Deregulation metering: turning pulses into profits

DEREGULATION METERING-TURNING PULSES INTO PROFITS

Frank J. Richards, PE, CEP

The Richards� Energy Group

Gerald R. Mimno

AES Intellinet

Elizabeth M. Kimmel

Alliant Energy

Randolph L. Haines, CPE, CEM, CLEP

Thomas Jefferson University

ABSTRACT

Smart metering options in this age of deregulation has resulted in many emerging opportunities to turn the pulses used to measure metered data into profits for all stakeholders�the end user, the energy service company, the equipment manufacturer and the consultant administering users� groups.

Real-time interval data posted on the Internet has a pyramid of value. At the bottom of the pyramid is Automatic Meter Reading that has a value of about one dollar per month per account.� Next up the pyramid are applications targeted to optimizing kW and kWh for commercial and industrial users.� Higher still is real-time data used for aggregation and distributed generation.� At the top of the pyramid is real time risk management used to support energy trading, forward purchasing, and hedging where millions of dollars in energy contracts are at risk.� Energy and service suppliers have the opportunity to raise their sights above AMR and offer their C & I customers many real time interval based services offering higher returns in the pyramid of value.� The same interval data fuels value creation at each level of the pyramid.

Interval load data provides value to electric users� groups and members of these groups.

The PJM (Pennsylvania/New Jersey/Maryland) Interconnection has implemented several emergency and economic load response programs requiring the end user to provide interval load data.

Thomas Jefferson University has embarked on an in-depth program of interval data acquisition and interpretation, to provide opportunities to reduce costs at its facilities in Philadelphia.

THE NEED FOR REAL-TIME INTERVAL DATA

Since its inception 100 years ago, the power industry has depended on supply side load balancing.� Demand side data has been collected from meters one to 30 days after the fact and used for accounting.� Compared to other industries, utilities operate with very little real time data.� In real time, utilities know what their load is, but they do not know who is using it, where, or for what.� Neither do they or their customers know what the potential may be for demand reduction or how to avoid price spikes and rolling blackouts.�

Converging forces drive the need for real-time interval data.� The monetization of the utility industry through trading and hedging energy, power, and transmission requires more data.� Over 30% of wholesale power was traded in 2000.� The figure will reach 90% by 2004 ¹.� Financially sophisticated generators and suppliers such as Dynegy and Enron have seen unprecedented profit while the largest traditional utilities on the West Coast are nearly bankrupt.� Retail gas and electric prices have risen by 50% in some US markets ², while wholesale prices in CA have increased anywhere from five to 30 times ³.� Price spikes in the spot market have reached 50 times normal. Environmental restrictions and "Not in my back yard" politics have left California supply 5000 MW short of demand.� Only conservation can make this up in the next three of four years until new generation and transmission can come on line. �The problems in California are expected to appear next in New York where demand has increased 20% in five years with little new generation.� Any state pursuing deregulation where generation has been separated from distribution is vulnerable to price volatility and escalation.� A key factor in restoring balance is to provide C & I customers with real-time price signals.�

The Internet now makes it possible and economical to collect interval data on a near real time basis and to distribute this data to commercial and industrial customers and the companies in their supply chain including generators, independent system operators, transmission companies, traders, marketers, distributors, energy managers, financial controllers, and energy service companies.� Real time, or more accurately �near real time� interval data is meter data encapsulating a 15-minute period that is accessible on a network before the close of the next 15-minute interval.� Interval data may relate to a single meter, an aggregation of meters, or a statistical sample of meters representing some aggregated or regional load.� Sharing contemporaneous data among the contracting parties in a supply chain adds value to the entire chain and improves the profit of each party.� The use of real-time interval data can be likened to a Pyramid of value with low value uses on the bottom providing a small benefit to a large number of users, middle level applications providing moderate value to many, and high value applications at the top of the pyramid providing very significant value to the few.

AUTOMATIC METER READING

AMR represents the lowest value application for interval data.� AMR technology is now deployed in the US in 7% to 10% of accounts but AMR has continued to focus on billing data that provides only a low incremental value.� An experienced meter reader can take a read for about one US dollar per account in an urban or suburban distribution system.� Typically the additional capital cost of an AMR system needs to be amortized over several years before operational savings improve the bottom line.� The difference between a real-time and episodic AMR system is significant.� A real-time system can continuously update inputs needed by remote energy applications.� Episodic data is collected monthly from a meter reader or drive by system or through a telephone dial-up connection.� The value of episodic AMR is to show past performance.� The value of real-time AMR is in changing the supply chain or demand management in the next 15 minutes or the next hour.� Expect episodic AMR to be upgraded to real-time in both commercial and residential settings.

The value of interval data in AMR is about a dollar a month in displaced costs per account.

KW & KWH OPTIMIZATION & CURTAILMENT

The next highest value for interval data is using near real time data to manage peak load, load shedding, and time-of-use pricing.� One municipal electric executive has noted that a customer that has never practiced peak demand management can save ten percent in demand charges with the implementation of the very first steps in a demand management program.� Since demand charges typically represent about one third of the cost of power, managing demand in real time allows substantial savings.� Typically peak costs were 40% above off-peak.� This is changing.� For example, in Maryland, PEPCO, prices in 2001 were 2 cents kWh off peak and 19 cents on peak.� Deregulation will increasingly pass this price differential on to both commercial and residential end-users.� This change will be accompanied by new TOU tariffs and new metering presented on the Internet to give users price signals to optimize their consumption and cost.

One of the outputs of the electricity chaos in California will be more information on the elasticity of demand.� Californians are mandated to reduce total consumption by 10%.� Imperfect measurements already show a reduction of 2% to 8%.� With real time data on load and tariffs, customers can see this data and respond to it.� These reductions will be especially important during critical price events.

Most larger facilities have on-site energy management systems.� However, these systems have become too complicated for on-site personnel who are reluctant to optimize a system or who implement very limited adjustments.� The systems also tend to be programmed using tight constraints for comfortable temperatures in a building and loose constraints on cost.� A skilled off-site energy manager can optimize both comfort and cost by anticipating operational requirements from a very small data set trending ambient temperature, humidity, chilled water temp, flow rate, and specific loads.� Based on this trending, the remote manager can benchmark a facility and operate optimum on-site energy management scripts.� Energy service companies [ESCO�s] can point to operating savings of as much as ten percent in office buildings from efficient mechanical management without loss of comfort or significant new investment.� Since utilities typically cost $1.75 sq. ft., saving ten percent in a 100,000 square foot office could add $17,500 to the bottom line of a Real Estate Investment Trust [REIT] and leverage the equity value by ten times that amount.� A real time remote curtailment system makes possible continuous energy optimization potentially saving customers thousands of dollars a month.

Another type of curtailment is described as non-invasive.� This is semi-automatic curtailment of small amounts of power over many customers.� One example cuts 2% of residential load by cutting out air conditioning for 25 minutes every hour.� This saves a single customer $9 month but can cause a very significant load reduction when applied to hundreds of thousands of customers.� Managing non-invasive curtailment is challenging but is made feasible by using the Internet as a communications backbone.

The value of interval data in optimization is $100's to $1,000's per month saved per facility.

AGGREGATION & DISTRIBUTED GENERATION

Continuing up the value chain, the next market segment is using interval data to manage aggregation and user groups.� Gas and electric deregulation will eventually lead to significant bidding for aggregated loads.� Anticipated targets are business, schools, and institutions.� Massachusetts initially announced plans for numerous aggregations including all state and municipally owned buildings, health and hospital facilities, colleges and education facilities, companies in the High Tech Council, companies in traditional industries, non-profit organizations, the Building Owners and Mangers Association, and more. In newly deregulated markets, the savings to the end user are not big enough to overcome the inertia of staying with the incumbent supplier.� While utility deregulation started in half the US states, as yet a real time market for aggregation has not developed and the energy marketing industry gets by with static monthly data.� However, needs are changing.� As a rule of thumb, eighty percent of power is sold to the twenty percent of accounts representing large users.� The MA aggregation represents well over half the power sold in a DISCO region and these meters will have to be networked to find benefits in deregulation.� For example, a typical University may have over 600 meters and cannot realize the overall benefit of deregulation until these are combined into one large �virtual� meter.� A power marketer with access to real time data would have significant competitive advantage in managing power aggregations.� Enron Energy Services uses real time data and monitoring in managing a national portfolio of malls and facilities for the Fortune 500.� Enron describes the assets as "smart peaked plants" as it trades power into and out of the portfolio. ⁴

Another lesson from new power markets is that small changes in peak demand cause large changes in spot market pricing.� As the California market tightened in 2001, wholesale energy prices were ten times higher than a year earlier.⁵� This dynamic works both ways.� A new study from the Electric Power Research Institute [EPRI] finds that a 2.5% reduction in peak demand can drop wholesale prices by 24%. ⁶��

Distributed Generation offers another approach to dynamic value.� Large downtown office buildings typically have stand by generation for 25% of their load for operation of elevators and key systems.� The ability to deploy stand-by generation has substantial value.� Under present tariffs, companies use distributed generation assets to shave peaks and reduce their overall demand charges.� Assuming favorable environmental review, energy managers could operate an auction market for distributed generation.� On a hot day, load shedding could be worth twenty times its regular price.� A new tariff in New England allows large users to curtail power and get the market price. ⁷ ��Real time interval data allows an auction market for stand-by generation and load shedding that can unlock the value of distributed generation.

The vale of real time interval data in aggregation and distributed generation is measured in $1,000's per month

RISK MANAGEMENT

The highest value in using real time meter interval data on the Internet is risk management or the process of using contemporaneous data to adjust positions in the energy forward market, energy spot market, or hedging with energy derivatives.� Energy trading may be conducted at a power exchange, through bilateral agreements between parties in the energy supply chain, or in the futures and options markets.� On average, energy or power is traded five times before it is delivered.� A single trading position may be planned a year ahead of delivery and adjusted six months out, three months out, and then at decreasing intervals of 1 month, 2 weeks, six days, three days, day ahead and hour ahead.

Today�s traders have a lot of detailed contemporaneous data on supply and market pricing but little data about current demand.� What data is available on specific high voltage transmission and distribution links is highly aggregated and not keyed to customers.� There is very little contemporaneous data available at the customer level.� Most customer data is collected for monthly billing and is likely a month or more out of date.�� The Internet offers the opportunity to access current demand data in a data warehouse giving traders insight into the unpredictable effects of climate, local weather, business operations, and demographic variation on the demand side.�

Some traders want to avoid risk by locking in future prices, other traders seek profit in the spread between current and future prices.� Energy risk managers, who do not expect to take physical delivery of the product, use financial derivatives such as futures and options to manage price exposure in the market place.�� These financial instruments are based on different estimates of the future, and the derivatives manager who has current demand data will have significant advantage over colleagues trading while looking through the rear view mirror.� In a recent storm, a power trader made tens of thousands of dollars in one day by having better real-time weather data than the market. ⁸

Energy supply is no longer the operating process of delivering energy but is an increasingly complex process of filtering energy through the financial markets and requiring historical and real time data to adjust trading and marketing positions.�

The value of interval data in risk management is measured in hundreds of thousands / millions saved in contractual provisions.

FIGURE 1

PYRAMID VALUE OF REAL-TIME INTERVAL DATA

RISK MANAGEMENT

Value of interval data used in risk management is measured in millions of dollars per year

for adjusting trading positions

AGGREGATION &

DISTRIBUTED GENERATION

Value of data used in optimization is measured in

100�s � 1,000�s of dollars per month in

commercial / industrial accounts

KW & KWH OPTIMIZATION &

CURTAILMENT

Value of interval data for aggregation and

�remote management is measured in

one to two digit savings for C & I customers

AMR

AMR value realized after several years amortization

The same interval data input supports different networking and software applications at each level of� the pyramid.

COMMUNICATIONS & SOFTWARE

There are two significant technical challenges in unlocking value in real time interval data.� The first is finding an economical way to connect meters to the Internet every 15 minutes through the local loop.� .� This challenge is being met by many different wired and wireless technologies.� The spread of the Internet is rapidly lowering cost of communications as the distance needed to get meter data into an Internet connection is getting shorter and shorter.� Currently wireless is an attractive means to put economical interval data into a data warehouse on the web in near real time.� In the future, meters and control devices each with their own IP address are expected to be wired directly to the Internet.

The second challenge is software applications which turn interval data into decision and control strategies� saving commercial / industrial customers money.� The communications and software industries are well on their way to meeting these challenges.

DEREGULATION

Deregulation of electricity in Pennsylvania has provided a real alternative to end users who are willing to shop for electricity instead of taking total supply from the utility.� Unlike some other states, actual savings for end users has been attainable since January, 1999, by purchasing the commodity from any supplier licensed by the Pennsylvania Public Utility Commission.� The savings are based on a comparison of the supplier�s price for generation and transmission with the �price to compare� or �shopping credit,� determined by individual calculations for each billing period.

STAKEHOLDER ACRONYMS

Deregulation of electricity has developed a new industry with its own set of acronyms, which will be used throughout this paper.� Following is a list defining many of them with descriptions.

EDC�Electric Distribution Company.� This is the regulated part of the electric utility.� Charges from this part of the utility remain in the utility bill even after deregulation is fully implemented.

EGS�Electric Generation Supplier.� These are the deregulated suppliers of electricity as a� commodity.� Many of these are newly created subsidiaries of the old electric utilities.

PUC�Public Utility Commission.� �This is what Pennsylvania calls its government oversight agency for both regulated utilities and deregulation activities.

End User.� No acronym here�this is the ultimate consumer who has to pay the electric bill, whether it�s deregulated or not.

REAP�Richards� Energy Affinity Program.� This is the electric users� group formed by Richards� Energy Group to bind many end users into one market force.

AGGREGATION VS AFFINITY�

The users� group developed by REG is called REAP, or Richards� Energy Affinity Program.� This acronym would be more descriptive if �Affinity� were �Aggregation.�� However, Pennsylvania�s laws define aggregators as those who purchase energy for a group, then redistribute it to the group.� Since REAP does not take title to the power, it cannot be called an aggregator, by Pennsylvania�s definition.�

DOES BUYING AS A GROUP MAKE SENSE?

Buying groups are fairly common for many business applications, from trade organizations that buy large quantities of paper towels to a local Chambers of Commerce, which offers a health benefits, plan to its members.� So the concept of banding together to purchase electricity would seem to make sense.� My initial idea, however, was to band together a group of industrial, commercial and institutional electric consumers in an electric utility in central eastern Pennsylvania, for the purpose of NOT shopping for electricity.

The idea was to approach the utility, requesting that they provide favorable long-term contracts for our group to keep us from participating with anyone else in deregulation.� A major advantage of this plan was immediate implementation �deregulation was not to occur in Pennsylvania for another 2 years�entering into �non-shopping� contracts would start savings immediately, and would eliminate the uncertainty of whether and how much savings might occur with deregulation.� However, as happens with some ideas, this one was not to come to fruition.� The utility ultimately decided not to honor our group�s offer, but rather to solicit each end user to eventually take deregulated service individually from their newly emerging deregulated subsidiary.� As a result, the loose knit group dispersed.�

FORMATION OF REAP

The failure of this group served a very useful purpose�it showed REG how considerable market clout could be developed by a group�but it needed to be a �strong� group with a well-defined structure�one that could survive the ups and downs of moving forward in an emerging, volatile market.

What ultimately developed was an electric users� group that could bargain as one unit for electric power to achieve pricing better than each could achieve individually.� The vision was that putting together diverse loads that would �sink or swim� together would improve the competitive advantage we would have when shopping.

BASIS FOR INITIAL TARGET GROUP

Our initial target group was mid-size industrials, and large commercial/institutional loads.� Very large industrials were omitted, since these usually have substantial bargaining power on their own.� The thinking was that diverse loads would actually improve the load profile we provided to suppliers, for two reasons�improved overall load factor and reduced overall peak demand.

IMPROVED LOAD FACTOR

An electric user�s load factor is defined by how much of the time this user is consuming electricity at peak levels�the more time he is at or near his peak, the higher his load factor.� As a simple example, if a user is at 1000 kW for 8 hours a day and at 0 kW for the remaining 16 hours, his load factor will be

�����������

1000 kW X 8 hrs� X 100% �=� 33%

����������������� 1000 kW X 24 hrs

This is shown graphically in Figure 1.� If the group is diverse, the combined load factor of the group will be greater than the individual load factors.� As illustrated on the graph, the individual load factors are 33%, 50% and 58%, but the combined load factor is 100%.� This example was designed to illustrate the point, and of course is somewhat unrealistic.�

However, the graph in Figure 2 shows actual data for 7 users on a specific Monday, either in the spring or fall.� This same data is represented in chart form in Figure 3.� The daily load factor for each user ranges from 83% to 90%, while the combined load factor for the group is 90%.� Therefore, by �aggregating� these 7 loads, the overall load factor either increases or at worst stays the same.� This means that careful selection of group members can help the whole group�s load factor.�

LOAD FACTOR SAVINGS

Although commodity charges vary dramatically, my discussions with several suppliers have yielded some general guidelines that should prove accurate on a relative basis, as follows:

For one particular user with a load factor of 70%, and assuming the overall group load factor is 80%, the energy charge will be .1�/KWH less in the group than alone.� For this user�s annual consumption of 19,200,000 KWH, this results in annual savings of $19,200.� Keep in mind that if this user could not aggregate loads with others, this $19,200 savings would not exist.

CAPACITY REQUIREMENTS

When diverse loads are combined, the concept of �non-coincident� demand becomes important.� Simply put, one user�s peak is not likely to occur at the same time as another user�s peak (or the peaks are non-coincident).� This means that the peak demand with all users combined will be less than the sum of individual user�s peak demands.� Thus the electrical capacity, which has to be purchased to meet the peak, is lower for the group than it is for the sum of each individual.�

This can be seen in the chart in Figure 3 with the actual 24-hour data for 7 users.� Individual and group peaks for the day are shown boxed-in,� The sum of the individual peaks is 20,755 kW, but the group peak is 19,954, for a peak reduction of 801 kW.� Also notice that the time of the group peak occurs at a different time than any of the individual peaks.�

CAPACITY REQUIREMENTS SAVINGS

Based on this, REAP�s targeted 50,000 kW of individual loads would combine to about 48,000 kW diversified demand for the group, or a 2,000 kW reduction.� Charges for capacity requirements are based on demand, and amount to approximately $.005/kW on an hourly basis,

50,000kW X $.005/kWH capacity = $250/hr

48,000kW X $.005/kWH capacity = $240/hr

����� Savings� �����������������������������������������$10/hr X 8760 hr/year =

Annual Savings������ $87,600

The user in the example above has a demand of 3000kW.� Thus, this user�s capacity savings would be proportionate to the savings for the whole 50,000 kW group, or 3,000/50,000 X $87,600 = $5,300/yr.� Again as mentioned before, this $5,300 savings would not exist without aggregating this end user�s loads with others in the group.

TOTAL SAVINGS

Totaling the savings above for this example, this end user would save approximately $24,500/year, or 2.2% of his annual billing just through aggregation with the group.�

EARLY EXPERIENCE

REAP�s actual experience found some suppliers who supported our load factor and capacity findings, some who understood, but did not have the level of sophistication available yet to deal with them, and some who just didn�t understand at all.� In addition, many of the accounts within the group do not have the advanced metering capability to get the hourly load data essential for this type of analysis.

However, after receiving pricing quotes from several suppliers, it was found that while the larger users with high load factors and availability of hourly load data were in fact getting better overall prices, the percentage savings for smaller accounts with poor load factors was up to 32%, while some larger users were saving as little as 3%.

This phenomenon has been attributed to several factors:

�         The large users are already using their �large power� rate structure very efficiently, meaning the overall �/KWH is already low, which leaves little room for savings.

�         The smaller users are on �general service� rates (which are higher than large power rates).

�         The smaller users are using their rate structure very inefficiently, often not getting into the bottom step of the declining block rates.� This means the �/KWH rates are high, with significant room for savings.

�         Utility rate cases are sometimes proportioned away from rate classes that traditionally have a major presence in the proceedings (such as the Consumer Advocate for Residential, and lobbyists for large power consumers), and toward rate classes that aren�t well represented (such as general service).� When the generation portion of these rates is deregulated, prices are based on what the suppliers think the actual cost is, so it�s payback time for the general service ratepayer.

FUTURE DIRECTION

As advanced metering data becomes more available and less expensive, smaller accounts will be able to justify its cost�when that happens, we will see additional benefits for smaller users by improving overall load factor and reducing coincident demand.�

For now, REG emphasis is on growing the REAP group and continually searching out suppliers in this volatile market where many suppliers are dropping out.

WHAT IS REAP?

The Richards� Energy Group (REG) has built a strong electric users� group, named REAP, for various industrial and commercial businesses.� It presently has over 60 members of varying sizes and types.� REAP�s membership spectrum ranges from manufacturers, hospitals and retirement communities, to car dealers, restaurants and shoe stores.� This diverse group has one thing in common�-savings on electric bills.

�

HOW REAP WORKS

Evaluation:� The Richards� Energy Group (REG) evaluates an end user�s electric usage to determine projected savings, and whether they would benefit by joining REAP.�

Membership: Based upon those projected savings, the company joins REAP and becomes one member in a block of members for which REG negotiates the best electric rates available.� The annual membership fee for each member is based on total annual electric consumption.��

Shopping:� REG acquires and assembles detailed load and billing data for each member, then collates the data to benefit each member.� REG solicits suppliers and evaluates their qualifications, requests proposals from qualified suppliers, then selects the best for the group.� After contract terms are negotiated and approved by REG, contracts are executed between the supplier and REAP member.

Follow-up:� Once contracts are in place, REG selectively audits members� electric bills to ensure that contract terms are being met.� REG keeps all members informed of various deregulation issues and developments.� There is an annual meeting of all REAP members.

WHY REAP WORKS

Size: The REAP group is growing, with over 60 members who collectively consume more than 180 million KWH of electricity each year, and save over $700,000 each year on their electric bills �.�

Strong Group:� Each member of the group gives REG the exclusive right to solicit, evaluate, negotiate and maintain favorable pricing and terms from any and all electric suppliers.� When REG presents a group of electric accounts to suppliers for bid, the suppliers know that they will win all the accounts if they are the successful bidder.�

Data:� Providing electric suppliers the maximum amount of load data in a consistent, professional format enables REG to obtain better rates for REAP members.

Qualified Professionals:� All of the hassle and details involved in bidding, evaluating, negotiating the contracts and pricing are handled by REG.� Since REG is working only for the users who have enrolled in REAP, you can have confidence that opportunities with electric deregulation are being managed for your benefit.� You can then channel your energies toward your own area of expertise, for which your business is intended.

Focus and Independence:� REAP members commit to shop with the group.� Our members aren�t testing the waters to see if a good rate might float to the surface.� REAP was formed for the sole purpose of banding together diverse types of electrical loads, to reduce electricity rates for all members.� REG is paid by REAP members, and is not beholden to any electric supplier.

Update on the PJM 2001-2002 Load Response Pilot Program

About PJM

PJM (named because it serves portions of Pennsylvania, New Jersey and Maryland) operates one of the largest electricity grids in the nation and administers the largest wholesale electricity market in the world.� PJM�s region includes all or parts of PA, NJ, DE, MD, VA and D.C.� More than 140 new generating projects are planned which would add more than 40,000 megawatts of generation to PJM�s region and over $700 million is being invested in new and upgraded transmission system facilities.

PJM coordinates a pooled generating capacity of more than 58,000 megawatts and operates a wholesale electricity market with more than 200 market buyers, sellers and traders of electricity.� It has administered more than $5 billion in energy and energy service trades since the regional markets opened in 1997.� PJM combines Internet technology and innovative market rules to run its real-time wholesale energy market to meet the world�s rapidly increasing demands for reliable and affordable power.

In September 2000, PJM Technologies Inc. was created as a wholly owned subsidiary of PJM Interconnection, L.L.C. and designed to respond to market opportunities brought about by deregulation.� PJM Tech is focusing on cost-effective, reliable solutions for the energy marketplace.� It was created to commercialize PJM�s knowledge capital, experience and proven success in electric energy markets and system operations.

PJM has emerged as a dominant model for other Regional Transmission Organizations (RTO).� In July 2001 the U.S. Federal Energy Regulatory Commission ordered mediation talks with PJM, PJM West, New York and New England ISOs to create a single regional transmission organization for the Northeast to improve how electricity is shipped.� FERC�s action is a big step forward in its quest to have four RTOs serving the West, Northeast, Southeast and Midwest.� FERC believes that the Northeast needs to be served by one RTO instead of several transmission grid managers.� Once the 45 days of mediation talks are completed the administrative law judges will report back to the Commission (August 2001).�

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PJM 2001-2002 Load Response Pilot Program

In July 2001, PJM Interconnection, LLC met the needs of its more than 22 million customers while responding to record-setting demand.� During the week starting July 23^rd system-wide electricity use reached an all time peak of 51,798 megawatts (MW) on Tuesday and 52,200 MW on Wednesday. The region�s last all-time record for electricity usage was set on July 6, 1998 when electricity consumption reached 51,700 MW.�

PJM instituted several standard operational procedures in 2001 including the first-time use of a demand-side response program.� The program approved by the Federal Energy Regulatory Commission (FERC) compensates commercial and industrial customers for reducing energy use in times of high demand.�

The 2001-2002 Load Response Program is an outgrowth of the Customer Load Reduction Program PJM implemented last summer to enhance the reliability of the PJM system by encouraging load reduction and use of distributed resources.� It encourages customers with distributed generation resources to either sell them into the market or use them to meet their load requirements without taking energy from the PJM system.�

PJM is implementing two curtailment programs � an emergency program to keep the lights on and an economic program to respond to price spikes before an emergency arises.� The 2001-2002 Load Response Pilot program was filed and approved by FERC and in May PJM began accepting registrations for the Program.� The Emergency and Economic programs will run till May 31, 2001 and will enable participants that reduce load either during emergency conditions or as a result of high wholesale prices to receive payment for those reductions.�

A special category of PJM membership is offered for participation in the Emergency Option of the program while full PJM membership is required for participation in the Economic Option.� Participants may reduce load upon notification from PJM that is posted on the PJM web site as well as distributed via email.�

Participants can reduce load whenever LMP in the appropriate zone makes it economic to do so and an email must be sent to PJM immediately prior to the reduction.� Participants are also responsible for sending the appropriate meter data to PJM following a reduction.

PJM deals directly only with PJM members including end-use customers, aggregators and ESPs and payment is made to the member that brought the curtailment.� $500/MWh is paid to the member that nominates the load reduction and a $10 transaction fee is assessed per account for each event.�

Emergency Program

Participants that have the ability to supply required load reduction via local generators; can serve their load; are not synchronized to the grid and have no net export to the grid.

Special membership provisions apply to Emergency participants and the annual membership and application fees are waived ($6500).� Provisional membership ends August 30, 2002. Participants aren�t required to have 24/7 control center coverage but don�t have voting privileges.

A distributed resource must be capable of reducing at least 100 kW of load and have the ability to participate for a total of at least 10 hours over the pilot operating period.� The participant must be available any hours between 0900 and 2200 on any or all days of the week.� Participant must be capable of achieving full reduction within one hour of PJM�s request to reduce load and capable of receiving PJM notification.

Metering Requirements:

Participants must have metering equipment that provides integrated hourly kWh values that either meet the EDC requirements for accuracy or have a maximum error of two percent end-to-end (including PTs and CTs).� The metering requirements can be met in one of two ways:� 1) metering that is capable of recording integrated hourly values for actual net generation or 2) metering that provides actual load change by measuring actual load before and after the reduction request. A valid integrated hourly value for the hour prior to the event and each hour during the event is required.� In addition the meter must be one of the following: 1) an Electric Distributor Company (EDC) owned hourly meter; 2) a customer-owned meter, including one provided by an independent metering service provider or Curtailment Service Provider (CSP) approved by the EDC that is read electronically by PJM or that is read by the customer or the CSP and forwarded to PJM.

Economic Program

Much to everyone�s surprise, including PJM, and the utility members that voted against it, FERC approved the pilot Economic program.� It is an expansion of the prior program and is based on economic rather than emergency conditions.� The qualifications are the same except that the special membership provisions do not apply.� Participants must be full members of PJM and have the ability to reduce measurable and verifiable portion of load without onsite generation.

Allowing load to respond to prices brings obvious benefits to many, but there will be some that view it as competition to the services they provide and it was no surprise that the majority of generation owners and transmission owners opposed the economic program.���

Metering Requirements:

The metering requirements are the same for both programs.� The methods by which the requirements may be met, however, are slightly different.� Metering that is capable of recording integrated hourly values for generation running to serve local load (net of that used by generators) or metering that continuously records the load drawn from a specific process of application and is capable of demonstrating that the process or application was halted for the purposes of a load reduction and not due to normal conditions.�

Unlike the Emergency Option, the Economic Option is not based on the declaration of a Maximum Emergency Generation in PJM but rather on the economic decisions of the PJM market participants.� Participants determine the conditions under which they will reduce load.� The principal conditions will be the price of energy on the PJM system.� Participants are required to email the amount and price at which the load will be reduced to PJM immediately prior to or concurrent with accomplishing the load reduction.

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Predictions for Summer 2001

PJM predicted almost a seven percent increase in demand this year from last year with a new record summer peak expected.� Its all time peak demand was 51,700 MW set two years ago.� PJM expected to operate this summer with a power supply reserve margin of 15-17 percent.�

PECO Energy Co. predicted its customers were likely to push summer peak demand for electricity up about six percent over last year to 7,750 MW.� The forecast demand was less than the all-time peak demand of 7,959 MW set on July 6, 1999. �Summer weather last year was mild without prolonged stretches of extreme hot weather that tends to push electric consumption from air conditioners to peak.� PECO Energy delivers electricity to 1.5 million customers and natural gas to 430,000 customers in southeastern Pennsylvania.�

�

Results to Date

PJM implemented a temporary pilot program during the summer of 2000, the Customer Load Reduction Pilot Program, in an effort to encourage large users to voluntarily curtail load or sell the end-users own generation back to the system during periods of peak demand.� PJM attempted to put a permanent program in place for the summer of 2001 that would expand the operation of the program to be operable on an economic basis as well.� The program would come into play when there are peak period reliability concerns or when prices in PJM�s energy market reached a contractually pre-determined level.� Such programs provide the dual benefit of encouraging the development of workable competition as well as the benefit of enhancing the reliability of the grid during peak demand periods and could go a long way toward helping to resolve some of the problems experienced in California during 2000.� What was approved was a Load Response Program pilot program that is only in effect until May 30, 2002.��

The Load Reduction Pilot Program in 2000 was only effective from July 8^th to September 30^th whereas the 2001 program is effective for one full year.

No retail sale of electricity takes place under the Load Response Program and payments are made to PJM members that agree to reduce loads.

Many of the large industrial and commercial customers interested in the program hadn�t joined as of August 2001.� In Pennsylvania the Department of Environmental Protection (DEP) has very strict guidelines for the use of emergency generation especially generators using diesel fuel.� The head of the local DEP office was quoted as saying �that industrial and commercial customers will not be allowed to make a profit at the risk of the damaging the environment.�� Permits issued in Southeastern Pennsylvania only allow the use of back-up generation for emergencies such as power outages caused by the weather.��� Hopefully by next year PJM and their customers can pressure DEP to lower their standards by allowing back-up generators to operate for both emergency and economic load shedding.

The first time the program was needed occurred during the week of July 23^rd.� The use of the pilot program, in combination with other existing initiatives, contributed to PJM�s system operations on a day when PJM reached an all-time peak of electricity use.�

The Mid-Atlantic region�s power system had to cope with the record setting demand by its more than 22 million customers. Electricity demand rose to a record 51,798 MW on Tuesday and 52,200 MW on Wednesday.� The old record for electricity usage was the 51,700 MW number required on July 6, 1999.

Prior to July 23^rd, the most electricity consumed by PECO customers was on June 20^th with a peak demand of 6,725 MW occurring during the 4:00 p.m., (EDT hour with total usage for the day of 129,137,000 (kilowatt hours).� PECO introduced an energy conservation voluntary load reduction program in June 2001 call �Smart Returns� to more than 300 large customers who had interval metering and the ability to curtail their consumption.� This program gives PECO the ability to free up electricity from volunteering customers and sell it to others and PECO shares the financial gain with participating customers.�

Overall PJM was disappointed with the response to the program.� As of August 2001 PJM had about 180MW enrolled, 140 of which is Active Load Management (ALM) and 30 of which is in the economic program.� Records of what was actually reduced were not available as of the time of this writing. PJM Emergency Load Response Pilot Program Special Members include:

-          Benton Foundry, Inc

-          Cogenex Corporation

-          Downes Associates, Inc.

-          Durand Glass Manufacturing Company

-          Electrotek Concepts, Inc.

-          Epex, Inc.

-          Occidental Chemical Corporation

Summary

Voluntary load curtailment programs have been around for a few years and most of the programs are small in scale involving a few dozen participants and many like PJM are still in the pilot stage.� Load curtailment programs only make a small contribution towards balancing the supply and demand for power and reducing peak prices.� However it is widely accepted that dropping even a few megawatts off the system at peak periods is more efficient and economical than the incremental cost of generating them.� Also by providing additional load resources when generating resources are scarce, these megawatts help maintain the reliability of the grid.� Furthermore, market participation by load promotes the efficient working of the PJM energy market.� It is recognized that the lack of demand response is a failing of existing electricity markets and the ability to rely on demand side responses better allows the market to resolve demand and supply imbalances.�

One limitation to the expansion of voluntary load curtailment into the smaller Commercial and Industrial market is the need to install interval recording meters or at least meters that are remotely readable on demand so that information about hourly usage can be obtained during a curtailment event.�� Who pays for installing the meters and meter reading system in a deregulated environment?�

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PJM was delighted that both programs were approved by FERC but disappointed that more customers didn�t sign up for the 2001-2002 pilot programs.� One of the reasons is because the Department of Environmental Protection in Southeastern Pennsylvania wouldn�t allow customers with back-up generation to use it except in an emergency.

BIOGRAPHICAL DATA

Frank Richards established The Richards� Energy Group in Landisville, PA, in 1995, after 27 years� experience with PA Power & Light and Eastman Kodak.� His firm concentrates on reducing electric and gas utility bills for clients through rate options, audits and common sense.� To maximize the savings from electric deregulation in Pennsylvania, his firm has successfully developed a strong industrial-commercial users� group---wielding an electric load of 44,000KW ($12 million annual electric billing).�

Beyond his BSEE from Lehigh University, Frank is a licensed PE in PA and HI, is a Certified Energy Procurement Professional, and holds memberships in NSPE, IEEE and AEE.� His firm is now a Licensed Electric Supplier in PA.

Frank can be contacted by

phone:�

fax:�

website:�� www.richardsenergy.com

or regular mail:

����������� The Richards� Energy Group

����������� 1325 Crown Vetch Drive

����������� Landisville, PA� 17538

Gerald Mimno is a business development manager specializing in wireless applications for the Internet.� He has worked at AES-IntelliNet for six years developing wireless Internet applications for remote equipment monitoring, energy management, and submetering.� Mr. Mimno has a BA and MA from Harvard University concentrating in economic development and business development.� He has twenty years of practical experience in building systems.� He is a Licensed Construction Supervisor in the Commonwealth of MA.� He is responsible for developing new markets and relationships based on wireless and Internet technology.�

REFERENCES

1         Utility Business Sept 2000 pg. 3

2         Restructuring Today 3/7/01
^3� Wall Street Journal 3/9/01 pg. 2
^4� Restructuring Today 1/30/01 pg. 1
⁵ �Wall Street Journal 3/8/01 pg. 1
^6� Economist 3/3/01 pg. 60
⁷ �Restructuring Today 3/5/01 pg. 4
⁸� Wall Street Journal 3/8/01 pg. 1

Elizabeth Kimmel has many years experience in marketing, sales and Program and Project

Management.� In 1994 she started the development of the advanced metering market for metering programs at PECO Energy.� She continued to grow the business at Exelon Energy Services/Energy

Assets when PECO spun-off their advanced metering business to the deregulated subsidiaries.� She joined Alliant Energy Integrated Services in January 2001 when they purchased Energy Assets and continues to expand advanced metering and energy information systems in the Northeast.�� Ms. Kimmel is the recipient of the 1998 Electric Power Research Institute (EPRI) Product Champion Award for exemplary leadership as founding director - Education, Governmental and Institutional targets that helped guide electric utility support of schools and businesses in America. Until leaving PECO in 1999, Ms. Kimmel served on the EPRI Healthcare, Industrial, Water/Wastewater, Educational and Governmental committees.

A University of Pennsylvania Wharton Business School Graduate, Ms. Kimmel worked at General Electric, Honeywell, PECO Energy and Ferranti International in the UK.�� She is a member of the American Association of School Administrators (AASA), Association of Energy Service Professionals (AESP), Electrical Association of Philadelphia (EA) and Association for Higher Education Facilities Officers (APPA).� Liz serves on the board and is editor of the Association of Energy Engineers (AEE) Delaware Valley Newsletter.

Liz can be reached at:

Alliant Energy Integrated Services

2003 Renaissance Boulevard

King of Prussia, Pa. 19053