Under the design of the ISO and Power Exchange institutions
to create a competitive power market and to sustain system reliability,
all consumer's loads must be forecast, but on a different basis
than utilities have done for purposes of system dispatch. This
paper seeks to provide background on what has been done in the
past, and what will have to be done differently under the proposed
organization of the industry.
Utilities have made short run load forecasts for
purposes of making unit commitments, scheduling contract resources,
and dispatching resources to maintain system frequency. These
forecasts have been for the total aggregation of all customers'
loads, and only reflect specific customer information in special
circumstances.
The techniques used for these load forecasts rely
upon stability in the base of customers that the system is serving.
Aggregate load data is processed using econometric and time series
data processing techniques. Econometric techniques use measures
of weather and other time varying phenomena to develop relationships
between previous loads and a few aggregate explanatory factors.
Time series modeling techniques rely upon observations of what
has just been observed more than explanations what caused what
has been observed. The parameters estimated in these analyses,
along with short run forecasts of the explanatory variables, serve
to provide short run load forecasts that serve as the basis for
unit commitment and scheduling. Observations of actual system
load on a quite short run basis are used to update these models
on a very frequent basis, (e.g. daily or weekly).
All of the parties serving loads, whether through
bilateral contracts for larger consumers, through aggregations
of many smaller consumers, or the UDC for consumers not wishing
to participate in direct access, must forecast loads and provide
these forecasts to one or more entities upstream of the retailer.
For bilateral contract retailers, this will be directly to the
ISO through a scheduling coordinator to the ISO. For aggregators,
forecasts of loads will again be provided to the ISO or through
a scheduling coordinator to the ISO, but the ISO needs only an
aggregation of consumer's loads, not the actual loads for each
consumer individually. Finally, for loads served by the UDC, the
UDC provides its load forecast to the Power Exchange.
The scope of the load forecasts provided to the ISO
or to the PX are much smaller in scope than those traditionally
prepared by utilities for unit commitment and dispatch purposes.
Recall that those forecasts were for the entire utility customer
base - the system load. The principal exceptions were major self-generation
customers whose generating unit might be scheduled off for maintenance,
and this event might be treated in a specific, recognizable way
for scheduling utility units or contract resources.
There may be dozens or hundreds of separate schedules provided
to the ISO and the PX, which collectively sum to the three IOU
systems that were formerly treated as three disjoint sets of loads
for the three IOU systems. Therefore, each of the load forecast
schedules are much smaller in scope than the previous utility
system load forecasts. Further, some of the load forecast schedules
will be composed of a single or a few end-use consumers. Therefore,
the methods for preparing load forecasts for these much smaller
groupings of loads cannot ignore the consumer-specific features
of loads, e.g. things that cause a single or a few customers to
do something at specific times that cannot be explained by techniques
that are based on averages of large numbers of customers.
Some aggregations of loads, and certainly the UDC load forecasts
submitted to the PX, will be large enough and diverse enough that
similar methods to those used traditionally by utilities would
be satisfactory. However, even these load forecasts have to accommodate
the fact that customers are moving into or out of various aggregations
(whether that of a specific DA retailers or the UDC) all the time,
and thus accounting for customer turnover in some explicit way
will be necessary.
It is extremely important to understand that the
purpose of these load forecasts will be different than those developed
previously by utilities. To reiterate, the traditional load forecasts
were used to make unit commitment and contract resource decisions
from a relatively fixed pool of generating resources owned, operated,
and controlled to varying degrees by the utility. Capital costs
of these facilities and the decision to add resources (the capacity
expansion question) was determined in a completely different forum
than the utilization of resources.
Under the proposed market structure, however, load forecasts serve
to provide a commitment to purchase power according to the specified
schedule. Failure to support the load forecast does not reduce
the payment that must be made to the power supply industry. In
effect, you pay what you asked for if you asked for too much,
and you pay for what you used if your actual is larger than what
you asked for. The financial consequences of errors are much larger
under the new market structure than in the previous industry structure.
Previously, errors in the unit commitment process implied too
many resources were brought up to spinning status, or too few
were brought up, but other resources could be run somewhat harder,
using more fuel than would have been optimal with perfect foresight
of loads. The net result was additional fuel costs but no additional
capital costs.
In contrast, under the new market structure, generators will be
submitting generation bids that presumably cover both capital
and operating costs. The bids may even be higher than costs justify
if the generator believes that the facility can still be scheduled
into the Power Exchange market. Therefore, under the new market
structure, every kilowatthour of error in scheduled load forecasts
versus actual loads imposes greater costs on the party responsible
for the load bid.
Bilateral contract suppliers can be expected to have
problems with developing load forecasts for their associated load
customers simply because making such forecasts has not been developed
into a refined art. Developing such forecasts obviously relies
upon having and analyzing historic load patterns of the customer(s).[1]
Even given the data, however, the variations from an expected
pattern may be considerable, and not known to any party since
historic usage was not metered or recorded in this manner in the
past. Retailers will have varying levels of difficulty in making
these load forecasts, with the production process of the customer
being the dominant consideration.[2]
Emergent aggregators with hundreds to thousands of small customers
may have the greatest difficulties since there may be no customer-
specific hourly load metering historic data, and little understanding
of how specific customers do or do not match up with known load
research data for the broad class within which the customer had
formerly been classified by the utility. Once some degree of actual
metering data becomes available for the "classes" or
"subgroups" of the aggregation retailer, then improvements
in load forecasts can be expected.
The UDC must provide a load forecast for its full
service customers to the Power Exchange, so that the Power Exchange
can include these loads in the determination of generator loading
order to minimize expected market price. The UDC prepares this
short term load forecast very frequently on the schedule needed
by the Power Exchange.
Unfortunately, the existence of DA customers mixed in with full
service customers of the UDC makes the job of predicting UDC loads
more difficult. The following discussion develops what would be
needed for two different approaches:
a. Approach 1 presumes that the UDC makes a total regional load
forecast and nets out DA loads to determine a UDC load forecast
for its full service customers.
b. Approach 2 presumes that the UDC and other parties make parallel
load forecasts, with direct access load forecasts going to the
ISO through the scheduling coordinators, and the UDC load forecast
goes to the Power Exchange.
4.A Approach 1--Netting Out DA Loads from Total Load Forecasts
Utilities are currently making short term load forecasts for use
in scheduling utility powerplant operations, contract purchases,
generator maintenance, etc. These forecasts represent all uses
of electricity within the service area, with the exception of
self- generators providing their own loads. All consumption within
the region, less self-generation, is known to the utility and
available for use in making consumption forecasts. The omission
of self- generator loads, however, is not crucial to the load
forecasting function, because self generator loads do not flow
through the distribution system nor present requirements to utility
generators. With the advent of DA, however, the UDC will not routinely
be able to make total consumption forecasts unless the UDC continues
to have access to generation usage data for all loads, not just
those of its full service customers. Under the current policy
decision, the UDC continues to responsible for the billing system,
but D.96- 03-022 sets in motion an examination of distribution
component services and it is conceivable that the UDC may lose
access to consumption data for all customers at some future date.
Using historic load data for all electricity consumers in the
UDC franchise service area, the UDC can prepare load forecasts
for the area much like it currently does. Once the total load
forecast for the franchise service area and the DA load forecast
disaggregated to service area have been prepared, the computation
of net UDC loads can be performed. This information is provided
to the Power Exchange and used by the Power Exchange to scheduled
generators in least cost merit order to determine a minimum market
price to serve
UDC loads, or any others contractually served by
the Power Exchange.[3]
The statistical properties of the sum of DA load
forecasts will show inherently more variation than total regional
loads because customers can shift back and forth between DA and
UDC full service status with no penalty. A netting approach translates
this variation into the net UDC load forecast. Thus all of the
usual physical and economic reasons for uncertainty in load are
compounded by the ability of the customer to shift status from
full service to DA and back in a short period of time.[4] Since
DA retailers will be required to provide schedules to the ISO,
this imposes a forecasting burden on them. Errors in load forecasts
will induce DA retailers to make an effort to provide reasonably
reliable estimates of short term loads, because the errors result
in costs that either customers have to absorb or the aggregator's
profits must cover. In Approach 1, the UDC needs DA load forecasts
categorized by UDC service area, the DA suppliers would have an
obligation to provide their best load forecast information to
the entity that makes the net UDC load forecast, otherwise the
UDC's customers would be paying for mistakes made by the DA retailer.
a. Should the UDC net out the DA loads in its franchise
service area? If the UDC has this obligation, how will DA loads
be provided to the UDC?
b. Should the PX net out the DA loads applicable
to a UDC service area to obtain a UDC full service customer load
forecast? If the PX has this obligation, how will DA loads be
provided to the PX?
c. Are there competitive reasons for the UDC or PX
to not be provided loads of aggregators and bilateral direct access
customers which eliminate netting as a feasible approach?
d. What responsibility for costs would UDC full service
customers bear when errors in its load forecast were caused by
errors in DA load forecasts?
Approach 2 presumes that UDCs are notified that specific
customers have entered into DA arrangements (which would be required
so as to be able to offer them an appropriate tariff for remaining
distribution services, so this is not a new requirement just for
load forecasting purposes), and the UDC is able to make use of
this information in making load forecasts for the UDC's full service
customers. Thus, the UDC does not have a forecast prepared by
netting out forecasts made by others, but rather focuses on preparing
a forecast for the customers for which it continues to be the
energy supplier.
In order to do this, the UDC would have to adapt
its current load forecasting techniques to recognize, perhaps,
some broad classes of customers who might be expected to behave
homogeneously, and it continuously adjusts these class load forecasts
for the number of customers for which it has an energy supply
responsibility. One could imagine that some time series techniques
would continue to be used, but at a customer class level, and
that through a multiplier or as an explanatory variable the aggregate
load of this customer class was adjusted as numbers of customers
in that class increase or decrease.
Accomplishing this result might require greater reliance
upon customer class load research data in real time, rather than
in the very much delayed way in which load research data is now
collected, processed, and made available for use for analytic
purposes. Real time communication systems would be required of
the customers included in the class samples to permit their data
to be obtained and used along with hundreds of others to continuously
update the class load forecasts for submission to the PX.[5]
a. What advance notice requirements would be necessary
to allow the UDC to process the transfer of a full service customer
to DA status so that this information could be included within
the UDC load forecasting process?
b. Would any adjustments be made for those instances in which the sum of retailer's load forecasts was
implausibly high or low, because the methods used
all simultaneously erred in the same direction?
Developing load forecasts for submission by direct
access retailers to the ISO through a scheduling coordinator or
by the UDC to the Power Exchange will require changes in practices
which utilities have refined under the circumstances of the integrated
utility dispatching resources to meet loads while preserving a
high degree of system reliability. At least two different methods
of preparing a load forecast for the UDC have been discussed.
Each has tradeoffs of difficulty, cost, and apparent advantages
and/or disadvantages. Many of the issues facing the UDC in developing
accurate load forecasts also apply to aggregation retailers who
have large numbers of smaller customers for which detailed analyses
of specific customers is infeasible.
It should be noted that some of the data and analysis issues discussed here for load forecasts also appear as issues in the ISO and/or scheduling coordinator settlement process, where the use of estimates versus actual load data is also under discussion.[6]
[1] Requests for release of customer-specific load
data must be submitted to utilities and received from utilities
in a timely fashion to permit analysis to support forecast development.
Large numbers of such requests may be anticipated, thus utilities
will have to create systems that permit such data requests to
be processed satisfactorily in significantly greater volumes than
have ever been requested in the past. Most requests for data will
not result in hourly load data, since few customers have been
metered to provide this level of specificity. Therefore, the potential
retailer will have to have in place methods using assumed load
profiles to convert aggregated data into hourly load schedules.
[2] The anticipated access of all electricity consumers
in the United Kingdom in 1998 to competitive providers has caused
the Pool to develop a series of load profiles to which each customer
will be assigned for purposes of forecasting loads and allocating
cost responsibility for each customer of a supplier without half-hourly
metering. Source: Bill O'Reilly, United Kingdom Data Collection
Service, May 17, 1996.
[3] This paper will not address the complexity of
developing separate load forecasts for at least four classes of
electricity consumers: (1) time-aggregated energy consumers unresponsive
to real time or TOU price, (2) consumers with RTP or TOU metering
and information notification capabilities, (3) customers who make
explicit load bids with price caps, and (4) customers who are
willing to shed load for a fee as part of the ISO's options to
preserve system reliability within desired tolerances. Each of
these classes of customers might exist in either direct access
or full service variants, and therefore all retailers of generation
services may have to make various "class" load forecasts
along these lines.
[4] CPUC, D.95-12-063 categorically rejects earlier
utility proposals to impose penalties or otherwise restrain DA
customer return to full service customers of the UDC, p. 73. JACR
of May 17, 1996 reiterates that the three UDCs retain an obligation
for those customers "...who do not elect to procure their
own electricity supplies.", p. 10.
[5] A similar technique may be required of aggregation
retailers for developing load forecasts for their customers. While
conceptually similar, the sampling issues to ensure representative
data for rapidly evolving classes might be especially challenging
in the initial years when direct access is permitted for smaller
size customers.
[6] See M. R. Jaske, "Metering and Communication Systems in Relation to Consumer, Supplier, and System Information Requirements", Direct Access Working Group Paper, May 16, 1996._