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Volume 4 |
From the Editor: Joel Gilbert, P.E., CEO, Apogee Interactive, Inc. Note from the Chairman: Ross Malme, CEO, RETX Peak Load Management Alliance Fall Meeting October 7th & 8th, Annapolis, Maryland ISO Status Reports and Plans for the Future A Panel on FERC's SMD NOPR Panel on Distribution Company Perspectives The Free Market Commodity Trading Perspective Panel on New Concepts in Creating Demand Response And, Now … The Customer Perspective A Robust Demand Response Program As An Integral Component of Optimization EEI and PLMA Roll Out 2002 Demand Response Benchmarking Tool | |
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From the Editor: Joel Gilbert, P.E., CEO, Apogee Interactive, Inc.
The outfall on customer demand response programs is beginning. The business case for demand response is being scrutinized more closely, and those who persist will soon separate themselves from the pack of lemmings about to beach themselves on the boom-bust investment cycle logic. This fall's Peak Load Management Alliance meeting in Annapolis was well attended, and the presentations were professional, insightful, and pointing towards two success paths: creative regulatory thinking in regulated retail markets, and innovative market models in regional electricity markets where customer choice is being attempted. If you were at this meeting, you came away with a wealth of ideas and insights. If you missed it, this newsletter will at least give you a brief, but largely inadequate, set of "Cliff Notes." If any of you have other ideas you would like to share with our readers, please send them in. Doug Backer from Cannon did, and we have included a summary in this newsletter. The full text is available by clicking on the link noted. And, last but certainly not least, please see the notice announcing the EEI Demand Response Benchmarking Tool, which is now open for this year's participation. |
Well, we are certainly witnessing the Chinese Curse: May you live in interesting times! The
same Wall Street analysts who insisted energy companies needed to stop acting like dinosaurs and follow
Enron's model for assetless opportunism are now criticizing the energy companies who did, and at the worst of
possible times for them to attempt a change in plans. Why is it that these analysts, and the credit rating
agencies they influence, are escaping blame?
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Note from the Chairman: Ross Malme, CEO, RETX
A year ago the PLMA Board of Directors established an initiative to make the organization more relevant to the demand response industry. We wanted PLMA to provide more value to its membership and to the demand response industry as a whole by creating more awareness of the value of our industry and by becoming the place where people come for information on demand response. Looking back I am pleased to say I believe we have delivered on that objective. I want to thank a number of the PLMA Board members for that success. Without their leadership, skills and contributions we would not have been able to create and achieve as much value to the industry as we've done. All of this has been done on a voluntary basis. The PLMA Newsletter, which has a readership in excess of 1500 industry participants, is primarily the result of the efforts of Joel Gilbert of Apogee as editor and Joe Leccese of Comverge as the Chairman of the PLMA Communications Committee. Joe and his Committee have established the concept of "Beat Reporters" where specific Board members are responsible to bring content to the Newsletter on newsworthy items from the various segments of the industry. This keeps the Newsletter relevant and fresh on current issues affecting the demand response industry. Over the last year we have debated if PLMA should be involved in the creation and commenting directly on public policy issues affecting the industry. While I can tell you that this has been a hotly debated topic over the last year, the Board has decided that we will not take positions on public policy due to the diverse interests of our membership. However, we will create channels for the issues to be aired and debated, and information products to help our membership and the industry better understand the issues. Examples of these channels are the two "White Papers" on demand response created by Dan Violette and his team. The first "Design Principles for Regulatory Guidance" paper was published last spring. This was done in conjunction with a conference on February 14th, which PLMA assisted in organizing with FERC/DOE on demand response programs for ISO/RTOs. This meeting was a prelude to the current NOPR on Standard Market Design. This paper is available on the PLMA website, www.peaklma.com. The second paper, "Design Principles for Creating Customer Value", will be published by the end of October. To receive a copy of this paper contact any PLMA Board member, Elliot Boardman, our Executive Director or you can download the paper from the website shortly after publication. In order for our membership to stay current with the whirlwind of regulatory and public policy initiatives underway which affect the demand response industry we have created a Public Policy Tracking Committee headed by Dave Kathan of ICF Consulting. The Committee will publish a brief internally to the PLMA membership on a monthly basis on current events. The first of these briefs was published this month and you can find a summary of the brief later in this newsletter. If you were ever thinking about the value of PLMA membership to your organization, I believe this brief alone can more than justify that investment. Shortly you will be seeing a new look and feel to the PLMA Website. With all of the new products and services now available from PLMA we felt we needed to offer more information, functionality and connectivity to the website to create more value to our constituency. If you have any comments or thoughts about what you would like to see offered from the PLMA website, please contact Elliot Boardman directly. One of the more visible initiatives of the PLMA has been our annual PLMA awards to the best demand response programs in the industry. This year we had 18 applicants for awards, all of which were quality programs and worthy of industry recognition. The PLMA Awards Committee had a tough time making the final decisions but this year we are proud to give awards to the best demand response programs in 6 industry segments. Details on each of the programs can be found later in this newsletter. These programs are the "Poster Child" of success in our industry and I believe we need to provide more visibility not only to the winners but all of the programs worthy of recognition. Finally, over the last year we have taken PLMA "On the Road." Not only have we participated as speakers at various FERC meetings on the Standard Market Design but we've also been an active participant in the New England Demand Response Initiative (NEDRI) which is FERC's incubator for the future of demand response programs. We also have been a guest speaker at the EEI Annual Meeting held in Boston in June, the NARUC Summer Meeting held in Portland, Oregon in July and presented at the October EPRI Primen Conference in Salt Lake City. Additionally, DistribuTECH has accepted a PLMA's proposal for a dedicated panel on demand response comprised of speakers from the PLMA Board at its February conference in Las Vegas. As you can see we are putting substantial effort into outreach at PLMA and creating recognition of the value of our industry, and creating brand recognition for PLMA as the place to go for information on demand response. If you need a speaker on demand response at an upcoming industry function please don't hesitate to call on us as we have a stable of "GREAT" speakers. Looking forward to next year I think you will see us continue aforementioned successful programs, albeit with a little refinement, and even take on a few additional projects subject to member availability and funding. We would love to have you as a member of our organization and an active participant whether you are an energy company, demand response aggregator, consultant, technology provider, industry association, government agency, or end user you are welcome to our eclectic yet highly motivated band of industry professionals. There is much work to do, but, oh so much to be gained. |
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Peak Load Management Alliance Fall Meeting
October 7th & 8th, Annapolis, Maryland
Demand Response, FERC's Perspective, Ms. Alison Silverstein, Technical Advisor, FERC. Alison, an ardent advocate of demand response (DR), kicked off the meeting with her views of the current regulatory landscape. She indicated that the audience must recognize the critical distinction that FERC regulates wholesale not retail markets. So don't look to FERC to fix some of the local issues that state regulatory agencies need to fix. The FERC will focus on long term resource adequacy requirements as a major element in long term price stability. While, demand response is the "magic bullet" for mitigating price spikes, the FERC recommended minimum 12% resource adequacy margin can and should include demand response. She is hopeful that the regions will set the mark higher. Alison went on to suggest that regional state advisory committees need to help implement the Standard Market Design (SMD) on a regional basis and these folks will of necessity get into the details of how these resources are paid for. There needs to be more work done to refine these concepts and make them implementable. She did indicate that one mechanism that may be the most workable in the short run is to use a systems benefit charge. The FERC is looking to NEDRI to develop real live projects and real live meaningful feedback and put that into the SMD. They want programs put in the field for three years with no fooling around to produce the data needed to plan a broader implementation. The EPA has also been asked to prove whether DR has a beneficial impact. The FERC is also going to review an enormous amount of feedback from the ISOs and DISCOs. She pointed to five things that are on her mind: Who benefits from demand response? She wants real dollar impacts and a reinvention of the integrated resource planning process. Pricing questions include how much the customer is paid, who writes the check and how is it going to be spread? Should there be floors and ceilings in the market? What markets can and should DR participate in? Her last item is the social policy question about the long run way to pay for this resource. She believes customers need to be educated as (but she can't necessarily solve this because it is a state issue). Demand Response, a State Regulatory Perspective, Commissioner Terry Fitzpatrick, PA Public Utility Commission. Commissioner Fitzpatrick suggested that the California crisis perhaps had a retail price hike that came too late. And, while Enron was the visible proponent of competition, when it went down, it tarnished the industry and brought with it the demise of several other trading firms plus the general economic condition, which has now lowered overall power prices. He suggested that Pennsylvanians have good news (they are not California) … but the bad news is that there really isn't much competition. The market opened in 1999 and 25% of the load was competitive and after 15 months it was to over a third competitive, and then the numbers went down. By July, 2001 it was back to about 8% shopping, where it has been ever since. The problem was obviously that the wholesale energy prices were above the POLR. He raised the real question of whether anyone will really make the investment to move beyond the current situation. Then, what can a state regulator do to lead the market out of this transition? So, he has decided that accepting the caps and creating more demand response at the retail level is the only viable path forward. Industrial voluntary load reduction programs have been put in place, smart thermostat, along with some time-of-use programs. He would like demand response programs for all customers. They are having a hearing on retail competition in December to answer the questions about what should be done to move beyond the current situation. He believes that the POLR really needs to be de-averaged, perhaps using a model similar to the two-part real-time pricing used by others. |
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ISO Status Reports and Plans for the Future California ISO, Glen Perez. If you can't find a program you like in what is available in California, you just didn't look hard enough. They have something for everybody. Unfortunately, the business case for their activity seems elusive at the moment. CPUC Programs are Scheduled Load Reduction Program (SLRP), Demand Bidding Program (DBP) morphed from a voluntary load reduction program, existing interruptible program, Base Interruptible Program (BIP) and the Optional Binding Mandatory Curtailment (OBMC), the 20/20 program from the Governor, and the California Power Authority program. NYISO, Dave Lawrence, Manager, Product Development. The New York ISO won an award at this meeting for their programs. Their menu of solutions includes an installed capacity program (special case resources), day-ahead and a real-time market program. The remainder is bilateral forward. Ancillary services also uses an emergency demand response program. The New York ISO also uses an ICAP at 118% of load. The value for ICAP varies significantly within the State. They have a day-ahead and a two-hour notice. It is an obligatory program. The emergency program pays for the performance and has no reservation element. They are offered a minimum of four hours. The day-ahead program operates through the load serving entity and then a decrement schedule (startup, minimum generation, and operating cost) and this goes directly into the bid stack. They achieved about 1,000 MW of proven resource out of a total of about 1,400 MW of enrolled resources (a little over 1,700 customers). The rules are being changed about the order in which programs are called. Special case resources are called first and are paid at the strike price so that the ISO can select the zonal participation. These strike prices would then be allowed to set the marginal clearing price (something that is expected to occur about 10 hours a year or so). The New York and the New England ISOs are going to merge and many details about that are still unclear at this time. PJM, Stu Bressler, Manager, Market Development. Their programs are similar to the NY ISO with an ICAP but rather have an active load management participation program. They achieve a total of 830 MW for both programs. There was a 300% increase in the total registration and a 400% increase in the economic between 2001 and 2002. In addition, there was more total activity at $150 in 2002 than at $900 in 2001 (because they have a larger customer response inventory). NE ISO, Presented by Ross Malme, CEO of RETX. The FERC has approved the NE ISO demand response programs for 2003. Their programs include a day ahead program along with an aggregated residential program. There are two load pockets of concern in their region (Boston and SW Connecticut) and they went out for an RFP and paid $180,000 per MW for four summer months of capacity. This ISO is also planning to introduce LMP as well. View from the Executive Suite, Stan Bright, former CEO of MidAmerican Energy. Stan shared some insights into the views from the executive level in the energy industry and expressed serious concerns about the consequence of the loss of investor, regulatory, and customer confidence in the business. While most of the energy industry leaders have done their job well, a few have behaved so unprofessionally and irresponsibly that it is going to take some time to see things improve. This when coupled with the general "stall" on the movement toward open, competitive markets is, in his view, going to keep us here for a while. |
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NRECA, Jay Morrison, Regulatory Affairs. NRECA serves 7% of the load and 48% of the wires in the US. He lead the panel on the FERC SMD NOPR He expressed concerns that the SMD is overly prescriptive in some areas and not adequately detailed in other ways. Scott Miller, Director of Market Development, the FERC. The FERC recognizes that so much of what is needed is in the state's hands, but there is a lot to be done in the design and implementation of wholesale markets. They are going to press the RTOs to have demand response that participate in all markets that seem to make sense. If the Load Serving Entity (LSE) is caught short of the 112% adequacy level, the FERC wants to see serious penalties. This adequacy level can be met through either generation owned or contracted for, or demand response. He hopes the LSE would use the resource on DR that is cost effective. Rich Cowart, Regulatory Assistance Project (NEDRI). Demand response is only going to work when the regional market participants incorporate it harmoniously into the value chain. If it doesn't answer the business fundamentals, DR isn't going to happen. He believes DR can play in the wholesale, reliability, and retail markets. He believes there needs to be a long term price signal to fund energy efficiency. Transmission planning must also include some form of integrated regional analysis and solution set. He suggested an "efficient reliability test" that in essence asks the integrated resource planning question for transmission planning. Steve Rosenstock, Edison Electric Institute. Steve believes the question before us all is whether we have to somehow solve the same problem President Eisenhower faced in building the Federal highway systems. EEI's thoughts and issues are published on their website (www.eei.org). He believes the real sticky question now is what happens when things go wrong and who is responsible? |
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Panel on Distribution Company Perspectives Dan Violette, Summit View Consulting. Dan asked the critical question: Isn't the ultimate solution dynamic pricing? Doesn't that avoid the emergencies in the first place? There is a place for a callable option. Dan summarized the recent Peak Load Management Alliance papers, which are available on its website (www.peaklma.com). Dan then concluded his remarks by indicating his belief that regulators will be asking tougher questions over this next year. Sharon Flannery, Team Leader, Northeast Utilities. Northeast Utilities had 400 kW participating last year and have about 40,000 kW this year (73 customers) with their "toes in the water." They collect their 86 million budget through a 3 mil charge on customer bills. Two million of that budget comes into the load management program efforts. Their primary concern is the Southwest Connecticut area where the load served is mostly commercial. They are performing demand response capability audits for the customer facilities and paying for facility investment requirements to implement the ISO NE program. They even offer participants e-mail addressable pagers. Chris Siebens, Manager, Demand Response Programs First Energy Technologies (New Jersey). Programs are paid for a societal benefit charge in New Jersey. There is no equivalent in Pennsylvania except for a low income program. There is a distributed generation pilot with a few hospitals in Pennsylvania. They have 51 customers 40 MW in New Jersey this year but not sure about whether they will do it again next year because of the possibility of regulatory change there. Voluntary program this year was 50% of day ahead and 100% of day of, and they now pay a more even split. Most of these customer thought about playing with the ISO directly, but felt the First Energy program made it easier. The proposed changes in the New Jersey rules for the wires companies will likely eliminate economic benefit for First Energy. Mark Wollenrod, Manager of Pricing and Load Management, Southern California Edison. SCE wants to be in the business and believes they are better at this than anyone else in the market. They are also getting back into the energy procurement business. SCE typically gets about 700 MW of demand response. They deal with large transaction volume and therefore work hard at standardization. They visit 5,000 customers in person and another 4,000 by phone, plus 100,000 residential and small commercial. They get over 2 million hits to their web site over a two week period. They found retail was difficult to get into programs and that the best partners were their large industrial and manufacturing customers. They also experienced a large derating effect for a their voluntary program due to the current low prices. They find third party suppliers (i.e., curtailment service providers) simply confuse customers and they wind up back to SCE for programs. Because SCE's programs are so large, there are significant consequent costs of small percentage errors. SCE can have significant costs associated with small percentage errors when emails don't get through or autodialers are claimed to have not worked. They found there is a big drop off at $250 per MWh to the customer which means that the wholesale price has to be quite a bit higher than that to have voluntary participation. The current cap at $250 per MWh in the market obviously precludes such price signals. |
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The Free Market Commodity Trading Perspective Bradford Leach, Senior Director, NYMEX. Brad started at the NYMEX to get the natural gas contract in place. But, unlike electricity, the natural gas delivery systems were configured for interstate commerce … a fundamental difference between it and the electricity infrastructure. Heating oil was the first energy commodity traded (1978) at the NYMEX, which was popular because of the hedging function (transfer of risk) plus the price discovery it provided. He emphasized that standardization is the key but that it has to be consistent with industry delivery mechanism. NYMEX's margin requirements based upon marking positions to market daily offers counterparty protection along with trade surveillance mechanisms. They are taking the counterparty credit risks. Brad then went on to describe what is really at work in the generation sectors. He indicated that debt was being loaded on with abandon before the Enron collapse and the rating agencies were caught off guard by the suddenness of the reversals. They are now much more intrusive and emphatic about safeguards. There has been a 240 billion has been lost over the last year (84%). About 25% of the generation in New York State is junk and almost 100% of one zone is junk. 46% of the California market is junk status. |
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Panel on New Concepts in Creating Demand Response Joel Gilbert, CEO, Apogee Interactive. Joel summarized his work with Bill Smith from EPRI on demand trading liquidity and the need for aggregated resource banks to assure all market participants of a firm resource. He showed how using price signals automatically leads to boom-bust cycles for resource development and why demand response needs a third party banking agent to assure all market participants that resource will be available. He also indicated that the concept that one price sets the margin for demand response is naive and will defeat the creation of a robust portfolio. Ahmed Faruqui, Charles River Associates. Ahmed showed how mass market customers do respond to dynamic pricing and create substantial value for the serving energy company. He illustrated how coincident peak pricing (CPP) is likely to be superior to the traditional TOU rates because of the better alignment between price signal price exposures. This concept was originally developed in France by EDF where they have the largest block of TOU rates (10 million customers), using a simple intuitive "signals" (red, white, and blue days). The number of each type of days are known but you don't know when they are called. The days are called the day before and they are a form of critical peak pricing. Their experience indicates that if you double the on peak price you tend to drop on peak loads by 20%. And, to no one's surprise, averages are possibly misleading. The elasticity has generally been measured at 30% (a 15% price increase yields a 5% improvement). Ahmed indicates that experience in the US is different in that when you double the on peak price in Phoenix and you get about a 30% response, possibly because the political will is missing. There is a societal benefit and a lowering of prices for all through this critical peak pricing. Traditional rate cost effectiveness tests would declare this program design cost- effective. Bill Uhr, UHR Technologies. Bill followed in the tracks of Ahmed to challenge the regulators on their own turf. He echoed Joel's remarks that the economics of the customer facing programs can not be exposed to boom-bust cycles. Bill focused on solving the dynamic pricing from a regulatory perspective and suggested they should offer it as a choice just because it is one. Enabling technologies are in place and at reasonable prices … it is just that the politics of implementation require courage. After all there are customers who are going to invest in their homes for their own reasons who can participate in time-sensitive pricing mechanisms. He suggested a model where all customers must be offered CPP with a revenue neutral rate design by creating a proxy critical peak marginal cost (peakers) and adjusting that annually with an agreed upon number of hours (100) for both energy and distribution peak load relief. The hours themselves would not be known in advance. This would then be compared to the wholesale market performance annually and accrued against the market itself over time. A wires asset offset model could also be considered by allocating a healthy part of the distribution costs and peak load growth (25% to 50% of the wires cost) in kind of a time-allocated demand charge. The wires and commodity hours overlap somewhat so that having 100 hours for each effect can probably be managed with a total of 150 hours a year. Bill also felt that the rate design has to have clear price signals so that marketers can come un and use them to offer customers turnkey programs. And, after all, this is far superior to a flat price where the price risk itself is not recognized. |
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And, Now … The Customer Perspective Dennis Moran, Director of Strategic Contracting, Avendra. Dennis offers procurement services for Marriott, Hyatt, Fairmont and others in the business. He has spent most of his time as an educator within the hospitality industry. His primary strategies are energy efficiency, smart purchasing, and load management. This is a very difficult industry to embrace in this business. Energy is a low priority outside of supply disruptions and price spikes (both gas and electric). Guest comfort is the top priority. Managers often do not own the buildings. Owners often are a tough sell. The industry is in a staffing crunch due to the business conditions. Hotel engineers aren't … they are more often janitorial in orientation. This segment likes flat rates and is budget driven organizations. Small payments and the lack of savings assuredness is a real detractor. They do not like penalties. Therefore, most of the efforts are focused on energy efficiency. Flat rates discourage load management. Using emergency generators for peak shaving are the best load management option and paralleling gear is the best solution but not common, but tough environmental rules can make this option impossible. There is a significant opportunity for room air conditioning load controls but it requires investment confidence. The eyes of the management he has to convince "still glaze over." Gene Ameduri, Vice President, Facilities Automation, Roth Brothers (First Energy). This is a contracting company that manages thousands of properties (universities, schools, retailers) using a sophisticated load management program. Their program started in the spring and summer of last year to see how the automation programs could shift load from one time to another in the same day, therefore "meter spin" wasn't the primary focus, and as such did not benefit the customer that much without some external incentives. Ten days in the summer of 2001 with signals via email and shift load on a day in advance (with voluntary participation) but they had to perform for 10 out of 12 days. They precooled the building by 2 F coast through the period (72-77) minimized the outside air, no duty cycling, and brought the equipment on in a controlled sequence. Retail customers (Office Max, JoAnne, and others plus one of the First Energy office buildings participated. They tried to do this with buildings with automated control systems. The results were as follows: Office Max (19-37,000 sf) 147-240 kW demand. They attacked ten of those stores. JoAnne (11-47,000 sf) 45-220 kW peaks. Two groups of malls (.5-1.5 million sf) 500-1500 kW peaks. First Energy (Akron) is 97,000 sf with a peak air conditioning load of 265 kW. 90 F high humidity days. It took a minimum of 2 hours to pre-cool and often a lot longer. They were able to shift load a full four hours. Retail load could be shifted 15-25%. Shopping centers were 20%, and the office building 20%. The target was to do this for under $350 per kW. The rate structure did not reward these activities. James Rouse, Associate Director, State Affairs, Praxair. Electricity is 70-75% of their operating cost so they have been interruptible customers for years. January 2001 they were interrupted five days in a row. They can go offline with ten minute notice and their product is stored. It takes four to five hours to get back up to the purity levels. They had 430 MW in the EDRP plus SCR (traditional interruptible) which will be called. The bulk of the SCR is in Western New York and out of the zone in which the power is needed. Robert Weishaar, McNees Wallace and Nurick. Robert represents industrial and commercial customers around the country before the PUCs, ISOs, and the FERC. He presented his perspective on ISO programs and what has to be in it for the customer. It includes ease of administration (simple programs), baselines must be simple and reasonably prompt payment for performance. His customers participating this last summer still have not been paid. The interruption must answer to cost-benefit justification so some large industry participants. Price certainty is an imperative. The interruption has to be economically worthwhile. They do see an uptick in the overall interest at the state and the federal levels. They have seen increased formalization of demand response and a longer term vision (the move away from pilot programs). There was a significant increase in participation. There were 23 days this past summer where they voluntarily interrupted. Steel manufacturers and paper makers also take some time to come back. He understands the tension between the gaming and the valuation. The resource valuation for ICAP or UCAP should be there in all markets. The call option valuation and timing are real problems. ISO driven programs need improved clarification of procedures. |
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A Robust Demand Response Program As An Integral Component of
Optimization The key requirements for using a demand response (DR) program in this way include:
Combined with a platform for distribution automation, energy data collection, substation automation, a robust DR program can be utilized for micro-managing power delivery efficiency down to the feeder or phase level.
To read more about Doug's insights, please click here: |
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EEI and PLMA Roll Out 2002 Demand Response Benchmarking Tool The Edison Electric Institute (EEI) and Peak Load Management Alliance (PLMA) are pleased to announce that the 2002 On-Line Demand Response Benchmarking System is ready to receive data from interested parties. For companies or entities that operate demand response programs, there is no cost to participate. The purpose of this streamlined system is to allow program managers to compare and contrast their programs with those of other companies. Ideally, this will help provide valuable program effectiveness feedback for those who operate or consider operating demand response programs. The web site, www.eeidatasource.com/eeilreq/index.cfm, provides information on how to register for the on- line system. Access to this system is obviously restricted to companies or entities that run demand response programs, such as investor-owned utilities, municipal utilities, cooperatives, ISO's/RTO's, state/federal utilities, and energy services companies. In order to access the on-line data, an entity must submit data. We believe this system will provide value for your company. If you have any questions or comments, the EEI contact is Steve Rosenstock. Steve can be reached by phone at 202-508-5465, or by e-mail at srosenstock@eei.org. The PLMA contact is Elliot Boardman, who can be reached by phone at 561-432-8836 or by e-mail at eboardman@aesp.org. |
