.
In most mature electricity markets, the settlement surplus are used
to pay the holders of financial transmission rights (FTRs), also
known as transmission congestion contracts (TCC) in New York
and fixed transmission rights (also using the acronym FTR).
FTRs are tradable property rights defined, directionally, between
any two connected nodes, and denominated in MWs. Ownership of
a node j to k FTR for an amount Pjk in MWs for particular hour
entitle the FTR holder to the difference between the nodal prices of
bus j and bus k, paid by the market operator from the funds
accumulated from the hourly settlement surpluses. The FTRs do
not confer an exclusive right to use line j-k but simply remunerate
their holder if congestion occurs.
FTRs are important financial instruments in an electricity market
because they allow market participants to hedge against the
uncertainty created by the effect of transmission constraints on
nodal prices. If a market participant is concerned that a particular
path will be heavily constrained, resulting in a situation where that
market participant will see very undesirable prices, then that
market participant can purchase FTRs for that transmission path. If
the congestion occurs, the market participant will still see the
undesirable prices. Independently, if they hold FTRs to the
constrained path, they will receive an amount equal to Pjk(λj-λk).
Two closely related questions naturally arise in regards to the FTR
market.
1. What is the price to purchase them?
2. Who owns them initially?
The first question is easily answered by an auction. Thus, the price
paid is entirely determined by the market desire for them. Question
2 arises from question 1 because if there is no FTR ownership in
advance of the first auction, then who receives the auction
proceeds? Thus, it is necessary that an initial FTR owner be
assigned.
In regards to existing transmission facilities, question 2 has been a
difficult one for the industry. The basic issue is that transmission
owners, load serving entities, and existing transmission contract
holders all feel that the initial FTR should belong to them, and all
have a legitimate claim. Solutions worked out in regards to this
issue have been rather complex and are detailed in [1] pp. 153-156.
In regards to new transmission facilities, however, question 2 is
simpler [1].
If investment cost of the new facilities is included in mandatory
transmission access (base) charges payable by all users, then
the associated FTRs are allocated to those paying the access
charges.
If investment is market-based and not included in mandatory
access (base) charges, the investors receive the associated
FTRs.
5.2 Base charge
This base transmission service charge is generally determined
based on a “postage stamp” or “license plate” approach where the
charge equals the total cost of transmission facilities in the service
area, per year, divided by the peak load, subject to a cost-of-service
rate of return approved by local regulators. Such transmission
service charges range from $15/kW-year to $25/kw-year.
Transmission customers may purchase transmission service in at
least two different forms:
Firm service: Such service is guaranteed as long as the physical
facilities are operational. This price also includes the cost of
any upgrades to the network made necessary by the service.
Non-firm service: Such service is subject to curtailment when
congestion arises. The price does not include the cost of
upgrades to the network since usually none are made for this
service.
5.3 Interconnection charges
Whenever new generation is constructed, there is cost to build new
facilities and reinforce existing ones in order to interconnect the
unit with the system. The same is true for so-called merchant
transmission, which is new transmission built by entrepreneurial
developers (typically market participants) where the developers
take the entire usage or revenue risk.
6.0 The transmission planning process
Assignment (to be completed in your groups): You are assigned to
develop three detailed flow charts of the transmission planning
process using three different resources. These resources are given
on the web page under
www.ee.iastate.edu/~jdm/ee458/ee458schedule.htm. These
resources are:
- Transmission planning process used at Ontario Hydro
- Transmission planning process used at PG&E
- Transmission planning process used at ???
Each person in your group should take one of these and work
alone developing the flow chart. Then the entire group should
come together and compare flow charts. You should turn in the
flow charts together with a statement of the differences and
similarities between the transmission planning processes used at
these three companies.
7.0 Appendix: Industry comments on transmission planning
An e-mail message was sent to a number of different transmission
planning engineers around the country asking the question “What
overall topics would you think would be good for fresh
undergraduate to see if they were preparing to come into your
group there?”
The soliciting e-mail message, together with the responses, are
given below. Names and company affiliation of responders have
been removed.
XXXX:
I used to work in PG&E’s transmission planning department during 1980’s
and now I am a university professor at Iowa State University. I think
transmission planning has changed significantly since I did it.
I am teaching a course this semester at ISU called "Economic systems
for electric power planning."
The course is about optimization, basics of economics, nodal pricing,
electricity markets, and planning. I am teaching the course with two
other faculty, one is an economist.
There are about 35 students in the course. You can find the schedule of
topics at http://www.ee.iastate.edu/~jdm/ee458/ee458schedule.htm.
In regards to planning, I will concentrate on transmission planning.
What overall topics would you think would be good for fresh
undergraduate to see if they were preparing to come into your group
there?
I realize you do not want to spend much time on a reply to this
question, so just a 2-3 high-level bullets that come immediately to
mind would be appreciated.
Thanks.
Jim McCalley
Professor of Electrical and Computer Engineering
Iowa State University
515-294-4844 (v)
------------------------------------------------------
Jim
Here are some points:
Transmission planning is part of an overall process to supply the
customer load in the most cost effective manner. Transmission
facilities provide the trade-off between resource that are closed to
the load and those that are far away. Success in transmission planning
is measured by the number of problems solved in the most cost-effective
manner and not by the number, sizes and costs of transmission projects
proposed.
Transmission planning is a process to make investment decisions, as
compared to operations, which guard against the next worst contingency.
Transmission planning process anticipate future problems over a
planning horizon by comparing simulations of system performances under
various reasonable adverse system conditions with those required by the
Planning Standards. A potential problem exists when simulated system
performance do not meet the Applicable Standards. In North America,
utilities adhere to the North America Electric Reliability Council
(NERC) Planning Standards in addition to Regional Standards (e.g.,
WECC) and local Standards, as appropriate. Because planning standards
determines future investments, they represent a trade-off between costs
and risks. It is not always necessary to get rid of all transmission
constraints - transmission reinforcements should be made where the
benefits (enable the standards to be met or provide economic benefits)
outweigh the cost. Some people may want to tag on environmental
benefits such as enabling the transfer of renewable resources.
However, such environmental benefits (reduce emission) must be off-set
by the environment impacts of building more transmission lines,
especially if they may be stranded because the resources either do not
develop or developed in other locations.
-----------------------------------------------------------------
Jim,
In taking a few minutes to read the information on the link you provided, it sounds like an
interesting and timely course. I think it will hit upon a item which we struggle with continually -
which is the identification of transmission projects which will be enough of a band-aid to grant an
entity transmission service versus implementing a more strategic solution (usually more costly
and time prohibitive to grant the original transmission service request). A typical struggle is the
decision to re-conductor a line versus building another line - which tends to make stability limits
more prevalent.
A couple of additional topics that immediately come to mind for your consideration for the limited
time you will have:
Project prioritization with deterministic versus probabilistic planning techniques
Stability constraints caused by concentration of generation near fuel sources (gas lines) with
inadequate transmission paths(including transient, small signal, voltage stability)
One more bullet item that I can't believe I forgot to include: the impact of load models on TP
study results. As we are planning closer to the edge, our load model assumptions are critical - for
both loadflow type analysis and stability analysis. A new graduate engineer with an appreciation
of load modeling issues would have a huge "leg up" on the majority of new graduates.
Thanks - I appreciate the opportunity for the input.
I hope that helps
Jim,
Some topics you might want to include in your course:
Optimal Power Flow (Introduction to power flow software i.e, PTI's PSS/E)
Basic Transmission Equipment Ratings Calculations (Industry standards such as IEEE
738 and CIGRE 22.12)
Introduction to the role of Regional Transmission Operators (RTO's) such as MISO,
NYISO, PJM and their respective interconnection processes, day-ahead markets,
Installed Capacity (ICAP) Market, Transmission Congestion Charge (TCC),
Transmission Service Charge (TSC).
Static and Dynamic Line Thermal Ratings (CAT-1 System and EPRI's Dynamic
Thermal Conductor Rating Software)
I hope the above topics are helpful. Good luck.
Good evening Jim,
Glad to reply and give my opinion for content.
1) Overview of how Planning fits into the control of the Bulk Electric Power Grid.......things to
discuss would be how there are 3 main aspects to the control operator's responsibility. The other
two are Operations and Markets.
2) I would focus one session on how running generation plants is done and how the market
signals that are given influence this day-to-day(or minute to minute) operation. I would stress in
this the transmission facilities vital link in this for it to work.
3) I would discuss how Load flow, Short Circuit, & Dynamic analysis works, the measures for
establishing if a plant and transmission facility is viable to be built and how a Generation
interconnection process Queues are used, like we use, in these efforts.
Understanding of power flows (Stevenson, Gross, or similar). (AC vs.
DC power flows - for the purpose of your discussion I would stik to DC
flows.
Optimal Power Flow (OPF) vs. power flow (e.g., PowerWorld, PSS/E, PSLF)
Transmission Planning vs. System Operations (Emphasis on System
Operations rather than planning - my background is planning but in the
world where LMP is king, day to day operations rules the day. This is,
of course, from a practical standpoint.
Good luck, and I hope this helps.
Jim,
The primary planning tasks we do are running PSSE contingency load flows for identifying
system weak areas in terms of overload, low voltage, transmission congestions, ATC, TRM and
CBM requirements. Flowgates limitations and management is another important aspect. Load
forecasts, capital budget planning, project cost/benefit anaylysis for ranking and justification
purposes are daily routine works. Voltage stability and angular stability are also important. From
time to time short circuit fault analyses are performed for relay setting purposes.
Hope this will give you enough material for three classes.
Thanks and best,
Jim - Hi! I would break it down into the separate elements of what we
are planning, as each has a different approach.
Resource Planning - ensure sufficient MWs are available to serve the
load; 1day/10 year rule of thumb criteria; need for more capacity than
you have load due to maintenance and forced outages; typical reserve
margins are 12-18% depending on system configuration (need a higher
amount if you have large generation plants remote from load vs a lower
margin if you have highly dispersed small generation plants with few
transmission constraints); uses spreadsheet analysis and LOLE programs.
Transmission Planning - ensure sufficient facilities to move power from
where it is generated to where it is required to serve load reliably;
bulk transmission (moves power long distances/between markets), area
transmission (moves power from the bulk system down to specific load
areas), sub-transmission (moves power from defined areas to specific
load centers' distribution system); voltage level is a function of
distance the power needs to be moved and the density of the load;
deterministic criteria driven (for the loss of any single element of
the bulk system, no load will be shed); use powerflow programs.
Electric System Reliability Planning - ensure sufficient support
systems so the facilities (generation and transmission) can be operated
in a reliable and secure manner; determine protection schemes, special
operating measures, back-up systems, etc.; use stability analysis, nose
curves, etc.
I always like to insert (especially when economists are involved and
there are discussions of markets) that you can have reliability as an
output from markets when you are talking about resource planning, but
transmission reliability is the platform that markets are built on.
Hope that helps and good luck,
References
[1] F. Woolf, “Global Transmission Expansion; Recipes for
Success,” 2003 by Penn Well Corporation, Tulsa Oklahoma.
[2] D. Owens, “Challenges for Expanding Transmission
Infrastructure,” June 14, 2004, at
http://www.psc.state.sc.us/SEARUC/presentations/Owens.PPT
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