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RG&E Load Shed Project Team RG&E Economic Curtailment Program Program Concept Final Report Prepared For Rochester Gas and Electric Corporation 89 East Avenue Rochester, NY 14649 December 31, 2000 RG&E/PSC - 2001 Load Program Report RG&E Load Shed Project Team Table of Contents 1. Introduction and Background ....................................................................................... 1 2. A Sample of Utility Curtailment Programs .................................................................... 3 3. Activities of the Load Shed Project Team ..................................................................... 5 4. RG&E Curtailable Market ........................................................................................... 10 5. Preliminary Program Design ...................................................................................... 10 6. Other Important Program Issues ................................................................................ 13 7. Implementation Plan................................................................................................... 14 8. Conclusions................................................................................................................ 16 EXHIBITS .......................................................................................................................... 18 EXHIBIT A .................................................................................................................. 19 EXHIBIT B .................................................................................................................. 22 EXHIBIT C.................................................................................................................. 25 RG&E/PSC - 2001 Load Program Report RG&E Load Shed Project Team RG&E Economic Curtailment Program Program Concept/Analysis 1. Introduction and Background The New Energy Crisis Over the last couple of summers, a number of electric markets around the United States have experienced significant increases in spot electric energy prices and, in some cases, shortages as a result of high summer energy demands. The most drastic and recent example is in the deregulated state of California where the summer of 2000 saw average electric rates go out of control. With many customers in New York State now subject to market prices, there is a growing concern that they have limited options to respond to these prices to cut their own costs and, at the same time, assist the New York State power system better allocate and manage electric supplies during critical periods. The major energy events fueling concern include: The run up of oil prices to the $30/barrel price level1 accompanied by unprecedented increases in the price of natural gas to over $10/Dth which is almost three times higher than what it was 15 months ago.2 Severe price spikes and energy shortages experienced in California this past summer casting a shadow over the electric energy deregulation process. In the San Diego market alone, electric bills tripled and overall the state’s three investor-owned utilities incurred debts in the range of $6 billion.3 This past fall in New York, utility executives from around the country met to discuss electric prices and concluded that brownouts and blackouts are a real possibility over the next three years.4 RG&E's approximately 300+ MW disparity in peak summer periods. (See Table 1). 1 During the week of 12/18/00, crude oil spot and futures hovered between $28 and $30/barrel, Energy Information Administration, “Heating Oil and Propane Update”, DOE, Wash., DC, 12/28/00 2 Energy Information Administration, “Natural Gas Update”, DOE, Wash., DC, 12/28/00 3 McSwain, Dan, “California Gov. Davis Considers State Takeover of the Power Grid,” North County Times, Escondido, CA., December 1, 2000. 4 Belcher, Jack, "California Crisis Creates Uncertainty Around the States," Energy Markets, November 2000, pp. 26-27 12/31/00 1 RG&E Load Shed Project Team Table 1 - RG&E Electric Demand Statistics Year Highest Peak System Demand (MW) 1995 1425 1996 1305 1997 1421 1998 1388 1999 1433 Peak System Demand (1999) 1433 MW ISO Capacity requirement based on 1999 + 258 MW (1433 MW x reserve margin of 18%)) Require RG&E Capability 1691 MW RG&E owned generation + 990 MW Long-term power contracts + 210 MW Short-term power contracts + 491 MW TOTAL RG&E Capability 2001 (est.) 1691 MW Estimated capability purchased (portion of short and 258 MW long-term contracts) This report documents the development and analysis of a load curtailment program concept. Sections 2 through 5 provide more background and definition of the problem, the process followed, the market and the data that was gathered and analyzed. Section 6 presents the basic program design elements and assumptions used. Sections 7 and 8 present important program considerations and an implementation plan. And, finally, Section 9 presents a summary of the findings and the possible justifications for and against implementation of a load curtailment program. What's being done? Electric load curtailment or reduction has been available throughout the country for many years in the form of utility interruptible and curtailable rate programs. The problem with many of these programs in the past is that they have not been flexible enough to provide the proper signals of supply or demand problems in an electric system or rewarding enough for many customers to use effectively. In particular, the penalty provisions common to many interruptible tariffs have discouraged their use. As a result, curtailable load remains in many parts of the country a substantially untapped resource that can benefit both individual end-users as well as the electric system as a whole. The new generations of curtailable load products using recent web-enabled technologies have the capability to link end-use customers much more directly to near, real-time market price fluctuations. In addition, they offer a reasonably priced method for responding to these signals and verifying the load impact. Energy suppliers who have already adopted 12/31/00 2 RG&E Load Shed Project Team the use of these products will have a powerful, low-cost offering to end-users that allows them the ability to better manage their risk in the wholesale electric market. There are a number of efforts underway in New York State to address the problem of peak electric demand and constrained generation. The most notable is the New York Independent System Operator (NYISO). Through its Price Responsive Working Group (PRLWG) it is in the process of developing a curtailment program to improve the reliability of New York State's electric power system when demand on the system is very high. Simultaneously, an informal non-profit organization known as The Price Responsive Load Coalition (PRLC) composed of load serving entities, generators, end-use customers, and aggregators was convened to advocate for electric consumers and others who support the delivery of demand reduction services to electric customers.5 In particular, the PRLC is highlighting the need of smaller end-use customers (< 2 MW in size) to economically provide load curtailment resources to the New York grid. There are also strong indications that New York State Energy Research and Development Corporation (NYSERDA) will soon publish a Program Opportunity Notice (PON) to fund several independent load curtailment programs around the State.6 Finally, it is generally understood that most electric utilities in the State are also pursuing more robust load curtailment strategies in time for summer of 2001. In addition to the factors mentioned above, being a net purchaser of electric power during the peak summer season Rochester Gas and Electric Corporation (RG&E) formed the Load Shed Project Team (LSPT)7 to explore development of an independent response to the problem in RG&E's franchise territory. 2. A Sample of Utility Curtailment Programs In November 2000 the Edison Electric Institute (EEI) published the results of a study that showed that in 1998 utilities spent over $376 million on load management programs designed to spur conservation efforts. 8 Michael McGrath EEI, group director of Energy Services said the “study confirms that shareholder-owned electric utilities recognize that it makes good sense to invest in programs that help our customers manage – and potentially reduce – their peak load usage on the system.” The EEI study noted that member companies are increasing their emphasis on load management strategies and expanding program initiatives. The LSPT conducted its own very brief survey in November and identified a number of curtailment programs (including a pilot initiated last year). They are briefly described below. More expansive descriptions and briefs of some of these programs are presented in Exhibit A. 5 Price Responsive Load Coalition, formed in the summer of 2000, Albany, NY 6 Conversation with Peter Douglas, NYSERDA, November 6, 2000. 7 The Load Shed Project Team was formed at the request of Steve Adams, Manager, Business Customer Service. Members of the Committee include: Richard Thomas, Roy Brown, William Flood, Lee Loomis, and Mike Fitzpatrick. 8 Energy User News, "Utilities Use Load Management to Cope with Demand," November 2000, p4. 12/31/00 3 RG&E Load Shed Project Team RG&E, Rochester, NY - Last year, RG&E implemented a pilot curtailable load program known as RG&E Economic Load Reduction Program 2000 starting with three customers. Under the program, participants (limited to MV-90 equipped customers) were offered a one-time incentive of $5,000 to subscribe and RG&E agree to pay $0.15 per kWh for load shedding and $0.25 kWh for operation of on-site generation. The program potential load reduction was estimated at approximately 2.6 MW. Due to the relatively mild summer no load reduction events were requested. (See Exhibit A for more information.) Gulf Power (Southern Company), Pensacola, FL - Gulf Power has a Standby Generation Program that offers a wide array of on-site generation equipment services including financing, turnkey installation, testing and O&M, and in some areas incentives for operation of the system during system peak periods for load curtailment. (No specific program activity is available as yet.) Florida Power and Light (FPL), Miami, FL - Called the Business On Call program, FPL pays customers $2 month for each ton of eligible direct expansion air conditioning (AC) for a seven-month period each year (April-October). The program uses remote operated controllers to cycle the AC units 15 of every 30 minutes for a period of up to six hours. Ameren Energy, St. Louis, MO - The Customer Energy Exchange was launched for Ameren Energy’s largest customers in 1999 who could reduce their load by as little as 500 kW. The program uses an internet-based system to automate the notification and response process and administer market-based offers and rapid credit calculation. In 1999, the CEE paid over $800,000 in incentives to customers. (See Exhibit A for more information.) Kansas City Power and Light, Kansas City, Missouri - KCP&L implemented two curtailment programs in 1999. The first, Peak Load Curtailment Credit (PLCC) provides a bill credit at a fixed rate to participating customers during high demand periods during the summer season. The Voluntary Load Reduction (VLR) provides a bill credit based on market rates. In 1999, the PLCC paid approximately $520,000 in credits and the VLR paid approximately $128,000. Pennsylvania New Jersey Maryland Interconnection - This market allows suppliers to offer and buyers to purchase Capacity Credits. Prospective buyers/sellers of Capacity Credits submit Buy Bids/Sell Offers indicating the maximum amounts (MW) and prices ($/MW-day) which they are willing to pay/receive for Capacity Credits for a given period of time. All Buy Bids and Sell Offers are confidential. PJM OI validates and processes Buy Bids and Sell Offers to clear the market at a Capacity Clearing Price. 12/31/00 4 RG&E Load Shed Project Team 3. Activities of the Load Shed Project Team Interruptible Rates - The LSPT examined interruptible rates at the following utilities: Consolidated Edison9 New York State Electric and Gas (NYSEG) Niagara Mohawk Northeast Utilities Pennsylvania Power and Light Pacific Gas and Electric Southern California Edison San Diego Gas and Electric. In New York State, only Consolidated Edison had a functioning tariff rate for interruptible loads. NYSEG does not have an interruptible tariff and Niagara Mohawk's rate was cancelled by filing with the New York State Public Service Commission (NYSPSC). The other companies who have interruptible tariffs in place, in general, seem to employ a similar structure. That is, they pay a certain posted rate for serving interruptible load and a penalty two or three times this level if the customer does not shed the agreed amount on demand. As a result, although the tariffs may exist, participation is generally low and provides a small amount of capacity reduction the market is capable of providing. Residential Option - In October 2000, a load survey was initiated to determine the number of AC compressors and pool filter pumps in the service territory. At the time of this report the count was still being collected. Preliminary survey results indicate that a significant portion of the residential population has the capability to curtail loads should a program be developed and they desired to participate. The residential option is not under consideration this year for a number of reasons: Need for development of a reliable data set Time and cost to develop a program Low impact compared to C/I/M customers Significant operational resources required Most utilities and ISO's target larger commercial and industrial customers. The residential option could play a role if a phased approach was implemented. Large Customer Option - Load Shed 2000 program revisited and under review; mail survey of C/I customers (with MV-90) sent out in November 2000 to determine load curtailment interest and onsite generation capability. Considered the preferred initial strategy for the following reasons: 9 Consolidated Edison is the only New York utility with a functioning tariff rate for interruptible loads. 12/31/00 5 RG&E Load Shed Project Team Large Customer Option -Continued Some of the audience has load shed history in voluntary or incentive programs Greater load reduction potential Ability to achieve faster capture, to have an impact this summer, May 1 Minimal instrumentation needed - leverage MV-90 Lower cost of implementation and resource requirements. As of December 19, 2000, of the 170 surveys sent out, approximately 65 were returned with contact names for possible future marketing and educational efforts. Distributed Generation – Distributed generation is very limited in the RG&E franchise territory. Even if it were widespread it would not be a potential resource for contribution to system load reduction because it is our assumption that most systems would normally be in operation during the peak periods of the curtailment season. On-site Generator Costs - It was determined that it was necessary to understand customers’ costs of operating on-site generation equipment if this program concept is to succeed. For example, if the incentives offered by RG&E for load reduction cover the operating cost of generators and leave something left over for the customer to pocket, then the value is adequate. If the incentives are less, then recruitment will be restricted. Based on the research conducted at this stage the following estimates for operation of on- site reciprocating engine generators were developed: Fuel cost o $0.16/kWh for diesel @ $1.60/gallon o $0.12/kWh for natural gas @ $6/dth. O&M cost o between $0.015/kWh and $0.02/kWh10 Internal C/I/M assessment - C/I/M customer base is under review for participation. The LSPT focus on leveraging the capability of MV-90 system. The top 200-400 C/I/M customers are viable prospects and with an online system may be more willing to play. Vendors and Technology – The LSPT identified and/or reviewed a number of curtailment technologies or systems. There are residential and commercial systems available. There are two types of commercial systems – comprehensive (turnkey) system and partial systems. Table 2 provides a comparison of the various systems. PSC/ISO - RG&E is a member of the Price Responsive Load Working Group (PRLWG). This group is an advocate for consumers and public and private interests who are seeking demand reduction services for electric consumers. RG&E is actively participating in the discussion groups and helping to create reasonable policies in this area for the NYISO. 10 Curry, Tom, Senior Engineer, O’Brien Energy Systems, Wilmington, DE, Dec 1999 12/31/00 6 RG&E Load Shed Project Team The first demand reduction program that will be developed by the NYISO will be the Emergency Curtailment program. 12/31/00 7 Table 2 - Comparison of Curtailment Applications Name of Company Res/ Application System Web- Approximate Cost System Com Capability based Ener Touch Ener Touch R Residential application for load control of residential equipment such as whole house air Yes conditioning compressors, electric waters heaters, and pool pumps. Prisem – The Plurimi, Inc. C C/M/I loads and on-site generation Comprehensive Yes cost > $275,000 base price with capability discount of approximately 25- Virtual Peaker 35% for participation in pilot program by end of January 2001; also annual maintenance fee). Customer Energy Silicon Energy, C C/M/I loads and on-site generation Comprehensive budget price of $275,000 to capability $350,000 including first year Exchange Inc Yes maintenance cost; on-going annual maintenance fee approximately 18% of initial license fee). Curtailment Ameren DMS, C C/M/I loads and on-site generation Comprehensive Reputed to cost ~ $150,000 capability Manager Inc. Yes Ebidenergy.com Ebidenergy.com C C/M/I loads and on-site generation Monitoring & Yes Budget price between $10,000 - Monitoring and verification only Verification only 20,000. (RG&E would have to develop ISO price tracking, notification, and incentive calculation systems or do these manually). 12/29/00 8 One PRLC document provides insights into the current situation in New York in its “Initial Comments to NYSIO Price Responsive Load Working Group.”11 Excerpts from the comments are provided below: The escalating prices in deregulated wholesale electricity markets in New York, PJM, New England, and “most conspicuously California… have occurred in the context of relatively limited abilities for electric customers to respond.” “In part this is due to an inability of customers to see prices in a timely fashion, thus being deprived of the knowledge to act.” Other factors contributing to this condition include lack of complete exposure to volatile prices and also lack of mechanism for receiving benefits for reducing demand. “It is absolutely essential that the New York ISO’s Load Serving Entities (LSEs) and aggregators, including end-use customers acting as their own LSEs, be able to reduce their purchases from the hourly markets thereby “selling” the unused power back into the ISO’s relevant markets.” “Load reductions during peak load periods provide direct, substantial benefits to the NYISO, both in terms of price mitigation and system security.” “New York urgently needs to acquire additional responsive demand side resources before next summer.” The PRLWG strongly encourages “the ISO to implement and facilitate the third-party implementation of pilot programs this winter, so long as doing so will not interfere with the ability to implement full-scale programs next summer.” See Exhibit B for the latest notes on the development of the NYISO’s Emergency Curtailment program. Customer Case Studies -- There are many large customers around the United States that have developed agreements with their local utilities to provide load curtailment during periods of peak system demand. Whether through the use of interruptible rates or special programs there is significant evidence to suggest that there are opportunities in the market that benefit both the end-use customer who is doing the curtailing and a system operator which is trying to manage risk. An example of a successful customer curtailment experience is presented in EXHIBIT C. 11 Initial Comments to NYSIO Price Responsive Load Working Group, NYISO, Albany, NY, September 22, 2000. 12/31/00 9 . 4. RG&E Curtailable Market As previously stated, the LSPT has decided to focus on development of a pilot program for next summer on the large commercial, industrial, and municipal (C/I/M) customers. The reasons include: Greater load reduction potential Ability to achieve faster capture to meet our load objective Lower cost of implementation Lower resource requirement. Minimal instrumentation needed. On this last point, the LSPT has opted to concentrate on an initial market of RG&E customers larger than 200 kW who are equipped with interval meters and the MV-90 data acquisition system. In the RG&E service territory this constitutes approximately 268 businesses with 409 accounts constituting a total load of approximately 350 MW load. In late November a survey was sent to these customers to determine contact names with the authority to discuss load curtailment strategies and willingness to offer load reduction potential from either load shifting or the operation of on-site generation systems. The following list provides some insight on the possible status of a number of prominent Rochester businesses. 5. Preliminary Program Design As a matter of good program design and one that offers RG&E customers the most choice, the LSPT suggests that two options be developed - a voluntary curtailment option and a mandatory curtailment option. The voluntary option allows customers with load shed or on-site generation capabilities to use their discretion in deciding whether to participate in a high cost period when notified. The mandatory option provides RG&E a viable alternative to the purchase of options for future supplies in the curtailment season. Table 3 provides preliminary assumptions for the two options in the program. They are presented in adjoining columns for comparison. 12/31/00 10 . Table 3 – Program Assumptions Program Voluntary Mandatory Parameters/Assumptions Curtailment Option Curtailment Option Time horizon 1-5 year window 1-5 year window Recruitment target 50 MW Same customers Load Reduction target Unknown 3 MW Average event participation rate 0.5 1.0 Estimated participants 10 5 Estimated number of meters 20 5 Customer type C/M/I with MV90 meter C/M/I with MV90 meter Customer facility load size > 200 kW > 200 kW Curtailment season May 1 – September 30 May 1 – September 30 Load Shed timeframe 12 pm – 7 pm 12 pm – 7 pm Pricing model Day ahead market (NY ISO) Day ahead market (NY ISO) Estimated number of 98 98 hours/season 12 Estimated average unit price of $230/MWh $230/MWh 1 MW during curtailment RG&E margin 30% 30% 13 Recruitment Incentive payment $931/MW $1862/MW Penalty No penalty Penalty equivalent to the ISO price during the curtailment event. A critical assumption is determining the expected number of hours and potential number of curtailable events that could be expected in one season. From an economic perspective, a choice of the number of events and duration must simultaneously address the needs of the RG&E and/or New York State power system (providing load shedding during critical high cost periods of the summer when the system is under a strain from high demand) and the needs of customers who, in order to benefit from the program, must more than cover the cost of using on-site generation during a particular event. To determine this threshold, the LSPT requested cost projections for several scenarios of load duration that could conceivably occur during the curtailment season of 2001. These numbers were compared with the cost of on-site generation options and the experience of a number of other curtailment programs in other parts of the country. Based on this analysis, 98 hours was selected as a reasonable starting point for program design. 12 Weighted average of low, base, and high projections of Day Ahead Market prices for the NY ISO. 13 Estimated average price of an option for future power. 12/31/00 11 . Table 4 and 5 present the cost categories for a conceptual Load Curtailment Program. Table 4 presents the hardware and software costs and these are rolled into the overall program budget estimate for the complete program. Table 4 – Software and Hardware Requirements Cost Categories 1st Year 2nd Year $ $ 14 Program software and setup 5,000 --- Data hosting and services (120 meters) 36,000 36,000 Additional funds for submetering specific loads (20) 10,000 15 Development of RG&E systems for program operation 15,000 5,000 TOTAL $66,000 $41,000 Table 5 - Program Budget Estimate Cost Categories 1st Year 2nd Year $ $ Program Development 10,000 --- Supervision/reporting 2,500 2,500 Marketing 1,000 1,000 Selling 15,000 5,000 Legal 2,500 1,000 Management/operations 35,000 45,000 Software and Hardware Requirements (See Table 2) 66,000 41,000 Subtotal Administration $132,000 $95,500 Recruitment Incentives (options) Voluntary 46,550 46,550 Recruitment Incentives (options) Mandatory 9,310 9,310 TOTAL PROGRAM COSTS $187,860 $151,360 For purposes of evaluating both program options - Voluntary and Mandatory - program costs are allocated between the two based on the number of projected customers and meters for each. 14 Based on use of a web-enabled advanced monitoring and verification system and using the MV90 system, but no proprietary curtailment software. 15 RG&E will have to develop its own ISO price tracking, customer notification and customer incentive payments systems. 12/31/00 12 . Critical Issues or Concerns Can Business Customer Service recruit curtailment customers with a $1-2,000 incentive per MW/season? Uncertainty regarding future impacts of deregulation on the RG&E system Unwary RG&E customer base of pending problems and potential solutions Timing - need short-term option in place by May. 6. Other Important Program Issues Verification Process There are a number of proprietary software systems that have been custom made for load curtailment operations including: Prism (a.k.a. The Virtual Peaker) was developed by Plurimi, a company with internet expertise in systems design. Customer Energy Exchange was developed and implemented by Ameren DMS for its regulated utility Ameren Energy (formerly Union Electric of St. Louis). In addition to monitoring and verification, both systems may provide a number of features that facilitate the administration and management of curtailment programs, including, communications/notification and calculation of incentives. Unfortunately, these systems are expensive and, at this time, considered an unjustifiable cost given future uncertainties and the need for some operations experience. The LSPT believes that RG&E can manage notification and communications through its own systems and conduct validations of load reductions either through a manual process or, possibly, through the use of a metering and data hosting services provided by a local vendor. The advantages of using a web-enabled load tracking system is that it would provide convenience of simultaneous, desktop, web-enabled access to the metered data for both RG&E and their clients. Use of such a tool could reduce disputes regarding load reductions, increase the speed of verification and payment processing. RG&E could also elect to use existing tools it has and develop a procedure to accomplish the same thing. Barriers to Entry There are potential barriers to entering this curtailable load market in RG&E's franchise territory. They include: Customer uncertainty Short time period to market The option incentive of $932/MWh and $1,862/MWh for the Voluntary and Mandatory Options may not be sufficient to induce needed participation. Metering and technology costs From RG&E's perspective, the voluntary program as an economic option does not offer a comparable form of supply to the purchase of an option and therefore is more risky than a price hedge such as purchase of an option to buy power in the future. 12/31/00 13 . Future Options Based on a successful first year of operations and establishment of a medium term need, it is possible that RG&E could extend this program to smaller commercial and industrial loads and even residential customers in the future. However, the LSPT feels that the development of a load curtailment system for the mass market presents a vastly wider array of challenges from administrative, technical, labor, marketing, and operations perspectives. Additional research on how other residential curtailment systems are working should be conducted before any additional steps are taken in this direction. 7. Implementation Plan If the program concept were approved for implementation the following activities would be addressed and outlined in a project plan with appropriate tasks and dates for a successful May/June implementation: Final program design Operations and guidelines Instrumentation plans Monitoring and verification Marketing and sales Incentive payments Contracts Supervision and administration. Figure 2 provides a Load Shed Program Process flow of activities. Major areas of program development include: Selling program Registration and collection of customer data Metering and instrumentation Development and testing of notification and incentive calculation tools Procurement of web-enabled monitoring and verification system Development of internal management procedures and systems. 12/31/00 14 . Figure 2 – Load Shed Program Process Program kick-off Selling program -survey follow-up by telephone -qualification of prospect -send program announcement Subscriptions -site visit. -collection of contact info -verification of load -contract signature Development of internal notification System for RG&E -Establish procedure -Test procedure -Review/modify procedure -Test procedure again. Development of notification Email -design email notice Metering -test email, pager, telephone contact -instrumentation -assign customer user name & password -metering check -test energy data verification -verification of load w/customer -payment of option. 1st Curtailment Event Figure 3 suggests the time considerations regarding putting a program in place by May 1, 2001. Backing up from initialization of a program capability on May 1, the LSPT recommends a decision by upper management before the end of January 31, 2001. Figure 3 – Projected Time Line March 2001 February 2001 Set-up Operations Finalize Prgm. Design Sign contracts February 2001 April 2001 January 2001 Initiate Sales Cals Test Systems/procedures Go/no Go? May 1, 2001 Go on-line! 12/31/00 15 . 8. Conclusions RG&E's intent and objective is to consider the benefits and costs of developing an economic load curtailment program. Which simultaneously will contribute to various statewide efforts to improve the reliability of electric supplies during peak summer periods and provide its customers the access and ability to respond electric market prices with load shed and on-site generation resources. If RG&E and others are successful, the expected result will be that electric utilities, aggregators, and other load serving entities will all contribute to solving transmission and supply constraints in the New York State at a reasonable cost and in a manner that will reduce the risk of brownouts and shortages. Primary Finding The primary finding is that a load curtailment strategy/program can be economically viable and designed and fielded by May 1, 2001. Major elements / assumptions for load curtailment program proposal include: Target market is estimated to be about 50 MW. Actual customer participation is unknown at this time Load reduction amount is dependent upon customer participation per event 12 - 14 Curtailment events per season - 7 hours per event $230/MWh trigger price - average price for 98 hours during curtailment season A startup budget of approximately $190,000. Voluntary and mandatory components of the program 12/31/00 16 . Rationale For Implementation After providing an economically viable response to a market problem, the development and implementation of a load curtailment program by RG&E can also increase economic development and project a civic responsibility. Reasons for implementation include: A Load Curtailment Program managed by RG&E will provide customers access to the Day-ahead and, potentially, the real-time markets in New York State where they may be able to constructively assist utilities meet demand during critical summer periods and be compensated reasonably well for the service. The heightened awareness of California’s problems with deregulation, shortages and cost of electric supply during critical periods of the year, a load curtailment program for customers could be regarded as and extension of RG&E's civic duty. By providing C/M/I customers access to the load curtailment market, RG&E can add this program to other economic development efforts. If electric supply positions become severely strained during the summer of 2001 and emergency action is required by RG&E customers, a load curtailment program at minimum will offer a mechanism for compensating customers for any extraordinary load curtailment assistance they render to RG&E and the NY State grid. Taking a long-term view of the electric load situation in New York State, it is likely that the existence of effective and reliable load curtailment programs will, over time, tend to reduce the volatility of electric prices during system peak periods. Provide Acquire and Sell Energy Process a supplemental option. Rationale Against Implementation The amount of load curtailment potential in the RG&E service territory is likely to be less than 50 MW. The basic premise of providing load curtailment services ignores the view that beyond reliable power services C/M/I customers want to be left alone to concentrate on their primary businesses. No one vendor, method or application has been proven or tested as the best approach. C/M/I customers already wary of competition woes require significant education and sales effort as well as incentives to play. 12/31/00 17 . EXHIBITS 12/31/00 18 . EXHIBIT A Selected Descriptions of Load Curtailment/Reduction Programs 12/31/00 19 . RG&E’s Economic Load Reduction Program 2000 Pilot Effort Program Guidelines 1. The customer will be notified the day before, no later than 2 pm for the reduction the following day. 2. The reduction of load will be for 6 hours, from 11 AM to 7 PM. 3. The payment for reduced load will be $0.15 per kWh of load deferred b y turning off equipment and will $0.25 per kWh of load reduced due to running generators where load cannot be deferred. If it is necessary for the customer to implement a change to their procedures or wiring configurations these costs might be paid through an Option Premium. 4. The MV-90 metering system must be in place due to the site being a SC-8. The load reduction will be calculated through the perceived reduction from the normal operation and payment will be for all kWh reduced. 5. If the customer does not provide the requested load reduction he will forfeit the Option Premium he has received and will reimburse RG&E at the same rate per kWh he would have received in item 3. 6. This agreement would be in place beginning June 1, 2000. 7. Based on past experience it is anticipated that this load reduction would be needed for up to 3 days at a time and may be required 5-7 times during June, July, August, and September. The actual number of times this reduction will be used is not known nor guaranteed. The 15 to 20 days is intended as a guide. 8. The customer will need to provide a point of contact with alternate telephone numbers and persons as well as possibly e-mail addresses. ____________ 12/31/00 20 . Electrical Curtailment Program News Source: Don Gulley, Director of Retail Sales, Ameren Energy Marketing St. Louis, Missouri Date: 7/21/00 Last year, Ameren Services of St. Louis implemented a Customer Energy Exchange program for its larger customers. The program may be the first automated electric, curtailable load program in the country using state of the art software to notify, monitor, and account for the value of customer curtailments during utility system peak periods. In the summer of 1999, the program provided generous credits to participants while helping the utility reduce its overall cost of electric supply. Because of energy market volatility during the summer season, electric prices soared in 1999 to as high as $1.20/kWh during 12 curtailment days. As a result, Ameren Energy paid over $800,000 to participating customers. Summary of 1999 results (1st Year) More than $800,000 credits to customers 44 customers participated 140 MW total customer commitment 37 MW Peak Demand Reduced 1,400 MWh reduced $100-$1,200/MWH offered June and July 12 total curtailment days. Among the participants were a couple of St. Louis’ largest hospitals that operated their back-up generators and achieved partial load reductions by running their standby generators. In Missouri, hospital back-up generation systems typically have to run in parallel with the utility, giving plant operators the flexibility to run the generators to partially reduce overall plant load while the balance of the non-critical areas of the hospital are supplied from the utility electric service. Interestingly, Dan Gulley, said that when they contacted five hospitals in St. Louis about the program only those hospitals where departmental cost centers were established participated. The other hospitals that did not participate not only cited reasons of risk, run-time, and liability as concerns but also were institutions various departments’ costs were not separately tracked. St. Louis is where the headquarters of a number of the nation’s largest healthcare systems are located including - BJC, Tenant, and Sisters of Mercy. 12/31/00 21 . EXHIBIT B Notes from the New York State ISO Price Responsive Working Group 12/31/00 22 . Notes from the New York ISO Price Responsive Working Group16 The NYISO Emergency Curtailment Program is to be put in its final draft form and mailed to members of the group on November 22, 2000. Comments and discussion will be on November 28th, with initial presentation to the BIC on November 30th. The following represent the status of development as of December 15, 2000. 1. Curtailment Service Providers can be: An LSE ( may or may not be serving the load) NYISO approved Aggregator Any Direct Customer of the NYISO Curtailment Program Direct Customer (CPDC) (reduced membership requirements for this program) [Membership requirements have not yet been determined, a subcommittee has not yet begun to work on the details.] 2. The program will be effective from May 1, 2001 through December 31, 2002 3. Participation is voluntary, with energy payments only, and no penalties. Penalties will be assessed in the Special Case Resources (SCR) program if someone participates in both. 4. Existing LSE curtailment programs would be entitled to participate in the program as long as the provisions of the two programs do not conflict. [A subcommittee is working on the definition of conflict.] 5. A subcommittee is attempting to determine a fair method of determining the amount of curtailment. It is expected that there will be more than one allowable method because of differing customer load profiles. 6. Customers will be required to have an appropriate hourly interval meter that records the consumption. 7. Actual load reduction will be verified by the NYISO through data submitted within 45 days of the load reduction event. Load reduction will be determined by one of the following: Average change in load based on the 5 previous business days. Change in load from the hour preceding the curtailment. (One of the previous.) Direct metering of the generator output. Wait for the draft to see how it turns out. [Subcommittee is trying to determine the methods.] 8. The program is limited to emergency situations, and would be called between the manual voltage reduction order and the automatic voltage reduction and prior to requesting assistance from neighboring control areas. [“Emergency” has not yet been defined.] 16 RG&E has been participating in the Price Responsive Working Group. 12/31/00 23 . 9. Each CSP will designate one person to interface between the NYISO and the CSP. 10. Payments will be the greater of the real-time zonal LBMP clearing price or $500/MWhr, and will be paid directly to the CSP. 11. CSP’s must be able to provide a load reduction of at least 1MW, and be able to respond within 2 hours of emergency notification. 12. Customers must have the ability to participate for a minimum of 10 hours of the operating period of the program, and will be paid for a minimum of 4 hours per event. The first two hours will be paid at the greater of $500/MWh or LBMP, and the second two hours will be paid at LBMP (which is expected to be less than $500). 13. Customers under a contract that limits their ability to curtail energy are prohibited from participating in the program. 14. The program is intended to support the NYS power system during emergency periods. The costs will be allocated to the zone for a zonal problem, and state wide for a state wide problem. [Definition of “emergency” still to come.] 15. Emergencies invoked by an LSE in response to a local problem are not subject to this program. 16. Customers participating in the ECP may also participate in the Special Case Resources program if they are qualified. 12/31/00 24 . EXHIBIT C Customer Curtailment Example 12/31/00 25 . Electric Curtailment News Source: Bill Jewell, Director of Plant Services, Saint Thomas Hospital Nashville, Tennessee Date: 7/28/00 With the right curtailable rate program, the right generator plant, and the right management, hospitals can save money, improve operational reliability, and still maintain the highest life safety standards. Saint Thomas Hospital in Nashville, Tennessee is a 1 million square foot, 571-bed facility that has participated in Tennessee Valley Authority’s ESP program and is a model for what hospitals can accomplish. Saint Thomas Hospital has four 1600 kW generators (Caterpillar) backing up its emergency load, peak shaving is done through six Automatic Transfer Switches (ATS). Each load is between 500 and 1000 kW. Total facility load is approximately 7 MW during the summer. The hospital’s electric bill is between $1.5 and $2 million/year depending on seasonal temperatures. Back in 1993, shortly after he joined Saint Thomas Hospital as its Director of Plant Services, Bill Jewell started looking at his generator plant as more than simply an insurance policy in case there was a power outage. Why not use these generation assets to make some money for the hospital and possibly even improve operations in the process? With the current capacity the plant was capable of taking as much as 5 MW of the hospital’s 7 MW off the utility. During a hot summer season the potential financial benefit to the hospital was substantial. Tennessee Valley Authority’s (TVA) ESP program offered the perfect opportunity by allowing large customers to combine real time electric purchases with operation of on-site generation during high cost periods such as the summer or any other time when a system peak occurred. Customers agree to curtail their demand in emergencies. Although TVA has not called to curtail since the summer of 1995, Saint Thomas Hospital has self- curtailed for economic reasons several times. To join the program and implement the system, Jewell needed approval from his management, an engineering study to validate the design, and about $30,000 to install synchronizers and logic gear needed to allow a smooth transition between utility and on- site generation. The engineering study (required by TVA) assured that the power system was technically correct and could interface with TVA’s system. The system needed to provide a closed switch, in-phase transition between power sources. That means that during a time of switchover from utility to on-site power there is blinkless operation (electricity source never goes to zero). 12/31/00 26 . Once all systems were checked and put on line, the payoffs began. Typically, the on-site generation system is set to operate when utility costs of energy exceed $.10/kWh price. During these events, the hospital transfers approximately 4 to 5 MW of load to the on-site system. It has a contract with TVA to receive 2 MW of firm power. Although it varies from year to year, Jewell estimates that the savings from this system and mode of operation average approximately $300,000/year. Jewell credits his boss and upper management for supporting his efforts and TVA’s ESP program for making this operation a big success story and one that was way ahead of its time. Today, this open-minded approach to facilities and operations are the way plant managers can better leverage their assets and have significant positive effects on the bottom line. _________ 12/31/00 27 .
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