Attachment A
Prepared for the Western Interstate Energy Board Meeting
October 29, 2001
Seattle, WA Todd Davis, SAIC
William
King, SAIC
This paper presents the rationale supporting the use of demand reduction and real time pricing (RTP) programs. A summary of prior experiences with these programs is provided. The paper presents best practices of these programs. An argument is made for linking demand response and real time prices to state energy master plans and market conditions and communicating to customers and energy sales and marketing personnel the role and rationale of these programs. Recommendations are provided for creating a Western region demand bidding and real time pricing market under certain conditions. State energy master plans would focus on the state’s energy supply chain, infrastructure, strengths/weaknesses/opportunities, key risks and demand profile. This could help avoid some surprises similar to what California experienced this past summer. As states move into more uncharted seas of deregulation and market dynamics such plans would not only be timely but also save a tremendous amount of money and help keep local utilities financially viable.
Demand reduction programs are usually event driven programs that occur when power prices either hit a certain cost threshold or reserve margins drop below a minimum percent – usually 8% or less of available peak load. These programs are usually of two types: predefined economic or emergency demand reduction programs where a specified price is paid for guaranteed load reduction independent of day ahead market prices; or flexible load reduction programs where bid prices are tied to day ahead spot prices of power. These latter programs are more voluntary and customers can determine whether or not they want to participate. The former program also frequently offers a firm capacity payment and the latter is sometimes a lower incentive.
EPRI estimated that demand response programs have the potential of reducing 45,000 MW’s of capacity, or 6.4% of baseline usage.[1] EPRI has also estimated that demand reduction programs can save anywhere from 4,800 MW to 9,000 MW’s of load, depending on the scenario.
The events of this past summer showed that in California as much as 13% of demand could be provided met by conservation and demand reduction programs. A significant percent of this is met by flexible demand reduction measures - 7% of CAISO load. This past summer the New York Pool obtained as much as 400 MW’s on selected peak load days through demand reduction programs. Utilities in the Pacific Northwest saw as much as 1000 MW’s bid by customers for an average price of less than $100/kW. At certain periods this past summer, this was a less costly way to buy capacity than to by power in a highly volatile day ahead market where prices went higher than $400/kW. However, there may be periods where day ahead prices fall below $60/MWh and the need for demand reduction may be less important from a strict economic perspective. The attractiveness of demand reduction programs is that you use them only during periods of energy or capacity need. You can set up these programs during periods of energy or capacity shortfalls. It is not uncommon to offer as many as three programs in one market area – with each program designed in a way that addresses the capacity or energy problem. Prior experience shows that different types of customers will respond to different types of demand bidding programs.
There are many benefits of interruptible and demand bidding programs for buyers of load, sellers of load, regional power agencies and states that are active in demand reduction programs. Generally speaking, interruptible programs and demand bidding, in particular, are a “call option” whereby buyers in a market that may need temporary capacity pay a nominal fee to have access to load when it is needed. Given the growing volatility in wholesale markets, the boom and bust cycle for power development, and the greater uncertainty of guaranteed supply and the need for a suitable reserve that can be called upon during emergencies, interruptible and demand bidding programs are expected to be around for some time. These programs are a win/win for buyers and sellers.
For buyers of demand reduction load namely the states and utilities that need (this sentence is unreadable in present format) capacity, they may acquire this load at a price that is less than the day ahead market and even avert curtailments which may be more costly.
Demand reduction programs are an efficient means of transferring demand from customers who are more flexible or willing to reduce their coincident demand and sell it to markets that need it the most. This is an efficient market clearing mechanism.
Sellers include end-use customers, aggregators, and wholesale suppliers who benefit by adding diversity, reliability and higher margin producing possibilities to their sales opportunities. This past summer showed examples where BPA “acquired” additional energy from a major Aluminum Company including the wages of employees because of the need to avoid expensive day ahead power and the chance that load could not be met. This was when no other sources were readily available to avert curtailments. On the other hand Portland General Electric (PGE) saw demand reduction programs as an opportunity to sell available capacity in the California market and use the higher margins from these sales as a means to reduce scheduled rate increases for local customers. This contrasts with other Northwest utilities that used demand reduction as a means to save on purchased power costs. Later the FERC price caps somewhat limited the opportunity by imposing limits to the superheated day-ahead spot market and this limited the very high returns to demand bidding.
In California and New York, there are also third party aggregators that are seeking interruptible loads and selling these loads to regional power organizations like the New York Pool, which have programs to purchase interruptible loads during certain occasions. Also, energy marketers like to use these programs as opportunities to create marketing and cross sale opportunities where a portion of the capacity payment is invested in additional cost saving diagnostics and opportunities – like metering and bill tracking and verification services.
To summarize, demand reduction programs are a win/win for buyers and sellers. They create less costly demand and energy supply, increase reliability, and are only used when the market needs the resource. The Western states would benefit from carefully designed demand reduction programs both within states and across states to help improve transmission flow and capacity and influence price stability. This may include both energy and capacity programs that are either day ahead and longer term where capacity payments occur to insure that some reserves exist to meet potential zone constraints. Also, these programs may be designed to appeal to different types of customers. However, great care must be taken to not design too many programs because this can be too confusing to customers and inhibit participation.
The objectives of this paper are to:
There are generally two types of interruptible programs: passive price programs and demand bidding programs. Passive price programs define in advance the requirements for the customer to qualify, what the minimum loads are that can be interrupted and what the price is for the interruption. These programs are less flexible in responding to market price dynamics than other programs. The other type of program is a demand bidding or exchange program where customers participate in a day ahead market and bid a certain amount of load at a given price. The buyer may or may not take the bid.
Demand reduction bid prices range from $100-500 on average. Typical loads that are available to aggregators are from 100-400 MW’s of load. Market data from some organizations indicated that about 2/3’s of the load from any entity aggregating demand could be acquired at about $100/kW. Both BPA and other Northwest utilities have found that a substantial amount of load is possible even at prices slightly below $100/kW. Demand bidding programs were offered by utilities in the Northwest, California, New England, New York state and utilities who are members of PJM – a longstanding regional power pool serving Pennsylvania, New Jersey and Maryland.
Examples are provided below.
The three programs
that the NY ISO offered this past summer are the following:
ü A Special Case Resources Program called ICAP for
interruptible capacity where a customer gets paid up front to shed a defined MW
load. If customers are not able to
deliver the pledged load they must buy the energy back at a premium.
ü Emergency Demand Response Program (EDRP) - Voluntary. If the customer can shut down the load in
time to meet system requirements, payment is made. No payment or penalty if customer does not.
ü Day Ahead Demand Response Program - Twenty-four hours in
advance, customer indicates amount of load available for reduction. NYISO accepts all or a portion of the bid
load at least cost for a specific time period and pays the customer ahead for
committing to the accepted amount. The
payment is the day-ahead price of the savings (greater of market price or
$500/MW). Effectively, the customer is
treated as a generation resource and must pay a ten percent penalty if the
curtailment is not delivered upon request, in addition to paying the greater of
the day-ahead or real time cost of the agreed curtailment amount.
Program Process - Twenty-four hours prior to an expected load curtailment
event, the NYISO Customer Relations department sends e-mails to customers requesting
bids. Customers and load aggregators
often reply. There is no set reduction
amount; bids range anywhere from 1 MW up.
On the day of curtailment, NYISO issues a curtailment warning two hours
prior to the event. The program is
marketed by load serving entities (LSEs), ESCOs, and load aggregators.
Program Results - As of August 2001, EDRP had 23 participants, representing
611 MW load reduction capability. This
amount includes 467 MW interruptible loads, 107 MW on-site generation, and 37
MW combined interruptible load and on-site generation. From August 6-10, available interruptible
loads ranged from 406-476 MW’s. On average on peak days 50% and more bids were
accepted. During the highest days
nearly all the bids were accepted. For
the Day head Demand Response Program from 20-40 MW’s was accepted on average
for the highest peak days. Curtailment
aggregators must provide at least 100kW in load in a single zone. A payment of
the higher of $500/MWh or the RT Zonal LBMP or locational marginal price /MWh
for verified reductions in load.
Program Experience – The EDRP program was activated four times during Summer
2001 (August 7 through 9). Load
aggregators bring most of the load reduction bids to the NYISO. The curtailment events went smoothly. For instance, the EDRP program worked
smoothly on August 7 and 8, 2001, with preliminary estimates of 400 MW demand
reduction over the two days. About 90%
of the data for these events has been analyzed and results remain close to the
estimated curtailment amount. A level
of 95% compliance was observed.
Communications with customers was not an issue, even with load
aggregators, who represented many of the customers.
Note: New York State
loads on the curtailment days were at all-time highs: August 7, 2001 (30,509
MW) and August 8, 2001 (30,665 MW). [2]
The PJM Load Response Program includes two options: Emergency Load Response Program and Economic Load Response Program. These are somewhat similar to the NY Pool demand response programs. Customers must reduce at least 100 kW in load. A minimum of ten hours of interruption is required and must be able to participate between 9AM and 10 PM during any and all days in the week. Customers must also pay the $5,000 membership fee to join PJM. Notification must be received electronically. Interval hourly meters are required. The higher amount of the zonal marginal price or $500/MWh will be paid.
PGE’s Demand Buyback Program (Oregon)
PGE offers a voluntary
buyback program to customers where customers may receive anywhere from
$.10-.45/kWh depending on market prices for load that is curtailed. The program is initiatived during peak
periods when electric prices are at their highest. Advanced notice of 12 hours and up to two days occurs. Load interruptions may last from a few hours
to up to 24 hours. Customers can pick
the duration and load amounts interrupted.
An easy interactive web page is used to receive bids, track
participation and account status.
California’s Large Portfolio of Interruptible Programs
The state of
California has perhaps the most exhaustive array of demand reduction
programs. These programs coupled with
other conservation programs resulted in approximately 8,000 MW’s reduced from
the State’s Total Load requirements of 61,000 MW’s (13%). The interruptible programs are estimated to
represent about 3,000 MW’s of the 8,000 MW’s of load reduction. The main programs offered include:
ü Base Interruptible Program
ü Optional Binding Mandatory Curtailment Program
ü Voluntary Demand Reduction Programs
ü Non-firm Interruptible programs
ü Demand Bidding program.
A summary of these
programs as implemented by PG&E appears in Attachment A. In early July the state created a demand
bidding program. However, while
customers have signed up for the program and one utility has about 300 MW’s it
could bid in the program, the Department of Water Resources (DWR) is not taking
bids because day ahead spot prices of power are lower than what most customers
may be willing to bid in load at. One
utility showed over two-thirds of customers willing to bid load at between $75
and $100/MWh. Attachment B shows which
of these programs may be most appealing to certain types of customers.
Currently the state
is considering ways to improve the performance of these programs and even
possibly consolidate the number of programs that exist. Actual load reported as of the first week of
July is 188 MW for the VDRP program, 88 MW for the CEC Demand Responsiveness
Program, 38 MW for the OBMC program and 1 MW for the Baseload Interruptible
program.
It is difficult to
recommend a particular demand bidding program without the participation of
various stakeholder groups. One program
design does not necessarily apply to all customers. Customers vary in their tolerance of frequency and duration of
interruptions. Both passive price
programs (do you mean “programs” here?) and market-based demand bids can be
used simultaneously in two different programs.
Based on available
experience, to date, recommended program considerations include the following:
A major cause of the
electric supply crisis in California was the more static retail prices while
wholesale prices skyrocketed and became quite volatile. Other contributors were buying too much
power in the day ahead market and no long term hedge on electric prices. California demonstrated that demand response
programs and conservation could be a big hedge to balance supply and demand. Also, given that states now will have to
contend with more uncertainty in supply and that there will always be some
capacity that is not definite, stronger vigilance will be needed by state
regulatory bodies to:
State level energy
master or contingency plans are needed to recognize that energy policies and
success to date in promoting competitive markets has not progressed as much as
expected. Meanwhile the great trends of
energy security, environmental protection, technology development, and
increasing customer and stakeholder collaborative business processes requires
that states and regions get their arms around these fundamental trends and find
their complimentary place. Encouraging demand bidding, real time pricing and
other time differentiated programs should be a part of state tactical and
strategic energy planning. The California
PUC is considering provisions for customers having an interval meter must be on
some demand reduction program, real time pricing or time of use pricing. States also at a strategic level need to
find their niche in the West in terms of being a supplier, transporter or
modifier of end use energy and technology.
Such plans are needed to realize opportunities and limit risks in a much
more uncertain energy sea. Supply and
demand initiatives though more highly market driven, need to have contingencies
and the states need to be aggressive in evaluating what they should be. In the future, as much as 10-15 % of load
may be at risk and so adequate precautions are needed to take this into account
in terms of considering tactical and longer term planning. Such plans should be developed not only from
state perspectives but also the context of being in a broader regional market,
including markets involving Canada and Mexico.
States need to be sure that their demand reduction programs are more
closely tied to market dynamics and that there are suitable contingencies to
respond to market fluctuations that run contrary to the public interest. California is a very good lesson of
experience here for the need of such plans.
An important way to
encourage more distributed resources is to encourage demand bidding and real
time pricing programs. This will
accelerate balancing supply and demand.
The highest form of load optimization and market price balancing is real
time pricing. While this form of pricing has been experimental for some time,
it is starting to grow in greater use in the year’s ahead.
The largest real time
pricing program is the Georgia Power Company Real Time Pricing Program. Currently, there are 1600 customers with
loads of over 250kW. There has been an over
400-800 MW response, which is equivalent to 2.5 – 5.0 % of GPC system
load.
Another innovative
program is the one involving Puget Sound Energy customers which uses smart
meters and Internet-based technologies that give customers nearly real time
information on the variable, time sensitive cost of energy.[3] Real time pricing programs are heavily
dependent upon time sensitive energy costs and consumption. Right now most customers rely on very static
information or lack of information in making energy consumption decisions. Programs similar to Puget’s should help
customers react in more real time, dynamic ways to market prices and their own
immediate needs. Puget Energy now supplies real time customer data to about
400,000 customers. Using Puget’s web site customer can talk to a customer
service representative to get advice on how to balance loads with energy
prices. Recent Puget surveys have indicated that over 79% of residential
customers and 70% of business customers have taken action to alter their energy
use. About 43% of residential customers
have taken action to shift electric use to off peak periods. And 41 % have cut
their use during peak periods. A trial of 300,000 households is now occurring
through September and there are plans to offer universal real time pricing
programs to all of Puget’s customers.
A recent report by
McKinsey Company found that Americans could save $15 billion annually with real
time pricing.[4] A report by EPRI found that California
customers could have reduced the state’s peak demand by 2.5 % during the Summer
2000 period and cut electric bills by $700 million. RTP benefits occur primarily during periods of lowering
consumption during higher price periods.
Usually the amount of energy or load shifted is far less than the impact
on market prices – which may be as much as five times greater impact, depending
on the market.
The experience to
date is that customers will respond to prices based on their needs, knowledge
of how to modify loads and perceived economic value. Customers will invest in a variety of new demand side products
and solutions. Price responses of
customers are often creative. Large C/I
customers clearly have economies of scale.[5]
The key success factors of RTP are:
Given the prior experience of other sponsors of demand bidding and real
time pricing programs, and considering the unique aspects of the Western power
market, and size of the retail market for states outside of California, there
is a need for the Western states to consider the following:
SAIC
has substantial experience in designing, implementing and managing
interruptible and demand response programs.
We have participated in the design of such programs in the Middle
Atlantic region and in the West. SAIC
staff has been involved in front office, mid office and back office support
roles. We have also developed sales and
marketing programs for these programs.
SAIC is prepared to assist WGA in evaluating; planning and implementing
demand response, RTP and other price and demand responsive programs for the WSCC
and Western states. Please contact Mr.
Todd Davis for more information. Todd.d.davis@saic.com
If your primary concern is: Select
·
Reliability OBMC
·
Guaranteed minimum
savings ($/kw-yr) Interruptible,
ISO DRP
·
Fixed $/kWh savings UDC
VDRP, ISO DRP, ISO DLCP
·
Maximum # reductions Interruptible,
ISO DRP
·
No minimum load
reduction RTP
·
No new interval
metering ISO
DLCP
·
Daily savings
opportunities RTP
·
Day ahead notice RTP,
ISO DLCP
·
Month ahead notice UDC
SLRP
·
No penalty if do not
reduce demand RTP,
TOU, ISO DLPC?
·
Protection of load
growth from market prices Any
but RTP
·
May buy incremental
power below tariff rate RTP
·
Complements to
OBMC/Interruptible RTP
[1]. EPRI, “Closing the Electricity Infrastructure
Gap – Can We Avert a Crisis”. EPRI Advisory Council and Board of
Directors: Summer Seminar 2000” (August
5-7, 2001), p. 22.
[2]. Additional information on experience/results
of August curtailment events: See NYISO website, Services - Board of Directors,
Committees and Working Groups - Business Issues Committee - Price-Response Load
Working Group - Meeting Materials - Meeting Materials for Sept. 14 meeting -
Agenda Items 2 and 8
[3] “The Imperative for Real Time Pricing.” Utility Business (September 2001), 36-38.
[4] Ibid.
[5]. SCT, “Implementation of California RTP
Supplemental Tariff”. Presented to CEC in July, 2001.