The Barriers to Real-Time Pricing Separating Fact From Fiction

8/11/2020 The Barriers to Real-Time Pricing: Separating Fact From Fiction
https://www.fortnightly.com/print/11469 1/14
Deck:
Real-time pricing has been hindered by the misperception that a shift to RTP will create new types
of risks, without creating benefits for utilities or customers.
Byline: Ahmad Faruqui and Melanie Mauldin
Published on Fortnightly (https://www.fortnightly.com)
Home > Printer-friendly > The Barriers to Real-Time Pricing: Separating Fact From Fiction
The Barriers to Real-Time Pricing: Separating Fact From
Fiction [1]
Fortnightly Magazine - July 15 2002 [2]
Real-time pricing has been hindered by the misperception that a shift
to RTP will create new types of risks, without creating benefits for
utilities or customers.
During the past two decades, real-time pricing (RTP) has spawned a cottage industry
of experts who continue to wax eloquent on its benefits. RTP can indeed provide
substantial benefits to energy customers and utilities. However, only a handful of utilities
offer such programs, and only a few thousand customers receive RTP service. This
paradox resolves itself once we realize that there are significant barriers to RTP, many of
them having to do with perceptions and not reality.
The overarching barrier to widespread application of RTP is a misperception that a shift
to RTP will create new types of risks for utilities and regulators, without creating
commensurate benefits for either utilities or customers. Both utilities and regulators have
become risk averse in experimentation with new policies, having been burned first in
California and then in the Enron crisis. The challenge is to convince them that no such
failures await them with implementing RTP.
Another barrier is a misperception that a prerequisite for RTP is competition between
retail energy service providers. However, as the examples of California and Georgia
illustrate, retail competition is neither sufficient nor necessary for RTP.
The vast majority of customers have a natural reluctance to participate in RTP because
they equate higher price volatility with higher prices, which in their minds translates into
higher bills. They do not realize that higher price volatility often means that prices will be
very high during a certain number of hours, but very low during a greater number of
hours-potentially with lower annual bills. Of those customers who realize that higher
price volatility may well translate into lower expected bills, a large number are risk
averse. These customers are not inclined to "play the market." Other customers believe
that the effort involved in any type of load shifting outweighs any potential benefits. And

then there are some paranoid customers who think that RTP is just another way for their
electric utility to gouge them.
These perceptions are borne out in a series of market research studies that have been
conducted over the past five years. In these studies, researchers interviewed customers
about their preferences for a range of pricing options, based on their stated intent to buy
or not buy one or more of these products ().
For example, customers are willing to pay real money to avoid being placed on a time-
dependent rate structure, such as seasonal, time-of-use (TOU), or RTP.1 In fact, large
commercial and industrial (C&I) customers would be willing to pay a premium of .33
cents per kWh in a flat rate, rather than be placed on a two-part RTP. Small and medium
C&I customers would be willing to pay a substantially higher premium, of 3.9 cents per
kWh, to avoid being placed on hourly prices. These perceptions constitute a real barrier
to RTP.
As the example of utilities such as Georgia Power illustrates, it is possible to overcome
this barrier through successful program design. Examples from other industries indicate
that customers do respond to the opportunity to lower costs by shifting their usage
patterns (airlines) or by taking on time-varying products (adjustable rate mortgages).
Utility customers are attracted to RTP on the premise that it will save them money.
However, when prices spiked in various markets during the past few summers, many
customers dropped out. For example, Duke Energy had 100 customers on its RTP
program, but now it has only 59. BC Hydro had 25 customers; now it has none.
Researchers need to study and analyze the following inter-related set of issues:
If customers were offered RTP on a voluntary basis, how many would take it?
Are customers more likely to take a two-part design than a one-part design
because it provides a measure of price insurance?
What types of customers are drawn to RTP?
At what rate are customers willing to trade off a lower expected value of price
against a higher standard deviation of price?
How many more customers would take RTP if it were to be combined with some
type of price protection product, such as a price cap or a price collar?
What is the demand for other types of market-based pricing roducts, such as
occasional RTP?
Another issue that needs to be tackled by researchers is the amount of load clipping or
shifting that would be induced by RTP. Experience has shown that only a few customers
either reduce load or shift it from on-peak to off-peak periods. And of those that do
respond to RTP, there is considerable day-to-day variation in response patterns.
Customers may not sign up for RTP because they do not know how to lower costs by
reducing usage during high-cost hours and increasing usage during low-cost hours. Or
they may lack the capability to shift load. This contention, often advanced by skeptics,
has been negated by research conducted over a number of years and over several
geographical regions. This research finds that customers do shift load, but the
magnitude of shifting varies across business types.
The Electric Power Research Institute's (EPRI) StatsBank contains the measured
responses of about 1,000 customers in the United States and the United Kingdom. Each
of these customers has been on some form of a time-differentiated or RTP for several
years, while others have been on some type of curtailable or interruptible rate. EPRI has

estimated the between hours.2 Across all business segments, the estimated hour-to-
hour elasticity of substitution within a day ranges from zero for some segments to values
in excess of .30 for other segments.
Within the manufacturing sector, the highest elasticities are observed for electrically
intensive customers. These include firms in the pulp and paper and primary metals
industries. These customers have an average elasticity of .09. The lowest elasticities are
observed for non-electrically intensive customers, such as firms in furniture
manufacturing, printing, and publishing. These firms have an average elasticity of .04.
The elasticities rise significantly if the customers have on-site generation. For example,
the elasticity for electrically intensive customers with on-site generation is .15, compared
with .09 for customers without on-site generation. The elasticity for the least electrically
intensive customers is .07, compared with .04 for customers without on-site generation.
For firms in the pulp and paper industry, the presence of on-site generation doubles the
elasticity from .15 to .30.
It would be useful to know what types of customers are likely to shift more load. It also
would be useful to know how much load relief can be expected from RTP, and whether
the amount of load relief varies with a one-part design versus a two-part design. What
segments are likely to shift more load? How applicable is the load shifting information
contained in EPRI's StatsBank to utilities that are not included in that database? Is load-
shifting information stable and reliable over time?
A related issue deals with market segmentation and targeting. Prior work suggests that
customers with on-site generation, discrete production processes, and previous
experience with interruptible tariffs are more likely to benefit from RTP. What is the best
recruitment strategy for signing up these customers? How much education is needed to
get customers acclimatized to the incentives provided by RTP?
A final issue relates to implementation strategy. Some utilities have only a handful of
customers on RTP. Can better results be obtained? Some have argued that customers
face real transactions costs when switching to a new rate structure, and those costs
become a barrier to their joining RTP programs. Are these costs real or perceived? It
would be useful to conduct a pilot program before proceeding with full-scale
implementation.
Utility Barriers: Rates & Revenue Loss
Utilities have several issues regarding RTP. First, they are concerned about the revenue
loss that can arise from RTP. This problem is acute with one-part designs, where
revenue loss can arise if the rates are offered on a voluntary basis and customers who
have inverse load shapes self-select themselves onto the real-time rate. The customers
would lower their bills without shifting any load from peak to off-peak hours. They would
benefit, but the utility and non-participating customers would lose. There would be a loss
of revenue to the utility, without any reduction in its costs-resulting in a loss of earnings.
The lost earnings then would have to be made up by charging other customers a higher
price.
This concern can be addressed in three ways: by offering a two-part design; by making
the rates mandatory; or by offering a true-up mechanism, ensuring that forecast
revenues are recovered. It would be useful to conduct research on how serious is the
potential revenue loss associated with RTP. Also, to what extent can it be offset by
following a two-part design?

A second issue relates to the potential for gaming associated with two-part designs that
require the establishment of a customer baseline usage (CBL). There is some anecdotal
evidence that customers may have gamed the selection of their base load when signing
up for market-based load curtailment programs. A similar concern may also apply to two-
part RTP designs. This could be addressed through researching whether there is any
empirical evidence from other states that customers have gamed the selection of their
CBLs. If so, can better educational programs offset this problem?
A third issue deals with billing and settlement systems. Most existing systems are not
capable of calculating bills based on hourly usage patterns. Modifications must be made
by the IT staff, which often is overburdened with other duties. The only practical solution
is to outsource this capability, and that often comes with a large price tag. It would be
useful to research the cost of implementing billing and settlement systems that would
enable RTP, and how these costs can be managed most effectively.
A fourth issue relates to the lack of integration of demand-side responses with system
dispatch. Oftentimes, utilities are skeptical that the pricing program will produce real and
tangible savings that they can count on. Some have more confidence in traditional load
management programs involving direct load control of specific appliances. This concern
is not limited to the United States. For example, ESKOM, the state-owned utility in South
Africa, has 1,400 MW on RTP with a simultaneous load response capability of 350-400
MW for up to three consecutive hours. While RTP is set up on a day-ahead basis,
customer response is not used to optimize the dispatch of the power system. Electricity
prices are based on the Pool Output Price, and do not change in response to changes in
customer demand that may be induced by RTP. The utility is not aggressively marketing
the program for this reason. It hopes that once a competitive energy market has been
created, with a functioning Power Exchange, RTP then will be able to play its proper role
in system operations3
Fifth, there is a perception that RTP makes sense only during periods of wholesale price
spikes. Thus, if wholesale prices are low (as they have been during the past year in the
western states), RTP is not needed. What is often overlooked is that wholesale prices
were high not too long ago, and that the sequential existence of low and high prices
implies high price volatility. Customers who sign up for RTP will benefit when prices are
low, and the existence of low prices during several hours of the year can be an
inducement to participation in RTP. When a utility has a large number of customers on
RTP, it creates flexibility for itself during high-price periods, when it can transmit a high-
price signal to the customers and get customers to cut back on usage.
Finally, there is a perception that customers will not like RTP and will complain to the
public utility commission. Utilities are concerned they may be trading off customer
satisfaction for some questionable efficiency gains. Many cite the consumer revolt that
was triggered in San Diego when electric bills doubled and tripled during the summer of
2000. However, it would be incorrect to regard the San Diego experience as a fair test of
RTP. Customers were neither educated nor prepared for a doubling or tripling of their
bills. Their prices did not vary hourly, as they would in an RTP setting, but on a monthly
basis. No hourly meters were in place, and load profiling was used to compute their
monthly bill.
Regulatory Barriers: The Morality of Pricing
The concept of RTP originated with William Vickrey in 1971, when he wrote a
groundbreaking article on "responsive pricing." Vickrey, who went on to win the Nobel
Memorial Prize in Economic Sciences in the late 1990s, wrote that "the main difficulty

with responsive pricing is likely to be not just mechanical or economic, but political." He
felt that people shared the medieval notion of a just price as an ethical norm, and that
prices that varied according to the circumstances of the moment were intrinsically evil.
He opined prophetically:
In a similar vein, veteran energy analyst Eric Hirst noted recently, "the greatest barriers
are legislative and regulatory, deriving from state efforts to protect retail customers from
the vagaries of competitive markets."5
One of the key barriers among regulators relates to fairness and distributional concerns.
Not every customer would benefit from a switch to RTP, and some customers would be
at a disadvantage. Those who consume large amounts of energy during peak times
would be disadvantaged because they would lose their subsidy from the other
customers. Recently, Puget Sound Energy was unable to get regulatory approval for its
tracker rate, which would have given customers a daily price signal layered on top of a
traditional four-period time-of-use rate. There was a concern that many customer
segments comprised of elderly customers or low-income customers would be harmed by
the real-time component of the rate. Unfortunately, a policy that seeks to make no one
worse off will imprison us in the status quo.
We need to search for a more forward-looking way of thinking. Policy makers have to
devise a framework for balancing the competing demands of greater efficiency against
the political pressures of special interest groups. What insights can be derived from the
vast literature on welfare economics? According to the well-known Kaldor-Hicks
criterion, if the gainers from a public policy can compensate the losers, the policy may be
worth pursuing, even if the losers are not compensated.6
A related topic is whether market-based load curtailment programs can co-exist with
RTP. Should customers who volunteer for a load curtailment program be excluded from
receiving service on a real-time basis? Would this constitute double dipping? Or would it
be a cost-effective way to obtain additional load shifting without having to make any
additional investment in control technologies?
A third topic relates to a perception that RTP will seriously inconvenience customers
because they cannot reduce peak usage or shift load from on-peak to off-peak periods.
What is the best way to convince regulators that customers can indeed be trained to shift
their loads from on-peak to off-peak hours? It would be useful to conduct a series of
seminars and workshops for regulators, utilities, and prospective customers, in which
customer case studies from other parts of the country would be featured.
Finally, a fourth issue arises from California's situation, in which the state has purchased
power under long-term contracts, thereby seemingly eliminating the need for RTP. There
appears to be no hourly variation in power prices under these contracts, but there is
variation by pricing period. For example, blocks of peak power are much more expensive
than blocks of off-peak power. Some have argued that RTP is now irrelevant in
California because there is no hourly price variation in the wholesale price of power.
The argument that RTP does not apply in this situation has two weaknesses. First, it
ignores the fact that the existence of long-term contracts has not eliminated the
wholesale spot market for power. According to some sources, during peak periods, as
much as 30 to 40 percent of the power may be traded in this market. During such times,
RTP at the retail level would provide customers with the appropriate signal to conserve

power usage. This would benefit the state, and, if customers can reduce peak load, it
would also benefit the participating customers.
Second, it overlooks the fact that during times when the state has surplus power at long-
term contracts, it is forced to dump this power on the wholesale market at below-cost
prices. If customers were on RTP, they could be offered this power at the state's cost,
which would be lower than the customer's average price. This lower price may stimulate
growth in customer usage during off-peak hours, especially if the customers have been
trained in how to increase power usage by rescheduling operations. It would lead to
even greater usage if customers have enabling technologies on their premises.
Customers and taxpayers would be better off, and so would the state.
Technological Barriers: The Cost of IT
Many technological barriers also impede the introduction and diffusion of RTP. The
barriers are not intrinsically technological because the required technologies exist in
today's marketplace. However, the market penetration of these technologies has been
very limited due to their high capital costs. This in turn is due at least in part to their
limited market penetration and to the barriers discussed in the previous sections.
Technological barriers include the:
lack of hourly metering equipment,
lack of digital communication equipment to transmit hourly prices in real-time to
customers,
limited penetration of sophisticated energy management and control systems,
even more limited penetration of time-flexible energy-using equipment that allows
the energy to be stored during off-peak periods and released during on-peak
periods, and
small penetration of distribution energy resource systems.
An independent study of four industrial firms finds that self-generation significantly
enhances customer responsiveness to RTP.7 Duke Power's experience suggests that
customer response increases over time. Customer elasticities grew from .20 in 1995 to
.25 in 1999.8 These findings illustrate the role of enabling technologies and provide
some preliminary evidence on whether customer responses increase over time. They
raise an important research issue: As customers learn how to take advantage of RTP
and invest in new enabling technologies, do they display increasing responses,
suggesting that long-run elasticities of substitution would be higher than short-run
elasticities?
Of course, both utilities and state and federal regulatory commissions should make
research on the barriers identified in this article a priority. Otherwise, like King Tantalus in
Greek mythology, tomorrow's customers will continue to be starved of these benefits,
whether they bend low to drink the water from the stream or reach high to eat the fruit
from the tree.
1. These estimates were derived from data gathered through customer interviews.
Customers ranked various pricing products, and the resulting rankings were
subjected to conjoint analysis. One important caveat is that, in all but one interview,
the data were derived from a standard model of customer choice that enforces the
same preference functions on all customers. Once that assumption is relaxed, by
using a more advanced model known as the mixed logic model, important
information on the variation in customer preferences within segments is revealed.
Thus, on average, customers may display a preference away from RTP and be

willing to pay a higher flat price than go on a real-time price. However, several
customers within each segment may have a preference toward RTP, and these
customers can form the target population for the RTP program.
2. This elasticity measures the percentage change in the ratio of usage in two hours
that is induced by a one percent change in the corresponding price ratio. The
elasticity is a negative number, but in popular writing the negative sign is dropped.
Thus, a higher elasticity number indicates that customers are more easily able to
substitute usage between hours.
3. Personal correspondence with Pieter Brand, RTP Product Manager and Gold
Sector Specialist, Johannesburg, South Africa, April 5, 2002.
4. Vickrey, William, "Responsive pricing of public utility services," Bell Journal of
Economics and Management Science, 2, 1971, pp. 337-346.
5. Eric Hirst, "Price-Responsive Demand in Wholesale Markets: Why Is So Little
Happening?" The Electricity Journal, May 2001.
6. Of course, if the compensation is actually paid, then no one is worse off, and the
program is Pareto Optimal.
7. Nainish K. Gupta and Albert L. Danielsen, "RTP: Ready for the Meter? An
Empirical Study of Customer Response," Public Utilities Fortnightly, November 1,
1998.
8. Peter M. Schwarz, Thomas N.Taylor, Matthew Birmingham, and Shana L. Dardan,
"Industrial Response to Real-Time Prices for Electricity: Short-Run and Long-Run,"
Economic Inquiry, forthcoming 2002.
Industry research yields new insights on RTP.
The benefits of real-time pricing (RTP) arewell known, and include the mitigation of
price volatility and market power in wholesale markets.1 RTP promotes economic
efficiency by giving customers a strong incentive to lower usage when hourly prices are
high. This serves to reduce the threat of power outages. As Californians found out the
hard way in the winter of 2001, blackouts are an inefficient way of rationing customer
demand because they affect all customers equally, regardless of the value they place on
electricity. They can impose significant economic costs, since customers often place a
substantially higher value on electric service than the amount they pay in electric rates.
The Electric Power Research Institute (EPRI) has estimated that the annual cost of
power outages for California businesses ranges between $12 billion and $18 billion, and
the corresponding cost to U.S. businesses ranges between $104 billion and $164
billion.2
In another study, several researchers quantified the benefits of RTP to California by
conducting a counterfactual experiment (see Figure 2).3 They showed what would have
occurred in the year 2000 had the state implemented RTP. The study assumed that all
customers above 200 kW load were eligible for RTP, and assessed impacts under three
scenarios of customer participation, ranging from 25 percent to 50 percent to 100
percent. Figure 2 shows what would have occurred if customers had displayed a
moderate amount of price responsiveness: half of them would have displayed no price
responsiveness, and the other half would have displayed a degree of responsiveness
consistent with experience elsewhere in the United States and the United Kingdom. If all
customers had chosen to participate, peak demand would have fallen by 2.8 percent,
peak prices by 20.4 percent, and seasonal electricity costs by 6 percent.
Even higher results would be obtained if customers had displayed a greater degree of
price responsiveness. To quantify these benefits, the study examined another scenario
in which two-thirds of all customers displayed a degree of price responsiveness equal to

the average responsiveness that has been observed in other utilities, and the other third
of them displayed a greater degree of price responsiveness than has been observed
with customers who are equipped with enabling technologies such as self-generation. If
all customers participated in RTP in this scenario, peak demand would have fallen by 6.9
percent, peak hourly prices by 56 percent, and seasonal electricity costs by 13.2
percent.
While examining the effects of RTP in the Carolinas, Tom Taylor of Duke Power and
researchers at the University of North Carolina have found that RTP has induced load
reductions of about 70 MW, which translates into a long-term savings of some $2.7
million per year.4 In a similar vein, MIT Professor Schweppe's definitive work
demonstrated the economic efficiency that would result from RTP.5 Schweppe and his
co-authors conjectured that if the various "publics" involved in RTP could be convinced
of its many benefits, implementation would flow automatically. California's inability to
implement RTP in the summer of 2001 shows that, in the real world, implementation
never can be expected to flow automatically.
Lack of interval metering traditionally had been considered the biggest barrier to
implementing RTP. To overcome this barrier, the California Assembly passed a bill, AB
29X, allocating $35 million for installation of real-time meters on the premises of all
customers with a demand in excess of 200 kW. About 15,600 real-time meters were
expected to be installed or upgraded by June 2002, affecting approximately 30 percent
of peak demand in the state.6 This should have paved the way for implementation of
RTP, but it did not.
The California Energy Commission (CEC) filed an RTP tariff with the California Public
Utilities Commission (CPUC) in June 2001.7 This tariff was modeled after Georgia
Power's approach. Georgia Power runs what may be the world's largest and most
successful RTP program. Using a two-part design, Georgia Power has been able to
attract about 1,650 customers to RTP, representing 40 percent of the 4,100 customers
larger than 250 kW. These customers represent about 5,000 MW of total load, and 80
percent of them are engaged in industrial activities. Through its RTP program, Georgia
Power has been able to achieve a peak demand reduction of up to 17 percent on critical
days.
The CPUC rejected the CEC's proposal in a draft decision in July 2001. The CEC
revised its proposal, and submitted a simpler approach to the CPUC. The following
month the CPUC rejected this approach, and directed the utility distribution companies
to make their own filings. These were submitted later in August. As of this writing, the
CPUC still has not ruled on these filings, but the CPUC is considering a new Order
Instituting Rulemaking (OIR) on the issue.
California's experience with RTP draws attention to the very real barriers that face
utilities and states seeking RTP implementation. Last August, we conducted a series of
telephone interviews to assess the experience of utilities around the country with RTP.
Nine important lessons emerged from our interviews.
Lessons Learned from Utility RTP Programs
RTP programs have been around for more than 15 years, and over 30 utilities have
implemented some type of program, though many of these have been experimental.
However, relatively few utilities have sizable RTP programs. Figure 3 lists some of the

leading RTP programs. The following are lessons we have identified from our utility
interviews:
1. RTP programs can offer significant load shifting benefits, but most of the
load response comes from relatively few customers.
Customers pay attention to prices, and shift loads in response to price movements.
It is not unusual to find examples of peak load shifts of 15 to 20 percent or more.
However, most of the load shifting comes from a relatively small group of
customers, and many customers do not shift load at all.8 One utility found that it
had roughly the same response in 2001 with 59 customers as it did in 2000 with
over 100, because the non-responsive customers dropped off the rate. Another
found that only three of its 14 customers have done any "significant" shifting. Some
utilities found that almost no customers are shifting. Customers had to be allowed
to drop off their market-based RTP program by a California utility after PX prices
shot up, because customers didn't know how to shift. A Canadian utility has found
that even though it has roughly 25 customers on RTP, only one ever has really
shifted load, and even that customer could not sustain this shifting.
Even among price-responsive customers, response can vary significantly over
time.9 Presumably, customers have more scheduling flexibility at certain times than
at others.
2. Certain types of customers are more likely to respond to RTP.
The following groups of customers repeatedly have been shown to be more
responsive:
customers with on-site generation, such as hotels and large office buildings
in the commercial sector, and pulp and paper mills in the industrial sector;
customers with non-continuous (discrete) production processes, such as
municipal water pumping and cement production; and
customers who have previously been on interruptible rates, such as
universities.
3. A variety of customers can respond to prices.
Customers with the incentive to shift load can find innovative ways to do so.
Therefore, RTP programs should not exclude customers simply because they are
not in the groups most likely to respond to prices. Price responsive customers at
one utility include office buildings and grocery stores. Another utility has a price
responsive hospital that changes its chiller use in response to hourly prices.
4. Customers join RTP to save money.
Customers join real-time pricing programs to save money. While it may seem
obvious that customers with a choice of rates would choose the one in their best
interest, it is also true that customers joining an RTP program have certain
expectations about the rate-producing savings. This appears to be true even for
customers who do not plan to shift load significantly in response to price variation.
Thus, when the overall level of RTP prices (not just the price volatility) increases,
customer satisfaction with the program decreases. In some cases, customers
return to embedded cost-based rates in response to higher overall prices. For
example, all of BC Hydro's customers dropped off its RTP program within a year
after market prices increased.10
This finding also holds true for residential customers. Electricit‚ de France (EdF)
has had over 120,000 residential customers on a simplified RTP rate called Tempo
since 1996. Its surveys show that customers join the rate, and are satisfied with it,
because of bill savings. EdF has spent a significant amount of time finding
customers "suitable" to the rate-e.g., those with the ability to shift and save money
and to whom EdF can offer peak reductions.11 The program features two daily
pricing periods, on-peak and off-peak. It also features day-of-the-year pricing. The

year is divided into three types of days. The blue days are the most numerous
(300) and least expensive; the white days are the next most numerous (43) and
mid-range in price; and the red days are the least numerous (22) and the most
expensive.12
EdF does not offer a fixed calendar of days, but customers can know what color
will take effect the next day by checking a variety of different sources:
consulting the Tempo Web site, www.tempo.tm.fr [3],
subscribing to an email service that alerts them of the colors to come,
using Minitel (a data terminal particular to France, sometimes called a
primitive form of Internet),
using a vocal system over the telephone, or
checking an electrical device (Compteur Electronique) provided by EdF that
can be plugged into any electrical socket.
Commercial and industrial customers at PG&E, Southern California Edison,
Virginia Electric Power Company (Vepco), and Niagara Mohawk also indicated that
bill savings, as well as the related "control over costs," are a major reason for
joining RTP programs.13
While not as well documented, the implication that RTP programs have "free
riders" that join to save money is a serious issue. One utility has a one-part rate
that is designed to be revenue neutral with its time-of-use (TOU) rate. Since one-
part rates are often designed to be revenue neutral for the class as a whole, they
produce "winners" and "losers"-e.g., customers who can switch to RTP and expect
to save money without necessarily shifting load. Customers on this utility's market-
based rate did not seem to know how to respond to prices (because they had not
planned to shift) when PX prices increased significantly. As a result, the utility
ended up allowing customers to move back to the TOU rate, despite the fact that
customers had a contractual obligation to remain on the RTP rate.
Even customers who can and do respond to prices become less satisfied when the
overall level of prices increases. When prices increased on average by a penny
per kWh, Georgia Power's customers asked the state PUC for relief. The utility
modified the rate by slightly lowering hourly prices for these customers.
5. Customers do not like unmitigated price volatility.br /> Customer satisfaction
with RTP programs increases if they feel that their price exposure is limited.14
Greater price volatility can lead to higher bills. This is true even for price
responsive customers, because they may have periods when their response is
constrained because of business conditions. EdF has found that customers on the
RTP rate generally postpone laundry and other tasks on high-priced days, but if
three high-priced days come in a row, customers-especially those with young
children-will do their laundry and pay the high prices.15
To guard against such situations, many utilities have integrated some type of risk
mitigation feature into their RTP programs. For instance, Vepco's program sets an
upper limit on the number of high-priced days and a minimum limit on the number
of low-priced days.16 A study at Long Island Lighting Company also found that
limiting risk was likely to increase program participation.17
To limit price risk for its RTP customers, Southern California Edison limits its
program's highest-priced hour to $3.00/kWh. In the United Kingdom, customers
can purchase contracts for differences that essentially provide them with fixed
prices over a specific period of time.
In part to reduce customers' exposure to extreme price volatility, most U.S. utilities
with RTP programs recently have developed two-part RTP rates. These rates allow
a portion of customers' loads to be protected from price volatility. The Tennessee
Valley Authority (TVA), a utility that has had a one-part rate for 15 years, has
developed a two-part rate and has two very large industrial customers on that rate.

Some utilities with two-part RTP rates also offer risk protection products similar to
those offered in the United Kingdom. These products are intended to provide
customers with relief in the event that high prices coincide with periods in which
their ability to shift is limited. These products generally apply to a specific period of
time, and the utilities that offer them still offer incentives to reduce load during high-
cost hours.
6. RTP programs create revenue stability issues for utilities and bill stability
issues for customers.
Because RTP programs encourage decreased usage during high-priced hours,
utilities face the risk of under-collecting revenues. This is particularly true with one-
part rates, which generally include fixed costs in the hourly energy price. The pilot
RTP programs have shown that it is actually not hard for utilities to lose money on
RTP. The reason most RTP programs are still "experimental," and even permanent
ones often have very few customers on them, is at least in part due to this issue.18
Utilities are choosing two-part RTP rates in part because they have lower risk of
under-collecting fixed costs. One company has chosen to apply its "adder," which
provides a contribution to fixed costs, only on net incremental (vs. decremental)
energy to help avoid this problem. Other utilities with two-part rates, such as Aquila
and Public Service of Oklahoma, use variable adders, which tend to result in
smaller adders being paid to customers for when they reduce usage below their
customer baseline usage (CBL) than those paid by customers for incremental use.
7. With two-part RTP rates, utilities and customers often prefer simpler
designs.
Georgia Power and Duke, which have among them the oldest and most successful
two-part RTP programs in the country, began setting CBL with 8,760 hour load
profiles. Both utilities have moved to simpler CBLs for most customers. The utilities
report that they believe the simpler CBLs make sense for most customers, and that
customers tend to find them less confusing.
8. RTP programs can be successfully combined with interruptible programs.
In some cases, such as TVA, the utility's RTP rate applies only to interruptible
power. While high prices alone would in theory encourage customers to decrease
load at critical times, the interruptible nature of the power ensures that TVA has a
certain load management resource. TVA does offer a firm RTP rate, but as of this
writing, it had no takers for that rate.19 More typically, utilities allow interruptible
customers on RTP programs, and require them to interrupt to the level of firm
demand during interruptible periods. Customers not interrupting may have to pay a
penalty for non-compliance, in addition to purchasing energy at the hourly price.
Some utilities offer customers the option of buying energy during interruption
periods, but reduce the size of the interruptible discount for customers choosing
this option.
Typically, utilities offer interruptible customers RTP because these customers have
demonstrated an ability to shift load, and may be able to provide valuable price
response during periods of high prices that are outside interruptible periods. None
of the utilities that offered RTP to its interruptible customers felt that RTP
negatively impacted responses from the interruptible rate. As one respondent
explained it, "The rates are so different; interruptions only occur a few times a year,
[but customers can respond to prices every hour]."
9. Customer education is key.
This is the single most important lesson. Customers need to be educated
repeatedly for a couple of reasons. First, there is turnover at their companies, so
the person who best understands the RTP program might not be there in the
future. Second, customers tend not to focus on RTP when prices are low, and
begin to pay attention only as prices increase. To address its educational needs,
Georgia Power holds annual meetings of RTP customers all over the state. These

meetings are very well attended, and the utility believes the education program has
definitely paid off in terms of customer satisfaction.
-AF and MM
1. Steven Braithwait and Ahmad Faruqui, "The Choice Not to Buy: Energy Savings
and Policy Alternatives for Demand Response," Public Utilities Fortnightly, March
15, 2001, 48-60.
2. EPRI's Consortium for Electric Infrastructure for a Digital Society (CEIDS), "The
Cost of Power Disturbances to Industrial and Digital Economy Companies," Palo
Alto, California, July 29, 2001.
3. Ahmad Faruqui, Hung-po Chao, Vic Niemeyer, Jeremy Platt, and Karl Stahlkopf,
"Getting out of the dark," Regulation, Fall 2001, pp. 58-62.
4. Peter M. Schwarz, Thomas N.Taylor, Matthew Birmingham, and Shana L. Dardan,
"Industrial Response to Real-Time Prices for Electricity: Short-Run and Long-Run,"
Economic Inquiry, forthcoming 2002.
5. Fred C. Schweppe, Michael C. Carmanis, Richard D. Tabors, and Roger E. Bohn,
Spot Pricing of Electricity, Kluwer Academic Publishing, 1988.
6. Michael R. Jaske and Arthur H. Rosenfeld, "Developing Demand Responsiveness
in California's Energy Markets," 76th Annual WEA Conference, July 2001.
7. "Petition of the California Energy Commission for Modification of Decision 01-05-
064 By Proposing a RTP Tariff," June 21, 2001.
8. Kathleen King, "The Impact of Real-Time Pricing: Evidence from the British
Experience," Proceedings: 1994 Innovative Electricity Pricing, EPRI TR-103629,
257-267. At the time of the study, all of the customers on Midlands Electricity's rate
were 1 MW or larger.
9. Id.
10. According to BC Hydro's Allan Chung, the RTP rate was negotiated with customers
when market prices were lower than tariffs. It was not symmetrical, and some
customers could apply for reduced customer baseline usages (CBLs). From the
onset, customers viewed the program as a way to lower bills. Thus, when prices
went above market, many customers had price exposure arising from their reduced
CBLs and could not benefit from the rate because of the lack of symmetrical
pricing. They all left the rate. But the results could have been different, had the rate
been structured differently.
11. J. Cubille and P. Valentin, "Tempo Customers: Their Reaction to a New Tariff
Option," presented at the Unipede Conference on Customers and Markets, Lisboa,
June 1998.
12. Aubin et al. (1995).
13. Juliet C. Mak and Bruce Chapman, "A Survey of Current Real-time Pricing
Programs," The Electricity Journal, August/September 1993, page 62.
14. EPRI, Real-Time Pricing QuickStart Guide, TR-105045, August 1995, page 24.
15. Cubille and Valentin, at section 3.3.
16. Juliet C. Mak, and Bruce Chapman, "A Survey of Current Real-time Pricing
Programs," The Electricity Journal, August/September 1993, page 62.
17. Yannis Takos, Mitchel Horowitz, and Ellen Ford, "Gauging Customer Acceptance
for Various Real-Time Pricing Configurations," Proceedings: 1994 Innovative
Electricity Pricing, EPRI TR-103629, 138-144. 18 Glen Weisbrod and Ellen Ford,
"Market Segmentation and Targeting for Real Time Pricing," Proceedings: 1996
EPRI Conferences on Innovative Approaches to Electricity Pricing, EPRI, TR-
106232, 14-1. 19 Personal correspondence with Tom Miraldi, Cost and Price
Analysis, TVA, April 4, 2002.

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